NOTICE OF HEARINGS

PROCEDURAL HISTORY
BACKGROUND OF FEDERAL REQUIREMENTS
SUMMARY AND DISCUSSION OF THE PROPOSAL
1. Appendix G
TECHNICAL AND ECONOMIC CONSIDERATIONS
Annual Compliance
Cost-Effectiveness
Agency Testimony
Pipeline Consortium Testimony
1. Board Finding
CONCLUSION
1. PTE potential to emit

ILLINOIS POLLUTION CONTROL BOARD

IN THE MATTER OF:

FAST-TRACK RULES UNDER NITROGEN

) SIP CALL PHASE II:

AMENDMENTS TO 35 ILL. ADM. CODE

SECTION 201.146 AND PARTS 211 and 217

(Rulemaking - Air)

Proposed Rule. Second Notice.

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

Today the Board adopts for second notice rules intended to reduce interstate and

intrastate transport of nitrogen oxides (NO

) emissions on ozone season and annual bases by

emissions from stationary reciprocating internal combustion engines addressed in

State Implementation Plan (SIP) Call Phase II.

69 Fed. Reg. 21603 (April 21,

2004). This proposal will add a new Subpart Q to Part 217 of the Board’s air regulations. The

existing units subject to this rulemaking are specifically listed in Appendix G.

The Illinois Environmental Protection Agency (Agency) originally filed its rulemaking

proposal in this docket on April 6, 2007 under the “fast-track” procedures of Section 28.5 of the

Environmental Protection Act (Act) (415 ILCS 5/28.5 (2006)). In an order dated May 17, 2007,

the Board concluded that the Agency’s entire proposal is not “required to be adopted” by the

Clean Air Act (CAA). Accordingly, the Board bifurcated the proposal by continuing to consider

only the portion applicable to engines affected by the NO

SIP Call Phase II under fast-track

procedures. In the same order, the Board directed publication of the remainder of the Agency’s

original proposal for first notice under Sections 27 and 28 of the Act in docket R 07-19 without

commenting on the merits of the proposal.

35 Ill. Reg. 7683, 7702.

In this opinion, the Board first provides the procedural history of this rulemaking and the

federal regulatory background for the Agency’s proposal. The opinion then summarizes the

Agency’s proposal in light of the Board’s May 17, 2007 order before addressing technical and

economic issues raised in hearings and in the post-hearing comments of the participants. The

order following this opinion then sets forth the proposed amendments for second notice

publication in the

Illinois Register

PROCEDURAL HISTORY

On April 6, 2007, the Agency filed with the Board a rulemaking proposal intended to

reduce emissions of NO

from stationary reciprocating engines and turbines. The Agency’s

proposal included a technical support document (TSD). In its accompanying statement of

reasons (Statement), the Agency invoked as statutory authorities for filing its proposal sections

9.9, 10, and 27 of the Act. Statement at 1, 7-8;

415 ILCS 5/9.9, 10, 27 (2006)). The Agency

also invoked Section 28.5 of the Act, which provides for “fast-track” proceedings applying

“solely to the adoption of rules proposed by the Agency and required to be adopted by the State

under the Clean Air Act as amended by the Clean Air Act Amendments of 1990 (CAAA).”

Statement at 8-11, citing 415 ILCS 5/28.5(a) (2004).

On April 16, 2007, ANR Pipeline Company, Natural Gas Pipeline Company, Trunkline

Gas Company, and Panhandle Eastern Pipeline Company (collectively, the Pipeline Consortium)

filed an “Objection to Use of Section 28.5 Fast Track Procedures for Consideration of Nitrogen

Oxide Proposal as Filed.” On April 17, 2007, the Illinois Environmental Regulatory Group

(IERG) filed an “Objection to Use of Section 28.5 ‘Fast-Track’ Rulemaking for the Illinois

Environmental Protection Agency’s Proposed Rules.”

On April 19, 2007, the Board adopted an order accepting the Agency’s proposal for

hearing without commenting on its merits and sending the proposed rule to first notice under the

Illinois Administrative Procedure Act.

31 Ill. Reg. 6559, 6578, 6597; 31 Ill. Reg. 7370-72

(correction of hearing date);

(2006). In the same order, the

Board noted that it had received objections to the Agency’s reliance on section 28.5 procedures

both from the Pipeline Consortium and from IERG. The same order directed that any response

to the two objections be filed by May 1, 2007, and allowed replies to the responses to be filed by

On May 1, 2007, the Agency filed a “Response to the Pipeline Consortium’s Objection to

Use of Section 28.5 Fast Track Procedures for Consideration of Nitrogen Oxide Proposal,”

accompanied by the affidavit of Robert Kaleel. Also on May 1, 2007, the Agency filed a

“Response to the Illinois Environmental Regulatory Group’s Objection to Use of Section 28.5

Fast Track Procedures for Consideration of Nitrogen Oxide Proposal”, accompanied by an

affidavit of Robert Kaleel.

On May 8, 2007, the Pipeline Consortium filed a “Reply to the Illinois Environmental

Protection Agency’s Responses to Objections to the Use of Section 28.5 Fast-Track Rulemaking

Procedures in this Matter.” Also on May 8, 2007, IERG filed a “Reply to Response to Objection

to Use of Section 28.5 ‘Fast-Track’ Rulemaking for the Illinois Environmental Protection

Agency’s Proposed Rules,” accompanied by an affidavit of Deirdre K. Hirner.

On May 14, 2007, the Pipeline Consortium filed in Sangamon County Circuit Court a

complaint seeking declaratory and injunctive relief related to this proceeding. The Pipeline

Consortium asserted that it filed its complaint “as a result of IPCB’s illegal rulemaking

procedure and the IEPA’s illegal filing of a proposed rule with the IPCB.” ANR Pipeline

Company, Natural Gas Pipeline Company, Trunkline Gas Company, and Panhandle Eastern Pipe

Line Company v. Illinois Pollution Control Board and Illinois Environmental Protection Agency,

No. 07MR190 (Sangamon County Circuit Court). Generally, plaintiffs alleged that Section 28.5

of the Act is unconstitutional and could not be used to adopt certain portions of IEPA’s original

proposal. On June 14, 2007, the parties filed an agreed motion to continue.

In an order dated May 17, 2007, the Board concluded that the Agency’s entire proposal is

not “required to be adopted” by the Clean Air Act (CAA). Accordingly, the Board bifurcated the

proposal by continuing to consider only the

portion applicable to the 28 internal combustion

engines affected by the NO

SIP Call Phase II under the fast-track procedures of Section 28.5 of

the Act. In the same order, the Board directed publication of the remainder of the Agency’s

proposal for first notice under Sections 27 and 28 of the Act in docket R07-19 without

commenting on the merits of the proposal.

In a letter dated May 2, 2007, the Board requested that the Department of Commerce and

Economic Opportunity (DCEO) conduct an economic impact study of this rulemaking proposal.

415 ILCS 5/27(b) (2006). On May 21, 2007, the Board received from DCEO a response

stating that, based upon its review of the request and in light of its continued financial

constraints, DCEO had determined not to conduct a study of the economic impact of the

On May 11, 2007, the Agency prefiled the testimony of Robert Kaleel, Yoginder

Mahajan, Scott Leopold, and Michael Koerber. On May 18, 2007, the Agency filed a motion to

withdraw testimony. Specifically, the Agency sought leave to withdraw the testimony of Scott

Leopold and Michael Koerber in light of the Board’s May 17, 2007 order bifurcating the

Agency’s original proposal. Also on May 18, 2007, the Agency filed a motion to amend

testimony. Specifically, the Agency sought leave to amend the testimony of Robert Kaleel and

Yoginder Mahajan in light of the Board’s May 17, 2007 order bifurcating the Agency’s original

The first hearing (Tr. 1) in this proceeding took place on May 21, 2007 in Springfield. At

the beginning of that hearing, the hearing officer granted the Agency’s motion to withdraw

testimony, granted the Agency’s motion to amend testimony, and accepted the amended

testimony of Robert Kaleel (Kaleel Test.) and Yoginder Mahajan (Mahajan Test.). Tr. 1 at 4-5.

Two exhibits, the amended testimony of Robert Kaleel (Exh. 1) and the amended testimony of

Yoginder Mahajan (Exh. 2) were admitted into the record at the first hearing.

On June 8, 2007, James McCarthy prefiled testimony (McCarthy Test.). The second

hearing (Tr. 2) in this proceeding took place on June 19, 2007 in Chicago. Seven exhibits were

admitted into the record at the first hearing:

Testimony of James McCarthy (Exh. 3)

Hearing Officer Order of May 24, 2007 (Exh.4)

Appendix G: Existing Reciprocating Internal Combustion Engines Affected by NO

Interstate Ozone Transport: Response to Court Decisions on the NO

Call Technical Amendments, and Section 126 Rules; Final Rule (69 Fed.Reg. 21606-48)

Alternative Control Techniques

Document – NO

Emissions from Stationary

Reciprocating Internal Combustion Engines (USEPA) (Exh. 7)

Technical Support Document for Controlling NO

Emissions from Stationary

Reciprocating Internal Combustion Engines and Turbines (AQPSTR 07-01) (Exh. 8)

Stationary Reciprocating Internal Combustion Engines Technical Support Document for

SIP CALL (October 2003) (Exh. 9)

On the record at the second hearing, the Agency indicated that it did not intend to

introduce any additional material into the record and would have no objection if the Board

cancelled the third hearing in this proceeding, which had been scheduled to begin on July 2,

2007. Tr. 2 at 44-45. A hearing officer order dated June 22, 2007 cancelled the third hearing

and set the statutory 14-day comment period to run from June 21, 2007, to July 5, 2007.

ILCS 5/28.5(l) (2006).

On June 25, 2007, the Agency filed a motion for reconsideration of the Board’s May 17,

2007 order bifurcating the Agency’s original proposal. On July 9, 2007, the Board received the

Pipeline Consortium’s response to the motion for reconsideration. Also on July 9, 2007, the

Board received from IERG a motion to strike and a response to the motion for reconsideration.

Also on July 9, 2007, the Agency filed a motion for leave to supplement and a supplement to its

motion for reconsideration. Specifically, the Agency sought to add as an exhibit to its motion a

document entitled

Report of the Attorney General’s Task Force on Environmental Legal

Resources (1992)

. On the same date, the Agency also filed a motion for waiver of the

requirement that it file an original and nine copies of the supplemental exhibit.

On July 11, 2007, the Agency filed a motion for leave to file a reply by date certain,

which committed to file a reply addressing both responses no later than July 18, 2007. In an

order dated July 12, 2007, the Board granted the Agency leave to reply and directed the Agency

to file that reply no later than July 18, 2007. On July 19, 2007, the Agency filed a motion for

leave to file its consolidated reply

, accompanied by its consolidated reply. On July 23,

2007, the Agency filed a response to IERG’s motion to strike.

In an order dated July 26, 2007, the Board granted the Agency’s motion for leave to

supplement, accepted the supplemental exhibit, and granted the Agency’s motion for waiver of

procedural requirements. Also in the July 26, 2007 order, the Board granted the Agency’s

, denied IERG’s motion to strike the Agency’s motion to reconsider, and

denied the Agency’s motion for reconsideration of the Board’s May 17, 2007 order.

On July 5, 2007, the Board received the Agency’s post- hearing comments (PC 1). Also

on July 5, 2007, the Board received the Pipeline Consortium’s comments (PC 2).

BACKGROUND OF FEDERAL REQUIREMENTS

The Agency states that the purpose of

its proposed new Subpart Q, as modified by the

Board’s May 17, 2007 order, is the reduction of interstate and intrastate transport of NO

emissions on ozone season and annual bases by adopting rules reducing NO

stationary reciprocating internal combustion engines addressed in the NO

SIP Call Phase II. PC

The Agency states that USEPA in 2004 promulgated a rule addressing interstate ozone

transport. Statement at 6, citing 69 Fed. Reg. 21603 (April 21, 2004). The Agency further states

that this rule responded to the court’s ruling in Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000).

The Agency argues that, in its most important provision, the federal rule “sets the control limit

for large natural gas-fired stationary internal combustion engines at 82 percent and for diesel and

dual fuel stationary internal combustion engines at 90 percent.” Statement at 7. The Agency

states that the federal rule also provided that states required to address the NO

stationary internal combustion engines were required to submit Phase II SIPs by April 1, 2005.

The Agency claims that “[i]n November 2005, Illinois and other states received

notification that USEPA had found a failure to submit a SIP addressing the Phase II

requirements.”

., citing Statement, Att. 7.b (letter from USEPA Regional Administrator to

Agency Director). The Agency further claims that USEPA has “published the findings of failure

to submit Phase II SIPs, but it had not yet published a federal implementation plan for Phase II

or started a Section 179 sanctions clock.” Statement at 7, citing 71 Fed. Reg. 6347 (Feb. 8,

Tr. 1 at 14-15.

The Pipeline Consortium argues that the NO

SIP Call Phase II merely obligates the state

emissions according to a budget and does not require the state to regulate

emissions from units subject to the proposal. PC 2 at 1, citing 69 Fed. Reg. 21604-05 (April 21,

2004), 63 Fed. Reg. 57356, 57405 (Oct. 27, 1998), Tr. 1 at 15. While the Pipeline Consortium

had objected on this basis to considering the proposal under Section 28.5 of the Act (415 ILCS 5.

28.5 (2006)), the Pipeline Consortium set aside that objection because of the bifurcation of the

rule. PC 2 at 1. The Pipeline Consortium notes that it participated with the Agency in

developing the proposed rules and that it regards the proposal as consistent with the principles of

the Phase II NO

. at 2. The Pipeline Consortium also notes that it “has been

proactive in complying with the rule even prior to its adoption by the Board.

SUMMARY AND DISCUSSION OF THE PROPOSAL

Part 201: Permits and General Provisions

Exemptions from State Permit Requirements (Section 201.146)

Section 201.146 exempts specified equipment and activities from the requirements of

obtaining state construction or operating permits. 35 Ill. Adm. Code 201.146. The Agency

originally proposed to amend subsection (i) of this Section, which addresses stationary internal

combustion engines. The Agency’s proposal clarified that the exemption applied to both engines

and turbines, and specified when a turbine or an internal combustion engine must obtain a

In its post-hearing comments, however, the Agency noted that its original proposal and

the accompanying TSD had addressed a “much broader range of engines.” PC 1 at 3. As noted

above under “Procedural History,” the Board bifurcated the original proposal by continuing to

consider in this docket only the portion of that proposal applicable to the 28 internal combustion

engines affected by the NO

SIP Call Phase II. The Agency’s post-hearing comment further

stated that “[a]mendments to Section 201.146(j)

and the broader range of engines will be

addressed in R07-19.” PC 1 at 3. Furthermore, counsel for the Agency stated at the first hearing

that “[t]he Agency is agreeable that the amendment to 35 Illinois Administrative Code 201.146

concerning a change in the permanent exemption for engines be moved to the docket in R07-19.”

As the Agency has plainly indicated that it does not intend to address this proposed

amendment to Section 201.146 in this docket, the Board will not include the proposed

amendment to that section in its second notice order below.

415 ILCS 5/28.5(m) (2006).

Reflecting the Agency’s testimony at hearing and post-hearing comment, the Board finds that

permit exemption changes to Section 201.146(i) must be addressed in docket R07-19.

Part 211: Definitions and General Provisions

The Agency proposes to add new definitions to Part 211 and also to amend an existing

definition under the same Part. The proposed amendments to Part 211 are briefly described

Brakehorsepower (rated-bhp) (Section 211.740)

The Agency proposes to add a definition of “brakehorsepower (rated – bhp) at Section

211.740. The term is used to specify which engines would be subject to the requirements of

Subpart Q. Statement at 16. The Agency proposes to define the term as “the rated horsepower

capacity of the engine as defined on the engine nameplate at standard conditions.” PC 1, Att. A

Statement, Exh. 9.b.

Diesel Engine (Section 211.1740)

The Agency proposes to add a definition of “diesel engine” at Section 211.1740. “Diesel

engine” is defines as, “for the purposes of 35 Ill. Adm. Code 217, Subpart Q, a compression

ignited two- or four-stroke engine in which liquid fuel injected into the combustion chamber

The Board notes that Section 201.146(j) addresses “[r]est room facilities and associated cleanup operations, and

stacks or vents used to prevent the escape of sewer gases through plumbing traps.” 35 Ill. Adm. Code 201.146(j).

As the preceding subsection 210.146(i) addresses stationary internal combustion engines, and as the Agency

included subsection 210.146(i) in its original rulemaking proposal, the Board regards the reference to subsection (j)

as inadvertent and concludes that the Agency intends in the subsequent docket R07-19 to address Section

ignites when the air charge is compressed to a

temperature sufficiently high for auto-ignition.”

PC 1, Att. A at 21;

Statement, Exh. 9.b.

Emergency or Standby Unit (Section 211.1920)

The Agency proposes to add language to the existing definition of “emergency or standby

unit” at Section 211.1920. Statement at 16-17. Specifically, the proposed amendments clarify

that a unit being used to supplement power capacity is not an emergency or standby unit.

PC 1, Att. A at 21. Further, the proposed changes clarify “that testing the unit or verifying the

unit’s readiness for use does not disqualify the unit as an emergency or standby unit.” Statement

PC 1, Att. A at 21.

Lean-burn engine (Section 211.3300)

The Agency proposes to add a definition of “lean-burn engine” at Section 211.3300,

since that term is used to specify the control to which affected engines will be subject under the

requirements of Subpart Q. Statement at 17. The Agency proposes to define the term as “any

spark-ignited engine that is not a rich-burn engine.” PC 1, Att. A at 21; Statement, Exh. 9.b.

Rich-burn engine (Section 211.5640)

The Agency’s proposal includes a definition of “rich-burn engine” at Section 211.5640 to

specify the control to which affected engines will be subject under the requirements of Subpart

Q. Statement at 17. The Agency’s proposal defines the term as “a spark-ignited engine where

the oxygen content in the exhaust stream of the engine before any dilutions is 1 percent or less

by volume measured on a dry basis.” PC 1, Att. A at 22; Statement, Exh. 9.b.

In its post-hearing comments, the Agency characterized the proposed definitions as “a

necessary part of the proposal” and specifically requested that they “be included in the proposal

for adoption.” PC 1 at 5;

Tr. 1 at 9. The Board notes that it included these five

definitions in its first notice opinion and order on April 19, 2007 (

31 Ill. Reg. 6578; 31 Ill.

Reg. 7371 (correction of hearing date)). Based on a review of the record, the Board finds that

the amendment to Part 211 reflect the proposed intent and includes them in its order below for

Part 217: Nitrogen Oxides Emissions

Measurement Methods (Section 217.101)

Section 217.101 now provides three methods according to which NO

must be measured.

35 Ill. Adm. Code 217.101. The Agency proposes two types of amendments to this provision.

First, the Agency proposes to strike references to the dates on which USEPA last updated the

specified methods. Statement at 17;

PC 1, Att. A at 4. The Agency also proposes to add

cross-references to Section 217.104, which incorporates these procedures by reference and

provides specific dates for the incorporated procedures. Statement at 17;

PC 1, Att. A at 4.

Second, the Agency proposes to add a

measurement method for monitoring NO

portable monitors. Statement at 17;

PC 1, Att. A at 4. The Board notes that it included this

section in its first notice opinion and order on April 19, 2007.

31 Ill. Reg. 6597, 31 Ill. Reg.

The Agency characterizes this section as “a necessary part” of its proposal, as proposed

Section 217.394 “makes extensive use of the measurement methods that are proposed for

inclusion in Section 217.101.” PC 1 at 5;

Tr. 1 at 9. The Agency specifically requested

that this section “be included in the proposal for adoption.” PC 1 at 5. The Board agrees with

the Agency’s characterization and includes the proposed amendments to Section 217.101 in its

order below for second notice.

Abbreviations and Units (Section 217.102)

Section 217.102 now provides abbreviations and conversion factors used in Part 217.

35 Ill. Adm. Code 217.102. The Agency originally proposed “to add the abbreviations and

conversion factors used in Subpart Q and to correct the alphabetical order of the existing list.”

Statement at 17. The Board sent the proposed changes to first notice on April 19, 2007.

Ill. Reg. 6597, 31 Ill. Reg. 7372.

The Agency in its final comments notes that the Pipeline Consortium recommended

deleting the last three conversion factors listed in the Agency’s proposal at Section 217.102(b).

Statement, Exh. 9.c. The Agency states that, on the basis of its own review, it

“finds that these conversion factors are not necessary to other Subparts in Part 217 or for use in

Subpart Q” and therefore proposes to delete them.

., Att. A at 4-5.

The Agency characterizes the remaining amendments to Section 217.102 as “a necessary

part” of its proposal. PC 1 at 5;

Tr. 1 at 9. The Agency specifically requested that this

section “be included in the proposal for adoption.” PC 1 at 5. The Board agrees with the

Agency’s characterization and includes the proposed amendments to Section 217.102, as

amended in the Agency’s post-hearing comments, in its order below for second notice.

Incorporation by Reference (Section 217.104)

Section 217.104 now incorporates specified materials by reference.

Code 217.104. The Agency first proposes to update various incorporations by reference.

Statement at 17;

PC 1, Att. A at 6. The Agency also proposes to incorporate an ASTM

emissions testing method for portable monitors. Statement at 17;

PC 1, Att. A at 6. Finally,

the Agency also proposes to incorporate “test methods for NO

emissions from engines and

turbines.” Statement at 17;

PC 1, Att. A at 6. The Board sent the proposed changes to first

notice on April 19, 2007.

31 Ill. Reg. 6597, 31 Ill. Reg. 7372.

The Agency characterizes this section as “a necessary part” of its proposal, as proposed

Section 217.394 “makes extensive use of the measurement methods that are proposed for

inclusion in . . . Section 217.104.” PC 1 at 5;

Tr. 1 at 9. The Agency specifically

requested that this section “be included in the

proposal for adoption.” PC 1 at 5. The Board

agrees and includes the proposed amendments to Section 217.104 in its order below for second

Applicability (Section 217.386)

In its original proposal, the Agency proposed for this new section criteria establishing

whether a stationary reciprocating internal combustion engine or turbine is an affected unit

subject to the requirements of the proposed Subpart Q. Statement at 18; Statement, Exh. 9.c.

The Agency notes, however, that the Board’s May 17, 2007 order bifurcated the original

proposal and narrowed the scope of this rulemaking. PC 1 at 1. The Agency now proposes

revised language for this section, which in its entirety provides that “[a] stationary reciprocating

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

Subpart Q.” PC 1, Att. A at 6-7.

In his pre-filed testimony on behalf of the Pipeline Consortium for the second hearing in

this proceeding, Mr. McCarthy notes that the Agency’s TSD “implies a 1500 horsepower (“hp”)

size threshold for SIP Call engines,” but he states that “[l]arge NO

SIP Call engines are

considerably larger than the TSD implies.” McCarthy Test. at 3-4, citing TSD at 17. In its post-

hearing comments, the Agency addressed Mr. McCarthy’s claim by stating that “[t]he

applicability of the NO

SIP Call to large engines is based on the quantity of NO

ton) in 1995 summer day and is not based on the size of the engine in terms of rated brake

horsepower.” PC 1 at 2-3. Mr. McCarthy’s pre-filed testimony states that, “[a]ssuming a typical

uncontrolled NO

emission rate, for an internal combustion (IC) engine to be identified as a

Large SIP Call Engine in the 1995 inventory, a 2400 hp unit would require full utilization

throughout the ozone season to achieve a one ton per day average NO

emission rate.”

McCarthy Test. at 4.

Responding to a question at the second hearing, Mr. McCarthy acknowledged that the

proposed Appendix G lists no threshold for applicability of Subpart Q but “just lists the affected

engines.” Tr. 2 at 11-12. The Agency emphasizes that “each of the 28 NO

SIP Call-affected

engines is much larger than 1,500 bhp.” PC 1 at 3;

Tr. 2 at 11. The Agency further

emphasizes that the TSD supported its original proposal covering a much broader range of

engines and turbines and that that broader range is now addressed in R07-19. PC 1 at 3.

The Board finds that the changes proposed by the Agency to Section 217.386 are

appropriate since the scope of the instant rulemaking is limited to the engines listed in Appendix

G. Accordingly, the Board includes the proposed amendments to Section 217.386, as amended

in the Agency’s post-hearing comments, in its order below for second notice.

Control and Maintenance Requirements (Section 217.388)

In its original proposal, the Agency proposed for this new section new control and

maintenance requirements on owners or operators of affected units. Statement at 18-19;

Statement, Exh. 9.c. The Board sent the proposed changes to Section 217.388 to first notice on

April 19, 2007.

31 Ill. Reg. 6597, 31 Ill.

Reg. 7372. The Agency notes, however, that

the Board’s May 17, 2007 order bifurcated the original proposal and narrowed the scope of this

rulemaking. PC 1 at 1. The Agency now proposes revised language for this section. PC 1, Att.

A at 7-8. The revised language deletes the provision pertaining to low usage units at Section

217.388(c) and renumbers the inspection and maintenance provision at subsection (d) as

subsection (c).

First, the Agency proposes under subsection (a)(1) and (a)(2) that an “owner or operator

must limit the discharge from an affected unit into the atmosphere of any gases that contain

” to separate concentration limits for spark-ignited rich-burn engines and spark-ignited lean-

burn engines. PC 1, Att. A at 7. The Agency proposes to delete emission limits for Worthington

engines, diesel engines, and turbines initially proposed at subsection (a)(3) through (a)(6).

Second, the Agency proposes in subsection (b) that “owners and operators be allowed the

option of complying with an emissions averaging plan instead of concentration limits.”

Statement at 18;

PC 1, Att. A at 7; Statement, Exh. 9.c. Emissions averaging plans are

addressed below in proposed Section 217.390.

Third, the Agency deletes the provision pertaining to low usage units at Section

217.388(c) and renumbers the inspection and maintenance provision at subsection (d) as

subsection (c). PC 1, Att. A at 7-8. For units not located at a natural gas transmission

compressor station or storage facility, the inspection and maintenance according to a plan based

in the manufacturer’s recommendation. PC 1, Att. A at 7. In the event that the original

equipment manual is not available or substantial modifications require an alternate plan, the

Agency proposes that the inspection and maintenance be performed according to “what is

customary for the type of air pollution control equipment, monitoring device, and affected unit.”

PC 1, Att. A at 7. For units located at a natural gas transmission compressor station or storage

facility, owners and operators follow “the operator’s maintenance procedures for the applicable

air pollution control device, monitoring device, and affected unit.” PC 1, Att. A at 7-8.

The Board finds that the proposed changes to Section 217.388 are appropriate in light of

the narrowed scope of the instant rulemaking and includes Section 217.388, as amended in the

Agency’s post-hearing, in its order below for second notice.

Emissions Averaging Plan (Section 217.390)

In its original proposal, the Agency proposed for this new section language regarding

emissions averaging plans. Statement at 19-21; Statement, Exh. 9.c. Generally, the Agency

proposes “that owners and operators may comply with an emissions averaging plan in lieu of

meeting the specified concentration limit for each affected unit set forth in Section 217.388.”

Statement at 19. The Agency notes, however, that the Board’s May 17, 2007 order bifurcated

the original proposal and narrowed the scope of this rulemaking. PC 1 at 1. The Agency now

proposes revised language for this section. PC 1, Att. A at 8-13.

First, the Agency proposes under

subsection (a)(1) to describe units that

commenced operation before January 1, 2002 that may be included in an emissions averaging

plan. PC 1, Att. A at 8. Those include units located in Illinois so long as the units are owned by

the same company or parent company and are not included in more than one emissions averaging

. Under subsection (a)(2), the Agency proposes to describe units that may not be

included in an emissions averaging plan.

. Ineligible units are “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.”

. In its post-hearing comment, the Agency notes that

a cross reference in subsection (a)(2) to Section 217.396(d)(3) must change to Section

217.396(c)(3) “due to more limited applicability of the proposal to only NO

SIP Call engines.”

PC 1 at 6; PC 1, Att. A at 8. The Agency also deletes the provisions at Sections

217.390(a)(1)(B) and (a)(2)(B), as those provisions do not apply to the Appendix G units to

which this docket applies as a result of the Board’s bifurcation of the Agency’s original proposal.

Second, the Agency proposes under subsection (b) to provide requirements for

submitting an emissions averaging plan. PC 1, Att. at 8. An owner or operator must submit a

plan by the applicable compliance date set forth in proposed Section 217.392 below.

plan must list “affected units included in the plan by nit identification number and permit

. In addition, an owner or operator must demonstrate compliance through a sample

calculation using the methodology provided in subsection (f).

Third, the Agency proposes under subsection (c) to address amendment of emissions

averaging plans. PC 1, Att. A at 8. That proposed provision provides that “[a]n owner or

operator may amend an emissions averaging plan only once per calendar year.”

provides that, “[i]f an amendment for a calendar year is going to be submitted, it must be

submitted no later than May 1 of the applicable year; otherwise, the plan from the previous year

will be the applicable plan.” Statement at 20;

PC 1, Att. A at 8.

Fourth, the Agency proposes under subsection (d) to require that, “if an affected unit

included in a plan is sold or taken out of service, the owner or operator, and the buyer, if

applicable, must submit an updated emissions averaging plan within 60 days of the occurrence.”

Statement at 20;

PC 1, Att. A at 8-9. The Agency deletes the provision at Section

217.390(d)(2), as that provision does not apply to the Appendix G units to which this docket

applies as a result of the Board’s bifurcation of the Agency’s original proposal.

Fifth, the Agency proposed under subsection (e) to require an owner or operator to

demonstrate compliance both for the ozone season and for the calendar year. PC 1, Att. A at 9.

The Agency also proposes to require that owners and operators must “[n]otify the Agency by

October 31 following the ozone season, if compliance cannot be demonstrated for that ozone

Statement at 20-21. The Agency also proposes to require that owners and

operators must submit a compliance report by January 31 following each calendar year. PC 1,

Att. A at 9. In its post-hearing comment, the Agency notes that a cross reference subsections

addressing emissions averaging plans was “incomplete.” PC 1 at 6. Accordingly, the Agency

proposes to add to the existing cross reference

to subsection (b) cross references to subsection

(c) and (d). PC 1 at 6; PC 1, Att. A at 9.

Sixth, the Agency proposes under subsection (f) to establish the formula for

demonstrating compliance through an emissions averaging plan. PC 1, Att. A at 9-10. Under

this provisions, “[t]he total mass of NO

emissions from the units listed in the emissions

averaging plan must be equal to or less than the total mass of allowable NO

emissions for those

unites for both the ozone seasons and calendar year.”

. at 9. In its post-hearing comment, the

Agency notes that “the references to total mass of allowable emissions EM

and total mass of

actual emissions EM

include in some cases redundant references and, in other, fail to include

relevant references within this subsection.” PC 1 at 6-7. Specifically, with regard to the total

mass of allowable NO

emissions, the Agency proposes to strike references to subsections (g)(3),

(g)(4), and (g)(5) and to add a reference to subsection (h)(2).

., Att, A at 9. With regard to

the total mass of actual NO

emissions, the Agency proposes to strike references to subsection

(g)(3) and (g)(5) and to amend a reference to subsection (h) to refer to subsection (h)(1).

., Att. A at 9.

Seventh, the Agency proposes under subsection (g)(1) the equation for determining

affected units’ actual NO

emissions for each fuel used. PC 1, Att. A at 10. The Agency

proposes under subsections (g)(2) the equation for determining affected units’ allowable NO

emissions for each fuel used. PC 1, Att. A at 10-11. In its post-hearing comment, the Agency

states that, within this equation, “the references to total mass of allowable emissions EM

total mass of actual emissions EM

and allowable concentration C

fail to include the

relevant references within this subsection. PC 1 at 7. The Agency proposes to amend this

provision to include specific reference within this subsection.

, Att. A at 10.

In addition, the Agency proposes under subsection (g)(3) “a specific formula for electric

replacement units” and under subsection (g)(4) “a formula for non-electric replacement units.”

Statement at 21;

PC 1, Att. A at 11-12. In its post-hearing comment, the Agency states that

subsection (g)(4) contains “language that no longer has an application and should be deleted.”

PC 1 at 7; PC 1, Att. A at 12.

The Agency proposes under subsection (g)(5) “a formula for units that have been

replaced through the purchase of power.” Statement at 21;

PC 1, Att. A at 12. This proposed

subsection also proposes that “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.”

PC 1, Att. A at 12. Finally, the Agency proposes under subsection (g)(6) a formula for units that

are not listed in Appendix G but are used in an emissions averaging plan.

Eighth, the Agency proposes under subsection (h) “conditions for units using

C[ontinuous] E[missions] M[onitoring] S[ystem] in lieu of stack testing an portable monitoring.”

Statement at 21;

PC 1, Att. A at 12-13. Subsection (h)(1) and (h)(2) address actual NO

emissions and allowable NO

emissions, respectively. PC 1, Att. A at 13. In its post-hearing

comment, the Agency proposes a technical correction in the equation for determining allowable

emissions. PC 1 at 8; PC 1, Att. A at 13.

Specifically, the Agency states that “the

subscript below the summation sign should be ‘j’ not ‘i.’” PC 1 at 8 (noting that Agency’s word

processing program does not allow underlined indication of this proposed amendment); PC 1,

The Board finds that the proposed emissions averaging plan provides flexibility to

sources in complying with the regulations. As determined by the Agency, most engines and

turbines will be able to comply with the proposed NO

emission limits. However, the Board

believes that the emissions averaging plan provides a mechanism for compliance for those

engines and turbines that may experience difficulty in achieving the emission limits. The Board

includes Section 217.390, as amended in the Agency’s post-hearing comments, in its order

below for second notice.

Compliance (Section 217.392)

The Agency’s initial filing on April 6, 2007 proposed a compliance date of May 1, 2007.

Statement, Exh. 9.c. In its post-hearing comment, the Agency notes that “[t]he compliance date

initially proposed by the Illinois EPA has passed. If the Board adopted that initially proposed

date, it would result in a retroactive compliance date; hence, the Illinois EPA is recommending a

new compliance date of January 1, 2008.” PC 1 at 8; PC 1, Att. A at 13; Kaleel Test. at 4. The

Agency also proposes to strike language regarding exemption from the requirements of Subpart

Q that the Board is no longer no longer considering in this docket. PC 1 at 8; PC 1, Att. A at 13.

This proposed section provides that, 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.” PC 1, Att. A at 13. The Board agrees with the Agency

that the compliance date needs to be moved forward in order to avoid retroactive application of

the rules and adopts the new compliance date of January 1, 2008 for second notice.

Testing and Monitoring (Section 217.394)

In its original proposal, the Agency proposed for this new section language regarding

testing and monitoring. Statement at 22-23; Statement, Exh. 9.c. The Agency notes, however,

that the Board’s May 17, 2007 order bifurcated the original proposal and narrowed the scope of

this rulemaking. PC 1 at 1. The Agency now proposes minor revisions to Section 217.394 that

reflect the change in scope of the rulemaking. PC 1, Att. A at 13-15.

Generally, proposed subsection (a) establishes requirements regarding initial

performance testing.

PC 1, Att. A at 13-14. Proposed subsection (a)(1) requires that engines

listed in Appendix G must undergo an initial performance test.

. at 13. In its post-hearing

comments, the Agency states that, in this proposed subsection (a), “language referring to units

not included in Appendix G or an averaging plan, or compliance dates other than January 1,

2008, should be deleted.” PC 1 at 8; PC 1, Att. A at 13-14. The proposed subsection further

provides that these “[p]erformance tests must be conducted on units listed in Appendix G, even

if the unit is included in an emissions averaging plan.”

Proposed subsection (a)(2) provides,

with regard to units that are not affected units

but are included in an emissions averaging plan and operate more than 876 hours per calendar

year, that this testing must occur within the first 876 hours of operation per calendar year.

13-14. In its post-hearing comment, the Pipeline Consortium states that, in this subsection

(a)(2), the first comma and the phrase “whichever is later” should be deleted “since multiple

dates no not apply in this rulemaking.” PC 2 at 3;

PC 1, Att. A at 14. This suggestion is

incorporated in the Agency’s revisions.

Proposed subsection (a)(3) requires, with regard to “units that are not affected units that

are included in an emissions averaging plan and that operate fewer than 876 hours per calendar

year” must undergo testing once within the five-year period after the compliance date.

In revising this subsection of its original proposal, the Agency states that “language referring to

units not included in Appendix G or an averaging plan, or compliance dates other than January 1,

2008, should be deleted.” PC 1 at 8;

PC 1, Att. A at 13-14.

Generally, proposed subsection (b) establishes requirements regarding subsequent

PC 1, Att. A at14. Proposed subsection (b)(1) provides, with regard to units either

listed in Appendix G or included in an emissions averaging plan, that that they must undergo

testing once every five years.

. The proposed subsection further provide that “[t]esting must

be performed in the calendar year by May 1 or within 60 days of starting operation, whichever is

. Proposed subsection (b)(2) provides that an owner or operator must notify the

Agency within 30 days if monitored data shows that the unit does not comply with the applicable

emissions concentration limit or emissions averaging plan.

. The proposed subsection also

requires the owner or operator to conduct a performance test “within 90 days of the

determination of noncompliance.”

. Finally, proposed subsection (b)(3) provides that, when

the Agency or USEPA form the opinion that testing is necessary to demonstrate compliance, the

owner or operator must conduct that testing at his or her own expense within 90 days of

receiving a notice to test from the Agency or USEPA.

Generally, proposed subsection (c) establishes testing procedures.

PC 1, Att. A at 14.

Proposed subsection (c)(1) provides that owners and operators of engines must conduct testing

“using Method 7 or 7E of 40 C.F.R. 60, Appendix A, as incorporated by reference in Section

. The proposed subsection further provides that tests must include three separate

runs with a duration of at least 60 minutes each.

. The proposed subsection further provides

emissions must be measured while the affected unit is operating at peak load.”

Finally, the proposed subsection provides, with regard to units that combust more than one type

of fuel, that separate performance tests are required for each of those fuels.

subsection (c)(2) provides that owners and operators of turbines included in an emissions

averaging plan must perform testing according to the provisions on 40 C.F.R. 60.4400, as

proposed for incorporation by reference in Section 217.104.

Generally, proposed subsection (d) establishes monitoring procedures.

at 15. The proposed subsection provides that owners and operators of affected units or units

included in an emissions averaging plan must monitor NO

concentrations annually, except for

years in which a performance test is conducted.

. For units that operate less than 876 hours

per calendar year, the proposed subsection

requires this monitoring at least once every

. Proposed subsection (d)(1) requires that this monitoring be performed method

ASTM D6522-00, as proposed for incorporation by reference in Section 217.104, or a method

approved by the Agency.

. The proposed subsection further requires that, “[I]f the unit

combusts both liquid or gaseous fuels as primary or backup fuels, separate monitoring is

required for each fuel.”

. Proposed subsection (d)(2) requires that “[m]easurements of NO

concentrations must be taken three times for a duration of at least 20 minutes while the

unit is operating at the highest achievable load.” Statement at 23;

PC 1, Att. A at 15.

Generally, proposed subsection (e) addresses a continuous emissions monitoring system

(CEMS). The proposed subsection that units equipped with a CEMS meeting specified federal

requirements or following alternate procedures approved by the Agency or USEPA in a federally

enforceable permit are not required to meet the compliance testing and monitoring requirements

of this section. PC 1, Att. A at 15.The proposed subsection requires compliance on ozone season

and on an annual basis.

The Board finds that the proposed provisions for performance testing of the affected

engines provide for ongoing demonstration of compliance with the requirements of the proposed

regulations. Further, the Board notes that the proposed regulations prescribe USEPA-approved

methods for testing and monitoring of the performance of an affected engine. The Board

includes Section 217.394, as amended in the Agency’s post-hearing comments, in its order

below for second notice.

Recordkeeping and Reporting (Section 217.396)

In its original proposal, the Agency proposed for this new section language regarding

recordkeeping and reporting. Statement at 23-24; Statement, Exh. 9.c. The Agency notes,

however, that the Board’s May 17, 2007 order bifurcated the original proposal and narrowed the

scope of this rulemaking. PC 1 at 1. The Agency now proposes minor revisions to Section

217.396 that reflect the change in scope of this rulemaking. PC 1, Att. A at 15-18.

Proposed subsection (a) establishes requirements regarding recordkeeping.

Att. A at 15-16. The owner or operator of a unit listed in Appendix G or included in an

emissions averaging plan must maintain records that demonstrate compliance with the

requirements of Subpart Q.

. at 15. These records include, but are not limited to, data such as

hours of operation, test results, and logs of inspections and maintenance.

. at 16. In its post-

hearing comment, the Agency notes that, [i]n Section 217.396(a) the sentence pertaining to

exempt units and low usage units should be struck as those porvisions are no longer included in

the proposal.” PC 1 at 8; PC 1, Att. A at 15. In the same comment, the Agency states that a

cross reference in subsection (a)(7) to Section 217.388(d) must change to Section 217.388(c)

“due to more limited applicability of the proposal to only NO

SIP Call engines.” PC 1 at 6;

PC 1, Att. A at 16.

Proposed subsection (b) provides that an owner or operator of an affected unit or a unit

included in an emissions averaging plan must maintain the records required by proposed

subsection (a) for five years. PC 1, Att. A at

16. The proposed subsection also provides

that “[t]he records must be made available to the Agency and USEPA upon request.”

post-hearing comment, the Agency states that this subsection contains an incorrect cross

reference. PC 1 at 9. Specifically, the agency proposes to delete a cross reference to subsection

., Att. A at 16.

Proposed subsection (c) provides deadlines by which an owner or operator must provide

to the Agency notification of testing, a testing protocol, test results, monitored exceedences of

the applicable NO

concentration, and permanent shutdowns. PC 1, Att. A at 16-17. The

proposed subsection also provides deadlines by which an owner or operator must provide

notification that he or she cannot demonstrate compliance for the ozone season and submit a

compliance plan containing specified data.

. at 17-18. The proposed subsection also provides

that, in an owner or operator operates a CEMS, he or she is required to submit an excess

emissions and monitoring systems performance report according to federal requirements.

18. In its post-hearing comment, the Agency states that this subsection contains an incorrect

cross reference. PC 1 at 9. Specifically, the agency proposes to add a cross reference to

subsection (b).

., Att. A at 16.

The Board finds that the proposed recordkeeping and reporting requirements are

adequate for ensuring the Agency’s oversight. The Board includes Section 217.396, as amended

in the Agency’s post-hearing comments, in its order below for second notice.

The Agency states that, “[i]n Appendix G, Illinois EPA is proposing to add a list of the

SIP Call engines based on how the unit is listed in the most recent permit issued or

construction permit application submitted.” Statement at 24;

PC 1, Att. A at 19-20.

The Agency characterizes this Appendix G as “a necessary part” of its proposal. PC 1 at

5. The Agency specifically requested that this appendix “be included in the proposal for

. The Board notes that it included this section in its first notice opinion and order

on April 19, 2007 (

31 Ill. Reg. 6597; 31 Ill. Reg. 7372 (correction of hearing date)), and the

Board includes the proposed Appendix G in its order below for second notice.

TECHNICAL AND ECONOMIC CONSIDERATIONS

The Agency addressed the technical feasibility and economic reasonableness of the

proposed regulations in the TSD and its testimony. The Agency relied upon documents

published by USEPA and the State and Territorial Air Pollution Program

Administrators/Association of Local Air Pollution Control Officials for their information on

control technology and economic impacts. In testimony pre-filed for the second hearing, the

Pipeline Consortium raised items relating generally to the technical feasibility and economic

reasonableness of the Agency’ s proposal.

415 ILCS 5/27(a) (2006). The Board below

addresses those items, including the response of the Agency as the proponent of this proposal.

Annual Compliance

In his pre-filed testimony on behalf of the consortium, Mr. McCarthy notes that, while

USEPA’s Phase II rules addresses only the ozone season, “[t]he IEPA proposal includes both

ozone season and annual requirements, with associated reporting and recordkeeping.” McCarthy

Test. at 7. Mr. McCarthy characterizes these annual requirements as “an additional compliance

Addressing this issue, Mr. McCarthy notes that “the control strategies employed by the

natural gas companies are operational whenever the unit operates, and so emissions reduction

will not be limited to the ozone season.” McCarthy Test. at 7. Referring specifically to the

strategy of low-emission combustion (LEC), Mr. McCarthy stated that it becomes inherent to the

engine once it is installed and cannot be turned on and off. Tr. 2 at 16. Although the Pipeline

Consortium notes that its engines typically work most heavily during the winter months outside

the ozone season (Tr. 2 at 41), and that the proposed annual compliance poses a higher

possibility for noncompliance, “none of the companies comprising the Pipeline Consortium

anticipate compliance difficulties.” PC 2 at 2. Furthermore, counsel for the consortium stated at

hearing that it had no objection to the annual applicability of the rule. Tr. 2 at 18, 21.

Application of Selective Catalytic Reduction (SCR)

In his pre-filed testimony for the consortium, Mr. McCarthy notes that the Agency’s TSD

includes SCR as an emissions control technology applicable to internal combustion engines.

McCarthy Test. at 7. He further claims that, “to date, SCR has not been successfully applied to

gas transmission units, and USEPA has acknowledged this limitation.”

. at 7-8, citing 67 Fed.

Reg. 8395, 8411 (Feb. 22, 2002). Mr. McCarthy also opines that the Agency’s TSD lists NO

control technologies such as ignition timing retard and prestratified charge, which may apply

only questionably to natural gas-fired internal combustion engines. McCarthy Test. at 8.

In response, the Agency notes USEPA’s acknowledgement that SCR has not yet been

widely demonstrated in the United States on lean-burn internal combustion engines in variable

load operation. PC 1 at 3, citing Statement, Att. 11.g at 14-15 (TSD for NO

at 26. The Agency states, however, that “SCR technology is very effective and provides 90

emission reductions from all other engines, such as lean-burn engines operating at

constant load, diesel engines and dual fuel-fired engines.” PC 1 at 2, citing Statement, Att. 11.c

at 5-55 (USEPA Alternative Control Techniques Document). The Agency nonetheless

emphasizes that its proposal “does not require installation of SCR or any other particular

technology to comply with the proposal” and that “[o]wners and operators have the discretion to

choose the most cost-effective technology or compliance option.” PC 1 at 4;

Tr. 1 at 28, Tr.

Cost-Effectiveness

In his pre-filed testimony for the Pipeline Consortium, Mr. McCarthy states that, with

regard to the cost and cost-effectivess of NO

emission controls, “[t]he TSD indicates that a

$5000 per ton basis is used for IC engines

SIP Call.” McCarthy Test. at 8,

citing TSD at 40. Mr. McCartyh argues that this is not consistent with the 1998 SIP Call Rule or

with the 2004 Phase II Rule.

., citing 63 Fed. Reg. 21604, 21618 (April 21, 2004). Mr.

McCarthy further argues that USEPA in the Phase II Rule “determined that an average of

approximately $2,000 per ton removed is highly cost effective.” McCarthy Test. at 8, citing 69

Fed. Reg. 21604, 21618 (April 21, 2004). Mr. McCarthy characterizes the difference between

the Agency’s figure and the SIP Call as “significant.” McCarthy Test. at 8.

In response, the Agency characterizes Mr. McCarthy’s testimony that a $5,000 per ton

rate is used as internal combustion engines under the NO

SIP Call as incorrect. PC 1 at 4. The

Agency first notes that Mr. McCarthy refers to information obtained from a USEPA regulatory

impact analysis. PC 1 at 4, citing Statement, Att. 11.f. The Agency claims that USEPA

evaluated the cost effectiveness of control at per ton cost ceilings of $1,500, $2,000, $3,000,

$4,000, and $5,000 under the NO

SIP Call Phase I. PC 1 at 4. The Agency argues that

“USEPA selected the $5,000 alternative when it evaluated a 90 percent reduction from the 2007

emissions baseline.”

. When USEPA adopted an 82 percent reduction from that 2007

baseline, it obtained a cost effectiveness of approximately $542 per ton.

. at 4-5, citing

Statement, Att. 11.g at 34;

Agency Testimony

In his testimony on behalf of the Agency, Mr. Mahajan relied on sources published by

USEPA and the State and Territorial Air Pollution Program Administrators/Association of Local

Air Pollution Control Officials for their information on the costs and economic impacts of this

proposal. Mahajan Test. at 2-3, citing Statement, Exhs. 11.c, 11.e, 11.f, 11.g. Mr. Mahajan

stated that a review of these sources led the Agency to conclude “that there are cost effective

control techniques available to reduce NO

emissions” from reciprocating internal

combustion engines.

. at 3. Specifically, Mr. Mahajan stated that review of updated USEPA

data led the Agency to conclude that the cost of controlling engines affected by the NO

during the ozone season “would be $552 (1990 dollars) per ton of NO

Statement, Att. 11.g at 34. He further stated that the cost of controlling those engines would be

lower on an annual basis. Mahajan Test. at 4

Pipeline Consortium Testimony

In his pre-filed testimony on behalf of the Pipeline Consortium, Mr. McCarthy stated that

the natural gas industry’s trade association took part in USEPA’s adoption of the Phase II rule

and the development of a model rule to assist states in developing SIPs. McCarthy Test. at 6.

The Pipeline Consortium has also cooperated with the Agency “since 2005 to integrate

provisions consistent with federal guidance and the model rule into the IEPA proposal.”

PC 2 at 2, Statement at 15. Mr. McCarthy states that, with knowledge of federal requirements,

the eight natural gas facilities that operate NO

SIP Call engines in Illinois have “initiated

projects to install emission controls and reduce NO

in conformance with the federal program

intent.” McCarthy Test. at 6. Specifically, “the affected natural gas companies have proactively

initiated reduction programs and compliance plans for the units in Appendix G of the proposal.”

. The Pipeline Consortium states in its post-

hearing comment that it “has been proactive in

complying with the rule even prior to its adoption by the Board.” PC 2 at 2, citing McCarthy

Test. at 6. Consequently, Mr. McCarthy testified that “the Pipeline Group does not object to the

Subpart Q proposal under consideration.” McCarthy Test. at 7; Tr. 2 at 41. The Pipeline

Consortium reiterated this position in its post-hearing comment. PC 2 at 3. In addition, Mr.

McCarthy testified that “[t]his proactive approach by natural gas companies has culminated in a

workable proposal and will assist IEPA in addressing federal obligations under the NO

Phase II Rule.” McCarthy Test. at 9.

Board Finding

The Board finds the proposed regulations are technically feasible and economically

reasonable. The Board notes that both combustion and post-combustion controls are available

for reducing NO

emissions from reciprocating internal combustion engines. Further, the Board

finds that the affected sources can comply with the proposed NO

emission reductions at a

reasonable cost. The record indicates that some of the affected sources have already initiated

projects to install emission controls to educe NO

emissions. Lastly, the Board notes that the

rules provide compliance flexibility by allowing emissions averaging and the discretion to

choose the most effective control technology.

The Board finds that, as now modified according to the Board’s May 17, 2007 order and

the testimony and comments of the proponent and participants in the record of this proceeding,

the Agency’s proposal for the control of NO

emissions from stationary internal combustion

engines affected by the NO

SIP Call Phase II and the program for implementing it are

technologically feasible and economically reasonable. The Board has also made a limited

number of technical changes that do not merit substantive discussion. Accordingly, the Board

adopts for second notice the following order.

The Board directs the Clerk to cause publication of the following proposed amendments

Illinois Register

for second notice. Proposed additions to Parts 211 and 217 are

underlined, and proposed deletions appear stricken.

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

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

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. _______, effective ____________.

SUBPART B: DEFINITIONS

Section 211.740

Brakehorsepower (rated-bhp)

“Brakehorsepower” or “bhp” means the rated horsepower capacity of the engine as defined on

the engine nameplate at standard conditions.

(Source: Added at 31 Ill. Reg._____________, effective ______________)

Section 211.1740

“Diesel engine” means for the purposes of 35 Ill. Adm. Code 217, Subpart Q, a compression

ignited two- or four-stroke engine in which liquid fuel injected into the combustion chamber

ignites when the air charge is compressed to a temperature sufficiently high for auto-ignition.

(Source: Added at 31 Ill. Reg._____________, effective ______________)

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 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.; or

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 standby use.

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 31 Ill. Reg._____________, effective ______________)

Section 211.3300

Lean-Burn Engine

“Lean-burn engine” means any spark-ignited engine that is not a rich-burn engine.

(Source: Added at 31 Ill. Reg._____________, effective ______________)

Section 211.5640

Rich-Burn Engine

“Rich-burn engine” means a spark-ignited engine where the oxygen content in the exhaust

stream of the engine before any dilutions is 1 percent or less by volume measured on a dry basis.

(Source: Added at 31 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

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

CONTROL AND TRADING PROGRAM FOR

GENERATING UNITS

Compliance Requirements

Permitting Requirements

Methodology for Obtaining NO

Methodology for Determining NO

Allowances from the New Source Set-Aside

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 NO

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

TRADING PROGRAM FOR ELECTRICAL

GENERATING UNITS

Compliance Requirements

Permitting Requirements

Methodology for Calculating NO

Allocations for Budget Electrical

Generating Units (EGUs)

Allocations for Budget EGUs

New Source Set-Asides for “New” Budget EGUs

Early Reduction Credits for Budget EGUs

Budget Opt-In Units: Withdrawal from NO

Trading Program

Opt-In Units: Change in

Regulatory Status

Allowance Allocations to Budget Opt-In Units

SUBPART X: VOLUNTARY NO

EMISSIONS REDUCTION PROGRAM

Emission Unit Eligibility

Participation Requirements

Emission Reductions and the Subpart X NO

Baseline Emissions Determination

Calculation of Creditable NO

Emission Reductions

Limitations on NO

Emission Reductions

Emission Reduction Proposal

Emissions Determination Methods

Emissions Monitoring

APPENDIX A Rule into Section Table

APPENDIX B Section into Rule Table

APPENDIX C Compliance Dates

APPENDIX D Non-Electrical Generating Units

APPENDIX E Large Non-Electrical Generating Units

APPENDIX F Allowances for Electrical Generating Units

APPENDIX G Existing Reciprocating Internal Combustion Engines Affected by the NO

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

Environmental Protection Act [415 ILCS 5/9.9, 10, 27 and 28.5 (2004)].

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. ___________, effective _______________.

SUBPART A: GENERAL PROVISIONS

Section 217.101

Measurement Methods

Measurement of nitrogen oxides must be according to:

The phenol disulfonic acid proceduresmethod, 40 CFR 60, Appendix A, Method

7, as incorporated by reference in Section 217.104(1999);

Continuous emissions monitoring pursuant to 40 CFR 75, as incorporated by

reference in Section 217.104(1999); and

Determination of Nitrogen Oxides Emissions from Stationary Sources

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

incorporated by reference in Section 217.104;(1999).

Monitoring with portable monitors pursuant to ASTM D6522-00, as incorporated

by reference in Section 217.104; and

How do I conduct the initial and subsequent performance tests (for turbines),

pursuant to 40 CFR 60.4400, as incorporated by reference in

Section 217.104.

(Source: Amended at 31 Ill. Reg._________, effective ________________)

Section 217.102

Abbreviations and Units

The following abbreviations are used in this Part:

American Society for Testing and Materials

British thermal unit (60

brake horsepower

continuous emissions monitoring system

Electrical Generating Unit

dry standard cubic feet

grams per brake horsepower-hour

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

Nitrogen Oxides

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

megagram or metric tonne

million British thermal units

million British thermal units per hour

megawatt of electricity

megawatt; one million watts

Allowance Tracking System

nitrogen dioxide

nitrogen oxides

pounds per square inch absolute

potential electrical output capacity

potential to emit

parts per million

parts per million by volume

The following conversion factors have been used in this Part:

1 lb/mmBbtu 1.548 kg/MW-hr

1 mmBtu/hr 0.293 MW

1 mmBtu/hr 393 bhp

(Source: Amended at 31 Ill. Reg._________, effective ________________)

Section 217.104

Incorporations by Reference

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

later amendments or editions.

The phenol disulfonic acid proceduresmethod

, as published in 40 CFR 60,

Appendix A, Method 7 (2000)(1999);

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

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

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

40 CFR 60, 72, 75 & 76 (2006)(1999);

Alternative Control Techniques Document---- NO

Emissions from Cement

Manufacturing, EPA-453/R-94-004, U. S. Environmental Protection Agency-

Office of Air Quality Planning and Standards, Research Triangle Park, N.C.

27711, March 1994;

Section 11.6, Portland Cement

Manufacturing, AP-42 Compilation of Air

Emission Factors, Volume 1: Stationary Point and Area Sources, U.S.

Environmental Protection Agency-Office of Air Quality Planning and Standards,

Research Triangle Park, N. C. 27711, revised January 1995;

40 CFR § 60.13 (2001)(1999); and

40 CFR 60, Appendix A, Methods 3A, 7, 7A, 7C, 7D, and 7E, 19, and 20

ASTM D6522-00, Standard Test Method for Determination of Nitrogen Oxides,

Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-

Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters

Using Portable Analyzers (2000);

Standards of Performance for Stationary Combustion Turbines, 40 CFR 60,

Subpart KKKK, 60.4400 (2006); and

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

Point and Area Sources (2000), USEPA.

(Source: Amended at 31 Ill. Reg._________, effective ________________)

SUBPART Q: STATIONARY RECIPROCATING INTERNAL COMBUSTION ENGINES

Section 217.386

A stationary reciprocating internal combustion engine

listed in Appendix G of this Part is subject

to the requirements of this Subpart Q.

(Source: Added at 31 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 (dc) of this

Section and comply with 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 limit the discharge from an affected unit into the

atmosphere of any gases that

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 comply with the requirements of the applicable

emissions averaging plan as set forth in Section 217.390.

The owner or operator must operate 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 (c). Only one of the following exemptions

may be utilized at a particular source:

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-hr/MW-hr 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 not located at a natural

gas transmission compressor station or storage facility that drive a natural

gas compressor station, the operation limits of subsections (c)(2)(A) and

(B) of this Section must be contained in a federally enforceable permit.

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 inspect and perform 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: Added at 31 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 an emissions averaging plan as follows:

Units units 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 listed in only one emissions averaging plan.;

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 exempt. For as long as

such a 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 a low usage unit 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. 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

An owner or operator may amend an emissions averaging plan only once per

calendar year. An amended plan must be submitted to the Agency by May 1 of

the applicable calendar year. 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 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), (c), or

(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

217.396(dc)(4).

The total mass of actual NO

emissions from the units listed in the emissions

averaging plan must be equal to or less than the total mass of allowable NO

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 NO

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 NO

mass emissions from units

included in the averaging plan for each fuel used (lbs

per ozone season and calendar year).

mass of allowable NO

emissions in lbs for a

determined in subsection (g)(2), (g)(3)

, (g)(4), (g)(5),or

or (h)(2) of this Section.

Total mass of actual NO

emissions in lbs for a unit as

determined in subsection (g)(1), (g)(3), (g)(5) or (h)(1) of

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 NO

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 NO

emissions in lbs for a unit, except

as provided for in subsections (g)(3) and (g)(5) of this

Total mass of allowable NO

emissions in lbs for a unit,

except as provided for in subsection (g)(3) of this Section.

emission rate (lbs/mmBtu) calculated

according to the above equation.

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

Actual concentration of NO

in lb/dscf (ppmv x 1.194 x

) on a dry basis for the fuel used. Actual concentration

is determined on each of the most recent test run or

monitoring pass performed pursuant to Section 217.394,

whichever is higher.

Allowable concentration of NO

in lb/dscf (allowable

emission limit in ppmv specified in Section 217.388(a),

except as provided for in subsections (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, Appendix A,

Method 19 or as determined using 40 CFR 60, Appendix

Concentration of oxygen in effluent gas stream measured

on a dry basis during each of the applicable test 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 NO

emissions from the affected unit that was replaced should be used in the

averaging calculations and the actual NO

emissions for the electric-

powered replacement unit (EM

) are zero. Allowable NO

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 NO

emission rate in lb/bhp-hr of the replaced unit.

The allowable mass of NO

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 NO

emission rate of the replaced

) in lb/mmBtu converted to lb/bhp-hr. For this calculation the

following equation should be used:

Mass of allowable NO

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 year.

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 either:

Prior to the applicable compliance date for the replaced unit

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 Area Sources, as incorporated by reference in Section 217.104

for the unit that was replaced; or .

On and after the applicable compliance date for the replaced unit

pursuant to Section 217.392, the applicable emissions

concentration for the type of unit that replaced pursuant to Section

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 shutdown

averaged over the three-year period prior to the shutdown. The actual

emissions for the units replaced by purchased power (EM

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.

later compliance date, For non-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

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; and

On and after the units 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 NO

emissions determined pursuant to subsection (h)(1) of this Section is less than or

equal to the allowable NO

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 NO

emissions in lbs for a unit (EM

the sum of the total mass of actual NO

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: Added at 31 Ill. Reg.

_______________, effective

__________________.)

Section 217.392

An owner or operator of an affected unit may not operate that unit unless it meets

the applicable concentration limit in Section 217.388(a), or is included in an

emissions averaging plan pursuant to Section 217.388(b), or meets the low usage

requirements pursuant to Section 217.388(c), and complies with all other

applicable requirements of this Subpart Q by the earliest applicable date listed

On and after May 1, 2007January 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).;

On and after January 1, 2009, an owner or operator of an affected unit and

that is located in Cook, DuPage, Aux Sable Township and Goose Lake

Township in Grundy, Kane, Oswego Township in Kendall, Lake,

McHenry, Will, Jersey, Madison, Monroe, Randolph Township in

Randolph, or St. Clair County, and 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);

On and after January 1, 2011, an owner or operator of an affected engine

with a nameplate capacity rated at 1500 bhp or more, and affected turbines

rated at 5 MW (6,702 bhp) or more that is not subject to subsection (a)(1)

or (a)(2) of this Section, 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); or

On and after January 1, 2012, an owner or operator of an affected engine

with a nameplate capacity rated at less than 1500 bhp or an affected

turbine rated at less than 5 MW (6,702 bhp) that is not subject to

subsection (a)(1), (a)(2) or (a)(3) of this Section, may not operate the

affected engine or turbine 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

program administered by USEPA where one allowance is equal to one ton

allowances may only be used 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 emissions exceedance.

To achieve compliance no more than twice in any rolling five-year

For a unit that is not listed in Appendix G.

The owner or operator of the affected unit must surrender to the Agency

allowance for each ton or portion of a ton of NO

actual emissions exceed allowed emissions. For noncompliance with a

seasonal limit, a NO

ozone season allowance must be used. For

noncompliance with the emissions concentration limits in Section

217.388(a) or an annual limitation in an emissions averaging plan, only a

annual allowance may be used.

The owner or 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 the NO

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 or the annual

emission averaging plan limits. The report must contain the NATS serial

numbers of the NO

(Source: Added at 31 Ill. Reg. _______________, effective __________________.)

Section 217.394

Testing and Monitoring

An owner or operator of an engine or turbine

must conduct an initial performance

test pursuant to subsection (c)(1) or (c)(2) of this Section as follows:

By May 1, 2007January

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 217.388(b).

By the applicable compliance date

as set forth in Section 217.392, or

wWithin the first 876 hours of operation per calendar year, whichever is

For affected units not listed in Appendix G that operate more than

876 hours per calendar year; and

For 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

For for units that are not affected units that are included in an

emissions averaging plan and that operate fewer than 876 hours

per calendar year

An owner or operator of an engine or turbine

must conduct subsequent

performance tests pursuant to subsection (c)(1) or (c)(2) of this Section as

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

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 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

must 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.

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 utilizing 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, or 40 CFR 75

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

(Source: Added at 31 Ill. Reg. _______________, effective __________________.)

Section 217.396

Recordkeeping and Reporting

Recordkeeping. The owner or operator of

an Appendix G unit or 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) 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(dc).

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.

reconciliation reports submitted pursuant to

Section 217.392(e).

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; or

For each unit complying with Section 217.388(c)(2), maintain a record of

bhp or MW hours operated each calendar year.

The owner or operator of an affected unit or unit included in an emissions

averaging plan must maintain the records required by subsections (a) and (b) of

this Section 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 subsections 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 30 following the applicable calendar year, the owner or

operator must submit to the Agency a report that demonstrates the

For all units that are part of the emissions averaging plan,

the total mass of allowable NO

emissions for the ozone

season and for the annual control period;

The total mass of actual NO

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

emissions are less than the total mass of

emissions using equations in Sections

217.390(f) and (g); and

The information required to determine the total mass of

emissions and the calculations performed in

subsection (d)(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(b)(3).

(Source: Added at 31 Ill. Reg. _______________, effective __________________.)

Section 217.APPENDIX G: Existing Reciprocating Internal Combustion Engines Affected by

ANR Pipeline Co. – Sandwich

Natural Gas Pipeline Co. of America 8310

Natural Gas Pipeline Co. of America Sta 110

Northern Illinois Gas Co. - Stor Stat 359

Panhandle Eastern Pipe Line Co.-Glenarm

Panhandle Eastern Pipeline - Tuscola St

Panhandle Eastern Pipeline Co.

Panhandle Eastern Pipeline Co.-Glenarm

Phoenix Chemical Co.

(Source: Added at 31 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 order on August 9, 2007, by a vote of 4-0.

___________________________________

John T. Therriault, Assistant Clerk

Illinois Pollution Control Board