ILLINOIS POLLUTION CONTROL BOARD

ABBREVIATED PROCEDURAL BACKGROUND
SUMMARY OF THE AGENCY’S AMENDED PROPOSAL
1. Part 201: Permits and General Provisions

ILLINOIS POLLUTION CONTROL BOARD

September 16, 2008

IN THE MATTER OF:

SECTION 27 PROPOSED RULES FOR

NITROGEN OXIDE (NO

FROM STATIONARY RECIPROCATING

INTERNAL COMBUSTION ENGINES AND

TURBINES: AMENDMENTS TO 35 ILL.

ADM. CODE SECTION 201.146 AND

PARTS 211 AND 217

(Rulemaking - Air)

. First Notice.

OPINION AND ORDER OF THE BOARD (by A.S. Moore):

Today the Board proposes amendments to its regulations governing emission of nitrogen

) (35 Ill. Adm. Code 201, 211, 217) for first-notice publication in the

. On December 20, 2007, the Illinois Environmental Protection Agency (Agency or

IEPA) filed a motion to proceed in this docket with an amended rulemaking proposal, which the

Board granted on January 10, 2008. After conducting two public hearings on the amended

proposal and considering the entire record, the Board adopts for first notice the amendments

described below in this opinion and order.

The first-notice amendments are intended primarily to control NO

engines and turbines located at 100 ton per year sources located in the Greater Chicago and

Metro East/St. Louis nonattainment areas with a capacity of 500 brake horsepower (bhp) or 3.5

megawatts (MW). In its motion to proceed with an amended proposal, the Agency stated that its

proposed regulations would help Illinois to meet Clean Air Act (CAA) requirements for NO

reasonably available control technology (RACT) under the under the eight-hour National

Ambient Air Quality Standard (NAAQS) for ozone and would also improve air quality by

reducing precursors of fine particulate matter (PM

). Publication of these proposed

amendments in the

Illinois Register

will begin a 45-day public comment period.

In this opinion, the Board first provides an abbreviated procedural background of this

rulemaking. Next, the Board analyzes the Agency’s proposal and the issues raised both at

hearing and in six public comments. The Board then analyzes technical and economic

considerations before making its findings and reaching its conclusions. The order following this

opinion then sets forth the proposed amendments for first notice publication.

ABBREVIATED PROCEDURAL BACKGROUND

On April 6, 2007, the Agency filed a rulemaking proposal intended to reduce emissions

of nitrogen oxides (NO

) from stationary reciprocating engines and turbines. The Board

docketed the proposal as R07-18. In an order dated May 17, 2007, the Board concluded that the

Agency’s entire proposal was not “required to be adopted” by the CAA under Section 28.5 of the

Environmental Protection Act (Act). 415 ILCS 5/28.5 (2006). Accordingly, the Board

bifurcated the proposal and continued to consider in docket R07-18 under Section 28.5 “fast-

track” procedures only the portion of the proposal applicable to the 28 internal combustion (IC)

engines affected by the NO

State Implementation Plan (SIP) Call Phase II. In a new docket

R07-19, the Board provided first-notice publication of the remainder of the Agency’s proposal

under the general rulemaking provisions of Sections 27 and 28 of the Act (415 ILCS 5/27, 28

(2006)). Fast-Track Rules Under Nitrogen Oxide (NO

) SIP Call Phase II: Amendments to 35

Ill. Adm. Code Section 201.146 and Parts 211 and 217, R07-18, slip op. at 2, 34-35 (May 17,

2007). The Board’s opinion and order bifurcating the Agency’s original proposal did not

comment on the merits of docket R07-19.

The Board adopted final rules in R07-18 on

September 20, 2007.

Fast-Track Rules Under Nitrogen Oxide (NO

) SIP Call Phase II:

Amendments to 35 Ill. Adm. Code Section 201.146 and Parts 211 and 217, R07-18 (Sept. 20,

31 Ill. Reg. 14254-71 (Oct. 12, 2007).

On June 15, 2007, the hearing officer issued an order in R07-19 scheduling two hearings

and setting deadlines for prefiled testimony. On August 23, 2007, the Agency filed a motion to

cancel the scheduled hearings and prefiling deadlines. In an order dated August 27, 2007, the

hearing officer granted the motion. At the direction of the hearing officer, the Agency

subsequently filed two status reports, a first on October 31, 2007, and a second on November 19,

2007, which indicated that the Agency would file an amended proposal with the Board before the

end of December 2007.

On December 20, 2007, the Agency filed its “Motion to Proceed with Amended Proposal

and Withdraw Testimony” (Mot. Amend). The motion included as Attachment B an amended

Technical Support Document (TSD). On January 3, 2008, the Illinois Environmental Regulatory

Group (IERG) filed its response. In an order dated January 10, 2008, the Board granted the

Agency’s motion. In a letter dated January 23, 2008, the Board requested that the Department of

Commerce and Economic Opportunity conduct an economic impact study of the amended

415 ILCS 5/27(b) (2006). The Board has not received a response to this request.

On March 26, 2008, the Board received prefiled testimony from four witnesses: Mr.

Robert Kaleel (Kaleel Test.) and Mr. Yoginder Mahajan (Mahajan Test.) on behalf of the

Agency; Mr. Kevin Wagner on behalf of the Illinois Municipal Electric Agency (IMEA)

(Wagner Test.); and Ms. Deirdre Hirner (Hirner Test.) on behalf of IERG. The first hearing in

this proceeding (Tr.1) took place on April 9, 2008, in Edwardsville, Madison County. At the

first hearing, the hearing officer admitted into the record one exhibit, a finding by the United

States Environmental Protection Agency (USEPA) that Illinois had failed to submit SIPs

required under the eight-hour NAAQS for ozone (Exh. 1).

73 Fed. Reg. 15416-21 (Mar. 24,

In an order dated April 17, 2008, the Board directed its Clerk to withdraw the proposed

amendments that the Board had originally sent to first-notice publication in this docket.

Section 27 Proposed Rules for Nitrogen Oxide (NO

) Emissions from Stationary Reciprocating

Internal Combustion Engines and Turbines: Amendments to 35 Ill. Adm. Code Parts 211 and

217, R07-19, slip op. at 1-2 (Apr. 17, 2008). The Secretary of State subsequently published

notice of withdrawal of the proposed amendments. 32 Ill. Reg. 7230-31 (May 2, 2008).

On April 23, 2008, the Board received prefiled testimony from Mr. James McCarthy

(McCarthy Test.) of Innovative Environmental Solutions, Inc. on behalf of two natural gas

transmission companies, ANR Pipeline Company and Natural Gas Pipeline Company of

America (collectively, the Pipeline Group). The second hearing in this proceeding (Tr.2) took

place on May 7, 2008 in Chicago. At the second hearing, the hearing officer admitted into the

record one exhibit, a document offered by the Agency and entitled “Clarifications and

Sheet” (Exh. 2).

In an order dated May 12, 2008, the hearing officer set a deadline of June 9, 2008 for

filing post-hearing comments and a deadline of June 23, 2008 for filing a response to post-

hearing comments. On June 9, 2008, the Board received post-hearing comments from the

Agency (PC 1), IMEA (PC 2), and IERG (PC 3). On June 23, 2008, the Board received a

response to post-hearing comments from the Agency (PC 4). On July 1, 2008, the Board

received a comment from Mr. Don C. DiCristoforo of Blue Sky Environmental LLC (Blue Sky)

(PC 5). On July 16, 2008, the Board received from the Agency a motion for leave to file

a response to the comment filed on behalf of Blue Sky (Mot. Leave), accompanied by

the Agency’s response to that comment (PC 6).

Filing Public Comments

First-notice publication of these proposed rule changes in the

Illinois Register

period of at least 45 days during which anyone may file a public comment with the Board,

regardless of whether the person has already filed a public comment in this proceeding. The

Board encourages persons to file public comments on these proposed amendments. The docket

number for this rulemaking, R07-19, should be indicated on the public comment.

Public comments must be filed with the Clerk of the Board at the following address:

Pollution Control Board

John T. Therriault, Assistant Clerk

James R. Thompson Center

100 W. Randolph Street, Suite 11-500

Chicago, IL 60601

As an alternative, public comments may be filed with the Clerk electronically through the

Clerk’s Office On-Line (COOL) at www.ipcb.state.il.us

. Any questions about electronic filing

through COOL should be directed to the Clerk’s Office at (312) 814-3629. Please note that all

filings with the Clerk of the Board must be served on the hearing officer and on those persons on

the Service List for this rulemaking. Before filing any document with the Clerk, please check

with the hearing officer or the Clerk’s Office to verify the current version of the Service List.

PRELIMINARY ISSUE

On July 16, 2008, the Agency filed a motion for leave to file

response to the comment filed on behalf of Blue Sky. Mot. Leave at 1. The Agency’s response

accompanied its motion.

. at 1-2. In the motion, the Agency states that Blue Sky

submitted a post-hearing comment to the Board on July 1, 2008, one week beyond the June 23,

2008, deadline for filing a response to post-hearing comments.

. The Agency further states

that, because the comment was neither filed nor served until after that deadline, the Agency

could not file a response before the applicable deadline.

. Accordingly, the Agency sought

leave to file a response to Blue Sky’s comment

The Board’s procedural rules provide that, “[w]ithin 14 days after service of a motion, a

party may file a response to the motion. If no response is filed, the party will be deemed to have

waived objection to the granting of the motion, but the waiver of objection does not bind the

Board . . . in its disposition of the motion.” 35 Ill. Adm. Code 101.500(d);

35 Ill. Adm. Code

102.402. The Board has received no response to the Agency’s motion for leave to file

Accordingly, the Board grants the Agency’s motion, accepts the Agency’s response to the post-

hearing comment by Blue Sky, and addresses that response in the opinion below.

BACKGROUND OF FEDERAL REQUIREMENTS

USEPA revised the NAAQS for PM

and ozone in 1997. TSD at 11 (§2.1), citing 62

Fed. Reg. 38652 (July 18, 1997) (PM

standards), 62 Fed. Reg. 38855 (July 17, 1997) (ozone

Kaleel Test. at 2. Upon setting the NAAQS for PM

, USEPA designated two

areas in Illinois, Chicago and Metro East/St. Louis, as nonattainment areas.

(Figure 2-1). “These designations became effective on April 5, 2005.”

. at 11, citing 70 Fed.

Reg. 943 (Jan. 5, 2005). USEPA has since reviewed the NAAQS for PM

and strengthened the

24-hour standard. Kaleel Test. at 2, citing 71 Fed. Reg. 61144 (Oct. 17, 2006).

“The revised NAAQS for ozone replaced the previous 1-hour averaging time with an 8-

hour averaging time, and reduced the applicable ambient concentration threshold from 0.12 parts

per million (ppm) to 0.08 ppm.” TSD at 11, Kaleel Test. at 2. USEPA has designated two areas

in Illinois, greater Chicago and Metro East/St. Louis, as moderate nonattainment areas for

. at 12 (Figure 2-2), Kaleel Test. at 2. “These designations become

effective on June 15, 2004.” TSD at 11, citing 69 Fed. Reg. 23858 (Apr. 3, 2004).

NAAQS, the following jurisdictions comprise the greater Chicago nonattainment

area: Cook, DuPage, Kane, Lake, McHenry, and Will Counties, Aux Sable and Goose Lake

Townships in Grundy County, and Oswego Township in Kendall County. TSD at 11, Mot.

Amend at 2 n.1. The following jurisdictions comprise the Metro-East/St. Louis nonattainment

area: Madison, Monroe, and St. Clair Counties and Baldwin Township of Randolph County.

TSD at 11, Mot. Amend at 2, n.1.

For the eight-hour ozone NAAQS, the following jurisdictions comprise the greater Chicago

nonattainment area: Cook, DuPage, Kane, Lake, McHenry, and Will Counties, Aux Sable and

Goose Lake Townships in Grundy County, and Oswego Township in Kendall County. TSD at

11, Mot. Amend at 2 n.1. The following counties comprise the Metro-East/St. Louis

nonattainment area: Jersey, Madison, Monroe, and St. Clair.

“Under Section 110 of the CAA and related provisions, states are required to submit for

USEPA’s approval, SIPs that provide for the attainment and maintenance of standards

established by USEPA through control programs directed to sources of the pollutant involved.”

Kaleel Test. at 3, citing 42 U.S.C. §7410. “USEPA has determined that, in addition to direct

particulate matter, that NO

, sulfur dioxide (SO

), VOCs [volatile organic compounds], and

ammonia are precursors to the formation of PM

.” Kaleel Test. at 2-3. Accordingly, states are

required to address issue including NO

emissions in their attainment plans under the 1997 PM

. at 3. “This rulemaking address NO

as a precursor to ozone and PM

The CAA includes provisions for the state to address emissions sources on an area-wide

basis through requirements including reasonably available control measures (RACM) and

reasonably available control technology (RACT). Kaleel Test. at 3, citing 42 U.S.C. §§ 7502,

7511a. In nonattainment areas,

the CAA requires the State to demonstrate that it has adopted ‘all reasonably

available control measures as expeditiously as possible (including such reductions

in emissions from existing sources in the area as may be obtained through the

adoption, at a minimum, of reasonably available control technology) and shall

provide for attainment of the national primary ambient air quality standards.’

Kaleel Test. at 3, citing 42 U.S.C. § 7502(c)(1).

Under Sections 172 and 182 of the CAA, “RACT is required for all existing major sources of the

applicable criteria pollutant and its precursors” in the nonattainment areas. TSD at 13. USEPA

has recently defined RACT as “the lowest emission limitation that a particular source is capable

of meeting by the application of control technology that is reasonably available considering

technological feasibility and economic reasonableness.” TSD at 13, citing 70 Fed. Reg. 71612

(Nov. 29, 2005). In moderate nonattainment areas such as Illinois’, the major source threshold is

100 tons per year (tpy). TSD at 13.

USEPA recently issued “Finding of Failure to Submit State Implementation Plans (SIP)

Required for the 1997 8-Hour Ozone NAAQS.” PC 1 at 1, citing 73 Fed. Reg. 15416 (Mar. 24,

Exh. 1. This action issued a SIP call to all states with ozone nonattainment areas that

had failed to submit complete RACT SIPs and began the running of sanctions clock. Exh. 1, Tr.

1 at 7-8. USEPA’s SIP Call included both the greater Chicago and Metro East/St/. Louis areas.

PC 1 at 3; 73 Fed. Reg. 15417-18.

SUMMARY OF THE AGENCY’S AMENDED PROPOSAL

Part 201: Permits and General Provisions

Exemptions from State Permit Requirements (Section 201.146)

Section 201.146 of the Board’s air permit regulations exempts specified equipment and

activities from the requirement of obtaining state construction or operating permits. 35 Ill. Adm.

Code 201.146. Subsection (i) specifically addresses stationary internal combustion engines and

stationary gas turbines. 35 Ill. Adm. Code 201.146(i).

The Agency originally proposed to amend this subsection in docket R07-18. After the

Board order bifurcating the original proposal, however, the Agency agreed that this particular

amendment should instead be addressed in this docket. Fast-Track Rules Under Nitrogen Oxide

) SIP Call Phase II: Amendments to 35 Ill. Adm. Code Section 201.146 and Parts 211 and

217, R07-18, slip op. at 5-6 (Aug. 9, 2007). The Board found that the issue of this proposed

permit exemption “must be addressed in docket R07-19” and accordingly did not include the

proposed amendment to Section 201.146(i) in the Second Notice opinion and order in R07-18.

In its motion to proceed with an amended proposal, the Agency addressed Section

201.146 by directing the Board to “[u]se the language as it appeared in the first notice as set forth

in the Ill. Reg. dated May 4, 2007.” Mot. at 19;

Emissions from Stationary

Reciprocating Internal Combustion Engines and Turbines: Amendments to 35 Ill. Adm. Code

Section 201.146 and Parts 211 and 217, R 07-18, slip op at 7-8 (Apr. 19, 2007) (first-notice

opinion and order); 31 Ill. Reg. 6559-77 (May 4, 2007);

Tr.1 at 32-33. However, in its

subsequent “Clarifications and

Sheet” submitted at the second hearing on May 7, 2008,

the Agency proposes an amendment to Section 201.146 that differs from the amendment it had

originally proposed in R07-18.

In its “Clarifications and

Sheet,” the Agency proposes to amend Section

201.146(i) to provide that the criteria of the permit exemption apply both to specified engines

and stationary turbines. Exh. 2 at 3;

35 Ill. Adm. Code 201.146(i). Finally, the Agency also

proposes to provide that “[a]ny internal combustion engine with a rating at equal to or greater

than 500 bhp output that is subject to the control requirements of 35 Ill. Adm. Code Part

217.388(a) or (b)” must obtain a permit. Exh. 2 at 3;

35 Ill. Adm. Code 217.388.

Part 211: Definitions and General Provisions

Emergency or Standby Unit (Section 211.1920)

Part 211 of the Board’s air regulations provides definitions and general provisions with

regard to emission standards and limitations for stationary sources. 35 Ill. Adm. Code 211.

Specifically, Section 211.1920 defines, for a stationary gas turbine or a stationary reciprocating

IC engine, an “emergency or standby unit.” 35 Ill. Adm. Code 211.1920. The Agency proposes

to add to this definition a new subsection (e) providing that, “[n]otwithstanding any other

subsection in this Section, emergency or standby units may operate an additional 50 hours per

year in non-emergency situations.” Mot. at 3, 18. The Agency states that “[t]his change is

At the first hearing in this proceeding, counsel for the Agency suggested that the Agency

wished to amend the caption to reflect the proposed amendment to Section 201.146. Tr.1 at 11.

Although the Agency did not formally offer a motion to that effect, the Board today on its own

motion amends the caption as reflected above.

consistent with a similar definition that applies to maximum achievable control technology

units.” Mot. at 3.

After the deadlines to file post-hearing comments and any responses to post-hearing

comments had passed, the Board on July 1, 2008 received a comment from Blue Sky (PC 5).

Blue Sky recommends “that the definition of emergency or standby unit in Section 211.1920 be

amended to include the operation during PJM’s Emergency Load Response Program

(“ELRP”).”

PC 5 at 1. Blue Sky indicates that PJM activates the ELRP and the use of

emergency units according to specific procedures in the event of a declared emergency. PC 5 at

1. Blue Sky argues that

[n]umerous states now allow emergency engines to participate during such time

(as opposed to waiting for a blackout), principally because studies prove that it is

better to prevent a blackout by using a subset of emergency generators for a short

period of time as opposed to losing the grid, which would mean all emergency

generators in the state operating for many hours or possibly days. PC 5 at 1.

Blue Sky states that that the ELRP is distinct from other PJM programs that are implemented for

economic reasons and that PJM has activated the program only five times for a total of 20 hours

in the last five years.

Blue Sky suggests that the current definition of “emergency or standby unit” allows

operation of those units only after a voltage reduction, brownout, or blackout has occurred. PC 5

35 Ill. Adm. Code 211.1920. Because it characterizes the ELRP as a “panic button” to

be pushed just before those occurrences, Blue Sky recommends adding the following language to

the definition:

[a]n engine that operates during an emergency condition according to the

procedures in the PJM Emergency Operations Manual for a PJM Declared

Emergency. A PJM Declared Emergency means a condition that exists where the

PJM Interconnections, LLC, or its successor, notifies electric distributors that an

emergency exists or may occur and it is necessary to implement the procedures in

the PJM Manual 13 Emergency Operations, as revised. PC 5 at 2.

On July 16, 2008, the Agency filed a motion for leave to file

a response to Blue

Sky’s comment and its response (PC 6). Above, the Board granted the Agency’s motion and

accepted its response. The Agency suggests that Blue Sky represents Klein Tool, which

“enrolled in ELRP to provide emergency electrical service for short periods of time to prevent

Although Blue Sky’s comment provides no description or background of PJM, the Board finds

the prefiled testimony of Mr. Wagner of IMEA to be instructive on this issue. Mr. Wagner states

that the high-voltage electric transmission grid is administered by regional transmission

organizations (RTOs), one of which is PJM. Wagner Test. at 4. He further states that these

RTOs operate wholesale power markets and oversee use of the grid and assure its availability on

a non-discriminatory basis.

. at 4-5. Mr. Wagner indicates that “PJM’s footprint is primarily

north of Interstate 80.”

black outs.” PC 6 at 1. The Agency states that Blue Sky raised the possibility that Klein Tool

generating units operating at the request of PJM might not meet the Board’s definition of an

“emergency or standby unit” or comply with Klein Tool’s current permit. PC 6 at 1. The

Agency has indicated to Klein Tool that, under the described circumstances, its units fall within

that definition.

at 1-2. The Agency states that it has also indicated to Klein Tool that, based

on the same circumstances, there is no need to modify its permit.

. The Agency concludes that

“no amendments to the current or proposed definition of emergency/standby unit are necessary at

. at 2. In addition, the Agency argues that the amendment proposed by Blue Sky

“falls beyond the scope of the current rulemaking[,] which was proposed to address NO

Having considered Blue Sky’s comment and the Agency’s response to it, the Board

declines to adopt the language proposed by Blue Sky and adopts for first-notice publication the

language proposed by the Agency to amend the definition of “emergency or standby unit” at

Section 211.1920. The Board reflects that language in its order below.

Part 217: Nitrogen Oxides Emissions

On September 20, 2007, the Board adopted a new Subpart Q to Part 217 of the Board’s

air regulations. Fast-Track Rules Under Nitrogen Oxide (NO

) SIP Call Phase II: Amendments

to 35 Ill. Adm. Code Section 201.146 and Parts 211 and 217, R07-18 (Sept. 20, 2007);

Reg. 14254-71 (Oct. 12, 2007);

35 Ill. Adm. Code 217.386-396. Section 217.386 of the

regulations now provides in its entirety that “[a] stationary reciprocating internal

combustion engine listed in Appendix G of this Part is subject to the requirements of this Subpart

Q.” 35 Ill. Adm. Code 217.386. Appendix G lists 28 existing reciprocating internal combustion

engines affected by Phase II of the NO

217 Ill. Adm. Code Appendix G.

The Agency states that its rulemaking proposal in this docket would amend the

requirements of Subpart Q “but would not change the substantive elements as they apply to NO

SIP Call engines.” Mot. Amend at 2. In his prefiled testimony on behalf of the Agency, Mr.

Kaleel stated that the approach to NO

control in this proposal is consistent with the approach

adopted in R07-18 for large engines subject to Phase II of the NO

SIP Call. Kaleel Test. at 4;

citing Fast-Track Rules Under Nitrogen Oxide (NO

SIP Call Phase II: Amendments to 35 Ill.

Adm. Code Section 201.146 and Parts 211 and 217, R07-18 (Sept. 20, 2007);

14254-71 (Oct. 12, 2007);

35 Ill. Adm. Code 217.386–396. Specifically, Mr. Kaleel

stated that the Agency has proposed that “turbines and engines not subject to Phase II of the NO

SIP Call be subject to NO

emissions limits at the same level as that required by R07-18 which

met the State’s obligations under Phase II of the NO

SIP Call.” Kaleel Test. at 4;

Applicability (Section 217.386)

Section 217.386(a).

The Agency’s proposal would apply Subpart Q to specified units in

the greater Chicago and Metro East/St. Louis nonattainment areas. Mot. Amend at 2-3;

Amend, Att. A at 1 (proposed new Section 217.386(a)(2));

Kaleel Test. at 4, TSD at 13

(RACT). In her testimony on behalf of IERG, Ms. Hirner supported the geographical

applicability of the proposed rule to the nonattainment areas. Hirner Test. at 3. She stated that

“IERG has long advocated this approach and it is supported by NO

emissions modeling.”

citing Mot. Amend. In his testimony on behalf of the Pipeline Group, Mr. McCarthy also noted

that the Agency limited the geographical applicability of the proposed regulation to the

nonattainment areas. McCarthy Test. at 5. He stated that “[t]his applicability criterion was

adamantly supported by the Pipeline Group throughout rule development, and substantiated by

regional air quality modeling completed in the fall of 2007.”

In addition to limiting its geographical applicability to the nonattainment areas, the

Agency also proposed to limit the proposed regulation to “[s]tationary reciprocating internal

combustion engines and turbines located at a source that emits or has the potential to emit NO

an amount equal to or greater than 100 tons per year.” Mot. Amend, Att. A at 1 (proposed new

Section 217.386(a)(2));

Mot. Amend at 2-3, TSD at 13 (major source threshold for RACT).

In her testimony on behalf of IERG, Ms. Hirner stated that IERG had misgivings about the

applicability language originally proposed by the Agency. Hirner Test. at 3;

Because that original language was not consistent with existing permit exemptions, IERG feared

that it would impose new requirements on “an unknown universe of engines and turbines.”

Hirner Test. at 3, PC 3 at 4. Ms. Hirner testified that, because the Agency’s amended proposal

applies only to major sources of NO

, it “provides more certainty to the reach of this

rulemaking.” Hirner Test. at 3;

PC 3 at 4. In its post-hearing comments, IERG

characterized this applicability provision as one of the “vitally important” elements of the

Agency’s amended proposal. PC 3 at 8.

Responding to questions at the first hearing, Mr. Kaleel clarified that the threshold of 100

tpy is not calculated solely on the basis of NO

emission from engines and turbines.

19. Specifically, he stated that Section 217.386(a)(2) “could refer to any emission units that

at a source.”

. Mr. Kaleel also indicated that the Agency’s proposed rule would not

apply to engines or turbines located in one of the nonattainment areas at a source that does not

emit or have the potential to emit 100 tpy of NO

. Tr.1 at 27-28. Mr. Kaleel further indicated

that a single engine or turbine located in one of the nonattainment areas that emits or has a

potential to emit 100 tpy of NO

would be subject to the proposed regulations. Tr.1 at 28.

However, Mr. Kaleel acknowledged that, if actual emissions from that engine or turbine are less

than 100 tpy, the operator could seek a federally enforceable emissions limit or restriction on

operation that would reduce the potential to emit below 100 tpy.

. Mr. Kaleel stated that, if

the operator accepted such an enforceable limit, “they could avoid the requirements of the rule.”

In addition to applying to major sources of NO

emission in the nonattainment areas, the

Agency’s proposed regulations apply to stationary internal combustion engines and turbines

where “[t]he engine at nameplate capacity is rated at equal to or greater than 500 bhp output; or

[t]he turbine is rated at equal to or greater than 3.5 MW . . .” Mot. Amend, Att. B at 1; Mahajan

Test. at 2; Kaleel Test. at 5.

In his testimony on behalf of the Pipeline Group, Mr. McCarthy expressed a firm belief

that larger “engines and turbines provide the most cost effective and environmentally beneficial

avenue for emission reductions” and questioned both the basis and legitimacy of the 500 bhp

threshold for engines and the 3.5 MW threshold for turbines. McCarthy Test. at 6. Responding

to a question at the second hearing, Mr. Kaleel stated that the Agency developed these thresholds

based on the belief that units of that size have the potential to emit 100 tpy of NO

Mr. Kaleel acknowledged that engines of this size would not necessarily operate continuously

throughout the year and may not actually emit 100 tons of NO

. He noted that the proposed

rule includes mechanisms through which “engines of this size could avoid having to comply with

. at 15-16. Specifically, “[s]ources can opt for a federally enforceable emissions

limit or a low usage limit in terms of the number of hours the unit will be operated.” PC 1 at 5.

Mr. McCarthy testified that the limited geographical applicability of the proposed rule and the

option of low usage operation “partially ameliorate our concerns and thus the Pipeline Group

does not strenuously object here. . . .” McCarthy Test. at 6.

Section 217.386(b).

The Agency’s proposal also provides an exemption for mobile or

portable units: “[n]otwithstanding subsection (a) of this Section, an affected unit is not subject to

the requirements of this Subpart Q if the engine or turbine is or has been . . . [a]n engine with

nameplate capacity rated at less than 1,500 bhp (1,118kW) output, mounted on a chassis or skids,

designed to be movable, and moved to a different source at least once every 12 months.” Mot.

Amend, Att. A at 1 (proposed Section 217.386(b)(5)). In responding to questions at the first

hearing, Mr. Kaleel expressed the intent that, in order for this exemption to apply, the engine or

turbine would have to be physically moved to a different Clean Air Act source at least once

every 12 months. Tr.1 at 14. He further clarified that the Agency did not intend the exemption

to apply to engines or turbines that moved between different locations within a source.

16. Mr. Kaleel suggested that units remaining at a particular source may effectively be

stationary, while others may be moved frequently from source to source. Tr.1 at 14.

We’re really thinking of things like construction sites or perhaps asphalt plants

that are movable and mobile. They’re not going to be in the same general

location for any significant length of time. It’s difficult to regulate units like that,

difficult to track them, to inspect them on a regular basis or routine basis. Tr.1 at

The Agency also accounted for the cap of 1,500 bhp in this proposed exemption. The

Agency indicated that this threshold is based in part on regulatory language exempting engines

rated at 1,500 bhp or less from permit requirements. PC 1 at 5, citing 35 Ill. Adm. Code

201.146. Although the Agency acknowledges that its proposal generally applies to engines rated

at or greater than 500 bhp, it states that potentially-affected sources confirm that “many units

rated between 500 bhp and 1,500 bhp will have low emissions, especially those engines that are

mounted on skids and moved around a particular source.” PC 1 at 5. The Agency further states

that small units may be used on a limited basis as back-up generation and have low emissions but

will not fall under the exemption for an emergency or standby unit. PC 1 at 5;

Code 211.1920; Mot. Amend, Att. A at 18 (proposing amendment to definition of “emergency or

standby unit”). For engines rated higher than 1,500 bhp that have low emissions, the Agency

states that “an owner or operator may opt for a federally enforceable emission limit or a limit on

the hours of operation.” PC 1 at 5.

In addition to mobile or portable units, the Agency proposed to exempt four other

categories of units from the requirements of Subpart Q. First, the Agency proposes to exempt an

engine or turbine that “is or has been [u]sed as an emergency or standby unit as defined by 35 Ill

Adm. Code 211.1920.” Mot. Amend, Att. A at 1 (proposed new Section 217.386(b)(1));

at 6-8 (proposing to amend definition). Second, the Agency suggested to exempt those

“[u]sed for research or for the purposes of performance verification or testing.” Mot. Amend,

Att. A at 1 (proposed new Section 217.386(b)(2)). Third, the Agency also proposed an

exemption for units “[u]sed to control emissions from landfills, where at least 50 percent of the

heat input is gas collected from a landfill.” Mot. Amend, Att. A at 1 (proposed new Section

217.386(b)(3)). Fourth, the Agency recommended an exemption for units “[u]sed for

agricultural purposes including the raising of crops or livestock that are produced on site, but not

for associated businesses like packing operations, sale of equipment or repair.” Mot. Amend,

Att. A at 1 (proposed new Section 217.386(b)(4). These four proposed exemptions did not

generate significant comment or dispute in the course of these proceedings.

Section 217.386(c).

The Agency proposes to add a new subsection (c) providing that,

“[i]f an exempt unit ceases to fulfill the criteria specified in subsection (b) of this Section, the

owner or operator must notify the Agency in writing within 30 days after becoming aware that

the exemption no longer applies and comply with the control requirements of this Subpart Q.”

Mot. Amend, Att. A at 2 (proposed new Section 218.386(c)). This proposed language did not

generate significant comment or dispute in the course of these proceedings.

Section 217.386(d).

The Agency proposes to add a new subsection (d) providing that

“[t]he requirements of this Subpart Q will continue to apply to any engine or turbine that has

ever been subject to the control requirements of Section 217.388, even if the affected unit or

source ceases to fulfill the rating requirements of subsection (a) of this Section or becomes

eligible for an exemption pursuant to subsection (b) of this Section.” Mot. Amend, Att. A at 2

(proposed new Section 217.386(d)). This proposed language did not generate significant

comment or dispute in the course of these proceedings.

Subsection (e).

In testimony on behalf of IERG, Ms. Hirner noted that the Agency’s

proposal includes a compliance deadline of May 1, 2010. Hirner Test. at 5;

Att. A at 10 (proposed new Section 217.392(b)). Ms. Hirner testified that

sources may have already implemented or may be implementing emission

reductions at units that would be affected by the Proposed Rule. Reasons for such

reductions may involve a larger decision across the source to target reductions in

one area in order to offset additional NO

emissions that may be planned in

another area, which is often referred to as ‘netting.’ Similarly, sources may

decide to reduce their own emissions in order to sell emission reduction credits as

‘offsets’ so that another source may add NO

emission. Hirner Test. at 5.

Ms. Hirner further testifies that both netting and offsetting typically involve the permitting

process “in order to recognize the creditable emissions decreases and their use for the

corresponding emissions increases.”

. at 5-6. Ms. Hirner expressed the concern that permits

could “rely on NO

emissions reductions at units that would now be subject to the Proposed

. at 6. In order to prevent any conflicts between prior permits and the Agency’s

proposal, IERG proposed as a new subsection (e) the following language:

[w]here a construction permit, for which the application was submitted to the

Agency prior to the adoption of this Subpart, is issued that relies on decreases in

emissions of NO

from existing emission units for purposes of netting or emission

offsets, such NO

decreases shall remain creditable notwithstanding any

requirements that may apply to the existing emissions units pursuant to this

Ms. Hirner further testified that the Agency concurred in this adding this subsection “ín order to

provide certainty in past, current and future permitting decisions.”

Indeed, in filing its “Clarifications and

Sheet” as Exhibit 2, the Agency proposed a

new subsection (e) substantially identical to that proposed by IERG in Ms. Hirner’s testimony.

Exh. 2 at 1. In post-hearing comments, IERG noted this proposal on the part of the Agency. PC

3 at 7. Emphasizing that this proposed subsection (e) “would preserve NO

emission reductions

in qualifying netting or offset situations,” IERG urged the Board to adopt this language. The

Board finds that the provision proposed by IERG and the Agency resolves conflicts between

prior permits and the instant proposal and adopts the proposed Section 217.386(e) for first notice.

Control and Maintenance Requirements (Section 217.388)

Section 217.388(a).

Section 217.388(a) now provides that “[t]he owner or operator must

limit the discharge from an affected unit into the atmosphere of any gases that contain NO

separate emissions concentration limits for spark-ignited rich-burn engines and spark-ignited

lean-burn engines. 35 Ill. Adm. Code 217.388(a). In addition to these two types of units, Mr.

Kaleel testified that the Agency’s proposal offers four new and “separate concentration limits for

different types of engines and turbines, and based on the kind of fuel used.” Kaleel Test. at 5.

Specifically, the Agency first proposes to amend the current emission concentration level for

spark-ignited lean-burn engines to provide an exception “for existing spark-ignited Worthington

engines that are not listed in Appendix G.” Mot. Amend, Att. A at 2 (proposed Section

217.388(a)(2));

35 Ill. Adm. Code 217. Appendix G (Existing Reciprocal Internal

Combustion Engines Affected by the NO

SIP Call). The Agency then proposes a new

subsection (a)(3), which provides a new emissions concentration level applicable to those

engines. Mot. Amend, Att. A at 2 (proposed new Section 217.388(a)(3)). In addition, the

Agency proposes new language providing three separate emissions concentration levels

applicable to diesel engines, gaseous fuel-fired turbines, and liquid fuel-fired turbines. Mot.

Amend, Att. A at 2 (proposed new Sections 217.388(a)(4), (a)(5), (a)(6)).

In his testimony on behalf of the Pipeline Group, Mr. McCarthy stated that engines and

turbines respond to emission controls in a manner that varies among the manufacturers and

models of those units. McCarthy Test. at 5. Specifically, he stated that “[u]nit-specific

technology costs and performance can vary dramatically for the slow speed, integral IC engines

prevalent in gas transmission,” requiring flexibility in NO

. Mr. McCarthy lends

support to the Agency’s proposal to add Section 217.388(a)(3) by stating that the Agency “has

properly considered an example of performance limitations by including a less stringent NO

standard under Section 217.388(a)(3) for a certain engine type found in the gas transmission

In its post-hearing comments, the IMEA stated that it “has not challenged” aspects of the

Agency’s proposed rule, including the control requirements. PC 2 at 7 (noting proposed

compliance options); Tr.1 at 43. Similarly, post-hearing comments from IERG indicated that it

“has not objected to the emission concentration limits” in the Agency’s proposal. PC 3 at 1-2

(noting compliance options); Tr.1 at 43.

Section 217.388(b).

Section 217.388(b) now provides that the owner or operator of an

affected unit may, as an alternative to complying with the emissions concentration limits in

subsection (a), comply with the requirements of an emissions averaging plan as set forth in

Section 217.390. 35 Ill. Adm. Code 217.388(b);

35 Ill. Adm. Code 217.390. The Agency

proposes to amend this subsection in two respects. First, the Agency proposes that “

unit identified by Section 217.386” may satisfy the control requirements of Subpart Q by

complying with the “requirements of the applicable emissions averaging plan as set forth in

Section 217.390.” Mot. Amend, Att. A at 2-3 (proposed Section 217.388(b)(1)) (emphasis

35 Ill. Adm. Code 217.390. Second, the Agency proposes that “units identified in

Section 217.386(a)(2),” may satisfy the control requirements by complying with “[t]he

requirements of an emissions averaging plan adopted pursuant to any other Subpart of this Part.”

Mot. Amend, Att. A at 3 (proposed new Section 217.388(b)(2)).

In her testimony on behalf of IERG, Ms. Hirner stated generally that emissions averaging

plans allow “source to decide which emission units are the most effective to control, thus

allowing over-compliant units to offset emissions from units that are not effective to control.”

Hirner Test. at 4. She lent support to the Agency’s proposed Section 217.388(b)(2), stating that

the language would allow averaging plans “to span across different Subparts of Part 217.”

She further stated that “[t]his will be helpful to our members that may not be able to utilize

averaging among Subpart Q units alone, but could achieve compliance for Subpart Q units by

averaging with emission units affected by other Part 217 provisions.”

Section 217.388(c).

The Agency proposes to add language allowing the owner or

operator of an affected unit to comply with the control requirements of Subpart Q by operating as

a low usage unit. Mot. Amend, Att. A at 3 (proposed new Section 217.388(c)). This proposed

new language specifically provides that “[l]ow usage units are not subject to the requirements of

this Subpart Q except for the requirements to inspect and maintain the unit pursuant to

subsection (d) of this Section, and retain records pursuant to Sections 217.396(b) and (d).”

“Testing and monitoring do not apply to low usage units.” Mot. Amend at 3 (¶6e). The Agency

proposes two ways for sources to qualify for this low usage exemption.

First, a source qualifies as low usage under the proposed rule if “[t]he potential to emit

(PTE) is no more than 100 TPY NO

aggregated from all engines and turbines located at the

source that are not otherwise exempt pursuant to Section 217.386(b), and not complying with the

requirements of subsection (a) or (b) of this Section, and the NO

PTE limit is contained in a

federally enforceable permit.” Mot. Amend, Att. A at 3 (proposed new Section 217.388(c)(1)).

Responding to questions at the first hearing, Mr. Kaleel clarified that units complying with the

control requirements of the proposed rule and units exempt from those requirements are not

counted toward this 100 tpy threshold. Tr.1 at 18-20 (distinguishing low usage from general

applicability threshold);

Tr.1 at 47-48 (Wagner response); PC 2 at 4.

Second, a source qualifies as a low usage unit under the proposed rule if “[t]he aggregate

bhp-hrs/MW-hrs from all affected units at the source that are not exempt pursuant to Section

217.386(b), and not complying with the requirements of subsection (a) or (b) of this Section, are

less than or equal to . . . 8 mm bhp-hrs or less on an annual basis for engines; and 20,000 MW-

hrs or less on an annual basis for turbines.” Mot. Amend, Att. A at 3 (proposed Section

217.388(c)(2)). In his testimony on behalf of the Agency, Mr. Kaleel stated that stakeholders

proposed these operating limits and that the actual thresholds resulted from negotiations with

them. Tr.1 at 48-49. Mr. Kaleel explained the rationale for these thresholds by stating that “a

relatively small unit could operate for a lot of hours and not trigger that threshold, and the

smaller unit would have fewer emissions. A larger unit would be allowed fewer hours before it

triggered that requirements because that larger unit would be expected to have larger emissions.”

Id. at 49. In responding to questions at the first hearing, Mr. Kaleel clarified that, if a source

includes both engines and turbines, it could count those hours separately by limiting annual

operation of engines to 8 mm bhp-hrs and turbines to 20,000MW-hrs and still remain a low

usage unit. Tr.1 at 21-22. However, Mr. Kaleel also stated that a source could qualify as a low

usage unit either through the enforceable NO

PTE limit in subsection (c)(1), or through the

operation limits in subsection (c)(2), but not both.

.; Mot. Amend, Att. A at 3 (proposed

Section 217.388(c)).

In her testimony on behalf of IERG, Ms. Hirner stated that the low usage option “will be

particularly useful to our industrial members who employ engine-driven electric generators.

Because such units typically operate only on an as-needed basis, our members believe that

retrofitting these types of units with controls in not practical or cost effective. Hirner Test. at 4;

PC 3 at 2. In his testimony on behalf of IMEA, Mr. Wagner stated that “[a]n emissions

averaging plan offers little compliance relief due to the uniformity in design and operation

among most municipal units. Thus, the low usage designation is critical for our member to be

able to comply with this Proposed Rule.” Wagner Test. at 10;

PC 2 at 4. Noting that

proposed Section 217.388(c)(2) allows a source including both engines and turbines to count

their annual operating hours separately, Mr. Wagner stated that “[t]his approach provides

important flexibility for IMEA’s members, which IMEA strongly supports.” Wagner Test. at 8.

In his testimony on behalf of the Pipeline Group, Mr. McCarthy characterized the low usage

criteria as one notable way that the Agency’s proposal provides flexibility to affected sources.

McCarthy Test. at 5. He further stated that the provision is one of the compliance options

“necessary for a workable rule” and one strongly supported by the Pipeline Group.

Emissions Averaging Plan (Section 217.390)

Section 217.390 allows an owner or operator of certain affected units to comply with the

control requirements of Subpart Q through an emissions averaging plan. 35 Ill. Adm. Code

217.390. The section includes language implementing this compliance option.

Code 217.390(a) – (h).

As noted above, Ms. Hirner characterized emissions averaging as a “useful addition” to

the Agency’s proposal: “[t]his compliance option allows sources to decide which emission units

are the most effective to control , thus allowing over-compliant units to offset emissions from

units that are not effective to control.” Hirner Test. at 4, PC 3 at 2. She emphasized that the

Agency proposes to allow averaging of emissions from Subpart Q units “with emission units

affected by other Part 217 provisions.” PC 3 at 2;

Hirner Test. at 4, citing Mot. Amend,

Att. A at 3 (proposed new Section 217.388(b)(2)). In his testimony on behalf of the Pipeline

Group, Mr. McCarthy characterized emissions averaging as one notable way that the Agency’s

proposal provides flexibility to affected sources. McCarthy Test. at 5. He further stated that the

provision is one of the compliance options “necessary for a workable rule” and one strongly

supported by the Pipeline Group.

The Agency has not proposed significant amendments to subsections addressing the

following matters: demonstrating compliance with a plan (35 Ill. Adm. Code 217.390(e)); the

equation for determining compliance with a plan (35 Ill. Adm. Code 217.390(f)); and compliance

for units that use continuous emissions monitoring systems (CEMS) (35 Ill. Adm. Code

Mot. Amend, Att. A at 6-7, 10; Exh. 2 at 1-2. The Board below summarizes

amendments proposed by the Agency to the remaining subsections of Section 217.390 on a

subsection-by-subsection basis.

Section 217.390(a).

In the provision describing units that commenced operation before

January 1, 2002 that may be included in a single emission averaging plan, the Agency proposes

to add language under which “owners or operators with affected engines and turbines located at

more than one source within a given nonattainment area may develop a companywide emissions

averaging plan for the given nonattainment area.” Mot. Amend at 3 (¶6d);

Mot. Amend, Att.

A at 4 (proposed new Section 217.390(a)(1)(A)(ii)), Exh. 2 at 1 (¶4) (correction);

see generally

Kaleel Test. at 6. The Agency also proposes to add new language making eligible for averaging

plans “[u]nits that have a compliance date later than the control period for which the averaging

plan is being used for compliance.” Mot. Amend, Att. A at 4 (proposed new Section

217.390(a)(1)(B)). The Agency also proposes to add language making eligible

[u]nits which the owner or operator may claim as exempt pursuant to Section

217.386(a) but does not claim as exempt. For as long as such unit is included in

an emissions averaging plan, it will be treated as an affected unit and subject to

the applicable emission concentration, limits, testing, monitoring, recordkeeping

and reporting requirements. Mot. Amend, Att. A at 5 (proposed new Section

217.390(a)(1)(C)).

Finally, the Agency also proposes language adding to the types of units may not be included in

an averaging plan “[u]nits which the owner or operator is claiming are exempt pursuant to

Section 217.386(b) or as low usage units pursuant to Section 217.388(c).” Mot. Amend, Att. A

at 5 (proposed new Section 217.390(a)(2)(B)).

Section 217.390(b).

The prefatory paragraph of Section 217.390(b) now provides in part

that “[a]n owner or operator must submit an emissions averaging plan to the Agency by the

applicable compliance date set forth in Section 217.392.” 35 Ill. Adm. Code 217.390(b). The

subsection continues by describing information the submitted plan must include.

“Clarification and

Sheet,” the Agency states that this “submission date needs to be

clarified to include an option for an owner or operator to change their method of compliance

after the initial compliance date.” Exh. 2 at 2 (¶5). Specifically, the Agency proposes to add to

the current language cited above that the plan may be submitted “by May 1 of the year in which

the owner or operator is using a new emissions averaging plan to comply.”

The Agency also proposes in Exhibit 2 to provide the effective date of averaging plans.

After re-numbering existing subsection (b)(1) and (b)(2) to subsection (b)(1)(A) and (B)(1)(B),

respectively, the Agency proposes to add a new Section 217.390(b)(2):

Those plans will be effective as follows:

An initial plan for units required to comply by January 1, 2008, is

effective January 1, 2008;

An initial plan for units required to comply by May 1, 2010, is

effective May 1, 2010 for those units;

A new plan submitted pursuant to subsection (b) of this Section but

not submitted by January 1, 2008 or May 1, 2010 is effective

retroactively to January 1 of the applicable year;

An amended plan submitted pursuant to subsection (c) of this

Section is effective retroactively to January 1 of the applicable

An amended plan submitted pursuant to subsection (d) of this

Section is effective on the date it is received by the Agency. Exh.

Section 217.390(c).

Section 217.390(c) allows an owner or operator to amend an

averaging plan only once per calendar year. 35 Ill. Adm. Code 217.390(c). The Agency

proposes to add to this subsection language providing that “[a]n amended plan must include the

information from subsection (b)(1) and may, but is not limited to changing the group of affected

units or reflecting changes in the operation of the affected units.” Exh. 2 at 2. The Agency also

proposes to add language providing that amended plans submitted to the Agency become

effective as set forth in the proposed new subsection (b)(2).

Section 217.390(d).

Subsection (d) provides that, notwithstanding subsection (c)

allowing an emissions averaging plan to be amended only once per calendar year, “an owner or

operator, and the buyer, if applicable, must submit an updated emissions averaging plan or plans

to the Agency within 60 days if a unit that is listed in an emissions averaging plan is sold or

taken out of service.” 35 Ill. Adm. Code 217.390(d);

35 Ill. Adm. Code 217.390(c). The

Agency proposes to re-number this language as subsection (d)(1). Mot. Amend, Att. A at 6. The

Agency also proposed to add as subsection (d)(2) language providing that, notwithstanding

subsection (c), an owner or operator, and the buyer, if applicable, “[m]ay amend its emissions

averaging plan to include another unit within 30 days of discovering that the unit no longer

qualifies as an exempt unit pursuant to Section 217.386(b) or as a low usage unit pursuant to

Section 217.388(c).” Mot. Amend, Att. A at 6.

Section 217.390(g).

Section 217.390(g)(6) establishes, for “non-Appendix G units used

in an emissions averaging plan,” the allowable emissions rate to be used in determining

allowable emissions under subsection (g)(2). 35 Ill. Adm. Code 217.390(g)(6);

Code 217.390(g)(2). Specifically, that rate is “the higher of the actual NO

determined by testing or monitoring data, or the applicable uncontrolled NO

emissions factor

from Compilation of Air Pollutant Emission Factors: AP-42, Volume I: Stationary Point and

Areas Sources, as incorporated by reference in Section 217.104.” 35 Ill. Adm. Code

The Agency first proposes to amend subsection (g)(6) by providing that it applies not to

“non-Appendix G units used in an emissions averaging plan,” but to “units that have a later

compliance date.” Mot. Amend, Att. A at 9. Second, the Agency proposes that the allowable

emissions rate must be the higher of the actual NO

emissions or the applicable uncontrolled

emissions factor “[p]rior to the applicable compliance date pursuant to Section 217.392.”

Mot. Amend, Att. A at 9;

35 Ill. Adm. Code 217.390(g)(6). Finally, the Agency proposes to

add language providing that, “[o]n and after the unit’s applicable compliance date pursuant to

section 217.392, the applicable emissions concentration for that type of unit pursuant to Section

217.388(a).” Mot. Amend, Att. A at 9;

35 Ill. Adm. Code 217.388(a).

Compliance (Section 217.392)

Section 217.392 now provides in its entirety that “[o]n and after January 1, 2008, an

owner or operator of an affected engine listed in Appendix G may not operate the affected engine

unless the requirements of this Subpart Q are met or the affected engine is exempt pursuant to

Section 217.386(b).” 35 Ill. Adm. Code 217.392;

35 Ill. Adm. Code 217.386(b), 35 Ill. Adm.

Code Appendix G. The Agency proposes to re-number this provision as Section 217.392(a).

Mot. Amend, Att. A at 10. In its amended proposal, the Agency seeks to add a compliance date

of May 1, 2010 for RACT units. Mot. Amend at 3 (¶6b); Kaleel Test. at 7. Specifically, the

Agency proposes to add a new Section 217.392(b) providing that, “[o]n and after May 1, 2010,

an owner or operator of a unit identified by Section 217.386 (a)(2), and that is not listed in

Appendix G, may not operate the affected unit unless the requirements of this Subpart Q are met

or the affected unit is exempt pursuant to Section 217.386(b).” Mot. Amend, Att. A at 10;

Exh. 2 at 3 (¶6) (correction).

The Agency also proposed to add to Section 217.392 a compliance option allowing

owners and operators under certain circumstances to use NO

trading program allowances to

satisfy the control requirements of Subpart Q. Kaleel Test. at 6; Mot. Amend, Att. A at 10-11

(proposed new Section 217.392(c)). The Agency’s proposed language defines a NO

as “an allowance used to meet the requirements of a NO

trading program administered by

USEPA where one allowance is equal to one ton of NO

emissions.” Mot. Amend, Att. A at 10-

11 (proposed new Section 217.392(c)). In his prefiled testimony on behalf of the Agency, Mr.

Kaleel stated that “[t]his option is included in the proposal at the request of stakeholders and will

again provide increased operating flexibility and will reduce compliance costs.” Kaleel Test. at

The Agency’s proposal lists three circumstances, all of which must apply for NO

allowances to be used. First, the allowances may be used only “[f]or a unit that is not listed in

Appendix G.” Mot. Amend, Att. A at 11 (proposed new Section 217.392(c)(1)(C)). Second,

there must occur “[a]n anomalous or unforeseen operating scenario inconsistent with historical

operation for a particular ozone season or calendar year that causes an exceedance of an

emissions or operating hour limitation.” Mot. Amend, Att. A at 11 (proposed new Section

217.392(c)(1)(A));

Tr.1 at 51, Kaleel Test. at 7,

Exh. 2 at 3 (¶7) (correction). In

responding to questions at the first hearing, Mr.Kaleel recognized that operators of engines and

turbines may face unforeseen circumstances, and he indicated that the Agency included NO

allowances in its proposal in order to address those. Tr.1 at 54.

Third, the owner or operator may use NO

allowances “[t]o achieve compliance for no

more than two events in any rolling five-year period.” Mot. Amend, Att. A at 11 (proposed new

Section 217.392(c)(1)(B));

Kaleel Test. at 7,

Exh. 2 at 3 (¶8) (correction). In

responding to questions at the first hearing, Mr. Kaleel suggested that exceedances occurring

more often than twice in any rolling five-year period may not be truly unforeseeable and may

require “better planning” on the part of owners and operators. Tr.1 at 51. He indicated that the

Agency did not want this option to become “open-ended” and felt that the option should not

become “an unlimited way of complying with the rule.”

The Agency also has proposed language on surrendering NO

allowances. Specifically,

“[t]he applicable type of NO

allowances must be used, that is, annual allowances must be used

for exceedances of an annual limit and ozone season allowances must be used for exceedances of

a seasonal limit.” Kaleel Test. at 7;

Mot. Amend, Att. A at 11 (proposed new Section

217.392(c)(2)). The Agency also proposes that, when an affected unit exceeds a low usage

limitation, “the owner or operator of the affected unit must calculate the NO

emissions resulting

from the number of hours that exceeded the operating hour low usage limit and surrender to the

allowance for each ton or portion of a ton of NO

that was calculated.” Mot.

Amend, Att. A at 11 (proposed new Section 217.392(c)(2)).

In addition, the Agency proposes to require that the owner or operator must file with the

Agency “a report documenting the circumstances that required the use of NO

identify what actions will be taken in subsequent years to address these circumstances.” Mot.

Amend, Att. A at 11 (proposed new Section 217.392(c)(3)). This proposed requirements

includes deadlines for submitting those reports: “by October 31 for exceedances during the

ozone season and March 1 for exceedances of the emissions concentration limits, the annual

emissions averaging plan limits, or low usage limitations.”

In his testimony on behalf of IMEA, Mr. Wagner stated that, for his association, “[a]n

emission averaging plan offers little compliance relief due to the uniformity in design and

operation among most municipal units.” Wagner Test. at 10. He further stated that “[m]any of

the IMEA members’ units, particularly the older units, will be forced to operate as low usage

units because it is economically not feasible to modify these units to comply with the emission

requirements of the Proposed Rule, particularly given that these units operate sporadically.”

at 8-9. Mr. Wagner suggested, however, that the benefit of the low usage option is significantly

reduced by “the substantial reduction on permitted capacity that some members will likely face.”

. at 11. He states allowing use of NO

allowances addresses this concern.

., PC 2 at 5. He

argues that “[t]he low usage compliance option would simply not be workable without the NO

allowance provision.” Wagner Test. at 11-12 (citing flexibility); PC 2 at 5. He summarizes by

stating that provision for low usage operation and the use of NO

allowances “are considered by

IMEA to be absolutely essential.” Wagner Test

at 13; PC 2 at 7.

In her testimony on behalf of IERG, Ms. Hirner characterized the ability to use NO

allowances as an “important component” of the Agency’s proposed rule. Hirner Test. at 5. She

states that “IERG supports the ability for regulated sources to utilize the emissions marketplace

when compliance difficulties arise. Such an approach is beneficial to the environment as well, as

emission allowances, in an amount equivalent to the compliance excursion, would be retired

from the allowance pool.”

In his testimony on behalf of the Pipeline Group, Mr. McCarthy characterized the limited

emissions allowances in anomalous circumstances as one notable way in which the

Agency’s proposal provides flexibility to affected sources. McCarthy Test. at 5. He further

stated that the provision is one of the compliance options “necessary for a workable rule” and

one strongly supported by the Pipeline Group.

Testing and Monitoring (Section 217.394)

Section 217.394 includes provisions relating to initial performance tests of affected units

(35 Ill. Adm. Code 217.394(a)), subsequent performance tests (35 Ill. Adm. Code 217.394(b)),

testing procedures (35 Ill. Adm. Code 217.394(c)), monitoring (35 Ill. Adm. Code 217.394(d)),

and units that use CEMS (35 Ill. Adm. Code 217.394(e)).

In his prefiled testimony on behalf of the Agency, Mr. Kaleel claims that the Agency’s

proposal “provides a flexible approach for meeting the requirements for testing and monitoring.”

Kaleel Test. at 7. He stated that, “[i]n general, affected units must conduct a compliance test by

the applicable compliance date.”

Mot. Amend, Att. A at 12 (proposed Section

217.394(a)(2)). He further stated that “[a]ffected units that operate intermittently do not need to

be tested until after they have operated at least 876 hours in a year.” Kaleel Test. at 7.

Amend, Att. A at 12 (proposed Section 217.394(a)(2)). Mr. Kaleel also stated that “[u]nits that

operate less than 876 hours per calendar year can be tested at the owner’s or operator’s choosing

any time within the first five years after the applicable compliance date.” Kaleel Test. at 7;

Mot. Amend, Att. A at 12 (proposed Section 217.394(a)(3)).

Although the Agency does not propose significant amendments to subsections (b), (c),

(d), or (e), it proposes a new subsection (f) regarding low usage units.

Mot. Amend, Att. A

at 14. That new subsection clarifies that, “[t]he testing and monitoring requirements of this

Section do not apply to affected units in compliance with the requirements of the low usage

limitations pursuant to Section 217.388(c) or low usage units using NO

allowances to comply

with the requirements of this Subpart pursuant to Section 217.392(c).”

. (proposed new

Section 217.394(f));

Mot. Amend at 3 (¶6e), Tr.1 at 36 (Kaleel testimony). The Agency also

proposes to require that, if the Agency or USEPA determines that “it is necessary to conduct

testing to demonstrate compliance with Section 217.388, the owner or operator of a unit must, at

his or her own expense, conduct the test in accordance with the applicable test methods and

procedures specified in this Section within 90 days after receipt of a notice to test from the

Agency or USEPA.” Mot. Amend, Att. A at 14 (proposed new Section 217.394(f));

36 (Kaleel testimony).

Recordkeeping and Reporting (Section 217.396)

Section 217.396 now provides requirements with regard to recordkeeping and reporting.

35 Ill. Adm. Code 217.396. Recordkeeping requirements now apply to an owner or operator of

an Appendix G unit or a unit included in an emissions averaging plan. 35 Ill. Adm. Code

217.396(a). The Agency first proposes to amend this subsection by clarifying that its

requirements apply to the owner or operator of “a unit included in an emissions averaging plan or

an affected unit that it not exempt pursuant to Section 217.386(b) and is not subject to the low

usage exemption of Section 217.388(c).” Mot. Amend, Att. A at 14 (proposed amendment to

existing Section 217.396(a)).

Section 217.396(a) requires maintenance of “records that demonstrate compliance with

the requirements of Subpart Q which include, but are not limited to” ten specified items. 35 Ill.

Adm. Code 217.396(a)(1) – (10). The Agency proposes to add an eleventh required record:

allowance reconciliation reports submitted pursuant to Section 217.392(c)(3).” Mot.

Amend , Att. A at 15 (proposed new Section 217.396(a)(11)).

Section 217.396(c) places reporting requirements on the owner or operator of an affected

unit. 35 Ill. Adm. Code 217.396(c)(1) – (5). The Agency proposes to add a new Section

217.396(c)(6) providing that, if an owner or operator uses NO

allowances to comply with the

requirements of Section 217.388, he or she must submit “reconciliation report as required by

Section 217.392(c)(3).” Mot. Amend, Att. A at 17 (proposed new Section 217.396(c)(6)).

In addition, the Agency proposes to add a new Section 217.396(d) requiring that low

usage units “maintain records that demonstrate that they continue to qualify for that exemption.”

Tr.1 at 36 (Kaleel testimony). Specifically, the proposed language requires that the owner or

operator of a low usage unit must maintain a record of NO

emissions for each calendar year if

the unit complies through an enforceable limit on NO

PTE. Mot. Amend, Att. A at 17

(proposed new Section 217.396(d)(1)). The proposed language also requires a record of bhp or

MW hours operated each calendar year if the unit complies through an operation limit.

(proposed new Section 217.396(d)(2)). The proposed language also requires the maintenance

and submission of any NO

allowance reconciliation reports if the unit relies upon those

allowances for compliance.

(proposed new Section 217.396(d)(3)).

ECONOMIC AND TECHNICAL CONSIDERATIONS

Economic Impact Study

In a letter dated January 23, 2008, the Board requested that the Department of Commerce

and Economic Opportunity (DCEO) conduct an economic impact study on this amended

rulemaking proposal.

415 ILCS 5/27(b)(1) (2006). To date, the Board has received no

response to that request. At the second hearing, the Board received no testimony or comment

regarding the absence of any response to the request.

Technical Feasibility of Controls

In his testimony on behalf of the Agency, Mr. Mahajan stated that the Agency “identified

several sources of guidance” on the issue of controlling NO

emissions from engines and

turbines. Mahajan Test. at 2. He further stated that these sources include detailed information

on issues including strategies for controlling NO

and the cost of those strategies.

indicated that the Agency relied upon specific sources of information “for the proposed level of

controls, costs and economic impacts for this proposal.”

. The Agency first lists as a

source Alternative Control Techniques Document – NO

Emissions from Stationary

Reciprocating Internal Combustion Engines (EPA-453/R-93-032), published by USEPA.

2, TSD at 42 (§10.0 References);

Fast-Track Rules Under Nitrogen Oxide (NO

Phase II: Amendments to 35 Ill. Adm. Code Section 201.146 and Parts 211 and 217, R07-18

(Apr. 6, 2007) (Attachment 11c to original Agency proposal). The Agency also lists as a source

Alternative Control Techniques Document – NO

Emissions from Stationary Gas Turbines

(EPA-453/R-93-007), published by USEPA. Mahajan Test

at 2, TSD at 42 (§10.0 References);

Fast-Track Rules Under Nitrogen Oxide (NO

) SIP Call Phase II: Amendments to 35 Ill.

Adm. Code Section 201.146 and Parts 211 and 217, R07-18 (Apr. 6, 2007) (Attachment 11d to

original Agency proposal). Finally, the Agency also lists Controlling Nitrogen Oxides Under the

Clean Air Act: A Menu of Options, published by the State and Territorial Air Pollution Program

Administrators and Association of Local Air Pollution Control Officials (STAPPA/ALAPCO).

Mahajan Test. at 2, TSD at 42 (§10.0 References);

Fast-Track Rules Under Nitrogen Oxide

) SIP Call Phase II: Amendments to 35 Ill. Adm. Code Section 201.146 and Parts 211 and

217, R07-18 (Apr. 6, 2007) (Attachment 11e to original Agency proposal).

Combustion Controls for Engines

In his testimony on behalf of the Agency, Mr. Mahajan addressed the issue of NO

emission controls by stating that, “[f]or reciprocating engines and turbines, both combustion

controls and post-combustion catalytic reduction have been developed.” Mahajan Test. at 3;

TSD at 19 (§4.0 Technical Feasibility of Controls). Mr. Mahajan’s testimony first listed

combustion controls for reciprocating engines: air/fuel ratio adjustments, low emission

combustion, and prestratified charge. Mahajan Test. at 3. “These controls function by

modifying the combustion zone air/fuel ratio, thus influencing oxygen availability and peak

flame temperature.” TSD at 19. Mr. Mahajan also listed ignition timing retard, which “lowers

the peak flame temperature by delaying the onset of combustion.” Mahajan Test. at 3; TSD at

19. The Board addresses these strategies one-by-one in the succeeding paragraphs.

Air/Fuel Ratio Adjustments.

In its TSD, the Agency states that “[l]owering the air-to-

fuel (A/F) ratio in rich-burn engines limits oxygen availability in the cylinder, thus decreasing

emissions both by lowering peak flame temperature and by producing a reducing

atmosphere.” TSD at 19 (§4.1). In addition to actual adjustment of the A/F ratio, this strategy

requires a feedback controller in order to follow changes in load and other operating conditions.

. The Agency claims that, for rich-burn engines, this adjustment of the A/F ratio is “well-

demonstrated” and “typically yields 10-40 percent reductions in NO

Agency further claims that this range reflects the wide variety of existing A/F ratios.

Regarding lean-burn engines, the Agency states in its TSD that “increasing the A/F ratio

emissions.” TSD at 19. “Extra air dilutes the combustion gases, thus lowering

peak flame temperature and reducing thermal NO

. This strategy requires either

installation of a turbocharger or modification of an existing one in order to increase air flow at

constant fuel flow and to avoid de-rating the engine’s capacity.

. at 19-20. The Agency notes

that “space constraints may limit the extent to which turbocharger capacity may be increased.”

. at 20. The Agency further notes that this strategy may be less effective in carbureted engines,

which do not have the same A/F ratio in each cylinder.

. The Agency claims that, with A/F

ratio adjustment, “[r]eductions in lean-burn engine NO

emissions of 5-30 percent are possible.”

. The Agency states that these reductions may be limited by combustion instability, lean

misfire, and decreased engine efficiency.

. The Agency concludes its discussion of this

strategy by noting that it “is not applicable to compression ignition engines.”

Low Emission Combustion.

In its TSD, the Agency states that “[l]ow emission

combustion (LEC) is the combustion of very fuel-lean mixture.” TSD at 21 (§4.4). The Agency

reports that this strategy “requires considerable engine modification,” including the complete

rebuilding of rich-burn engines.

. The Agency further reports that LEC has limited

applicability, as “[c]onversion kits are not available for all engines and refitted engines may have

degraded load-following capabilities.”

. at 21-22. For rich-burn engines, however, LEC can

achieve emission reductions of 70-90 percent.

. at 22. Lean-burn engines can achieve a

“reduction of about 80-93 percent.”

The Agency stresses that “LEC is not effective for diesel engines, but does work for dual-

fuel engines.” TSD at 22. Specifically, the Agency claims that these engines can decrease

emissions by 60-80 percent with LEC.

. The Agency also claims that “[s]ome reductions in

exhaust opacity have been claimed when LEC is implemented on dual-fuel engines.”

Prestratified Charge.

In its TSD, the Agency describes prestratified charge (PSC) as “a

technology for injecting fuel and air into the intake manifold in distinct ‘slugs,’ which become

separate fuel and air layers upon intake into the cylinders.” TSD at 21 (§4.3). The Agency states

that this strategy allows combustion to occur at lower temperatures and to produce less thermal

without misfiring.

. The Agency further states that PSC “is applicable to carbureted,

spark ignition four-stroke engines” and that retrofitting kits area available for most of them.

The Agency notes, however, that PSC is not applicable to fuel-injected or blower-scavenged

. The Agency concludes its discussion of this strategy by claiming that this strategy

can reduce emission by 80-95 percent.

Ignition Timing Retard.

In its TSD, the Agency claims that ignition timing retard (ITR)

“is applicable to all engines.” TSD at 20 (§4.2). The Agency states that this strategy moves “the

ignition event to later in the power stroke when the piston has begun to move downward,”

lowering the peak flame temperature and thermal NO

. Although the Agency

indicates that these timing adjustments are relatively simple, it suggests that replacing the

ignition system “will provide better performance with varying engine load and conditions.”

The Agency claims that ITR can achieve emission reductions of 0-40 percent for spark-

ignited engines and 20-30 percent for compression-ignited engines. TSD at 21. The Agency

states that these reductions vary with engine design and operating conditions, particularly air/fuel

. The Agency further states that “[r]eductions are also restricted by limitations on the

extent to which ignition may be delayed, in that excess retard results in engine misfire.”

20-21. The Agency acknowledges that ITR normally decreases fuel efficiency and increases

exhaust temperatures, which can result in reducing the life of exhaust valves and turbochargers.

. at 21. Also, the Agency notes that, “[o]n diesel engines, it also may result in black smoke.”

Combustion Controls for Turbines

In his testimony on behalf of the Agency, Mr. Mahajan addressed turbines by stating that

“water/steam injection and dry low-NO

combustors are the combustion control technologies

used to control NO

emissions.” Mahajan Test. at 3;

TSD at 19 (§4.0 Technical Feasibility

of Controls). The Board addresses these two strategies in the succeeding paragraphs.

Water/Steam Injection.

In its TSD, the Agency states that this strategy “lowers peak

flame temperature by providing an inert diluent, thus limiting thermal NO

formation.” TSD at

22 (§4.5). The Agency claims that this “[w]et injection is applicable to most, if not all, turbines,

and has been applied to a large number of turbines in the United States.”

. The Agency further

claims that “[m]ost turbine manufacturers sell water and steam injection systems.”

Because wet injection limits only thermal NO

formation, controlling emissions depends

on the amount of injected water and the fuel/nitrogen content. TSD at 23. The Agency claims

that emission reductions of 60-90 percent can be obtained with both natural gas and distillate oil.

. The Agency acknowledges, however, that “[h]igh water-to-fuel ratios result in increased

hydrocarbon and greatly increased CO [carbon monoxide] emissions.”

. Also, the energy used

to heat injected water may reduce the fuel efficiency of the turbine.

. In addition, this strategy

may require increased turbine maintenance.

. Finally, the Agency states that treating water for

injection generates wastewater.

Combustors.

In its TSD, the Agency states that, while “[d]ry low-NO

combustors encompass several different technologies, “[l]ean premixed combustion is the

commercially available technology that affords the largest NO

reductions.” TSD at 23 (§4.6).

The Agency explains that this strategy operates by providing excess air to the combustion

chamber, which lowers peak temperatures.

The Agency acknowledges that, while retrofit low-NO

combustors have been installed

on may turbines, they are not available for all models. TSD at 23. The Agency further

acknowledges that these retrofits face difficulties. First, “they are less effective on oil-fired than

on gas-fired turbines” because they reduce only thermal NO

. Second, the retrofit

may require “some modification of the combustor section of the turbine.”

. at 23-24. Finally,

oil-fired turbines can obtain comparable emission reductions without retrofitting.

Nonetheless, the Agency claims that this strategy obtains emission reductions of 60-95 percent.

Post-Combustion Controls

In his testimony on behalf of the Agency, Mr. Mahajan addressed post-combustion

controls for both engines and turbines. Mahajan Test. at 3;

TSD at 19 (§4.0 Technical

Feasibility of Controls). He stated that these strategies destroy NO

once it is formed. Mahajan

Test. at 3. The Board addresses these two strategies in the succeeding paragraphs.

Non-Selective Catalytic Reduction.

In its TSD, the Agency states that “[n]on-selective

catalytic reduction (NSCR) uses the three-way catalysts found in automotive applications to

promote that reduction of NO

to nitrogen and water.” TSD at 24 (§4.7). The Agency further

states that “NSCR is applicable only to rich burn engines with exhaust oxygen concentrations

below about one percent.”

The Agency reports that NSCR is not feasible for turbines and

that the exhaust from lean-burn engines will not be sufficient for reduction of the NO

. In addition, the Agency notes that NSCR retrofits involve installation of a catalyst, catalyst

housing, and “an oxygen sensor and feedback controller to maintain an appropriate A/F ratio

under variable load conditions.”

. Nonetheless, the Agency claims that this strategy can

achieve emission reductions greater than 90 percent.

Selective Catalytic Reduction.

In its TSD, the Agency describes selective catalytic

reduction (SCR) as “[t]he catalyzed reduction of NO

with injected ammonia.” TSD at 24

(§4.8). The Agency states that this strategy applies “only to lean-burn engines with greater than

about one percent exhaust oxygen, as oxygen is a reagent in the selective reduction reaction.”

The Agency further states that an SCR retrofit involves installation of “the reactor and catalyst,

appropriate ductwork, an ammonia storage and distribution system, and a control system for

variable load operation.”

. at 25. The Agency claims that emission reductions with this

strategy “are limited only by the amount of catalyst used and typically are on the order of 90

Potentially Affected Sources

In its TSD, the Agency stated that it reviewed its 2004 inventory of reciprocating internal

combustion engines and turbines in order to determine those that may be affected by its proposal.

TSD at 38 (§7.0 Potentially Affected Sources). This review concluded that 541 engines located

in the nonattainment areas had the potential to be affected by the proposed regulations.

Mahajan Test. at 3. After applying an exemption of approximately 100 tons of NO

from all engines at a facility, the Agency estimates that its proposal will have an actual impact on

55 of those engines. Mahajan Test. at 3, TSD at 38 (Table 7-1), TSD, Attachment A (listing

impacted engines).

Because current regulations do not require a permit to operate an engine with a capacity

of less than 1,500 bhp, the Agency’s “NO

inventory does not include all the engines from 500 to

1,500 bhp that may be affected by this proposal.” TSD at 38. In order to identify those sources,

the Agency conducted a statewide survey of businesses and industries with the assistance of the

. From the results of that survey, the Agency estimated that there are 79 units in that

range that may also be affected by the proposal.

. The Agency “further assumed that many of

these units would qualify for exemptions and therefore, only approximately eight engines would

be impacted by this proposal.” TSD at 38, TSD, Attachment A (listing impacted engines);

Mahajan Test. at 3-4. The Agency expects a total of 63 engines to be affected by its proposed

regulations. Mahajan Test. at 4, TSD at 38 (Table 7-1).

The Agency also states in its TSD that the review of inventory revealed 220 turbines

located in the nonattainment areas that may be affected by its proposal. TSD at 38, Mahajan

Test. at 4. After applying an exemption of approximately 100 tons of NO

per year from all

turbines at a facility, the Agency concluded that its proposal would affect 58 of those turbines.

TSD at 38 (Table 7-1), TSD, Attachment A (listing impacted turbines), Mahajan Test. at 4.

In her testimony on behalf of IERG, Ms. Hirner noted that the Agency in Attachment A

to its amended TSD had sought to list potentially affected engines and turbines in the

nonattainment areas. Hirner Test. at 3;

TSD, Attachment A. She claimed that “IERG has

nonattainment area members that will be affected by this Proposed Rule, yet these units are not

listed in Attachment A.” Hirner Test. at 3. Ms. Hirner stated that IERG considers the Agency’s

proposed language on applicability of Subpart Q to be, for the most part, “acceptable.”

However, she stated that “IERG does not believe that the Amended Technical Support Document

provides correct information regarding the applicability of the Proposed Rule.”

In post-hearing comments, IERG stated that it had conferred with its members who have

major sources of NO

emissions in the nonattainment areas. PC 3 at 5. With its comments,

IERG submitted an Exhibit 1, a preliminary list of its members having “engines and turbines that

seem to be potentially subject to the Proposed Rule.”

PC 3, Exhibit 1. IERG notes that it

did not include in its exhibit insignificant activities such as qualifying emergency/standby units

or units with capacity less than 150 bhp.

., citing 35 Ill. Adm. Code 201.210(a)(15),

210(a)(16). The comment claimed that “[t]he vast majority of the units in Exhibit 1 were not

identified by Illinois EPA as potentially subject to the Proposed Rule.” PC 3 at 5.

IERG further commented that, “[w]here units identified in Exhibit 1 currently have

federally enforceable [emission] limits, those limits were included in the unit descriptions.” PC

PC 3, Exhibit 1. IERG stated that it included those limits to demonstrate that the

Agency had not identified as potentially subject to the proposed rule units that do not appear to

qualify for the low usage exemption. PC 3 at 6. IERG states that, if these units wished to

qualify for that exemption, they would be required to expend permitting resources to obtain a

federally enforceable emissions limit and restrict its operating ability.

. Alternatively, those

units may have to comply with the proposed emissions limits, which could require retrofit

. IERG argues that units facing elections of this nature should be addressed in

any discussion of the proposal’s impact.

In its post-hearing comments, the Agency acknowledged that, although it drew its list of

potentially impacted engines and turbines from a database on which it heavily relies, its

inventory is not a perfect document. PC 4 at 1, citing Tr.1 at 24-26. The Agency emphasized

that the inventory included only units that it believed would require NO

controls after taking

into account the low usage option and the exemptions in the proposal. PC 4 at 2.

Nonetheless, the Agency stated that it had reviewed IERG’s comments and determined

that IERG had identified 35 additional engines that the proposed rule may affect. PC 4 at 1. Of

those 35, the Agency concludes based on facility reported NO

emission data that 30 will qualify

for the low-usage option and two will qualify for the landfill gas usage exemption.

the remaining three engines at U.S. Steel Corporation, the Agency stated that it could not “find

the facility reported NO

emissions because these emissions were reported as part of their

associated processes.”

. The Agency stated that U.S. Steel Corporation’s most recent permit

application includes one emergency generator limited to emitting 19.9 tons of NO

one engine that will have NSCR installed to control NO

The Agency also reviewed IERG’s comments to determine that IERG had identified 78

additional turbines that the proposed rule may affect. PC 4 at 1. Of those 78, the Agency states

that “24 turbines are already retrofitted with NO

controls, 11 turbines will qualify for [the]

landfill gas exemption, and 43 turbines, mostly used as peaking units at power plants, will

qualify for the 20,000 MW-hrs limit compliance option.”

. at 2. The Agency expresses the

belief that the units retrofitted with emission controls comply with the proposed regulations. The

Agency claims that “there will not be any additional cost of controlling NO

emissions to the

sources except for some administrative cost of recordkeeping and reporting.”

Emissions Reductions

In its TSD, the Agency represented that, of the 541 permitted engines it identified as

potentially affected by the proposed rule, it expected the proposal actually to affect 55 of them.

TSD at 38 (Table 7-1). The Agency estimated the total 2004 NO

emissions from those 55

engines to be 1,198 tpy and 528 tons per ozone season. TSD at 39 (Table 8-1). To estimate NO

emission reductions from the proposal, the Agency then applied an 82 percent control level to

gas-fired engines and a 25 percent control efficiency to diesel engines.

. Accordingly, the

Agency concludes that the proposed rule will achieve estimated NO

emissions reductions from

these 55 engines of 983 tpy and 433 tons per ozone season.

In its TSD, the Agency also represented that, of the 79 smaller engines potentially

affected by the proposed rule, it expected the proposal to actually to affect eight of them. To

emission reductions from smaller engines rated between 500 bhp and 1,500 bhp,

the Agency assumed capacity of the affected engines to be 1,000 bhp and the annual operating

schedule to be 4,000 hours. TSD at 39. “At a NO

emission rate of 16.8 g/bhp-hr, the estimated

emissions were determined to be 593 tpy and 247 tons per ozone season.”

Applying a control efficiency of 82 percent, the Agency calculated the estimated NO

reductions from these smaller engines to be 486 tpy and 203 tons per ozone season.

Mahajan Test. at 4 (estimating emission reductions from all 63 engines).

In its TSD, the Agency also represented that, of the 220 turbines it identified as

potentially affected by the proposed rule, it expected the proposal actually to affect 58 of them.

TSD at 38 (Table 7-1). The Agency estimated the total 2004 NO

emissions from those 58

turbines to be 1,316 tpy and 706 tons per ozone season. TSD at 39 (Table 8-1). To estimate

emissions reductions from the proposal, the Agency then applied a 60 percent control

efficiency, although “[n]o control was applied to a turbine which is subject to NSPS [New

Source Performance Standards] for NO

emissions.” TSD at 39. Accordingly, the Agency

concludes that the proposed rule will achieve estimated NO

emissions reductions from these 58

turbines of 686 tpy and 381 tons per ozone season. TSD at 39 (Table 8-1), Mahajan Test. at 4.

The Agency states that the total 2004 NO

emissions from all three categories of units

was 3,107 tpy and 1,481 tons per ozone season. TSD at 39. The Agency further states that,

when fully implemented, the proposal will provide NO

emission reductions of 2,155 tpy and

1,017 tons per ozone season.

Cost Effectiveness of Controls

The Agency indicates that USEPA has in its alterative control techniques (ACT)

documents estimated the cost effectiveness of controlling NO

emissions from engines and

turbines. TSD at 27 (§5.0 Cost Effectiveness of Controls). The Agency cites Alternative

Control Techniques Document – NO

Emissions from Stationary Reciprocating Internal

Combustion Engines (EPA-453/R-93-032). TSD at 27;

TSD at 42 (§10.0 References); Fast-

Track Rules Under Nitrogen Oxide (NO

) SIP Call Phase II: Amendments to 35 Ill. Adm. Code

Section 201.146 and Parts 211 and 217, R07-18 (Apr. 6, 2007) (Attachment 11c to original

Agency proposal). The Agency also cites Alternative Control Techniques Document – NO

Emissions from Stationary Gas Turbines (EPA-453/R-93-007). TSD at 27;

TSD at 42 (§10.0

References); Fast-Track Rules Under Nitrogen Oxide (NO

) SIP Call Phase II: Amendments to

35 Ill. Adm. Code Section 201.146 and Parts 211 and 217, R07-18 (Apr. 6, 2007) (Attachment

11d to original Agency proposal). The Agency states that it “relied on these documents to

estimate the cost effectiveness of controlling Illinois NO

emissions [from] sources potentially

affected by this proposed rulemaking.” TSD at 27.

Cost Effectiveness of Controls on Engines

The Agency indicates that USEPA estimates the cost effectiveness of NO

controls by considering total capital costs and total annual costs. TSD at 27 (§5.1), citing

Alternative Control Techniques Document – NO

Emissions from Stationary Reciprocating

Internal Combustion Engines (EPA-453/R-93-032).

The total capital cost is the sum of the purchased equipment costs, direct

installation costs, indirect installation costs, and emergency costs. Annual costs

consist of the direct operating costs of materials and labor for maintenance,

operation, utilities, material replacement and disposal, and indirect operating

charges including plant overhead, general administration, and capital recovery

charges. TSD at 27.

The Agency states that USEPA’s ACT document includes the costs of various NO

The Agency further states that cost effectiveness of each control technique is calculated in

dollars per ton of NO

removed “by dividing the total annual cost by the annual tons of NO

removed” and varies with the type, size, and operating hours of an engine.

USEPA’s ACT document, the Agency reports that available control options achieve the

proposed control levels with cost effectiveness ranging from $163 to $5,961 per ton of NO

removed on an annual basis.

. at 28 (Table 5-1).

With regard to engines, the Agency reports that it also relied upon the reference

document “Stationary Reciprocating Internal Combustion Engines.” TSD at 28;

(§10.0 References), Fast-Track Rules Under Nitrogen Oxide (NO

) SIP Call Phase II:

Amendments to 35 Ill. Adm. Code Section 201.146 and Parts 211 and 217, R07-18 (Apr. 6,

2007) (Attachment 11s to original Agency proposal). This document incorporates information

on LEC from various sources and assesses the cost effectiveness of LEC. TSD at 28. The

Agency states that, “[i]n most respects the analysis was conducted according to the methodology

of the 1993 ACT document.”

. at 28-29. For engines at or above 500 bhp in size and based

upon specific inputs the cost effectiveness on an annual basis ranges from $230 to $1,360 per ton

. at 29 (Table 5-2) (adjusting cost data from 1990 to 2004 dollars). For the

same engines on an ozone season basis, the cost effectiveness ranges from $550 to $3,270 per

Cost Effectiveness of Controls on Turbines

The Agency states that USEPA’s ACT document describes the capital costs and cost

effectiveness of various NO

emission controls for turbines based on 1990 dollars. TSD at 29

(§5.2), citing Alternative Control Techniques Document – NO

Emissions from Stationary Gas

Turbines (EPA-453/R-93-007).

The cost effectiveness of two types of controls for smaller turbines of 3.3 MW

varies from $2,645 per ton of NO

on an annual basis removed for steam injection

to $3,005 per ton of NO

removed for water injection control. For dry low-NO

combustion, cost effectiveness was $1,532 per ton of NO

removed for a four

MW gas-fired turbine. TSD at 29 (adjusting estimates to 2004 dollars).

The Agency reports that, based on USEPA’s ACT document, STAPPA/ALAPCO has estimated

the cost of controlling various sizes of turbines.

., citing Controlling Nitrogen Oxides Under

the Clean Air Act: A Menu of Options (Attachment 11e to original Agency proposal). The

Agency claims that the cost effectiveness of controlling NO

emissions from 5 to 25 MW

turbines operating 8,000 hours annually ranges from $314 to $3,203 per ton of NO

TSD at 29-30 (Table 5-3) (adjusting costs from 1993 to 2004 dollars).

The Agency summarizes by stating that affected sources will comply with Subpart Q by

installing combustion controls. TSD at 30. Rich burn engines will install NSCR and lean burn

engines will install LEC technologies to comply with the regulations.

. Based on these

options, the Agency estimates that controlling sources at proposed levels will result in retrofitting

costs of $319 to $2,575 per ton of NO

reduced for engines and $314 to $3,005 per ton of NO

reduced for turbines in 2004 dollars.

Pipeline Group Comment

In testimony pre-filed for the second hearing, the Pipeline Group raised issues relating

generally to the technical feasibility and economic reasonableness of the Agency’s proposal.

415 ILCS 5/27(a) (2006). On behalf of the Pipeline Group, Mr. McCarthy commented on the

TSD, stating that “[s]everal technologies discussed in the TSD are not proven for application to

natural gas transmission IC [internal combustion] engines and turbines are of limited or no

benefit.” McCarthy Test. at 6. The Board below addresses these comments.

Mr. McCarthy states that, although the TSD lists SCR as a control strategy for both

engines and turbines, “to date, SCR has not been successfully applied to gas transmission units,

and U.S. EPA has acknowledged this situation.” McCarthy Test. at 7. He cites USEPA as

believing that “that there is an insufficient basis to conclude that SCR is an appropriate

technology for large lean-burn engines.”

., citing 67 Fed. Reg. 8395, 8411 (Feb. 22, 2002). He

also cites USEPA as stating that, “[f]or engines which typically operate at variable loads, such as

engines on gas transmission pipelines, an SCR system may not function effectively, causing

either periods of ammonia slip or insufficient ammonia to gain the reductions needed.”

McCarthy Test. at 7 (citing AP-42 document on control of lean-burn engines).

Mr. McCarthy states that SCR has not been successfully demonstrated on retrofit units at

natural gas compressor stations. McCarthy Test. at 7. Although the technology was installed on

a turbine in California, he claims that the installation “resulted in significant site-specific re-

engineering that has resulted in exorbitant costs and a relaxation of the initial emission limits.”

. He also states that SCR has been installed on new engines at a compressor station in the

eastern United States, although the station has limited operation during periods of high gas

. Mr. McCarthy acknowledges that “SCR is marketed for application to IC engines.”

However, he argues that, “based on the U.S. EPA record and very limited industry

experience, SCR is not a demonstrated technology for retrofit application to IC engines or

turbines in gas transmission.”

Mr. McCarthy also notes that the TSD lists water or steam injection as a NO

strategy. McCarthy Test. at 8. He characterizes that technology as “ a ‘first generation’ retrofit

control that introduces operational, efficiency, and emissions challenges.”

states that water or steam injection has not been used in any gas transmissions turbines and that

the strategy has been “supplanted by DLN technology.”

. In addition, Mr. McCarthy claims

that ignition timing retard has only questionable applicability to natural gas-fired engines and

that it “may not provide meaningful emission reduction.”

. Finally, he argues that “the

commercial availability and performance of prestratified charge technology are questionable.”

PARTICIPANTS’ POSITIONS ON AMENDED PROPOSAL

In the course of this proceeding, participants including the Pipeline Group, IMEA, and

IERG voiced no significant objection to the Agency’s amended proposal. Mr. McCarthy stated

in his prefiled testimony that “[t]he Pipeline Group does not object to the IEPA Subpart Q

proposal under consideration at today’s hearing.” McCarthy Test. at 6;

Tr.2 at 10-11. He

elaborated that “the Pipeline Group has worked with IEPA to integrate compliance options that

provide compliance flexibility and address some of the unique technology and operating

attributes and limitation of the natural gas transmission sector.”

In her testimony on behalf of IMEA and IERG, Ms. Driver stated that

we have not talked about, nor challenged, the level of the emission limits in the

proposed rule, the control technology that the Agency has focused on for getting

to those limits, or the costs of those controls, and the reason is because for the

most part we feel that our membership in both organizations will be able to find

an approach in the rule that works for them as long as those approaches remain as

proposed. Tr.1 at 43.

In its post-hearing comments, IMEA emphasized that it had not challenged the approach taken

by the Agency in its proposal, “either in term of applicability, control requirements or projected

compliance costs.” PC 2 at 7. IMEA stated that it based this position “solely on the ability of its

members to comply with the Proposed Rule via Sections 217.388(c) [low usage] and 217.392(c)

allowances].”

. IMEA recommended that the Board retain these provisions in

proceeding to First Notice.

In its post-hearing comments, IERG stated that its most significant concerns with the

proposed rule had ultimately been addressed in the course of working with the Agency. PC 3 at

1. IERG questioned whether the Agency had identified all units that may be affected by the

requirements of the proposed rule and whether the Agency had accurately represented the

technical feasibility and economic reasonableness of that proposal. PC 3 at 8. Nonetheless,

IERG stated that it

believes that the Proposed Rule, as currently situated, provides the necessary

flexibility of compliance options, including the ability to utilize NO

for the diversity of covered units and operating needs for those units. These

components of the Proposed Rule are vitally important, as is the current approach

for applicability to major source of NO

emissions in the ozone and PM

nonattainment areas.

Board Findings

The Board finds the proposed amendments technically feasible and economically

reasonable. The Board adopts the Agency’s amended proposal, as amended by the clarifications

sheet submitted by the Agency at the second hearing as Exhibit 2. In addition, the

Board makes additional technical corrections necessary to keep the rule language consistent with

regulatory language typically reviewed by the Joint Committee on Administrative Rules and

adopted by the Board.

The Board proposes for first notice amendments to the Board’s regulations governing

emissions of NO

in Parts 201, 211, and 217 (35 Ill. Adm. Code 201, 211, 217). Substantively,

the Board is adopting the Agency’s amended proposal, including changes reflected in the

clarifications and

sheet submitted by the Agency at the second hearing.

Publication of the proposed amendment in the

Illinois Register

will start a period of at

least 45 days during which any person may file public comments with the Clerk of the Board at

the address provided above at page 3 of this opinion. As noted above, persons may also file

comments electronically through COOL at www.ipcb.state.il.us.

The Board directs the Clerk to cause publication of the following proposed amendments

Illinois Register

for first notice. Proposed additions to Parts 201, 211, and 217 are

underlined, and proposed deletions appear stricken.

TITLE 35: ENVIRONMENTAL PROTECTION

SUBTITLE B: AIR POLLUTION

CHAPTER I: POLLUTION CONTROL BOARD

SUBCHAPTER a: PERMITS AND GENERAL PROVISIONS

PERMITS AND GENERAL PROVISIONS

SUBPART A: DEFINITIONS

Other Definitions

Abbreviations and Units

Incorporations by Reference

SUBPART B: GENERAL PROVISIONS

Existence of Permit No Defense

Proof of Emissions

Burden of Persuasion Regarding Exceptions

SUBPART C: PROHIBITIONS

Prohibition of Air Pollution

Construction Permit Required

Operating Permits for New Sources

Operating Permits for Existing Sources

Exemptions from State Permit Requirements

Operation Without Compliance Program and Project Completion Schedule

Operation During Malfunction, Breakdown or Startups

Design of Effluent Exhaust Systems

SUBPART D: PERMIT APPLICATIONS AND REVIEW PROCESS

Contents of Application for Construction Permit

Incomplete Applications (Repealed)

Signatures (Repealed)

Standards for Issuance (Repealed)

Contents of Application for Operating Permit

Incomplete Applications

Standards for Issuance

Joint Construction and Operating Permits

Design Criteria

Revisions to Permits

Appeals from Conditions

Special Provisions for Certain Operating Permits

Portable Emission Units

SUBPART E: SPECIAL PROVISIONS FOR OPERATING PERMITS FOR CERTAIN

SMALLER SOURCES

Applicability (Repealed)

Expiration and Renewal (Repealed)

Requirement for a Revised Permit (Repealed)

SUBPART F: CAAPP PERMITS

Supplemental Information

Emissions of Hazardous Air Pollutants

Categories of Insignificant Activities or Emission Levels

Application for Classification as an Insignificant Activity

Revisions to Lists of Insignificant Activities or Emission Levels

SUBPART G: EXPERIMENTAL PERMITS (Reserved)

SUBPART H: COMPLIANCE PROGRAMS AND

PROJECT COMPLETION SCHEDULES

Contents of Compliance Program

Contents of Project Completion Schedule

Standards for Approval

Effects of Approval

Records and Reports

Submission and Approval Dates

SUBPART I: MALFUNCTIONS, BREAKDOWNS OR STARTUPS

Contents of Request for Permission to Operate During a Malfunction, Breakdown

Standards for Granting Permission to Operate During a Malfunction, Breakdown

Records and Reports

Continued Operation or Startup Prior to Granting of Operating Permit

Effect of Granting of Permission to Operate During a Malfunction, Breakdown or

SUBPART J: MONITORING AND TESTING

Permit Monitoring Equipment Requirements

Records and Reports

SUBPART K: RECORDS AND REPORTS

SUBPART L: CONTINUOUS MONITORING

Continuous Monitoring Requirements

Alternative Monitoring

Monitoring System Malfunction

Excess Emission Reporting

Retention of Information

Compliance Schedules

Rule into Section Table

Section into Rule Table

Past Compliance Dates

AUTHORITY: Implementing Sections 10, 39, and 39.5 and authorized by Sections 27 and 28.5

of the Environmental Protection Act [415 ILCS 5/10, 27, 28.5, 39, and 39.5].

SOURCE: Adopted as Chapter 2: Air Pollution, Part I: General Provisions, in R71-23, 4 PCB

191, filed and effective April 14, 1972; 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. 13579; amended in R82-1 (Docket A) at 10 Ill. Reg. 12628,

effective July 7, 1986; amended in R87-38 at 13 Ill. Reg. 2066, effective February 3, 1989;

amended in R89-7(A) at 13 Ill. Reg. 19444, effective December 5, 1989; amended in R89-7(B)

at 15 Ill. Reg. 17710, effective November 26, 1991; amended in R93-11 at 17 Ill. Reg. 21483,

effective December 7, 1993; amended in R94-12 at 18 Ill. Reg. 15002, effective September 21,

1994; amended in R94-14 at 18 Ill. Reg. 15760, effective October 17, 1994; amended in R96-17

at 21 Ill. Reg. 7878, effective June 17, 1997; amended in R98-13 at 22 Ill. Reg. 11451, effective

June 23, 1998; amended in R98-28 at 22 Ill. Reg. 11823, effective July 31, 1998; amended in

R02-10 at 27 Ill. Reg. 5820, effective March 21, 2003; amended in R05-19 and R05-20 at 30 Ill.

Reg. 4901, effective March 3, 2006; amended in R07-19 at 32 Ill. Reg. ______________,

effective _______________.

SUBPART C: PROHIBITIONS

Section 201.146

Exemptions from State Permit Requirements

Construction or operating permits, pursuant to Sections 201.142, 201.143 and 201.144 of this

Part, are not required for the classes of equipment and activities listed below in this Section. The

permitting exemptions in this Section do not relieve the owner or operator of any source from

any obligation to comply with any other applicable requirements, including the obligation to

obtain a permit pursuant to Sections 9.1(d) and 39.5 of the Act, Sections 165, 173 and 502 of the

Clean Air Act or any other applicable permit or registration requirements.

Air contaminant detectors or recorders, combustion controllers or combustion

Air conditioning or ventilating equipment not designed to remove air

contaminants generated by or released from associated equipment;

Each fuel burning emission unit for indirect systems and for heating and reheating

furnace systems used exclusively for residential, or commercial establishments

using gas and/or fuel oil exclusively with a design heat input capacity of less than

14.6 MW (50 mmbtu/hr), except that a permit shall be required for any such

emission unit with a design heat input capacity of at least 10 mmbtu/hr that was

constructed, reconstructed or modified after June 9, 1989 and that is subject to 40

CFR 60, Subpart D;

Each fuel burning emission unit other than those listed in subsection (c) of this

Section for direct systems used for comfort heating purposes and indirect heating

systems with a design heat input capacity of less than 2930 kW (10 mmbtu/hr);

Internal combustion engines or boilers (including the fuel system) of motor

vehicles, locomotives, air craft, watercraft, lifttrucks and other vehicles powered

by nonroad engines;

Bench scale laboratory equipment and laboratory equipment used exclusively for

chemical and physical analysis, including associated laboratory fume hoods,

vacuum producing devices and control devices installed primarily to address

potential accidental releases;

Coating operations located at a source using not in excess of 18,925 l (5,000 gal)

of coating (including thinner) per year;

Any emission unit acquired exclusively for domestic use, except that a permit

shall be required for any incinerator and for any fuel combustion emission unit

using solid fuel with a design heat input capacity of 14.6 MW (50 mmbtu/hr) or

Any stationary internal combustion engine with a rated power output of less than

1118 kW (1500 bhphorsepower) or stationary turbine, except that a permit shall

be required for the following:

Any internal combustion engine with a rating at equal to or greater than

500 bhp output that is subject to the control requirements of 35 Ill. Adm.

Code Part 217.388(a) or (b); or

Anyany stationary gas turbine engine with a rated heat input at peak load

of 10.7 gigajoules/hr (10 mmbtu/hr) or more that is constructed,

reconstructed or modified after October 3, 1977 and that is subject to

requirements of 40 CFR 60, Subpart GG;

Rest room facilities and associated cleanup operations, and stacks or vents used to

prevent the escape of sewer gases through plumbing traps;

Safety devices designed to protect life and limb, provided that a permit is not

otherwise required for the emission unit with which the safety device is

Storage tanks for liquids for retail dispensing except for storage tanks that are

subject to the requirements of 35 Ill. Adm. Code 215.583(a)(2), 218.583(a)(2) or

Printing operations with aggregate organic solvent usage that never exceeds 2,839

l (750 gal) per year from all printing lines at the source, including organic solvent

from inks, dilutents, fountain solutions and cleaning materials;

Storage tanks of:

Organic liquids with a capacity of less than 37,850 l (10,000 gal),

provided the storage tank is not used to store any material listed as a

hazardous air pollutant pursuant to Section 112(b) of the Clean Air Act,

and provided the storage tank is not subject to the requirements of 35 Ill.

Adm. Code 215.583(a)(2), 218.583(a)(2) or 219.583(a)(2);

Any size containing exclusively soaps, detergents, surfactants, waxes,

glycerin, vegetable oils, greases, animal fats, sweetener, corn syrup,

aqueous salt solutions or aqueous caustic solutions, provided an organic

solvent has not been mixed with such materials; or

Any size containing virgin or re-refined distillate oil, hydrocarbon

condensate from natural gas pipeline or storage systems, lubricating oil or

residual fuel oils;

Threaded pipe connections, vessel manways, flanges, valves, pump seals, pressure

relief valves, pressure relief devices and pumps;

Sampling connections used exclusively to withdraw materials for testing and

All storage tanks of Illinois crude oil with capacity of less than 151,400 l (40,000

gal) located on oil field sites;

All organic material-water single or multiple compartment effluent water

separator facilities for Illinois crude oil of vapor pressure of less than 34.5 kPa

absolute (5 psia);

Grain-handling operations, exclusive of grain-drying operations, with an annual

grain through-put not exceeding 300,000 bushels;

Grain-drying operations with a total grain-drying capacity not exceeding 750

bushels per hour for 5% moisture extraction at manufacturer's rated capacity,

using the American Society of Agricultural Engineers Standard 248.2, Section 9,

Basis for Stating Drying Capacity of Batch and Continuous-Flow Grain Dryers;

Portable grain-handling equipment and one-turn storage space;

Cold cleaning degreasers that are not in-line cleaning machines, where the vapor

pressure of the solvents used never exceeds 2 kPa (15 mmHg or 0.3 psi) measured

at 38°C (100°F) or 0.7 kPa (5 mmHg or 0.1 psi) at 20°C (68°F);

Coin-operated dry cleaning operations;

Dry cleaning operations at a source that consume less than 30 gallons per month

of perchloroethylene;

Brazing, soldering, wave soldering or welding equipment, including associated

ventilation hoods;

Cafeterias, kitchens, and other similar facilities, including smokehouses, used for

preparing food or beverages, but not including facilities used in the manufacturing

and wholesale distribution of food, beverages, food or beverage products, or food

or beverage components;

Equipment for carving, cutting, routing, turning, drilling, machining, sawing,

surface grinding, sanding, planing, buffing, sand blast cleaning, shot blasting, shot

peening, or polishing ceramic artwork, leather, metals (other than beryllium),

plastics, concrete, rubber, paper stock, wood or wood products, where such

equipment is either:

Used for maintenance activity;

Manually operated;

Exhausted inside a building; or

Vented externally with emissions controlled by an appropriately operated

cyclonic inertial separator (cyclone), filter, electro-static precipitor or a

Feed mills that produce no more than 10,000 tons of feed per calendar year,

provided that a permit is not otherwise required for the source pursuant to Section

201.142, 201.143 or 201.144;

Extruders used for the extrusion of metals, minerals, plastics, rubber or wood,

Extruders used in the manufacture of polymers;

Extruders using foaming agents or release agents that contain volatile

organic materials or Class I or II substances subject to the requirements of

Title VI of the Clean Air Act; and

Extruders processing scrap material that was produced using foaming

agents containing volatile organic materials or Class I or II substances

subject to the requirements of Title VI of the Clean Air Act;

Furnaces used for melting metals, other than beryllium, with a brim full capacity

of less than 450 cubic inches by volume;

Equipment used for the melting or application of less than 22,767 kg/yr (50,000

lbs/yr) of wax to which no organic solvent has been added;

Equipment used for filling drums, pails or other packaging containers, excluding

aerosol cans, with soaps, detergents, surfactants, lubricating oils, waxes, vegetable

oils, greases, animal fats, glycerin, sweeteners, corn syrup, aqueous salt solutions

or aqueous caustic solutions, provided an organic solvent has not been mixed with

such materials;

Loading and unloading systems for railcars, tank trucks, or watercraft that handle

only the following liquid materials: soaps, detergents, surfactants, lubricating oils,

waxes, glycerin, vegetable oils, greases, animal fats, sweetener, corn syrup,

aqueous salt solutions or aqueous caustic solutions, provided an organic solvent

has not been mixed with such materials;

Equipment used for the mixing and blending of materials at ambient temperatures

to make water based adhesives, provided each material mixed or blended contains

less than 5% organic solvent by weight;

Die casting machines where a metal or plastic is formed under pressure in a die

located at a source with a through-put of less than 2,000,000 lbs of metal or

plastic per year, in the aggregate, from all die casting machines;

Air pollution control devices used exclusively with other equipment that is

exempt from permitting, as provided in this Section;

An emission unit for which a registration system designed to identify sources and

emission units subject to emission control requirements is in place, such as the

registration system found at 35 Ill. Adm. Code 218.586 (Gasoline Dispensing

Operations - Motor Vehicle Fueling Operations) and 35 Ill. Adm. Code 218,

Subpart HH (Motor Vehicle Refinishing);

Photographic process equipment by which an image is reproduced upon material

sensitized to radiant energy;

mm) Equipment used for hydraulic or hydrostatic testing;

General vehicle maintenance and servicing activities conducted at a source, motor

vehicle repair shops, and motor vehicle body shops, but not including:

Gasoline fuel handling; and

Motor vehicle refinishing;.

Equipment using water, water and soap or detergent, or a suspension of abrasives

in water for purposes of cleaning or finishing, provided no organic solvent has

been added to the water;

Administrative activities including, but not limited to, paper shredding, copying,

photographic activities and blueprinting machines. This does not include

Laundry dryers, extractors, and tumblers processing that have been cleaned with

water solutions of bleach or detergents that are:

Located at a source and process clothing, bedding and other fabric items

used at the source, provided that any organic solvent present in such items

before processing that is retained from cleanup operations shall be

addressed as part of the VOM emissions from use of cleaning materials;

Located at a commercial laundry; or

Housekeeping activities for cleaning purposes, including collecting spilled and

accumulated materials, including operation of fixed vacuum cleaning systems

specifically for such purposes, but not including use of cleaning materials that

contain organic solvent;

Refrigeration systems, including storage tanks used in refrigeration systems, but

excluding any combustion equipment associated with such systems;

Activities associated with the construction, on-site repair, maintenance or

dismantlement of buildings, utility lines, pipelines, wells, excavations, earthworks

and other structures that do not constitute emission units;

Piping and storage systems for natural gas, propane and liquefied petroleum gas;

Water treatment or storage systems, as follows:

Systems for potable water or boiler feedwater;

Systems, including cooling towers, for process water, provided that such

water has not been in direct or indirect contact with process streams that

contain volatile organic material or materials listed as hazardous air

pollutants pursuant to Section 112(b) of the Clean Air Act;.

ww) Lawn care, landscape maintenance and grounds keeping activities;

Containers, reservoirs or tanks used exclusively in dipping operations to coat

objects with oils, waxes or greases, provided no organic solvent has been mixed

with such materials;

Use of consumer products, including hazardous substances as that term is defined

in the Federal Hazardous Substances Act (15 USC U.S.C

. 1261 et seq.), where the

product is used at a source in the same manner as normal consumer use;

Activities directly used in the diagnosis and treatment of disease, injury or other

medical condition;

Activities associated with the construction, repair or maintenance of roads or

other paved or open areas, including operation of street sweepers, vacuum trucks,

spray trucks and other vehicles related to the control of fugitive emissions of such

roads or other areas;

bbb) Storage and handling of drums or other transportable containers, where the

containers are sealed during storage and handling;

Activities at a source associated with the maintenance, repair or dismantlement of

an emission unit or other equipment installed at the source, not including the

shutdown of the unit or equipment, including preparation for maintenance, repair

or dismantlement, and preparation for subsequent startup, including preparation of

a shutdown vessel for entry, replacement of insulation, welding and cutting, and

steam purging of a vessel prior to startup;

ddd) Equipment used for corona arc discharge surface treatment of plastic with a power

rating of 5 kW or less or equipped with an ozone destruction device;

Equipment used to seal or cut plastic bags for commercial, industrial or domestic

Each direct-fired gas dryer used for a washing, cleaning, coating or printing line,

Dryers with a rated heat input capacity of 2930 kW (10 mmbtu/hr) or

Dryers for which emissions other than those attributable to combustion of

fuel in the dryer, including emissions attributable to use or application of

cleaning agents, washing materials, coatings or inks or other process

materials that contain volatile organic material are not addressed as part of

the permitting of such line, if a permit is otherwise required for the line;

ggg) Municipal solid waste landfills with a maximum total design capacity of less than

2.5 million Mg or 2.5 million m

that are not required to install a gas collection

and control system pursuant to 35 Ill. Adm. Code 220 or 800 through 849 or

Section 9.1 of the Act; and

hhh) Replacement or addition of air pollution control equipment for existing emission

units in circumstances where:

The existing emission unit is permitted and has operated in compliance for

The new control equipment will provide equal or better control of the

target pollutants;

The new control device will not be accompanied by a net increase in

emissions of any non-targeted criteria air pollutant;

Different State or federal regulatory requirements or newly proposed

regulatory requirements will not apply to the unit; and

BOARD NOTE: All sources must comply with underlying federal

regulations and future State regulations.

Where the existing air pollution control equipment had required

monitoring equipment, the new air pollution control equipment will be

equipped with the instrumentation and monitoring devices that are

typically installed on the new equipment of that type.

BOARD NOTE: For major sources subject to Section 39.5 of the Act,

where the new air pollution control equipment will require a different

compliance determination method in the facility’s CAAPP permit, the

facility may need a permit modification to address the changed

compliance determination method;

Replacement, addition, or modification of emission units at facilities with

federally enforceable State operating permits limiting their potential to emit in

circumstances where:

The potential to emit any regulated air pollutant in the absence of air

pollution control equipment from the new emission unit, or the increase in

the potential to emit resulting from the modification of any existing

emission unit, is less than 0.1 pound per hour or 0.44 tons per year;

The raw materials and fuels used or present in the emission unit that cause

or contribute to emissions, based on the information contained in Material

Safety Data Sheets for those materials, do not contain equal to or greater

than 0.01 percent by weight of any hazardous air pollutant as defined

under Section 112(b) of the federal Clean Air Act;

The emission unit or modification is not subject to an emission standard or

other regulatory requirement pursuant to Section 111 of the federal Clean

Potential emissions of regulated air pollutants from the emission unit or

modification will not, in combination with emissions from existing units

or other proposed units, trigger permitting requirements under Section

39.5, permitting requirements under Section 165 or 173 of the federal

Clean Air Act, or the requirement to obtain a revised federally enforceable

State operating permit limiting the source’s potential to emit; and

The source is not currently the subject of a Non-compliance Advisory,

Clean Air Act Section 114 Request, Violation Notice, Notice of Violation,

Compliance Commitment Agreement, Administrative Order, or civil or

criminal enforcement action, related to the air emissions of the source;.

Replacement, addition, or modification of emission units at permitted sources that

are not major sources subject to Section 39.5 and that do not have a federally

enforceable state operating permit limiting their potential to emit, in

circumstances where:

The potential to emit of any regulated air pollutant in the absence of air

pollution control equipment from the new emission unit, or the increase in

the potential to emit resulting from the modification of any existing

emission unit is either:

Less than 0.1 pound per hour or 0.44 tons per year; or

Less than 0.5 pound per hour, and the permittee provides prior

notification to the Agency of the intent to construct or install the

unit. The unit may be constructed, installed or modified

immediately after the notification is filed;

The emission unit or modification is not subject to an emission standard or

other regulatory requirement under Section 111 or 112 of the federal

Potential emissions of regulated air pollutants from the emission unit or

modification will not, in combination with the emissions from existing

units or other proposed units, trigger permitting requirements under

Section 39.5 or the requirement to obtain a federally enforceable permit

limiting the source’s potential to emit; and

The source is not currently the subject of a Non-compliance Advisory,

Clean Air Act Section 114 Request, Violation Notice, Notice of Violation,

Compliance Commitment Agreement, Administrative Order, or civil or

criminal enforcement action, related to the air emissions of the source;.

kkk) The owner or operator of a CAAPP source is not required to obtain an air

pollution control construction permit for the construction or modification of an

emission unit or activity that is an insignificant activity as addressed by Section

201.210 or 201.211 of this Part. Section 201.212 of this Part must still be

followed, as applicable. Other than excusing the owner or operator of a CAAPP

source from the requirement to obtain an air pollution control construction permit

for the emission units or activities, nothing in this subsection shall alter or affect

the liability of the CAAPP source for compliance with emission standards and

other requirements that apply to the emission units or activities, either

individually or in conjunction with other emission units or activities constructed,

modified or located at the source;.

Plastic injection molding equipment with an annual through-put not exceeding

5,000 tons of plastic resin in the aggregate from all plastic injection molding

equipment at the source, and all associated plastic resin loading, unloading,

conveying, mixing, storage, grinding, and drying equipment and associated mold

release and mold cleaning agents.

(Source: Amended at 32 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

DEFINITIONS AND GENERAL PROVISIONS

SUBPART A: GENERAL PROVISIONS

Incorporations by Reference

Abbreviations and Conversion Factors

SUBPART B: DEFINITIONS

Other Definitions

Definitions (Repealed)

Actual Heat Input

Adhesion Promoter

Aerosol Can Filling Line

Air Contaminant

Air Dried Coatings

Air Oxidation Process

Air Pollution Control Equipment

Air Suspension Coater/Dryer

Air Assisted Airless Spray

Animal Pathological Waste

Annual Grain Through-Put

Anti-Glare/Safety Coating

Application Area

Architectural Coating

As-Applied Fountain Solution

Asphalt Prime Coat

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

Truck Manufacturing Plant

Automobile or Light-Duty Truck Refinishing

Automotive/Transportation Plastic Parts

Basecoat/Clearcoat System

Batch Operation

Batch Process Train

Brakehorsepower (rated-bhp)

British Thermal Unit

Brush or Wipe Coating

Bulk Gasoline Plant

Bulk Gasoline Terminal

Business Machine Plastic Parts

Can Coating Line

Capture Efficiency

Carbon Adsorber

Certified Investigation

Chemical Manufacturing Process Unit

Cleaning and Separating Operation

Cleaning Materials

Closed Purge System

Closed Vent System

Coating Applicator

Coil Coating Line

Combined Cycle System

Combustion Turbine

Commence Commercial Operation

Commence Operation

Complete Combustion

Concrete Curing Compounds

Concentrated Nitric Acid Manufacturing Process

Condensible PM-10

Continuous Automatic Stoking

Continuous Coater

Continuous Process

Control Device Efficiency

Conventional Air Spray

Conventional Soybean Crushing Source

Conveyorized Degreasing

Crude Oil Gathering

Custody Transfer

Cutback Asphalt

Daily-Weighted Average VOM Content

Delivery Vessel

Distillate Fuel Oil

Distillation Unit

Dry Cleaning Operation or Dry Cleaning Facility

Effective Grate Area

Effluent Water Separator

Elastomeric Materials

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

Electronic Component

Electrostatic Bell or Disc Spray

Electrostatic Prep Coat

Electrostatic Spray

Emergency or Standby Unit

End Sealing Compound Coat

Enhanced Under-the-Cup Fill

Ethanol Blend Gasoline

Excess Emissions

Excessive Release

Existing Grain-Drying Operation (Repealed)

Existing Grain-Handling Operation (Repealed)

Exterior Base Coat

Exterior End Coat

External Floating Roof

Extreme Performance Coating

Fabric Coating Line

Federally Enforceable Limitations and Conditions

Fermentation Time

Final Repair Coat

Fixed-Roof Tank

Flexible Coating

Flexible Operation Unit

Flexographic Printing

Flexographic Printing Line

Fossil Fuel-Fired

Fountain Solution

Freeboard Height

Fuel Combustion Emission Unit or Fuel Combustion Emission Source

Fugitive Particulate Matter

Full Operating Flowrate

Gasoline Dispensing Operation or Gasoline Dispensing Facility

Grain-Drying Operation

Grain-Handling and Conditioning Operation

Grain-Handling Operation

Green-Tire Spraying

Gross Heating Value

Gross Vehicle Weight Rating

Heated Airless Spray

Heat Input Rate

Heatset Web Offset Lithographic Printing Line

Heavy Off-Highway Vehicle Products

Heavy Off-Highway Vehicle Products Coating

Heavy Off-Highway Vehicle Products Coating Line

High Temperature Aluminum Coating

High Volume Low Pressure (HVLP) Spray

Housekeeping Practices

Indirect Heat Transfer

In-Process Tank

In-Situ Sampling Systems

Interior Body Spray Coat

Internal-Floating Roof

Internal Transferring Area

Large Appliance

Large Appliance Coating

Large Appliance Coating Line

Lean-Burn Engine

Light-Duty Truck

Liquid/Gas Method

Liquid-Mounted Seal

Liquids Dripping

Lithographic Printing Line

Low Solvent Coating

Lubricating Oil

Magnet Wire Coating

Magnet Wire Coating Line

Major Metropolitan Area (MMA)

Major Population Area (MPA)

Manually Operated Equipment

Manufacturing Process

Marine Terminal

Material Recovery Section

Maximum Theoretical Emissions

Maximum True Vapor Pressure

Metal Furniture

Metal Furniture Coating

Metal Furniture Coating Line

Metallic Shoe-Type Seal

Mid-Kiln Firing

Miscellaneous Fabricated Product Manufacturing Process

Miscellaneous Formulation Manufacturing Process

Miscellaneous Metal Parts and Products

Miscellaneous Metal Parts and Products Coating

Miscellaneous Metal Parts or Products Coating Line

Miscellaneous Organic Chemical Manufacturing Process

Mixing Operation

Mobile Equipment

Motor Vehicle Refinishing

Multiple Package Coating

Nameplate Capacity

New Grain-Drying Operation (Repealed)

New Grain-Handling Operation (Repealed)

No Detectable Volatile Organic Material Emissions

Non-Contact Process Water Cooling Tower

Non-Flexible Coating

NOx Trading Program

One Hundred Percent Acid

One-Turn Storage Space

Open Top Vapor Degreasing

Open-Ended Valve

Operator of a Gasoline Dispensing Operation or Operator of a Gasoline

Dispensing Facility

Organic Compound

Organic Material and Organic Materials

Organic Solvent

Overall Control

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

Owner or Operator

Packaging Rotogravure Printing

Packaging Rotogravure Printing Line

Paint Manufacturing Source or Paint Manufacturing Plant

Paper Coating Line

Particulate Matter

Parts Per Million (Volume) or PPM (Vol)

Petroleum Liquid

Petroleum Refinery

Pharmaceutical Coating Operation

Photochemically Reactive Material

Pigmented Coatings

Pneumatic Rubber Tire Manufacture

Polybasic Organic Acid Partial Oxidation Manufacturing Process

Polyester Resin Material(s)

Polyester Resin Products Manufacturing Process

Polystyrene Plant

Polystyrene Resin

Portable Grain-Handling Equipment

Portland Cement Manufacturing Process Emission Source

Portland Cement Process or Portland Cement Manufacturing Plant

Potential Electrical Output Capacity

Potential to Emit

Power Driven Fastener Coating

Preheater/Precalciner Kiln

Pressure Release

Pressure/Vacuum Relief Valve

Pretreatment Wash Primer

Primary Product

Primer Surfacer Coat

Primer Surfacer Operation

Process Emission Source

Process Emission Unit

Process Unit Shutdown

Process Weight Rate

Production Equipment Exhaust System

Publication Rotogravure Printing Line

Purged Process Fluid

Rated Heat Input Capacity

Reasonably Available Control Technology (RACT)

Reclamation System

Refinery Fuel Gas

Refinery Fuel Gas System

Refinery Unit or Refinery Process Unit

Reflective Argent Coating

Refrigerated Condenser

Regulated Air Pollutant

Reid Vapor Pressure

Residual Fuel Oil

Restricted Area

Rich-Burn Engine

Ringelmann Chart

Rotogravure Printing

Rotogravure Printing Line

Safety Relief Valve

Sanding Sealers

Screen Printing on Paper

Semi-Transparent Stains

Set of Safety Relief Valves

Side-Seam Spray Coat

Single Unit Operation

Smokeless Flare

Solvent Cleaning

Solvent Recovery System

Specialty Coatings

Specialty Coatings for Motor Vehicles

Specialty High Gloss Catalyzed Coating

Specialty Leather

Specialty Soybean Crushing Source

Standard Conditions

Standard Cubic Foot (scf)

Stationary Emission Source

Stationary Emission Unit

Stationary Gas Turbine

Stationary Reciprocating Internal Combustion Engine

Stationary Source

Stationary Storage Tank

Storage Tank or Storage Vessel

Strippable Spray Booth Coating

Styrene Devolatilizer Unit

Styrene Recovery Unit

Submerged Loading Pipe

Sulfuric Acid Mist

Surface Condenser

Surface Preparation Materials

Synthetic Organic Chemical or Polymer Manufacturing Plant

Tablet Coating Operation

Thirty-Day Rolling Average

Three-Piece Can

Three or Four Stage Coating System

Through-the-Valve Fill

Topcoat Operation

Touch-Up Coating

Transfer Efficiency

Tread End Cementing

True Vapor Pressure

Under-the-Cup Fill

Undertread Cementing

Uniform Finish Blender

Unregulated Safety Relief Valve

Vacuum Metallizing

Vacuum Producing System

Valves Not Externally Regulated

Vapor Balance System

Vapor Collection System

Vapor Control System

Vapor-Mounted Primary Seal

Vapor Recovery System

Vapor-Suppressed Polyester Resin

Vinyl Coating Line

Volatile Organic Liquid (VOL)

Volatile Organic Material Content (VOMC)

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

Volatile Petroleum Liquid

Washoff Operations

Wastewater (Oil/Water) Separator

Weak Nitric Acid Manufacturing Process

Wholesale Purchase - Consumer

Wood Furniture Coating

Wood Furniture Coating Line

Yeast Percentage

Rule into Section Table

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 R01-9 at 25 Ill. Reg. 108, effective December

26, 2000; amended in R01-11 at 25 Ill. Reg. 4582, effective March 15, 2001; amended in R01-17

at 25 Ill. Reg. 5900, effective April 17, 2001; amended in R05-16 at 29 Ill. Reg. 8181, effective

May 23, 2005; amended in R05-11 at 29 Ill. Reg.8892, effective June 13, 2005; amended in R04-

12/20 at 30 Ill. Reg. 9654, effective May 15, 2006; amended in R07-18 at 31 Ill. Reg. 14271,

effective September 25, 2007; amended in R07-19 at 32 Ill. Reg. ______________, effective

_______________..

SUBPART B: DEFINITIONS

Section 211.1920

Emergency or Standby Unit

“Emergency or Standby Unit” means, for a stationary gas turbine or a stationary reciprocating

internal combustion engine, a unit that:

Supplies power for the source at which it is located but operates only when the

normal supply of power has been rendered unavailable by circumstances beyond

the control of the owner or operator of the source and only as necessary to assure

the availability of the engine or turbine. An emergency or standby unit may not

be operated to supplement a primary power source when the load capacity or

rating of the primary power source has been reached or exceeded.

Operates exclusively for firefighting or flood control or both.

Operates in response to and during the existence of any officially declared disaster

or state of emergency.

Operates for the purpose of testing, repair or routine maintenance to verify its

readiness for emergency or standby use.

Notwithstanding any other subsection in this Section, emergency or standby units

may operate an additional 50 hours per year in non-emergency situations.

The term does not include equipment used for purposes other than emergencies, as

described above, such as to supply power during high electric demand days.

(Source: Amended at 32 Ill. Reg.,

TITLE 35: ENVIRONMENTAL PROTECTION

SUBTITLE B: AIR POLLUTION

CHAPTER I: POLLUTION CONTROL BOARD

SUBCHAPTER C: EMISSION STANDARDS AND LIMITATIONS

FOR STATIONARY SOURCES

NITROGEN OXIDES EMISSIONS

SUBPART A: GENERAL PROVISIONS

Scope and Organization

Measurement Methods

Abbreviations and Units

Incorporations by Reference

SUBPART B: NEW FUEL COMBUSTION EMISSION SOURCES

New Emission Sources

SUBPART C: EXISTING FUEL COMBUSTION EMISSION SOURCES

Existing Emission Sources in Major Metropolitan Areas

SUBPART K: PROCESS EMISSION SOURCES

Industrial Processes

SUBPART O: CHEMICAL MANUFACTURE

Nitric Acid Manufacturing Processes

SUBPART Q: STATIONARY RECIPROCATING INTERNAL COMBUSTION

ENGINES AND TURBINES

Control and Maintenance Requirements

Emissions Averaging Plans

Testing and Monitoring

Recordkeeping and Reporting

SUBPART T: CEMENT KILNS

Control Requirements

SUBPART U: NOx CONTROL AND TRADING PROGRAM FOR

SPECIFIED NOx GENERATING UNITS

Compliance Requirements

Permitting Requirements

Subpart U NOx Trading Budget

Methodology for Obtaining NOx Allocations

Methodology for Determining NOx Allowances from the New Source Set-Aside

NOx Allocations Procedure for Subpart U Budget Units

New Source Set-Asides for “New” Budget Units

Early Reduction Credits (ERCs) for Budget Units

Low-Emitter Requirements

Opt-In Budget Units: Withdrawal from NOx Trading Program

Opt-In Units: Change in Regulatory Status

Allowance Allocations to Opt-In Budget Units

SUBPART V: ELECTRIC POWER GENERATION

Lake of Egypt Power Plant

Emission Limitations

Reporting and Recordkeeping

SUBPART W: NOx TRADING PROGRAM FOR ELECTRICAL

GENERATING UNITS

Compliance Requirements

Permitting Requirements

NOx Trading Budget

Methodology for Calculating NOx Allocations for Budget Electrical

Generating Units (EGUs)

NOx Allocations for Budget EGUs

New Source Set-Asides for “New” Budget EGUs

Early Reduction Credits for Budget EGUs

Budget Opt-In Units: Withdrawal from NOx Trading Program

Opt-In Units: Change in Regulatory Status

Allowance Allocations to Budget Opt-In Units

SUBPART X: VOLUNTARY NOx EMISSIONS REDUCTION PROGRAM

Emission Unit Eligibility

Participation Requirements

NOx Emission Reductions and the Subpart X NOx Trading Budget

Baseline Emissions Determination

Calculation of Creditable NOx Emission Reductions

Limitations on NOx Emission Reductions

NOx Emission Reduction Proposal

Emissions Determination Methods

Emissions Monitoring

Rule into Section Table

Section into Rule Table

Compliance Dates

Non-Electrical Generating Units

Large Non-Electrical Generating Units

Allowances for Electrical Generating Units

Existing Reciprocating Internal Combustion Engines Affected by the NO

Authority: Implementing Sections 9.9 and 10 and authorized by Sections 27 and 28 of the

Environmental Protection Act [415 ILCS 5/9.9, 10, 27 and 28].

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 25 Ill. Reg. 128,

effective December 26, 2000; amended in R01-11 at 25 Ill. Reg. 4597, effective March 15, 2001;

amended in R01-16 and R01-17 at 25 Ill. Reg. 5914, effective April 17, 2001; amended in R07-

18 at 31 Ill. Reg. 14254, effective September 25, 2007; amended in R07-19 at 32. Ill. Reg.

_____, effective __________.

SUBPART Q: STATIONARY RECIPROCATING INTERNAL COMBUSTION

ENGINES AND TURBINES

Section 217.386

The provisions of this Subpart shall apply to all:

A stationary Stationary reciprocating internal combustion engines engine

listed in Appendix G of this Part is subject to the requirements of this

Stationary reciprocating internal combustion engines and turbines located

at a source that emits or has the potential to emit NO

in an amount equal

to or greater than 100 tons per year and is in either the area composed of

the Chicago area counties of Cook, DuPage, Kane, Lake, McHenry, and

Will, the Townships of Aux Sable and Goose Lake in Grundy County, and

the Township of Oswego in Kendall County, or in the area composed of

the Metro-East counties of Jersey, Madison, Monroe, and St. Clair, and the

Township of Baldwin in Randolph County, where:

The engine at nameplate capacity is rated at equal to or greater

than 500 bhp output; or

The turbine is rated at equal to or greater than 3.5 MW (4,694 bhp)

output at 14.7 psia, 59ºF and 60 percent relative humidity.

Notwithstanding subsection (a) of this Section, an affected unit is not subject to

the requirements of this Subpart Q if the engine or turbine is or has been:

Used as an emergency or standby unit as defined by 35 Ill. Adm. Code

Used for research or for the purposes of performance verification or

Used to control emissions from landfills, where at least 50 percent of the

heat input is gas collected from a landfill;

Used for agricultural purposes including the raising of crops or livestock

that are produced on site, but not for associated businesses like packing

operations, sale of equipment or repair; or

An engine with nameplate capacity rated at less than 1,500 bhp (1,118kW)

output, mounted on a chassis or skids, designed to be moveable, and

moved to a different source at least once every 12 months;

If an exempt unit ceases to fulfill the criteria specified in subsection (b) of this

Section, the owner or operator must notify the Agency in writing within 30 days

after becoming aware that the exemption no longer applies and comply with the

control requirements of this Subpart Q.

The requirements of this Subpart Q will continue to apply to any engine or turbine

that has ever been subject to the control requirements of Section 217.388, even if

the affected unit or source ceases to fulfill the rating requirements of subsection

(a) of this Section or becomes eligible for an exemption pursuant to subsection (b)

of this Section.

Where a construction permit, for which the application was submitted to the

Agency prior to the adoption of this Subpart, is issued that relies on decreases in

emissions of NO

from existing emission units for purposes of netting or

emissions offsets, such NO

decreases shall remain creditable notwithstanding

any requirements that may apply to the existing emissions units pursuant to this

(Source: Amended at 32 Ill. Reg. ______, effective ____________)

Section 217.388

Control and Maintenance Requirements

On and after the applicable compliance date in Section 217.392, an owner or operator of an

affected unit must inspect and maintain affected units as required by subsection (cd)

Section and comply with one of the following:either

the applicable emissions concentration as

set forth in subsection (a) of this Section, or

the requirements for an emissions averaging plan as

specified in subsection (b) of this Section, or the requirements for operation as a low usage unit

as specified in subsection (c) of this Section.

The owner or operator must

limits the discharge from an affected unit into the

atmosphere of any gases that contain NOx to no more than:

150 ppmv (corrected to 15 percent O

on a dry basis) for spark-ignited

rich-burn engines;

210 ppmv (corrected to 15 percent O

on a dry basis) for spark-ignited

lean-burn engines, except for existing spark-ignited Worthington engines

that are not listed in Appendix G;

365 ppmv (corrected to 15 percent O

on a dry basis) for existing spark-

ignited Worthington engines that are not listed in Appendix G;

660 ppmv (corrected to 15 percent O

on a dry basis) for diesel engines;

42 ppmv (corrected to 15 percent O

on a dry basis) for gaseous fuel-fired

96 ppmv (corrected to 15 percent O

on a dry basis) for liquid fuel-fired

The owner or operator must compliesy with an emissions averaging plan as

provided for in either subsection (b)(1) or (b)(2) of this Section:

For any affected unit identified by Section 217.386: The the requirements

of the applicable emissions averaging plan as set forth in Section 217.390;

For units identified in Section 217.386(a)(2): The requirements of an

emissions averaging plan adopted pursuant to any other Subpart of this

Part. For such affected engines and turbines the applicable requirements

of this Subpart apply, including but not limited to, calculation of NO

allowable and actual emissions rates, compliance dates, monitoring,

testing, reporting, and recordkeeping.

The owner or operator operates the affected unit as a low usage unit pursuant to

subsection (c)(1) or (c)(2) of this Section. Low usage units are not subject to the

requirements of this Subpart Q except for the requirements to inspect and

maintain the unit pursuant to subsection (d) of this Section, and retain records

pursuant to Sections 217.396(b) and (d). Either the limitation in subsection (c)(1)

or (c)(2) may be utilized at a source, but not both:

The potential to emit (PTE) is no more than 100 TPY NO

from all engines and turbines located at the source that are not otherwise

exempt pursuant to Section 217.386(b), and not complying with the

requirements of subsection (a) or (b) of this Section, and the NO

limit is contained in a federally enforceable permit; or

The aggregate bhp-hrs/MW-hrs from all affected units located at the

source that are not exempt pursuant to Section 217.386(b), and not

complying with the requirements of subsection (a) or (b) of this Section,

are less than or equal to the bhp-hrs and MW-hrs operation limit listed in

subsection (c)(2)(A) and (c)(2)(B) of this Section. For units that drive a

natural gas compressor station but that are not located at a natural gas

compressor station or storage facility, the operation limits of subsection

(c)(2)(A) and (c)(2)(B) of this Section must be contained in a federally

enforceable permit. The operation limits are:

8 mm bhp-hrs or less on an annual basis for engines; and

20,000 MW-hrs or less on an annual basis for turbines.

The owner or operator must inspects and performs periodic maintenance on the

affected unit, in accordance with a Maintenance Plan that documents:

For a unit not located at natural gas transmission compressor station or

storage facility, either:

The manufacturer’s recommended inspection and maintenance of

the applicable air pollution control equipment, monitoring device,

and affected unit; or

If the original equipment manual is not available or substantial

modifications have been made that require an alternative procedure

for the applicable air pollution control device, monitoring device,

or affected unit, the owner or operator must establish a plan for

inspection and maintenance in accordance with what is customary

for the type of air pollution control equipment, monitoring device,

and affected unit.

For a unit located at a natural gas compressor station or storage facility,

the operator’s maintenance procedures for the applicable air pollution

control device, monitoring device, and affected unit.

(Source: Amended at 32 Ill. Reg. _________, effective _____________)

Section 217.390

Emissions Averaging Plans

An owner or operator of certain affected units may comply through an emissions

averaging plan.

The unit or units that commenced operation before January 1, 2002, may

be included in only onean emissions averaging plan, as follows:

Listed in Appendix G and located at a single source or at

multiple sources in Illinois, so long as the units are owned

by the same company or parent company where the parent

company has working control through stock ownership of

its subsidiary corporations. A unit may be

one emissions averaging plan; or

Identified in Section 217.386(a)(2), and located at a single

source or at multiple sources in either the Chicago area

counties or Metro-East area counties, so long as the units

are owned by the same company or parent company where

the parent company has working control through stock

ownership of its subsidiary corporations.

Units that have a compliance date later than the control period for

which the averaging plan is being used for compliance; and

Units which the owner or operator may claim as exempt pursuant

to Section 217.386(b) but does not claim as exempt. For as long as

such unit is included in an emissions averaging plan, it will be

treated as an affected unit and subject to the applicable emission

concentration, limits, testing, monitoring, recordkeeping and

reporting requirements.

The following types of units may not be included in an emissions

averaging plan:

Units units that commence operation after January 1, 2002, unless

the unit replaces an engine or turbine that commenced operation on

or before January 1, 2002, or it replaces an engine or turbine that

replaced a unit that commenced operation on or before January 1,

2002. The new unit must be used for the same purpose as the

replacement unit. The owner or operator of a unit that is shutdown

and replaced must comply with the provisions of Section

217.396(dc)(3) before the replacement unit may be included in an

emissions averaging plan.

Units which the owner or operator is claiming are exempt pursuant

to Section 217.386(b) or as low usage units pursuant to Section

An owner or operator must submit an emissions averaging plan to the Agency by

the applicable compliance date set forth in Section 217.392, or by May 1 of the

year in which the owner or operator is using a new emissions averaging plan to

The plan must include, but is not limited to:

The list of affected units included in the plan by unit identification

number and permit number.

A sample calculation demonstrating compliance using the

methodology provided in subsection (f) of this Section for both the

ozone season and calendar year.

The plan will be effective as follows

An initial plan for units required to comply by January 1, 2008, is

effective January 1, 2008;

An initial plan for units required to comply by May 1, 2010, is

effective May 1, 2010 for those units;

A new plan submitted pursuant to subsection (b) of this Section but

not submitted by January 1, 2008 or May 1, 2010 is effective

retroactively to January 1 of the applicable year;

An amended plan submitted pursuant to subsection (c) of this

Section is effective retroactively to January 1 of the applicable

An amended plan submitted pursuant to subsection (d) of this

Section is effective on the date it is received by the Agency.

An owner or operator may amend an emissions averaging plan only once per

calendar year. An amended plan must include the information from subsection

(b)(1) and may, but is not limited to changing the group of affected units or

reflecting changes in the operation of the affected units. An amended plan must

be submitted to the Agency by May 1 of the applicable calendar year and is

effective as set forth in subsection (b)(2) of this Section. If an amended plan is

not received by the Agency by May 1 of the applicable calendar year, the

previous year’s plan will be the applicable emissions averaging plan.

Notwithstanding subsection (c) of this Section, an owner or operator, and the

buyer, if applicable:

Must submit an updated emissions averaging plan or plans to the Agency

within 60 days,

if a unit that is listed in an emissions averaging plan is sold

or taken out of service.

May amend its emissions averaging plan to include another unit within 30

days of discovering that the unit no longer qualifies as an exempt unit

pursuant to Section 217.386(b) or as a low usage unit pursuant to Section

An owner or operator must:

Demonstrate compliance for both the ozone season (May 1 through

September 30) and the calendar year (January 1 through December 31) by

using the methodology and the units listed in the most recent emissions

averaging plan submitted to the Agency pursuant to subsection (b),

(d) of this Section; the higher of the monitoring or test data determined

pursuant to Section 217.394; and the actual hours of operation for the

applicable control period;

Notify the Agency by October 31 following the ozone season, if

compliance cannot be demonstrated for that ozone season; and

Submit to the Agency by January 31 following each calendar year, a

compliance report containing the information required by Section

The total mass of actual NOx emissions from the units listed in the emissions

averaging plan must be equal to or less than the total mass of allowable NOx

emissions for those units for both the ozone season and calendar year. The

following equation must be used to determine compliance:

Total sum of the actual NOx mass emissions from

units included in the averaging plan for each fuel used (lbs

per ozone season and calendar year).

Total sum of the allowable NOx mass emissions from units

included in the averaging plan for each fuel used (lbs per

ozone season and calendar year).

Total mass of allowable NOx emissions in lbs for a unit as

determined in subsection (g)(2) or (h)(2) of this Section.

Total mass of actual NO

emissions in lbs for a unit

as determined in subsection (g)(1) or (h)(1) of this Section.

Subscript denoting an individual unit and fuel used.

Number of different units in the averaging plan.

For each unit in the averaging plan, and each fuel used by a unit, determine actual

and allowable NOx emissions using the following equations, except as provided

for in subsection (h) of this Section:

Actual emissions must be determined as follows:

Allowable emissions must be determined as follows:

Total mass of actual NOx emissions in lbs for a unit, except

as provided for in subsections (g)(3) and (g)(5) of this

Total mass of allowable NOx emissions in lbs for a unit,

except as provided for in subsection (g)(3) of this Section.

Actual NOx emission rate (lbs/mmBtu) calculated

according to the above equation.

Allowable NOx emission rate (lbs/mmBtu)

calculated according to the above equation.

Heat input (mmBtu/ozone season or mmBtu/year)

calculated from fuel flow meter and the heating

value of the fuel used.

Actual concentration of NOx in lb/dscf (ppmv x

) on a dry basis for the fuel used. Actual

concentration is determined on each of the most recent test

or monitoring passes performed pursuant to Section

217.394, whichever is higher.

Allowable concentration of NOx in lb/dscf (allowable

emission limit in ppmv specified in Section 217.388(a),

except as provided for in subsection (g)(4), (g)(5), or (g)(6)

of this Section, if applicable.

,(multiplied by 1.194 x 10

on a dry basis for the fuel used.

The ratio of the gas volume of the products of combustion

to the heat content of the fuel (dscf/mmBtu) as given in the

table of F Factors included in 40 CFR 60, Aappendix

Method 19 or as determined using 40 CFR 60, Aappendix

Concentration of oxygen in effluent gas stream measured

on a dry basis during each of the applicable tests or

monitoring runs used for determining emissions, as

represented by a whole number percent, e.g., for 18.7%O

18.7 would be used.

Subscript denoting an individual unit and the fuel used.

Subscript denoting each test run or monitoring pass for an

affected unit for a given fuel.

The number of test runs or monitoring passes for an

affected unit using a given fuel.

For a replacement unit that is electric-powered, the allowable NOx

emissions from the affected unit that was replaced should be used in the

averaging calculations and the actual NOx emissions for the electric-

powered replacement unit (EM

) are zero. Allowable NOx

emissions for the electric-powered replacement are calculated using the

actual total bhp-hrs generated by the electric-powered replacement unit on

an ozone season and on an annual basis multiplied by the allowable NOx

emission rate in lb/bhp-hr of the replaced unit. The allowable mass of

NOx emissions from an electric-powered replacement unit (EM

must be determined by multiplying the nameplate capacity of the unit by

the hours operated during the ozone season or annually and the allowable

NOx emission rate of the replaced unit (E

) in lb/mmBtu converted to

lb/bhp-hr. For this calculation the following equation should be used:

= bhp x OP x F x E

Mass of allowable NOx emissions from the electric-

powered replacement unit in pounds per ozone season or

= Nameplate capacity of the electric-powered

replacement unit in brake- horsepower.

= Operating hours during the ozone season or calendar

= Conversion factor of 0.0077 mmBtu/bhp-hr.

emission rate (lbs/mmBtu) of the replaced

= Subscript denoting an individual electric unit and the fuel

For a replacement unit that is not electric, the allowable NO

rate used in the above equations set forth in subsection (g)(2) of this

Section must be the higher of the actual NO

emissions as determined by

testing or monitoring data or the applicable uncontrolled NO

factor from Compilation of Air pPollutant

eEmission Factors: AP-42,

Volume I: Stationary Point and Area Sources, as incorporated by reference

in Section 217.104 for the unit that was replaced.

For a unit that is replaced with purchased power, the allowable NO

emissions rate used in the above

equations set forth in subsection (g)(2) of

this Section must be the emissions concentration as set forth in Section

217.388(a) or subsection (g)(6) of this Section, when applicable, for the

type of unit that was replaced. For owners or operators replacing units

with purchased power, the annual hours of operations that must be used

are the calendar year hours of operation for the unit that was shutdownshut

down, averaged over the three-year period prior to the shutdown. The

actual NOx emissions for the units replaced by purchased power (EM

are zero. These units may be included in any emissions averaging plan for

no more than five years beginning with the calendar year that the replaced

unit is shut down.

For units that have a later compliance datenon-Appendix G units used in

an emissions averaging plan, allowable emissions rate used in the above

equations set forth in subsection (g)(2) of this Section must be:

Prior to the applicable compliance date pursuant to Section

217.392, the higher of the actual NO

emissions as determined by

testing or monitoring data, or the applicable uncontrolled NO

emissions factor from Compilation of Air Pollutant Emission

Factors: AP-42, Volume I: Stationary Point and Areas Sources, as

incorporated by reference in Section 217.104); or

On and after the unit’s applicable compliance date pursuant to

section 217.392, the applicable emissions concentration for that

type of unit pursuant to Section 217.388(a).

For units that use CEMS,

the data must show that the total mass of actual NOx

emissions determined pursuant to subsection (h)(1) of this Section is less than or

equal to the allowable NOx emissions calculated in accordance with the equations

in subsections (f) and (h)(2) of this Section for both the ozone season and calendar

year. The equations in subsection (g) of this Section will not apply.

The total mass of actual NOx emissions in lbs for a unit (EM

the sum of the total mass of actual NOx emissions from each affected unit

using CEMS data collected in accordance with 40 CFR 60 or 75, or

alternate methodology that has been approved by the Agency or USEPA

and included in a federally enforceable permit.

The allowable NO

emissions must be determined as follows:

Total mass of allowable NO

emissions in lbs for a unit.

Stack flow (dscf/hr) for a given stack.

Allowable concentration of NO

(ppmv) specified in

Section 217.388(a) of this subpart

for a given stack. (1.194

) converts to lb/dscf).

subscript denoting each hour operation of a given unit.

Total number of hours of operation of a unit.

Subscript denoting an individual unit and the fuel used.

(Source: Amended at

(Source: Amended at 32 Ill. Reg. _________, effective ________________)

Section 217.392

On and after January 1, 2008, an owner or operator of an affected engine listed in

Appendix G may not operate the affected engine unless the requirements of this

Subpart Q are met or the affected engine is exempt pursuant to Section

On and after May 1, 2010, an owner or operator of a unit identified by Section

217.386(a)(2), and that is not listed in Appendix G, may not operate the affected

unit unless the requirements of this Subpart Q are met or the affected unit is

exempt pursuant to Section 217.386(b).

Owners and operators of an affected unit may use NO

allowances to meet the

compliance requirements in Section 217.388 as specified below. A NO

allowance is defined as an allowance used to meet the requirements of a NO

trading program administered by USEPA where one allowance is equal to one ton

allowances may be used only under the following circumstances:

An anomalous or unforeseen operating scenario inconsistent with

historical operations for a particular ozone season or calendar year

that causes an exceedance of an emissions or operating hour

To achieve compliance for no more than two events in any rolling

five-year period; and

For a unit that is not listed in Appendix G.

The owner or operator of the affected unit must surrender to the Agency a

allowance for each ton or portion of a ton of NO

by which actual

emissions exceed allowed emissions. Where a low usage limitation under

Section 217.388(c)(2) has been exceeded, the owner or operator of the

affected unit must calculate the NO

emissions resulting from the number

of hours that exceeded the operating hour low usage limit and surrender to

the Agency one NO

allowance for each ton or portion of a ton of NO

that was calculated. For noncompliance with a seasonal limit in Section

217.388(b), only a NO

ozone season allowance must be used. For

noncompliance with the emissions concentration limits in Section

217.388(a), low usage limitations in Section 217.388(c) or an annual

limitation in an emissions averaging plan in Section 217.388(b), only a

annual allowance may be used.

The owner operator must submit a report documenting the circumstances

that required the use of NO

allowances and identify what actions will be

taken in subsequent years to address these circumstances and must transfer

allowances to the Agency’s federal NO

retirement account. The

report and the transfer of allowances must be submitted by October 31 for

exceedances during the ozone season and March 1 for exceedances of the

emissions concentration limits, the annual emissions averaging plan limits,

or low usage limitations. The report must contain the NATS serial

numbers of the NO

(Source: Amended at 32 Ill. Reg. _________, effective ________________)

Section 217.394

Testing and Monitoring

An owner or operator must conduct an initial performance test pursuant to

subsection (c)(1) or (c)(2) of this Section as follows:

By January 1, 2008, for affected engines listed in Appendix G.

Performance tests must be conducted on units listed in Appendix G, even

if the unit is included in an emissions averaging plan pursuant to Section

By the applicable compliance date as set forth in Section 217.392, or

withinWithin the first 876 hours of operation per calendar year, whichever

Performance tests must be conducted on For affected units not

listed in Appendix G that operate more than 876 hours per calendar

For units that are not affected units that are included in an

emissions averaging plan and operate more than 876 hours per

Once within the five-year period after the applicable compliance date as

set forth in Section 217.392:

For affected units that operate fewer than 876 hours per calendar

year; and. Performance tests must be conducted on

For units that are not affected units that are included in an

emissions averaging plan and that operate fewer than 876 hours per

An owner or operator of an engine or turbine must conduct subsequent

performance tests pursuant to subsection (cb)(1), or (cb)(2), and (b)(3) of this

Section as follows:

For affected engines listed in Appendix G and all units included in an

emissions averaging plan, once every five years. Testing must be

performed in the calendar year by May 1 or within 60 days after starting

operation, whichever is later;

If the monitored data shows that the unit is not in compliance with the

applicable emissions concentration or emissions averaging plan, the owner

or operator must report the deviation to the Agency in writing within 30

days and conduct a performance test pursuant to subsection (c) of this

Section within 90 days of the determination of noncompliance; and

in the opinion of the Agency or USEPA, it is necessary to conduct

testing to demonstrate compliance with Section 217.388, the owner or

operator of a unit must, at his or her own expense, conduct the test in

accordance with the applicable test methods and procedures specified in

this Section within 90 days after receipt of a notice to test from the

Agency or USEPA.

Testing Procedures:

For an engine: The owner or operator must conduct a performance test

using Method 7 or 7E of 40 CFR 60, appendix A, as incorporated by

reference in Section 217.104. Each compliance test must consist of three

separate runs, each lasting a minimum of 60 minutes. NO

be measured while the affected unit is operating at peak load. If the unit

combusts more than one type of fuel (gaseous or liquid), including backup

fuels, a separate performance test is required for each fuel.

For a turbine included in an emissions averaging plan: The owner or

operator must conduct a performance test using the applicable procedures

and methods in 40 CFR 60.4400, as incorporated by reference in Section

Monitoring: Except for those years in which a performance test is conducted

pursuant to subsection (a) or (b) of this Section, the owner or operator of an

affected unit or a unit included in an emissions averaging plan must monitor NO

concentrations annually, once between January 1 and May 1 or within the first

876 hours of operation per calendar year, whichever is later. If annual operation

is less than 876 hours per calendar year, each affected unit must be monitored at

least once every five years. Monitoring must be performed as follows:

monitor utilizingand method ASTM D6522-00, as

incorporated by reference in Section 217.104, or a method approved by

the Agency must be used. If the engine or turbine combusts both liquid

and gaseous fuels as primary or backup fuels, separate monitoring is

required for each fuel.

concentrations measurements must be taken three times for a

duration of at least 20 minutes. Monitoring must be done at highest

achievable load. The concentrations from the three monitoring runs must

be averaged to determine whether the affected unit is in compliance with

the applicable emissions concentration or emissions averaging plan, as

specified in Section 217.388.

Instead of complying with the requirements of subsections (a), (b), (c) and (d) of

this Section, an owner or operator may install and operate a CEMS on an affected

unit that meets the applicable requirements of 40 CFR 60, subpart A, and

appendix B, incorporated by reference in Section 217.104, and complies with the

quality assurance procedures specified in 40 CFR 60, appendix F,

as incorporated by reference in Section 217.104, or an alternate procedure as

approved by the Agency or USEPA in a federally enforceable permit. The CEMS

must be used to demonstrate compliance with the applicable emissions

concentration or emissions averaging plan only on an ozone season and annual

The testing and monitoring requirements of this Section do not apply to affected

units in compliance with the requirements of the low usage limitations pursuant to

Section 217.388(c) or low usage units using NO

allowances to comply with the

requirements of this Subpart pursuant to Section 217.392(c). Notwithstanding the

above circumstances, when in the opinion of the Agency or USEPA, it is

necessary to conduct testing to demonstrate compliance with Section 217.388, the

owner or operator of a unit must, at his or her own expense, conduct the test in

accordance with the applicable test methods and procedures specified in this

Section within 90 days after receipt of a notice to test from the Agency or

(Source: Amended at 32 Ill. Reg. _______, effective _____________)

Section 217.396

Recordkeeping and Reporting

Recordkeeping. The owner or operator of a unit included in an emissions

averaging plan or an affected unit that is not exempt pursuant to Section

217.386(b) and is not subject to the low usage exemption of Section 217.388(c) of

an Appendix G unit or a unit included in an emissions averaging plan must

maintain records that demonstrate compliance with the requirements of this

Subpart Q, which include, but are not limited to:

Identification, type (e.g., lean-burn, gas-fired), and location of each unit.

Calendar date of the record.

The number of hours the unit operated on a monthly basis, and during

each ozone season.

Type and quantity of the fuel used on a daily basis.

The results of all monitoring performed on the unit and reported

The results of all tests performed on the unit.

The plan for performing inspection and maintenance of the units, air

pollution control equipment, and the applicable monitoring device

pursuant to Section 217.388(d)(c)

A log of inspections and maintenance performed on the unit’s air

emissions, monitoring device, and air pollution control device. These

records must include, at a minimum, date, load levels and any manual

adjustments, along with the reason for the adjustment (e.g., air to fuel

ratio, timing or other settings).

If complying with the emissions averaging plan provisions of Sections

217.388(b) and 217.390, copies of the calculations used to demonstrate

compliance with the ozone season and annual control period limits,

noncompliance reports for the ozone season, and ozone and annual control

period compliance reports submitted to the Agency.

Identification of time periods for which operating conditions and pollutant

data were not obtained by either the CEMS or alternate monitoring

procedures, including the reasons for not obtaining sufficient data and a

description of corrective actions taken.

allowance reconciliation reports submitted pursuant to Section

The owner or operator of an affected unit or unit included in an emissions

averaging plan must maintain the records required by subsectionssubsection (a) or

(d) of this Section, as applicable, for a period of five- years at the source at which

the unit is located. The records must be made available to the Agency and

USEPA upon request.

Reporting Requirements

The owner or operator must notify the Agency in writing 30 days and five

days prior to testing,

pursuant to Section 217.394(a) and (b) and:

If, after the 30-days notice for an initially scheduled test is sent,

there is a delay (e.g., due to operational problems) in conducting

the performance test as scheduled, the owner or operator of the unit

must notify the Agency as soon as possible of the delay in the

original test date, either by providing at least seven days prior

notice of the rescheduled date of the performance test, or by

arranging a new test date with the Agency by mutual agreement;

Provide a testing protocol to the Agency 60 days prior to testing;

Not later than 30 days after the completion of the test, submit the

results of the test to the Agency.

Pursuant to the requirements for monitoring in Section 217.394(d), the

owner or operator of the unit must report to the Agency any monitored

exceedances of the applicable NO

concentration from Section 217.388(a)

or (b) within 30 days after performing the monitoring.

Within 90 days after permanently shutting down an affected unit or a unit

included in an emissions averaging plan, the owner or operator of the unit

must withdraw or amend the applicable permit to reflect that the unit is no

longer in service.

If demonstrating compliance through an emissions averaging plan:

By October 31 following the applicable ozone season, the owner or

operator must notify the Agency if he or she cannot demonstrate

compliance for that ozone season; and

By January 3130 following the applicable calendar year, the owner

or operator must submit to the Agency a report that demonstrates

For all units that are part of the emissions averaging plan,

the total mass of allowable NOx emissions for the ozone

season and for the annual control period;

The total mass of actual NOx emissions for the ozone

season and annual control period for each unit included in

the averaging plan;

The calculations that demonstrate that the total mass of

actual NOx emissions are less than the total mass of

allowable NOx emissions using equations in Sections

217.390(f) and (g); and

The information required to determine the total mass of

actual NOx emissions and the calculations performed in

subsection (cd)(4)(B)(iii) of this Section.

If operating a CEMS, the owner or operator must submit an excess

emissions and monitoring systems performance report in accordance with

the requirements of 40 CFR 60.7(c) and 60.13, or 40 CFR 75, incorporated

by reference in Section 217.104, or an alternate procedure approved by the

Agency or USEPA and included in a federally enforceable permit.

allowances to comply with the requirements of Section

217.388, reconciliation reports as required by Section 217.392(c)(3).

The owner or operator of an affected unit that is complying with the low usage

provisions of Section 217.388(c) must:

For each unit complying with Section 217.388(c)(1), maintain a record of

emissions for each calendar year;

For each unit complying with Section 217.388(c)(2), maintain a record of

bhp or MW hours operated each calendar year; and

For each unit utilizing NO

allowances for compliance pursuant to Section

217.392(c)(3), maintain and submit any NO

allowance reconciliation

(Source: Amended at 32 Ill. Reg. _______, effective ____________)

IT IS SO ORDERED.

I, John T. Therriault, Assistant Clerk of the Illinois Pollution Control Board, certify that

the Board adopted the above opinion and order on September 16, 2008, by a vote of 4-0.

___________________________________

John T. Therriault, Assistant Clerk

Illinois Pollution Control Board