ILLINOIS POLLUTION CONTROL BOARD

Section 211.102 Abbreviations and Conversion Factors

TITLE 35: ENVIRONMENTAL PROTECTION
SUBTITLE B: AIR POLLUTION
1. CHAPTER I: POLLUTION CONTROL BOARD
2. SUBCHAPTER c: EMISSION STANDARDS AND LIMITATIONS FOR STATIONARY SOURCES
  1. PART 217
  2. NITROGEN OXIDES EMISSIONS
Section 217.760 NOx Trading Budget

ILLINOIS POLLUTION CONTROL BOARD
November 16, 2000

IN THE MATTER OF:		)
	)
PROPOSED NEW 35 ILL. ADM. CODE 217,
)		R01-9
SUBPART W, THE NOX TRADING		) (Rulemaking - Air)
PROGRAM FOR ELECTRICAL GENERATING
)

UNITS, AND AMENDMENTS TO

)

35 ILL. ADM. CODE 211 AND 217	)

Proposed Rule. Second Notice.

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

Today the Board adopts for second notice a proposal to implement a nitrogen oxides (NOx) ¹ 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 the large EGUs at 30,701 tons of NOx per ozone season. The purpose of this cap is to reduce atmospheric contamination, most specifically for ozone. ²

The Illinois General Assembly has found that an emissions trading program is a cost-effective means of reducing NOx emissions (415 ILCS 5/9.9(a)(3) (1998 State Bar Edition, 1999 Supp.)). Further, the Illinois General Assembly has directed the Board to adopt regulations implementing such a program (415 ILCS 5/9.9(b) (1998 State Bar Edition, 1999 Supp.)). The Board’s action today is in response to that directive.

Today’s second-notice proposal follows substantially the proposal filed with the Board by the Illinois Environmental Protection Agency (Agency) on July 11, 2000, and adopted by the Board for first notice on July 13, 2000. ³ The principal provisions of the trading program occur in a proposed new subpart at 35 Ill. Adm. Code 217.Subpart W. The proposal also includes conforming amendments in Parts 211 and 217.

The Board notes that there is general and substantial support on the part of the stakeholders for an emissions trading program such as presented in today’s proposal. We note as well, however, that the emissions reductions necessary to comply with the federal cap are severe. This has fostered some polarization among various stakeholders regarding how best to phase in the trading program, including issues such as how to accommodate early reduction credits, how to make initial allowance allocations, and how and when to phase to a fully market-controlled program. We believe that the proposal offered by the Agency strikes a most equitable compromise, within the scope allowed by the General Assembly, among the contending interests.

PROCEDURAL HISTORY

The Board held public hearings in this matter in Springfield, Illinois, on August 28 and 29, 2000, and in Chicago, Illinois, on September 26, 2000, before Board Hearing Officer Catherine Glenn. ⁴ Hearings were scheduled and conducted in accordance with Section 28.5 of the Environmental Protection Act (Act) (415 ILCS 5/28.5 (1998)). Section 28.5 provides for “fast-track” adoption of certain regulations necessary for compliance with the CAAA.

The Agency presented various management and technical staff as witnesses. Stakeholder testimony was presented by Tony Shea on behalf of ABB Energy Ventures and Grand Prairie Energy (Exh. 30; Tr.2 at 12-22); Joseph N. Darguzas on behalf of EnviroPower, L.L.C. (Exh. 31; Tr.2 at 23-29); Michael Menne on behalf of Ameren Corporation (Exh. 32; Tr.2 at 30-63, 223-230); Brian Urbaszewski on behalf of the American Lung Association of Metropolitan Chicago, The Illinois Environmental Council, The Environmental Law and Policy Center, and The Illinois Public Interest Research Group (Exh. 34; Tr.2 at 77-114); Lenny DePuis on behalf of Dominion Generation (Exh. 35; Tr.2 at 115-141); J. Derek Furstenwerth on behalf of Reliant Energy, Incorporated (Exh. 37 and 38; Tr.2 at 147-166); Scott Miller and Kent Wanninger on behalf of Midwest Generation EME, LLC (Exh. 38; Tr.2 at 167-182); Mary Schoen on behalf of Enron Corporation (Exh. 40; Tr.2 at 184-222); and Aric Diericx on behalf of Dynegy Midwest Generation (Exh. 41; Tr.2 at 232-239).

The record in this matter closed on October 13, 2000, as provided for at Section 28.5(l) of the Act. Ten public comments have been filed: Dynegy Midwest Generation (PC 1); EnviroPower (PC 2 and PC 8); The Agency (PC 3); Office of Public Utilities, City of Springfield (PC 4); Ameren Corporation (PC 5); Midwest Generation EME, LLC (PC 6); Enron Corp (PC 7); Environmental Law and Policy Center (PC 9); and Chicago Department of Environment (PC 10).

REGULATORY FRAMEWORK

Federal Actions/Requirements

Requirement for Attainment of the Ozone National Ambient Air Quality Standard

The State of Illinois has the primary responsibility under the CAAA for ensuring that all National Ambient Air Quality Standards (NAAQS) are met in the State. This includes the NAAQS for ozone. 42 U.S.C. § 7407(a) (1990). Currently there are two areas of the State which do meet the one-hour ozone NAAQS. These areas are the Chicago and Metro-East ozone nonattainment areas (NAA). ⁵

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. ⁶ 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.

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. ⁷

The NOx SIP Call also suggests, but does not require, that states adopt a “cap and trade” strategy for the control of NOx emissions from EGUs. The Illinois General Assembly has determined that the Illinois NOx SIP Call is to be met using the “cap and trade” system as outlined in the NOx SIP Call. 415 ILCS 5/9.9 (1998 State Bar Edition, 1999 Supp.); also see below.

Under the NOx SIP Call, USEPA has determined that the NOx emissions budget (i.e., cap) for large EGUs in Illinois is 30,701 tons during the ozone season. ⁸ Tr.1 at 100. To participate in the interstate NOx trading program, Illinois must submit a SIP in which all affected sources in Illinois combined emit no more than 30,701 tons of NOx per season, adjusted for emission allowances purchased from and sold to out-of-state EGUs.

An emission allowance is a permit to emit one ton of NOx. Thus, pursuant to the NOx SIP Call, Illinois’ large EGUs are allocated 30,701 allowances annually. The trading rules promulgated by the various states are to include methods of allocating those allowances among each state’s emitters, within limits allowed in the NOx SIP Call. Because the emission budgets in a given state and the total allocations in the aggregate of affected states are capped, the allocations do not affect the total NOx emissions from EGUs, but only the distribution of the emissions. Exh. 40 at 2.

Action in Federal Court

The NOx SIP Call was challenged before the U.S. Court of Appeals for the D.C. Circuit. See Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000). That court subsequently stayed the effective date of the NOx SIP Call rule. Michigan v. EPA, No. 98-1497, (D.C. Cir. May 25, 1999) (order granting stay). However, on March 3, 2000, the court upheld most of the NOx SIP Call rule. Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000). ⁹ On September 20, 2000, and October 20, 2000, a total of three writs of certiorari were filed in the Supreme Court. See Michigan v. EPA, U.S., Nos. 00-445, 00-632, 00-633. As of this date, the Supreme Court has not indicated whether it intends to hear the appeals. Other NOx-related court actions are also pending. ¹⁰

Ameren Corporation (Ameren) contends that attainment of the ozone NAAQS in the two Illinois nonattainment areas can be achieved with a lesser reduction in NOx emissions than is required under the NOx SIP Call. Tr.2 at 34-38; Exh. 32; PC 5. Ameren thus observes that if the NOx SIP Call is overturned in the courts, Illinois should adopt a less stringent NOx control policy. PC 5 at 2-3.

The Board cannot, of course, base its decision in this matter on a prospective outcome of a court action. It is necessary for the Board to make its decision based on the current status of the law. In that regard, the Board believes the law requires that we move forward with the proposal presented to us by the Agency. The Board will revisit our decision if a change in the law requires.

State Actions/Requirements

Section 9.9 of the Act (Nitrogen oxides trading system)

The Illinois General Assembly in 1999 adopted new Section 9.9 of the Act titled “Nitrogen oxides trading system.” ¹¹ 415 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:

1.	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;

2.	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;

4.	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

5.	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.

A.	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.

B.	The Agency may charge EGUs that commence commercial operation, as defined in 40 CFR Section 96.2, on or after
	January 1, 2003, for the allowances it issues to them.

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

The Board has reviewed today’s proposal, and finds that it complies with each of the required parts of Section 9.9(d).

PROPOSAL BACKGROUND

Proposal Development

Today’s action is the most recent in a long series of actions designed to achieve compliance with CAAA regulations in the State of Illinois. Since the 1980s, Illinois has pursued strategies to control ground-level ozone, and has had significant, but not complete, success as measured by decreases in the number of recorded violations of the ozone one-hour NAAQS. Tr.1 at 40.

Beginning in 1998, following issuance of the NOx SIP Call, the Agency commenced regular meetings with persons interested in development of the instant rules. Members of the affected industries and environmental groups were included in the meetings. Statement at 36-37. These meetings provided the Agency with the perspective it used to develop the instant proposal. The Agency contends that the proposal “represents a sound approach to those areas of discretion permitted under the federal NOx Trading Program.” Statement at 39.

Scope and Affected Facilities

The geographic region subject to the NOx Trading Program for EGUs is the entire State of Illinois. Statement at 20. There are approximately 100 existing EGUs within this region, all of which are expected to be affected by the proposed regulations. Statement at 20. The regulations also will affect any new EGUs (i.e., those that commenced operation on or after January 1, 1995) that serve a generator greater than 25 megawatts, or any unit with a maximum design heat input that is greater than 250 mmbtu/hr and that has the potential to use more than 50% of the “potential electrical output capacity.” Statement at 20-21.

Implementation Date

At first notice the date for full implementation of the NOx trading program was May 1, 2003. This date was part of the original NOx SIP Call and is included in Section 9.9 of the Act. However, on August 30, 2000, the D.C. Circuit Court of Appeals issued an order extending the deadline for full implementation to May 31, 2004. See Michigan v. EPA, No. 98-1497 (D.C. Cir. 2000).

At hearing the Agency filed a motion to amend its proposal to incorporate the later, May 31, 2004 implementation date ordered by the Court of Appeals. See Exh. 33. The Board grants that motion, and includes in today’s proposal all the changes requested in the Agency’s motion. ¹²
The Board notes that, as of the current date, USEPA has not explained how it will incorporate aspects of the date change into Part 96, including how to implement the May 31, 2000 start of the trading program. The Agency recommends certain changes to the first proposal to allow the USEPA, explanation when issued, to be incorporated into the Illinois rule. The Board agrees with this strategy, and incorporates those changes into today’s proposal.

NOx TRADING PROGRAM

Mandatory Provisions

Much of the NOx trading program proposed today is mandatory, in that a trading program compatible with 40 C.F.R. Part 96 is required under Section 9.9 of the Act. States that participate in the trading program of Part 96 have limited discretion in adopting state programs. Part 96 limits state discretion to assure that the principal parts of the NOx trading program will be standard in all affected states. Exh. 25 at 5. In today’s proposal these mandatory provisions are effectuated via incorporation by reference. See proposed Section 217.104 and 217.754(a). ¹³

Among the mandatory provisions are provisions relating to management of NOx accounts, including the structure of accounts, account flow control, banking of allowances, and the responsibilities of account representatives. The mandatory provisions also included elements related to monitoring and reporting of NOx emissions.

The Board will not review here in further detail the mandatory provisions of the NOx trading program. The Board directs interested persons to the NOx SIP Call for the specifics.

Optional Provisions

Part 96 provides for a small amount of flexibility in the tailoring of individual state programs. Today’s proposal employs that flexibility in four areas, as follows:

1.	whether to allow low-emitting NOx emission units to opt out of the trading system;

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

3. whether to allow credit for early reductions emission; and

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

“Opt-In” Provision

Part 96 also provides that a state program may allow certain emissions sources that are not otherwise included into the trading program to elect to participate in the trading program. The “opt-in” provisions are included in the instant regulations at Sections 217.774 to 217.782. The provisions are limited to operating fossil fuel-fired stationary boilers, combustion turbines, or combined cycle systems. See proposed Section 217.774(a). “Opt-in” provisions in state law must comport with the parallel provisions in Part 96, and they so do in the instant proposal. “Opt-in” units must also comply with the NOx SIP Call regulations of 40 C.F.R. Part 75.

Early Emission Reduction Credit (ERC)

The NOx SIP Call includes a Compliance Supplement Pool consisting of allowances available to states’ emission sources in the first years of the trading program. States have some discretion in how these allowances may be distributed. The Agency recommends that these allowances be used to bankroll an Early Emission Reduction Credit (ERC). See proposed Section 217.770. The Board agrees.

EGUs earn allowances from the ERC pool by reducing emissions earlier than otherwise required. The NOx SIP Call currently provides that early reductions must occur in the 2001 and 2002 control periods, and that the allowances so earned must be used in the 2003 and 2004 control periods. 63 Fed. Reg. 57,529 (October 27, 1998). However, in its Motion to
Amend (Exh. 33), the Agency proposes including 2003, in addition to 2001 and 2002, as a control period year in which the early reductions must occur. Exh. 33 at 4. The Agency explains that the D.C. Circuit Court of Appeals’ order on August 30, 2000, did not address whether the dates regarding the control periods for ERCs should be adjusted. However, the Agency’s preliminary contact with USEPA suggests that USEPA, in response to the
August 30, 2000 ruling, will allow ERCs to be earned in the 2003 control period. The Board has accordingly accepted this change in Section 217.770.

The Agency also notes in its Motion to Amend that the USEPA has preliminarily indicated that ERCs may only be used in the 2004 control period. Exh. 33 at 4. The Agency has accordingly recommended that the proposal be modified to not only allow ERCs to be used in 2004, but also in any years authorized by USEPA. PC 3 at 15.

Ameren testified that ERCs should only be earned during the 2001 and 2002 control periods, in part because they believe allowing credits to be earned in 2003 would not give them enough time to know how to manage compliance in 2004. Tr.2 at 47. Midwest Generation also argues that allowing ERCs to be earned in 2003 is inappropriate. PC 6 at 8. The Board appreciates these comments, but supports adjusting the timeframes for earning ERCs in accordance with the Agency’s Motion to Amend. See Section 217.770.

Allocation of NOx Allowances

“Fixed/Flex” Allocation

States are allowed latitude under the NOx SIP Call to determine how allowances are to be allocated among emitters. Pursuant to the USEPA budget emission for Illinois, NOx emissions from all Illinois EGUs are capped at 30,701 tons per ozone season. Tr.1 at 100. This is the total Illinois NOx allocation for large EGUs. Tr.1 at 100. It is much less than current emissions. ¹⁴ Thus, any allocation system by necessity requires existing EGUs to significantly decrease their emissions. It also requires that new EGUs use “clean” technologies.

The Agency negotiated with affected sources to try to create a balanced approach to allocating the limited number of allowances. PC 3 at 8. The approach which the Agency proposes, and which the Board adopts today, is termed a “fixed/flex” allocation scheme. Initially, the large percentage of allowances are allocated to existing emitters based on historical emission rates. The list of existing emitters is presented in the proposal at Part 217.Appendix F. As time progresses, the allocations “flex” to accommodate changes in the identity and mix of EGUs as older EGUs are phased out or modified, and as new EGUs come on line as replacements or new additions to the total EGU population. See proposed Section 217.762.

In the years 2004, 2005, and 2006, the sources listed in proposed Part 217.Appendix F will receive the number of allowances listed in column 7 of Appendix F. The total allocations in column 7 amount to 95% of the 30,701 total allowances. The remaining 5% are set aside for new EGUs that are not included in Part 217.Appendix F.

For the years 2007 and 2008, the EGUs in Appendix F will receive approximately 80% of the allowances specified in column 7. See 217.Appendix F, column 8. Additionally, 2% will be set aside for new EGUs, and the remaining allowances will be reserved for flexible allocation based on the formula in proposed Section 217.762. At this stage some of the EGUs which were “new” for the purposes of the earlier allocations will begin to quality for and draw their allocations from the “flex” portion of the NOx budget.

In 2009 and 2010, the procedures above will be repeated, except that both the “fixed” and “flex” portions of the allocation are 50% of the budget, reserving 2% for a new source set-aside. Starting with 2011, allowances will be allocated to all existing EGUs (those in Appendix F and those that rolled into the flex portion) on the basis of average control period heat input.

New Source Set-Aside

Section 9.9(d)(5) of the Act provides that the NOx trading program shall include a provision that the Agency “set aside annually a number of allowances, not to exceed 5% of the total EGU trading budget, to be made available to new EGUs.” See 415 ILCS 5/9.9(d)(5). Today’s proposal incorporates this provision at Section 217.768, “New Source Set-Asides for ‘New’ Budget EGUs.” Among other things, the provision allows that each new source set-aside will be allocated allowances equal to 5% of the EGU trading budget in 2004, 2005, and 2006. See proposed Section 217.768(c)(1). Beginning in 2007, new source set-asides will be allocated allowances equal to 2% of the 2007 trading budget. See proposed Section 217.768(c)(2).

The NOx SIP Call also contains a 5% set-aside provision for the first three control seasons, followed by a 2% provision for the control periods thereafter. 63 Fed. Reg. 57,471. However, USEPA left it up to individual states’ discretion whether to adopt a set-aside provision, including the size of the set-aside. 63 Fed. Reg. 57,471.

Both at hearing and in public comment, some representatives of new EGUs expressed concern that a new source set-aside of 5%, which later decreases to 2%, is insufficient for their needs. Tr.2 at 14; PC 8 at 5-8; PC 10 at 3. Some participants recommend that the Board maintain the statutory maximum of 5%. PC 8 at 9; Tr.2 at 16, 157. Some participants also suggest the Agency seek legislative approval to increase the 5% maximum. Tr.2 at 16.

At hearing, the Agency explained the rationale for decreasing the 5% maximum to 2% in 2007. The Agency first noted that those EGUs that are eligible for the new source set-aside allocation are those EGUs that began operation on or after January 1, 1995. Tr.1 at 84. Therefore, when the implementation date occurs (May 31, 2004), roughly a decade’s worth of new EGUs will get their allocations from this set-aside. Tr.2 at 84. However, the demand for allowances from the set-aside will begin to decrease as of the year 2007, when the new EGUs start drawing allowances from the flex portion of the NOx budget. Thus, beginning in 2007, when the set-aside is set at the 2% maximum, the Agency anticipates that there will be fewer new sources that apply for the allowances from the set-aside. Tr.1 at 84. The Agency also noted in its prefiled testimony that the new source set-aside allocations follow the levels suggested in the NOx SIP Call. Exh. 25 at 15.

Additionally, some participants argue that the proposal unduly favors the existing EGUs over the new EGUs because the existing EGUs are guaranteed the “fixed” allocations, and the new EGUs can only access the allocations available in the new source set-aside; they contend that these are not enough to meet the projected demand. Tr.2 at 153-154; PC 8 at 8-12. However, existing EGUs note that even with the fixed allocations, they will incur great costs to comply with the new Subpart W. PC 5 at 4. Namely, they will be forced to achieve great control levels due to the projected oversubscription in allowances. PC 5 at 4.

Other participants contend that the Agency’s allocation system is equitable, and should be adopted by the Board. e.g., PC 5 at 3, PC 6 at 3-4. They note that the Agency developed the proposal only after extensive efforts to reach out to all interested parties, and that no stakeholder was hindered from presenting its point of view. PC 5 at 3.

The Board concludes that the allocation system proposed by the Agency is fair and reasonable. Additionally, the 5% change to 2% is consistent with the USEPA’s suggested
set-aside provision. Accordingly, the Board retains these provisions in today’s proposal.

Energy Efficiency/Renewable Energy Set-Aside

The American Lung Association et al. (Exh. 34 at 6-7; Tr.2 at 91-93), the Environmental Law and Policy Center (PC 9), the Chicago Department of Environment (PC 10), and Enron Corp. (PC 7), each recommend that the Board provide a set-aside for energy efficiency and renewable energy measures. The Agency opposes this idea, but does not explain its basis for its opposition. PC 3 at 28.

The Board believes that measures to increase energy efficiency are admirable and needed. Similarly, the Board believes that reliable, cost-effective renewable energy needs to be aggressively developed. However, the Board is not convinced that the set-aside proposal is an appropriate or productive method to achieve these ends, especially in view of the small amount of emission allowances available in Illinois.

Charges for Allowances

Proposed Section 217.768(k) contains a provision that would impose a market-rate fee on allowances awarded to EGUs that start operations after January 1, 2004. Several participants contend that this provision should be deleted or significantly modified. e.g., Tr.2 at 17-18; PC 8 at 17. Specifically, some participants suggest that the allocation methodology favors existing EGUs over new EGUs, because new EGUs that commence commercial operation on or after January 1, 2004, and get allowances from the new source set-aside will have to pay for the allocations. See proposed Section 217.768(k); Tr.2 at 17-18, 94-100, 157-159. ¹⁵ Section 9.9(d)(5)(B) of the Act allows the Agency to charge these EGUs for their allowances. 415 ILCS 5/9.9(d)(5)(B) (1998 State Bar Edition, 1999 Supp.). At first notice, proposed Section 217.768(k)(3) allowed the Agency, after covering administrative costs, to give fees collected from the sale of allowances on a pro-rata basis to EGUs receiving allowances under Section 217.764. ABB Energy Ventures believes proposed Section 217.768(k)(3) mandates that new EGUs subsidize existing EGUs, which they assert is unfair and places a disproportionate burden on new EGUs. Tr.2 at 18, 22. If any fee is to be charged at all, ABB Energy Ventures argues the fee should only cover the Agency’s administrative costs. Tr.2 at 18. Enviropower also argues that the fees charged to the new sources should only cover the Agency’s administrative costs. PC 8 at 17.

The Agency responds that charging new EGUs for their allowances will deter sources from asking for more allowances than they need, which will help limit oversubscription to the new source set-aside. PC 3 at 13. The Agency further notes that charging for allowances is allowed under Section 9.9. PC 3 at 13-14. Additionally, Section 9.9(i)(2) of the Act authorizes the Agency to disburse the proceeds of the NOx allowances sales pro-rata to the EGUs that were 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 ¹⁶ published by the USEPA as background information. Further, the Agency relied on the information contained in the USEPA’s Regulatory Impact Analysis for the NOx SIP Call (63 Fed. Reg. 57,356), the proposed Federal Implementation Plan (FIP) (63 Fed. Reg. 56,394), and USEPA’s proposed findings on various petitions filed under Section 126 of the CAAA (65 Fed. Reg. 2,674) to support its proposal. Exh. 27 and PC 3 at 19-20.

The USEPA’s analysis of the cost impact of the NOx SIP Call on large EGUs involved the determination of the “cost effectiveness,” which is measured as the cost in dollars per ton of NOx reduced, of various alternative NOx control levels. USEPA chose a NOx control level of 0.15 lbs per mmbtu to be highly cost effective for reducing emissions from large EGUs. 63 Fed. Reg. 57,399 – 57,402. Based on this control level, the USEPA determined the average cost effectiveness for NOx control on a region wide (23 jurisdictions) basis to be $1,468 per ton of NOx. USEPA notes that for large EGUs the average cost effectiveness of $1,468 per ton of NOx is consistent with the range of cost effectiveness for various control measures. 63 Fed. Reg. 57,401.

Although the Agency relies on the USEPA’s cost analysis to support its proposal, the Agency performed its own cost impact analysis. The Agency determined the cost effectiveness to be $1,486 per ton of NOx. Exh. 27 at 10. In addition, the U.S. Department of Energy also made a separate analysis of the cost impact of the NOx SIP Call and found the cost effectiveness to be $1,460 per ton of NOx. Exh. 27 at 10. All the three analyses included trading in their assessments.

Ameren and Dynegy Midwest Generation expressed concerns regarding the Agency’s compliance cost estimates. They assert that the costs of NOx control for their units would be much higher than the USEPA estimate. Ameren testified that it would cost Ameren $130 million ($8,784 per ton of NOx) to come into compliance with the proposed regulation. Tr.2 at 36 and Exh. 32 at 5. They also noted that the incremental cost of reducing NOx emissions from a control level of 0.25 lbs per mmbtu (0.25 rule) to the proposed control level of 0.15 lbs per mmbtu would be $100 million. Dynegy Midwest Generation also stated that the Agency has underestimated the compliance cost. They noted that the incremental cost of reducing NOx from a control level of 0.25 lbs per mmbtu to the proposed control level of 0.15 lbs per mmbtu for Dynegy Midwest Generaton would be $7,339 per ton of NOx over a five-year period or $4,582 per ton of NOx over a ten-year period. Exh. 41 at 6-7.

The Board believes that a principle factor that should be considered in determining the economic impact of the proposed regulations is the flexibility afforded to the affected entities to participate in a trading program to determine their compliance alternatives. As the Agency notes, the USEPA determined that NOx control level of 0.15 lbs per mmbtu to be highly cost effective in the realm of a trading program. The instant proposal does not require all affected units to reduce NOx emissions by using control options. An affected unit may comply with the NOx emissions limitation either by using control options or by purchasing the necessary allowances to cover its emissions. Each affected source has to make a determination as to the compliance option based on a number of factors such as the type of boiler, existing control technology, cost of additional control, amount of emissions reductions, etc.

The Board recognizes that the cost of emissions control vary from unit to unit, as illustrated in Ameren’s comments. PC 5, Attachment 2. Although the cost of achieving compliance for a specific unit may exceed the average cost effectiveness determined by USEPA, the Board believes that the economic impact of the proposed regulations must be evaluated in terms of the overall cost imposed by the trading program. Regarding the affected sources’ cost estimates, the Board agrees with the Agency that the use of incremental costs between two levels of NOx control to show that the cost effectiveness of NOx control is significantly higher is inappropriate. Any comparison of compliance costs of two different control levels should consider differential costs between the two levels with respect to the base line emissions. PC 3 at 21. Moreover, the Board notes that the evaluation of even the differential costs is not relevant in this proceeding since the instant regulations address only one NOx control level (0.15 lbs per mmbtu) which the USEPA has determined to be highly cost effective.

In light of the above, the Board finds that the USEPA’s determination of average cost effectiveness of $1,468 per ton of NOx for large EGUs to be reasonable. Further, the Board finds that the proposed trading program provides flexibility to the affected sources to achieve compliance at lower costs. The Board also notes that the average cost effectiveness of NOx control for large EGUs is similar to the cost effectiveness of various VOC control measures adopted by this Board pursuant to the CAAA. In addition, the Board finds that technically feasible control technologies are available for reducing NOx emissions from large EGUs. In sum, the Board finds that the proposed regulations for reducing NOx emissions from large EGUs to be economically reasonable and technically feasible.

CONCLUSION

Pursuant to federal law, large EGUs in Illinois are required to significantly reduce emissions of NOx during the ozone season. Faced with this circumstance, Illinois has sought, within the parameters allowed us by federal and State law, to find an equitable and economic method of bringing about that reduction.

The Board appreciates the extensive effort undertaken by various stakeholders in this matter to inform both the Agency and us regarding their interests. We believe that the Agency proposal strikes an appropriate balance among these various interests, and for this reason we today adopt the Agency’s proposal, with minor modification, for second notice.

ORDER

The Board hereby proposes for second notice the following amendments to 35 Ill. Adm. Code 211 and 217. The Clerk of the Board is directed to file these proposed rules with the Joint Committee on Administrative Rules.

TITLE 35: ENVIRONMENTAL PROTECTION
SUBTITLE B: AIR POLLUTION
CHAPTER I: POLLUTION CONTROL BOARD

SUBCHAPTER c: EMISSION STANDARDS AND LIMITATIONS FOR STATIONARY SOURCES

PART 211
DEFINITIONS AND GENERAL PROVISIONS

SUBPART A: GENERAL PROVISIONS

Section

211.101	Incorporations by Reference
211.102	Abbreviations and Conversion Factors

SUBPART B: DEFINITIONS

Section

211.121	Other Definitions
211.122	Definitions (Repealed)
211.130	Accelacota
211.150	Accumulator
211.170	Acid Gases
211.210	Actual Heat Input
211.230	Adhesive
211.240	Adhesion Promoter
211.250	Aeration
211.270	Aerosol Can Filling Line
211.290	Afterburner
211.310	Air Contaminant
211.330	Air Dried Coatings
211.350	Air Oxidation Process
211.370	Air Pollutant
211.390	Air Pollution
211.410	Air Pollution Control Equipment
211.430	Air Suspension Coater/Dryer
211.450	Airless Spray
211.470	Air Assisted Airless Spray
211.474	Alcohol
211.479	Allowance
211.484	Animal
211.485	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
211.570	Asphalt
211.590	Asphalt Prime Coat
211.610	Automobile
211.630	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
211.670	Baked Coatings
211.680	Bakery Oven
211.685	Basecoat/Clearcoat System
211.690	Batch Loading
211.695	Batch Operation
211.696	Batch Process Train
211.710	Bead-Dipping
211.730	Binders
211.750	British Thermal Unit
211.770	Brush or Wipe Coating
211.790	Bulk Gasoline Plant
211.810	Bulk Gasoline Terminal
211.820	Business Machine Plastic Parts
211.830	Can
211.850	Can Coating
211.870	Can Coating Line
211.890	Capture
211.910	Capture Device
211.930	Capture Efficiency
211.950	Capture System
211.970	Certified Investigation
211.980	Chemical Manufacturing Process Unit
211.990	Choke Loading
211.1010	Clean Air Act
211.1050	Cleaning and Separating Operation
211.1070	Cleaning Materials
211.1090	Clear Coating
211.1110	Clear Topcoat
211.1130	Closed Purge System
211.1150	Closed Vent System
211.1170	Coal Refuse
211.1190	Coating
211.1210	Coating Applicator
211.1230	Coating Line
211.1250	Coating Plant
211.1270	Coil Coating
211.1290	Coil Coating Line
211.1310	Cold Cleaning
211.1312	Combined Cycle System
211.1316	Combustion Turbine
211.1320	Commence Commercial Operation
211.1324	Commence Operation
211.1328	Common Stack
211.1330	Complete Combustion
211.1350	Component
211.1370	Concrete Curing Compounds
211.1390	Concentrated Nitric Acid Manufacturing Process
211.1410	Condensate
211.1430	Condensible PM-10
211.1465	Continuous Automatic Stoking
211.1467	Continuous Coater
211.1470	Continuous Process
211.1490	Control Device
211.1510	Control Device Efficiency
211.1515	Control Period
211.1520	Conventional Air Spray
211.1530	Conventional Soybean Crushing Source
211.1550	Conveyorized Degreasing
211.1570	Crude Oil
211.1590	Crude Oil Gathering
211.1610	Crushing
211.1630	Custody Transfer
211.1650	Cutback Asphalt
211.1670	Daily-Weighted Average VOM Content
211.1690	Day
211.1710	Degreaser
211.1730	Delivery Vessel
211.1750	Dip Coating
211.1770	Distillate Fuel Oil
211.1780	Distillation Unit
211.1790	Drum
211.1810	Dry Cleaning Operation or Dry Cleaning Facility
211.1830	Dump-Pit Area
211.1850	Effective Grate Area
211.1870	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
211.1930	Emission Rate
211.1950	Emission Unit
211.1970	Enamel
211.1990	Enclose
211.2010	End Sealing Compound Coat
211.2030	Enhanced Under-the-Cup Fill
211.2050	Ethanol Blend Gasoline
211.2070	Excess Air
211.2080	Excess Emissions
211.2090	Excessive Release
211.2110	Existing Grain-Drying Operation (Repealed)
211.2130	Existing Grain-Handling Operation (Repealed)
211.2150	Exterior Base Coat
211.2170	Exterior End Coat
211.2190	External Floating Roof
211.2210	Extreme Performance Coating
211.2230	Fabric Coating
211.2250	Fabric Coating Line
211.2270	Federally Enforceable Limitations and Conditions
211.2285	Feed Mill
211.2290	Fermentation Time
211.2300	Fill
211.2310	Final Repair Coat
211.2330	Firebox
211.2350	Fixed-Roof Tank
211.2360	Flexible Coating
211.2365	Flexible Operating Unit
211.2370	Flexographic Printing
211.2390	Flexographic Printing Line
211.2410	Floating Roof
211.2420	Fossil Fuel
211.2425	Fossil Fuel-Fired
211.2430	Fountain Solution
211.2450	Freeboard Height
211.2470	Fuel Combustion Emission Unit or Fuel Combustion Emission Source
211.2490	Fugitive Particulate Matter
211.2510	Full Operating Flowrate
211.2530	Gas Service
211.2550	Gas/Gas Method
211.2570	Gasoline
211.2590	Gasoline Dispensing Operation or Gasoline Dispensing Facility
211.2620	Generator
211.2610	Gel Coat
211.2630	Gloss Reducers
211.2650	Grain
211.2670	Grain-Drying Operation
211.2690	Grain-Handling and Conditioning Operation
211.2710	Grain-Handling Operation
211.2730	Green-Tire Spraying
211.2750	Green Tires
211.2770	Gross Heating Value
211.2790	Gross Vehicle Weight Rating
211.2810	Heated Airless Spray
211.2815	Heat Input
211.2820	Heat Input Rate
211.2830	Heatset
211.2850	Heatset Web Offset Lithographic Printing Line
211.2870	Heavy Liquid
211.2890	Heavy Metals
211.2910	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
211.3010	Hood
211.3030	Hot Well
211.3050	Housekeeping Practices
211.3070	Incinerator
211.3090	Indirect Heat Transfer
211.3110	Ink
211.3130	In-Process Tank
211.3150	In-Situ Sampling Systems
211.3170	Interior Body Spray Coat
211.3190	Internal-Floating Roof
211.3210	Internal Transferring Area
211.3230	Lacquers
211.3250	Large Appliance
211.3270	Large Appliance Coating
211.3290	Large Appliance Coating Line
211.3310	Light Liquid
211.3330	Light-Duty Truck
211.3350	Light Oil
211.3370	Liquid/Gas Method
211.3390	Liquid-Mounted Seal
211.3410	Liquid Service
211.3430	Liquids Dripping
211.3450	Lithographic Printing Line
211.3470	Load-Out Area
211.3480	Loading Event
211.3490	Low Solvent Coating
211.3500	Lubricating Oil
211.3510	Magnet Wire
211.3530	Magnet Wire Coating
211.3550	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
211.3650	Marine Terminal
211.3660	Marine Vessel
211.3670	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
211.3910	Mixing Operation
211.3915	Mobile Equipment
211.3930	Monitor
211.3950	Monomer
211.3960	Motor Vehicles
211.3965	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
211.4055	Non-Flexible Coating
211.4065	Non-Heatset
211.4070	Offset
211.4090	One Hundred Percent Acid
211.4110	One-Turn Storage Space
211.4130	Opacity
211.4150	Opaque Stains
211.4170	Open Top Vapor Degreasing
211.4190	Open-Ended Valve
211.4210	Operator of a Gasoline Dispensing Operation or Operator of a Gasoline Dispensing Facility
211.4230	Organic Compound
211.4250	Organic Material and Organic Materials
211.4260	Organic Solvent
211.4270	Organic Vapor
211.4290	Oven
211.4310	Overall Control
211.4330	Overvarnish
211.4350	Owner of a Gasoline Dispensing Operation or Owner of a Gasoline Dispensing Facility
211.4370	Owner or Operator
211.4390	Packaging Rotogravure Printing
211.4410	Packaging Rotogravure Printing Line
211.4430	Pail
211.4450	Paint Manufacturing Source or Paint Manufacturing Plant
211.4470	Paper Coating
211.4490	Paper Coating Line
211.4510	Particulate Matter
211.4530	Parts Per Million (Volume) or PPM (Vol)
211.4550	Person
211.4590	Petroleum
211.4610	Petroleum Liquid
211.4630	Petroleum Refinery
211.4650	Pharmaceutical
211.4670	Pharmaceutical Coating Operation
211.4690	Photochemically Reactive Material
211.4710	Pigmented Coatings
211.4730	Plant
211.4740	Plastic Part
211.4750	Plasticizers
211.4770	PM-10
211.4790	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
211.4870	Polystyrene Plant
211.4890	Polystyrene Resin
211.4910	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
211.5010	Precoat
211.5030	Pressure Release
211.5050	Pressure Tank
211.5060	Pressure/Vacuum Relief Valve
211.5061	Pretreatment Wash Primer
211.5065	Primary Product
211.5070	Prime Coat
211.5080	Primer Sealer
211.5090	Primer Surfacer Coat
211.5110	Primer Surfacer Operation
211.5130	Primers
211.5150	Printing
211.5170	Printing Line
211.5185	Process Emission Source
211.5190	Process Emission Unit
211.5210	Process Unit
211.5230	Process Unit Shutdown
211.5245	Process Vent
211.5250	Process Weight Rate
211.5270	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)
211.5390	Reclamation System
211.5410	Refiner
211.5430	Refinery Fuel Gas
211.5450	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
211.5510	Reid Vapor Pressure
211.5530	Repair
211.5550	Repair Coat
211.5570	Repaired
211.5580	Repowering
211.5590	Residual Fuel Oil
211.5600	Resist Coat
211.5610	Restricted Area
211.5630	Retail Outlet
211.5650	Ringelmann Chart
211.5670	Roadway
211.5690	Roll Coater
211.5710	Roll Coating
211.5730	Roll Printer
211.5750	Roll Printing
211.5770	Rotogravure Printing
211.5790	Rotogravure Printing Line
211.5810	Safety Relief Valve
211.5830	Sandblasting
211.5850	Sanding Sealers
211.5870	Screening
211.5890	Sealer
211.5910	Semi-Transparent Stains
211.5930	Sensor
211.5950	Set of Safety Relief Valves
211.5970	Sheet Basecoat
211.5980	Sheet-Fed
211.5990	Shotblasting
211.6010	Side-Seam Spray Coat
211.6025	Single Unit Operation
211.6030	Smoke
211.6050	Smokeless Flare
211.6060	Soft Coat
211.6070	Solvent
211.6090	Solvent Cleaning
211.6110	Solvent Recovery System
211.6130	Source
211.6140	Specialty Coatings
211.6145	Specialty Coatings for Motor Vehicles
211.6150	Specialty High Gloss Catalyzed Coating
211.6170	Specialty Leather
211.6190	Specialty Soybean Crushing Source
211.6210	Splash Loading
211.6230	Stack
211.6250	Stain Coating
211.6270	Standard Conditions
211.6290	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
211.6490	Substrate
211.6510	Sulfuric Acid Mist
211.6530	Surface Condenser
211.6540	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
211.6650	Tooling Resin
211.6670	Topcoat
211.6690	Topcoat Operation
211.6695	Topcoat System
211.6710	Touch-Up
211.6720	Touch-Up Coating
211.6730	Transfer Efficiency
211.6750	Tread End Cementing
211.6770	True Vapor Pressure
211.6790	Turnaround
211.6810	Two-Piece Can
211.6830	Under-the-Cup Fill
211.6850	Undertread Cementing
211.6860	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
211.7070	Vinyl Coating
211.7090	Vinyl Coating Line
211.7110	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
211.7190	Wash Coat
211.7200	Washoff Operations
211.7210	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
211.7350	Woodworking
211.7400	Yeast Percentage

211.Appendix A	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

a)	Abbreviations used in this Part include the following:

ASTM	American Society for Testing and Materials
bbl	barrels (42 gallons)
btu	British thermal units (60^oF)
btu/hr	btu per hour
^oC	degrees Celsius or centigrade
CAAPP	Clean Air Act Permit Program
cm	centimeters
cu in	cubic inches
EGU	Electrical Generating Unit
^oF	degrees Fahrenheit
FIP	Federal Implementation Plan
ft	feet
ft²	square feet
ft³	cubic feet
g	grams
gpm	gallons per minute
g/mole	grams per mole
gal	gallons
hp	horsepower
hr	hours
in	inch
^oK	degrees Kelvin
kcal	kilocalories
kg	kilograms
kg/hr	kilograms per hour
kPa	kilopascals; one thousand newtons per square meter
kW	kilowatt
l	liters
l/sec	liters per second
lbs	pounds
lbs/day	pounds per day
lbs/hr	pounds per hour
lbs/gal	pounds per gallon
lbs/yr	pounds per year
LEL	lower explosive limit
m	meters
m²	square meters
m³	cubic meters
mg	milligrams
Mg	Megagrams, metric tons or tonnes
ml	milliliters
min	minutes
MJ	megajoules
mmbtu	million British thermal units
mmbtu/hr	million British thermal units per hour
mmHg	millimeters of mercury
MTE	maximum theoretical emissions
MWe	megawatt of electricity
MW	megawatt; one million watts
MW-hr	megawatt per hour
NDO	natural draft opening
NO_x	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
sq cm	square centimeters
sq in	square inches
T	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

b)	The following conversion factors have been used in this Part:

English	Metric
1 gal	3.785 1
1,000 gal	3,785 1 or 3.785 m³
1 psia	6.897 kPA (51.71 mmHg)
2.205 lbs	1 kg
32^o	0^oC (273.15^oK)
1 bbl	159.0 l
1 cu in	16.39 ml
1 lb/gal	119,800 mg/l
1 lb/mmbtu	1.548 kg/MW-hr
1 lb/T	0.500 kg/Mg
1 ton	0.907 Mg
1 T	0.907 Mg
mmbtu/hr	0.293 MW

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

Section 211.479	Allowance

“Allowance” means an authorization to emit up to one ton of NO_x during the control period of a specified year or any year thereafter under 35 Ill. Adm. Code 217 and 40 CFR part 96.

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

Section 211.1312
Combined Cycle System

“Combined Cycle System” means a system comprised of one or more combustion turbines, heat recovery steam generators, and steam turbines configured to improve overall efficiency of electricity generation or steam production.

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

Section 211.1316
Combustion Turbine

“Combustion Turbine” means an enclosed fossil or other fuel-fired device that is comprised of a compressor, a combustor, and a turbine, and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine.

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

Section 211.1320
Commence Commercial Operation

For purposes of allocation of allowances as described in 35 Ill. Adm. Code 217, “commence commercial operation” means, with regard to an EGU that serves a generator, to have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation. Such date shall remain the unit’s date of commencement of operation even if the EGU is subsequently modified, reconstructed or repowered.

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

Section 211. 1324
Commence Operation

For purposes of allocation of allowances as described in 35 Ill. Adm. Code 217, “commence operation” means with regard to a stationary boiler, combustion turbine, or combined cycle system to have begun any mechanical, chemical, or electronic process, including, start-up of the unit’s combustion chamber. Such date shall remain the unit’s date of commencement of operation even if the unit is subsequently modified, reconstructed, or repowered.

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

Section 211.1328
Common Stack

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

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

Section 211.1515
Control Period

For purposes of 35 Ill. Adm. Code 217, “control period” means the period beginning May 1 of a year and ending on September 30 of the same year, inclusive, except that in 2004, “control period” means May 31 through September 30.

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

Section 211.2080
Excess Emissions

“Excess emissions” means any tonnage of NO_x emitted by a NO_x budget unit during a control period that exceeds the NO_x 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_x 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_x TRADING PROGRAM FOR ELECTRICAL GENERATING UNITS

Section

217.750	Purpose
217.752	Severability
217.754	Applicability
217.756	Compliance Requirements
217.758	Permitting Requirements
217.760	NO_x Trading Budget
217.762	Methodology for Calculating NO_x Allocations for Budget Electrical Generating Units (“EGUs”)
217.764	NO_x Allocations for Budget EGUs
217.768	New Source Set-Asides for “New” Budget EGUs
217.770	Early Reduction Credits for Budget EGUs
217.774	Opt-In Units
217.776	Opt-In Process
217.778	Budget Opt-In Units: Withdrawal from NO_x 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

a)	This Part sets standards and limitations for emission of oxides of nitrogen from stationary sources.

b)	Permits for sources subject to this Part may be required pursuant to 35 Ill. Adm. Code 201.

c)	Notwithstanding the provisions of this Part the air quality standards contained in 35 Ill. Adm. Code 243 may not be violated.

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

~~1) Subpart A: General Provisions;~~

~~2) Subparts B-J: Fuel Combustion Sources and Incinerators;~~

~~3) Subparts K-M: Process Emission Sources;~~

~~4) 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:


a) The ~~the~~ phenol disulfonic acid method, ~~36 Fed. Reg. 15, 718~~ 40 CFR 60, Appendix A, Method 7. (1999); ~~and~~

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

c) 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

a) The following abbreviations are used in this Part:

btu British thermal unit (60^oF)
EGU Electrical Generating Unit
kg kilogram
kg/MW-hr kilograms per megawatt-hour, usually used as an hourly emission rate
lb pound
NO_x Nitrogen Oxides
lbs/mmbtu pounds per million btu, usually used as an hourly emission rate
Mg megagram or metric tonne
mmbtu million British thermal units
mmbtu/hr million British thermal units per hour
MWe megawatt of electricity
MW megawatt; one million watts
MW-hr megawatt-hour
peoc potential electrical output capacity
ppm parts per million
ppmv parts per million by volume

T English ton

b) The following conversion factors have been used in this Part:

English Metric
2.205 lb 1 kg
1 T 0.907 Mg
1 lb/T 0.500 kg/Mg
Mmbtu/hr 0.293 MW
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.

a) The ~~the~~ phenol disulfonic acid method as published in ~~36 Fed. Reg. 15, 718,~~ 40 CFR 60, Appendix A, Method 7. (1999);

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

c) 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

d) 40 CFR 72, 75 & 76 (1999).

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

SUBPART W: NO_x TRADING PROGRAM FOR ELECTRICAL GENERATING UNITS

Section 217.750 Purpose

The purpose of this Subpart is to control the emissions of nitrogen oxides (NO_x) 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_x 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

a)
The following fossil fuel-fired stationary boilers, combustion turbines or combined cycle systems are electrical generating units (EGUs) and are subject to this Subpart:


1) 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.

2) Any unit with a maximum design heat input that is greater than 250 mmbtu/hr that commences operation on or after January 1, 1999, serving at any time a generator that has a nameplate capacity of 25 MWe or less and has the potential to use more than 50% of the potential electrical output capacity of the unit. Fifty percent (50%) of a unit’s potential electrical output capacity shall be determined by multiplying the unit’s maximum design heat input by 0.0488 MWe/mmbtu. If the size of the generator is greater than this calculated number, the unit is an EGU subject to the provisions of this Subpart.


b)
Those units that meet the above criteria and are subject to the NO_x Trading Program emissions limitations contained in this Subpart are budget EGUs.

c)
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).

1) For each control period under this subsection (c), the federally enforceable permit conditions must:


A) Restrict the EGU to burning only natural gas, fuel oil, or natural gas and fuel oil;

B) Limit the EGU’s potential NO_x mass emissions for the control period to 25 tons or less;

C) Restrict the EGU’s operating hours during the control period to the number calculated by dividing 25 tons of potential NO_x mass emissions by the EGU’s maximum potential hourly NO_x mass emissions;

D) Require that the EGU’s potential NO_x 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:

i) Select the applicable default NO_x 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_x 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;


E) 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

F) 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.

2) 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:

A) The permit with federally enforceable conditions that includes the restrictions in subsection (c)(1) of this Section is issued by the Agency;

B)
Such permit is revised to remove any such restriction;

C) Such permit includes any such restriction that is no longer applicable; or

D)
The EGU does not comply with any such restriction.


3) 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.

4) 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_x emissions the EGU is permitted to emit during the control period as set forth in the EGU’s federally enforceable state operating permit.

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

a)
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.

b) Permit requirements:


1) 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_x Trading Program (“budget permit”) that complies with the requirements of Section 217.758 of this Part.

2) 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.

c) Monitoring requirements:


1) 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.

2) 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.

d) NO_x requirements:

1) 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_x 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.


2) Each ton of NO_x emitted in excess of the number of NO_x 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.

3) A budget EGU shall be subject to the monitoring and NO_x requirements of subsections (c)(1) and (d)(1) of this Section starting on the later of ~~May 1, 2003~~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_X 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_X TRADING PROGRAMS AND OTHER REQUIRED REDUCTIONS OF NO_X EMISSIONS PURSUANT TO THE NO_X 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.

4) 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.

5) 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.

6) An allowance allocated by the Agency or USEPA under the NO_x Trading Program is a limited authorization to emit one ton of NO_x in accordance with the NO_x Trading Program. No provision of the NO_x 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.

7) An allowance allocated by the Agency or USEPA under the NO_x Trading Program does not constitute a property right.

8) 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.

e) Recordkeeping and reporting requirements:

1) 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.


A) 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.

B) 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.

C) Copies of all reports, compliance certifications, and other submissions and all records made or required under the NO_x Trading Program or documents necessary to demonstrate compliance with the requirements of the NO_x Trading Program or with the requirements of this Subpart.

D) Copies of all documents used to complete a budget permit application and any other submission under the NO_x Trading Program.

2) 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_x Trading Program, including those under 40 ~~part~~ CFR 96, subparts D and H, and Section 217.774 of this Part.

f) Liability:


1) No revision of a permit for a budget EGU shall excuse any violation of the requirements of the NO_x Trading Program that occurs prior to the date that the revision to such budget permit takes effect.

2) Each budget source and each budget EGU shall meet the requirements of the NO_x Trading Program.

3) Any provision of the NO_x 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.

4) Any provision of the NO_x 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.

5) ~~Excess emissions requirements.~~ The account representative of a budget EGU that has excess emissions in any control period shall:

A) S surrender the allowances as required for deduction under 40 CFR 96.54(d)(1)~~; and~~.

6) ~~B) Pay~~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.

g) Effect on other authorities. No provision of the NO_x Trading Program, a budget permit application, a budget permit, a low-emitter exemption under Section 217.754(c) of this Subpart,~~40 CFR 96.4(b),~~ or a retired unit exemption under 40 CFR 96.5 shall be construed as exempting or excluding the owner and operator and, to the extent applicable, the account representative of a budget source or budget EGU, from compliance with any other regulation promulgated under the CAA, the Act, an approved State implementation plan, or a federally enforceable permit.

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

Section 217.758 Permitting Requirements

a) Budget permit requirements:


1) Each source with a budget EGU is required to submit a complete permit application addressing all applicable NO_x 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.

2) Each budget permit (including a draft or proposed budget permit, if applicable) shall contain federally enforceable conditions addressing all applicable NO_x Trading Program requirements and shall be a complete and segregable portion of the source’s entire permit under subsection (a)(1) of this Section.

3) No budget permit shall be issued, and no NO_x 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.

4) 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.

5) 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.

6) 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.

b) Budget permit applications:


1) 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.

2) 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:

A) Identification of the source, including plant name. The ORIS (Office of Regulatory Information Systems) or facility code assigned to the source by the Energy Information Administration shall also be included, if applicable;


B) 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;

C) The compliance requirements of Section 217.756 of this Part; and

D) For each opt-in unit at the source the following certification statements by the account representative:


i) “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.”

3) 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 ____________________)

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Section 217.760
NO_x Trading Budget

The NO_x trading budget available for allowance allocations for each control period shall be determined as follows:

a) The total base EGU trading budget is 30,701 tons per control period subject, however, to the following:


1) 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

2) 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.


b) The Agency ~~may~~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.

c) 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_x 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:

a) The applicable NO_x emission rates are as follows:


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

2) For budget EGUs not listed in Appendix F: The more stringent of 0.15 lb/mmbtu or the permitted NO_x emission rate, but not less than 0.055 lb/mmbtu.

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

1) 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:


A) If the budget EGU has heat input for the control period four years prior to the year for which the NO_x 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

B) If the budget EGU has heat inputs for the control periods four and five years prior to the year for which the NO_x 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.

2) 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:


A) 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

B) 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.

c) The general equation for determining allowances is:

Where:


HI = heat input (in mmbtu/control period) as determined in Section 217.762(b) of this Part.

ER = The NO_x emission rate in lbs/mmbtu as determined in Section 217.762(a) of this Part.

A = allowances of NO_x/control period.

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

Section 217.764 NO_x Allocations for Budget EGUs

For each control period, the Agency will allocate the total number of NO_x allowances in the trading budget apportioned to budget EGUs under Section 217.760 of this Part. These allocations will be issued as provided in subsections (a) through (f) of this Section and Section 271.768 of this Part of new sources. Specifically:

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


1) 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.

2) 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.

3) The Agency will report these allocations to USEPA at the time it submits the SIP.

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


1) 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.

2) 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:

Where:


HI = heat input (in mmbtu/control period) as determined in Section 217.762(b) of this Part.

ER = the NO_x emission rate in lbs/mmbtu, as determined in Section 217.762(a)(2) of this Part.

A = allowances of NO_x/control period.


3) 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_x 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.

4) 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:


A) 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.

B) 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.


5) 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.

6) 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.

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


1) 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.

2) 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:

Where:


HI = heat input (in mmbtu/control period) as determined in Section 217.762(b) of this Part.

ER = the NO_x emission rate in lbs/mmbtu, as determined in Section 217.762(a)(2) of this Part.

A = allowances of NO_x/control period.


3) 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_x 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.

4) 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:


A) 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.

B) 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.


5) 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.

6) 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.

d) In 2009 (or the sixth year of the program):


1) 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.

2) 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:

Where:


HI = heat input (in mmbtu/control period) as determined in Section 217.762(b) of this Part.

ER = the NO_x emission rate in lbs/mmbtu, as determined in Section 217.762(a)(2) of this Part.

A = allowances of NO_x/control period.


3) 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_x 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.

4) 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:


A) 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.

B) 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.


5) 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.

6) As of April 30, 2009, if the number of allowances in the new source set-aside exceeds three percent (3%) of the total number of tons of NO_x emissions in the trading budget apportioned to budget EGUs as determined pursuant to Section 217.768(i) and (j) of this Part, the number of allowances above three percent (3%) will be allocated to budget EGUs receiving allowances pursuant to this subsection (d).

7) 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.

e) In 2010 (or the seventh year of the program):


1) 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.

2) 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:

Where:


HI = heat input (in mmbtu/control period) as determined in Section 217.762(b) of this Part.

ER = the NO_x emission rate in lbs/mmbtu, as determined in Section 217.762(a)(2) of this Part.

A = allowances of NO_x/control period.


3) 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_x 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.

4) 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:


A) 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.

B) 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.


5) 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.

6) As of April 30, 2010, if the number of allowances in the new source set-aside exceeds three percent (3%) of the total number of tons of NO_x emissions in the trading budget apportioned to budget EGUs as determined pursuant to Section 217.768(i) and (j) of this Part, the number of allowances above three percent (3%) will be allocated to budget EGUs receiving allowances pursuant to this subsection (e).

7) 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.

f) In 2011 (or the eighth year) of the program and annually thereafter:

1) The Agency will apportion the available NO_x allowances to each budget EGU based on its heat input determined in Section 217.762(b) of this Part, multiplied by:


A) For budget EGUs that commenced commercial operation prior to January 1, 1995, the NO_x emission rate determined in Section 217.762(a)(1) of this Part.

B) For budget EGUs that commenced commercial operation on or after January 1, 1995, the NO_x emission rate determined in Section 217.762(a)(2) of this Part.


2) 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.

3) As of April 30, 2011, if the number of allowances in the new source set-aside exceeds three percent (3%) of the total number of tons of NO_x emissions in the trading budget apportioned to budget EGUs as determined pursuant to Section 217.768(e) and (f) of this Part, the number of allowances above three percent (3%) will be allocated to budget EGUs receiving allowances pursuant to this subsection (f).

4) 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_x 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

a) “New” budget EGUs


1) 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.

2) “New” budget EGUs must have an allowance for every ton of NO_x emitted during the control period as provided in Section 217.756(d) of this Part.

3) 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.

b) The Agency shall apportion allowances from the new source set-aside as follows:


1) For 2004, 2005, and 2006, to budget EGUs that commenced commercial operation on or after January 1, 1995; and

2) 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.

c) The Agency will establish a new source set-aside for each control period. Each new source set-aside will be allocated allowances equal to:


1) Five percent (5%) of the EGU trading budget in 2004, 2005, and 2006, which is 1,535 allowances, subject to adjustment to reflect additions or deletions to the EGU trading budget;

2) Two percent (2%) of the EGU of the trading budget in 2007 and thereafter, which is 614 allowances, subject to adjustment to reflect additions or deletions to the EGU trading budget.

3) As of April 30 of the applicable year, beginning in 2009 and thereafter, if the number of allowances in the new source set-aside is greater than or equal to three percent (3%) of the total number of tons of NO_x emissions in the trading budget apportioned to budget EGUs, which is 921 allowances, subject to adjustment to reflect additions or deletions to the EGU trading budget, pursuant to subsections (i) and (j) of this Section, the number of allowances above three percent (3%) will be allocated to budget EGUs receiving allowances pursuant to Section 217.764 of this Part. These allowances shall be allocated on a pro-rata basis.

d) 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.

e) 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:


1) 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;

2) 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;

3) 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

4) For “new” budget EGUs that have commenced commercial operation but have not operated for ~~more than half of a full~~ at least 77 days of the control period prior to the allocation year, the budget EGU’s maximum design heat input for the control period as designated in the construction permit.

f) 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:


1) 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.

2) 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.

3) 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.


g) 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.

h) 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.

i) For “new” budget EGUs that have commenced commercial operation but have operated for ~~less than one-half~~ 76 or fewer days of the control period in 2003, USEPA will deduct allowances to account for the actual utilization of the EGU during the 2004 control period consistent with the provisions of 40 CFR 96.42(e). Any allowances allocated by the Agency for such “new” budget EGUs that are not used for compliance during the 2004 control period shall be returned to the Agency’s new source set-aside account.

j) 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.

k) Fees for new source set-aside allowances:


1) “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.

2) The price of allowances from the new source set-aside shall be:


A) The average price at which NO_x allowances are traded in the interstate NO_x Trading Program for the preceding control period; and

B) For 2004 only, the price shall be the average price at which NO_x allowances were traded in 2003 in the Ozone Transport Region.

3) 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.

l) 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:


1) 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.

2) 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_x 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_x 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:


a) Each budget EGU for which the account representative requests any ERCs under subsection (d) of this Section shall monitor NO_x emissions in accordance with 40 CFR 96, subpart H, as incorporated by reference in Section 217.104 of this Part, starting with the control period prior to the control period for which ERCs will first be requested and for each control period for which ERCs will be requested. For example, if ERCs are requested for reductions made in the 2001 control period, the budget EGU must have implemented the applicable monitoring for the 2000 control period. The unit’s monitoring system availability shall be not less than 8090 percent during the control period prior to the control period in which the NO_x emissions reduction is made and the unit must be in compliance with any applicable State or federal emissions or emissions-related requirements.

b) The NO_x emission rate and heat input under subsections (c) through (e) of this Section shall be determined in accordance with 40 CFR 96, subpart H.

c) Each budget EGU for which ERCs are requested under subsection (d) of this Section must have reduced its NO_x emission rate for each control period for which ERCs are requested, as follows:


1) For budget EGUs subject to the requirements of Title IV of the CAA and not included in a NO_x 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_x emission rate specified in the applicable Title IV permit or other applicable federally enforceable permit.

2) For budget EGUs subject to the requirements of Title IV of the CAA and included in a NO_x averaging plan pursuant to 40 CFR 72 and 76, at least 30% less than the annual emission rate required in the NO_x averaging plan in the applicable Title IV permit or other applicable federally enforceable permit.

3) For budget EGUs not subject to the requirements of Title IV of the CAA, at least 30% less than the actual NO_x emissions rate (lbs/mmbtu) for the 2000 control period.

d) 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_x emission rate reductions made by the EGU in control periods 2001, 2002, and 2003, in accordance with subsection (c) of this Section.


1) 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_x emission rate (meeting the requirements of subsection (c) of this Section for the applicable control period) and the EGU’s actual NO_x emission rate for the applicable control period, divided by 2000 lbs/ton, and rounded to the nearest ton.

2) 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.

3) The early reduction request must be submitted in a format specified by the Agency by:


A) November 1, 2001, for reductions made in the 2001 control period;

B) November 1, 2002, for reductions made in the 2002 control period; and

C) November 1, 2003, for reductions made in the 2003 control period.


e) In the event that the date for implementing the NO_x SIP Call, May ~~1, 2003~~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_x SIP Call (63 Fed. Reg. 57356).by November 1 of the year two years before the implementation date for the reductions made in the control period two years before the implementation date, and by November 1 of the year preceding the implementation date for the reductions made in the control period preceding the implementation date. Should this occur, the other dates in this Section shall be adjusted accordingly.

f) 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:


1) 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;

2) The Agency shall allocate at least 15,261 ERCs over ~~two~~three years, as follows:


A) If USEPA has approved this Subpart as a SIP revision, not more than ~~7,630~~ one-half of the total ERC allowances for reductions made in the control period in 2001;

B) ~~At least 7,631~~ Not more than one-half of the total ERC allowances~~, plus any ERC allowances not allocated pursuant to subsection (f)(2)(A) of this Section,~~ for reductions made in the control period in 2002; and

C) Any ERC allowances not allocated pursuant to subsections (f)(2)(A) or (B) of this Section, for reductions made in the control period in 2003.


3) 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;

4) If the number of ERC allowances requested for a reduction achieved in the control period in 2003 is greater than the number of ERC allowances designated for that control period in subsection (f)(2)(A) of this Section, the Agency will allocate to each budget EGU allowances for accepted requests on a pro-rata basis.~~; and~~

5) ~~For accepted ERC requests for reductions made in the control period in 2002, the Agency will allocate ERCs on a pro-rata basis.~~

g) 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:


1) By ~~May~~ March 1, 2002, for ERCs requested for and earned in the 2001 control period;

2) By ~~May~~ March 1, 2003, for ERCs requested for and earned in the 2002 control period; and

3) By March 1, 2004, for ERCs requested for and earned in the 2003 control period.


h) 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.

i) 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.

j) 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

a) 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:

1) Is not a budget EGU under Section 217.754 of this Part;


2) Vents all of its emissions to a stack or, for a unit that does not vent all of its emissions to a stack, obtains a permit with federally enforceable conditions specifying the applicable conditions for participation in the NO_x Trading Program;

3) 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;

4) Is not covered by a retired unit exemption under 40 CFR 96.5; ~~and~~


5) Is not covered by the low-emitter exemption under Section 217.754(c) of this Part; and

6) Is not located at a source listed in Appendix D of this Part.

b) 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.

c) Authorized account representative:


1) 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.

2) 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.

d) 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:

1) A budget permit application for the unit that:

A) Meets the requirements under Section 217.758 of this Part; and

B) 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.

2) A monitoring plan for the unit in accordance with 40 CFR 96, subpart H.

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

Section 217.776 Opt-In Process

The owner or operator of a unit meeting the qualifications of Section 217.774(a) of this Part may submit an application for a budget permit for a budget opt-in unit under Section 217.774(d) of this Part. The Agency will issue or deny a budget permit for such opt-in unit in accordance with Section 217.758 of this Part and the following:


a) 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_x 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.

b) 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_x emission rate and the heat input of the unit shall be monitored and reported in accordance with 40 CFR 96, subpart H, for one full control period during which the monitoring system availability is not less than 80 90 percent and during which the unit is in full compliance with any applicable State or federal emissions or emissions-related requirements.

c) 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_x emission rate shall be calculated as the unit's total NO_x 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_x Trading Program


a) Requesting withdrawal. To withdraw from the NO_x Trading Program, the account representative of a budget opt-in unit shall submit to the Agency a request to withdraw from the NO_x 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.

b) Conditions for withdrawal.

1) Before a budget opt-in unit may withdraw from the NO_x Trading Program and the budget permit may be withdrawn under this Section, the following conditions must be met:


A) 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.

B) 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_x 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.

2) 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.


c) A budget opt-in unit that withdraws from the NO_x Trading Program shall comply with all requirements under the NO_x 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.

d) Notification.


1) 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.

2) 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.


e) 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.

f) Ability to return to the NO_x Trading Program. Once an opt-in unit withdraws from the NO_x 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


a) 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.

b) 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.

c) USEPA action.

1) 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:


A) 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

B) 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.


2) 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.

3) 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.

4) 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.


d) 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.

e) 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

a) Allowance allocations:


1) 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.

2) 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.

b) 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:

1) The heat input (in mmbtu) used for calculating allowance allocations will be the lesser of:


A) The opt-in unit's baseline heat input determined pursuant to Section 217.778(c) of this Part; or

B) 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.

2) 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:


A) The unit's baseline NO_x emission rate (in lbs/mmbtu) determined pursuant to Section 217.776(c) of this Part; or

B) The lowest NO_x emissions limitation (calculated in lbs/mmbtu) under State or federal law that is applicable to the budget opt-in unit for ~~the control period in~~ the year ~~prior to the year~~ of the control period for which the allocations are being calculated during the control period, regardless of the averaging period to which the emissions limitation applies.

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

Section 217.Appendix D Non-Electrical Generating Units

COMPANY ID # / NAME

UNIT DESIGNATION

UNIT DESCRIPTION

1

2

3

A E STALEY MANUFACTURING CO
115015ABX

85070061299

COAL-FIRED BOILER 1

115015ABX

85070061299

COAL-FIRED BOILER 2

115015ABX

73020084129

BOILER #25

ARCHER DANIELS MIDLAND CO EAST PLANT
115015AAE

85060030081

COAL-FIRED BOILER 1

115015AAE

85060030081

COAL-FIRED BOILER 2

115015AAE

85060030081

COAL-FIRED BOILER 3

115015AAE

85060030082

COAL-FIRED BOILER 4

115015AAE

85060030082

COAL-FIRED BOILER 5

115015AAE

85060030082

COAL-FIRED BOILER 6

115015AAE

85060030083

GAS-FIRED BOILER 7

115015AAE

85060030083

GAS-FIRED BOILER 8

CPC INTERNATIONAL INC.
031012ABI

91020069160

COAL-FIRED BOILER 6

031012ABI

73020146041

BOILER SERIAL 15813

031012ABI

73020146042

BOILER SERIAL 15812

031012ABI

73020146043

GAS FIRED BOILER NO 4

031012ABI

73020147045

BOILER SERIAL 18345

031012ABI

73020147046

GAS FIRED BOILER NO 5

GREAT LAKES NAVAL STATION
097811AAC

78080071011

BOILER # 5

097811AAC

78080071011

BOILER # 6

INDIAN REFINING LIMITED PARTNERSHIP
101805AAC

72110297015

BOILER 18601

101805AAC

72110297016

BOILER 18602

101805AAC

72110297017

BOILER 18603

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 DOWN

197800AAA

86010009043

STATIONARY GAS TURBINE

PEKIN ENERGY COMPANY
179060ACR

73020087019

QUANTUM - USI DIVISION

063800AAC

72100016013

BOILER # 1

063800AAC

72100016013

BOILER # 2

063800AAC

72100016014

#3 GAS FIRED BOILER

063800AAC

72100016016

#5 GAS FIRED BOILER

063800AAC

72100016017

#6 BOILER

QUANTUM - USI DIVISION
041804AAB

72121207108

BOILER NO 1

041804AAB

72121207109

BOILER NO 2

041804AAB

72121207110

BOILER NO 3

041804AAB

72121207111

BOILER NO 4

041804AAB

72121207112

BOILER NO 5

SHELL OIL CO WOOD RIVER MFG COMPLEX
119090AAA

72110633080

BOILER NO 15

119090AAA

72110633081

BOILER NO 16

119090AAA

72110633082

BOILER NO 17

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
019010ADA

82090027006

BOILER #7 (265 MBTU)

UNO-VEN COMPANY
197090AAI

72110253037

BOILER 43-B-1

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

Section 217.Appendix F Allowances for Electrical Generating Units

Company Name/ ID #

Generating Unit Designation

EGU Designation

NO_x Budget Allowances

80% of NO_x Budget
Allowances

50% of NO_x
Budget Allowances

2004, 2005, 2006 Allowances

2007, 2008 Allowances

2009, 2010 Allowances

1

2

3

4

5

6

7

8

9

Company Totals
No NSSA

No NSSA

No NSSA

5% NSSA

2% NSSA

2% NSSA

Ameren Energy Generating Company

135803AAA

Coffeen 1

Coffeen 1

550

440

275

523

431

270

135803AAA

Coffeen 2

Coffeen 2

945

756

473

898

741

463

077806AAA

G. Tower 3

Boiler 7

55

44

28

52

43

27

077806AAA

G. Tower 3

Boiler 8

44

35

22

42

35

22

077806AAA

G. Tower 4

Boiler 9

199

159

100

189

156

98

033801AAA

Hutsonville 3

Boiler 5

161

129

81

153

126

79

033801AAA

Hutsonville 4

Boiler 6

129

103

65

123

101

63

135805AAA

Meredosia 1

Boiler 1

33

26

17

31

26

16

135805AAA

Meredosia 1

Boiler 2

23

18

12

22

18

11

135805AAA

Meredosia 2

Boiler 3

23

18

12

21

18

11

135805AAA

Meredosia 2

Boiler 4

28

22

14

27

22

14

135805AAA

Meredosia 3

Boiler 5

432

346

216

410

339

212

135805AAA

Meredosia 4

Boiler 6

28

22

14

27

22

13

079808AAA

Newton 1

Newton 1

1,101

881

551

1,046

863

539

079808AAA

Newton 2

Newton 2

1,074

859

537

1,020

842

526

Ameren Eng. Gen. Co. Totals
4,825

3,860

2,413

4,584

3,783

2,364

AES

057801AAA

D. Creek

D. Creek

914

731

457

868

717

448

143805AAG

Edwards 1

Edwards 1

251

201

126

239

197

123

143805AAG

Edwards 2

Edwards 2

368

294

184

350

288

180

143805AAG

Edwards 3

Edwards 3

655

524

328

622

513

321

AES Totals
2,188

1,750

1,094

2,079

1,715

1,072

CWLP

167120AAO

Dallman 1

Boiler 31

141

113

71

134

111

69

167120AAO

Dallman 2

Boiler 32

202

162

101

192

158

99

167120AAO

Dallman 3

Boiler 33

474

379

237

450

372

232

167120AGQ

G. Turbine #2

G. Turbine #2

91

73

46

86

71

45

167120AAO

Lakeside 7

Lakeside 7

47

38

24

45

37

23

167120AAO

Lakeside 8

Lakeside 8

42

34

21

40

33

21

CWLP Totals
997

798

499

947

782

489

Midwest Generation

063806AAF

Collins 1

Collins 1

302

242

151

287

237

148

063806AAF

Collins 2

Collins 2

305

244

153

290

239

150

063806AAF

Collins 3

Collins 3

469

375

235

446

368

230

063806AAF

Collins 4

Collins 4

290

232

145

275

227

142

063806AAF

Collins 5

Collins 5

458

366

229

435

359

224

031600AIN

Crawford 7

Crawford 7

365

292

183

347

286

179

031600AIN

Crawford 8

Crawford 8

463

370

232

440

363

227

031600AMI

Fisk 19

Fisk 19

523

418

262

497

410

256

031600AMI

Fisk Peaker

GT 31-1

9

7

5

9

7

4

031600AMI

Fisk Peaker

GT 31-2

9

7

5

9

7

4

031600AMI

Fisk Peaker

GT 32-1

9

7

5

9

7

4

031600AMI

Fisk Peaker

GT 32-2

9

7

5

9

7

4

031600AMI

Fisk Peaker

GT 33-1

9

7

5

8

7

5

031600AMI

Fisk Peaker

GT 33-2

9

7

5

8

7

5

031600AMI

Fisk Peaker

GT 34-1

9

7

5

8

7

5

031600AMI

Fisk Peaker

GT 34-2

9

7

5

8

7

5

197809AAO

Joliet 6

Boiler 5

119

95

60

113

93

58

197809AAO

Joliet 7

Boiler 71

455

364

228

432

357

223

197809AAO

Joliet 7

Boiler 72

709

567

355

673

556

347

197809AAO

Joliet 8

Boiler 81

748

598

374

711

587

367

197809AAO

Joliet 8

Boiler 82

497

398

249

472

390

244

179801AAA

Powerton 5

Boiler 52

739

591

370

702

579

362

179801AAA

Powerton 5

Boiler 51

739

591

370

702

579

362

179801AAA

Powerton 6

Boiler 61

739

591

370

702

579

362

179801AAA

Powerton 6

Boiler 62

739

591

370

702

579

362

097190AAC

Waukegan 6

Boiler 17

199

159

100

189

156

98

097190AAC

Waukegan 7

Waukegan 7

376

301

188

357

295

184

097190AAC

Waukegan 8

Waukegan 8

667

534

334

634

523

327

097190AAC

Peaker

GT 31-1

5

4

3

4

4

2

097190AAC

Peaker

GT 31-2

5

4

3

5

4

2

097190AAC

Peaker

GT 32-1

5

4

3

5

4

3

097190AAC

Peaker

GT 32-2

5

4

3

5

4

3

197810AAK

Will County 1

Will County 1

364

291

182

346

285

178

197810AAK

Will County 2

Will County 2

354

283

177

336

278

173

197810AAK

Will County 3

Will County 3

449

359

225

427

352

220

197810AAK

Will County 4

Will County 4

766

613

383

728

601

375

Midwest Generation Totals
11,926

9,541

5,963

11,330

9,350

5,844

Dom. Energy

021814AAB

Kincaid 1

Kincaid 1

792

634

396

752

621

388

021814AAB

Kincaid 2

Kincaid 2

873

698

437

829

684

428

Dom. Energy Totals
1,665

1,332

833

1,581

1,305

816

El. Energy Inc.

127855AAC

Joppa 1

Joppa 1

481

385

241

457

377

236

127855AAC

Joppa 2

Joppa 2

515

412

258

489

404

252

127855AAC

Joppa 3

Joppa 3

513

410

257

487

402

251

127855AAC

Joppa 4

Joppa 4

384

307

192

365

301

188

127855AAC

Joppa 5

Joppa 5

463

370

232

440

363

227

127855AAC

Joppa 6

Joppa 6

524

419

262

498

411

257

El. Energy Inc. Totals
2,880

2,304

1,440

2,736

2,258

1,411

DMG

157851AAA

Baldwin 1

Baldwin 1

1,114

891

557

1,058

873

546

157851AAA

Baldwin 2

Baldwin 2

931

745

466

884

730

456

157851AAA

Baldwin 3

Baldwin 3

1,318

1,054

659

1,252

1,034

646

125804AAB

Havana 1-5

Boiler 1

0

0

0

0

0

0

125804AAB

Havana 1-5

Boiler 2

0

0

0

0

0

0

125804AAB

Havana 1-5

Boiler 3

0

0

0

0

0

0

125804AAB

Havana 1-5

Boiler 4

0

0

0

0

0

0

125804AAB

Havana 1-5

Boiler 5

0

0

0

0

0

0

125804AAB

Havana 1-5

Boiler 6

0

0

0

0

0

0

125804AAB

Havana 1-5

Boiler 7

0

0

0

0

0

0

125804AAB

Havana 1-5

Boiler 8

0

0

0

0

0

0

125804AAB

Havana 6

Boiler 9

547

438

274

520

429

268

155010AAA

Hennepin 1

Hennepin 1

149

119

75

142

117

73

155010AAA

Hennepin 2

Hennepin 2

540

432

270

513

423

265

183814AAA

Vermilion 1

Vermilion 1

17

14

9

16

13

8

183814AAA

Vermilion 2

Vermilion 2

31

25

16

30

24

15

119020AAE

Wood River 1

Wood River 1

0

0

0

0

0

0

119020AAE

Wood River 2

Wood River 2

0

0

0

0

0

0

119020AAE

Wood River 3

Wood River 3

0

0

0

0

0

0

119020AAE

Wood River 4

Wood River 4

219

175

110

208

172

107

119020AAE

Wood River 5

Wood River 5

714

571

357

678

560

350

DMG Totals
5,580

4,464

2,790

5,301

4,375

2,734

SIPCO

199856AAC

Marion 1

Marion 1

14

11

7

13

11

7

199856AAC

Marion 2

Marion 2

10

8

5

10

8

5

199856AAC

Marion 3

Marion 3

30

24

15

29

23

15

199856AAC

Marion 4

Marion 4

511

409

256

485

401

250

SIPCO Totals
565

452

283

537

443

277

Union Electric

119105AAA

Turbine

Turbine

4

3

2

4

3

2

119105AAA

Venice 1

Venice 1

10

8

5

9

8

5

119105AAA

Venice 2

Venice 2

13

10

7

12

10

6

119105AAA

Venice 3

Venice 3

6

5

3

6

5

3

119105AAA

Venice 4

Venice 4

7

6

4

7

5

4

119105AAA

Venice 5

Venice 5

15

12

8

14

12

7

119105AAA

Venice 6

Venice 6

16

13

8

15

13

8

119105AAA

Venice 7

Venice 7

2

2

1

2

1

1

119105AAA

Venice 8

Venice 8

2

2

1

2

2

1

Union Electric Totals
75

60

38

71

59

37

TOTAL
30,701

24,561

15,351

29,166

24,070

15,044

(Source: Added at ____ Ill. Reg. __________, effective _____________)


IT IS SO ORDERED.

I, Dorothy M. Gunn, Clerk of the Illinois Pollution Control Board, hereby certify that the above opinion and order was adopted on the 16th day of November 2000 by a vote of 7-0.


Dorothy M. Gunn, Clerk
Illinois Pollution Control Board

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ed	These rules have been grouped for convenience of the public; the scope of each is determined by its language and history.

a)	The ~~the~~ phenol disulfonic acid method, ~~36 Fed. Reg. 15, 718~~ 40 CFR 60, Appendix A, Method 7. (1999); ~~and~~

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

c)	Determination of Nitrogen Oxides Emissions from Stationary Sources (Instrumental Analyzer Procedure), 40 CFR 60, Appendix A, Method 7E (1999).

btu	British thermal unit (60^oF)
EGU	Electrical Generating Unit
kg	kilogram
kg/MW-hr	kilograms per megawatt-hour, usually used as an hourly emission rate
lb	pound
NO_x	Nitrogen Oxides
lbs/mmbtu	pounds per million btu, usually used as an hourly emission rate
Mg	megagram or metric tonne
mmbtu	million British thermal units
mmbtu/hr	million British thermal units per hour
MWe	megawatt of electricity
MW	megawatt; one million watts
MW-hr	megawatt-hour
peoc	potential electrical output capacity
ppm	parts per million
ppmv	parts per million by volume

English	Metric
2.205 lb	1 kg
1 T	0.907 Mg
1 lb/T	0.500 kg/Mg
Mmbtu/hr	0.293 MW
1 lb/mmbtu	1.548 kg/MW-hr

a)
The following fossil fuel-fired stationary boilers, combustion turbines or combined cycle systems are electrical generating units (EGUs) and are subject to this Subpart:

1)		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.

2)		Any unit with a maximum design heat input that is greater than 250 mmbtu/hr that commences operation on or after January 1, 1999, serving at any time a generator that has a nameplate capacity of 25 MWe or less and has the potential to use more than 50% of the potential electrical output capacity of the unit. Fifty percent (50%) of a unit’s potential electrical output capacity shall be determined by multiplying the unit’s maximum design heat input by 0.0488 MWe/mmbtu. If the size of the generator is greater than this calculated number, the unit is an EGU subject to the provisions of this Subpart.

b)
Those units that meet the above criteria and are subject to the NO_x Trading Program emissions limitations contained in this Subpart are budget EGUs.

c)
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).

1)		For each control period under this subsection (c), the federally enforceable permit conditions must:

A)		Restrict the EGU to burning only natural gas, fuel oil, or natural gas and fuel oil;

B)		Limit the EGU’s potential NO_x mass emissions for the control period to 25 tons or less;

C)		Restrict the EGU’s operating hours during the control period to the number calculated by dividing 25 tons of potential NO_x mass emissions by the EGU’s maximum potential hourly NO_x mass emissions;

D)		Require that the EGU’s potential NO_x 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:

i)		Select the applicable default NO_x emission rate from one of the following:

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

ii)		Multiply the default NO_x 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;

E)		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

F)		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.

2)		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:

A)		The permit with federally enforceable conditions that includes the restrictions in subsection (c)(1) of this Section is issued by the Agency;

C)	Such permit includes any such restriction that is no longer applicable; or

3)		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.

4)		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_x emissions the EGU is permitted to emit during the control period as set forth in the EGU’s federally enforceable state operating permit.

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

a)
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.

1)		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_x Trading Program (“budget permit”) that complies with the requirements of Section 217.758 of this Part.

2)		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.

1)		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.

2)		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.

2)		Each ton of NO_x emitted in excess of the number of NO_x 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.

3)		A budget EGU shall be subject to the monitoring and NO_x requirements of subsections (c)(1) and (d)(1) of this Section starting on the later of ~~May 1, 2003~~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_X 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_X TRADING PROGRAMS AND OTHER REQUIRED REDUCTIONS OF NO_X EMISSIONS PURSUANT TO THE NO_X 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.

4)		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.

5)		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.

6)		An allowance allocated by the Agency or USEPA under the NO_x Trading Program is a limited authorization to emit one ton of NO_x in accordance with the NO_x Trading Program. No provision of the NO_x 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.

7)		An allowance allocated by the Agency or USEPA under the NO_x Trading Program does not constitute a property right.

A)	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.

B)	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.

C)	Copies of all reports, compliance certifications, and other submissions and all records made or required under the NO_x Trading Program or documents necessary to demonstrate compliance with the requirements of the NO_x Trading Program or with the requirements of this Subpart.

D)	Copies of all documents used to complete a budget permit application and any other submission under the NO_x Trading Program.

2)	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_x Trading Program, including those under 40 ~~part~~ CFR 96, subparts D and H, and Section 217.774 of this Part.

1)	No revision of a permit for a budget EGU shall excuse any violation of the requirements of the NO_x Trading Program that occurs prior to the date that the revision to such budget permit takes effect.

2)	Each budget source and each budget EGU shall meet the requirements of the NO_x Trading Program.

3)	Any provision of the NO_x 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.

5)	~~Excess emissions requirements.~~ The account representative of a budget EGU that has excess emissions in any control period shall:

A)	S surrender the allowances as required for deduction under 40 CFR 96.54(d)(1)~~; and~~.

6)	~~B) Pay~~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.

1)	Each source with a budget EGU is required to submit a complete permit application addressing all applicable NO_x 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.

2)	Each budget permit (including a draft or proposed budget permit, if applicable) shall contain federally enforceable conditions addressing all applicable NO_x Trading Program requirements and shall be a complete and segregable portion of the source’s entire permit under subsection (a)(1) of this Section.

3)	No budget permit shall be issued, and no NO_x 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.

4)	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.

5)	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.

6)	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.

1)	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.

2)	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: