BEFORE THE ILLINOIS POLLUTION CONTROL BOARD

IN THE MATTER OF:

)

)

FAST-TRACK NITROGEN OXIDE

)

R07-18

(NOx) SIP CALL PHASE II:

)

(Rulemaking - Air)

AMENDMENTS TO 35 ILL.

)

ADM. CODE SECTION 201.146

)

AND (sic) PARTS 211 AND 217

)

NOTICE

TO:

Dorothy Gunn, Clerk

Illinois Pollution Control Board

State of Illinois Center

100 West Randolph, Suite 11-500

Chicago, Illinois 60601

SEE ATTACHED SERVICE LIST

PLEASE TAKE NOTICE that I have today filed with the Office of the Pollution Control

Board the attached POST HEARING COMMENTS of the Illinois Environmental Protection

Agency a copy of which is herewith served upon you.

ILLINOIS ENVIRONMENTAL PROTECTION

AGENCY

By: ______________________

Rachel L. Doctors

Assistant Counsel

Division of Legal Counsel

DATED: July 5, 2007

P.O. Box 19276

Springfield, Illinois 62794-9276

217/782-5544

217.782.9143 (TDD)

---

BEFORE THE ILLINOIS POLLUTION CONTROL BOARD

IN THE MATTER OF:

)

)

FAST-TRACK NITROGEN OXIDE

)

R07-18

(NOx) SIP CALL PHASE II:

)

(Rulemaking - Air)

AMENDMENTS TO 35 ILL.

)

ADM. CODE SECTION 201.146

)

AND (sic) PARTS 211 AND 217

)

POST HEARING COMMENTS OF ILLINOIS

ENVIRONMENTAL PROTECTION AGENCY

NOW COMES the ILLINOIS ENVIRONMENTAL PROTECTION AGENCY (“Illinois

EPA”), by one of its attorneys, and hereby submits its post hearing comments in the above

rulemaking proceeding. The purpose of proposed new Subpart Q is to reduce intra- and

interstate transport of nitrogen oxides (“NO

x

”) emissions on an annual basis (January 1 though

December 31) and on an ozone season basis (May 1 through September 30) of each year,

through the adoption of the rules reducing NO

x

emissions from NO

x

State Implementation Plan

(“SIP”) Call Phase II stationary reciprocating internal combustion engines. This proposal is

intended to satisfy Illinois’ obligations under the United States Environmental Protection

Agency’s (“USEPA”) NO

x

SIP Call Phase II. The proposed new Subpart will also help Illinois

make progress toward achieving the new PM

2.5

National Ambient Air Quality Standards

(“NAAQS”).

The Illinois EPA filed its initial proposal on April 6, 2007. However, on May 17, 2007,

the Illinois Pollution Control Board (“Board”) issued an order significantly narrowing the scope

of this rulemaking and splitting the Illinois EPA’s proposal into two dockets, R07-18 and R07-

19. The subsequent hearings that were held in the present docket pertained to the proposal as it

applied to engines affected by NO

x

SIP Call Phase II. The Illinois EPA engaged in extensive

---

outreach on this proposal and held regular meetings with representatives of the affected sources

during the last two years. The Illinois EPA witnesses testified and provided evidence in support

of the proposed rulemaking at the first hearing that was held in Springfield on May 21, 2007. At

the second hearing that was held in Chicago on June 19, 2007, opponents and supporters of the

proposal had an opportunity to present testimony. Only one witness testified.

The Illinois EPA’s post hearing comments address four areas: 1) clarification of the size

of the engine affected by the NO

x

SIP Call; 2) selective catalytic reduction (“SCR”) technology;

3) cost-effectiveness; and 4) proposed clarifications and corrections to the regulatory language in

Attachment 1 of the Board’s May 24, 2007 Order. A complete copy of the Illinois EPA’s

proposed changes is attached.

I.

The Size of NO

x

SIP Call Engines

James McCarthy presented prefiled testimony on behalf of ANR Pipeline Company,

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

Company (collectively, “the Pipeline Consortium”). In his prefiled testimony, Mr. McCarthy

states that page 17 of Illinois EPA’s technical support document (“TSD”) implies a 1,500

horsepower size threshold for NOx SIP Call engines: “Note that the IEPA Technical Support

Document (“TSD”) for the proposal (

see

Section 2.2, page 17) implies a 1500 horsepower (“hp”)

size threshold for SIP Call Engines.” McCarthy at 3. However, this statement was never meant

to be construed for the proposition that Illinois EPA is defining NO

x

SIP Call engines as being

rated at 1,500 bhp and this rating is equivalent to one ton of NO

x

or more. In fact, the TSD

states: “[I]n Illinois, the NO

x

SIP Call affects large engines, greater than 1500 bhp….” TSD at

17. The applicability of the NO

x

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

x

emissions (one ton) in 1995 summer day and is not based on the size of the engine in terms of

2

---

rated brake horsepower (“bhp”). This statement in the TSD was made to support the

applicability of the proposal to 500 bhp for engines and the proposed amendments to 35 Ill.

Adm. Code Section 201.146(j) which currently exempts engines of less than 1,500 horsepower

from permitting requirements. Further, each of the 28 NO

x

SIP Call-affected engines is much

larger than 1,500 bhp as testified to by Mr. McCarthy. The TSD, however, was originally

written to support the applicability of the proposal to include a much broader range of engines

and turbines. Amendments to Section 201.146(j) and the broader range of engines and turbines

will be addressed in R07-19.

II.

SCR Technology

Mr. McCarthy’s testimony implies that SCR technology is not an applicable technology

for internal combustion engines: “In addition, the IEPA TSD describes emission control

technologies that are not necessarily proven controls for application to natural gas transmission

and storage ICE engines. Selective Catalytic Reduction (“SCR”) is included as an applicable

control technology for IC engines. However, to date SCR has not been successfully applied to

gas transmission units…” McCarthy at 7. Compare this testimony to USEPA’s Alternative

Control Technology (“ACT”) document, which includes SCR as one of the cost effective and

viable technology to reduce NO

x

emissions from lean-burn engines. ACT Ref. 8, pp. 5-55.

USEPA agreed that SCR still remains to be widely demonstrated in the United States on lean

burn IC engines in variable load operation. TSD Ref. 12, p. 15. SCR technology is very effective

and provides 90 percent NO

x

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

engines operating at constant load, diesel engines and dual fuel-fired engines. TSD Ref. 24, pp.

4-16. The shortcomings of earlier SCR systems have been corrected by the new generation of

technology which includes improved catalysts, a predictive emissions monitoring system feed

3

---

forward controls, and the use of urea as the reducing agent. Id. Illinois EPA posits that some

affected engines in Illinois will use SCR to comply with the proposal.

Most importantly, the Illinois EPA’s proposal does not require installation of SCR or any

other particular technology to comply with the proposal. Owners and operators have the

discretion to choose the most cost-effective technology or compliance option. It may be true that

in some cases where an engine is included in an averaging plan, no new technology needs to be

installed.

III.

Cost-Effectiveness

Mr. McCarthy’s prefiled testimony incorrectly characterizes the Illinois EPA as stating

that a $5,000 per ton rate is the basis used for stationary reciprocating internal combustion

engines under the NO

x

SIP Call: “The TSD (section 5.1, page 40) indicates that a $5000 per ton

basis is used for IC engines under the NOx SIP Call.” McCarthy at 8. Tables 5-2 and 5-3 and

other information contained on page 40 of the TSD were obtained from USEPA’s document

“Regulatory Impact Analysis for the NO

x

SIP Call, FIP, and Section 126 Petitions, Volume 1,

Costs and Economic Impacts.” TSD Ref. 11. USEPA evaluated emission reductions and cost

effectiveness of NO

x

control in the ozone season for each of the regulatory alternatives

(command and control regulations) at cost ceilings of $1,500, $2,000, $3,000, $4,000, and

$5,000 per ton as it pertained to control of emissions under the NO

x

SIP Call Phase I. Each of

the $2,000, $3,000 and $4,000 alternatives provided 82,584 tons of NO

x

emission reductions at

cost-effectiveness of NO

x

controls of $1,213 per ozone season ton, whereas the $5,000

alternative provided 82,623 tons of NO

x

emission reductions at a cost effectiveness of NO

x

control of $1,215. USEPA selected the $5,000 alternative when it evaluated a 90 percent

reduction from the 2007 NO

x

emissions baseline. It subsequently changed the baseline reduction

4

---

to a 82 percent reduction from the 2007 baseline with a cost effectiveness of approximately $542

a ton. TSD Ref. 12, p. 34.

IV.

Clarifications and Corrections to Attachment 1

After reviewing the Hearing Officer’s Attachment 1, the Pipeline Consortium and the

Illinois Environmental Regulatory Group shared with the Illinois EPA a number of comments

specifying the typos and clarifications. Those comments have been included in the Illinois

EPA’s Attachment A to these comments. In addition, the Illinois EPA found a number of

additions and deletions to the Hearing Officer’s Attachment 1. The Illinois EPA shared those

comments with the Pipeline Consortium and IERG. On July 3, 2007, the Pipeline Consortium

indicated that it was in agreement with the Illinois EPA’s proposed language as set forth in

Attachment A. The Illinois EPA’s proposed changes to the Hearing Officer’s Attachment 1 are

discussed below.

1.

The Illinois EPA notes that necessary parts of its proposal were omitted from

Attachment 1, specifically proposed amendments to Part 217- Nitrogen Oxides Emissions,

Sections 217.101 Measurement Methods, 217.102 – Abbreviations and Units, 217.104 –

Incorporations by Reference, Appendix G – Existing Reciprocating Internal Combustion Engines

Affected by the NO

x

SIP Call, and Part 211 – Definitions. The Illinois EPA requests that these

provisions be included in the proposal for adoption, as the provisions are a necessary part of the

proposal. For example, Section 217.394 Testing and Monitoring makes extensive use of the

measurement methods that are proposed for inclusion in Sections 217.101 and 217.104.

2.

The Pipeline Consortium had raised an issue concerning the implications of

engine efficiency and the last three conversion factors included in Section 217.102(b) and

recommended deleting them. The Illinois EPA has reviewed Part 217 and finds that these

5

---

conversion factors are not necessary to other Subparts in Part 217 or for use in Subpart Q; hence,

it is proposing that these conversion factors be deleted:

b)

The following conversion factors have been used in this Part:

English

Metric

2.205 lb

1 kg

1 T

0.907 Mg

1 lb/T

0.500 kg/Mg

Mmbtu/hr

0.293 MW

1 lb/mmBtu 1.548 kg/MW-hr

mmbtu

1 mmBtu/hr 0.293 MW

1 mmBtu/hr 393 bhp

3.

There are several places where the cross references have changed due to more

limited applicability of the proposal to only NOx SIP call engines. Specifically:

i.

Section 217.390(a)(2):

………. 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(cd)(3) before the

replacement unit may be included in an emissions averaging plan.

ii.

Section 217.396(a)(7):

The plan for performing inspection and maintenance of the units, air pollution

control equipment, and the applicable monitoring device pursuant to Section

217.388(cd).

4.

In Section 217.390(e)(1) the cross reference to the subsections which contain

averaging plans was incomplete:

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;

5.

In Section 217.390(f), the references to total mass of allowable emissions

EM

all(i)

6

---

and total mass of action emissions EM

act(i)

include in some cases redundant references and, in

others, fail to include relevant references within this subsection:

EM

all(i)

=

Total mass of allowable NO

x

emissions in lbs for a unit as

determined in subsection (g)(2),

(g)(3), (g)(4), (g)(5), or

(g)(6) or (h)(2) of this Section.

EM

act(i)

=

Total mass of actual NO

x

emissions in lbs for a unit as

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

this Section.

6.

In Section 217.390(g), the references to total mass of allowable emissions EM

all(i)

,

total mass of action emissions EM

act(i)

, and allowable concentration C

d(all)

fail to include the

relevant references within this subsection:

EM

act(i)

=

Total mass of actual NO

x

emissions in lbs for a unit, except as provided

for in subsections (g)(3) and (g)(5).

EM

all(i)

=

Total mass of allowable NO

x

emissions in lbs for a unit, except as

provided for in subsections (g)(3) of this Section.

C

d(all)

=

Allowable concentration of NO

x

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.

7.

In Section 217.390(g)(4)(A) & (B), due to the applicability being limited to NO

x

SIP Call engines, there is language that no longer has an application and should be deleted:

4)

For a replacement unit that is not electric, the allowable NO

x

emissions

rate used in the above equations set forth in subsection (g)(2) of this

Section must be

either:

A)

Prior to the applicable compliance date for the replaced unit

pursuant to Section 217.392, the higher of the actual NO

x

emissions as determined by testing or monitoring data or the

applicable uncontrolled NO

x

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

B)

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

217.388(a).

7

---

8.

In Section 217.390(h)(2), the subscript below the summation sign should be “j”

not “i.” Unfortunately, the equation editor in Microsoft Word does not allow for the use of

strikeouts and underlines:

7)

1

(

*

*1.194 10

−

EM

=

∑

=

Cd Flow

i

x

m

ji

9.

The 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:

i.

In Section 217.392:

On and after January 1, 2008May 1, 2007, 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).

ii.

In Section 217.394(a)(1):

By January 1, 2008May 1, 2007, 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).

10.

In Section 217.392(a)(1) and (a)(2), language referring to units not included in

Appendix G or an averaging plan, or compliance dates other than January 1, 2008, should be

deleted, as well as the phrase in subsection (a)(1) that refers to a second compliance date:

1)

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 later, for units that are

not affected units that are included in an emissions averaging plan and operate

more than 876 hours per calendar year.

2)

Once within the five-year period after the applicable compliance date as set forth

in Section 217.392 :

fA)

For affected units that operate fewer than 876 hours per calendar year; and

11.

In Section 217.396 (a) the sentence pertaining to exempt units and low usage units

should be struck as those provisions are no longer included in the proposal:

8

---

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:

12.

Section 217.396 contains incorrect cross references:

b)

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.

c)

Reporting requirements:

1)

The owner or operator must notify the Agency in writing 30 days and five

days prior to testing pursuant to Sections 217.394(a) and (b), and:

Respectfully submitted,

ILLINOIS ENVIRONMENTAL

PROTECTION AGENCY

By:

_/s/ Rachel L. Doctors

Rachel L. Doctors

Assistant Counsel

Air Regulatory Unit

Division of Legal Counsel

DATED: July 5, 2007

1021 North Grand Avenue, East

P.O. Box 19276

Springfield, Illinois 62794-9276

217.782.5544

217.782.9807 (Fax)

9

---

ILLINOIS EPA

ATTACHMENT A TO COMMENTS

TITLE 35: ENVIRONMENTAL PROTECTION

SUBTITLE B: AIR POLLUTION

CHAPTER I: POLLUTION CONTROL BOARD

SUBCHAPTER C: EMISION STANDARDS AND LIMITATIONS

FOR STATIONARY SOURCES

PART 217

NITROGEN OXIDES EMISSIONS

SUBPART A: GENERAL PROVISIONS

Section

217.100

Scope and Organization

217.101

Measurement Methods

217.102

Abbreviations and Units

217.103

Definitions

217.104

Incorporations by Reference

SUBPART B: NEW FUEL COMBUSTION EMISSION SOURCES

Section

217.121

New Emission Sources

SUBPART C: EXISTING FUEL COMBUSTION EMISSION SOURCES

Section

217.141

Existing Emission Sources in Major Metropolitan Areas

SUBPART K: PROCESS EMISSION SOURCES

Section

217.301

Industrial Processes

SUBPART O: CHEMICAL MANUFACTURE

Section

217.381

Nitric Acid Manufacturing Processes

SUBPART Q: STATIONARY RECIPROCATING INTERNAL COMBUSTION

ENGINES AND TURBINES

Section

217.386

Applicability

217.388

Control Requirements

217.390

Emissions Averaging Plans

217.392

Compliance

217.394

Testing and Monitoring

217.396

Recordkeeping and Reporting

1

---

SUBPART T: CEMENT KILNS

Section

217.400

Applicability

217.402

Control Requirements

217.404

Testing

217.406

Monitoring

217.408

Reporting

217.410

Recordkeeping

SUBPART U: NO

x

CONTROL AND TRADING PROGRAM FOR

SPECIFIED NO

x

GENERATING UNITS

Section

217.450

Purpose

217.452

Severability

217.454

Applicability

217.456

Compliance Requirements

217.458

Permitting Requirements

217.460

Subpart U NO

x

Trading Budget

217.462

Methodology for Obtaining NO

x

Allocations

217.464

Methodology for Determining NO

x

Allowances from the New Source Set-Aside

217.466

NO

x

Allocations Procedure for Subpart U Budget Units

217.468

New Source Set-Asides for “New” Budget Units

217.470

Early Reduction Credits (ERCs) for Budget Units

217.472

Low-Emitter Requirements

217.474

Opt-In Units

217.476

Opt-In Process

217.478

Opt-In Budget Units: Withdrawal from NO

x

Trading Program

217.480

Opt-In Units: Change in Regulatory Status

217.482

Allowance Allocations to Opt-In Budget Units

SUBPART V: ELECTRIC POWER GENERATION

Section

217.521

Lake of Egypt Power Plant

217.700

Purpose

217.702

Severability

217.704

Applicability

217.706

Emission Limitations

217.708

NO

x

Averaging

217.710

Monitoring

217.712

Reporting and Recordkeeping

SUBPART W: NO

x

TRADING PROGRAM FOR ELECTRICAL

GENERATING UNITS

2

---

Section

217.750

Purpose

217.752

Severability

217.754

Applicability

217.756

Compliance Requirements

217.758

Permitting Requirements

217.760

NO

x

Trading Budget

217.762

Methodology for Calculating NO

x

Allocations for Budget Electrical

Generating Units (EGUs)

217.764

NO

x

Allocations for Budget EGUs

217.768

New Source Set-Asides for “New” Budget EGUs

217.770

Early Reduction Credits for Budget EGUs

217.774

Opt-In Units

217.776

Opt-In Process

217.778

Budget Opt-In Units: Withdrawal from NO

x

Trading Program

217.780

Opt-In Units: Change in Regulatory Status

217.782

Allowance Allocations to Budget Opt-In Units

SUBPART X: VOLUNTARY NO

x

EMISSIONS REDUCTION PROGRAM

Section

217.800

Purpose

217.805

Emission Unit Eligibility

217.810

Participation Requirements

217.815

NO

x

Emission Reductions and the Subpart X NO

x

Trading Budget

217.820

Baseline Emissions Determination

217.825

Calculation of Creditable NO

x

Emission Reductions

217.830

Limitations on NO

x

Emission Reductions

217.835

NO

x

Emission Reduction Proposal

217.840

Agency Action

217.845

Emissions Determination Methods

217.850

Emissions Monitoring

217.855

Reporting

217.860

Recordkeeping

217.865

Enforcement

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

x

SIP

Call

3

---

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

Ill. Reg.

, effective

.

SUBPART A: GENERAL PROVISIONS

Section 217.101

Measurement Methods

Measurement of nitrogen oxides must be according to

:

a)

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

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

b)

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

reference in Section 217.104(1999); and

c)

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).

d)

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

by reference in Section 217.104; and

e)

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

regarding NO

x

pursuant to 40 CFR 60.4400, as incorporated by reference in

Section 217.104 .

(Source: Amended at

Ill. Reg.

, effective

)

Section 217.102

Abbreviations and Units

a)

The following abbreviations are used in this Part:

ASTM

American Society for Testing and Materials

Btubtu

British thermal unit (60

o

F)

bhp

brake horsepower

CEMS

continuous emissions monitoring system

EGU

Electrical Generating Unit

dscf

dry standard cubic feet

g/bhp-hr

grams per brake horsepower-hour

4

---

kg

kilogram

kg/MW-hr

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

rate

lb

pound

NO

x

Nitrogen Oxides

lbs/mmBtu

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

lbs/mmbtu

Mg

megagram or metric tonne

mm

million

mmBtu

million British thermal units

mmbtu

mmBtu/hr

million British thermal units per hour

mmbtu/hr

MWe

megawatt of electricity

MW

megawatt; one million watts

MW-hr

megawatt-hour

NATS

NO

x

Allowance Tracking System

NO

2

nitrogen dioxide

NO

x

nitrogen oxides

O

2

oxygen

psia

pounds per square inch absolute

peoc

potential electrical output capacity

PTE

potential to emit

ppm

parts per million

ppmv

parts per million by volume

T

English ton

TPY

tons per year

b)

The following conversion factors have been used in this Part:

English

Metric

2.205 lb

1 kg

1 T

0.907 Mg

1 lb/T

0.500 kg/Mg

Mmbtu/hr

0.293 MW

1 lb/mmBtu 1.548 kg/MW-hr

mmbtu

1 mmBtu/hr 0.293 MW

1 mmBtu/hr 393 bhp

(Source: Amended at

Ill. Reg.

, effective

)

Section 217.104

Incorporations by Reference

5

---

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

later amendments or editions.

a)

The phenol disulfonic acid

proceduresmethod, as published in 40 CFR 60,

Appendix A, Method 7

(2000)(1999);

b)

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

c)

40 CFR

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

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

d)

40 CFR

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

e)

Alternative Control Techniques Document---- NO

x

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;

f)

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;

g)

40 CFR § 60.13 (2001)(1999); and

h)

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

(2000)(1999).;

i)

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);

k)

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

Subpart KKKK, 60.4400 (2006); and

l)

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

Point and Area Sources (2000), USEPA.

(Source: Amended at

Ill. Reg.

, effective

)

SUBPART Q: STATIONARY RECIPROCATING INTERNAL COMBUSTION ENGINES

AND TURBINES

Section 217.386

Applicability

6

---

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 (c) 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.

a)

The owner or operator must limit the discharge from an affected unit into the

atmosphere of any gases that contain NO

x

to no more than:

1)

150 ppmv (corrected to 15 percent O

2

on a dry basis) for spark-ignited

rich-burn engines;

2)

210 ppmv (corrected to 15 percent O

2

on a dry basis) for spark-ignited

lean-burn engines.

b)

The owner or operator must comply with the requirements of the applicable

emissions averaging plan as set forth in Section 217.390.

c)

The owner or operator must inspect and perform periodic maintenance on the

affected unit, in accordance with a Maintenance Plan that documents:

1)

For a unit not located at natural gas transmission compressor station or

storage facility either:

A)

The manufacturer’s recommended inspection and maintenance of

the applicable air pollution control equipment, monitoring device,

and affected unit; or

B)

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.

2)

For a unit located at a natural gas compressor station or storage facility,

the operator’s maintenance procedures for the applicable air pollution

7

---

control device, monitoring device, and affected unit.

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

Section 217.390

Emissions Averaging Plans

a)

An owner or operator of certain affected units may comply through an emissions

averaging plan.

1)

The unit or units that commenced operation before January 1, 2002, may

be included in an emissions averaging plan as follows: 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.;

2)

The following types of units may not be included in an emissions

averaging plan: 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(cd)(3) before the replacement unit may be

included in an emissions averaging plan.

b)

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:

1)

The list of affected units included in the plan by unit identification number

and permit number.

2)

A sample calculation demonstrating compliance using the methodology

provided in subsection (f) of this Section for both the ozone season and

calendar year.

c)

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.

d)

Notwithstanding subsection (c) of this Section, an owner or operator, and the

buyer, if applicable must submit an updated emissions averaging plan or plans to

8

---

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

sold or taken out of service.

e)

An owner or operator must:

1)

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;

2)

Notify the Agency by October 31 following the ozone season, if

compliance cannot be demonstrated for that ozone season; and

3)

Submit to the Agency by January 31 following each calendar year, a

compliance report containing the information required by Section

217.396(cd)(4).

f)

The total mass of actual NO

x

emissions from the units listed in the emissions

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

x

emissions for those units for both the ozone season and calendar year. The

following equation must be used to determine compliance:

N

act

≤

N

all

Where:

N

act

=

∑

=

n

i1

EM

act(i)

N

all

=

∑

=

n

i1

EM

all(i)

N

act

=

Total sum of the actual NO

x

mass emissions from units

included in the averaging plan for each fuel used (lbs per

ozone season and calendar year).

N

all

=

Total sum of the allowable NO

x

mass emissions from units

included in the averaging plan for each fuel used (lbs

per ozone season and calendar year).

EM

all(i)

=

Total mass of allowable NO

x

emissions in lbs for a unit as

determined in subsection (g)(2),

(g)(3), (g)(4), (g)(5), or

(g)(6) or (h)(2) of this Section.

EM

act(i)

=

Total mass of actual NO

x

emissions in lbs for a unit as

determined in subsection (g)(1)

, (g)(3), (g)(5) or (h)(1) of

this Section.

i

=

Subscript denoting an individual unit and fuel used.

9

---

n

=

Number of different units in the averaging plan.

g)

For each unit in the averaging plan, and each fuel used by a unit, determine actual

and allowable NO

x

emissions using the following equations, except as provided

for in subsection (h) of this Section:

1)

Actual emissions must be determined as follows:

EM

act(i)

=

E

act(i)

x H

i

m

20.9 %O

C

xF x

20.9

E

m

j 1

2d(j)

d(act( j))

d

act(i)

∑

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

−

=

=

2)

Allowable emissions must be determined as follows:

EM

all(i)

=

E

all(i)

x H

i

m

20.9 %O

C

xF x

20.9

E

m

j 1

2d(j)

d(all)

d

all(i)

∑

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

−

=

=

Where:

EM

act(i)

=

Total mass of actual NO

x

emissions in lbs for a unit, except

as provided for in subsections (g)(3) and (g)(5).

EM

all(i)

=

Total mass of allowable NO

x

emissions in lbs for a unit,

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

E

act

=

Actual NO

x

emission rate (lbs/mmBtu) calculated

according to the above equation.

E

all

=

Allowable NO

x

emission rate (lbs/mmBtu) calculated

according to the above equation.

H

=

Heat input (mmBtu/ozone season or mmBtu/year)

calculated from fuel flow meter and the heating value of the

fuel used.

C

d(act)

=

Actual concentration of NO

x

in lb/dscf (ppmv x 1.194 x

10

-7

) 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.

C

d(all)

=

Allowable concentration of NO

x

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.

10

---

multiplied by 1.194 x 10

-7

) on a dry basis for the fuel used.

F

d

=

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 A,

Method 19.

%O

2d

=

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

2d

,

18.7 would be used.

i

=

Subscript denoting an individual unit and the fuel used.

j

=

Subscript denoting each test run or monitoring pass for an

affected unit for a given fuel.

m

=

The number of test runs or monitoring passes for an

affected unit using a given fuel.

3)

For a replacement unit that is electric-powered, the allowable NO

x

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

averaging calculations and the actual NO

x

emissions for the electric-

powered replacement unit (EM

(i)act elec

) are zero. Allowable NO

x

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

x

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

The allowable mass of NO

x

emissions from an electric-powered

replacement unit (EM

(i)all elec

) 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

x

emission rate of the replaced

unit (E

all rep

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

following equation should be used:

EM

all elec(i)

= bhp x OP x F x E

all rep(i)

Where:

EM

all elec(i)

=

Mass of allowable NO

x

emissions from the electric-

powered replacement unit in pounds per ozone season or

calendar year.

bhp

= Nameplate capacity of the electric-powered

replacement unit in brake-horsepower.

OP

= Operating hours during the ozone season or calendar year.

F

= Conversion factor of 0.0077 mmBtu/bhp-hr.

E

all rep(i)

= Allowable NO

X

emission rate (lbs/mmBtu) of the replaced

unit.

i

= Subscript denoting an individual electric unit and the fuel

11

---

used.

4)

For a replacement unit that is not electric, the allowable NO

x

emissions

rate used in the above equations set forth in subsection (g)(2) of this

Section must be

either:

A)

Prior to the applicable compliance date for the replaced unit

pursuant to Section 217.392, the higher of the actual NO

x

emissions as determined by testing or monitoring data or the

applicable uncontrolled NO

x

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

B)

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

217.388(a).

5)

For a unit that is replaced with purchased power, the allowable NO

x

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

NO

x

emissions for the units replaced by purchased power (EM

(i)act

) are

zero. These units may be included in any emissions averaging plan for no

more than five years beginning with the calendar year that the replaced

unit is shut down.

6)

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 be the higher of the actual NO

x

emissions as determined

by testing or monitoring data, or the applicable uncontrolled NO

x

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.

h)

For units that use CEMS the data must show that the total mass of actual NO

x

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

equal to the allowable NO

x

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.

12

---

1)

The total mass of actual NO

x

emissions in lbs for a unit (EM

act

) must be

the sum of the total mass of actual NO

x

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.

2)

The allowable NO

x

emissions must be determined as follows:

7)

1

(

*

*1.194 10

−

EM

=

∑

=

Cd Flow

i

x

m

ji

Where:

EM

all(i)

=

Total mass of allowable NO

x

emissions in lbs for a unit.

Flow

i

=

Stack flow (dscf/hr) for a given stack.

Cd

i

=

Allowable concentration of NO

x

(ppmv) specified in

Section 217.388(a) of this subpart for a given stack. (1.194

x 10

-7

) converts to lb/dscf).

j

=

subscript denoting each hour operation of a given unit.

m

=

Total number of hours of operation of a unit.

i

=

Subscript denoting an individual unit and the fuel used.

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

Section 217.392

Compliance

On and after

January 1, 2008May 1, 2007, 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).

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

Section 217.394

Testing and Monitoring

a)

An owner or operator must conduct an initial performance test pursuant to

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

1)

By

January 1, 2008May 1, 2007, 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).

2)

By the applicable compliance date as set forth in Section 217.392, or

13

---

wWithin

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

later, for units that are not affected units that are included in an emissions

averaging plan and operate more than 876 hours per calendar year.

3)

Once within the five-year period after the applicable compliance date as

set forth in Section 217.392

:

fA)

For affected units that operate fewer than 876 hours per calendar

year; and

B)

Ffor units that are not affected units that are included in an

emissions averaging plan and that operate fewer than 876 hours per

calendar year

b)

An owner or operator must conduct subsequent performance tests pursuant to

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

1)

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 of starting

operation, whichever is later;

2)

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

3)

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 217.394 within 90 days of receipt of a notice to test from the

Agency or USEPA.

c)

Testing Procedures:

1)

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

x

emissions 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.

2)

For a turbine included in an emissions averaging plan: The owner

14

---

operator must conduct a performance test using the applicable procedures

and methods in 40 CFR 60.4400, as incorporated by reference in Section

217.104.

d)

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

x

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:

1)

A portable NO

x

monitor and 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 or

gaseous fuels as primary or backup fuels, separate monitoring is required

for each fuel.

2)

NO

x

and O

2

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.

e)

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

basis.

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

Section 217.396

Recordkeeping and Reporting

a)

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:

15

---

1)

Identification, type (e.g., lean-burn, gas-fired), and location of each unit.

2)

Calendar date of the record.

3)

The number of hours the unit operated on a monthly basis, and during

each ozone season.

4)

Type and quantity of the fuel used on a daily basis.

5)

The results of all monitoring performed on the unit and reported

deviations.

6)

The results of all tests performed on the unit.

7)

The plan for performing inspection and maintenance of the units, air

pollution control equipment, and the applicable monitoring device

pursuant to Section 217.388(cd).

8)

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).

9)

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.

10)

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.

b)

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.

c)

Reporting requirements:

1)

The owner or operator must notify the Agency in writing 30 days and five

days prior to testing pursuant to Sections

217.394(a) and (b), and:

16

---

A)

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;

B)

Provide a testing protocol to the Agency 60 days prior to testing;

and

C)

Not later than 30 days after the completion of the test, submit the

results of the test to the Agency.

2)

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

x

concentration from Section 217.388(a)

or (b) within 30 days of performing the monitoring.

3)

Within 90 days of 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.

4)

If demonstrating compliance through an emissions averaging plan:

A)

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

B)

By January 30 following the applicable calendar year, the owner or

operator must submit to the Agency a report that demonstrates the

following:

i)

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

the total mass of allowable NO

x

emissions for the ozone

season and for the annual control period;

ii)

The total mass of actual NO

x

emissions for the ozone

season and annual control period for each unit included in

the averaging plan;

iii)

The calculations that demonstrate that the total mass of

actual NO

x

emissions are less than the total mass of

allowable NO

x

emissions using equations in Sections

217.390(f) and (g); and

17

---

iv)

The information required to determine the total mass of

actual NO

x

emissions and the calculations performed in

subsection (d)(4)(B)(iii) of this Section.

5)

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.

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

18

---

APPENDIX G: EXISTING RECIPROCATING INTERNAL COMBUSTION ENGINES

AFFECTED BY NOx SIP CALL

Plant ID

Point ID

Segment

ANR Pipeline Co. – Sandwich

093802AAF

E-108

1

Natural Gas Pipeline Co. of America 8310

027807AAC

730103540041

1

Natural Gas Pipeline Co. of America Sta 110

073816AAA

851000140011

1

073816AAA

851000140012

2

073816AAA

851000140013

3

073816AAA

851000140014

4

073816AAA

851000140041

1

073816AAA

851000140051

1

Northern Illinois Gas Co. - Stor Stat 359

113817AAA

730105440021

1

113817AAA

730105440031

1

113821AAA

730105430021

1

113821AAA

730105430051

1

Panhandle Eastern Pipe Line Co.-Glenarm

167801AAA

87090038002

1

167801AAA

87090038004

1

167801AAA

87090038005

1

Panhandle Eastern Pipeline - Tuscola St

041804AAC

73010573009

9

041804AAC

73010573010

10

041804AAC

73010573011

11

041804AAC

73010573012

12

041804AAC

73010573013

13

Panhandle Eastern Pipeline Co.

149820AAB

7301057199G

3

149820AAB

7301057199I

1

149820AAB

7301057199J

1

19

---

149820AAB

7301057199K

1

Panhandle Eastern Pipeline Co.-Glenarm

167801AAA

87090038001

1

Phoenix Chemical Co.

085809AAA

730700330101

1

085809AAA

730700330102

2

085809AAA

730700330103

3

20

---

Part 211: SUBPART B: DEFINITIONS

Section 211.740

Brakehorsepower (rated-bhp)

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

engine nameplate at standard conditions.

(Source: Added at

Ill. Reg.

, effective

)

Section 211.1740

Diesel Engine

“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

Ill. Reg.

, effective

)

Section 211.1920

Emergency or Standby Unit

“Emergency or Standby Unit” means, for a stationary gas turbine or stationary reciprocating

internal combustion engine, a unit that:

a)

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.;

b)

Operates exclusively for firefighting or flood control or both.; or

c)

Operates in response to and during the existence of any officially declared disaster

or state of emergency.

d)

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

Ill. Reg.

, effective

)

Section 211.3300

Lean-Burn Engine

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

21

---

(Source: Added at

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

Ill. Reg.

, effective

)

22

---