ILLINOIS POLLUTION CONTROL BOARD

ORDER
Section 211.102?Abbreviations and Conversion Factors
TITLE 35: ENVIRONMENTAL PROTECTION
SUBTITLE B: AIR POLLUTION
1. CHAPTER I: POLLUTION CONTROL BOARD
2. SUBCHAPTER c: EMISSION STANDARDS AND LIMITATIONS FOR STATIONARY SOURCES
  1. PART 217
  2. NITROGEN OXIDES EMISSIONS
Section 217.760?NOx Trading Budget
1. _
  1. _
    1. _
      - Section 217.Appendix F?Allowances for Electrical Generating Units

November 16, 2000

IN THE MATTER OF:

)

PROPOSED NEW 35 ILL. ADM. CODE 217,

)

R01-9

SUBPART W, THE NOX TRADING

)

(Rulemaking - Air)

PROGRAM FOR ELECTRICAL GENERATING )

UNITS, AND AMENDMENTS TO

)

35 ILL. ADM. CODE 211 AND 217

)

Proposed Rule. Second Notice.

OPINION AND ORDER OF THE BOARD (by R.C. Flemal):

Today the Board adopts for second notice a proposal to implement a nitrogen oxides

(NOx)

emissions trading program applicable to large fossil fuel electrical generating units

(EGUs). The purpose of the program is to reduce NOx emissions using market-based trading

controls. The program applies to emissions that occur during the period of May 1 to September

30 of each calendar year beginning in 2004.

Illinois and 21 other states are under order of the United States Environmental Protection

Agency (USEPA) and the Clean Air Act Amendments of 1990 (CAAA) (42 U.S.C. §§ 7401

seq.

(1990)) to reduce overall NOx emissions. In pertinent part, Illinois is under federal directive

to cap its emissions from the large EGUs at 30,701 tons of NOx per ozone season. The purpose

of this cap is to reduce atmospheric contamination, most specifically for ozone.

The Illinois General Assembly has found that an emissions trading program is a cost-

effective means of reducing NOx emissions (415 ILCS 5/9.9(a)(3) (1998 State Bar Edition, 1999

Supp.)). Further, the Illinois General Assembly has directed the Board to adopt regulations

implementing such a program (415 ILCS 5/9.9(b) (1998 State Bar Edition, 1999 Supp.)). The

Board’s action today is in response to that directive.

Today’s second-notice proposal follows substantially the proposal filed with the Board by

the Illinois Environmental Protection Agency (Agency) on July 11, 2000, and adopted by the

Board for first notice on July 13, 2000.

The principal provisions of the trading program occur in

Nitrogen oxides consist of compounds of nitrogen and oxygen. The ratio of oxygen to nitrogen

in these compounds ranges from .5 to 2.5. The term NOx is conventionally used for this group of

compounds.

Ozone is produced in the lower levels of the atmosphere when NOx or volatile organic

compounds react with oxygen in the presence of sunlight. Controlling NOx is accordingly a

method for controlling ozone.

In re

: Proposed New 35 Ill. Adm. Code 217, Subpart W, the NOx Trading Program for

Electrical Generating Units, and Amendments to 35 Ill. Adm. Code 211 and 217 (July 13, 2000),

a proposed new subpart at 35 Ill. Adm. Code 217.Subpart W. The proposal also includes

conforming amendments in Parts 211 and 217.

The Board notes that there is general and substantial support on the part of the

stakeholders for an emissions trading program such as presented in today’s proposal. We note as

well, however, that the emissions reductions necessary to comply with the federal cap are severe.

This has fostered some polarization among various stakeholders regarding how best to phase in

the trading program, including issues such as how to accommodate early reduction credits, how

to make initial allowance allocations, and how and when to phase to a fully market-controlled

program. We believe that the proposal offered by the Agency strikes a most equitable

compromise, within the scope allowed by the General Assembly, among the contending interests.

PROCEDURAL HISTORY

The Board held public hearings in this matter in Springfield, Illinois, on August 28 and

29, 2000, and in Chicago, Illinois, on September 26, 2000, before Board Hearing Officer

Catherine Glenn.

Hearings were scheduled and conducted in accordance with Section 28.5 of

the Environmental Protection Act (Act) (415 ILCS 5/28.5 (1998)). Section 28.5 provides for

“fast-track” adoption of certain regulations necessary for compliance with the CAAA.

The Agency presented various management and technical staff as witnesses. Stakeholder

testimony was presented by Tony Shea on behalf of ABB Energy Ventures and Grand Prairie

Energy (Exh. 30; Tr.2 at 12-22); Joseph N. Darguzas on behalf of EnviroPower, L.L.C. (Exh. 31;

Tr.2 at 23-29); Michael Menne on behalf of Ameren Corporation (Exh. 32; Tr.2 at 30-63, 223-

230); Brian Urbaszewski on behalf of the American Lung Association of Metropolitan Chicago,

The Illinois Environmental Council, The Environmental Law and Policy Center, and The Illinois

Public Interest Research Group (Exh. 34; Tr.2 at 77-114); Lenny DePuis on behalf of Dominion

Generation (Exh. 35; Tr.2 at 115-141); J. Derek Furstenwerth on behalf of Reliant Energy,

Incorporated (Exh. 37 and 38; Tr.2 at 147-166); Scott Miller and Kent Wanninger on behalf of

Midwest Generation EME, LLC (Exh. 38; Tr.2 at 167-182); Mary Schoen on behalf of Enron

Corporation (Exh. 40; Tr.2 at 184-222); and Aric Diericx on behalf of Dynegy Midwest

Generation (Exh. 41; Tr.2 at 232-239).

The record in this matter closed on October 13, 2000, as provided for at Section 28.5(l) of

the Act. Ten public comments have been filed: Dynegy Midwest Generation (PC 1);

EnviroPower (PC 2 and PC 8); The Agency (PC 3); Office of Public Utilities, City of Springfield

(PC 4); Ameren Corporation (PC 5); Midwest Generation EME, LLC (PC 6); Enron Corp (PC

7); Environmental Law and Policy Center (PC 9); and Chicago Department of Environment (PC

10).

R01-9. First-notice publication occurred in the Illinois Register, Vol. 24, August 4, 2000, at

11473 and 11493.

The transcripts of the hearing will be cited as “Tr.1 at ___” and “Tr.2 at ___” for the Springfield

and Chicago hearings, respectively. Exhibits admitted at hearing will be cited as “Exh.___ at

___.”

REGULATORY FRAMEWORK

Federal Actions/Requirements

Requirement for Attainment of the Ozone National Ambient Air Quality Standard

The State of Illinois has the primary responsibility under the CAAA for ensuring that all

National Ambient Air Quality Standards (NAAQS) are met in the State. This includes the

NAAQS for ozone. 42 U.S.C. § 7407(a) (1990). Currently there are two areas of the State which

do meet the one-hour ozone NAAQS. These areas are the Chicago and Metro-East ozone

nonattainment areas (NAA).

In addition, Illinois is required to control emissions that “contribute significantly to

nonattainment in, or interfere with maintenance [of NAAQS] by, any other State…” 42 U.S.C. §

7410(a)(2)(D) (1990).

The USEPA has determined that emissions of NOx from EGUs located in the State of

Illinois contribute to nonattainment of the ozone NAAQS in the Chicago and Metro-East NAAs,

as well as in NAAs located outside of the State of Illinois. For this reason, USEPA requires that

Illinois submit a State Implementation Plan (SIP) addressing the emissions of NOx from EGUs.

NOx SIP Call

On October 27, 1998, the USEPA promulgated a document titled “Finding of Significant

Contribution and Rulemaking for Certain States in the Ozone Transport Assessment Group

Regions for Purpose of Reducing Regional Transport of Ozone.” 63 Fed. Reg. 57,356 (October

27, 1998). This document, and the requirements it imposes on states, is commonly known as the

“NOx SIP Call”.

The NOx SIP Call requires that Illinois, along with other states located east of the

Mississippi, develop plans to limit NOx emissions to a specified budget. The final state-wide

budget for Illinois is 270,560 tons per budget year from several categories of emissions sources,

including large EGUs.

65 Fed. Reg. 11,222 (March 2, 2000). If a state fails to adopt a plan

acceptable to USEPA, USEPA will impose its own plan.

The terms “Metro-East NAA” and “Chicago NAA” are used in existing Board regulations to

refer to the two ozone nonattaiment areas in Illinois. See 35 Ill. Adm. Code Parts 218 and 219.

The same terms will be used herein. It is to be noted, however, that in portions of the instant

record these areas are referred to by the Agency respectively as the “Metro-East/St. Louis NAA”

and the “Lake Michigan NAA.” See Statement of Reasons at 4. The Agency assures the Board

that there is no intended regulatory consequence in this use of alternate terminology. Tr.1 at 235-

Proposals for regulations to implement the non-EGU portions of the NOx SIP Call are currently

before the Board in regulatory dockets R01-11 (addressing cement kilns) and R01-17. A

Illinois is not required under the NOx SIP Call to control any particular source at any

particular level, as long as the State meets its final state-wide budget. As the Agency observes,

however, as a practical matter controls on EGUs are necessary to meet the state-wide budget.

Statement at 27.

The NOx SIP Call also suggests, but does not require, that states adopt a “cap and trade”

strategy for the control of NOx emissions from EGUs. The Illinois General Assembly has

determined that the Illinois NOx SIP Call is to be met using the “cap and trade” system as

outlined in the NOx SIP Call. 415 ILCS 5/9.9 (1998 State Bar Edition, 1999 Supp.); also see

below.

Under the NOx SIP Call, USEPA has determined that the NOx emissions budget (

i.e.

cap) for large EGUs in Illinois is 30,701 tons during the ozone season.

Tr.1 at 100. To

participate in the interstate NOx trading program, Illinois must submit a SIP in which all affected

sources in Illinois combined emit no more than 30,701 tons of NOx per season, adjusted for

emission allowances purchased from and sold to out-of-state EGUs.

An emission allowance is a permit to emit one ton of NOx. Thus, pursuant to the NOx

SIP Call, Illinois’ large EGUs are allocated 30,701 allowances annually. The trading rules

promulgated by the various states are to include methods of allocating those allowances among

each state’s emitters, within limits allowed in the NOx SIP Call. Because the emission budgets

in a given state and the total allocations in the aggregate of affected states are capped, the

allocations do not affect the total NOx emissions from EGUs, but only the distribution of the

emissions. Exh. 40 at 2.

Action in Federal Court

The NOx SIP Call was challenged before the U.S. Court of Appeals for the D.C. Circuit.

See Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000). That court subsequently stayed the

effective date of the NOx SIP Call rule. Michigan v. EPA, No. 98-1497, (D.C. Cir. May 25,

1999) (order granting stay). However, on March 3, 2000, the court upheld most of the NOx SIP

Call rule. Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000).

On September 20, 2000, and

October 20, 2000, a total of three

writs of certiorari

were filed in the Supreme Court. See

Michigan v. EPA, U.S., Nos. 00-445, 00-632, 00-633. As of this date, the Supreme Court has

proposal to impose NOx controls on EGUs prior to the May 31, 2004 effective date of the instant

proposal is also currently before the Board in docket R01-16.

The Agency’s Statement of Reasons filed July 11, 2000, will be cited as “Statement at ___.”

The ozone season is defined as May 1 through September 30.

The court reversed and remanded for further consideration the inclusion of portions of Missouri

and Georgia in the rule, and reversed the inclusion of Wisconsin in the rule because USEPA had

not made a showing that sources in Wisconsin significantly contributed to nonattainment or

interfered with maintenance of the NAAQS in any other State. 2000 WL 180650 at *31. Neither

of these changes affects today’s proposed action.

not indicated whether it intends to hear the appeals. Other NOx-related court actions are also

pending.

Ameren Corporation (Ameren) contends that attainment of the ozone NAAQS in the two

Illinois nonattainment areas can be achieved with a lesser reduction in NOx emissions than is

required under the NOx SIP Call. Tr.2 at 34-38; Exh. 32; PC 5. Ameren thus observes that if the

NOx SIP Call is overturned in the courts, Illinois should adopt a less stringent NOx control

policy. PC 5 at 2-3.

The Board cannot, of course, base its decision in this matter on a prospective outcome of

a court action. It is necessary for the Board to make its decision based on the current status of the

law. In that regard, the Board believes the law requires that we move forward with the proposal

presented to us by the Agency. The Board will revisit our decision if a change in the law

requires.

State Actions/Requirements

Section 9.9 of the Act (Nitrogen oxides trading system)

The Illinois General Assembly in 1999 adopted new Section 9.9 of the Act titled

“Nitrogen oxides trading system.”

415 ILCS 5/9.9 (1998 State Bar Edition, 1999 Supp.). In

Section 9.9 the General Assembly finds “that reducing emissions of NOx in the State helps the

State to meet the national ambient air quality standard for ozone” (415 ILCS 5/9.9(a)(2) (1998

State Bar Edition, 1999 Supp.)) and “that emissions trading is a cost effective means of obtaining

reductions of NOx emissions.” 415 ILCS 5/9.9(a)(3) (1998 State Bar Edition, 1999 Supp.).

Further, Section 9.9 directs that “the Board shall adopt regulations to implement an interstate

NOx trading program.” 415 ILCS 5/9.9(b) (1998 State Bar Edition, 1999 Supp.).

Section 9.9 also requires that the Illinois NOx emissions trading program be “as provided

for in 40 CFR Part 96.” 415 ILCS 5/9.9(b) (1998 State Bar Edition, 1999 Supp.). Part 96 is the

portion of the NOx SIP Call, which contains the federal NOx emissions trading program. Tr.1 at

255-258.

Section 9.9(d) further directs the Board to address specific issues in adopting regulations

to implement the NOx trading program. These issues are that the Board shall:

assure that the economic impact and technical feasibility of NOx

emissions reductions under the NOx Trading Program are considered

relative to the traditional regulatory control requirements in the State for

EGUs and non-EGUs;

These include American Trucking Association v. EPA, 175 F.3d 1027 (D.C. Cir. 1999)

involving the 8-hour ozone air quality standard, and Appalachian Power Company v. EPA, Case

No. 99-1268 (D.C. Circuit) involving NOx budget allocations.

On August 19, 1999, Governor Ryan signed Section 9.9 into law as Pub. Act 91-0631.

provide that emission units, as defined in Section 39.5(1) of this Act, may

opt into the NOx Trading Program;

provide for voluntary reductions of NOx emissions from emission units, as

defined in Section 39.5(1) of this Act, not otherwise included under

paragraph (c) or (d)(2) of this Section to provide additional allowances to

EGUs and non-EGUs to be allocated by the Agency. The regulations shall

further provide that such voluntary reductions are verifiable, quantifiable,

permanent, and federally enforceable;

provide that the Agency allocate to non-EGUs allowances that are

designated in the rule, unless the Agency has been directed to transfer the

allocations to another unit subject to the requirements of the NOx Trading

Program, and that upon shutdown of a non-EGU, the unit may transfer or

sell the NOx allowances that are allocated to such unit; and

provide that the Agency shall set aside annually a number of allowances,

not to exceed 5% of the total EGU trading budget, to be made available to

new EGUs.

Those EGUs that commence commercial operation, as defined in

40 CFR Section 96.2, at a time that is more than half way through

the control period in 2002 shall return to the Agency any

allowances that were issued to it by the Agency and were not used

for compliance in 2003.

The Agency may charge EGUs that commence commercial

operation, as defined in 40 CFR Section 96.2, on or after

January 1, 2003, for the allowances it issues to them.

(415 ILCS 5/9.9(d) (1998 State Bar Edition, 1999 Supp.).

The Board has reviewed today’s proposal, and finds that it complies with each of the

required parts of Section 9.9(d).

PROPOSAL BACKGROUND

Proposal Development

Today’s action is the most recent in a long series of actions designed to achieve

compliance with CAAA regulations in the State of Illinois. Since the 1980s, Illinois has pursued

strategies to control ground-level ozone, and has had significant, but not complete, success as

measured by decreases in the number of recorded violations of the ozone one-hour NAAQS.

Tr.1 at 40.

Beginning in 1998, following issuance of the NOx SIP Call, the Agency commenced

regular meetings with persons interested in development of the instant rules. Members of the

affected industries and environmental groups were included in the meetings. Statement at 36-37.

These meetings provided the Agency with the perspective it used to develop the instant proposal.

The Agency contends that the proposal “represents a sound approach to those areas of discretion

permitted under the federal NOx Trading Program.” Statement at 39.

Scope and Affected Facilities

The geographic region subject to the NOx Trading Program for EGUs is the entire State

of Illinois. Statement at 20. There are approximately 100 existing EGUs within this region, all

of which are expected to be affected by the proposed regulations. Statement at 20. The

regulations also will affect any new EGUs (

i.e.

, those that commenced operation on or after

January 1, 1995) that serve a generator greater than 25 megawatts, or any unit with a maximum

design heat input that is greater than 250 mmbtu/hr and that has the potential to use more than

50% of the “potential electrical output capacity.” Statement at 20-21.

Implementation Date

At first notice the date for full implementation of the NOx trading program was May 1,

2003. This date was part of the original NOx SIP Call and is included in Section 9.9 of the Act.

However, on August 30, 2000, the D.C. Circuit Court of Appeals issued an order extending the

deadline for full implementation to May 31, 2004. See Michigan v. EPA, No. 98-1497 (D.C. Cir.

2000).

At hearing the Agency filed a motion to amend its proposal to incorporate the later, May

31, 2004 implementation date ordered by the Court of Appeals. See Exh. 33. The Board grants

that motion, and includes in today’s proposal all the changes requested in the Agency’s motion.

The Board notes that, as of the current date, USEPA has not explained how it will

incorporate aspects of the date change into Part 96, including how to implement the May 31,

2000 start of the trading program. The Agency recommends certain changes to the first proposal

to allow the USEPA, explanation when issued, to be incorporated into the Illinois rule. The

Board agrees with this strategy, and incorporates those changes into today’s proposal.

NOx TRADING PROGRAM

Primarily those changes include shifting the relevant dates in the proposal to the following

year, since the implementation date is now 2004, rather than 2003. See Section 217.758(a)(4),(5)

and (6); Section 217.760(a)(1) and (2). Additionally, the owner or operator of an EGU, rather

than the account representative, must pay any fine, penalty, or assessment or comply with any

other remedy imposed under 40 C.F.R. § 96.54(d)(3) and the Act. See Section 217.756(f). Also,

an application for a budget permit will be treated as a modification of the EGU’s existing

federally enforceable permit, if such a permit has been issued for that EGU, and will be subject to

the same procedural requirements. See Section 217.758(b)(3).

Mandatory Provisions

Much of the NOx trading program proposed today is mandatory, in that a trading program

compatible with 40 C.F.R. Part 96 is required under Section 9.9 of the Act. States that

participate in the trading program of Part 96 have limited discretion in adopting state programs.

Part 96 limits state discretion to assure that the principal parts of the NOx trading program will

be standard in all affected states. Exh. 25 at 5. In today’s proposal these mandatory provisions

are effectuated via incorporation by reference. See proposed Section 217.104 and 217.754(a).

Among the mandatory provisions are provisions relating to management of NOx

accounts, including the structure of accounts, account flow control, banking of allowances, and

the responsibilities of account representatives. The mandatory provisions also included elements

related to monitoring and reporting of NOx emissions.

The Board will not review here in further detail the mandatory provisions of the NOx

trading program. The Board directs interested persons to the NOx SIP Call for the specifics.

Optional Provisions

Part 96 provides for a small amount of flexibility in the tailoring of individual state

programs. Today’s proposal employs that flexibility in four areas, as follows:

whether to allow low-emitting NOx emission units to opt out of the trading

system;

whether to allow smaller emission units to opt in to the federal trading program;

whether to allow credit for early reductions emission; and

various details for allocating the State’s total NOx allowances among the State’s

EGUs.

Each of these issues is discussed below.

“Opt-Out” Provision

Part 96 provides that a state program may allow low-emitting units to opt out of the

trading program, provided several conditions are met. This provision is incorporated into the

instant regulations at Section 217.754(c). The “opt-out” provision is limited to units that are

fueled by natural gas or fuel oil and that have the potential to emit 25 tons or less of NOx during

The Board notes that Ameren suggests adding a definition for “NOx Trading Program” to

today’s proposal. PC 5 at 7-8. The Board believes that this would be a meritorious addition.

However, the Board declines to add this definition without the benefit of the Agency’s and other

participants’ comments.

the May-September control period. There are additional requirements regarding operating hours,

methods of emissions calculations, record keeping, and reporting. See proposed Section

217.754(c)(1)(C)-(F). “Opt-out” units are otherwise exempted from the rest of the NOx trading

provisions.

“Opt-In” Provision

Part 96 also provides that a state program may allow certain emissions sources that are

not otherwise included into the trading program to elect to participate in the trading program.

The “opt-in” provisions are included in the instant regulations at Sections 217.774 to 217.782.

The provisions are limited to operating fossil fuel-fired stationary boilers, combustion turbines,

or combined cycle systems. See proposed Section 217.774(a). “Opt-in” provisions in state law

must comport with the parallel provisions in Part 96, and they so do in the instant proposal.

“Opt-in” units must also comply with the NOx SIP Call regulations of 40 C.F.R. Part 75.

Early Emission Reduction Credit (ERC)

The NOx SIP Call includes a Compliance Supplement Pool consisting of allowances

available to states’ emission sources in the first years of the trading program. States have some

discretion in how these allowances may be distributed. The Agency recommends that these

allowances be used to bankroll an Early Emission Reduction Credit (ERC). See proposed

Section 217.770. The Board agrees.

EGUs earn allowances from the ERC pool by reducing emissions earlier than otherwise

required. The NOx SIP Call currently provides that early reductions must occur in the 2001 and

2002 control periods, and that the allowances so earned must be used in the 2003 and 2004

control periods. 63 Fed. Reg. 57,529 (October 27, 1998). However, in its Motion to

Amend (Exh. 33), the Agency proposes including 2003, in addition to 2001 and 2002, as a

control period year in which the early reductions must occur. Exh. 33 at 4. The Agency explains

that the D.C. Circuit Court of Appeals’ order on August 30, 2000, did not address whether the

dates regarding the control periods for ERCs should be adjusted. However, the Agency’s

preliminary contact with USEPA suggests that USEPA, in response to the

August 30, 2000 ruling, will allow ERCs to be earned in the 2003 control period. The Board has

accordingly accepted this change in Section 217.770.

The Agency also notes in its Motion to Amend that the USEPA has preliminarily

indicated that ERCs may only be used in the 2004 control period. Exh. 33 at 4. The Agency has

accordingly recommended that the proposal be modified to not only allow ERCs to be used in

2004, but also in any years authorized by USEPA. PC 3 at 15.

Ameren testified that ERCs should only be earned during the 2001 and 2002 control

periods, in part because they believe allowing credits to be earned in 2003 would not give them

enough time to know how to manage compliance in 2004. Tr.2 at 47. Midwest Generation also

argues that allowing ERCs to be earned in 2003 is inappropriate. PC 6 at 8. The Board

appreciates these comments, but supports adjusting the timeframes for earning ERCs in

accordance with the Agency’s Motion to Amend. See Section 217.770.

Allocation of NOx Allowances

“Fixed/Flex” Allocation

States are allowed latitude under the NOx SIP Call to determine how allowances are to be

allocated among emitters. Pursuant to the USEPA budget emission for Illinois, NOx emissions

from all Illinois EGUs are capped at 30,701 tons per ozone season. Tr.1 at 100. This is the total

Illinois NOx allocation for large EGUs. Tr.1 at 100. It is much less than current emissions.

Thus, any allocation system by necessity requires existing EGUs to significantly decrease their

emissions. It also requires that new EGUs use “clean” technologies.

The Agency negotiated with affected sources to try to create a balanced approach to

allocating the limited number of allowances. PC 3 at 8. The approach which the Agency

proposes, and which the Board adopts today, is termed a “fixed/flex” allocation scheme. Initially,

the large percentage of allowances are allocated to existing emitters based on historical emission

rates. The list of existing emitters is presented in the proposal at Part 217.Appendix F. As time

progresses, the allocations “flex” to accommodate changes in the identity and mix of EGUs as

older EGUs are phased out or modified, and as new EGUs come on line as replacements or new

additions to the total EGU population. See proposed Section 217.762.

In the years 2004, 2005, and 2006, the sources listed in proposed Part 217.Appendix F

will receive the number of allowances listed in column 7 of Appendix F. The total allocations in

column 7 amount to 95% of the 30,701 total allowances. The remaining 5% are set aside for new

EGUs that are not included in Part 217.Appendix F.

For the years 2007 and 2008, the EGUs in Appendix F will receive approximately 80% of

the allowances specified in column 7. See 217.Appendix F, column 8. Additionally, 2% will be

set aside for new EGUs, and the remaining allowances will be reserved for flexible allocation

based on the formula in proposed Section 217.762. At this stage some of the EGUs which were

“new” for the purposes of the earlier allocations will begin to quality for and draw their

allocations from the “flex” portion of the NOx budget.

In 2009 and 2010, the procedures above will be repeated, except that both the “fixed” and

“flex” portions of the allocation are 50% of the budget, reserving 2% for a new source set-aside.

Starting with 2011, allowances will be allocated to all existing EGUs (those in Appendix F and

those that rolled into the flex portion) on the basis of average control period heat input.

New Source Set-Aside

On average, existing EGUs in Illinois will have to reduce emissions about 74%. Exh. 27 at 6.

Section 9.9(d)(5) of the Act provides that the NOx trading program shall include a

provision that the Agency “set aside annually a number of allowances, not to exceed 5% of the

total EGU trading budget, to be made available to new EGUs.” See 415 ILCS 5/9.9(d)(5).

Today’s proposal incorporates this provision at Section 217.768, “New Source Set-Asides for

‘New’ Budget EGUs.” Among other things, the provision allows that each new source set-aside

will be allocated allowances equal to 5% of the EGU trading budget in 2004, 2005, and 2006.

See proposed Section 217.768(c)(1). Beginning in 2007, new source set-asides will be allocated

allowances equal to 2% of the 2007 trading budget. See proposed Section 217.768(c)(2).

The NOx SIP Call also contains a 5% set-aside provision for the first three control

seasons, followed by a 2% provision for the control periods thereafter. 63 Fed. Reg. 57,471.

However, USEPA left it up to individual states’ discretion whether to adopt a set-aside provision,

including the size of the set-aside. 63 Fed. Reg. 57,471.

Both at hearing and in public comment, some representatives of new EGUs expressed

concern that a new source set-aside of 5%, which later decreases to 2%, is insufficient for their

needs. Tr.2 at 14; PC 8 at 5-8; PC 10 at 3. Some participants recommend that the Board

maintain the statutory maximum of 5%. PC 8 at 9; Tr.2 at 16, 157. Some participants also

suggest the Agency seek legislative approval to increase the 5% maximum. Tr.2 at 16.

At hearing, the Agency explained the rationale for decreasing the 5% maximum to 2% in

2007. The Agency first noted that those EGUs that are eligible for the new source set-aside

allocation are those EGUs that began operation on or after January 1, 1995. Tr.1 at 84.

Therefore, when the implementation date occurs (May 31, 2004), roughly a decade’s worth of

new EGUs will get their allocations from this set-aside. Tr.2 at 84. However, the demand for

allowances from the set-aside will begin to decrease as of the year 2007, when the new EGUs

start drawing allowances from the flex portion of the NOx budget. Thus, beginning in 2007,

when the set-aside is set at the 2% maximum, the Agency anticipates that there will be fewer

new sources that apply for the allowances from the set-aside. Tr.1 at 84. The Agency also noted

in its prefiled testimony that the new source set-aside allocations follow the levels suggested in

the NOx SIP Call. Exh. 25 at 15.

Additionally, some participants argue that the proposal unduly favors the existing EGUs

over the new EGUs because the existing EGUs are guaranteed the “fixed” allocations, and the

new EGUs can only access the allocations available in the new source set-aside; they contend

that these are not enough to meet the projected demand. Tr.2 at 153-154; PC 8 at 8-12.

However, existing EGUs note that even with the fixed allocations, they will incur great costs to

comply with the new Subpart W. PC 5 at 4. Namely, they will be forced to achieve great control

levels due to the projected oversubscription in allowances. PC 5 at 4.

Other participants contend that the Agency’s allocation system is equitable, and should be

adopted by the Board.

e.g.

, PC 5 at 3, PC 6 at 3-4. They note that the Agency developed the

proposal only after extensive efforts to reach out to all interested parties, and that no stakeholder

was hindered from presenting its point of view. PC 5 at 3.

The Board concludes that the allocation system proposed by the Agency is fair and

reasonable. Additionally, the 5% change to 2% is consistent with the USEPA’s suggested

set-aside provision. Accordingly, the Board retains these provisions in today’s proposal.

Energy Efficiency/Renewable Energy Set-Aside

The American Lung Association

et al.

(Exh. 34 at 6-7; Tr.2 at 91-93), the Environmental

Law and Policy Center (PC 9), the Chicago Department of Environment (PC 10), and Enron

Corp. (PC 7), each recommend that the Board provide a set-aside for energy efficiency and

renewable energy measures. The Agency opposes this idea, but does not explain its basis for its

opposition. PC 3 at 28.

The Board believes that measures to increase energy efficiency are admirable and needed.

Similarly, the Board believes that reliable, cost-effective renewable energy needs to be

aggressively developed. However, the Board is not convinced that the set-aside proposal is an

appropriate or productive method to achieve these ends, especially in view of the small amount

of emission allowances available in Illinois.

Charges for Allowances

Proposed Section 217.768(k) contains a provision that would impose a market-rate fee on

allowances awarded to EGUs that start operations after January 1, 2004. Several participants

contend that this provision should be deleted or significantly modified.

e.g.,

Tr.2 at 17-18; PC 8

at 17. Specifically, some participants suggest that the allocation methodology favors existing

EGUs over new EGUs, because new EGUs that commence commercial operation on or after

January 1, 2004, and get allowances from the new source set-aside will have to pay for the

allocations. See proposed Section 217.768(k); Tr.2 at 17-18, 94-100, 157-159.

Section

9.9(d)(5)(B) of the Act allows the Agency to charge these EGUs for their allowances. 415 ILCS

5/9.9(d)(5)(B) (1998 State Bar Edition, 1999 Supp.). At first notice, proposed Section

217.768(k)(3) allowed the Agency, after covering administrative costs, to give fees collected

from the sale of allowances on a pro-rata basis to EGUs receiving allowances under Section

217.764. ABB Energy Ventures believes proposed Section 217.768(k)(3) mandates that new

EGUs subsidize existing EGUs, which they assert is unfair and places a disproportionate burden

on new EGUs. Tr.2 at 18, 22. If any fee is to be charged at all, ABB Energy Ventures argues the

fee should only cover the Agency’s administrative costs. Tr.2 at 18. Enviropower also argues

that the fees charged to the new sources should only cover the Agency’s administrative costs. PC

8 at 17.

The Agency responds that charging new EGUs for their allowances will deter sources

from asking for more allowances than they need, which will help limit oversubscription to the

new source set-aside. PC 3 at 13. The Agency further notes that charging for allowances is

allowed under Section 9.9. PC 3 at 13-14. Additionally, Section 9.9(i)(2) of the Act authorizes

the Agency to disburse the proceeds of the NOx allowances sales pro-rata to the EGUs that were

Other participants believe paying for allocations is appropriate. See PC 4 at 5.

not given allowances from the new source set-aside. See 415 ILCS 5/9.9(i)(2) (1998 State Bar

Edition, 1999 Supp.). The Board appreciates the participants’ concerns regarding the fees

charged for the allowances for the new source set-aside allowances. However, the Board will not

deviate from the Act’s provisions in this matter.

Upon review of all the comments, the Board agrees with the basic system proposed by the

Agency, and adopts it today for second notice. Today’s proposal incorporates minor technical

changes to the rules.

ECONOMIC AND TECHNICAL CONSIDERATION

Section 27(a) of the Act requires that in promulgating regulations, the Board “shall take

into account . . . the technical feasibility and economic reasonableness of measuring or reducing

the particular type of pollution.” 415 ILCS 5/27(a) (1998). Exh. 27 at 3 & 9-10; Tr.1 at 105-

106 and 249-252; Tr.2 at 36; Exh. 32 at 5. The Agency used the information contained in the

Alternative Control Techniques (ACT) documents

published by the USEPA as background

information. Further, the Agency relied on the information contained in the USEPA’s

Regulatory Impact Analysis for the NOx SIP Call (63 Fed. Reg. 57,356), the proposed Federal

Implementation Plan (FIP) (63 Fed. Reg. 56,394), and USEPA’s proposed findings on various

petitions filed under Section 126 of the CAAA (65 Fed. Reg. 2,674) to support its proposal. Exh.

27 and PC 3 at 19-20.

The USEPA’s analysis of the cost impact of the NOx SIP Call on large EGUs involved

the determination of the “cost effectiveness,” which is measured as the cost in dollars per ton of

NOx reduced, of various alternative NOx control levels. USEPA chose a NOx control level of

0.15 lbs per mmbtu to be highly cost effective for reducing emissions from large EGUs. 63 Fed.

Reg. 57,399 – 57,402. Based on this control level, the USEPA determined the average cost

effectiveness for NOx control on a region wide (23 jurisdictions) basis to be $1,468 per ton of

NOx. USEPA notes that for large EGUs the average cost effectiveness of $1,468 per ton of NOx

is consistent with the range of cost effectiveness for various control measures. 63 Fed. Reg.

57,401.

Although the Agency relies on the USEPA’s cost analysis to support its proposal, the

Agency performed its own cost impact analysis. The Agency determined the cost effectiveness

to be $1,486 per ton of NOx. Exh. 27 at 10. In addition, the U.S. Department of Energy also

made a separate analysis of the cost impact of the NOx SIP Call and found the cost effectiveness

to be $1,460 per ton of NOx. Exh. 27 at 10. All the three analyses included trading in their

assessments.

Ameren and Dynegy Midwest Generation expressed concerns regarding the Agency’s

compliance cost estimates. They assert that the costs of NOx control for their units would be

USEPA has published two ACT documents concerning control of NOx emissions from utility

boilers and gas turbines. These documents contain detailed description of the sources of NOx

emissions, various emissions control techniques and their costs.

much higher than the USEPA estimate. Ameren testified that it would cost Ameren $130 million

($8,784 per ton of NOx) to come into compliance with the proposed regulation. Tr.2 at 36 and

Exh. 32 at 5. They also noted that the incremental cost of reducing NOx emissions from a

control level of 0.25 lbs per mmbtu (0.25 rule) to the proposed control level of 0.15 lbs per

mmbtu would be $100 million. Dynegy Midwest Generation also stated that the Agency has

underestimated the compliance cost. They noted that the incremental cost of reducing NOx from

a control level of 0.25 lbs per mmbtu to the proposed control level of 0.15 lbs per mmbtu for

Dynegy Midwest Generaton would be $7,339 per ton of NOx over a five-year period or $4,582

per ton of NOx over a ten-year period. Exh. 41 at 6-7.

The Board believes that a principle factor that should be considered in determining the

economic impact of the proposed regulations is the flexibility afforded to the affected entities to

participate in a trading program to determine their compliance alternatives. As the Agency notes,

the USEPA determined that NOx control level of 0.15 lbs per mmbtu to be highly cost effective

in the realm of a trading program. The instant proposal does not require all affected units to

reduce NOx emissions by using control options. An affected unit may comply with the NOx

emissions limitation either by using control options or by purchasing the necessary allowances to

cover its emissions. Each affected source has to make a determination as to the compliance

option based on a number of factors such as the type of boiler, existing control technology, cost

of additional control, amount of emissions reductions, etc.

The Board recognizes that the cost of emissions control vary from unit to unit, as

illustrated in Ameren’s comments. PC 5, Attachment 2. Although the cost of achieving

compliance for a specific unit may exceed the average cost effectiveness determined by USEPA,

the Board believes that the economic impact of the proposed regulations must be evaluated in

terms of the overall cost imposed by the trading program. Regarding the affected sources’ cost

estimates, the Board agrees with the Agency that the use of incremental costs between two levels

of NOx control to show that the cost effectiveness of NOx control is significantly higher is

inappropriate. Any comparison of compliance costs of two different control levels should

consider differential costs between the two levels with respect to the base line emissions. PC 3 at

21. Moreover, the Board notes that the evaluation of even the differential costs is not relevant in

this proceeding since the instant regulations address only one NOx control level (0.15 lbs per

mmbtu) which the USEPA has determined to be highly cost effective.

In light of the above, the Board finds that the USEPA’s determination of average cost

effectiveness of $1,468 per ton of NOx for large EGUs to be reasonable. Further, the Board finds

that the proposed trading program provides flexibility to the affected sources to achieve

compliance at lower costs. The Board also notes that the average cost effectiveness of NOx

control for large EGUs is similar to the cost effectiveness of various VOC control measures

adopted by this Board pursuant to the CAAA. In addition, the Board finds that technically

feasible control technologies are available for reducing NOx emissions from large EGUs. In

sum, the Board finds that the proposed regulations for reducing NOx emissions from large EGUs

to be economically reasonable and technically feasible.

CONCLUSION

Pursuant to federal law, large EGUs in Illinois are required to significantly reduce

emissions of NOx during the ozone season. Faced with this circumstance, Illinois has sought,

within the parameters allowed us by federal and State law, to find an equitable and economic

method of bringing about that reduction.

The Board appreciates the extensive effort undertaken by various stakeholders in this

matter to inform both the Agency and us regarding their interests. We believe that the Agency

proposal strikes an appropriate balance among these various interests, and for this reason we

today adopt the Agency’s proposal, with minor modification, for second notice.

ORDER

The Board hereby proposes for second notice the following amendments to 35 Ill. Adm.

Code 211 and 217. The Clerk of the Board is directed to file these proposed rules with the Joint

Committee on Administrative Rules.

TITLE 35: ENVIRONMENTAL PROTECTION

SUBTITLE B: AIR POLLUTION

CHAPTER I: POLLUTION CONTROL BOARD

SUBCHAPTER c: EMISSION STANDARDS AND LIMITATIONS FOR

STATIONARY SOURCES

PART 211

DEFINITIONS AND GENERAL PROVISIONS

SUBPART A: GENERAL PROVISIONS

Section

211.101

Incorporations by Reference

211.102

Abbreviations and Conversion Factors

SUBPART B: DEFINITIONS

Definitions (Repealed)

Aerosol Can Filling Line

Air Oxidation Process

Air Pollution Control Equipment

211.430

Air Suspension Coater/Dryer

211.450

Airless Spray

211.470

Air Assisted Airless Spray

Animal Pathological Waste

211.490

Annual Grain Through-Put

211.495

Anti-Glare/Safety Coating

211.510

Application Area

211.530

Architectural Coating

211.550

As Applied

211.560

As-Applied Fountain Solution

Automobile or Light-Duty Truck Assembly Source or Automobile or Light-Duty

Truck Manufacturing Plant

211.650

Automobile or Light-Duty Truck Refinishing

211.660

Automotive/Transportation Plastic Parts

Basecoat/Clearcoat System

Brush or Wipe Coating

211.790

Bulk Gasoline Plant

211.810

Bulk Gasoline Terminal

211.820

Business Machine Plastic Parts

Certified Investigation

211.980

Chemical Manufacturing Process Unit

Cleaning and Separating Operation

Combined Cycle System

211.1316

Combustion Turbine

211.1320

Commence Commercial Operation

Concrete Curing Compounds

211.1390

Concentrated Nitric Acid Manufacturing Process

Continuous Automatic Stoking

Control Device Efficiency

211.1515

Control Period

211.1520

Conventional Air Spray

211.1530

Conventional Soybean Crushing Source

211.1550

Conveyorized Degreasing

Daily-Weighted Average VOM Content

Dry Cleaning Operation or Dry Cleaning Facility

Effluent Water Separator

211.1875

Elastomeric Materials

211.1880

Electromagnetic Interference/Radio Frequency (EMI/RFI) Shielding Coatings

211.1885

Electronic Component

211.1890

Electrostatic Bell or Disc Spray

211.1900

Electrostatic Prep Coat

211.1910

Electrostatic Spray

211.1920

Emergency or Standby Unit

End Sealing Compound Coat

211.2030

Enhanced Under-the-Cup Fill

211.2050

Ethanol Blend Gasoline

Existing Grain-Drying Operation (Repealed)

211.2130

Existing Grain-Handling Operation (Repealed)

External Floating Roof

211.2210

Extreme Performance Coating

Federally Enforceable Limitations and Conditions

Flexible Operating Unit

211.2370

Flexographic Printing

211.2390

Flexographic Printing Line

Fuel Combustion Emission Unit or Fuel Combustion Emission Source

211.2490

Fugitive Particulate Matter

211.2510

Full Operating Flowrate

Gasoline Dispensing Operation or Gasoline Dispensing Facility

Grain-Drying Operation

211.2690

Grain-Handling and Conditioning Operation

211.2710

Grain-Handling Operation

Gross Vehicle Weight Rating

Heatset Web Offset Lithographic Printing Line

Heavy Off-Highway Vehicle Products

211.2930

Heavy Off-Highway Vehicle Products Coating

211.2950

Heavy Off-Highway Vehicle Products Coating Line

211.2970

High Temperature Aluminum Coating

211.2990

High Volume Low Pressure (HVLP) Spray

Housekeeping Practices

211.3070

Incinerator

211.3090

Indirect Heat Transfer

In-Situ Sampling Systems

211.3170

Interior Body Spray Coat

211.3190

Internal-Floating Roof

211.3210

Internal Transferring Area

Large Appliance Coating

211.3290

Large Appliance Coating Line

Lithographic Printing Line

Magnet Wire Coating Line

211.3570

Major Dump Pit

211.3590

Major Metropolitan Area (MMA)

211.3610

Major Population Area (MPA)

211.3620

Manually Operated Equipment

211.3630

Manufacturing Process

Material Recovery Section

211.3690

Maximum Theoretical Emissions

211.3695

Maximum True Vapor Pressure

211.3710

Metal Furniture

211.3730

Metal Furniture Coating

211.3750

Metal Furniture Coating Line

211.3770

Metallic Shoe-Type Seal

211.3790

Miscellaneous Fabricated Product Manufacturing Process

211.3810

Miscellaneous Formulation Manufacturing Process

211.3830

Miscellaneous Metal Parts and Products

211.3850

Miscellaneous Metal Parts and Products Coating

211.3870

Miscellaneous Metal Parts or Products Coating Line

211.3890

Miscellaneous Organic Chemical Manufacturing Process

Motor Vehicle Refinishing

211.3970

Multiple Package Coating

211.3980

Nameplate Capacity

211.3990

New Grain-Drying Operation (Repealed)

211.4010

New Grain-Handling Operation (Repealed)

211.4030

No Detectable Volatile Organic Material Emissions

211.4050

Non-Contact Process Water Cooling Tower

One Hundred Percent Acid

211.4110

One-Turn Storage Space

Open Top Vapor Degreasing

211.4190

Open-Ended Valve

211.4210

Operator of a Gasoline Dispensing Operation or Operator of a Gasoline

Organic Material and Organic Materials

Owner of a Gasoline Dispensing Operation or Owner of a Gasoline Dispensing

Packaging Rotogravure Printing

211.4410

Packaging Rotogravure Printing Line

211.4430

Pail

211.4450

Paint Manufacturing Source or Paint Manufacturing Plant

Parts Per Million (Volume) or PPM (Vol)

Pharmaceutical Coating Operation

211.4690

Photochemically Reactive Material

Pneumatic Rubber Tire Manufacture

211.4810

Polybasic Organic Acid Partial Oxidation Manufacturing Process

211.4830

Polyester Resin Material(s)

211.4850

Polyester Resin Products Manufacturing Process

Portable Grain-Handling Equipment

211.4930

Portland Cement Manufacturing Process Emission Source

211.4950

Portland Cement Process or Portland Cement Manufacturing Plant

211.4960

Potential Electrical Output Capacity

211.4970

Potential to Emit

211.4990

Power Driven Fastener Coating

Pressure/Vacuum Relief Valve

211.5061

Pretreatment Wash Primer

Primer Surfacer Operation

Process Emission Source

211.5190

Process Emission Unit

211.5210

Process Unit

211.5230

Process Unit Shutdown

Production Equipment Exhaust System

211.5310

Publication Rotogravure Printing Line

211.5330

Purged Process Fluid

211.5340

Rated Heat Input Capacity

211.5350

Reactor

211.5370

Reasonably Available Control Technology (RACT)

Refinery Fuel Gas System

211.5470

Refinery Unit or Refinery Process Unit

211.5480

Reflective Argent Coating

211.5490

Refrigerated Condenser

211.5500

Regulated Air Pollutant

Rotogravure Printing Line

Semi-Transparent Stains

211.5930

Sensor

211.5950

Set of Safety Relief Valves

Single Unit Operation

Solvent Recovery System

Specialty Coatings for Motor Vehicles

211.6150

Specialty High Gloss Catalyzed Coating

211.6170

Specialty Leather

211.6190

Specialty Soybean Crushing Source

Standard Cubic Foot (scf)

211.6310

Start-Up

211.6330

Stationary Emission Source

211.6350

Stationary Emission Unit

211.6355

Stationary Gas Turbine

211.6360

Stationary Reciprocating Internal Combustion Engine

211.6370

Stationary Source

211.6390

Stationary Storage Tank

211.6400

Stencil Coat

211.6410

Storage Tank or Storage Vessel

211.6420

Strippable Spray Booth Coating

211.6430

Styrene Devolatilizer Unit

211.6450

Styrene Recovery Unit

211.6470

Submerged Loading Pipe

Surface Preparation Materials

211.6550

Synthetic Organic Chemical or Polymer Manufacturing Plant

211.6570

Tablet Coating Operation

211.6580

Texture Coat

211.6590

Thirty-Day Rolling Average

211.6610

Three-Piece Can

211.6620

Three or Four Stage Coating System

211.6630

Through-the-Valve Fill

Uniform Finish Blender

211.6870

Unregulated Safety Relief Valve

211.6880

Vacuum Metallizing

211.6890

Vacuum Producing System

211.6910

Vacuum Service

211.6930

Valves Not Externally Regulated

211.6950

Vapor Balance System

211.6970

Vapor Collection System

211.6990

Vapor Control System

211.7010

Vapor-Mounted Primary Seal

211.7030

Vapor Recovery System

211.7050

Vapor-Suppressed Polyester Resin

Volatile Organic Liquid (VOL)

211.7130

Volatile Organic Material Content (VOMC)

211.7150

Volatile Organic Material (VOM) or Volatile Organic Compound (VOC)

211.7170

Volatile Petroleum Liquid

Wastewater (Oil/Water) Separator

211.7230

Weak Nitric Acid Manufacturing Process

211.7250

Web

211.7270

Wholesale Purchase - Consumer

211.7290

Wood Furniture

211.7310

Wood Furniture Coating

211.7330

Wood Furniture Coating Line

Rule into Section Table

211.Appendix B

Section into Rule Table

AUTHORITY: Implementing Sections 9, 9.1, 9.9, and 10 and authorized by Sections 27 and

28.5 of the Environmental Protection Act [415 ILCS 5/9, 9.1, 9.9, 10, 27 and 28.5].

SOURCE: Adopted as Chapter 2: Air Pollution, Rule 201: Definitions, R71-23, 4 PCB 191,

filed and effective April 14, 1972; amended in R74-2 and R75-5, 32 PCB 295, at 3 Ill. Reg. 5, p.

777, effective February 3, 1979; amended in R78-3 and 4, 35 PCB 75 and 243, at 3 Ill. Reg. 30,

p. 124, effective July 28, 1979; amended in R80-5, at 7 Ill. Reg. 1244, effective January 21,

1983; codified at 7 Ill. Reg. 13590; amended in R82-1 (Docket A) at 10 Ill. Reg. 12624, effective

July 7, 1986; amended in R85-21(A) at 11 Ill. Reg. 11747, effective June 29, 1987; amended in

R86-34 at 11 Ill. Reg. 12267, effective July 10, 1987; amended in R86-39 at 11 Ill. Reg. 20804,

effective December 14, 1987; amended in R82-14 and R86-37 at 12 Ill. Reg. 787, effective

December 24, 1987; amended in R86-18 at 12 Ill. Reg. 7284, effective April 8, 1988; amended in

R86-10 at 12 Ill. Reg. 7621, effective April 11, 1988; amended in R88-23 at 13 Ill. Reg. 10862,

effective June 27, 1989; amended in R89-8 at 13 Ill. Reg. 17457, effective January 1, 1990;

amended in R89-16(A) at 14 Ill. Reg. 9141, effective May 23, 1990; amended in R88-30(B) at 15

Ill. Reg. 5223, effective March 28, 1991; amended in R88-14 at 15 Ill. Reg. 7901, effective May

14, 1991; amended in R91-10 at 15 Ill. Reg. 15564, effective October 11, 1991; amended in R91-

6 at 15 Ill. Reg. 15673, effective October 14, 1991; amended in R91-22 at 16 Ill. Reg. 7656,

effective May 1, 1992; amended in R91-24 at 16 Ill. Reg. 13526, effective August 24, 1992;

amended in R93-9 at 17 Ill. Reg. 16504, effective September 27, 1993; amended in R93-11 at 17

Ill. Reg. 21471, effective December 7, 1993; amended in R93-14 at 18 Ill. Reg. 1253, effective

January 18, 1994; amended in R94-12 at 18 Ill. Reg. 14962, effective September 21, 1994;

amended in R94-14 at 18 Ill. Reg. 15744, effective October 17, 1994; amended in R94-15 at 18

Ill. Reg. 16379, effective October 25, 1994; amended in R94-16 at 18 Ill. Reg. 16929, effective

November 15, 1994; amended in R94-21, R94-31 and R94-32 at 19 Ill. Reg. 6823, effective May

9, 1995; amended in R94-33 at 19 Ill. Reg. 7344, effective May 22, 1995; amended in R95-2 at

19 Ill. Reg. 11066, effective July 12, 1995; amended in R95-16 at 19 Ill. Reg. 15176, effective

October 19, 1995; amended in R96-5 at 20 Ill. Reg. 7590, effective May 22, 1996; amended in

R96-16 at 21 Ill. Reg. 2641, effective February 7, 1997; amended in R97-17 at 21 Ill. Reg. 6489,

effective May 16, 1997; amended in R97-24 at 21 Ill. Reg. 7695, effective June 9, 1997;

amended in R96-17 at 21 Ill. Reg. 7856, effective June 17, 1997; amended in R97-31 at 22 Ill.

Reg. 3497, effective February 2, 1998; amended in R98-17 at 22 Ill. Reg.11405, effective June

22, 1998; amended in R01-09 at ____ Ill. Reg. ________, effective ____________________.

BOARD NOTE: This Part implements the Illinois Environmental Protection Act as of July 1,

1994.

Section 211.102

Abbreviations and Conversion Factors

Abbreviations used in this Part include the following:

ASTM

American Society for Testing and Materials

bbl

barrels (42 gallons)

btu

British thermal units (60

btu/hr

btu per hour

degrees Celsius or centigrade

CAAPP

Clean Air Act Permit Program

Electrical Generating Unit

degrees Fahrenheit

FIP

Federal Implementation Plan

kilopascals; one thousand newtons per square meter

lower explosive limit

Megagrams, metric tons or tonnes

million British thermal units

mmbtu/hr

million British thermal units per hour

mmHg

millimeters of mercury

MTE

maximum theoretical emissions

MWe

megawatt of electricity

megawatt; one million watts

MW-hr

megawatt per hour

NDO

natural draft opening

nitrogen oxides

peoc

potential electrical output capacity

ppm (vol)

parts per million

ppmv

parts per million by volume

ppmvd

parts per million by volume dry

psi

pounds per square inch

psia

pounds per square inch absolute

psig

pounds per square inch gauge

PTE

potential to emit

RACT

reasonably available control technology

scf

standard cubic feet

scm

standard cubic meters

sec

seconds

SIP

State Implementation Plan

TTE

temporary total enclosure

short ton (2,000 lbs)

ton

short ton (2,000 lbs)

TPY

tons per year

USEPA

United States Environmental Protection Agency

VOC

volatile organic compounds

VOL

volatile organic liquids

VOM

volatile organic materials

The following conversion factors have been used in this Part:

6.897 kPA (51.71 mmHg)

(Source: Amended at ____ Ill. Reg. ________, effective ____________________)

Section 211.479

Allowance

“Allowance” means an authorization to emit up to one ton of NO

during the control period of a

specified year or any year thereafter under 35 Ill. Adm. Code 217 and 40 CFR part 96.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 211.1312

Combined Cycle System

“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.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 211.1316

Combustion Turbine

“Combustion Turbine” means an enclosed fossil or other fuel-fired device that is comprised of 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.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 211.1320

Commence Commercial Operation

For purposes of allocation of allowances as described in 35 Ill. Adm. Code 217, “commence

commercial operation” means, 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 shall remain the unit’s date of commencement of operation even if the

EGU is subsequently modified, reconstructed or repowered.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 211. 1324

Commence Operation

For purposes of allocation of allowances as described in 35 Ill. Adm. Code 217, “commence

operation” means with regard to a stationary boiler, combustion turbine, or combined cycle

system to have begun any mechanical, chemical, or electronic process, including, start-up of the

unit’s combustion chamber. Such date shall remain the unit’s date of commencement of

operation even if the unit is subsequently modified, reconstructed, or repowered.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 211.1328

Common Stack

“Common stack” means a single flue through which emissions from two or more units are

exhausted.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 211.1515

Control Period

For purposes of 35 Ill. Adm. Code 217, “control period” means the period beginning May 1 of a

year and ending on September 30 of the same year, inclusive, except that in 2004, “control

period” means May 31 through September 30.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 211.2080

Excess Emissions

“Excess emissions” means any tonnage of NO

emitted by a NO

budget unit during a control

period that exceeds the NO

allowances available for compliance deduction for the unit and for a

control period.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 211.2420

Fossil Fuel

“Fossil fuel” means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel

derived from such material.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 211.2425

Fossil Fuel-Fired

“Fossil fuel-fired” means the combustion of fossil fuel, alone or in combination with any other

fuel, where fossil fuel actually combusted comprises or is projected to comprise more than 50

percent of the annual heat input on a btu basis during any year.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 211.2620

Generator

“Generator” means a device that produces electricity.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 211.2815

Heat Input

“Heat input” means the product of the gross heating value of the fuel and the amount of fuel

combusted in a combustion device. Heat input does not include the heat derived from preheated

combustion air, recirculated flue gases, or exhaust from other sources.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 211.2820

Heat Input Rate

“Heat input rate” means the amount of heat input used by a combustion device, divided by its

operating time (in hrs).

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 211.3980

Nameplate Capacity

“Nameplate capacity” means the maximum electrical generating output (in MWe) that a

generator can sustain over a specified period of time when not restricted by seasonal or other

deratings as measured in accordance with the United States Department of Energy standards.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 211.4960

Potential Electrical Output Capacity

“Potential electrical output capacity” means the MWe capacity rating for the units which shall be

equal to 33% of the maximum design heat input capacity of the steam generating unit.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 211.5580

Repowering

For purposes of 35 Ill. Adm. Code 217, Subpart W, “repowering” means the conversion or

replacement of an existing budget EGU, as identified in Appendix F, with a technology capable

of controlling NO

and other combustion emissions simultaneously with improved boiler or

generation efficiency and with waste reduction, or any other replacement generation technology

as determined by the Illinois Environmental Protection Agency. Repowering shall be considered

a control technology for purposes of 35 Ill. Adm. Code 217.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

TITLE 35: ENVIRONMENTAL PROTECTION

SUBTITLE B: AIR POLLUTION

CHAPTER I: POLLUTION CONTROL BOARD

SUBCHAPTER c: EMISSION STANDARDS AND LIMITATIONS FOR

STATIONARY SOURCES

PART 217

NITROGEN OXIDES EMISSIONS

SUBPART A: GENERAL PROVISIONS

Section

217.100

Scope and Organization

217.101

Measurement Methods

217.102

Abbreviations and Units

217.103

Definitions

217.104

Incorporations by Reference

SUBPART B: NEW FUEL COMBUSTION EMISSION SOURCES

Section

217.121

New Emission Sources

SUBPART C: EXISTING FUEL COMBUSTION EMISSION SOURCES

Section

217.141

Existing Emission Sources in Major Metropolitan Areas

SUBPART K: PROCESS EMISSION SOURCES

Section

217.301

Industrial Processes

SUBPART O: CHEMICAL MANUFACTURE

Section

217.381

Nitric Acid Manufacturing Processes

SUBPART V: ELECTRIC POWER GENERATION

Section

217.521

Lake of Egypt Power Plant

SUBPART W: NO

TRADING PROGRAM FOR ELECTRICAL

Compliance Requirements

217.758

Permitting Requirements

217.760

Trading Budget

217.762

Methodology for Calculating NO

Allocations for Budget Electrical Generating

Units (“EGUs”)

217.764

Allocations for Budget EGUs

217.768

New Source Set-Asides for “New” Budget EGUs

217.770

Early Reduction Credits for Budget EGUs

Budget Opt-In Units: Withdrawal from NO

Trading Program

217.780

Opt-In Units: Change in Regulatory Status

217.782

Allowance Allocations to Budget Opt-In Units

APPENDIX A

Rule into Section Table

APPENDIX B

Section into Rule Table

APPENDIX C

Compliance Dates

APPENDIX D Non-Electrical Generating Units

APPENDIX F

Allowances for Electrical Generating Units

AUTHORITY: Implementing Sections 9.9 and 10 and authorized by Sections 27 and 28.5 of the

Environmental Protection Act (Ill. Rev. Stat. 1981, ch. 111 ½, pars. 1010 and 1027) [415 ILCS

5/9.9, 10, 27, and 28.5.]

SOURCE: Adopted as Chapter 2: Air Pollution, Rule 207: Nitrogen Oxides Emissions, R71-

23, 4 PCB 191, April 13, 1972, filed and effective April 14, 1972; amended at 2 Ill. Reg. 17, p.

101, effective April 13, 1978; codified at 7 Ill. Reg. 13609; amended in R01-9 at _____ Ill. Reg.

____, effective ____________________.

SUBPART A: GENERAL PROVISIONS

Section 217.100

Scope and Organization

This Part sets standards and limitations for emission of oxides of nitrogen from

stationary sources.

Permits for sources subject to this Part may be required pursuant to 35 Ill. Adm.

Code 201.

Notwithstanding the provisions of this Part the air quality standards contained in

35 Ill. Adm. Code 243 may not be violated.

This Part is divided into Subparts which are grouped as follows:

Subpart A: General Provisions;

Subparts B-J: Fuel Combustion Sources and Incinerators;

Subparts K-M: Process Emission Sources;

Subparts N-End: Industry and Site-specific rules.

These rules have been grouped for convenience of the public; the scope of each is

determined by its language and history.

(Source: Amended at ____ Ill. Reg. ________, effective ____________________)

Section 217.101

Measurement Methods

Measurement of nitrogen oxides shall be according to:

The the phenol disulfonic acid method, 36 Fed. Reg. 15, 718 40 CFR 60,

Appendix A, Method 7. (1999); and

Continuous emissions monitoring pursuant to 40 CFR 75 (1999).; and

Determination of Nitrogen Oxides Emissions from Stationary Sources

(Instrumental Analyzer Procedure), 40 CFR 60, Appendix A, Method 7E (1999).

(Source: Amended at ____ Ill. Reg. ________, effective ____________________)

Section 217.102

Abbreviations and Units

The following abbreviations are used in this Part:

btu

British thermal unit (60

EGU

Electrical Generating Unit

kilogram

kg/MW-hr

kilograms per megawatt-hour, usually used as an hourly emission

pounds per million btu, usually used as an hourly emission rate

megagram or metric tonne

mmbtu

million British thermal units

mmbtu/hr

million British thermal units per hour

MWe

megawatt of electricity

megawatt; one million watts

MW-hr

megawatt-hour

peoc

potential electrical output capacity

ppm

parts per million

ppmv

parts per million by volume

English ton

The following conversion factors have been used in this Part:

(Source: Amended at ____ Ill. Reg. ________, effective ____________________)

Section 217.104

Incorporations by Reference

The following materials are incorporated by reference. These incorporations do not include any

later amendments or editions.

The the phenol disulfonic acid method as published in 36 Fed. Reg. 15, 718, 40

CFR 60, Appendix A, Method 7. (1999);

40 CFR 96, subparts B, D, G and H (1999);

40 CFR 96.1 through 96.3, 96.5 through 96.7, 96.50 through 96.54, 96.55 (a) &

(b), 96.56 and 96.57 (1999); and

40 CFR 72, 75 & 76 (1999).

(Source: Amended at ____ Ill. Reg. ________, effective ____________________)

SUBPART W: NO

TRADING PROGRAM FOR ELECTRICAL GENERATING

UNITS

Section 217.750

Purpose

The purpose of this Subpart is to control the emissions of nitrogen oxides (NO

) during the ozone

control period (May 1 through September 30 of each year, except that in 2004, “control period”

means May 31 through September 30) from electrical generating units (EGUs) by determining

source allocations and implementing the NO

Trading Program pursuant to 40 CFR 96, as

authorized by Section 9.9 of the Act [415 ILCS 5/9.9].

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 217.752

Severability

If any Section, subsection or clause of this Subpart is found invalid, such finding shall not affect

the validity of this Subpart as a whole or any Section, sentence or clause not found invalid.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 217.754

Applicability

The following fossil fuel-fired stationary boilers, combustion turbines or

combined cycle systems are electrical generating units (EGUs) and are subject to

this Subpart:

Any unit serving a generator that has a nameplate capacity greater than 25

MWe and produces electricity for sale, excluding those units listed in

Appendix D of this Part.

Any unit with a maximum design heat input that is greater than 250

mmbtu/hr that commences operation on or after January 1, 1999, serving

at any time a generator that has a nameplate capacity of 25 MWe or less

and has the potential to use more than 50% of the potential electrical

output capacity of the unit. Fifty percent (50%) of a unit’s potential

electrical output capacity shall be determined by multiplying the unit’s

maximum design heat input by 0.0488 MWe/mmbtu. If the size of the

generator is greater than this calculated number, the unit is an EGU subject

to the provisions of this Subpart.

Those units that meet the above criteria and are subject to the NO

Trading

Program emissions limitations contained in this Subpart are budget EGUs.

Low-emitter status: Notwithstanding subsection (a) of this Section, the owner or

operator of a budget EGU under subsection (a) of this Section may elect low-

emitter status by obtaining a permit with federally enforceable conditions meeting

the requirements of subsection (c)(1) of this Section. Starting with the effective

date of such permit, the EGU shall not be a budget EGU and shall be subject only

to the requirements of this subsection (c).

For each control period under this subsection (c), the federally enforceable

permit conditions must:

Restrict the EGU to burning only natural gas, fuel oil, or natural

gas and fuel oil;

Limit the EGU’s potential NO

mass emissions for the control

period to 25 tons or less;

Restrict the EGU’s operating hours during the control period to the

number calculated by dividing 25 tons of potential NO

mass

emissions by the EGU’s maximum potential hourly NO

mass

emissions;

Require that the EGU’s potential NO

mass emissions be

calculated by using the monitoring provisions of 40 CFR 75 or, if

the EGU does not rely on these monitoring provisions, by using the

applicable default rate, as follows:

Select the applicable default NO

emission rate from one of

the following:

0.7 lb/mmbtu for combustion turbines burning natural gas

exclusively during the control period;

1.2 lbs/mmbtu for combustion turbines burning any fuel oil

during the control period;

1.5 lbs/mmbtu for boilers burning natural gas exclusively

during the control period; or

2 lbs/mmbtu for boilers burning any fuel oil during the

control period.

ii)

Multiply the default NO

emission rate under subsection

(c)(1)(D)(i) of this Section by the EGU’s unit-specific

maximum rated heat input (mmbtu), which is the higher of

the manufacturer’s maximum rated hourly heat input or the

highest observed hourly heat input. The owner or operator

of the EGU may request in the permit application required

by this subsection (c) that the Agency use a lower value for

the EGU’s maximum rated hourly heat input. The Agency

may approve such lower value if the owner or operator

demonstrates that the maximum hourly heat input specified

by the manufacturer or the highest observed hourly heat

input, or both, are not representative. The owner or

operator must also demonstrate that such lower value is

representative of the EGU’s current capabilities because

modifications have been made to the EGU that permanently

limit the EGU’s capacity;

Require that the owner or operator of the EGU retain for five years,

at the source that includes the EGU, records demonstrating that the

operating hours restriction, the fuel use restriction, and the other

requirements of the permit related to these restrictions were met;

and

Require that the owner or operator of the EGU report to the

Agency the EGU’s hours of operation (treating any partial hour of

operation as a whole hour of operation), heat input, and fuel use by

type during each control period. This report shall be submitted by

November 1 of each year the EGU elects low-emitter status.

The Agency will notify USEPA in writing of each EGU electing low-

emitter status pursuant to the requirements of subsection (c)(1) of this

Section and when any of the following occurs:

The permit with federally enforceable conditions that includes the

restrictions in subsection (c)(1) of this Section is issued by the

Agency;

Such permit is revised to remove any such restriction;

Such permit includes any such restriction that is no longer

applicable; or

The EGU does not comply with any such restriction.

The EGU shall become a budget EGU, subject to the requirements of this

Subpart if, for any control period under subsection (c) of this Section, the

fuel use restriction or the operating hours restriction under subsection

(c)(1) of this Section is removed from the EGU’s permit or otherwise

becomes no longer applicable, or the EGU does not comply with the fuel

use restriction or the operating hours restriction under subsection (c)(1) of

this Section. Such EGU shall be treated as commencing operation and, for

a unit under subsection (a)(1) of this Section, commencing commercial

operation, on September 30 of the year prior to the control period for

which the fuel use restriction or the operating hours restriction is no longer

applicable or during which the EGU does not comply with the fuel use

restriction or the operating hours restriction.

The owner or operator of an EGU to which the Agency has ever allocated

allowances may elect low-emitter status. In that case, the Agency will

reduce the EGU trading budget by the number of allowances

corresponding to the amount of NO

emissions the EGU is permitted to

emit during the control period as set forth in the EGU’s federally

enforceable state operating permit.

Notwithstanding the provisions in subsection (a) of this Section, sources may opt-

in to the NO

Trading Program and will receive allowance allocations consistent

with applicable requirements, if they meet the requirements for a budget opt-in

unit pursuant to Sections 217.774 through 217.782 of this Part.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 217.756

Compliance Requirements

All EGUs subject to the requirements of this Subpart must comply with the following:

The requirements of this Subpart and 40 CFR 96 (excluding 40 CFR 96.4(b) and

96.55(c), and excluding 40 CFR 96, Subparts C, E, and I) as incorporated by

reference in Section 217.104 of this Part.

Permit requirements:

The owner or operator of each source with one or more budget EGUs at

the source must apply for a permit issued by the Agency with federally

enforceable conditions covering the NO

Trading Program (“budget

permit”) that complies with the requirements of Section 217.758 of this

Part.

The owner or operator of each budget source and each budget EGU at the

source must operate the budget EGU in compliance with such budget

permit.

Monitoring requirements:

The owner or operator of each budget source and each budget EGU at the

source must comply with the monitoring requirements of 40 CFR 96,

subpart H. The account representative of each budget source and each

budget EGU at the source must comply with those sections of the

monitoring requirements of 40 CFR 96, subpart H, applicable to an

account representative.

The compliance of each budget EGU with the budget emissions limitation

under subsection (d) of this Section shall be determined by the emissions

measurements recorded and reported in accordance with 40 CFR 96,

subpart H.

requirements:

By November 30 of each year, the allowance transfer deadline, the account

representative of each budget source and each budget EGU at the source

shall hold allowances available for compliance deductions under 40 CFR

96.54 in the budget EGU’s compliance account or the source's overdraft

account. The number of allowances held shall not be less than the budget

EGU’s total tons of NO

emissions for the control period, rounded to the

nearest whole ton, as determined in accordance with 40 CFR 96, subpart

H, plus any number necessary to account for actual utilization (e.g., for

testing, start-up, malfunction, and shut down) under 40 CFR 96.42(e) for

the control period.

Each ton of NO

emitted in excess of the number of NO

allowances held

by the owner or operator for each budget EGU for each control period

shall constitute a separate violation of this Part and the Act.

A budget EGU shall be subject to the monitoring and NO

requirements of

subsections (c)(1) and (d)(1) of this Section starting on the later of May 1,

2003May 31, 2004, the date on which the EGU commences OR THE

FIRST DAY OF THE CONTROL SEASON SUBSEQUENT TO THE

CALENDAR YEAR IN WHICH ALL OF THE OTHER STATES

SUBJECT TO THE PROVISIONS OF THE NO

SIP CALL (63 Fed.

Reg. 57355 (October 27, 1998)) THAT ARE LOCATED IN USEPA

REGION V OR THAT ARE CONTIGUOUS TO ILLINOIS HAVE

ADOPTED REGULATIONS TO IMPLEMENT NO

TRADING

PROGRAMS AND OTHER REQUIRED REDUCTIONS OF NO

EMISSIONS PURSUANT TO THE NO

SIP CALL, AND SUCH

REGULATIONS HAVE RECEIVED FINAL APPROVAL BY USEPA

AS PART OF THE RESPECTIVE STATES’ SIPS FOR OZONE, OR A

FINAL FIP FOR OZONE PROMULGATED BY USEPA IS

EFFECTIVE.

Allowances shall be held in, deducted from, or transferred among

allowance accounts in accordance with this Subpart and 40 CFR 96,

subparts F and G, and Sections 217.774 through 217.782 of this Part.

In order to comply with the requirements of subsection (d)(1) of this

Section, an allowance may not be utilized for a control period in a year

prior to the year for which the allowance is allocated.

An allowance allocated by the Agency or USEPA under the NO

Trading

Program is a limited authorization to emit one ton of NO

in accordance

with the NO

Trading Program. No provision of the NO

Trading

Program, the budget permit application, the budget permit, or a retired unit

exemption under 40 CFR 96.5, and no provision of law shall be construed

to limit the authority of the United States or the State to terminate or limit

this authorization.

An allowance allocated by the Agency or USEPA under the NO

Trading

Program does not constitute a property right.

Upon recordation by USEPA under 40 CFR 96, subpart F or G, or Section

217.782 of this Part, every allocation, transfer, or deduction of an

allowance to or from a budget EGU’s compliance account or to or from

the overdraft account of the budget source where the budget EGU is

located is deemed to amend automatically, and become a part of, any

budget permit of the budget EGU. This automatic amendment of the

budget permit shall be deemed an operation of law and will not require any

further review.

Recordkeeping and reporting requirements:

Unless otherwise provided, the owner or operator of the budget source and

each budget EGU at the source shall 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.

The account certificate of representation of the account

representative for the source and each budget EGU at the source,

all documents that demonstrate the truth of the statements in the

account certificate of representation, in accordance with 40 CFR

96.13, provided that the certificate and documents must be retained

on site at the source beyond such five-year period until such

documents are superseded because of the submission of a new

account certificate of representation changing the account

representative.

All emissions monitoring information, in accordance with 40 CFR

96, subpart H, provided that to the extent that 40 CFR 96, subpart

H provides for a three-year period for recordkeeping, the three-year

period shall apply.

Copies of all reports, compliance certifications, and other

submissions and all records made or required under the NO

Trading Program or documents necessary to demonstrate

compliance with the requirements of the NO

Trading Program or

with the requirements of this Subpart.

Copies of all documents used to complete a budget permit

application and any other submission under the NO

Trading

Program.

The account representative of a budget source and each budget EGU at the

source must submit to the Agency and USEPA the reports and compliance

certifications required under the NO

Trading Program, including those

under 40 part CFR 96, subparts D and H, and Section 217.774 of this Part.

Liability:

No revision of a permit for a budget EGU shall excuse any violation of the

requirements of the NO

Trading Program that occurs prior to the date that

the revision to such budget permit takes effect.

Each budget source and each budget EGU shall meet the requirements of

the NO

Trading Program.

Any provision of the NO

Trading Program that applies to a budget source

(including any provision applicable to the account representative of a

budget source) shall also apply to the owner and operator of such budget

source and to the owner and operator of each budget EGU at the source.

Any provision of the NO

Trading Program that applies to a budget EGU

(including any provision applicable to the account representative of a

budget EGU) shall also apply to the owner and operator of such budget

EGU. Except with regard to the requirements applicable to budget EGUs

with a common stack under 40 CFR 96, subpart H, the owner and operator

and the account representative of one budget EGU shall not be liable for

any violation by any other budget EGU of which they are not an owner or

operator or the account representative.

Excess emissions requirements. The account representative of a budget

EGU that has excess emissions in any control period shall:

S surrender the allowances as required for deduction under 40 CFR

96.54(d)(1); and.

PayThe owner or operator of a budget EGU that has excess

emissions in any control period shall pay any fine, penalty, or assessment

or comply with any other remedy imposed under 40 CFR 96.54(d)(3) and

the Act.

Effect on other authorities. No provision of the NO

Trading Program, a budget

permit application, a budget permit, a low-emitter exemption under Section

217.754(c) of this Subpart,40 CFR 96.4(b), or a retired unit exemption under 40

CFR 96.5 shall be construed as exempting or excluding the owner and operator

and, to the extent applicable, the account representative of a budget source or

budget EGU, from compliance with any other regulation promulgated under the

CAA, the Act, an approved State implementation plan, or a federally enforceable

permit.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 217.758

Permitting Requirements

Budget permit requirements:

Each source with a budget EGU is required to submit a complete permit

application addressing all applicable NO

Trading Program requirements

for a permit meeting the requirements of this Section, applicable to each

budget EGU at the source. Each budget permit (including any draft or

proposed budget permit, if applicable) will contain elements required for a

complete budget permit application under subsection (b)(2) of this

Section.

Each budget permit (including a draft or proposed budget permit, if

applicable) shall contain federally enforceable conditions addressing all

applicable NO

Trading Program requirements and shall be a complete and

segregable portion of the source’s entire permit under subsection (a)(1) of

this Section.

No budget permit shall be issued, and no NO

allowance account shall be

established for a budget EGU at a source, until the Agency and USEPA

have received a complete account certificate of representation under 40

CFR 96, subpart B, for an account representative of the source and the

budget EGU at the source.

For budget EGUs that commenced operation before November 1, 2003,

and for which a CAAPP permit is not required pursuant to Section 39.5 of

the Act, the owner or operator of such unit must submit a budget permit

application meeting the requirements of this Section on or before

November 1, 2003.

For budget EGUs that commenced operation before August 1, 2003, and

for which a CAAPP permit is required pursuant to Section 39.5 of the Act,

the owner or operator of such unit must submit a budget permit application

meeting the requirements of this Section on or before August 1, 2003.

For budget EGUs that are subject to Section 39.5 of the Act and that

commence operation on or after August 1, 2003, and for budget EGUs not

subject to Section 39.5 of the Act and that commence operation on or after

November 1, 2003, 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 and 35 Ill.Adm.Code 201

and such applications must specify that they are applying for budget

permits, and must address the budget permit application requirements of

this Section.

Budget permit applications:

Duty to apply. The owner or operator of any source with one or more

budget EGUs shall submit to the Agency a complete budget permit

application for the source under subsection (b)(2) of this Section by the

applicable deadline in subsection (a)(4), (a)(5), or (a)(6) of this Section.

The owner or operator of any source with one or more budget EGUs shall

reapply for a budget permit for the source as required by this Subpart, 35

Ill. Adm. Code 201, and Sections 39 and 39.5 of the Act.

Information requirements for budget permit applications. A complete

budget permit application shall include the following elements concerning

the source for which the application is submitted:

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

shall also be included, if applicable;

Identification of each budget EGU at the source. An explanation

of whether each EGU is a budget EGU under Section 217.754 or

217.774 of this Part;

The compliance requirements of Section 217.756 of this Part; and

For each opt-in unit at the source the following certification

statements by the account representative:

“I certify that each unit for which this permit application is

submitted under Section 217.774 of this Part is not a budget

EGU under Section 217.754 of this Part and is not covered

by a retired unit exemption that is in effect under 40 CFR

96.5.”

ii)

If the application is for an initial budget permit, “I certify

that each unit for which this permit application is submitted

under Section 217.774 of this Part, and has documented

heat input for more than 876 hours in the six months

immediately preceding the submission of an application for

an initial budget permit under Section 217.774(d) of this

Part.”

An application for a budget permit shall be treated as a modification of the

EGU’s existing federally enforceable permit, if such a permit has been

issued for that EGU, and shall be subject to the same procedural

requirements. When the Agency issues a budget permit, it shall be

incorporated into and become part of that EGU’s existing federally

enforceable permit.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 217.760

Trading Budget

The NO

trading budget available for allowance allocations for each control period shall be

determined as follows:

The total base EGU trading budget is 30,701 tons per control period subject,

however, to the following:

In 2004 through 2006, 5% of this number shall be allocated to the new

source set-aside under Section 217.768 of this Part, resulting in an EGU

trading budget of 29,166 tons available for allocation per control period;

and

In 2007 and thereafter, 2% of this amount shall be allocated to the new

source set-aside, resulting in an EGU trading budget of 30,087 tons

available for allocation per control period.

The Agency maymust adjust the total base EGU trading budget available for

allocation in subsection (a) of this Section to remove allowances from budget

EGUs opting to become exempt pursuant to the requirements for low-emitters in

Section 217.754(c)(4) of this Part.

If USEPA adjusts the total base EGU trading budget for any reason, the Agency

will adjust the budget pro rata.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 217.762

Methodology for Calculating NO

Allocations for Budget Electrical

Generating Units(“EGUs”)

The methodology for calculating the allowances to be allocated to budget EGUs is based on the

following emission rates and heat inputs:

The applicable NO

emission rates are as follows:

For budget EGUs listed in Appendix F: 0.15 lb/mmbtu.

For budget EGUs not listed in Appendix F: The more stringent of 0.15

lb/mmbtu or the permitted NO

emission rate, but not less than 0.055

lb/mmbtu.

Heat input (HI) (in mmbtu/control period) is determined as follows:

The budget EGU’s two highest heat inputs from the control periods four to

six years prior to the year for which the allocation is being made are

averaged. However, for a budget EGU that did not commence commercial

operation at least six years prior to the control period for which the

allocation is being made, the heat inputs for the following control periods

shall be used:

If the budget EGU has heat input for the control period four years

prior to the year for which the NO

allocation is being made, but

not for the control periods five and six years prior, the heat input

for that control period four years prior shall be used; or

If the budget EGU has heat inputs for the control periods four and

five years prior to the year for which the NO

allocation is being

made, but not for the control period six years prior, the heat input

for the control periods four and five years prior shall be averaged.

The budget EGU’s heat input in subsection (b)(1) of this Section for the

control period in each year will be determined in accordance with:

40 CFR 75, as incorporated by reference in Section 217.104 of this

Part, if the budget EGU was otherwise subject to its requirements

for the year; or

The best available data reported to the Agency for the budget EGU

if the budget EGU was not subject to the requirements of 40 CFR

75, for the year.

The general equation for determining allowances is:

2000

Where:

HI = heat input (in mmbtu/control period) as determined in Section

217.762(b) of this Part.

ER = The NO

emission rate in lbs/mmbtu as determined in Section

217.762(a) of this Part.

A =

allowances of NO

/control period.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 217.764

Allocations for Budget EGUs

For each control period, the Agency will allocate the total number of NO

allowances in the

trading budget apportioned to budget EGUs under Section 217.760 of this Part. These

allocations will be issued as provided in subsections (a) through (f) of this Section and Section

271.768 of this Part of new sources. Specifically:

In 2004, 2005, and 2006 (or the first three years of the program):

The Agency will allocate to each budget EGU that is listed in Appendix F

of this Part the number of allowances listed in Column 7 of Appendix F of

this Part for that budget EGU, as well as any allowances that are not

allocated from the new source set-aside to budget EGUs in subsection

(a)(2) of this Section. Any such allowances from the new source set-aside

will be allocated to budget EGUs listed in Appendix F of this Part

pursuant to 217.768(j) of this Part.

The Agency will allocate allowances from the new source set-aside to

budget EGUs that commenced commercial operation on or after January 1,

1995, pursuant to Section 217.768 of this Part.

The Agency will report these allocations to USEPA at the time it submits

the SIP.

In 2007 (or the fourth year of the program):

The Agency will allocate to each budget EGU that is listed in Appendix F

of this Part the number of allowances listed in Column 8 of Appendix F

for that budget EGU, and any allowances that are not allocated to budget

EGUs under subsection (b)(2) of this Section will be allocated as provided

in subsection (b)(4) of this Section.

The Agency will apportion to each budget EGU that commenced

commercial operation on or after January 1, 1995, and before May 1, 2003,

allowances as calculated in the following equation:

HI = heat input (in mmbtu/control period) as determined

in Section 217.762(b) of this Part.

ER = the NO

emission rate in lbs/mmbtu, as determined

in Section 217.762(a)(2) of this Part.

A =

allowances of NO

/control period.

Notwithstanding subsection (b)(2) of this Section, if the total number of

allowances determined by subsection (b)(2) of this Section is more than

6,017, which is the number of allowances remaining in the trading budget

after allocations have been made to budget EGUs in subsection (b)(1) of

this Section, the Agency will prorate the number of NO

allowances

available to budget EGUs pursuant to the criteria in subsection (b)(2) of

this Section so that the total number of allowances allocated to these

budget EGUs does not exceed 6, 017.

If the total number of allowances allocated pursuant to subsection (b)(2) of

this Section is less than 6,017, which is the number of allowances

remaining in the trading budget after allocations have been made to budget

EGUs in subsection (b)(1) of this Section, the Agency will allocate the

remaining allowances to budget EGUs as follows:

For budget EGUs in subsection (b)(1) of this Section, the pro-rata

allocation shall be determined by the heat input calculated pursuant

to Section 217.762(b) of this Part, multiplied by the emission rate

in Section 217.762(a)(1) of this Part.

For budget EGUs in subsection (b)(2) of this Section, the pro-rata

allocation shall be determined by the heat input calculated pursuant

to Section 217.762(b) of this Part, multiplied by the emission rate

in Section 217.762(a)(2) of this Part.

The Agency will allocate allowances from the new source set-aside,

pursuant to Section 217.768 of this Part, to budget EGUs that commenced

commercial operation after May 1, 2003, and that have not operated for

the full 2003 control period.

The Agency will report these allocations to USEPA by April 1, 2004,

except for allocations from the new source set-aside, which the Agency

will report by May 1, 2007.

In 2008 (or the fifth year of the program):

The Agency will allocate to each budget EGU that is listed in Appendix F

of this Part the number of allowances listed in Column 8 of Appendix F

for that budget EGU, and any allowances that are not allocated to budget

EGUs under subsection (b)(2) of this Section will be allocated as provided

in subsection (b)(4) of this Section.

The Agency will apportion to each budget EGU that commenced

commercial operation on or after January 1, 1995, and before May 1, 2004,

allowances as calculated in the following equation:

HI = heat input (in mmbtu/control period) as determined

in Section 217.762(b) of this Part.

ER = the NO

emission rate in lbs/mmbtu, as determined

in Section 217.762(a)(2) of this Part.

A =

allowances of NO

/control period.

Notwithstanding subsection (c)(2) of this Section, if the total number of

allowances determined by subsection (c)(2) of this Section is more than

6,017, which is the number of allowances remaining in the trading budget

after allocations have been made to budget EGUs in subsection (c)(1) of

this Section, the Agency will prorate the number of NO

allowances

available to budget EGUs pursuant to the criteria in subsection (c)(2) of

this Section so that the total number of allowances allocated to these

budget EGUs does not exceed 6,017.

If the total number of allowances allocated pursuant to subsection (c)(2) of

this Section is less than 6,017, which is the number of allowances

remaining in the trading budget after allocations have been made to budget

EGUs in subsection (c)(1) of this Section, the Agency will allocate the

remaining allowances to budget EGUs as follows:

For budget EGUs in subsection (c)(1) of this Section, the pro-rata

allocation shall be determined by the heat input calculated

pursuant to Section 217.762(b) of this Part, multiplied by the

emission rate in Section 217.762(a)(1) of this Part.

For budget EGUs in subsection (c)(2) of this Section, the pro-rata

allocation shall be determined by the heat input calculated pursuant

to Section 217.762(b) of this Part, multiplied by the emission rate

in Section 217.762(a)(2) of this Part.

The Agency will allocate allowances from the new source set-aside,

pursuant to Section 217.768 of this Part, to budget EGUs that commenced

commercial operation after May 1, 2004, and that have not operated for

the full 2004 control period.

The Agency will report these allocations to USEPA by April 1, 2005,

except for allocations from the new source set-aside, which the Agency

will report by May 1, 2008.

In 2009 (or the sixth year of the program):

The Agency will allocate to each budget EGU that is listed in Appendix F

of this Part the number of allowances listed in Column 9 of Appendix F

for that budget EGU and any allowances that are not allocated to budget

EGUs under subsection (d)(2) of this Section will be allocated as provided

in subsection (d)(4) of this Section.

The Agency will apportion to each budget EGU that commenced

commercial operation on or after January 1, 1995, and before May 1, 2005,

allowances calculated in the following equation:

HI = heat input (in mmbtu/control period) as determined

in Section 217.762(b) of this Part.

ER = the NO

emission rate in lbs/mmbtu, as determined

in Section 217.762(a)(2) of this Part.

A =

allowances of NO

/control period.

Notwithstanding subsection (d)(2) of this Section, if the total number of

allowances determined by subsection (d)(2) of this Section is more than

15,043, which is the number of allowances remaining in the trading budget

after allocations have been made to budget EGUs in subsection (d)(1) of

this Section, the Agency will prorate the total number of NO

allowances

available to budget EGUs that received allowances pursuant to the criteria

in subsection (d)(2) of this Section so that the total number of allowances

allocated to these budget EGUs does not exceed 15,043.

If the total number of allowances allocated pursuant to subsection (d)(2) of

this Section is less than 15,043, which is the number of allowances

remaining in the trading budget after allocations have been made to budget

EGUs in subsection (d)(1) of this Section, the Agency will allocate the

remaining allowances to budget EGUs as follows:

For budget EGUs in subsection (d)(1) of this Section, the pro rata

allocation shall be determined by the heat input calculated pursuant

to Section 217.762(b) of this Part, multiplied by the emission rate

in Section 217.762(a)(1) of this Part.

For budget EGUs in subsection (d)(2) of this Section, the pro-rata

allocation shall be determined by the heat input calculated pursuant

to Section 217.762(b) of this Part, multiplied by the emission rate

in Section 217.762(a)(2) of this Part.

The Agency will allocate allowances from the new source set-aside,

pursuant to Section 217.768 of this Part, to budget EGUs that commenced

commercial operation after May 1, 2005, and that have not operated for

the full 2005 control period.

As of April 30, 2009, if the number of allowances in the new source set-

aside exceeds three percent (3%) of the total number of tons of NO

emissions in the trading budget apportioned to budget EGUs as determined

pursuant to Section 217.768(i) and (j) of this Part, the number of

allowances above three percent (3%) will be allocated to budget EGUs

receiving allowances pursuant to this subsection (d).

The Agency will report these allocations to USEPA by April 1, 2006,

except for allocations from the new source set-aside, which the Agency

will report by May 1, 2009.

In 2010 (or the seventh year of the program):

The Agency will allocate to each budget EGU that is listed in Appendix F

of this Part the number of allowances listed in Column 9 of Appendix F

for that budget EGU and any allowances that are not allocated to budget

EGUs under subsection (e)(2) of this Section as provided in subsection

(e)(4) of this Section.

The Agency will assign to each budget EGU that commenced commercial

operation on or after January 1, 1995, and before May 1, 2006, allowances

as calculated in the following equation:

HI = heat input (in mmbtu/control period) as determined

in Section 217.762(b) of this Part.

ER = the NO

emission rate in lbs/mmbtu, as determined

in Section 217.762(a)(2) of this Part.

A =

allowances of NO

/control period.

Notwithstanding subsection (e)(2) of this Section, if the total number of

allowances determined by subsection (e)(2) of this Section is more than

15,043, which is the number of allowances remaining in the trading budget

after allocations have been made to budget EGUs in subsection (e)(1) of

this Section, the Agency will prorate the total number of NO

allowances

allocated to budget EGUs that received allowances pursuant to the criteria

in subsection (e)(2) of this Section so that the total number of allowances

allocated to these budget EGUs does not exceed 15,043.

If the total number of allowances allocated pursuant to subsection (e)(2) of

this Section is less than 15,043, which is the number of allowances

remaining in the trading budget after allocations have been made to budget

EGUs in subsection (e)(1) of this Section, the Agency will allocate the

remaining allowances to budget EGUs as follows:

For budget EGUs in subsection (e)(1) of this Section, the pro-rata

allocation shall be determined by the heat input calculated pursuant

to Section 217.762(b) of this Part, multiplied by the emission rate

in Section 217.762(a)(1) of this Part.

For budget EGUs in subsection (e)(2) of this Section, the pro-rata

allocation shall be determined by the heat input calculated pursuant

to Section 217.762(b) of this Part, multiplied by the emission rate

in Section 217.762(a)(2) of this Part.

The Agency will allocate allowances from the new source set-aside,

pursuant to Section 217.768 of this Part, to budget EGUs that commenced

commercial operation after May 1, 2006, and that have not operated for

the full 2006 control period.

As of April 30, 2010, if the number of allowances in the new source set-

aside exceeds three percent (3%) of the total number of tons of NO

emissions in the trading budget apportioned to budget EGUs as determined

pursuant to Section 217.768(i) and (j) of this Part, the number of

allowances above three percent (3%) will be allocated to budget EGUs

receiving allowances pursuant to this subsection (e).

The Agency will report these allocations to USEPA by April 1, 2007,

except for allocations from the new source set-aside, which the Agency

will report by May 1, 2010.

In 2011 (or the eighth year) of the program and annually thereafter:

The Agency will apportion the available NO

allowances to each budget

EGU based on its heat input determined in Section 217.762(b) of this Part,

multiplied by:

For budget EGUs that commenced commercial operation prior to

January 1, 1995, the NO

emission rate determined in Section

217.762(a)(1) of this Part.

For budget EGUs that commenced commercial operation on or

after January 1, 1995, the NO

emission rate determined in Section

217.762(a)(2) of this Part.

The Agency will allocate allowances from the new source set-aside,

pursuant to Section 217.768 of this Part, to budget EGUs that commenced

commercial operation after the control period four years prior to the year

in which allocations are made and that have not operated for the full

control period four years prior to the year in which the allocations are

being made.

As of April 30, 2011, if the number of allowances in the new source set-

aside exceeds three percent (3%) of the total number of tons of NO

emissions in the trading budget apportioned to budget EGUs as determined

pursuant to Section 217.768(e) and (f) of this Part, the number of

allowances above three percent (3%) will be allocated to budget EGUs

receiving allowances pursuant to this subsection (f).

The Agency will report these allocations to USEPA by April 1 of each

year that is three years prior to the year in which the allocations are being

made, except for allocations from the new source set-aside, which the

Agency will report by May 1 of each year in which the allocations are

being made.

BOARD NOTE: Because of litigation involving the NO

SIP Call, Michigan v. EPA, No. 98-

1497, 2000 WL 180650 (D.C. Cir. March 3, 2000), the years defining the control periods may

change. Should this occur, the dates set forth under each year will be considered to adjust

correspondingly.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 217.768

New Source Set-Asides for “New” Budget EGUs

“New” budget EGUs

A “new” budget EGU is one that commenced commercial operation on or

after January 1, 1995, and does not receive allowances pursuant to Section

217.764 of this Part.

“New” budget EGUs must have an allowance for every ton of NO

emitted

during the control period as provided in Section 217.756(d) of this Part.

A “new”budget EGU may request from the Agency a number of

allowances that is not more than the number of allowances for which it is

eligible, as determined in subsection (e) of this Section.

The Agency shall apportion allowances from the new source set-aside as follows:

For 2004, 2005, and 2006, to budget EGUs that commenced commercial

operation on or after January 1, 1995; and

For 2007 and thereafter, to budget EGUs that have not operated the full

control period four years prior to the control period for which the

allocation is being made.

The Agency will establish a new source set-aside for each control period. Each

new source set-aside will be allocated allowances equal to:

Five percent (5%) of the EGU trading budget in 2004, 2005, and 2006,

which is 1,535 allowances, subject to adjustment to reflect additions or

deletions to the EGU trading budget;

Two percent (2%) of the EGU of the trading budget in 2007 and thereafter,

which is 614 allowances, subject to adjustment to reflect additions or

deletions to the EGU trading budget.

As of April 30 of the applicable year, beginning in 2009 and thereafter, if

the number of allowances in the new source set-aside is greater than or

equal to three percent (3%) of the total number of tons of NO

emissions

in the trading budget apportioned to budget EGUs, which is 921

allowances, subject to adjustment to reflect additions or deletions to the

EGU trading budget, pursuant to subsections (i) and (j) of this Section, the

number of allowances above three percent (3%) will be allocated to budget

EGUs receiving allowances pursuant to Section 217.764 of this Part.

These allowances shall be allocated on a pro-rata basis.

The account representative of a “new” budget EGU under subsection (a) of this

Section may obtain allowances from the new source set-aside by submitting to the

Agency a request, in writing or in a format specified by the Agency, to be

allocated allowances for the current control period from the new source set-aside.

The allocation request for each applicable control period must be submitted after

the date on which the Agency issues a construction permit to the budget EGU and

before March 1 of the control period for which the allocation is requested.

In an allocation request under subsection (d) of this Section, the account

representative may request allowances for a control period in a number that does

not exceed the projected heat input in mmbtu during the applicable control period

multiplied by the more stringent of 0.15 lb/mmbtu or the permitted emission rate,

but no more stringent than 0.055 lb/mmbtu. The projected heat input shall be

determined as set forth below, divided by 2000 lbs/ton:

For “new” budget EGUs that have heat input from at least three control

periods prior to the allocation year, the average of the budget EGU’s two

highest seasonal heat inputs from the control periods one to three years

prior to the allocation year;

For “new” budget EGUs that have heat input from only two control

periods prior to the allocation year, the average of the budget EGU’s

seasonal heat inputs from the control periods one and two years prior to

the allocation year;

For “new” budget EGUs that have seasonal heat input from only the

control period prior to the allocation year, the heat input from that control

period; or

For “new” budget EGUs that have commenced commercial operation but

have not operated for more than half of a full at least 77 days of the control

period prior to the allocation year, the budget EGU’s maximum design

heat input for the control period as designated in the construction permit.

Beginning in 2007, the Agency will review and allocate allowances pursuant to

each allocation request, contingent upon receiving payment pursuant to subsection

(k) of this Section, by April 15 of the applicable year, as follows:

Upon receipt of the allocation request, the Agency will determine whether

the request is consistent with the requirements of subsections (d) and (e) of

this Section and will make any necessary adjustments to the request to

ensure that the control period and the number of allowances requested are

consistent with those requirements of subsections (d) and (e) of this

Section.

If the new source set-aside for the control period for which allowances are

requested has a number of allowances greater than or equal to the total

number requested by all “new” budget EGUs, the Agency will allocate the

number of allowances requested to the “new” budget EGUs.

If the new source set-aside for the control period for which allowances are

requested has a number of allowances less than the total number of

allowances requested by all “new” budget EGUs, the Agency will allocate

the available allowances to the “new” budget EGUs on a pro-rata basis,

based on the number of allowances requested.

For “new” budget EGUs that commenced commercial operation on or after

January 1, 1995, but prior to January 1, 2004, the Agency will notify the account

representative of the number of allowances that have been allocated to the “new”

budget EGU by March 30 of the applicable year. There will be no charge for

allowances received under this subsection.

For “new” budget EGUs that commenced commercial operation on or after

January 1, 2004, the Agency will notify by March 30 of the applicable year the

account representative of the number of allowances that are eligible for purchase

for the “new” budget EGU pursuant to the requirements of subsection (k) of this

Section. If the Agency does not receive payment by April 15 of the applicable

year, the account representative will forfeit his/her eligibility to purchase the

allowances offered. The Agency will make available for purchase those forfeited

allowances on a pro-rata basis to “new” budget EGUs that received allocations

pursuant to subsection (f)(2) of this Section, up to the number of allowances

requested by each account representative. Such additional allocations are subject

to the purchase requirements of subsection (k) of this Section, to the extent

applicable.

For “new” budget EGUs that have commenced commercial operation but have

operated for less than one-half 76 or fewer days of the control period in 2003,

USEPA will deduct allowances to account for the actual utilization of the EGU

during the 2004 control period consistent with the provisions of 40 CFR 96.42(e).

Any allowances allocated by the Agency for such “new” budget EGUs that are not

used for compliance during the 2004 control period shall be returned to the

Agency’s new source set-aside account.

For the years 2004, 2005, and 2006, any allowances that are not allocated pursuant

to subsections (g), (h) and (i) of this Section will be allocated on a pro-rata basis

to the budget EGUs listed in Appendix F of this Part. There will be no charge for

allowances received under this subsection.

Fees for new source set-aside allowances:

“New” budget EGUs that commence commercial operation on or after

January 1, 2004, that obtain allowances allocated from the new source set-

aside shall pay for such allocations pursuant to Section 9.9 of the Act.

The price of allowances from the new source set-aside shall be:

The average price at which NO

allowances are traded in the

interstate NO

Trading Program for the preceding control period;

and

For 2004 only, the price shall be the average price at which NO

allowances were traded in 2003 in the Ozone Transport Region.

The fees collected by the Agency from the sale of allowances will be

distributed pro-rata to budget EGUs receiving allowances pursuant to

Section 217.764 of this Part on the basis of allocated allowances subject

to Agency administrative costs assessed pursuant to Section 9.9 of the Act.

A “new” budget EGU will become an existing budget EGU and will receive

allowances pursuant to the requirements of Section 217.764 of this Part, as

follows:

For a budget EGU that commences commercial operation between and

including January 1, 1995, and April 30, 2003, the budget EGU will be

allocated allowances in 2004 for the 2007 control period and will become

an existing budget EGU on May 1, 2007.

For a budget EGU that commences commercial operation after April 30,

2003, the budget EGU will become an existing budget EGU in the control

period for which it receives an allocation pursuant to Section 217.764 of

this Part. It will be considered a “new” budget EGU and will receive its

allowances from the new source set-aside in the intervening years from

start-up until it receives allocations pursuant to Section 217.764 of this

Part.

BOARD NOTE: Because of litigation involving the NO

SIP Call, Michigan v. EPA, No. 98-

1497 2000 WL 180650 (D.C. Cir. March 3, 2000), the years defining the control periods may

change. Should this occur, other dates in this Section will be considered to adjust as necessary.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 217.770

Early Reduction Credits for Budget EGUs

If a budget EGU reduces its NO

emission rate as required by the applicable provisions of

subsection (c) of this Section in the 2001, 2002, or 2003 control period, for use in the 2004

control period, or later control periods authorized by USEPA, the account representative may

request early reduction credits (ERCs) for such reductions, and the Agency will allocate ERCs to

the budget EGU in accordance with the following:

Each budget EGU for which the account representative requests any ERCs under

subsection (d) of this Section shall monitor NO

emissions in accordance with 40

CFR 96, subpart H, as incorporated by reference in Section 217.104 of this Part,

starting with the control period prior to the control period for which ERCs will

first be requested and for each control period for which ERCs will be requested.

For example, if ERCs are requested for reductions made in the 2001 control

period, the budget EGU must have implemented the applicable monitoring for the

2000 control period. The unit’s monitoring system availability shall be not less

than 8090 percent during the control period prior to the control period in which

the NO

emissions reduction is made and the unit must be in compliance with any

applicable State or federal emissions or emissions-related requirements.

The NO

emission rate and heat input under subsections (c) through (e) of this

Section shall be determined in accordance with 40 CFR 96, subpart H.

Each budget EGU for which ERCs are requested under subsection (d) of this

Section must have reduced its NO

emission rate for each control period for which

ERCs are requested, as follows:

For budget EGUs subject to the requirements of Title IV of the CAA and

not included in a NO

averaging plan pursuant to 40 CFR 72 and 76, as

incorporated by reference in Section 217.104 of this Part, at least 30% less

than the NO

emission rate specified in the applicable Title IV permit or

other applicable federally enforceable permit.

For budget EGUs subject to the requirements of Title IV of the CAA and

included in a NO

averaging plan pursuant to 40 CFR 72 and 76, at least

30% less than the annual emission rate required in the NO

averaging plan

in the applicable Title IV permit or other applicable federally enforceable

permit.

For budget EGUs not subject to the requirements of Title IV of the CAA,

at least 30% less than the actual NO

emissions rate (lbs/mmbtu) for the

2000 control period.

The account representative of a budget EGU that meets the requirements of

subsections (a) through (c) of this Section may submit to the Agency a request for

ERCs for a EGU based on NO

emission rate reductions made by the EGU in

control periods 2001, 2002, and 2003, in accordance with subsection (c) of this

Section.

The number of ERCs for any applicable control period shall be an amount

equal to the unit’s heat input for such control period multiplied by the

difference between the EGU’s NO

emission rate (meeting the

requirements of subsection (c) of this Section for the applicable control

period) and the EGU’s actual NO

emission rate for the applicable control

period, divided by 2000 lbs/ton, and rounded to the nearest ton.

Upon request of the account representative, the ERC allowance allocation

for a particular EGU may be deposited in the source’s general account

rather than in the unit’s compliance account.

The early reduction request must be submitted in a format specified by the

Agency by:

November 1, 2001, for reductions made in the 2001 control period;

November 1, 2002, for reductions made in the 2002 control period;

and

November 1, 2003, for reductions made in the 2003 control period.

In the event that the date for implementing the NO

SIP Call, May 1, 200331,

2004, is delayed, the early reduction request must be submitted in accordance with

any rulemaking or guidance by USEPA on the distribution of the Compliance

Supplement Pool under the NO

SIP Call (63 Fed. Reg. 57356).by November 1 of

the year two years before the implementation date for the reductions made in the

control period two years before the implementation date, and by November 1 of

the year preceding the implementation date for the reductions made in the control

period preceding the implementation date. Should this occur, the other dates in

this Section shall be adjusted accordingly.

The Agency will allocate ERCs to the budget EGUs meeting the requirements of

subsections (a) through (c) of this Section and covered by ERC requests meeting

the requirements of subsection (d) of this Section in accordance with the

following procedures:

Upon receipt of each ERC request, the Agency will accept the request only

if the requirements of subsections (a) through (d) of this Section are met

and will make any necessary adjustment to the request to ensure that the

amount of the ERCs requested meets the requirements of subsections (b)

through (d) of this Section;

The Agency shall allocate at least 15,261 ERCs over twothree years, as

follows:

If USEPA has approved this Subpart as a SIP revision, not more

than 7,630 one-half of the total ERC allowances for reductions

made in the control period in 2001;

At least 7,631 Not more than one-half of the total ERC allowances,

plus any ERC allowances not allocated pursuant to subsection

(f)(2)(A) of this Section, for reductions made in the control period

in 2002; and

Any ERC allowances not allocated pursuant to subsections

(f)(2)(A) or (B) of this Section, for reductions made in the control

period in 2003.

If the number of ERC allowances requested for a reduction achieved in the

control period in 2003 is less than or equal to the number of ERC

allowances designated for that control period in subsection (f)(2)(A) of

this Section, the Agency will allocate to each budget EGU one allowance

for each accepted ERC request;

If the number of ERC allowances requested for a reduction achieved in the

control period in 2003 is greater than the number of ERC allowances

designated for that control period in subsection (f)(2)(A) of this Section,

the Agency will allocate to each budget EGU allowances for accepted

requests on a pro-rata basis.; and

For accepted ERC requests for reductions made in the control period in

2002, the Agency will allocate ERCs on a pro-rata basis.

The Agency will notify the account representative submitting an ERC request for

the subsequent control period of the number of ERC allowances that will be

allocated to each budget EGU for that control period as follows:

By May March 1, 2002, for ERCs requested for and earned in the 2001

control period;

By May March 1, 2003, for ERCs requested for and earned in the 2002

control period; and

By March 1, 2004, for ERCs requested for and earned in the 2003 control

period.

By May 1, 2004, the Agency will submit to USEPA the ERC allocations made by

the Agency under this Section. USEPA will record such allocations to the extent

that they are consistent with the requirements of this Section.

ERC allowances recorded under subsection (h) of this Section may be deducted

for compliance under 40 CFR 96.54, as incorporated by reference in Section

217.104 of this Part, for the control period in 2004 or such additional control

periods as may be specified by USEPA. Notwithstanding 40 CFR 96.55(a),

USEPA will deduct as retired any ERC allowances that are not deducted for

compliance in accordance with 40 CFR 96.54 for the control period in 2004.

ERC allowances are treated as banked allowances in 2004 for the purposes of 40

CFR 96.55(a) and (b).

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 217.774

Opt-In Units

Any operating fossil fuel-fired stationary boiler, combustion turbine, combined

cycle system, cement kiln or stationary internal combustion engine in the State

may qualify under this Subpart to become a budget opt-in unit if it:

Is not a budget EGU under Section 217.754 of this Part;

Vents all of its emissions to a stack or, for a unit that does not vent all of

its emissions to a stack, obtains a permit with federally enforceable

conditions specifying the applicable conditions for participation in the

Trading Program;

Has documented heat input for more than 876 hours in the six months

immediately preceding the submission of an application for an initial

budget permit under subsection (d) of this Section;

Is not covered by a retired unit exemption under 40 CFR 96.5; and

Is not covered by the low-emitter exemption under Section 217.754(c) of

this Part; and

Is not located at a source listed in Appendix D of this Part.

Except as otherwise provided in this Part, a budget opt-in unit shall be treated as a

budget EGU for purposes of applying this Subpart and 40 CFR 96.

Authorized account representative:

If an opt-in unit is located at the same source as one or more budget EGUs,

it shall have the same account representative as those budget EGUs.

If the opt-in unit is not located at the same source as one or more budget

EGUs, the owner or operator of the opt-in unit shall submit a complete

account certificate of representation under 40 CFR 96.13.

To apply for a budget permit, the account representative of a unit meeting the

qualifications of subsection (a) of this Section must, except as provided under

Section 217.778(f) of this Part, submit to the Agency:

A budget permit application for the unit that:

Meets the requirements under Section 217.758 of this Part; and

Contains provisions for a change in the regulatory status of the unit

to a budget opt-in unit under Section 217.754 of this Part pursuant

to the provisions of Section 217.780(b) of this Part.

A monitoring plan for the unit in accordance with 40 CFR 96, subpart H.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 217.776

Opt-In Process

The owner or operator of a unit meeting the qualifications of Section 217.774(a) of this Part may

submit an application for a budget permit for a budget opt-in unit under Section 217.774(d) of

this Part. The Agency will issue or deny a budget permit for such opt-in unit in accordance with

Section 217.758 of this Part and the following:

The Agency will determine, on an interim basis, the sufficiency of the monitoring

plan accompanying the initial application for a budget permit for an opt-in unit. A

monitoring plan is sufficient, for purposes of interim review, if the plan contains

information demonstrating that the NO

emission rate and heat input of the unit

are monitored and reported in accordance with 40 CFR 96, subpart H. A

determination of sufficiency shall not be construed as acceptance or approval of

that unit's monitoring plan.

If the Agency determines that the unit's monitoring plan is sufficient under

subsection (a) of this Section and after completion of the monitoring system

certification under 40 CFR 96, subpart H, the NO

emission rate and the heat

input of the unit shall be monitored and reported in accordance with 40 CFR 96,

subpart H, for one full control period during which the monitoring system

availability is not less than 80 90 percent and during which the unit is in full

compliance with any applicable State or federal emissions or emissions-related

requirements.

Based on the information monitored and reported under subsection (b) of this

Section, the unit's baseline heat rate shall be calculated as the unit's total heat

input (in mmbtu) for the control period and the unit's baseline NO

emission rate

shall be calculated as the unit's total NO

emissions (in lbs) for the control period

divided by the unit's baseline heat rate.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 217.778

Budget Opt-In Units: Withdrawal from NO

Trading Program

Requesting withdrawal. To withdraw from the NO

Trading Program, the account

representative of a budget opt-in unit shall submit to the Agency a request to

withdraw from the NO

Trading Program and to withdraw the budget permit

effective as of a specified date between (and not including) September 30 and

May 1. The submission shall be made no later than 90 days prior to the requested

effective date of withdrawal.

Conditions for withdrawal.

Before a budget opt-in unit may withdraw from the NO

Trading Program

and the budget permit may be withdrawn under this Section, the following

conditions must be met:

For the control period immediately before the withdrawal is to be

effective, the account representative must submit to the Agency an

annual compliance certification report in accordance with 40 CFR

96.30.

If the budget opt-in unit has excess emissions for the control period

immediately before the withdrawal is to be effective, USEPA has

deducted from the budget opt-in unit's compliance account, or the

overdraft account of the NO

budget source where the budget opt-

in unit is located, the number of allowances required in accordance

with 40 CFR 96.54(d) for the control period.

After the requirements for withdrawal under subsection (b)(1) of this

Section are met, USEPA will deduct from the opt-in unit's compliance

account, or the overdraft account of the budget source where the budget

opt-in unit is located, allowances equal in number to any allowances

allocated to that unit under Section 217.782 of this Part for the same or

earlier control period for which the withdrawal is to be effective. USEPA

will close the budget opt-in unit's compliance account and will establish,

and transfer any remaining allowances to, a new general account for the

owners and operators of the opt-in unit. The account representative for the

budget opt-in unit shall become the account representative for the general

account.

A budget opt-in unit that withdraws from the NO

Trading Program shall comply

with all requirements under the NO

Trading Program concerning all years for

which such budget opt-in unit was a budget opt-in unit, even if such requirements

arise or must be complied with after the withdrawal takes effect.

Notification.

After the requirements for withdrawal under subsections (a) and (b) of this

Section are met (including deduction of the full amount of allowances

required), the Agency will revise the budget permit indicating a specified

effective date for the withdrawal that is after the requirements in

subsections (a) and (b) of this Section have been met and that is prior to

May 1 or after September 30.

If the requirements for withdrawal under subsections (a) and (b) of this

Section are not met, the Agency will issue a notification to the owner or

operator and the account representative of the budget opt-in unit that the

opt-in unit's request to withdraw its budget permit is denied. If the budget

opt-in unit's request to withdraw is denied, the budget opt-in unit shall

remain subject to the requirements for a budget opt-in unit.

Reapplication upon failure to meet conditions of withdrawal. If the Agency

denies the budget opt-in unit's request to withdraw, the account representative of

the budget opt-in unit may submit another request to withdraw in accordance with

subsections (a) and (b) of this Section.

Ability to return to the NO

Trading Program. Once an opt-in unit withdraws

from the NO

Trading Program and its budget permit is withdrawn under this

Section, the account representative may not submit another application for a

budget permit under Section 217.774(d) of this Part for the unit prior to the date

that is four years after the date on which the budget permit with opt-in conditions

is withdrawn.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 217.780

Opt-In Units: Change in Regulatory Status

Notification. When an opt-in unit becomes a budget opt-in unit under Section

217.754(d) of this Part, the owner or operator shall notify the Agency and USEPA

in writing of such change in the opt-in unit's regulatory status within 30 days after

such change.

Any permit application that provides for a change in the regulatory status of a unit

to a budget opt-in unit pursuant to Section 217.774(d)(1)(B) of this Part and is

included in a budget permit is effective on the date on which such opt-in unit

becomes a budget opt-in unit under Section 217.754 of this Part.

USEPA action.

USEPA will deduct from the compliance account for the budget opt-in

unit under this Section, or the overdraft account of the budget source

where the budget opt-in unit is located, allowances equal in number to and

allocated for the same or a prior control period as:

Any allowances allocated to the budget unit (as an opt-in unit)

under Section 217.782 of this Part for any control period after the

last control period during which the unit's budget permit was

effective; and

If the effective date of any budget permit under subsection (b) of

this Section is during a control period, the allowances allocated to

the budget opt-in unit (as an opt-in unit) under Section 217.782 of

this Part for the control period multiplied by the ratio of the

number of days in the control period, starting with the effective

date of the budget permit under subsection (b) of this Section,

divided by the total number of days in the control period.

The account representative shall ensure that the compliance account of the

budget opt-in unit under subsection (b) of this Section, or the overdraft

account of the budget source where the budget opt-in unit is located,

contains the allowances necessary for completion of the deduction under

subsection (c)(1) of this Section. If the compliance account or overdraft

account does not contain sufficient allowances, USEPA will deduct the

required number of allowances, regardless of the control period for which

they were allocated, whenever allowances are recorded in either account.

For every control period during which any budget permit under subsection

(b) of this Section is effective, the budget opt-in unit under subsection (b)

of this Section will be treated, solely for purposes of allowance allocations

under Section 217.764 or 217.768 of this Part, as a unit that commenced

operation on the effective date of the budget permit under subsection (b) of

this Section and will be allocated allowances in accordance with Section

217.764 or 217.768 of this Part.

Notwithstanding subsection (c)(2) of this Section, if the effective date of

any budget permit under subsection (b) of this Section is during a control

period, the following number of allowances will be allocated to the budget

opt-in unit under subsection (b) of this Section or under Section 217.764

or 217.768 of this Part for the control period: the number of allowances

otherwise allocated to the budget opt-in unit under Section 217.764 or

217.768 of this Part for the control period multiplied by the ratio of the

number of days in the control period, starting with the effective date of the

budget permit under subsection (b) of this Section, divided by the total

number of days in the control period.

When the owner or operator of an opt-in unit does not renew the budget permit for

the budget opt-in unit issued pursuant to Section 217.774(d), USEPA will deduct

from the budget opt-in unit's compliance account, or the overdraft account of the

budget source where the budget opt-in unit is located, allowances equal in number

to and allocated for the same or a prior control period as any allowances allocated

to the budget opt-in unit under Section 217.782 of this Part for any control period

after the last control period for which the budget permit is effective. The account

representative shall ensure that the budget opt-in unit's compliance account or the

overdraft account of the budget source where the budget opt-in unit is located

contains the allowances necessary for completion of such deduction. If the

compliance account or overdraft account does not contain sufficient allowances,

USEPA will deduct the required number of allowances, regardless of the control

period for which they were allocated, whenever allowances are recorded in either

account.

After the deduction under subsection (d) of this Section is completed, USEPA will

close the opt-in unit's compliance account. If any allowances remain in the

compliance account after completion of such deduction and any deduction under

40 CFR 96.54, USEPA will close the opt-in unit's compliance account and will

establish, and transfer any remaining allowances to, a new general account for the

owner or operator of the opt-in unit. The account representative for the opt-in unit

shall become the account representative for the general account.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 217.782

Allowance Allocations to Budget Opt-In Units

Allowance allocations:

By the December 31 immediately before the first control period for which

the budget permit is effective, the Agency will allocate allowances to the

budget opt-in unit and submit to USEPA the allocation for the control

period in accordance with subsection (b) of this Section.

By no later than the December 31 after the first control period for which

the budget permit is in effect and the December 31 of each year thereafter,

the Agency will allocate allowances to the budget opt-in unit and submit to

USEPA allocations for the next control period, in accordance with

subsection (b) of this Section.

For each control period for which the budget opt-in unit has a budget permit, the

budget opt-in unit will be allocated allowances in accordance with the following

procedures:

The heat input (in mmbtu) used for calculating allowance allocations will

be the lesser of:

The opt-in unit's baseline heat input determined pursuant to

Section 217.778(c) of this Part; or

The opt-in unit's heat input, for the control period in the year prior

to the year of the control period for which the allocations are being

calculated, as determined in accordance with 40 CFR 96, subpart

The Agency will allocate allowances to the budget opt-in unit in an

amount equaling the heat input (in mmbtu) determined under subsection

(b)(1) of this Section multiplied by the lesser of:

The unit's baseline NO

emission rate (in lbs/mmbtu) determined

pursuant to Section 217.776(c) of this Part; or

The lowest NO

emissions limitation (calculated in lbs/mmbtu)

under State or federal law that is applicable to the budget opt-in

unit for the control period in the year prior to the year of the

control period for which the allocations are being calculated during

the control period, regardless of the averaging period to which the

emissions limitation applies.

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 217.Appendix D

Non-Electrical Generating Units

COMPANY ID # / NAME

UNIT DESIGNATION

UNIT DESCRIPTION

A E STALEY MANUFACTURING CO

ARCHER DANIELS MIDLAND CO EAST PLANT

CPC INTERNATIONAL INC.

GAS FIRED BOILER NO 4

GAS FIRED BOILER NO 5

GREAT LAKES NAVAL STATION

INDIAN REFINING LIMITED PARTNERSHIP

JEFFERSON SMURFIT CORPORATION

119010AAL

72120426001

BLR 7-COAL FIRED

MARATHON OIL CO ILLINOIS REFINING DIVISION

033808AAB

72111291055

BOILER #3 OIL,REF GAS

FIRED

033808AAB

72111291056

BOILER #4 REF GAS,OIL

FIRED

MOBIL JOLIET REFINING CORP

197800AAA

72110567002

AUX BOILER-REFINERY

GAS FULL FIRE IF COGEN

QUANTUM - USI DIVISION

QUANTUM - USI DIVISION

SHELL OIL CO WOOD RIVER MFG COMPLEX

U S STEEL - SOUTH WORKS

031600ALZ

82010044013

NO. 6 BOILER,#5 POWER

STATION (FUEL-NAT.GAS)

031600ALZ

82010044014

NO 1 BLR NG

UNIV OF ILL - ABBOTT POWER PLANT

(Source: Added at ____ Ill. Reg. ________, effective ____________________)

Section 217.Appendix F

Allowances for Electrical Generating Units

Ameren Energy Generating Company

Ameren Eng. Gen. Co. Totals

Lakeside 7 Lakeside 7

167120AA

Lakeside 8 Lakeside 8

031600AIN Crawford 7 Crawford 7

031600AIN Crawford 8 Crawford 8

Midwest Generation Totals

El. Energy Inc. Totals

Hennepin 1 Hennepin 1

Hennepin 2 Hennepin 2

Union Electric Totals

TOTAL

30,701 24,561 15,351 29,166 24,070 15,044

(Source: Added at ____ Ill. Reg. __________, effective _____________)

IT IS SO ORDERED.

I, Dorothy M. Gunn, Clerk of the Illinois Pollution Control Board, hereby certify that the

above opinion and order was adopted on the 16th day of November 2000 by a vote of 7-0.

Dorothy M. Gunn, Clerk

Illinois Pollution Control Board