ILLINOIS POLLUTION CONTROL BOARD

ORDER
Section 211.102?Abbreviations and Conversion Factors
1. _
  1. Section 211. 1324?Commence Operation
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

December 21, 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

)

Adopted Rule. Final Order.

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

By today’s order the Board adopts regulations 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

et seq.

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

federal directive to cap its emissions from 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.

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.

PROCEDURAL HISTORY

The Illinois Environmental Protection Agency (Agency) filed a proposal in this matter

with the Board on July 11, 2000. The filing was pursuant to Section 28.5 of the

Environmental Protection Act (Act) (415 ILCS 5/28.5 (1998)), which provides for “fast-track”

adoption of certain regulations necessary for compliance with the CAAA.

The Board moved the Agency’s proposal to first notice on July 13, 2000. See

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), R01-9.

First-notice publication occurred in the Illinois Register, Vol. 24, August 4, 2000, at 11473

and 11493.

The Board held public hearings in Springfield, Illinois, on August 28 and 29, 2000, and

in Chicago, Illinois, on September 26, 2000, before Board Hearing Officer Catherine Glenn.

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. 415 ILCS 5/28.5(l) (1998). Ten public comments were 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).

On November 16, 2000, the Board adopted its second notice opinion and order, and

sent this matter to the Joint Committee on Administrative Rules (JCAR) for its consideration.

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), R01-9. On December 12, 2000, JCAR voted a certificate of no objection.

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

that 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 235-6.

Proposals for regulations to implement 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. However, 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.

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).

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 not indicated whether it intends to hear the appeals. Other NOx-related

court actions are also pending.

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. Neither of

these changes affects today’s proposed action.

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.

In light of this on-going litigation, the Board has considered whether actions other than

that taken today would be appropriate. The Board, of course, must base its action on the

current status of the law, and not on any prospective outcome of a court action. Inasmuch as

the Board believes that the law requires that we adopt the instant regulations, we do so today.

We 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;

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;

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

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 regulations, and finds that they comply with the

requirements of Section 9.9(d).

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.

Scope and Affected Facilities

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

State of Illinois. 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.” See Section 217.754.

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 May 31,

2004 implementation date ordered by the Court of Appeals. See Exh. 33. In its second-notice

opinion and order the Board granted that motion, and amended the proposal accordingly.

NOx TRADING PROGRAM

Mandatory Provisions

Much of the NOx trading program adopted today is mandatory, in that Section 9.9 of

the Act requires a trading program compatible with 40 C.F.R. Part 96. States that participate

in the trading program of Part 96 have limited discretion in adopting their 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 regulations these mandatory provisions

are effectuated via incorporation by reference. See 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 specific

details.

Optional Provisions

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

programs. Today’s regulations employ that flexibility in four areas, as follows:

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

(November 16, 2000), R01-9, p. 7.

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 reduction emissions; 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 May-September control period. There are additional requirements regarding

operating hours, methods of emissions calculations, record keeping, and reporting. See

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 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 regulations.

“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 has recommended that

these allowances be used to bankroll an Early Emission Reduction Credit (ERC). See 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 – 57,530 (October 27, 1998). However, in its Motion

to Amend (Exh. 33), the Agency proposed 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 incorporated this concept in Section 217.770.

The Agency also noted 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 allow ERCs to be used not only

in 2004, but also in any years authorized by USEPA. PC 3 at 15. The Board today adopts

that provision. See Section 217.770.

Allocation of NOx Allowances

“Fixed/Flex” Allocation

The NOx SIP Call allows State latitude to determine how to allocate allowances among

emitters. Pursuant to the USEPA emissions budget 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 Agency’s approach, which the

Board adopts today, is termed a “fixed/flex” allocation scheme. Initially, the large percentage

of allowances is allocated to existing emitters based on historical emission rates. The list of

existing emitters is presented 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 additions to the total EGU

population. See 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%

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

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

allocation based on the formula in Section 217.762. At this stage some of the EGUs that 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 allocations 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

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)

(1998 State Bar Edition, 1999 Supp.). Today’s regulations incorporate 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 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 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 set-aside provision 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 regulations.

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 recommended that the Board provide a set-aside for energy

efficiency and renewable energy measures.

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 provision is

an appropriate or productive method to achieve these ends, particularly in light of the limited

number of emission allowances available in Illinois.

Charges for Allowances

Section 217.768(k) contains a provision that imposes a market-rate fee on allowances

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

contended that this provision should be deleted or significantly modified,

e.g.,

Tr.2 at 17-18;

PC 8 at 17.

The Agency 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 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 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

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

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.

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 Generation 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 regulations do 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 varies 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.

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 instant

regulations strike an appropriate balance among these various interests, and for this reason we

today adopt them.

ORDER

The Clerk is directed to cause publication in the

Illinois Register

of the following

amendments to the Board’s air regulations at 35 Ill. Adm. Cope 211 and 217.

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)

1 lb/mmbtu 1.548 kg/MW-hr

(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 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.

ed)

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:

1 lb/mmbtu 1.548 kg/MW-hr

(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 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 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. [415 ILCS 5/9.9(f)]

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 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.

The account representative of a budget EGU that has excess emissions in

any control period shall surrender the allowances as required for

deduction under 40 CFR 96.54(d)(1).

The 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, 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 must 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

217.768 for 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 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

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 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

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 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

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:

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;

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 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 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 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 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 90 % 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 31, 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).

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 three years, as

follows:

If USEPA has approved this Subpart as a SIP revision, not more

than one-half of the total ERC allowances for reductions made in

the control period in 2001;

Not more than one-half of the total ERC allowances for

reductions made in the control period in 2002; and

Any ERC allowances not allocated pursuant to subsection

(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.

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 March 1, 2002, for ERCs requested for and earned in the 2001

control period;

By 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;

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;

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

(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 90 % 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 217.776(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 H.

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 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

Baldwin 1 Baldwin 1 1,114

Baldwin 3 Baldwin 3 1,318

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 21st day of December 2000 by a vote of 7-0.

Dorothy M. Gunn, Clerk

Illinois Pollution Control Board