217/782-2113 

CLEAN AIR ACT PERMIT PROGRAM (CAAPP) PERMIT 

PERMITTEE

Southern Illinois Power Cooperative 

Attn: Leonard Hopkins 

11543 Lake of Egypt Road 

Marion, Illinois 62959 

Application No.: 95090124 I.D. No.: 199856AAC 

Applicant’s Designation: MARION Date Received: September 08, 1995 

Operation of: Electrical Power Generation 

Date Issued: September 29, 2005 Expiration Date1

: September 29, 2010 

Source Location: 10825 Lake of Egypt Road, Marion (Williamson County) 

Responsible Official: Richard Myott, Environmental and Planning Dept. Manager 

This permit is hereby granted to the above-designated Permittee to OPERATE an 

electrical power generation station, pursuant to the above referenced permit 

application. This permit is subject to the conditions contained herein. 

The current federal Acid Rain Permit issued to Southern Illinois Power 

Cooperative by the Illinois EPA for this source is incorporated into this 

CAAPP permit (See Attachment 5). 

If you have any questions concerning this permit, please contact the Utility 

Unit at 217/782-2113 (217/782-9143 TDD). 

Donald E. Sutton, P.E. 

Manager, Permit Section 

Division of Air Pollution Control 

DES:MNP:jar 

cc: Illinois EPA, FOS, Region 3 

USEPA 

1 Except as addressed by Condition 8.7 of this permit.
2 

TABLE OF CONTENTS 

 PAGE

1.0 INTRODUCTION 4 

 

 1.1 Source Identification 

 1.2 Owner/Parent Company 

 1.3 Operator 

 1.4 General Source Description 

 1.5 Title I Conditions 

 

2.0 LIST OF ABBREVIATIONS/ACRONYMS USED IN THIS PERMIT 5 

 

3.0 CONDITIONS FOR INSIGNIFICANT ACTIVITIES 6 

 

 3.1 Identification of Insignificant Activities 

 3.2 Compliance with Applicable Requirements 

 3.3 Addition of Insignificant Activities 

 

4.0 SIGNIFICANT EMISSION UNITS AT THIS SOURCE 9 

 

5.0 OVERALL SOURCE CONDITIONS 10 

 

 5.1 Applicability of Clean Air Act Permit Program(CAAPP) 

 5.2 Applicable Regulations 

 5.3 General Non-Applicability of Regulations of Concern 

 5.4 Source-Wide Operational and Production Limits and Work 

Practices 

 5.5 Source-Wide Emission Limitations 

 5.6 General Recordkeeping Requirements 

 5.7 General Reporting Requirements 

 5.8 General Operational Flexibility/Anticipated Operating 

Scenarios 

 

6.0 CONDITIONS FOR EMISSIONS CONTROL PROGRAMS 16 

 

 6.1 NOx Trading Program 

 6.2 Acid Rain Program 

 

7.0 UNIT SPECIFIC CONDITIONS 27 

 

 7.1 Circulating Fluidized Bed Boiler 

 7.2 Coal-Fired Boiler 

 7.3 Coal Handling Equipment 

 7.4 Coal Processing Equipment 

 7.5 Ash Handling Equipment 

 7.6 Limestone Handling and Processing Equipment 

 7.7 Combustion Turbines 

 

8.0 GENERAL PERMIT CONDITIONS 162 

 

 8.1 Permit Shield 

 8.2 Applicability of Title IV Requirements 

 8.3 Emissions Trading Programs 

 8.4 Operational Flexibility/Anticipated Operating Scenarios 

 8.5 Testing Procedures 

 8.6 Reporting Requirements 

 8.7 Title I Conditions 
3 

 PAGE

9.0 STANDARD PERMIT CONDITIONS 167 

 

 9.1 Effect of Permit 

 9.2 General Obligations of Permittee 

 9.3 Obligation to Allow Illinois EPA Surveillance 

 9.4 Fees 

 9.5 Property Rights 

 9.6 Recordkeeping 

 9.7 Annual Emissions Report 

 9.8 Requirements for Compliance Certification 

 9.9 Certification 

 9.10 Defense to Enforcement Actions 

 9.11 Permanent Shutdown 

 9.12 Reopening And Reissuing Permit For Cause 

 9.13 Severability Clause 

 9.14 Permit Expiration and Renewal 

 9.15 General Authority for Permit Terms and Conditions 

 

10.0 ATTACHMENTS 

 

 10.1 Attachment 1 - Emissions of Particulate Matter from New 

Process Emission Units 

1-1 

 10.2 Attachment 2 - Emissions of Particulate Matter from 

Existing Process Emission Units 

2-1 

 10.3 Attachment 3 - Example Certification by a Responsible 

Official 

3-1 

 10.4 Attachment 4 – Guidance 4-1 

 10.5 Attachment 5 - Acid Rain Program Permit 5-1 
4 

1.0 INTRODUCTION 

1.1 Source Identification 

Southern Illinois Power Cooperative/Marion Generating Station 

10825 Lake of Egypt Road 

Marion, Illinois 62959 

618/964-1448 

I.D. No.: 199856AAC 

Acid Rain Permit ORIS Code No.: 976 

Standard Industrial Classification: 4911, Electrical Services 

1.2 Owner/Parent Company 

Southern Illinois Power Cooperative/Marion Generating Station 

11543 Lake of Egypt Road 

Marion, Illinois 62959 

1.3 Operator 

Southern Illinois Power Cooperative/Marion Generating Station 

11543 Lake of Egypt Road 

Marion, Illinois 62959 

Leonard Hopkins, Environmental Superintendent 

618/964-1448 

1.4 General Source Description 

The Marion Generating Station operates two coal-fired boilers and 

two peaking turbines to produce electricity. 

1.5 Title I Conditions 

This CAAPP permit contains certain conditions for units at this 

source that address the applicability of permitting programs for 

the construction and modification of sources, which programs were 

established pursuant to Title I of the Clean Air Act (CAA) and 

regulations thereunder. These programs include 40 CFR 52.21, 

Prevention of Significant Deterioration (PSD) and 35 IAC Part 203, 

Major Stationary Sources Construction and Modification (MSSCAM), 

and are implemented by the Illinois EPA pursuant to Sections 9, 

9.1, 39(a) and 39.5(7)(a) of Illinois’ Environmental Protection 

Act (Act). These “Title I conditions” within this permit are 

specifically designated as “T1,” if they reflect requirements 

established in construction permits issued for this source, “T1R” 

if they revise requirements established in such construction 

permits, or “T1N” if they are newly established in this CAAPP 

permit. These conditions continue in effect, notwithstanding the 

expiration date specified on the first page of this permit, as 

their authority derives from Titles I and V of the CAA, as well as 

Titles II and X of the Act. (See also Condition 8.7.) 
5 

2.0 LIST OF ABBREVIATIONS/ACRONYMS USED IN THIS PERMIT 

Act Illinois Environmental Protection Act [415 ILCS 5/1 et seq.] 

AP-42 Compilation of Air Pollutant Emission Factors, Volume 1, 

Stationary Point and Other Sources (and Supplements A 

through F), USEPA, Office of Air Quality Planning and 

Standards, Research Triangle Park, NC 27711 

Btu British thermal unit 

CAA Clean Air Act [42 U.S.C. Section 7401 et seq.] 

CAAPP Clean Air Act Permit Program 

CAM Compliance Assurance Monitoring 

CEMS Continuous Emission Monitoring System 

CFR Code of Federal Regulations 

EGU electrical generating unit(s) 

gal gallon 

HAP Hazardous Air Pollutant 

Hr hour 

IAC Illinois Administrative Code 

I.D. No. Identification Number of Source, assigned by Illinois EPA 

ILCS Illinois Compiled Statutes 

Illinois EPA Illinois Environmental Protection Agency 

Kw Kilowatts 

LAER Lowest Achievable Emission Rate 

lb pound 

MACT Maximum Achievable Control Technology 

mmBtu Million British thermal units 

Mg megagram or metric ton 

MW Megawatts 

NESHAP National Emission Standards for Hazardous Air Pollutants 

NOx Nitrogen Oxides 

NSPS New Source Performance Standards 

NSSA new source set-aside 

ORIS Office of Regulatory Information System 

PM Particulate Matter 

PM10 Particulate matter with an aerodynamic diameter less than or 

equal to a nominal 10 microns as measured by applicable test 

or monitoring methods 

ppm parts per million 

PSD Prevention of Significant Deterioration (40 CFR 52.21) 

RMP Risk Management Plan 

SO2 Sulfur Dioxide 

T ton (2000 pounds) 

T1 Title I – identifies Title I conditions that have been 

carried over from an existing permit 

T1N Title I New – identifies Title I conditions that are being 

established in this permit 

T1R Title I Revised – identifies Title I conditions that have 

been carried over from an existing permit and subsequently 

revised in this permit 

USEPA United States Environmental Protection Agency 

VOM Volatile Organic Material 
6 

3.0 CONDITIONS FOR INSIGNIFICANT ACTIVITIES 

3.1 Identification of Insignificant Activities 

The following activities at the source constitute insignificant 

activities as specified in 35 IAC 201.210: 

3.1.1 Activities determined by the Illinois EPA to be 

insignificant activities, pursuant to 35 IAC 201.210(a)(1) 

and 201.211, as follows: 

Cold Cleaning 

3.1.2 Activities that are insignificant activities based upon 

maximum emissions, pursuant to 35 IAC 201.210(a)(2) or 

(a)(3), as follows: 

Diesel Storage Tanks 

Lube Oil Tank 

Turbine Oil Tank 

Acid Storage Tank 

Anhydrous Ammonia Storage Tank 

3.1.3 Activities that are insignificant activities based upon 

their type or character, pursuant to 35 IAC 201.210(a)(4) 

through (18), as follows: 

Direct combustion units designed and used for comfort 

heating purposes and fuel combustion emission units as 

follows: (A) Units with a rated heat input capacity 

of less than 2.5 mmBtu/hr that fire only natural gas, 

propane, or liquefied petroleum gas; (B) Units with a 

rated heat input capacity of less than 1.0 mmBtu/hr 

that fire only oil or oil in combination with only 

natural gas, propane, or liquefied petroleum gas; and 

(C) Units with a rated heat input capacity of less 

than 200,000 Btu/hr which never burn refuse, or 

treated or chemically contaminated wood [35 IAC 

201.210(a)(4)]. 

Storage tanks of organic liquids with a capacity of 

less than 10,000 gallons and an annual throughput of 

less than 100,000 gallons per year, provided the 

storage tank is not used for the storage of gasoline 

or any material listed as a HAP pursuant to Section 

112(b) of the CAA [35 IAC 201.210(a)(10)]. 

Storage tanks of any size containing virgin or rerefined distillate oil, hydrocarbon condensate from 

natural gas pipeline or storage systems, lubricating 

oil, or residual fuel oils [35 IAC 201.210(a)(11)]. 

Coating operations (excluding powder, architectural 

and industrial maintenance coating) with aggregate VOM 

usage that never exceeds 15 lbs/day from all coating 

lines at the source, including VOM from coating, 

diluents, and cleaning materials [35 IAC 

201.210(a)(13)]. 
7 

3.1.4 Activities that are considered insignificant activities 

pursuant to 35 IAC 201.210(b). 

Note: The heating of a coal-fired boiler with auxiliary 

fuel during maintenance and repair of the boiler is 

considered an insignificant activity under 35 IAC 

201.210(b)(29) and is generally not addressed by the unitspecific conditions of this permit for the boilers. 

Notwithstanding such status as an insignificant activity, 

the opacity of the exhaust from each coal fired boiler is 

at all times subject to applicable opacity standards and 

the unit-specific conditions of this permit for boilers 

that relate to opacity are applicable during maintenance 

and repair of a boiler. 

3.2 Compliance with Applicable Requirements 

Insignificant activities are subject to applicable requirements 

notwithstanding status as insignificant activities. In 

particular, in addition to regulations of general applicability, 

such as 35 IAC 212.301 and 212.123 (Condition 5.2.2), the 

Permittee shall comply with the following requirements, as 

applicable: 

3.2.1 For each cold cleaning degreaser, the Permittee shall 

comply with the applicable equipment and operating 

requirements of 35 IAC 215.182. 

3.2.2 For each particulate matter process emission unit, other 

than the units excluded by 35 IAC 212.323 and 212. 681, 

the Permittee shall comply with the applicable particulate 

matter emission limit of 35 IAC 212.321 or 212.322. For 

example, the particulate matter emissions from a process 

emission unit shall not exceed 0.55 pounds per hour if the 

emission unit’s process weight rate is 100 pounds per hour 

or less, pursuant to 35 IAC 266.110. 

3.2.3 For each organic material emission unit that uses organic 

material, e.g., a mixer or printing line, the Permittee 

shall comply with the applicable VOM emission limit of 35 

IAC 215.301, which requires that organic material 

emissions not exceed 8.0 pounds per hour or do not qualify 

as photochemically reactive material as defined in 35 IAC 

211.4690. 

3.3 Addition of Insignificant Activities 

3.3.1 The Permittee is not required to notify the Illinois EPA 

of additional insignificant activities present at the 

source of a type that is identified in Condition 3.1, 

until the renewal application for this permit is 

submitted, pursuant to 35 IAC 201.212(a). 

3.3.2 The Permittee must notify the Illinois EPA of any proposed 

addition of a new insignificant activity of a type 

addressed by 35 IAC 201.210(a) and 201.211 other than 

those identified in Condition 3.1, pursuant to Section 

39.5(12)(b) of the Act. 
8 

3.3.3 The Permittee is not required to notify the Illinois EPA 

of additional insignificant activities present at the 

source of a type identified in 35 IAC 201.210(b). 
9 

4.0 SIGNIFICANT EMISSION UNITS AT THIS SOURCE 

Emission 

Unit Description 

Emission Control 

Equipment Ref* 

Boiler 

Unit 123 

Circulating Fluidized Bed 

(CFB) Boiler 

Limestone 

Injection, SNCR 

System and Baghouse 

7.1 

Boiler 

Unit 4 

Babcock & Wilcox Coal Boiler 

Nominal 1,700 mmBtu/hr (1975) 

SCR, ESP and 

Scrubber 

7.2 

Coal 

Handling 

Equipment 

Coal Receiving, Transfer, and 

Storage Operations 

Enclosure and Dust 

Suppressant 

Application System 

7.3 

Crusher 

House 

Coal Crushing Operation Enclosure and Dust 

Suppressant 

Application 

7.4 

Fly Ash 

Handling 

Transfer Systems, Storage and 

Loadout Operations 

Enclosure and Dust 

Collection Devices 

Fly Ash 

Pug Mill 

Fly Ash/Scrubber Sludge Mixing 

Operation 

Moisture Content 

and Enclosure 

7.5 

Limestone 

Handling & 

Processing 

Receiving, Storage Transfer 

and Crushing Operations 

Moisture Content 

and Enclosure 

7.6 

Turbine 

Unit 5 

Natural Gas Fired Turbine 

Nominal 969 mmBtu/hr 

Turbine 

Unit 6 

Natural Gas Fired Turbine 

Nominal 969 mmBtu/hr 

Low NOx Combustion 

Systems, with Water 

Injection for 

Backup Oil Firing 

7.7 

* Reference to the Unit Specific Conditions in Section 7 of this permit. 
10 

5.0 OVERALL SOURCE CONDITIONS 

5.1 Applicability of Clean Air Act Permit Program (CAAPP) 

5.1.1 This permit is issued based on the source requiring a 

CAAPP permit as a major source of SO2, CO, NOx, VOM, PM 

and HAP emissions. 

5.1.2 This permit is issued based on the source requiring a 

CAAPP permit as an “affected source” for the purposes of 

Acid Deposition Control, Title IV of the Clean Air Act. 

5.2 Applicable Regulations 

5.2.1 Specific emission units at this source are subject to 

particular regulations as set forth in Section 7 (UnitSpecific Conditions) of this permit. 

5.2.2 In addition, emission units at this source are subject to 

the following regulations of general applicability: 

a. No person shall cause or allow the emission of 

fugitive particulate matter from any process, 

including any material handling or storage activity, 

that is visible by an observer looking generally 

towards the zenith (i.e., overhead) at a point beyond 

the property line of the source unless the wind speed 

is greater than 40.2 kilometers per hour (25 miles per 

hour), pursuant to 35 IAC 212.301 and 212.314. 

b. No person shall cause or allow the emission of smoke or 

other particulate matter, with an opacity greater than 30 

percent, into the atmosphere from any emission unit other 

than those emission units subject to the requirements of 

35 IAC 212.122, pursuant to 35 IAC 212.123(a), except as 

allowed by 35 IAC 212.123(b) and 212.124. 

Note: As new fuel combustion emission units, 

constructed after April 14, 1972, with heat input 

capacity greater than 250 mmBtu/hr, the coal-fired 

boilers at this source are subject to 35 IAC 212.122, 

which sets a limit on opacity of 20 percent. 

5.2.3 Ozone Depleting Substances 

The Permittee shall comply with the standards for 

recycling and emissions reduction of ozone depleting 

substances pursuant to 40 CFR Part 82, Subpart F, 

including the following: 

a. Persons opening appliances for maintenance, service, 

repair, or disposal must comply with the required 

practices pursuant to 40 CFR 82.156. 

b. Equipment used during the maintenance, service, 

repair, or disposal of appliances must comply with the 

standards for recycling and recovery equipment 

pursuant to 40 CFR 82.158. 
11 

c. Persons performing maintenance, service, repair, or 

disposal of appliances must be appropriately certified 

by an approved technician certification program 

pursuant to 40 CFR 82.161. 

5.2.4 Risk Management Plan (RMP) 

Should this stationary source, as defined in 40 CFR 68.3, 

become subject to the federal rules for Chemical Accident 

Prevention in 40 CFR Part 68, then the owner or operator 

shall submit: 

a. A compliance schedule for meeting the requirements of 

40 CFR Part 68 by the date provided in 40 CFR 

68.10(a); or 

b. A certification statement that the source is in 

compliance with all applicable requirements of 40 CFR 

Part 68, including the registration and submission of 

the RMP, as part of the annual compliance 

certification required by Condition 9.8. 

Note: This condition is imposed pursuant to 40 CFR 

68.215(a). 

5.2.5 Future Emission Standards 

a. Should this source become subject to a regulation 

under 40 CFR Parts 60, 61, or 63, or 35 IAC Subtitle B 

after the date issued of this permit, the owner or 

operator shall, in accordance with the applicable 

regulation(s), comply with the applicable requirements 

by the date(s) specified and shall certify compliance 

or otherwise demonstrate initial compliance as 

provided by such regulation. Following the submittal 

of such a compliance certification or initial 

compliance demonstration, the Permittee shall address 

with the applicable requirements of such regulation as 

part of the annual compliance certification required 

by Condition 9.8. 

Note: This permit may also have to be revised or reopened 

to address such newly applicable regulations, as provided 

by Section 39.5(15)(a) of the Act. (See Condition 

9.12.2.) 

b. This permit and the terms and conditions herein do not 

affect the Permittee's past and/or continuing 

obligation with respect to statutory or regulatory 

requirements governing major source construction or 

modification under Title I of the CAA. Further, 

neither the issuance of this permit nor any of the 

terms or conditions of the permit shall alter or 

affect the liability of the Permittee for any 

violation of applicable requirements prior to or at 

the time of permit issuance. 
12 

5.2.6 Episode Action Plan 

a. Pursuant to 35 IAC 244.142, the Permittee shall 

maintain at the source and have on file with the 

Illinois EPA a written episode action plan (plan) for 

reducing the levels of emissions during yellow alerts, 

red alerts, and emergencies, consistent with safe 

operating procedures. The plan shall contain the 

information specified in 35 IAC 244.144. 

b. The Permittee shall immediately implement the 

appropriate steps described in this plan should an air 

pollution alert or emergency be declared. 

c. If an operational change occurs at the source that 

invalidates the plan, a revised plan shall be 

submitted to the Illinois EPA for review within 30 

days of the change, pursuant to 35 IAC 244.143(d). 

Such plans shall be further revised if disapproved by 

the Illinois EPA. 

5.2.7 Compliance Assurance Monitoring (CAM) Plan 

Pursuant to 40 CFR 64.5, if the Permittee submits a 

request for a significant revision of this permit that is 

applicable to an affected large pollutant-specific 

emissions unit, as defined by 40 CFR 64.1, 64.2 and 

64.5(a), (e.g., a coal-fired boiler as it emits 

particulate matter), the Permittee shall submit as part of 

such application the information required under 40 CFR 

64.4 for a CAM plan. 

Note: As provided by 40 CFR 64.5(a)(1), the Permittee was 

not required to submit CAM plans for affected large 

pollutant-specific emissions units with the application for 

this permit because a complete CAAPP application was 

submitted before April 20, 1998. For all pollutant-specific 

emissions units that meet the criteria in 40 CFR 64.42(a), so 

as to be subject to 40 CFR Part 64, Compliance Assurance 

Monitoring (CAM) for Major Stationary Sources, the source 

must submit the information required under 40 CFR 64.4 as 

part of the application for renewal of this permit. 

5.3 General Non-Applicability of Regulations of Concern 

None 

Note: For individual emissions units and groups of units, 

non-applicability of regulations is addressed in Section 7 of this 

permit. 

5.4 Source-Wide Operational and Production Limits and Work Practices 

In addition to the source-wide requirements in the Standard Permit 

Conditions in Section 9, the Permittee shall fulfill the following 

source-wide operational and production limitations and/or work 

practice requirements: 

None 
13 

5.5 Source-Wide Emission Limitations 

5.5.1 Permitted Emissions for Fees 

Emission limitations are not set for this source for the 

purpose of permit fees. Rather, the Permittee shall pay 

the maximum fee required pursuant to Section 

39.5(18)(a)(ii)(A) of the Act, which is currently 

$250,000.00 per year. (See also Condition 9.4.) 

5.6 General Recordkeeping Requirements 

5.6.1 Records for Emissions 

The Permittee shall maintain records for the source to 

prepare its Annual Emission Report including the following 

items, pursuant to Sections 4(b) and 39.5(7)(a), (b) and 

(e) of the Act: 

a. Records of annual emissions from the emission units 

that are covered by Section 7 (Unit Specific 

Conditions) of this permit, including emissions of 

mercury, hydrogen chloride, and hydrogen fluoride. 

b. i. For purposes of estimating mercury emissions 

from the source, the mercury content of coal 

burned in boilers may be based on the data 

collected by USEPA in its Information 

Collection Request (ICR) pursuant to Section 

112 of the Clean Air Act. 

ii. If ICR data or other reliable data for 

elemental composition, including mercury 

content, is not available for coal that is 

burned in a boiler, the Permittee shall 

collect representative data on the elemental 

composition of the coal, similar to the ICR 

data collected by USEPA. 

5.6.2 Retention and Availability of Records 

The Permittee shall comply with the following requirements 

with respect to retention and availability of records 

pursuant to Sections 4(b) and 39.5(7)(a), (b), (e) and (f) 

of the Act. 

a. All records and logs required by this permit shall be 

retained for at least five years from the date of 

entry (unless a longer retention period is specified 

by the particular recordkeeping provision herein), 

shall be kept at a location at the source that is 

readily accessible to the Illinois EPA or USEPA, and 

shall be made available for inspection and copying by 

the Illinois EPA or USEPA upon request. 

b. The Permittee shall retrieve and print, on paper 

during normal source office hours, any records 

retained in an electronic format (e.g., computer) in 

response to an Illinois EPA or USEPA request for 

specific records during the course of a source 
14 

inspection. 

c. Upon written request by the Illinois EPA for copies of 

records or reports required to be kept by this permit, 

the Permittee shall promptly submit a copy of such 

material to the Illinois EPA. For this purpose, 

material shall be submitted to the Illinois EPA within 

30 days unless additional time is provided by the 

Illinois EPA or the Permittee believes that the volume 

and nature of requested material would make this 

overly burdensome, in which case, the Permittee shall 

respond within 30 days with the explanation and a 

schedule for submittal of the requested material. 

(See also Condition 9.12.4.) 

d. For certain records required to be kept by this permit 

as specifically identified in the recordkeeping 

provisions in Section 7 of this permit, which records 

are a basis for control practices or other 

recordkeeping required by this permit, the Permittee 

shall promptly submit a copy of the record to the 

Illinois EPA when the record is created or revised. 

For this purpose, the initial record shall be 

submitted within 30 days of the issuance of this 

permit. Subsequent revisions shall be submitted 

within 10 days of the date the Permittee begins to 

rely upon the revised record. 

5.7 General Reporting Requirements 

5.7.1 General Source-Wide Reporting Requirements 

The Permittee shall promptly notify the Illinois EPA of 

deviations of the source with the permit requirements as 

follows, pursuant to Section 39.5(7)(f)(ii) of the Act. 

Reports shall describe the probable cause of such 

deviations, and any corrective actions or preventive 

measures taken. 

a. For emissions units that are addressed by the unitspecific conditions of this permit, the timing for 

reporting of deviations shall be in accordance with 

such conditions. 

b. i. For other emissions units and activities at the 

source, the timing for reporting of deviations 

shall be in accordance with the provisions of 

relevant regulations if such provisions address 

timing of deviation reports. 

ii. Otherwise, if the relevant regulations do not 

address timing of deviation reports, deviation 

reports shall be submitted within 30 days. 

5.7.2 Annual Emissions Report 

The annual emissions report required pursuant to Condition 

9.7 shall contain emissions information for the previous 

calendar year including information for emissions of 

mercury, hydrogen chloride, hydrogen fluoride, and other 
15 

hazardous air pollutants, as specified by 35 IAC Part 254. 

[Sections 4(b) and 39.5(7)(a), (b) and (f) of the Act] 

5.8 General Operational Flexibility/Anticipated Operating Scenarios 

None 

Note: For individual emissions units or groups of similar 

emission units, operation flexibility and anticipated operating 

scenarios are addressed in Section 7 of this permit. 
16 

6.0 CONDITIONS FOR EMISSIONS CONTROL PROGRAMS 

6.1 NOx Trading Program 

6.1.1 Description of NOx Trading Program 

The NOx Trading Program is a regional “cap and trade” 

market system for large sources of NOx emissions in the 

eastern United States, including Illinois. It is designed 

to reduce and maintain NOx emissions from the emission 

units covered by the program within a budget to help 

contribute to attainment and maintenance of the ozone 

ambient air quality standard in the multi-state region 

covered by the program. The NOx Trading Program applies 

in addition to other applicable requirements for NOx 

emissions and in no way relaxes these other requirements. 

Electrical generating units (EGU) that are subject to the 

NOx Trading Program are referred to as “budget EGU.” 

Sources that have one or more EGU or other units subject 

to the NOx Trading Program are referred to as budget 

sources. 

The NOx Trading Program controls NOx emissions from budget 

EGU and other budget units during a seasonal control 

period from May 1 through September 30 of each year, when 

weather conditions are conducive to formation of ozone in 

the ambient air. By November 30 of each year, the 

allowance transfer deadline, each budget source must hold 

“NOx allowances” for the actual NOx emissions of its 

budget units during the preceding control period. The 

USEPA will then retire NOx allowances in the source’s 

accounts in amounts equivalent to its seasonal emissions. 

If a source does not have sufficient allowances in its 

accounts, USEPA would subtract allowances from the 

source’s future allocation for the next control period and 

impose other penalties as appropriate. Stringent 

monitoring procedures developed by USEPA apply to budget 

units to assure that actual emissions of NOx are 

accurately determined. 

The number of NOx allowances available for budget sources 

is set by the overall budget for NOx emissions established 

by USEPA. This budget requires a substantial reduction in 

NOx emissions from historical levels as necessary to meet 

air quality goals. In Illinois, existing budget sources 

initially receive their allocation or share of the NOx 

allowances budgeted for EGU in an amount determined by 

rule [35 IAC Part 217, Appendix F]. Between 2007 and 

2011, the allocation mechanism for existing EGU gradually 

shifts to one based on the actual operation of EGU in 

preceding control periods. New budget EGU, for which 

limited operating data may be available, may obtain NOx 

allowances from the new source set-aside (NSSA), a portion 

of the overall budget reserved for new EGU. 
17 

In addition to directly receiving or purchasing NOx 

allowances as described above, budget sources may transfer 

NOx allowances from one of their units to another. They 

may also purchase allowances in the marketplace from other 

sources that are willing to sell some of the allowances 

that they have received. Each budget source must 

designate an account representative to handle all its 

allowance transactions. The USEPA, in a central national 

system, will maintain allowance accounts and record 

transfer of allowances among accounts. 

The ability of sources to transfer allowances will serve 

to minimize the costs of reducing NOx emissions from 

budget units to comply with the overall NOx budget. In 

particular, the NOx emissions of budget units that may be 

most economically controlled will be targeted by sources 

for further control of emissions. This will result in a 

surplus of NOx allowances from those units that can be 

transferred to other units at which it is more difficult 

to control NOx emissions. Experience with reduction of 

sulfur dioxide emissions under the federal Acid Rain 

program has shown that this type of trading program not 

only achieves regional emission reductions in a more costeffective manner but also results in greater overall 

reductions than application of traditional emission 

standards to individual emission units. 

The USEPA developed the plan for the NOx Trading Program 

with assistance from affected states. Illinois’ rules for 

the NOx Trading Program for EGU are located at 35 IAC Part 

217, Subpart W, and have been approved by the USEPA. 

These rules provide for interstate trading, as mandated by 

Section 9.9 of the Act. Accordingly, these rules refer to 

and rely upon federal rules at 40 CFR Part 96, which have 

been developed by USEPA for certain aspects of the NOx 

Trading Program, and which an individual state must follow 

to allow for interstate trading of allowances. 

Note: This narrative description of the NOx Trading 

Program is for informational purposes only and is not 

enforceable. 

6.1.2 Applicability 

a. The following emission units at this source are budget 

EGU for purposes of the NOx Trading Program. 

Accordingly, this source is a budget source and the 

Permittee is the owner or operator of a budget source 

and budget EGU. In this section of this permit, these 

emission units are addressed as budget EGU. 

Boilers: Units 123 and 4 (Existing Units*) 

Turbines: Units 5 and 6 (New Units) 

Note: Unit 123 is considered an existing budget EGU 

as it repowered existing budget EGUs, i.e., former 

Boilers 1, 2 and 3. Pursuant to 35 IAC 211.5580, 

repowering is treated as a control technology for 

purposes of 35 IAC Part 217, rather than construction 

of a new EGU. 
18 

b. This permit does not provide “low-emitter status” for 

the above emission units pursuant to 35 IAC 

217.754(c). 

6.1.3 General Provisions of the NOx Trading Program 

a. This source and the budget EGU at this source shall 

comply with all applicable requirements of Illinois’ 

NOx Trading Program, i.e., 35 IAC Part 217, Subpart W, 

and 40 CFR Part 96 (excluding 40 CFR 96.4(b) and 

96.55(c), and excluding 40 CFR 96, Subparts C, E, and 

I), pursuant to 35 IAC 217.756(a) and 217.756(f)(2). 

b. Any provision of the NOx Trading Program that applies 

to a budget source (including any provision applicable 

to the account representative of a budget source) 

shall also apply to the owner and operator of such 

budget source and to the owner and operator of each 

budget EGU at the source, pursuant to 35 IAC 

217.756(f)(3). 

c. Any provision of the NOx Trading Program that applies 

to a budget EGU (including any provision applicable to 

the account representative of a budget EGU) shall also 

apply to the owner and operator of such budget EGU. 

Except with regard to requirements applicable to 

budget EGUs with a common stack under 40 CFR 96, 

Subpart H, the owner and operator and the account 

representative of one budget EGU shall not be liable 

for any violation by any other budget EGU of which 

they are not an owner or operator or the account 

representative, pursuant to 35 IAC 217.756(f)(4). 

6.1.4 Requirements for NOx Allowances 

a. Beginning in 2004, by November 30 of each year, the 

allowance transfer deadline, the account 

representative of each budget EGU at this source shall 

hold allowances available for compliance deduction 

under 40 CFR 96.54 in the budget EGUs compliance 

account or the source’s overdraft account in an amount 

that shall not be less than the budget EGUs total tons 

of NOx emissions for the preceding control period, 

rounded to the nearest whole ton, as determined in 

accordance with 40 CFR 96, Subpart H, plus any number 

necessary to account for actual utilization (e.g., for 

testing, start-up, malfunction, and shut down) under 

40 CFR 96.42(e) for the control period, pursuant to 35 

IAC 217.756(d)(1). For purposes of this requirement, 

an allowance may not be utilized for a control period 

in a year prior to the year for which the allowance is 

allocated, pursuant to 35 IAC 217.756(d)(5). 

b. The account representative of a budget EGU that has 

excess emissions in any control period, i.e., NOx 

emissions in excess of the number of NOx allowances 

held as provided above, shall surrender allowances as 
19 

required for deduction under 40 CFR 96.54(d)(1), 

pursuant to 35 IAC 217.756(f)(5). In addition, the 

owner or operator of a budget EGU that has excess 

emissions shall pay any fine, penalty, or assessment, 

or comply with any other remedy imposed under 40 CFR 

96.54(d)(3) and the Act, pursuant to 35 IAC 

217.756(f)(6). Each ton of NOx emitted in excess of 

the number of NOx allowances held as provided above 

for each budget EGU for each control period shall 

constitute a separate violation of 35 IAC Part 217 and 

the Act, pursuant to 35 IAC 217.756(d)(2). 

c. An allowance allocated by the Illinois EPA or USEPA 

under the NOx Trading Program is a limited 

authorization to emit one ton of NOx in accordance 

with the NOx Trading Program. As explained by 35 IAC 

217.756(d)(6), no provisions of the NOx Trading 

Program, the budget permit application, the budget 

permit, or a retired unit exemption under 40 CFR 96.5 

and no provision of law shall be construed to limit 

the authority of the United States or the State of 

Illinois to terminate or limit this authorization. As 

further explained by 35 IAC 217.756(d)(7), an 

allowance allocated by the Illinois EPA or USEPA under 

the NOx Trading Program does not constitute a property 

right. As provided by 35 IAC 217.756(d)(4), 

allowances shall be held in, deducted from, or 

transferred among allowances accounts in accordance 

with 35 IAC Part 217, Subpart W, and 40 CFR 96, 

Subparts F and G. 

6.1.5 Monitoring Requirements for Budget EGU 

a. The Permittee shall comply with the monitoring 

requirements of 40 CFR Part 96, Subpart H, for each 

budget EGU and the compliance of each budget EGU with 

the emission limitation under Condition 6.1.4(a) shall 

be determined by the emission measurements recorded 

and reported in accordance with 40 CFR 96, Subpart H, 

pursuant to 35 IAC 217.756(c)(1), (c)(2) and (d)(3). 

i. For Unit 4 and Unit 123, the Permittee is 

conducting continuous emissions monitoring for 

NOx, as generally provided for by 40 CFR 

75.71(a). 

ii. For Unit 5 and Unit 6, the Permittee is using 

the low mass emissions excepted methodology, 

as generally provided for by 40 CFR 

75.71(e)(2). 

b. The account representative for the source and each 

budget EGU at the source shall comply with those 

sections of the monitoring requirements of 40 CFR 96, 

Subpart H, applicable to an account representative, 

pursuant to 35 IAC 217.756(c)(1) and (d)(3). 
20 

6.1.6 Recordkeeping Requirements for Budget EGU 

Unless otherwise provided below, the Permittee shall keep 

on site at the source each of the following documents for 

a period of 5 years from the date the document is created. 

This 5-year period may be extended for cause at any time 

prior to the end of the 5 years, in writing by the 

Illinois EPA or the USEPA. 

a. The account certificate of representation of the 

account representative for the source and each budget 

EGU at the source and all documents that demonstrate 

the truth of the statements in the account certificate 

of representation, in accordance with 40 CFR 96.13, as 

provided by 35 IAC 217.756(e)(1)(A). These 

certificates and documents must be retained on site at 

the source for at least 5-years after they are 

superseded because of the submission of a new account 

certificate of representation changing the account 

representative. 

b. All emissions monitoring information, in accordance 

with 40 CFR 96, Subpart H, (provided that to the 

extent that 40 CFR 96, Subpart H, provides for a 3-

year period for retaining records, the 3-year period 

shall apply), pursuant to 35 IAC 217.756(e)(1)(B). 

c. Copies of all reports, compliance certifications, and 

other submissions and all records made or required 

under the NOx Trading Program or documents necessary 

to demonstrate compliance with requirements of the NOx 

Trading Program, pursuant to 35 IAC 217.756(e)(1)(C). 

d. Copies of all documents used to complete a budget 

permit application and any other submission under the 

NOx Trading Program, pursuant to 35 IAC 

217.756(e)(1)(D). 

6.1.7 Reporting Requirements for Budget EGU 

a. The account representative for this source and each 

budget EGU at this source shall submit to the Illinois 

EPA and USEPA the reports and compliance 

certifications required under the NOx Trading Program, 

including those under 40 CFR 96, Subparts D and H, and 

35 IAC 217.774, pursuant to 35 IAC 217.756(e)(2). 

b. Notwithstanding the provisions in Conditions 9.8 and 

9.9 of this CAAPP permit, these submittals need only 

be signed by the designated representative, who may 

serve in place of the responsible official for this 

purpose, as provided by Section 39.5(1) of the Act, 

and submittals to the Illinois EPA need only be made 

to the Illinois EPA, Air Compliance Section. 
21 

6.1.8 Allocation of NOx Allowances to Budget EGU 

a. The existing budget EGU identified in Condition 

6.1.2(a) EGU are entitled to NOx allowances as 

follows. (The portion of Appendix F that applies to 

the Permittee is provided in Condition 6.1.11.) The 

number of NOx allowances actually allocated for the 

budget EGU shall be the number of NOx allowances 

issued by USEPA pursuant to the allocation information 

reported to it by the Illinois EPA, which information 

may reflect adjustments to the overall allocations to 

budget EGU as provided for by 35 IAC 217.760(b) and 

(c): 

i. In 2004 through 2006 (the first three years of 

the NOx Trading Program), an annual allocation 

of NOx allowances as specified by 35 IAC 

217.764(a)(1), i.e., the number of NOx 

allowances listed in Appendix F, Column 7, and 

as provided by 35 IAC 217.768(j), a pro-rata 

share of any NOx allowances remaining in the 

new source set-aside (NSSA) following the 

allocation of allowances to new budget EGU. 

ii. In 2007, as provided by 35 IAC 217.764(b), an 

allocation of NOx allowances as specified by 

35 IAC 217.764(b)(1), i.e., the number of NOx 

allowances listed in Appendix F, Column 8, and 

as provided by 35 IAC 217.764(b)(4), a prorata share of any NOx allowances remaining 

after the allocation of allowances pursuant to 

35 IAC 217.764(b)(2) to budget EGU that 

commence operation between January 1, 1995 and 

April 30, 2003. 

iii. In 2008, as provided by 35 IAC 217.764(c), a 

specified allocation of NOx allowances, i.e., 

the number of NOx allowances listed in 

Appendix F, Column 8, and as provided by 35 

IAC 217.764(c)(4), a pro-rata share of any NOx 

allowances remaining after the allocation of 

allowances to budget EGU that commence 

operation between January 1, 1995 and 

April 30, 2004. 

iv. In 2009, as provided by 35 IAC 217.764(d), a 

specified allocation of NOx allowances, i.e., 

the number of NOx allowances listed in 

Appendix F, Column 9, and as provided by 35 

IAC 217.764(d)(4), a pro-rata share of any NOx 

allowances remaining after the allocation of 

NOx allowances to budget EGU that commence 

operation between January 1, 1995 and April 

30, 2005, and as provided by 35 IAC 

217.764(d)(6), a pro-rata share of any surplus 

of NOx allowances in the NSSA after the 

allocation of NOx allowances to new budget EGU 

pursuant to 35 IAC 217.764(d)(5). 
22 

v. In 2010, as provided by 35 IAC 217.764(e), a 

specified allocation of NOx allowances, i.e., 

the number of NOx allowances listed in 

Appendix F, Column 9, and a pro-rata share of 

any NOx allowances remaining after the 

allocation of NOx allowances to budget EGU 

that commence operation between January 1, 

1995 and April 30, 2006, and a pro-rata share 

of any surplus of NOx allowances in the NSSA 

following the allocation of NOx allowances to 

new budget EGU. 

vi. In 2011 and annually thereafter, as provided 

by 35 IAC 217.764(f), an allocation of NOx 

allowances based on the prior operation of the 

EGU during previous control periods, as 

described in Condition 6.1.8(b), and a prorata share of any surplus of NOx allowances in 

the NSSA following the allocation of NOx 

allowances to new budget EGU. 

Note: If the start of the NOx Trading program is 

shifted because of a Court Decision, the years 

defining the different control periods would be 

considered to be adjusted accordingly, as provided by 

the Board note following 35 IAC 217.764. 

b. In accordance with 35 IAC 217.762, the theoretical 

number of NOx allowances for the budget EGU listed in 

Condition 6.1.2(a), calculated as the product of the 

applicable NOx emissions rate and heat input as 

follows, shall be the basis for determining the prorata share of NOx allowances for the budget EGU and 

the allocation of NOx allowances to the budget EGU 

based on their prior operation: 

i. The applicable NOx emission rate for the 

budget EGU shall be 0.15 lb/mmBtu, as 

specified by 35 IAC 217.762(a)(1). 

ii. The applicable heat input (mmBtu/control 

period) shall be the average of the two 

highest heat inputs from the control periods 

four to six years prior to the year for which 

the allocation is being made, as provided by 

35 IAC 217.762(b)(1). 

6.1.9 Eligibility for NOx Allowances from the New Source SetAside (NSSA) 

For the new budget EGU identified in Condition 6.1.2(a), 

the Permittee is eligible to obtain NOx allowances from 

the NSSA, as provided by 35 IAC 217.768. (The existing 

budget EGU are not eligible for such allowances because 

they are “existing.”) 
23 

6.1.10 Budget Permit Required by the NOx Trading Program 

a. For this source, this segment of the CAAPP Permit, 

i.e., Section 6.1, is the Budget Permit required by 

the NOx Trading Program and is intended to contain 

federally enforceable conditions addressing all 

applicable NOx Trading Program requirements. This 

Budget Permit shall be treated as a complete and 

segregable portion of the source’s entire CAAPP 

permit, as provided by 35 IAC 217.758(a)(2). 

b. The Permittee and any other owner or operator of this 

source and each budget EGU at the source shall operate 

the budget EGU in compliance with this Budget Permit, 

pursuant to 35 IAC 217.756(b)(2). 

c. No provision of this Budget Permit or the associated 

application shall be construed as exempting or 

excluding the Permittee, or other owner or operator 

and, to the extent applicable, the account 

representative of a budget source or budget EGU from 

compliance with any other regulation or requirement 

promulgated under the CAA, the Act, the approved State 

Implementation Plan, or other federally enforceable 

permit, pursuant to 35 IAC 217.756(g). 

d. Upon recordation by USEPA under 40 CFR 96, Subpart F 

or G, or 35 IAC 217.782, every allocation, transfer, 

or deduction of an allowance to or from the budget 

units’ compliance accounts or to or from the overdraft 

account for the budget source is deemed to amend 

automatically, and become part of, this budget permit, 

pursuant to 35 IAC 217.756(d)(8). This automatic 

amendment of this budget permit shall be deemed an 

operation of law and will not require any further 

review. 

e. No revision of this Budget Permit shall excuse any 

violation of the requirements of the NOx Trading 

Program that occurs prior to the date that the 

revisions to this permit takes effect, pursuant to 35 

IAC 217.756(f)(1). 

f. The Permittee, or other owner or operator of the 

source, shall reapply for a Budget Permit for the 

source as required by 35 IAC Part 217, Subpart W and 

Section 39.5 of the Act. For purposes of the NOx 

Trading Program, the application shall contain the 

information specified by 35 IAC 217.758(b)(2). 

6.1.11 References 

35 IAC Part 217 Appendix F (provisions applicable to the 

Permittee) 

Company 

Name/ 

I.D. No. 

Generating 

Unit EGU 

NOx 

Budget 

Allowances 

80% of 

NOx 

Budget 

Allowances 

50% of 

NOx 

Budget 

Allowances 

2004, 

2005, 

2006 

Allowances 

2007, 

2008 

Allowances 

2009, 

2010 

Allowances

1 2 3 4 5 6 7 8 9 

199856AAC Marion 1 Marion 1 14 11 7 13 11 7 

199856AAC Marion 2 Marion 2 10 8 5 10 8 5 

199856AAC Marion 3 Marion 3 30 24 15 29 23 15 

199856AAC Marion 4 Marion 4 511 409 256 485 401 250 
24 

Note: The three units listed in the above table as Marion 1, 

Marion 2 and Marion 3, which are now shutdown, were repowered by 

Unit 123. 
25 

6.2 Acid Rain Program 

6.2.1 Applicability 

Under Title IV of the CAA, Acid Deposition Control, this 

source is an affected source and the following emission units 

at the source are affected units for acid deposition: 

Boilers: Units 123 and 4 

Turbines: Units 5 and 6 

Note: Title IV of the CAA, and other laws and regulations 

promulgated thereunder, establish requirements for 

affected sources related to control of emissions of 

pollutants that contribute to acid rain. For purposes of 

this permit, these requirements are referred to as Title 

IV provisions. 

6.2.2 Applicable Emission Requirements 

The owners and operators of the source shall not violate 

applicable Title IV provisions. In particular, NOx 

emissions of Unit 4 shall not exceed the limit set by 40 

CFR Part 76, i.e., 0.86 lb/mmBtu, annual average. SO2

emissions of the affected units shall not exceed any 

allowances that the source lawfully holds under Title IV 

provisions. [Section 39.5(7)(g) and (17)(l) of the Act] 

Note: Affected sources must hold SO2 allowances to 

account for the SO2 emissions from affected units at the 

source that are subject to Title IV provisions. Each 

allowance is a limited authorization to emit up to one ton 

of SO2 emissions during or after a specified calendar year. 

The possession of allowances does not authorize 

exceedances of applicable emission standards or violations 

of ambient air quality standards. 

6.2.3 Monitoring, Recordkeeping and Reporting 

The owners and operators of the source and, to the extent 

applicable, their designated representative, shall comply 

with applicable requirements for monitoring, recordkeeping 

and reporting specified by Title IV provisions, including 

40 CFR Part 75. [Section 39.5(7)(b) and 17(m) of the Act] 

Note: As further addressed by Section 7 of this permit, 

the following emission determination methods are currently 

being used for the affected boiler units at this source. 

NOx: Continuous Emissions Monitoring (40 CFR 75.12) 

SO2: Continuous Emissions Monitoring (40 CFR 75.11) 

Opacity: Continuous Emission Monitoring (40 CFR 75.14) 

6.2.4 Acid Rain Permit 

The owners and operators of the source shall comply with 

the terms and conditions of the source’s Acid Rain permit. 

[Section 39.5(17)(l) of the Act] 
26 

Note: The source is subject to an Acid Rain permit, which 

was issued pursuant to Title IV provisions, including 

Section 39.5(17) of the Act. Affected sources must be 

operated in compliance with their Acid Rain permits. 

This source’s Acid Rain permit is incorporated by 

reference into this permit and a copy of the current Acid 

Rain permit is included as Attachment 5 of this permit. 

Revisions and modifications of this Acid Rain permit, 

including administrative amendments and automatic 

amendments (pursuant to Sections 408(b) and 403(d) of the 

CAA or regulations thereunder) are governed by Title IV 

provisions, as provided by Section 39.5(13)(e) of the Act. 

Accordingly, revision or renewal of the Acid Rain permit 

may be handled separately from this CAAPP permit and a 

copy of the new Acid Rain permit may be included in this 

permit by administrative amendment. 

6.2.5 Coordination with Other Requirements 

a. This permit does not contain any conditions that are 

intended to interfere with or modify the requirements 

of Title IV provisions. In particular, this permit 

does not restrict the flexibility under Title IV 

provisions of the owners and operators of this source 

to amend their Acid Rain compliance plan. [Section 

39.5(17)(h) of the Act] 

b. Where another applicable requirement of the CAA is 

more stringent than an applicable requirement of Title 

IV provisions, both requirements are incorporated into 

this permit and are enforceable and the owners and 

operators of the source shall comply with both 

requirements. [Section 39.5(7)(h) of the Act] 
27 

7.0 UNIT SPECIFIC CONDITIONS 

7.1 Circulating Fluidized Bed (CFB) Boiler 

7.1.1 Description 

The Permittee operates a circulating fluidized bed (CFB) 

boiler for electric generation. The boiler is designed to 

burn a variety of solid fuels, including coal, coal 

refuse, petroleum coke, tire derived fuel and wood chips. 

The boiler has a nominal capacity of 1402 mmBtu/hour and 

is served by a dedicated stack. In addition to coal and 

other solid fuels, this boiler fires fuel oil or natural 

gas as auxiliary fuel during startup and for flame 

stabilization. 

Sulfur dioxide (SO2) emissions from the boiler are 

controlled by limestone injection into the bed of the 

boiler. Nitrogen oxide (NOx) emissions are controlled by 

a selective non-catalytic reduction (SNCR) system. 

Particulate matter (PM) emissions are controlled by a 

baghouse. 

Construction of this boiler commenced in 2001,under Permit 

00070030. The boiler repowered an existing steam turbine, 

replacing three old coal fired boilers, Units 1, 2 and 3. 

 These old boilers have now been permanently removed from 

service. Accordingly, as provided by 35 IAC 211.5880, as 

Unit 123 repowered existing units, it is considered an 

existing unit for purposes of the NOx control requirements 

of 35 IAC Part 217, rather than a newly constructed unit. 

7.1.2 List of Emission Units and Air Pollution Control Equipment 

Boiler 

I.D. Description 

Emission Control 

Equipment 

Boiler 

Unit 123 

Circulating Fluidized Bed 

Boiler Nominal 

1,400 mmBtu/hr (2001) 

Limestone 

Injection, SNCR 

and Baghouse 

7.1.3 Applicability Provisions 

a. i. An “affected boiler” for the purpose of these 

unit-specific conditions is the boiler 

described in Conditions 7.1.1 and 7.1.2. 

ii. The affected boiler is also an “affected 

facility” for purposes of the New Source 

Performance Standards (NSPS) for Electric 

Utility Steam Generating Units for Which 

Construction Is Commenced After September 18, 

1978, pursuant to 40 CFR 60.40a. As an 

affected facility, the boiler is subject to 

applicable requirements of the NSPS, 40 CFR 60 

Subpart Da and related requirements in the 

NSPS, 40 CFR 60 Subpart A, General Provisions. 
28 

b. Startup Provisions 

Subject to the following terms and conditions, the 

Permittee is authorized to operate the affected boiler 

in violation of the applicable standards in Condition 

7.1.4(b) (35 IAC 212.122), Condition 7.1.4(c) (35 IAC 

212.204), Condition 7.1.4(d) (35 IAC 214.121(a)), 

Condition 7.1.4(e) (35 IAC 216.121), and Condition 

7.1.4(f) (35 IAC 217.121(d)) during startup. This 

authorization is provided pursuant to 35 IAC 201.149, 

201.161 and 201.262, as the Permittee has applied for 

such authorization in its application, generally 

describing the efforts that will be used “...to minimize 

startup emissions, duration of individual startups and 

frequency of startups.” 

i. This authorization does not relieve the 

Permittee from the continuing obligation to 

demonstrate that all reasonable efforts are 

made to minimize startup emissions, duration 

of individual startups and frequency of 

startups. 

ii. The Permittee shall conduct startup of an 

affected boiler in accordance with written 

procedures prepared by the Permittee and 

maintained in the control room for the boiler, 

that are specifically developed to minimize 

emissions from startups and that include, at a 

minimum, the following measures: 

A. Use of auxiliary fuel burners to heat the 

boiler prior to initiating burning of coal. 

B. Appropriate SNCR reagent injection to 

minimize emissions without damage or risk 

to personnel or equipment. 

C. Appropriate baghouse operation to minimize 

emissions without damage or risk to 

personnel or equipment. 

iii. The Permittee shall fulfill applicable 

recordkeeping and reporting requirements of 

Conditions 7.1.9(c), (d), (e), and (f) and 

7.1.10-2(a). 

iv. As provided by 35 IAC 201.265, an 

authorization in a permit for excess emissions 

during startup does not shield a Permittee 

from enforcement for any violation of 

applicable emission standard(s) that occurs 

during startup and only constitutes a prima 

facie defense to such an enforcement action 

provided that the Permittee has fully complied 

with all terms and conditions connected with 

such authorization. 
29 

c. Malfunction and Breakdown Provisions 

Subject to the following terms and conditions, the 

Permittee is authorized to continue operation of an 

affected boiler in violation of the applicable 

requirements of Condition 7.1.4(b) (35 IAC 212.122), 

Condition 7.1.4(c) (35 IAC 212.204), Condition 

7.1.4(d) (35 IAC 214.121(a)), Condition 7.1.4(e) (35 

IAC 216.121), and Condition 7.1.4(f) (35 IAC 

217.121(d)) in the event of a malfunction or breakdown 

of an affected boiler, including associated control 

equipment and support systems (coal bunkers, coal 

preparation systems, ash removal and handling systems, 

etc.). This authorization is provided pursuant to 35 

IAC 201.149, 201.161 and 201.262, as the Permittee has 

applied for such authorization in its application, 

generally explaining why such continued operation 

would be required to provide essential service or to 

prevent injury to personnel or severe damage to 

equipment, and describing the measures that will be 

taken to minimize emissions from any malfunctions and 

breakdowns. This authorization supersedes the general 

prohibition in Condition 9.2.3 against continued 

operation in such circumstances. 

i. This authorization only allows such continued 

operation as necessary to provide essential 

service or to prevent injury to personnel or 

severe damage to equipment and does not extend 

to continued operation solely for the economic 

benefit of the Permittee. 

ii. Upon occurrence of excess emissions due to 

malfunction or breakdown, the Permittee shall 

as soon as practicable reduce boiler load, 

repair the affected boiler, remove the 

affected boiler from service or undertake 

other action so that excess emissions cease. 

iii. The Permittee shall fulfill applicable 

recordkeeping and reporting requirements of 

Conditions 7.1.9(c) and (i), 7.1.10-2(d) and 

7.1.10-3(a). For these purposes, time shall be 

measured from the start of a particular 

incident. The absence of excess emissions for a 

short period shall not be considered to end the 

incident if excess emissions resume. In such 

circumstances, the incident shall be considered 

to continue until corrective actions are taken 

so that excess emissions cease or the Permittee 

takes the boiler out of service. 

iv. Following notification to the Illinois EPA of a 

malfunction or breakdown with excess emissions, 

the Permittee shall comply with all reasonable 

directives of the Illinois EPA with respect to 

such incident, pursuant to 35 IAC 201.263. 
30 

v. This authorization does not relieve the Permittee 

from the continuing obligation to minimize excess 

emissions during malfunction or breakdown. As 

provided by 35 IAC 201.265, an authorization in a 

permit for continued operation with excess 

emissions during malfunction and breakdown does 

not shield the Permittee from enforcement for any 

such violation and only constitutes a prima facie 

defense to such an enforcement action provided 

that the Permittee has fully complied with all 

terms and conditions connected with such 

authorization. 

7.1.4 Applicable Emission Standards 

a. Federal NSPS standards 

i. The affected boiler is subject to New Source 

Performance Standards (NSPS) for Electric 

Utility Steam Generating Units, 40 CFR 60, 

Subpart Da. 

ii. Pursuant to 40 CFR 60.42a(a), the emissions of 

PM from the affected boiler shall not exceed 

0.03 lb/million Btu heat input derived from 

the combustion of solid, liquid, or gaseous 

fuel. 

Note: Pursuant to 40 CFR 60.46a(a), 

compliance with the above limits constitutes 

compliance with the percent reduction 

requirements for PM emissions under 40 CFR 

60.42a(a)(2), i.e., 1 percent of the potential 

combustion concentration (99 percent 

reduction) when combusting solid fuel. 

iii. Opacity from the affected boiler shall not 

exceed 20 percent, as measured on a six minute 

average, except for one 6 minute period per 

hour of not more than 27 percent pursuant to 

NSPS, 40 CFR 60.42a(b). 

iv. Pursuant to 40 CFR 60.43a(a), the emissions of 

SO2 from the affected boiler shall not exceed 

the following limits. Compliance with the 

emission limit and percent reduction 

requirements are both determined on a 30-day 

rolling average basis, pursuant to 40 CFR 

60.43a(g). 

A. 1.20 lb/million Btu heat input and 10 

percent of the potential combustion 

concentration (90 percent reduction), or 

B. 30 percent of the potential combustion 

concentration (70 percent reduction), when 

emissions are less than 0.60 lb/million 

Btu heat input. 
31 

v. Pursuant to 40 CFR 60.44a(d)(1), the emissions 

of NOx from the affected boiler shall not 

exceed 1.6 pounds per megawatt-hour gross 

energy output, based on a 30-day rolling 

average. 

vi. Pursuant to 40 CFR 60.7(a) and 60.46a(c), the 

above standards in Conditions 7.1.4(a)(ii), 

(iii) and (v) do not apply during startup, 

malfunction, and shutdown, and the above 

standard in Condition 7.1.4(a)(iv) does not 

apply during startup and shutdown. For this 

purpose, the definitions of terms at 40 CFR 

60.2 are applicable. Notwithstanding this 

provision, exceedances of these limitations 

during startup, malfunction, and shutdown are 

still subject to recordkeeping and reporting 

requirements under the NSPS. 

b. The affected boiler is subject to 35 IAC 212.122, 

which provides that no person shall cause or allow the 

opacity from a new fuel combustion emission unit with 

a heat input greater than 250 mmBtu/hr to exceed 20 

percent, except as provided by 35 IAC 212.122(b). 

c. The emissions of PM from the affected boiler shall not 

exceed 0.1 lb/mmBtu of actual heat input in any one 

hour period, pursuant to 35 IAC 212.204. 

d. The emissions of SO2 from the affected boiler shall 

not exceed 1.2 lb/mmBtu of actual heat input, pursuant 

to 35 IAC 214.121(a). 

e. The emissions of CO from the affected boiler shall not 

exceed 200 ppm, corrected to 50 percent excess air, 

pursuant to 35 IAC 216.121. 

f. The emissions of NOx from the affected boiler shall 

not exceed 0.7 lb/mmBtu of actual heat input in any 

one hour period, pursuant to 35 IAC 217.121(d). 

g. The affected boiler is subject to the following 

requirements related to NOx emissions pursuant to 35 

IAC Part 217 Subpart V: 

i. During each ozone control period (May 1 

through September 30): 

A. The emissions of NOx from the affected 

boiler shall not exceed 0.25 lb/mmBtu of 

actual heat input based on an ozone 

control period average, for the unit, 

pursuant to 35 IAC 217.706(a), or 

B. If the Permittee elects to participate in 

a NOx averaging plan, the emissions of NOx 

from the affected boiler and other 
32 

eligible EGU that are participating in 

such NOx averaging demonstration shall not 

exceed 0.25 lbs/mmBtu of actual heat 

input, as averaged for the ozone control 

period for the EGU participating in the 

demonstration, pursuant to 35 IAC 

217.708(a) and (b). For this purpose, 

other eligible EGU include: (1) Existing 

Boiler 4 and (2) other EGU that are 

authorized to participate in a NOx 

averaging plan by a CAAPP permit or other 

federally enforceable permit issued by the 

Illinois EPA to the owner or operator of 

those EGU. 

Note: Given the emission determination methods 

specified by 35 IAC 217.710, the emissions of NOx for 

purposes of these standards are generally calculated 

in accordance with the federal Acid Rain Program and 

are different from the emissions determined for 

purposes of the NOx Trading Program. 

ii. If the Permittee elects to have the affected 

boiler participate in a NOx averaging 

demonstration as provided for and authorized 

above: 

A. The affected boiler shall be included in 

only one NOx averaging demonstration 

during an ozone control period, pursuant 

to 35 IAC 217.708(d). 

B. The NOx averaging demonstration shall only 

include other EGU that are authorized 

through a federally enforceable permit to 

participate in a NOx averaging 

demonstration and for which the owner or 

operator of the EGU maintains the required 

records, data and reports and submits 

copies of such records, data, and reports 

to the Illinois EPA upon request, pursuant 

to 35 IAC 217.708(c) and (g). 

C. The effect of failure of the NOx averaging 

demonstration to show compliance shall be 

that the compliance status of the affected 

boiler shall be determined pursuant to 

Condition 7.1.4(g)(i)(A) as if the NOx 

emission rate of the affected boiler was 

not averaged with other EGU, pursuant to 

35 IAC 217.708(f). 

Note: The above requirements also apply as a matter 

of rule to EGUs other than the affected boiler if the 

owner or operator of such other EGUs elects to 

participate in a NOx averaging demonstration. 
33 

7.1.5 Non-Applicability of Regulations of Concern 

a. This permit is issued based on the affected boiler not 

being subject to the NSPS, 40 CFR 60 Subpart D 

pursuant to 40 CFR 60.40(e), which provides that a 

steam generating unit covered by 40 CFR 60 Subpart Da 

is not covered under 40 CFR 60 Subpart D. 

b. i. This permit is issued based on the affected 

boiler not being subject to NSPS standards for 

firing of gas or oil, i.e., 40 CFR 60.43a(b) 

and (h) for SO2 and 40 CFR 60.44a(a) and (c), 

for NOx when it is using solid fuel as its 

principal fuel and other fuels are only used 

in incidental amounts for specific purposes, 

such as startup, opacity reduction emission 

mitigation, flame stabilization, outage of a 

coal pulverizer, or other temporary 

interruption in solid fuel supply, as 

associated with routine firing of solid fuel. 

ii. If the affected boiler is not using solid fuel 

as its principal fuel, the affected boiler 

shall comply with the requirements of the 

following NSPS standards that address burning 

a combination of fuels: 

A. For SO2, 40 CFR 60.43a(h). 

B. For NOx, 40 CFR 60.44a(c). 

c. i. The Permittee is shielded from 35 IAC 212.207, 

35 IAC 214.162, and 35 IAC 217.121(e), which 

address PM, SO2, and NOx emissions from 

burning a combination of fuels, for the 

affected boiler when the boiler is using solid 

fuel as its principal fuel. This is because 

incidental use of other fuels generally serves 

as a good combustion practice for firing of 

solid fuel and does not provide a decrease in 

emissions that can be used to reduce the 

emission rate that must be achieved for the 

emissions associated with combustion of solid 

fuel. 

ii. If the affected boiler is not using solid fuel 

as its principal fuel, the affected boiler 

shall comply with the requirements of the 

following conditions. During such periods for 

PM, Condition 7.1.5(c)(ii)(A) shall substitute 

for Condition 7.1.4(c); for SO2, Condition 

7.1.5(c)(ii)(B), shall supplement Condition 

7.1.4(d), and for NOx, Condition 

7.1.5(c)(ii)(C) shall substitute for Condition 

7.1.4(e). 
34 

A. The emissions of PM from the affected 

boiler in any one hour period shall not 

exceed the amount, in lb/hr, allowed by 

the formula in 35 IAC 212.207. For this 

purpose, the applicable PM standard for 

heat input from liquid fuel shall be 0.1 

lb/mmBtu, pursuant to 35 IAC 212.206 and 

212.207. 

B. The emissions of SO2 from the affected 

boiler in any one hour period shall not 

exceed the amount, in lb/hr, allowed by 

the formula in 35 IAC 214.162. For this 

purpose, the applicable SO2 standards for 

heat input from residual fuel oil, 

distillate fuel oil shall be 0.8, 0.3 

lb/mmBtu, respectively, pursuant to 35 IAC 

214.121(b)(1), 214.121(b)(2), and 214.162. 

C. The emissions of NOx from the affected 

boiler shall not exceed the amount, in 

lb/hr, allowed by the formula in 35 IAC 

217.121(e). 

iii. For the purpose of the above conditions, an 

affected boiler shall be considered to be using 

solid fuel as its principal fuel if the use of 

natural gas and/or fuel oil is incidental to the 

use of coal, occurring for specific purposes 

associated with routine firing of solid fuel, 

such as startup, opacity reduction emission 

mitigation, flame stabilization, outage of coal 

preparation equipment, or other temporary 

disruption in solid fuel supply. A boiler shall 

not be considered to be using solid fuel as its 

principal fuel if the use of natural gas and/or 

fuel oil is more than incidental to the firing of 

coal in the boiler or the use of fuel is 

incidental to the operation of the boiler. 

iv. The Permittee shall notify the Illinois EPA if 

the status of an affected boiler changes to or 

from using solid fuel as its principal fuel. 

This notification shall be provided at least 7 

days in advance of such change in status 

unless the change results from a sudden event 

that precludes such advance notification, in 

which case notification shall be provided as 

soon as practicable prior to the change. 

d. Pursuant to 35 IAC 201.403(a), the Permittee is not 

subject to the requirements of 35 IAC Part 201 Subpart 

L for opacity and SO2 monitoring because the Permittee 

must conduct opacity and SO2 monitoring on the 

affected boiler in accordance with the NSPS, 40 CFR 

Part 60, pursuant to the NSPS and the federal Acid 

Rain program. 
35 

7.1.6-1 Work Practice Requirements 

a. As part of its operation and maintenance of the 

affected boiler, the Permittee shall perform formal 

“combustion evaluation” on the boiler on at least a 

quarterly basis, pursuant to Section 39.5(7)(d) of the 

Act. These evaluations shall consist of diagnostic 

measurements of the concentration of CO in the flue 

gas of the boiler, with adjustments and preventative 

and corrective measures for the boiler’s combustion 

systems to maintain efficient combustion. 

b. At all times, the Permittee shall maintain and operate 

the affected boiler, including associated air 

pollution control equipment, in a manner consistent 

with good air pollution control practice for 

minimizing emissions, as required pursuant to the 

NSPS, 40 CFR 60.11(d). 

7.1.6-2 Requirements from Construction Permit 00070030 

a. The emissions from the affected boiler shall not 

exceed the following limits. Compliance with the 

annual limitations shall be determined from a running 

total of 12 months of data, i.e., from the sum of the 

data for the current month plus the preceding 11 

months. [T1] 

Emissions 

Pollutant Emission Rate (Lb/hr) (T/yr) 

 NOx 1.6 lb/MW-hr 192 841 

 CO 0.150 lb/mmBtu 210 921 

 VOM 0.01 lb/mmBtu 10.1 44.2 

 SO2 0.6 lb/mmBtu 841 3,690 

 TSP/PM10 0.011 lb/mmBtu* 15.4* 67.5*

* TSP and PM10 limits only include front-half 

(filterable) particulates. 

Notes: The emission limits in lb/MW-hr, lb/mmBtu and 

lb/hr shall not apply during start-up, shutdown, or 

malfunction, which are addressed by Condition 7.1.6-

2(c). The NOx and SO2 emission rate in lb/MW-hr and 

lb/mmBtu, respectively, are based upon a 30-day 

rolling average with compliance determined in 

accordance with the applicable provisions of the NSPS. 

The NOx and SO2 emission limits in lb/mmBtu are based 

on the applicable provisions in the NSPS 40 CFR Part 

60 Subpart Da. Compliance with other limits in 

lb/mmBtu and the limits in lb/hr shall be based on 

3-hour block averages. 

b. i. The CO emissions from the affected boiler 

shall not exceed 0.15 lb/mmBtu, based on a 

3-hour block average, except during startup, 

malfunction or breakdown and shutdown as 

addressed by Condition 7.1.6-2(c). [T1] 
36 

ii. The Permittee shall evaluate CO emissions from 

the affected boiler to determine whether a lower 

CO emission limit (as low as 0.10 lb/mmBtu) may 

be reliably achieved while complying with other 

emission limits without significant risk to 

equipment or personnel and unreasonable increase 

in maintenance and repair needed for the boiler. 

This evaluation shall be conducted in accordance 

with Condition 20 of Construction Permit 

00070030. [T1] 

c. The affected boiler and air pollution control 

equipment shall be operated to minimize emissions 

during startup, malfunction and shutdown including the 

following: [T1] 

i. A. Operation in accordance with the 

manufacturer's written instructions, or 

other written instructions developed and 

maintained by the Permittee; and 

B. Review of operating parameters of the unit 

during startup, malfunction, breakdown or 

shutdown as necessary to make adjustments 

to reduce or eliminate excess emissions. 

ii. The Permittee shall maintain the affected 

boiler and air pollution control equipment in 

accordance with written procedures developed 

and maintained by the Permittee. These 

procedures shall be reviewed at least annually 

and enhanced consistent with good air 

pollution control practice based on actual 

operating experience and performance. 

iii. Upon malfunction of the affected boiler or any 

air pollution control equipment that will 

result in emissions in excess of the 

applicable limits in Condition 7.1.6-2(a) or 

(b), the Permittee shall, as soon as 

practicable, repair the affected system or 

remove the system from service so that excess 

emissions cease. 

iv. Consistent with the above, if the Permittee 

has maintained and operated the affected 

boiler and air pollution control equipment so 

that malfunctions are infrequent, sudden, not 

caused by poor maintenance or careless 

operation, and in general are not reasonably 

preventable, the Permittee shall begin 

shutdown of the system within 90 minutes, 

unless the malfunction is expected to be 

repaired within 120 minutes or such shutdown 

could threaten the stability of the regional 

electrical power system. In such case, 

shutdown of the system shall be undertaken 
37 

when it is apparent that repair will not be 

accomplished within 120 minutes or shutdown 

will not endanger the regional power system. 

In no case shall shutdown of the affected 

boiler be delayed solely for the economic 

benefit of the Permittee. 

v. Notwithstanding the above, if the Permittee 

determines that the continuous emission 

monitoring system (CEMS) is inaccurately 

reporting excess emissions, the Permittee may 

continue operation provided the Permittee 

records the information it is relying upon to 

conclude that the affected boiler and emission 

control systems are functioning properly and 

the CEMS is reporting inaccurate data and the 

Permittee takes prompt action to resolve the 

accuracy of the CEMS. 

Note: The above requirements in Conditions 7.1.6-2(a), 

(b) and (c) were originally established in Construction 

Permit 00070030 pursuant to the federal PSD rules. For 

emissions of CO, Conditions 7.1.6-2(b) and (c) represent 

the application of BACT as required by the PSD rules. For 

pollutants other than CO, these requirements were intended 

to ensure that the construction and operation of the 

affected boiler do not constitute a major modification 

under the PSD rules. 

d. The fuel feed stream combusted in the affected boiler 

shall contain no more than 20 percent by weight, on a 

calendar quarter basis, of tires, tire derived fuel, and 

other materials which constitute municipal solid waste 

as defined in 40 CFR 60.51a. As a consequence of this 

restriction, if these supplemental fuels were fired, the 

affected boiler would constitute a co-fired boiler 

pursuant to 40 CFR 60.50b(g), provided that the 

Permittee notifies the USEPA of this status, with a copy 

of such notification also sent to the Illinois EPA. 

e. i. Supplemental fuels shall be burned in a blend 

with commercial fuels (coal refuse, coal, 

petroleum coke, etc.) so as to not exceed 20 

percent by weight in the total fuel supply to 

the affected boiler on a daily basis. For this 

purpose, supplemental fuels include tires and 

tire derived fuel, as defined in Section 54 of 

the Act, and clean wood, as defined in 40 CFR 

60.51b. 

ii. The Permittee shall handle supplemental fuels for 

the affected boiler in accordance with a written 

fuel management plan designed to assure that 

acceptable fuel is received and fuel is safely 

stored and handled. This plan shall include the 

specifications for acceptable fuel, anticipated 

sources of fuel, procedures for qualifying fuel 

suppliers, procedures for inspection of fuel 
38 

shipments, procedures for rejection of 

unacceptable shipments, and procedures for onsite handling and storage of fuel. 

iii. The Permittee shall burn supplemental fuels in 

the affected boiler in accordance with written 

operating procedures designed to assure a uniform 

and consistent blend of fuel to the boilers and 

operation of the boilers in compliance with 

applicable requirements of this permit. This 

plan shall include the design and maximum amount 

of the fuel in the total blend, procedures for 

blending fuels, changes to normal operating 

procedures for the boiler, if any, and acceptable 

ranges for boiler and air pollution control 

equipment operating parameters, if different than 

normal. 

iv. Nothing in these conditions shall excuse the 

Permittee from compliance with applicable 

statutes and rules governing supplemental 

fuels, including rules governing storage of 

tires. 

f. The Permittee shall not burn wastes that are generated 

by another person’s activities, other than tires and 

tire derived fuel in the affected boiler, without 

first having obtained local approval pursuant to 

Section 39.2 of the Act, if required, and appropriate 

permits from the Illinois EPA. For this purpose, a 

clean wood material may be considered a waste if it is 

a discarded material. 

Note: This requirement was originally established in 

Construction Permit 00070030 pursuant to State 

authority, to address State requirements under Section 

39.2 of the Act. As this condition addresses State 

requirements that are not federally enforceable, this 

condition is not a federally enforceable provision of 

this CAAPP permit. 

7.1.7 Testing Requirements 

Pursuant to Section 39.5(7)(d)(ii) of the Act, the 

Permittee shall have the PM and CO emissions of the 

affected boiler measured as specified below: 

a. i. Periodic PM emission measurements shall be 

made within a time period determined from the 

compliance margin for the applicable PM 

emission standard, based on the results of the 

preceding PM measurement, as follows. For this 

purpose, the compliance margin is the extent 

to which the actual PM emissions as measured 

are lower than the most stringent PM limit 

that is applicable. For example, if the 

measured PM emissions of the affected boiler 

is 0.02 lb/mmBtu, the compliance margin for 
39 

the applicable PM limit, 0.01 lb/mmBtu, would 

be 25 percent. (0.030 – 0.02 = 0.01, 

0.01/0.03 = 0.33 or 30 percent) 

A. If the compliance margin is less than 20 

percent, within 15 months of the previous 

measurement. 

B. If the compliance margin is between 20 and 

40 percent, within 27 months of the 

previous measurement. 

C. If the compliance margin is greater than 

40 percent, within 39 months of the 

previous measurement. 

ii. PM emission measurements shall be made within 

90 days of operating the affected boiler for 

more than 24 hours total in a calendar quarter 

at a load* that is more than 5 percent higher 

than the greatest load on the boiler during 

the most recent set of PM tests on the boiler 

in which compliance is shown (refer to 

Condition 7.1.7(e)(iii)(D)), provided, 

however, that the Illinois EPA may upon 

request of the Permittee provide more time for 

testing (if such time is reasonably needed to 

schedule and perform testing or coordinate 

testing with seasonal conditions). 

* For this purpose, load shall be expressed 

in terms of either gross megawatt output 

or steam flow, consistent with the form of 

the records kept by the Permittee pursuant 

to Condition 7.1.9(a). 

iii. Measurements of CO emissions shall be made 

with each measurement of PM emissions made 

pursuant to Condition 7.1.7(a)(i) or (ii) (or 

a RATA for SO2 or NOx preceding such 

measurement). 

iv. A. If commercial and supplemental fuels are 

less than 97.0 percent by weight of the 

fuel supply to a boiler during a quarter, 

the Permittee shall have measurements of 

PM and CO emissions from the boiler made 

during the next quarter while firing 

alternative fuel or process waste in the 

boiler. 

B. The Permittee shall conduct such 

measurements while firing the boiler with 

at least 1.25 times the greatest 

percentage of alternative fuel material or 

process waste in the calendar quarter that 

triggered the testing. This percentage at 

which testing shall be conducted shall not 
40 

exceed that allowed by the maximum design 

capacity of the alternative fuel handling 

system. If the boiler has been firing a 

mix of supplemental fuels, alternative 

fuel materials or process wastes, the mix 

of fuel during such measurements shall be 

approved by the Illinois EPA. 

C. The Permittee shall repeat such 

measurements if the percentage of 

alternative fuel materials and process 

wastes burned in a boiler during a quarter 

is more than the percentage of such 

material in the fuel supply to the boiler 

when previous emission measurements were 

conducted. 

v. Measurements of PM, CO and VOM emissions shall 

be made within 90 days (or such later date set 

by the Illinois EPA) following a request by 

the Illinois EPA for such measurements. 

Note: Construction Permit 00070030 requires that 

initial performance tests be conducted for the 

affected boiler that include measurements for 

emissions of PM, CO and VOM. Testing for emissions of 

SO2 and NOx is also required, but may be performed in 

conjunction with certification of the continuous 

emission monitoring systems (CEMS). 

b. i. These measurements shall be performed at the 

maximum operating load of the affected boiler 

and other operating conditions that are 

representative of normal operation. In 

addition, the Permittee may perform 

measurements at other operating conditions to 

evaluate variation in emissions. 

ii. Measurements shall be taken at an appropriate 

location in the ductwork or stack associated 

with the affected boiler. 

iii. The following test methods and procedures 

shall be used for these measurements. Refer 

to 40 CFR 60, Appendix A for USEPA Methods. 

Location of Sample Points Method 1 

Gas Flow and Velocity Method 2 

Flue Gas Weight Method 3 

Moisture Method 4 

Particulate Matter (PM) Methods 5 & 202* 

Carbon Monoxide (CO) Method 10** 

Volatile Organic Material (VOM) Methods 18 & 25/25A** 

* Measurements of condensable PM are also 

required by USEPA Method 202 (40 CFR Part 

51, Appendix M) or other established test 

method approved by the Illinois EPA, 

except for a test conducted prior to 

issuance of this permit. 
41 

** For CO and VOM, other test methods 

developed or adopted by USEPA may be used 

in place of the above methods with the 

approval of the Illinois EPA 

c. Except for minor deviations in test methods, as 

defined by 35 IAC 283.130, emission testing shall be 

conducted in accordance with a test plan prepared by 

the testing service or the Permittee and submitted to 

the Illinois EPA for review prior to emission testing, 

and the conditions, if any, imposed by the Illinois 

EPA as part of its review and approval of the test 

plan, pursuant to 35 IAC 283.220 and 283.230. 

i. The Permittee shall submit this test plan at 

least 60 days prior to the actual date of 

testing and the test plan shall include the 

information specified by Condition 8.6.2. 

ii. Notwithstanding the above, as provided by 35 IAC 

283.220(d), the Permittee need not submit a test 

plan for emission testing that will be conducted 

in accordance with the procedures used for 

previous tests accepted by the Illinois EPA or 

the previous test plan submitted to and approved 

by the Illinois EPA, provided that the 

Permittee’s notification for testing, as 

required below, contains the information 

specified by 35 IAC 283.220(d)(1)(A), (B) and 

(C). 

d. The Permittee shall notify the Illinois EPA prior to 

conducting emission tests to enable the Illinois EPA 

to observe testing. Notification for the expected 

test date shall be submitted a minimum of 30 days 

prior to the expected date of testing. Notification 

of the actual date and expected time of testing shall 

be submitted a minimum of 5 working days prior to the 

actual test date. The Illinois EPA may on a case-by 

case basis accept shorter advance notice if it would 

not interfere with the Illinois EPA’s ability to 

observe testing. 

e. The Permittee shall submit the Final Report(s) for any 

required emission testing to the Illinois EPA within 

45 days after the tests results are compiled and 

finalized but no later than 120 days after the date of 

testing. The Final Report shall include the 

information specified in Condition 8.6.3 and the 

following information: 

i. Description of test method(s), including 

description of sampling points, sampling 

train, analysis equipment, and test schedule. 

ii. A description of any minor deviations from the 

test plan, as provided by 35 IAC 283.230(a). 
42 

iii. Detailed description of operating conditions 

during testing, including: 

A. Source(s) of fuel and specifications (ash, 

sulfur and heat content). 

B. Boiler operating information, i.e., firing 

rate of the affected boiler(s) (mmBtu/hr), 

composition of fuel as burned (ash, sulfur 

and heat content), and fuel blending ratio 

(%), if a blend of fuels is burned. 

C. Combustion system information, i.e., 

settings for distribution of primary and 

secondary combustion air, target level for 

O2 in the flue gas, and levels of CO, CO2

or O2 in the flue gas, as determined by 

any diagnostic measurements. 

D. Control equipment information, i.e., 

equipment condition and operating 

parameters during testing. 

E. Load during testing (gross megawatt output 

and steam flow). 

iv. Data and calculations, including copies of all 

raw data sheets and records of laboratory 

analyses, sample calculations, and data on 

equipment calibration. 

v. The SO2, NOx, O2 or CO2, (hourly averages) and 

opacity data (6-minute averages) measured 

during testing. 

7.1.8 Monitoring Requirements 

a. Pursuant to 40 CFR 60.45a, 40 CFR 75.14, and Section 

39.5(7)(d)(iii) of the Act, the Permittee shall 

install, operate, calibrate and maintain continuous 

monitoring equipment for the measurement of opacity 

from the affected boiler. 

i. The Permittee shall operate this equipment in 

accordance with the general provisions for 

opacity monitoring systems in 40 CFR 75.10. 

ii. This monitor shall be the primary basis for 

reporting exceedances of Conditions 

7.1.4(a)(iii) and (c). (See Conditions 7.1.10-

2(a) and 7.1.10-3(a).) 

b. Pursuant to 40 CFR 60.47a(b), 40 CFR 75.11, and 

Section 39.5(7)(d)(iii) of the Act, the Permittee 

shall install, operate, calibrate and maintain a 

continuous emission monitoring system (CEMS) for the 

measurement of SO2 emissions from the affected boiler. 
43 

i. Pursuant to NSPS, 40 CFR 60.47a(f) and (h), 

the Permittee shall obtain emission data for 

at least 18 hours in at least 22 out of 30 

successive boiler operating days. If this 

minimum data requirement cannot be met with 

the CEMS, the Permittee shall supplement 

emission data with other monitoring systems, 

or USEPA Reference Method 6 shall be used to 

determine the SO2 concentration at the same 

location as the SO2 monitor. Samples shall be 

taken at 60-minute intervals. The sampling 

time and sample volume for each sample shall 

be at least 20 minutes and 0.71 dscf. Each 

sample represents a 1-hour average. The 

procedures in Method 19 shall be used to 

compute each 1-hour average concentration in 

1b/million Btu heat input. 

Note: This permit allows the use of an “Acid Rain 

Monitoring System,” operated to comply with 40 CFR 

Part 75, in lieu of an “NSPS Monitoring System,” as 

authorized under the NSPS. 

c. Pursuant to 40 CFR 60.47a(c), 40 CFR 75.12, and Section 

39.5(7)(d)(iii) of the Act, the Permittee shall 

install, operate, calibrate and maintain a CEMS for the 

measurement of NOx from the affected boiler in 

accordance with the requirements of 40 CFR 75 Subpart 

B. 

i. Pursuant to NSPS, 40 CFR 60.47a(f), the 

Permittee shall obtain emission data for at 

least 18 hours in at least 22 out of 30 

successive boiler operating days. If this 

minimum data requirement cannot be met with 

the CEMS, the Permittee shall supplement 

emission data with other monitoring systems, 

where Method 7 shall be used to determine the 

NOx concentration at the same location as the 

NOx monitor. Samples shall be taken at 

30-minute intervals. The arithmetic average of 

two consecutive samples represents a 1-hour 

average. The procedures in Method 19 shall be 

used to compute each 1-hour average 

concentration in 1b/million Btu heat input. 

d. Pursuant to Section 412 of the Clean Air Act and 40 

CFR Part 75, the source is required to operate 

continuous monitors for the affected boiler for 

various parameters, including SO2, NOx, volumetric 

flow and opacity, along with a computerized data 

acquisition and handling system for collected data. 

(See also Condition 6.2.3) To the extent that 

applicable performance specifications and operating 

requirements for monitoring under 40 CFR Part 75 are 

inconsistent with the above requirements for 

monitoring, the procedures of 40 CFR Part 75 shall 
44 

take precedence. (See also Condition 8.2) 

7.1.9 Recordkeeping Requirements 

a. Operational Records for the Affected Boiler 

Pursuant to Sections 39.5(7)(a) and (e) of the Act, 

the Permittee shall maintain the following operational 

records for the affected boiler: 

i. An operating log that includes the occurrence 

and duration of each startup, shutdown or 

malfunction of the boiler and any malfunction 

of the air pollution control equipment. (See 

also Conditions 7.1.9(b), (f) and (g).] [40 

CFR 60.7(b)] 

ii. A. Operating load of the boiler (in terms of 

either gross megawatts output or steam 

flow) on an hourly basis. 

B. If the Permittee is relying on data for 

heat input for purposes of determining 

compliance with applicable standards or 

emission limitations that is different 

from that recorded pursuant to the federal 

Acid Rain Program, records of heat input 

(mmBtu, on an hourly basis). 

iii. Records for each day when a supplemental fuel 

(i.e., a commercial fuel other coal, coal 

refuse, oil or gas) or an alternative fuel 

(i.e., a fuel material that is not a 

commercial fuel) was burned, including the 

estimated amount of each such material burned 

iv. Total operating hours of the boiler 

(hrs/quarter). 

v. A. Amount of each commercial fuel consumed 

(tons, gallons, cubic feet per quarter, as 

appropriate). 

B. Amount of each other fuel material 

consumed (tons, gallons, cubic feet per 

quarter, as appropriate). 

vi. A. Records of agreements with suppliers of 

supplemental fuel(s) and alternative 

fuel(s) for the boiler, including origin 

of such material, specifications for heat 

content (Btu/lb) and ash content (percent 

by weight), and representative data for 

elemental composition of such material 

(percent by weight or ppm by weight), 

including mercury and other heavy metals, 

sulfur, chlorine and fluorine. 
45 

B. Records for each load of such material 

received at the source, which at a minimum 

shall include date, supplier name, type of 

material and amount (tons). 

C. Written procedures, operating logs, and 

other records that address the 

requirements in Condition 7.1.6-2(e), 

which apply to use of supplemental and 

alternative fuels. 

vii. An operating log, maintenance and repair log, 

or other records for the affected boiler 

documenting the performance of the combustion 

evaluation required by Condition 7.1.6(a), 

including the date of the evaluation, the 

concentrations of CO measured at the start and 

conclusion of the evaluation, and a 

description of adjustments and preventative 

and corrective measures undertaken for the 

combustion systems of the boiler. 

b. Records for Control Equipment 

Pursuant to Sections 39.5(7)(a) and (e) of the Act, 

the Permittee shall maintain the following records for 

the air pollution control equipment on the affected 

boiler: 

i. Maintenance and Repair Log 

A maintenance and repair log for each control 

device, which shall list the activities performed, 

with date and description. (See also Condition 

9.6.1, Control Equipment Maintenance Records.) 

ii. Limestone Bed Injection System 

A. Manufacture/vendor or Permittee developed 

operating and maintenance procedures. 

B. Operating log including system settings. 

C. Records for usage of limestone (tons/month). 

iii. Selective Non-Catalytic Reduction (SNCR) 

System 

A. Manufacture/vendor or Permittee developed 

operating and maintenance procedures. 

B. Operating log including system settings. 

C. Records for usage of reagent (tons/month). 
46 

iv. Baghouse 

A. Manufacture/vendor or Permittee developed 

operating and maintenance procedures. 

c. Records for Continuous Opacity Monitoring Systems 

Pursuant to the NSPS, 60.47a(a), and Section 

39.5(7)(e) of the Act, the Permittee shall maintain 

records for the opacity monitoring system on the 

affected boiler required by Condition 7.1.8(a) that as 

a minimum shall include: 

i. Operating records for the system, including: 

A. Opacity measurements. 

B. Continuous monitoring system performance 

testing measurements. 

C. Performance evaluations and other quality 

assurance/control activities. 

D. Calibration checks. 

E. Maintenance and adjustment performed. 

F. Periods other than performance of quality 

assurance, calibration, and maintenance, 

as addressed above, when the monitor was 

inoperative, with reason. 

G. Quarterly reports submitted in accordance 

with NSPS, 40 CFR 60.7(c) and Condition 

7.1.10-2(a) and (d). 

ii. Records for the affected boiler that identify 

the upper bound of the 95% confidence interval 

(using a normal distribution and 1 minute 

averages) for opacity measurements from the 

boiler, considering an hour of operation, 

within which compliance with the PM 

limitations of Conditions 7.1.4(a)(ii) and 

7.1.6-2(a) (in lb/mmBtu), is assured. These 

records shall be accompanied by records of the 

supporting explanation and documentation for 

these ranges, including results of historic 

emission tests. At a minimum, these records 

shall be reviewed and revised as necessary 

following performance of each subsequent PM 

emission test on the affected boiler. Copies 

of these records shall be submitted to the 

Illinois EPA in accordance with Condition 

5.6.2(d). 

iii. Records to address compliance with applicable 

limits for opacity and PM emissions, 

including: 
47 

A. Each 6-minute period when the opacity was 

above the limitation of Conditions 

7.1.4(a)(iii) and 7.1.4(c) (20 percent 

opacity) with date, time, whether it 

occurred during startup, malfunction 

(malfunction/breakdown), or shutdown, and 

further explanation of the incident. 

B. Each hour when the measured opacity of the 

affected boiler was above the upper bound, 

as specified above in Condition 

7.1.9(c)(ii), with date, time, operating 

condition if startup, malfunction, 

breakdown, or shutdown, further 

explanation of the incident, and whether 

PM emissions may have exceeded the limits 

in lb/mmBtu of Conditions 7.1.6-2(a), 

7.1.4(c), or 7.1.4(a)(ii), with 

explanation. 

C. I. The date and time of any three-hour 

block-average period that includes 

an hour when the PM emission rate in 

lb/mmBtu, as recorded above, 

exceeded the limit of Condition 

7.1.6-2(a), with the estimated PM 

emission rates, in lb/hr, with 

supporting explanation and 

calculations. 

II. The date and time of any three-hour 

block-average period when the average 

PM emission rate, in lb/hr, exceeded 

the hourly limit in Condition 7.1.6-

2(a), with the calculated PM emission 

rate and supporting calculations. 

These records shall be prepared from 

the above records at least quarterly 

as needed to verify compliance with 

the limit in Condition 7.1.6-2(a). 

D. Other records required by the NSPS, 40 CFR 

60, Subpart Da, related to opacity and PM 

emissions. 

E. Records of PM emissions (tons/mo and 

tons/yr) to address compliance with the 

annual PM limit in Condition 7.1.6-2(a), 

with supporting calculations. For periods 

of compliant operation, which are not 

addressed by the above records, these 

records may be based on PM emission 

factor(s) developed from testing of the 

affected boiler. 
48 

d. Records for Continuous SO2 Monitoring Systems 

Pursuant to the NSPS, 60.7(c) and 40 CFR 60.47a, and 

Section 39.5(7)(e) of the Act the Permittee shall 

maintain records for the SO2 CEMS on the affected 

boiler required by Condition 7.1.8(b) that as a 

minimum shall include the following: 

i. Operating records for the SO2 CEMS, including: 

A. SO2 emission data into units of the 

applicable standards, lb/mmBtu. 

B. Continuous monitoring system performance 

testing measurements. 

C. Performance evaluations and other quality 

assurance /control activities. 

D. Calibration checks. 

E. Maintenance and adjustments performed. 

F. Periods when the SO2 CEMS was inoperative, 

with date, time and reason. 

G. Data reduction information. 

H. Quarterly reports submitted in accordance 

with NSPS, 40 CFR 60.7(c), and Condition 

7.1.10-2(a) and (b). 

ii. Records to verify compliance with applicable 

SO2 limits, including: 

A. SO2 emissions in the terms of the 

applicable standards (lb/mmBtu) from the 

affected boiler on an hourly basis, as 

derived from the data obtained by the SO2

CEMS. 

B. The dates of any 30-day averaging period 

when the SO2 emission rate from the 

affected boiler, determined in accordance 

with the applicable compliance procedures 

of the NSPS, exceeded the limit of 

Condition 7.1.4(a)(iv), with the 

calculated SO2 emission rate. 

C. I. The date and time of any three-hour 

block averaging period, other than 

startup or shutdown, when the 

average SO2 emission rate, in 

lb/mmBtu, exceeded the limit in 

Condition 7.1.4(d) or 7.1.6-2(a), 

with the calculated SO2 emission 

rate. 
49 

II. The date and time of any three-hour 

block averaging period when the 

average SO2 emission rate, in lb/hr, 

exceeded the limit in Condition 

7.1.6-2(a), with the calculated SO2

emission rate and supporting 

calculations. These records shall 

be prepared from the above records 

at least quarterly as needed to 

verify compliance with the hourly 

SO2 limit in Condition 7.1.6-2(a). 

D. Other records required by the NSPS, 40 CFR 

60 Subpart Da, related to SO2 emissions. 

E. Records of SO2 emissions (tons/mo and 

tons/yr) to address compliance with the 

annual SO2 limit in Condition 7.1.6-2(a), 

with supporting calculations. 

e. Records for Continuous NOx Monitoring 

Pursuant to the NSPS, 60.7(c) and 40 CFR 60.47a, 35 

IAC 217.712(a), and Section 39.5(7)(e) of the Act, the 

Permittee shall maintain records for the NOx CEMS on 

the affected boiler required by Condition 7.1.8(c) in 

accordance with the applicable recordkeeping 

requirements of 40 CFR 75, that as a minimum shall 

include: 

i. Operating records for the NOx CEMS, including: 

A. NOx emission data into units of the 

applicable standards, lb/mmBtu. 

B. Continuous monitoring system performance 

testing measurements. 

C. Performance evaluations and other quality 

assurance /control activities. 

D. Calibration checks. 

E. Maintenance and adjustments performed. 

F. Periods when the CEMS was inoperative, 

with date, time and reason. 

G. Data reduction information. 

H. Quarterly reports submitted in accordance 

with Condition 7.1.10-2(a) and (c). 

ii. Records to verify compliance with applicable 

NOx limits, including: 

A. NOx emissions in the terms of the 

applicable standards (lb/mmBtu) from the 

affected boiler on an hourly basis, as 

derived from the data obtained by the NOx 

CEMS. 
50 

B. The dates of any 30-day averaging period 

when the NOx emission rate from the 

affected boiler, determined in accordance 

with the applicable compliance procedures 

of the NSPS, exceeded the limit of 

Condition 7.1.4(a)(v), with the calculated 

NOx2 emission rate. 

C. I. The date and time of any three-hour 

block averaging period, other than 

startup or shutdown, when the 

average NOx emission rate, in 

lb/mmBtu, as recorded above, 

exceeded 0.137 lb/mmBtu or the limit 

of Condition 7.1.4(f), with the 

calculated NOx emission rate. 

II. The date and time of any three-hour 

block averaging period when the 

average NOx emission rate, in lb/hr, 

exceeded the limit of Condition 

7.1.6-2(a), with the calculated NOx 

emission rate and supporting 

calculations. These records shall 

be prepared from the above records 

at least quarterly as needed to 

verify compliance with the hourly 

NOx limit of Condition 7.1.6-2(a). 

D. Other records required by the NSPS, 40 CFR 

60 Subpart Da, related to NOx emissions. 

E. Records of NOx emissions (tons/mo and 

tons/yr) to address compliance with the 

annual NOx limit in Condition 7.1.6-2(a), 

with supporting calculations. 

f. Records for Startups 

Pursuant to Sections 39.5(7)(a) and (e) of the Act, 

the Permittee shall maintain records related to 

startup of the affected boiler that at a minimum shall 

include the following: 

i. The source’s startup procedures for the affected 

boiler (as required by Condition 7.1.3(b)(ii)) 

accompanied by the source’s estimate of both 

total and excess emissions of PM, SO2, CO, and 

NOx during typical startup(s), with supporting 

information and calculations. 

ii. Records for each startup of the affected 

boiler including: 

A. Date and description of startup, e.g., 

startup following scheduled maintenance 

outage. [40 CFR 60.7(b)] 
51 

B. Duration of the startup, from initial 

firing of fuel to achievement of normal 

operation, i.e., stable operation firing 

the principal fuel with control equipment 

operating to enable compliance. [40 CFR 

60.7(b)] 

C. If normal operation is not achieved within 

9 hours or if the source’s startup 

procedures are not followed: 

I. A detailed explanation why startup 

could not be completed sooner or the 

source’s startup procedures were not 

followed. 

II. Documentation for the source’s 

startup procedures that were 

followed. 

III. The time at which solid fuel (coal) 

firing was begun. 

IV. SNCR reagent usage during startup. 

V. Estimates of magnitude of PM, SO2, 

CO and NOx emitted in excess of the 

applicable standards during the 

startup. 

g. Records for Continued Operation During Malfunctions 

And Breakdowns 

Pursuant to 35 IAC 201.263 and Sections 39.5(7)(a) and 

(e) of the Act, the Permittee shall maintain records, 

related to malfunction and breakdown for the affected 

boiler that as a minimum, shall include: 

i. A maintenance and repair log for the affected 

boiler and associated equipment, listing 

activities performed with date. 

ii. Records for each incident when operation of 

the affected boiler continued with excess 

emissions, including malfunction or breakdown 

as provided by Condition 7.1.3(c), including 

the following information: 

A. Date and duration of malfunction or 

breakdown. 

B. A description of the malfunction or 

breakdown. 

C. The corrective actions used to reduce the 

quantity of emissions and the duration of 

the incident. 
52 

D. Confirmation of fulfillment of the 

requirements of Condition 7.1.10-3(a), as 

applicable, including copies of follow-up 

reports submitted pursuant to Condition 

7.1.10-3(a)(ii). 

E. If opacity exceeded the applicable 

standard (Condition 7.1.4(a)) for two or 

more hours or PM, SO2, CO or NOx emissions 

may have exceeded an hourly emission 

standard (Condition 7.1.4(a)(ii), (c), 

(d), (e) or (f)): 

I. A detailed explanation why continued 

operation of the affected boiler was 

necessary. 

II. The preventative measures that have 

been or will be planned or taken to 

prevent similar malfunctions or 

breakdowns or reduce their frequency 

and severity, including any repairs 

to the affected boiler and 

associated equipment and any changes 

to its operating and maintenance 

procedures. 

III. An estimate of the magnitude of 

excess emissions occurring during 

the incident. 

h. Acid Rain Program 

Records for the continuous emission monitoring 

required for the affected boiler by the Acid Rain 

Program should be kept by the source in accordance 

with 40 CFR Part 75, including the General 

Recordkeeping Provisions; the General Recordkeeping 

Provisions for Specific Situations, if applicable; and 

Certification, Quality Assurance and Quality Control 

Record Provisions. [See Condition 6.3.3] 

i. Records for CO and VOM Emissions 

The Permittee shall keep records of the CO and VOM 

emissions of the affected boiler (tons/month and 

tons/year) to verify compliance with the limits of 

Condition 7.1.6-2(a), with supporting documentation 

and calculations. The emission factors that are used 

for this purpose shall be based on the results of 

emission testing conducted pursuant to Condition 7.1.7 

and the above operating records. 
53 

7.1.10-1 Reporting Requirements - Reporting of Deviations 

a. Prompt Reporting of Deviations 

For the affected boiler, the Permittee shall promptly 

notify the Illinois EPA of deviations from permit 

requirements as follows. At a minimum, these 

notifications shall include a description of such 

deviations, including whether they occurred during 

startup or malfunction/breakdown, and a discussion of 

the possible cause of such deviations, any corrective 

actions and any preventative measures taken. [Section 

39.5(7)(f)(ii) of the Act] 

i. Notification and reporting as specified in 

Condition 7.1.10-3(a) for certain deviations 

from the PM limit in the PM limits in 

Conditions 7.1.4(a)(ii) or (c). 

ii. Notification and reporting as specified in 

Condition 7.1.10-3(a) for certain deviations 

from the opacity limits in the opacity limit 

in Conditions 7.1.4(a)(iii) and (b). 

iii. Notification with the reports required by 

Conditions 7.1.10-2(b), (c), (d) and (e) for 

deviations from Condition 7.1.4(a), (b), (c), 

(d), (f) and (g) and from the requirements of 

Condition 7.1.8 for emissions monitoring. 

iv. Notification with the quarterly reports 

required by Condition 7.1.10-2(a) for 

deviations not addressed above by Condition 

7.1.10-1(a)(i), (ii) or (iii), including 

deviations from other applicable requirements, 

e.g., the applicable CO emission standard, 

work practice requirements, and recordkeeping 

requirements. 

b. Periodic Reporting of Deviations 

The quarterly reports required by Condition 7.1.10-2(a) 

shall include the following information for the 

affected boiler related to deviations from permit 

requirements during the quarter. [Sections 39.5(7)(a) 

and (f)(i) of the Act] 

i. A listing of all instances of deviations that 

have been reported in writing to the Illinois 

EPA as provided by Condition 7.1.10-1(a)(i) 

and (ii), including identification of each 

such written notification or report. For this 

purpose, the Permittee need not resubmit 

copies of these previous notifications or 

reports but may elect to supplement such 

material. 
54 

ii. Detailed information, as required by Condition 

7.1.10-1(a)(iii) or (iv), for all other 

deviations not addressed in the above listing. 

7.1.10-2 Reporting Requirements - Periodic Reporting 

a. Quarterly Reports 

In place of the semi-annual monitoring reports 

otherwise required by Condition 8.6.1, the Permittee 

shall submit quarterly reports to the Illinois EPA 

pursuant to Sections 39.5(7)(a) and (f) of the Act. 

i. These reports shall include the following 

information for operation of the affected 

boiler during the quarter: 

A. The total operating hours for the affected 

boiler, as also reported in accordance 

with 40 CFR Part 75. 

B. The greatest load achieved by the affected 

boiler (steam flow or gross megawatts). 

C. A discussion of significant changes in the 

fuel supply to the affected boiler, if 

any, including changes in the source of 

coal, the introduction of new fuel 

materials other than coal, gas and oil, 

and changes in the source of such other 

fuel materials or the maximum rate at 

which they will be fired. 

D. A list of the startups of the affected 

boiler, including the date, duration and 

description of each startup, accompanied 

by a copy of the records pursuant to 

Condition 7.1.9(g)(ii)(C) for each startup 

for which such records were required. 

E. A copy of the records required by 

Condition 7.1.9(c)(iii)(B) identifying the 

date and time that the upper bound, as 

specified above in Condition 7.1.9(c)(ii), 

was exceeded, with operating condition if 

startup, malfunction, breakdown, or 

shutdown; with further explanation of the 

incident and whether particulate matter 

emissions may have exceeded the PM limit. 

ii. These report shall include the information for 

SO2, NOx, and PM emissions and opacity from 

the affected boiler during the quarter and the 

operation of required continuous monitoring 

systems specified by Conditions 7.1.10-2(b), 

(c) and (d). 
55 

iii. A. These reports shall be submitted after the 

end of every calendar quarter as follows: 

Monitoring Period Submittal Deadline 

 

January - March April 30 

 

April - June July 30 

 

July – September October 30 

 

October - December January 30 

b. Reporting of SO2 Emissions 

Pursuant to the NSPS, 40 CFR 60.49a, and Sections 

39.5(7) (a) and (f) of the Act, the Permittee shall 

report the following information to the Illinois EPA 

in accordance with 40 CFR 60.7(c) for the affected 

boiler with its quarterly reports pursuant to 

Condition 7.1.10-2(a): 

i. Summary information on the performance of the 

SO2 CEMS, including the information for a 

“Summary Report” specified by 40 CFR 60.7(d). 

When the SO2 CEMS was not inoperative, 

repaired or adjusted except for zero and span 

checks, this shall be stated in the report. 

ii. If specifically requested by the Illinois EPA 

or the CEMS downtime was more than 5 percent 

of the total operating time for the affected 

boiler, the date and time identifying each 

period during which the CEMS was inoperative 

except for zero and span checks, and the 

nature of CEMS repairs or adjustments and a 

summary of quality assurance data consistent 

with 40 CFR Part 75, i.e., the dates and 

results of the Linearity Test(s) and any 

Relative Accuracy Test Audit(s) during the 

quarter, a listing of any days when a required 

daily calibration was not performed, and the 

date and duration of any periods when the CEMS 

was out-of-control as addressed by 40 CFR 

75.24. 

iii. The information related to SO2 emissions 

specified by the NSPS, 40 CFR 60, Subpart Da. 

iv. The following information for each period when 

SO2 emissions were in excess of the applicable 

limits or requirements in Conditions 

7.1.4(a)(iv) or (d)* or Condition 7.1.6-2(a). 

When there were no such exceedances, this 

shall be stated in the report. 

A. The starting date and time of the SO2

excess emissions. 
56 

B. The duration of the excess emissions. 

C. A copy of the records for the excess 

emissions, as maintained pursuant to 

Condition 7.1.9(d)(ii), including the 

measured emission rate. 

D. A detailed explanation of the cause of the 

excess emissions. 

E. A detailed explanation of the corrective 

actions and actions taken to lessen the 

emissions. 

* The averaging period for determining 

compliance with the limit of Condition 

7.1.4(d) is a three-hour block average). 

The records for excess emissions shall 

consist of three-hour block emission 

averages during which the limit was 

exceeded. 

c. Reporting of NOx Emissions 

Pursuant to the NSPS, 40 CFR 60.49a, and Sections 

39.5(7) (a) and (f) of the Act, the Permittee shall 

report the following information for the affected 

boiler to the Illinois EPA in accordance with 40 CFR 

60.7(c) with its quarterly reports pursuant to 

Condition 7.1.10-2(a): 

i. Summary information on the performance of the 

NOx CEMS, including the information for a 

“Summary Report” specified by 40 CFR 60.7(d). 

 When the NOx the CEMS was not inoperative, 

repaired or adjusted except for zero and span 

checks, this shall be stated in the report. 

ii. If specifically requested by the Illinois EPA 

or the CEMS downtime was more than 5 percent 

of the total operating time for the affected 

boiler: the date and time identifying each 

period during which the CEMS was inoperative 

except for zero and span checks, and the 

nature of CEMS repairs or adjustments and a 

summary of quality assurance data consistent 

with 40 CFR Part 75, i.e., the dates and 

results of the Linearity Test(s) and any 

Relative Accuracy Test Audit(s) during the 

quarter, a listing of any days when a required 

daily calibration was not performed, and the 

date and duration of any periods when the CEMS 

was out-of-control as addressed by 40 CFR 

75.24. 
57 

iii. The information related to NOx emissions 

specified by the NSPS, 40 CFR 60, Subpart Da. 

iv. The following information for each period when 

NOx emissions were in excess of the limit in 

Conditions 7.1.4(a)(v) or (f)* or Condition 

7.1.6-2(a). When there were no such 

exceedances, this shall be stated in the 

report: 

A. The starting date and time of the NOx 

excess emissions. 

B. The duration of the excess emissions. 

C. A copy of the records for the excess 

emissions, as maintained pursuant to 

Condition 7.1.9(e)(ii), including the 

measured emission rate. 

D. A detailed explanation of the cause of the 

excess emissions. 

E. A detailed explanation of the corrective 

actions and actions taken to lessen the 

emissions. 

F. Identification of the previous report for 

the incident submitted to the Illinois EPA 

pursuant to Condition 7.1.10-1(b)(ii). 

For this purpose, the Permittee need not 

resubmit copies of such report but may 

elect to supplement such material. 

G. A summary of the records required by 

Condition 7.1.9(h)(ii) for incidents when 

operation of the affected boiler continued 

during malfunction or breakdown with 

excess emissions that are not addressed by 

individual reports submitted pursuant to 

Condition 7.1.10-3(a)(ii). 

* The averaging period to determine 

compliance with the limit of Condition 

7.1.4(f) is a three-hour block average. 

The records for excess emissions shall 

consist of three-hour block emission 

averages during which the limitation was 

exceeded. 

Note 1: While the NSPS provides that one sixminute period per hour during which the 

average opacity of emissions exceeds 20 

percent opacity, but not more than 27 percent 

opacity need not be reported (40 CFR 

60.45(g)(1)), such a provisions does not 

accompany 35 IAC 212.122. 
58 

Note 2: Because the Permittee is subject to 

the reporting requirements of the NSPS, 40 CFR 

60.7(c) and (d) for the affected boiler for 

opacity, as included above, the Permittee is 

not subject to reporting pursuant to 35 IAC 

201.405 (35 IAC 201.403(a)). 

d. Reporting Related to Opacity and PM Emissions 

Pursuant to the NSPS, 40 CFR 60.49a, and Sections 

39.5(7)(b) and (f) of the Act, the Permittee shall 

report the following information for the affected 

boiler to the Illinois EPA with its quarterly reports 

pursuant to Condition 7.1.10-2(a): 

i. Summary information on the performance of the 

opacity monitoring system and excess 

emissions, as required for a “Summary Report” 

in accordance with 40 CFR 60.7(d). When no 

excess opacity occurred or the continuous 

opacity monitoring system was not inoperative, 

repaired or adjusted except for zero and span 

checks, this shall be stated in the report. 

ii. The operating status of the opacity monitoring 

system, including the dates and times of any 

periods during which it was inoperative, if 

requested by the Illinois EPA or the opacity 

monitoring system downtime was more than 5 

percent of the total operating time for the 

affected boiler during the quarter. 

iii. The information related to opacity and PM 

emissions specified by the NSPS, 40 CFR 60, 

Subpart Da. 

iv. The following information for each period when 

opacity was in excess of the applicable limit 

in Condition 7.1.4(a)(iii) and (b) (20 

percent, six-minute average). When there were 

no such exceedances, this shall be stated in 

the report. 

A. The starting dates and time of the 

exceedance. 

B. The duration of the excess opacity. 

C. The magnitude of excess opacity, based on 

six minute average opacity, including: 

I. The percent opacity for each sixminute period. 

II. The start and stop time of each sixminute period in excess of the 

limitation. 
59 

D. A detailed explanation of the cause of 

excess opacity, if known, including 

whether such excess opacity occurred 

during startup, malfunction 

(malfunction/breakdown) or startup of the 

boiler. 

E. Corrective actions and actions that have 

been or will be taken to lessen the 

opacity. 

F. Identification of the previous report for 

the incident submitted to the Illinois EPA 

pursuant to Condition 7.1.10-3(a)(ii). 

For this purpose, the Permittee need not 

resubmit copies of such report but may 

elect to supplement such material. 

G. A summary of the records required by 

Condition 7.1.9(h)(ii) for incidents when 

operation of the affected boiler continued 

during malfunction or breakdown with 

excess emissions that are not addressed by 

individual reports submitted pursuant to 

Condition 7.1.10-3(a)(ii). 

v. The following information for each period when 

PM emissions were in excess of the limit in 

Condition 7.1.4(a)(ii)(A) or 7.1.4(c). If 

there were no such exceedances during the 

reporting period, the quarterly report shall 

so state. 

A. A summary of information for each period 

of exceedance that includes: 

I. The starting date and time of the 

exceedance. 

II. The duration of the exceedance. 

III. The magnitude of the exceedance. 

IV. The percent opacity measured for 

each six-minute period during the 

exceedance. 

V. The means by which the exceedance 

was indicated or identified, in 

addition to the level of opacity. 

VI. A detailed explanation of the cause 

of the exceedance, including whether 

the exceedance occurred during 

startup, malfunction 

(malfunction/breakdown) or shutdown. 
60 

VII. A detailed explanation of corrective 

actions and actions taken to lessen 

the emissions. 

B. Identification of the previous reports for 

the incidents submitted to the Illinois 

EPA pursuant to Condition 7.1.10-3(a)(ii). 

For this purpose, the Permittee need not 

resubmit copies of such report but may 

elect to supplement such material. 

vi. The following summary information related to 

opacity and PM exceedances: 

A. Further information for each type of 

recurring opacity exceedance that occurred 

during the quarter, including: a 

discussion of any circumstances or events 

during the quarter that generally affected 

the number or magnitude of such 

exceedances; a discussion of any 

additional understanding of the causes for 

such exceedances gained during the 

quarter, including the role of component 

failure or degradation, maintenance 

practices, and operating procedures; a 

general discussion of the effectiveness of 

the corrective actions that were taken in 

response to such exceedances; and a 

general discussion of further actions that 

are being considered to address such 

exceedances. 

B. Further information for any new type(s) of 

opacity exceedances that occurred during 

the quarter including: a general narrative 

description for the type(s) of exceedance; 

a general explanation of the cause(s) for 

such exceedances, including the role of 

component failure or degradation, 

maintenance practices, and operating 

procedures; a detailed explanation of the 

corrective actions that have been taken 

for such exceedances, including the 

reasons that the selected actions were 

taken, the effectiveness of those actions, 

and the likelihood of future occurrence of 

similar exceedances; and a general 

discussion of possible further actions 

that could be taken to address such 

exceedances. For this purpose, new 

type(s) of exceedance are ones that have 

not been addressed in the preceding four 

quarterly opacity reports. 

C. Other information relevant to generally 

explaining the number and magnitude of 

opacity and PM exceedances during the 
61 

quarter, e.g., a further discussion of 

specific events or circumstances that 

occurred that affected the number of 

magnitude or exceedances during the 

quarter. 

D. Information describing actions taken 

during the quarter that should generally 

act to significantly reduce the number or 

magnitude of future opacity or PM 

exceedances, e.g., a summary of relevant 

upgrades or replacements of components 

that were completed, with a description of 

such actions, an explanation of their 

relationship to exceedances, and a 

discussion of their anticipated effect on 

future exceedances. 

vi. A glossary of common technical terms used by 

the Permittee in its reports pursuant to this 

Condition 7.1.10-2(d), including the 

definitions for the categories used by the 

Permittee to classify exceedance events. 

e. Reporting of NOx Emissions for the Ozone Control Period 

The Permittee shall submit a report to the Illinois 

EPA by November 30 of each year that demonstrates 

whether the affected boiler has complied with 

Condition 7.1.4(g), pursuant to 35 IAC 217.712(d) and 

(e). 

i. If the Permittee is demonstrating compliance 

on a unit-specific basis with Condition 

7.1.4(g)(i)(A), this report shall contain the 

information specified by 35 IAC 217.712(d) 

including the heat input and NOx emissions of 

the unit for the ozone control period. 

ii. If the Permittee is demonstrating compliance 

by means of “NOx averaging” as authorized by 

Condition 7.1.4(g)(ii)(B), this report shall 

contain the information specified by 35 IAC 

217.712(e) and other related information as 

follows: 

A. In all cases, for the affected boiler, the 

Permittee shall report the following: 

I. Identification of the other EGU that 

are participating in the 

demonstration, including 

identification of the source that is 

the lead party for the demonstration 

and that is also taking 

responsibility for submitting the 

information required by Condition 

7.1.10-2(e)(ii)(B) below. 
62 

II. A statement confirming that the unit 

is eligible to participate in an 

averaging demonstration, i.e., the 

unit is included in only one 

demonstration [35 IAC 217.708(d)] 

and the Permittee is complying with 

applicable recordkeeping and 

reporting requirements for the unit, 

pursuant to 35 IAC 217.708(c) and 

(g). 

III. The average NOx emission rate for 

the unit, with calculations and 

supporting information, as required 

by 35 IAC 217.712(e)(2) and (3), 

including the heat input and NOx 

emissions of the unit for the ozone 

control period. 

IV. Confirmation that the unit would 

show compliance on its own in the 

absence of averaging. 

B. If the Permittee is the lead party for a 

NOx averaging demonstration, the Permittee 

shall report the following: 

I. Copies of the information submitted 

by other parties for the EGU 

participating in the demonstration, 

which include all material required 

by Condition 7.1.10-2(e)(ii)(A) 

above (unless or except as this 

information is provided with the 

submittal by a person who is a 

responsible official for the EGU 

participating in the demonstration). 

II. The averaged NOx emission rate for 

all EGU participating in the 

demonstration, with complete 

supporting calculations, as required 

by 35 IAC 217.712(e)(1). 

III. A statement whether the 

demonstration shows compliance. 

f. Submittal of Supplemental Information Related to NOx 

Emissions during the Ozone Control Period 

The Permittee shall submit copies of any records and 

data required by 35 IAC 217.712 to the Illinois EPA 

within 30 days after receipt of a written request by 

the Illinois EPA. [35 IAC 217.712(g)] 
63 

g. Acid Rain Program Reporting 

Pursuant to Sections 412 of the Clean Air Act and 40 

CFR Parts 72 and 75, the source is subject to the 

reporting requirements of 40 CFR Part 75, which 

includes General Provisions; Notifications; Initial 

Certification or Recertification Application; 

Quarterly Reports; and Opacity Reports. [See 

Condition 6.2.3] Pursuant to Section 39.5(17)(m) of 

the Act, the designated representative of the source 

must concurrently submit to the Illinois EPA in the 

same electronic format specified by the USEPA, the 

data and information submitted to USEPA on a quarterly 

basis pursuant to 40 CFR 75.64. 

7.1.10-3 Reporting Requirements - Notifications 

a. Reporting of Continued Operation During Malfunctions 

and Breakdowns 

Pursuant to 35 IAC 201.263 and Sections 39.5(7)(a) and 

(f) of the Act, the Permittee shall provide the 

following notifications and reports to the Illinois 

EPA, Compliance Section and Regional Office, 

concerning incidents when operation of the affected 

boiler continued with excess emissions, including 

continued operation during malfunction or breakdown as 

addressed by Condition 7.1.3(c). These requirements 

do not apply to such excess emissions, if any, that 

occur during startup or shutdown of the affected 

boiler. 

i. The Permittee shall immediately notify the 

Illinois EPA’s Regional Office, by telephone 

(voice, facsimile or electronic) for each 

incident in which the applicable PM emissions 

standard (Condition 7.1.4(c)) could be 

exceeded or in which the opacity from the 

affected boiler exceeds 20 percent for five or 

more 6-minute averaging periods unless the 

Permittee has begun the shutdown of the 

affected boiler by such time. (Otherwise, as 

related to opacity, if opacity during an 

incident only exceeds 20 percent for no more 

than five 6-minute averaging periods, the 

Permittee need only report the incident in 

accordance with Condition 7.1.10-1(a)(iii) and 

7.1.10-2(d).) 

ii. Upon conclusion of each incident in which the 

applicable PM emission standard may have been 

exceeded or in which exceedances of the 

opacity standard are two hours or more in 

duration, the Permittee shall submit a followup report to the Illinois EPA, Compliance 

Section and Regional Office, within 15 days 

that includes: a detailed description of the 

incident and its cause(s); an explanation why 
64 

continued operation of the affected boiler was 

necessary, the length of time during which 

operation continued under such conditions, 

until repairs were completed or the boiler was 

taken out of service; a description of the 

measures taken to minimize and correct 

deficiencies with chronology; and a 

description of the preventative measures that 

have been and are being taken. 

b. Reports Associated With Introduction of Supplemental Fuels 

i. The Permittee shall promptly submit monthly 

progress reports to the Illinois EPA while it 

is initially introducing a supplemental fuel 

into the affected boiler. This report shall 

include the firing rate(s) being evaluated, a 

description of the events and findings during 

the month, and a summary of CEMS emission 

data. 

ii. At the conclusion of the introduction of a 

supplemental fuel, the Permittee shall 

promptly submit a final report to the Illinois 

EPA stating the maximum rate at which the fuel 

will be burned and providing a summary of the 

written fuel management plan and operating 

procedures prepared for use of the fuel and 

the range of emission rates expected from 

operation with such fuel. 

Note: These requirements were originally established 

in Condition 10(f) of Construction Permit 00070030. 

7.1.11 Anticipated Operating Scenarios/Operating Flexibility 

The Permittee is authorized to make the following 

operational changes with respect to the affected boiler 

without prior notification to the Illinois EPA or revision 

of this permit, pursuant to Section 39.5(7)(a) and (l) of 

the Act. This condition does not affect the Permittee’s 

obligation to continue to comply with applicable 

requirements; to properly obtain a construction permit in 

a timely manner for any activity constituting construction 

or modification as defined in 35 IAC 201.102 or, as 

applicable, 40 CFR 52.21(a)(2) or 35 IAC 203.207; and to 

comply with other legal requirements that apply to such a 

change: 

a. Operation of additional air pollution control 

equipment, which is addressed by a separate 

construction permit. 

b. Firing of commercial fuels, including supplemental 

fuels, or a mix of such fuels from different 

suppliers. 
65 

c. Firing of the following materials in conjunction with 

firing of standard fuels, provided that such materials 

can be accommodated with the existing fuel handling 

system and the burners in the affected boiler, and 

that such materials do not make up more than 10 

percent by weight of the fuel supply to the boiler on 

a quarterly basis: 

i. Other process wastes generated at the source 

in addition to used oil and boiler cleaning 

residue. 

ii. Alternative fuels that do not constitute waste 

and were not generated from hazardous waste, 

such as clean lumber and wood waste (as 

defined at 40 CFR 60.2265), shredded 

polyethylene agricultural containers, and seed 

corn, provided that such materials are shipped 

to the source in homogeneous form prepared for 

use as fuel. 

Note: Other requirements unrelated to air pollution 

control may apply to firing of alternative fuels, such 

as Standards for Management of Used Oil, 35 IAC Part 

739. 

7.1.12 Compliance Procedures 

a. i. Compliance with the opacity limitation of 

Conditions 7.1.4(a)(iii) and (b) (20 percent 

opacity) is addressed by the average opacity 

calculated from 6-minute periods of opacity 

measurements from the continuous opacity 

monitoring system operated in accordance with 

the requirements of Condition 7.1.8(a) and the 

recordkeeping requirements of Conditions 

7.1.9. 

ii. Notwithstanding Condition 7.1.12(a)(i) above, 

should the Permittee choose to rely on 35 IAC 

212.122(b) to allow opacity greater than 20 

percent (6-minute average) from an affected 

boiler, the Permittee shall do the following: 

A. Maintain records for the affected boiler 

of short-term opacity data, that is, 

either a continuous chart recording of 

measured opacity, a record of discrete 

measurements of opacity taken no more than 

10 seconds apart, or a record of 1-minute 

average opacity data determined from six 

or more data points equally spaced during 

each minute period, to determine whether 

opacity from the boiler exceeded 20 

percent opacity. 
66 

B. Have the capability to review such shortterm opacity data for the affected boiler 

to identify: 

I. Any hour in which opacity exceeded 

20 percent, and then, in such hour: 

record the duration of opacity in 

excess of 20 percent; whether 

opacity ever exceeded 40 percent; 

and whether the duration of opacity 

in excess of 20 percent was more 

than 3 minutes in aggregate. 

II. For the affected boiler, whether 

opacity in excess of 20 percent 

occurred in more than three hours in 

a 24 hour period. 

C. For the existing coal-fired boiler at the 

source, have the ability to review shortterm opacity data representative of such 

units during hours in which the opacity of 

the affected boiler on a short-term basis 

may exceed 20 percent, to confirm that the 

opacity of that unit at the source did not 

exceed 20 percent in any minute during an 

hour in which the short-term opacity of 

the affected boiler may have exceeded 20 

percent. 

D. In the reports required by Condition 

7.1.10-2(d), confirm that the relevant 

short-term opacity data, reviewed as 

above, shows that the terms of 35 IAC 

212.122(b) are satisfied, when 35 IAC 

212.122(b) is relied upon as the basis to 

claim that an affected boiler did not 

violate Condition 7.1.4(b) even though 

opacity on a 6-minute average exceeded 20 

percent. 

E. Notify the Illinois EPA at least 15 days 

prior to changing its procedures 

associated with reliance on 35 IAC 

212.122(b), to allow the Illinois EPA to 

review the new recordkeeping and data 

handling practices planned by the 

Permittee. 

b. Compliance with PM emission limits of Conditions 

7.1.4(a)(ii) and (c), and Condition 7.1.6-2(a) is 

addressed by continuous opacity monitoring in 

accordance with Condition 7.1.8(a), PM testing in 

accordance with Condition 7.1.7, and the recordkeeping 

required by Conditions 7.1.9. 
67 

c. Compliance with the SO2 emission limits of Condition 

7.1.4(a)(iv) and (d) and Condition 7.1.6-2(a) is 

addressed by continuous emission monitoring in 

accordance with Condition 7.1.8(b) and the 

recordkeeping required by Condition 7.1.9(d). 

d. Compliance with the CO and VOM emission limitation of 

Condition 7.1.4(e) and 7.1.6-2(a) is addressed by the 

required work practices in Condition 7.1.6-1(a), 

emission testing in accordance with Conditions 7.1.7 

and the recordkeeping required by Condition 7.1.9. 

e. Compliance with NOx limits of Conditions 7.1.4(a)(v), 

(f) and (g) and Condition 7.1.6-2(a) is addressed by 

continuous monitoring in accordance with Condition 

7.1.8(c) and recordkeeping as required by Condition 

7.1.9(e). 

f. Compliance with the work practices required by 

Conditions 7.1.6-1 and 7.1.6-2 is addressed by the 

recordkeeping required by Condition 7.1.9. 

Note: This condition is included in this permit pursuant 

to Section 39.5(7)(p)(v) of the Act. 
68 

7.2 NSPS Coal Fired Boiler - Subject to 40 CFR 60 Subpart D 

7.2.1 Description 

The Permittee operates a conventional coal-fired boiler 

for electric generation. The boiler, which was built in 

the 1975, has a nominal capacity of 1700 mmBtu/hour and is 

served by its own stack. This boiler also has the 

capability to fire at various modes such as combination of 

coal and fuel oil as their principal fuel. In addition to 

coal, this boiler fire natural gas or fuel oil as 

auxiliary fuel during startup and for flame stabilization. 

Nitrogen oxide (NOx) emissions from the boiler are 

controlled by a selective catalytic reduction (SCR) 

system, which was recently installed pursuant to 

Construction Permit 00070028. This system is operated at 

the discretion of the Permittee as needed to facilitate 

compliance with the requirements for NOx emissions under 

the NOx Trading Program. Sulfur dioxide (SO2) emissions 

from the boiler are controlled by a flue gas 

desulfurization (FGD) scrubber system. Particulate matter 

(PM) emissions are controlled by an electrostatic 

precipitator (ESP). 

7.2.2 List of Emission Units and Air Pollution Control Equipment 

These unit-specific conditions address the following 

emission units: 

Boiler 

I.D. Description Emission Control 

Equipment 

Boiler 

Unit 4 

Babcock & Wilcox Boiler Nominal 

1,700 mmBtu/hr (1975) 

SCR, ESP and FGD 

7.2.3 Applicability Provisions 

a. i. An “affected boiler” for the purpose of these 

unit-specific conditions, is the boiler 

described in Conditions 7.2.1 and 7.2.2. 

ii. The affected boiler is also an “affected 

facility” for purposes of the New Source 

Performance Standards (NSPS) for Fossil-Fuel 

Fired Steam Generators for Which Construction 

Is Commenced After August 17, 1971, pursuant 

to 40 CFR 60.40. As an affected facility, the 

boiler is subject to applicable requirements 

of the NSPS, 40 CFR 60 Subpart D and related 

requirements in the NSPS, 40 CFR 60 Subpart A, 

General Provisions. 

b. Startup Provisions 

Subject to the following terms and conditions, the 

Permittee is authorized to operate the affected boiler 

in violation of the applicable standards in Condition 

7.2.4(b) (35 IAC 212.122), Condition 7.2.4(c) (35 IAC 
69 

212.204), Condition 7.2.4(d) (35 IAC 214.121(a)), 

Condition 7.2.4(e) (35 IAC 216.121), and Condition 

7.2.5(b)(ii) (35 IAC 217.121(d), if applicable) during 

startup. This authorization is provided pursuant to 

35 IAC 201.149, 201.161 and 201.262, as the Permittee 

has applied for such authorization in its application, 

generally describing the efforts that will be used 

“...to minimize startup emissions, duration of 

individual startups and frequency of startups.” 

i. This authorization does not relieve the 

Permittee from the continuing obligation to 

demonstrate that all reasonable efforts are 

made to minimize startup emissions, duration 

of individual startups and frequency of 

startups. 

ii. The Permittee shall conduct startup of the 

affected boiler in accordance with written 

procedures prepared by the Permittee and 

maintained in the control room for the boiler, 

that are specifically developed to minimize 

emissions from startups and that include, at a 

minimum, the following measures: 

A. Use of auxiliary fuel burners to heat the 

boiler prior to initiating burning of 

coal. 

B. Timely energization of the ESP as soon as 

this may be safely accomplished without 

damage or risk to personnel or equipment. 

C. Appropriate SCR reagent injection to 

minimize emissions without damage or risk 

to personnel or equipment. 

D. Appropriate flow of scrubbant in the FGD 

scrubber to minimize excess emissions 

without damage or risk to personnel or 

equipment. 

iii. The Permittee shall fulfill applicable 

recordkeeping and reporting requirements of 

Conditions 7.2.9(c), (d), (e) and (f) and 

7.2.10-2(a). 

iv. As provided by 35 IAC 201.265, an 

authorization in a permit for excess emissions 

during startup does not shield a Permittee 

from enforcement for any violation of 

applicable emission standard(s) that occurs 

during startup and only constitutes a prima 

facie defense to such an enforcement action 

provided that the Permittee has fully complied 

with all terms and conditions connected with 

such authorization. 
70 

c. Malfunction and Breakdown Provisions 

Subject to the following provisions, the Permittee is 

authorized to continue operation of an affected boiler 

in violation of the applicable requirements of 

Condition 7.2.4(b) (35 IAC 212.122), Condition 

7.2.4(c) (35 IAC 212.204), Condition 7.2.4(e) (35 IAC 

216.121), and Condition 7.2.5(b)(ii) (35 IAC 

217.121(d), if applicable) in the event of a 

malfunction or breakdown of the affected boiler, 

including associated control equipment and support 

systems (limestone handling and processing, coal 

bunkers, coal pulverizers, ash removal and handling 

systems, etc.). This authorization is provided 

pursuant to 35 IAC 201.149, 201.161 and 201.262, as 

the Permittee has applied for such authorization in 

its application, generally explaining why such 

continued operation would be required to provide 

essential service or to prevent injury to personnel or 

severe damage to equipment, and describing the 

measures that will be taken to minimize emissions from 

any malfunctions and breakdowns. This authorization 

supersedes the general prohibition in Condition 9.2.3 

against continued operation in such circumstances 

i. This authorization only allows such continued 

operation as necessary to provide essential 

service or to prevent injury to personnel or 

severe damage to equipment and does not extend 

to continued operation solely for the economic 

benefit of the Permittee. 

ii. Upon occurrence of excess emissions due to 

malfunction or breakdown, the Permittee shall 

as soon as practicable reduce boiler load, 

repair the affected boiler, remove the 

affected boiler from service or undertake 

other action so that excess emissions cease. 

iii. The Permittee shall fulfill applicable 

recordkeeping and reporting requirements of 

Conditions 7.2.9(c) and (h), 7.2.10-2(d) and 

7.2.10-3(a). For these purposes, time shall be 

measured from the start of a particular 

incident. The absence of excess emissions for 

a short period shall not be considered to end 

the incident if excess emissions resume. In 

such circumstances, the incident shall be 

considered to continue until corrective actions 

are taken so that excess emissions cease or the 

Permittee takes the boiler out of service. 

iv. Following notification to the Illinois EPA of 

a malfunction or breakdown with excess 

emissions, the Permittee shall comply with all 

reasonable directives of the Illinois EPA with 

respect to such incident, pursuant to 35 IAC 

201.263. 
71 

v. This authorization does not relieve the 

Permittee from the continuing obligation to 

minimize excess emissions during malfunction 

or breakdown. As provided by 35 IAC 201.265, 

an authorization in a permit for continued 

operation with excess emissions during 

malfunction and breakdown does not shield the 

Permittee from enforcement for any such 

violation and only constitutes a prima facie 

defense to such an enforcement action provided 

that the Permittee has fully complied with all 

terms and conditions connected with such 

authorization. 

7.2.4 Applicable Emission Standards 

a. Federal NSPS standards 

i. The affected boiler is subject to New Source 

Performance Standards (NSPS) for Fossil Fuel 

Fired Steam Generators, 40 CFR 60, Subparts A 

and D. 

ii. Pursuant to the NSPS, emissions from the 

affected boiler shall not exceed the following 

emission standards: 

 Standard 

Pollutant (lbs/mmBtu) Rule

PM 0.10 40 CFR 60.42(a)(1) 

SO2 1.20 40 CFR 60.43(a)(2) 

iii. Opacity from the affected boiler shall not 

exceed 20 percent, as measured on a six minute 

average, except for one 6 minute period per 

hour of not more than 27 percent pursuant to 

NSPS, 40 CFR 60.42(a)(2). 

iv. Pursuant to 40 CFR 60.7(a), the above emission 

limits do not apply during startup, 

malfunction, or shutdown, as defined by 40 CFR 

60.2. Notwithstanding this provision, 

exceedances of these limits during startup, 

malfunction, and shutdown are still subject to 

recordkeeping and reporting requirements under 

the NSPS. 

v. At all times, the Permittee shall maintain and 

operate the affected boiler, including 

associated air pollution control equipment, in 

a manner consistent with good air pollution 

control practice for minimizing emissions, as 

required pursuant to the NSPS, 40 CFR 

60.11(d). 
72 

b. The affected boiler is subject to 35 IAC 212.122, 

which provides that no person shall cause or allow the 

opacity from a new fuel combustion emission unit with 

a heat input greater than 250 mmBtu/hr to exceed 20 

percent, except as provided by 35 IAC 212.122(b). 

c. The emissions of PM from the affected boiler shall not 

exceed 0.1 lb/mmBtu of actual heat input in any one 

hour period, pursuant to 35 IAC 212.204. 

d. The emissions of SO2 from the affected boiler shall 

not exceed 1.2 lb/mmBtu of actual heat input, pursuant 

to 35 IAC 214.121(a). 

e. The emissions of CO from the affected boiler shall not 

exceed 200 ppm, corrected to 50 percent excess air, 

pursuant to 35 IAC 216.121. 

f. The affected boiler is subject to the following 

requirements related to NOx emissions pursuant to 35 

IAC Part 217 Subpart V: 

i. During each ozone control period (May 1 

through September 30): 

A. The emissions of NOx from the affected 

boiler shall not exceed 0.25 lb/mmBtu of 

actual heat input based on a ozone control 

period average, for that unit, pursuant to 

35 IAC 217.706(a), or 

B. If the Permittee elects to participate in a 

NOx averaging plan, the emissions of NOx from 

the affected boiler and other eligible EGU 

that are participating in such NOx averaging 

demonstration shall not exceed 0.25 lbs/mmBtu 

of actual heat input, as averaged for the 

ozone control period for the EGU 

participating in the demonstration,, pursuant 

to 35 IAC 217.708(a) and (b). For this 

purpose, other eligible EGU are EGU that are 

authorized to participate in a NOx averaging 

plan by a CAAPP permit or other federally 

enforceable permit issued by the Illinois EPA 

to the owner or operator of those EGU. 

Note: Given the emission determination methods 

specified by 35 IAC 217.710, the emissions of NOx for 

purposes of these standards are generally calculated 

in accordance with the federal Acid Rain Program and 

are different from the emissions determined for 

purposes of the NOx Trading Program. 

ii. If the Permittee elects to have the affected 

boiler comply by participation in a NOx 

averaging demonstration as provided for and 

authorized above: 
73 

A. The affected boiler shall be included in 

only one NOx averaging demonstration 

during an ozone control period, pursuant 

to 35 IAC 217.708(d). 

B. The NOx averaging demonstration shall only 

include other EGU that are authorized 

through a federally enforceable permit to 

participate in a NOx averaging 

demonstration and for which the owner or 

operator of the EGU maintains the required 

records, data and reports and submits 

copies of such records, data, and reports 

to the Illinois EPA upon request, pursuant 

to 35 IAC 217.708(c) and (g). 

C. The effect of failure of the NOx averaging 

demonstration to show compliance shall be 

that the compliance status of the affected 

boiler shall be determined pursuant to 

Condition 7.2.4(g)(i)(A) as if the NOx 

emission rates of the affected boiler were 

not averaged with other EGU, pursuant to 

35 IAC 217.708(f). 

Note: The above requirements also apply as a matter 

of rule to EGUs other than the affected boiler if the 

owner or operator of such other EGUs elects to 

participate in a NOx averaging demonstration. 

7.2.5 Non-Applicability of Regulations of Concern 

a. i. This permit is issued based on the affected 

boiler not being subject to a limit for NOx 

under the NSPS as provided by 40 CFR 

60.44(a)(1), because the fuel supply to the 

boiler contains more than 25 percent by weight 

coal refuse. 

ii. If the fuel supply to the boiler does not meet 

this criterion, the affected boiler is subject 

a NOx limit under 40 CFR 60.44(a)(1) for 

firing of solid fuel, e.g., for firing of 

bituminous coal, a limit of 0.60 lb/mmBtu and 

65 percent reduction from a potential 

combustion concentration, except during 

startup, malfunction and breakdown. 

b. i. This permit is issued based on the affected 

boiler not being subject to the NOx limit of 

35 IAC 217.121(d) or (e) as provided by 35 IAC 

217.521(c), because the boiler burns solid 

fossil fuel containing 25 percent by weight or 

more of coal refuse. 

ii. If the fuel supply to the boiler does not meet 

this criterion, the boiler is subject to a NOx 

limit under either 35 IAC 217.121(d) (0.7 
74 

lb/mmBtu, for firing of solid fuel) or 35 IAC 

217.121(e) (a limit in lb/hr, calculated for 

firing a combination solid fuel with gaseous 

or liquid fuel, as further addressed in 

Condition 7.2.5(e)). 

c. i. This permit is issued based on the affected 

boiler not being subject to the NSPS standards 

for firing of oil, i.e., 40 CFR 60.43(a)(1) 

for SO2 and 40 CFR 60.44(a)(2) for NOx, when 

the boiler is using solid fuel as its 

principal fuel and distillate fuel oil is only 

used in incidental amounts for specific 

purposes, such as startup, opacity reduction 

emission mitigation, flame stabilization, 

outage of a coal pulverizer, or other 

temporary disruption in solid fuel supply, as 

associated with routine firing of solid fuel. 

ii. If the affected boiler is not using solid fuel 

as its principal fuel, the affected boiler 

shall comply with the SO2 emission limit set 

by 40 CFR 60.43(b), which addresses units 

burning a combination of fuels. 

iii. If the affected boiler is not using solid fuel 

as its principal fuel and coal refuse is 25 

percent or less by weight of the fuel being 

fired in the boiler, the affected boiler shall 

comply with the NOx emission limit set by 40 

CFR 60.44(b), which addresses units burning a 

combination of fuels. 

d. i. The Permittee is shielded from the following 

rules for the affected boiler when the boiler 

is using solid fuel (coal) as its principal 

fuel. This is because incidental use of other 

fuels generally serves as a good combustion 

practice for firing of solid fuel and does not 

provide a decrease in emissions that can be 

used to reduce the emission rate that must be 

achieved for the emissions associated with 

combustion of solid fuel: 

A. 35 IAC 212.207, for PM emissions. 

B. 35 IAC 214.162, for SO2 emissions. 

ii. If the affected boiler is not using solid fuel 

as its principal fuel, the affected boiler 

shall comply with the requirements of the 

following conditions. During such periods, 

for PM, Condition 7.2.5(d)(ii)(A) shall 

substitute for Condition 7.2.4(c) and, for 

SO2, Condition 7.2.5(d)(ii)(B) shall 

substitute for Condition 7.2.4(d): 
75 

A. The emissions of PM from the affected 

boiler in any one hour period shall not 

exceed the amount, in lb/hr, allowed by 

the equation in 35 IAC 212.207. For this 

purpose, the applicable PM standard for 

heat input from liquid fuel shall be 0.1 

lb/mmBtu, pursuant to 35 IAC 212.206 and 

212.207. 

B. The emissions of SO2 from the affected 

boiler in any one hour period shall not 

exceed the amount, in lb/hr, allowed by 

the equation in 35 IAC 214.162. For this 

purpose, the applicable SO2 standards for 

heat input from residual fuel oil and 

distillate fuel oil shall be 0.8 and 0.3 

lb/mmBtu, respectively, pursuant to 35 IAC 

214.121(b)(1), 214.121(b)(2), and 214.162. 

iii. For the purpose of this condition and 

Condition 7.2.5(e), the affected boiler shall 

be considered to be using solid fuel as its 

principal fuel if the use of natural gas and 

fuel oil is incidental to the use of solid 

fuel (coal), occurring for specific purposes 

associated with routine firing of solid fuel, 

such as startup, opacity reduction emission 

mitigation, flame stabilization, outage of a 

coal pulverizer, or other temporary 

interruption in solid fuel supply. A boiler 

shall not be considered to be using solid fuel 

as its principal fuel if the use of natural 

gas and fuel oil is more than incidental to 

the firing of coal in the boiler or the use of 

solid fuel is incidental to the operation of 

the boiler. 

iv. The Permittee shall notify the Illinois EPA if 

the status of the affected boiler changes to 

or from using solid fuel as its principal 

fuel. This notification shall be provided at 

least 7 days in advance of such change in 

status unless the change results from a sudden 

event that precludes such advance 

notification, in which case notification shall 

be provided as soon as practicable prior to 

the change. 

d. If solid fossil fuel containing less than 25 percent 

coal refuse by weight is burned in the affected 

boiler, so that NOx emissions of the boiler are 

subject to 35 IAC 217.121: 

i. If the boiler is using solid fuel (coal) as its 

principal fuel, the NOx emissions of the boiler 

shall not exceed 0.07 lb/mmBtu in any one hour 

period, pursuant to 35 IAC 217.121(d) and the 

Permittee is shielded from 35 IAC 217.121(e). 
76 

This is because incidental use of other fuels 

with solid fuel generally serves as a good 

combustion practice for firing of solid fuel 

and does not provide a decrease in emissions 

that can be used to reduce the emission rate 

that must be achieved for the emissions 

associated with combustion of solid fuel. 

ii. If the affected boiler is not using solid fuel 

as its principal fuel, the affected boiler 

shall comply with 35 IAC 217.121(e), i.e., the 

emissions of NOx from the boiler shall not 

exceed the amount, in lb/hr, allowed by the 

equation in 35 IAC 217.121(e). 

f. Pursuant to 35 IAC 201.403(a), the Permittee is not 

subject to the requirements of 35 IAC Part 201 Subpart 

L for opacity and SO2 monitoring because the Permittee 

must conduct opacity and SO2 monitoring on the 

affected boiler in accordance with the NSPS, 40 CFR 

Part 60, and the federal Acid Rain program. 

7.2.6 Work Practices, Operational and Production Limits, and 

Emission Limitations 

a. As part of its operation and maintenance of the 

affected boiler, the Permittee shall perform formal 

“combustion evaluation” on the boiler on at least a 

quarterly basis, pursuant to Section 39.5(7)(d) of the 

Act. These evaluations shall consist of diagnostic 

measurements of the concentration of CO in the flue 

gas of the affected boiler, with adjustments and 

preventative and corrective measures for the boiler’s 

combustion systems to maintain efficient combustion. 

7.2.7 Testing Requirements 

Pursuant to Section 39.5(7)(d)(ii) of the Act, the 

Permittee shall have the PM and CO emissions of the 

affected boiler measured as specified below: 

a. i. PM emission measurements shall be made no 

later than 2 years after the effective date of 

this condition. (Measurements made after 

December 31, 2003 may satisfy this 

requirement.) 

ii. PM emission measurements shall be made within 

90 days of operating the affected boiler for 

more than 30 hours total in a calendar quarter 

at a load* that is more than 2 percent higher 

than the greatest load on the boiler, during 

the most recent set of PM tests on the 

affected boiler in which compliance is shown 

(refer to Condition 7.2.7(e)(iii)(D)), 

provided, however, that the Illinois EPA may 

upon request of the Permittee provide more 

time for testing (if such time is reasonably 
77 

needed to schedule and perform testing or 

coordinate testing with seasonal conditions). 

* For this purpose, load shall be expressed 

in terms of either gross megawatt output 

or steam flow, consistent with the form of 

the records kept by the Permittee pursuant 

to Condition 7.2.9(a). 

iii. Periodic PM emission measurements shall be 

made for the affected boiler within a time 

period determined from the compliance margin 

for the applicable PM emission standard, based 

on the results of the preceding PM 

measurement, as follows. For this purpose, the 

compliance margin is the extent to which the 

actual PM emissions as measured are lower than 

the applicable PM limit. For example, if the 

measured PM emissions of the affected boiler 

are 0.075 lb/mmBtu, the compliance margin for 

the applicable PM limit, 0.10 lb/mmBtu, would 

be 25 percent. (0.100 – 0.075 = 0.025, 

0.025/0.100 = 0.25 or 25 percent). 

A. If the compliance margin is less than 20 

percent, within 15 months of the previous 

measurement. 

B. If the compliance margin is between 20 and 

40 percent, within 27 months of the 

previous measurement. 

C. If the compliance margin is greater than 

40 percent, within 39 months of the 

previous measurement. 

iv. Measurements of CO emissions shall be made as 

follows: 

A. In conjunction with the initial 

measurements of PM emissions as required 

by Condition 7.2.7(a)(i) (unless this PM 

measurement is conducted prior to the 

issuance of this permit), if a measurement 

of CO emissions is not otherwise performed 

earlier in conjunction with a relative 

accuracy test audit (RATA) for SO2 or NOx 

conducted under this permit. 

B. In conjunction with each subsequent 

measurement of PM emissions made pursuant 

to Condition 7.2.7(a)(ii) or (iii) (or a 

RATA for SO2 or NOx preceding such 

measurement), provided, however, that if 

measured CO emissions are no more than 

half of the applicable limits, CO 

measurements need not be performed with 

the next PM measurement (or preceding 
78 

RATA) but shall be performed with the 

second measurement of PM emissions 

following the measurement in which CO 

emissions were no more half of the 

applicable limits (or a RATA preceding 

that PM measurement). 

v. A. If standard fuel (i.e., coal, coal refuse, 

fuel oil, and gas) is less than 97.0 

percent by weight of the fuel supply to a 

boiler during a quarter, the Permittee 

shall have measurements of PM and CO 

emissions from the boiler made during the 

next quarter while firing alternative fuel 

or process waste in the boiler. 

B. The Permittee shall conduct such 

measurements while firing the boiler with 

at least 1.25 times the greatest 

percentage of alternative fuel material or 

process waste in the calendar quarter that 

triggered the testing. This percentage at 

which testing shall be conducted shall not 

exceed that allowed by the maximum design 

capacity of the alternative fuel handling 

system. If the boiler has been firing a 

mix of alternative fuel materials or 

process wastes, the mix of fuel during 

such measurements shall be approved by the 

Illinois EPA. 

C. The Permittee shall repeat such 

measurements if the percentage of 

alternative fuel materials and process 

wastes burned in a boiler during a quarter 

is more than the percentage of such 

material in the fuel supply to the boiler 

when previous emission measurements were 

conducted. 

vi. Measurements of PM and CO emissions shall be 

made within 90 days (or such later date set by 

the Illinois EPA) following a request by the 

Illinois EPA for such measurements. 

b. i. These measurements shall be performed at the 

maximum operating loads of the affected boiler 

and other operating conditions that are 

representative of normal operation. In 

addition, the Permittee may perform 

measurements at other operating conditions to 

evaluate variation in emissions. 

ii. Measurements shall be taken at an appropriate 

location in the ductwork or stack associated 

with the affected boiler. 

iii. The following test methods and procedures 
79 

shall be used for these measurements. Refer 

to 40 CFR 60, Appendix A for USEPA Methods. 

Location of Sample Points USEPA Method 1 

Gas Flow and Velocity USEPA Method 2 

Flue Gas Weight USEPA Method 3 

Moisture USEPA Method 4 

Particulate Matter (PM) USEPA Methods 5 & 202* 

Carbon Monoxide (CO) USEPA Method 10 

Other test methods adopted by USEPA may be used 

in place of the above methods with the approval 

of the Illinois EPA 

* Measurements of condensable PM are also 

required by USEPA Method 202 (40 CFR Part 

51, Appendix M) or other established test 

method approved by the Illinois EPA, 

except for a test conducted prior to 

issuance of this permit. 

c. Except for minor deviations in test methods, as 

defined by 35 IAC 283.130, emission testing shall be 

conducted in accordance with a test plan prepared by 

the testing service or the Permittee and submitted to 

the Illinois EPA for review prior to emission testing, 

and the conditions, if any, imposed by the Illinois 

EPA as part of its review and approval of the test 

plan, pursuant to 35 IAC 283.220 and 283.230. 

i. The Permittee shall submit this test plan at 

least 60 days prior to the actual date of 

testing and the test plan shall include the 

information specified by Condition 8.6.2. 

ii. Notwithstanding the above, as provided by 35 

IAC 283.220(d), the Permittee need not submit 

a test plan for emission testing that will be 

conducted in accordance with the procedures 

used for previous tests accepted by the 

Illinois EPA or the previous test plan 

submitted to and approved by the Illinois EPA, 

provided that the Permittee’s notification for 

testing, as required below, contains the 

information specified by 35 IAC 

283.220(d)(1)(A), (B) and (C). 

d. The Permittee shall notify the Illinois EPA prior to 

conducting emission tests to enable the Illinois EPA 

to observe testing. Notification for the expected 

test date shall be submitted a minimum of 30 days 

prior to the expected date of testing. Notification 

of the actual date and expected time of testing shall 

be submitted a minimum of 5 working days prior to the 

actual test date. The Illinois EPA may on a case-by 

case basis accept shorter advance notice if it would 

not interfere with the Illinois EPA’s ability to 

observe testing. 
80 
81 

e. The Permittee shall submit the Final Report(s) for any 

required emission testing to the Illinois EPA within 

45 days after the tests results are compiled and 

finalized but no later than 120 days after the date of 

testing. The Final Report shall include the 

information specified in Condition 8.6.3 and the 

following information: 

i. Description of test method(s), including 

description of sampling points, sampling 

train, analysis equipment, and test schedule. 

ii. A description of any minor deviations from the 

test plan, as provided by 35 IAC 283.230(a). 

iii. Detailed description of operating conditions 

during testing, including: 

A. Source(s) of fuel and specifications (ash, 

sulfur and heat content). 

B. Boiler operating information, i.e., firing 

rate of the affected boiler(s) (mmBtu/hr), 

composition of fuel as burned (ash, sulfur 

and heat content), and fuel blending ratio 

(%), if a blend of fuels is burned. 

C. Combustion system information, i.e., 

settings for distribution of primary and 

secondary combustion air, target level for 

O2 in the flue gas, and levels of CO, CO2

or O2 in the flue gas, as determined by 

any diagnostic measurements. 

D. Control equipment information, i.e., 

equipment condition and operating 

parameters during testing, including any 

use of the flue gas conditioning system. 

E. Load during testing (gross megawatt output 

and steam flow). 

iv. Data and calculations, including copies of all 

raw data sheets and records of laboratory 

analyses, sample calculations, and data on 

equipment calibration. 

v. The SO2, NOx, O2 or CO2 and opacity data (6-

minute averages and hourly averages) measured 

during testing. 

7.2.8 Monitoring Requirements 

a. Pursuant to 40 CFR 60.45, 40 CFR 75.14, and Section 

39.5(7)(d)(iii) of the Act , the Permittee shall 

install, operate, calibrate and maintain continuous 

monitoring equipment for the measurement of opacity 

from the affected boiler. 
82 

i. This monitoring equipment shall meet the 

design, installation, equipment, and 

performance specifications in Performance 

Specification B in 40 CFR Part 60, Appendix B. 

ii. The Permittee shall operate this equipment in 

accordance with the general provisions for 

opacity monitoring systems in 40 CFR 75.10. 

iii. These monitors shall be the primary basis for 

reporting of exceedances of Condition 

7.2.4(b). (See Conditions 7.2.10-2(a) and 

7.2.10-3(a).) 

b. Pursuant to Section 39.5(7)(d)(iii) of the Act, 40 CFR 

75.11, and the NSPS, 40 CFR 60.45, the Permittee shall 

install, operate, calibrate and maintain a continuous 

emission monitoring system (CEMS) for the measurement 

of SO2 emissions from the affected boiler which shall 

be used to demonstrate compliance with the limits in 

Condition 7.2.4(d) based on the average hourly SO2

emission rate determined from monitored data from 

three-hour block averaging periods. This CEMS shall 

be operated pursuant to written monitoring procedures 

that include a quality assurance/control plan, which 

procedures address the requirements in 40 CFR Part 75. 

Note 1: This permit is issued based on the Permittee 

performing continuous emission monitoring for SO2

rather than fuel sampling and analysis for sulfur 

content, as provided by 40 CFR 60.45(b)(2). In 

addition, the permit allows the use of an “Acid Rain 

Monitoring System”, operated to comply with 40 CFR 

Part 75, in lieu of an “NSPS Monitoring System”, as 

authorized by USEPA guidance from the Stationary 

Source Compliance Division of the Office of Air 

Quality Planning and Standards, as such monitoring is 

equivalent or more stringent. 

Note 2: The requirements of 35 IAC Part 201 Subpart L 

for SO2 monitoring do not apply because the Permittee 

must conduct SO2 monitoring for the affected boiler in 

accordance with the NSPS. (Refer to Condition 

7.1.5(d).) 

c. Pursuant to 40 CFR 60.45, 40 CFR 75.12, 35 IAC 

217.710(a), and Section 39.5(7)(d)(iii) of the Act, 

the Permittee, shall install, calibrate, maintain and 

operate a CEMS for the measurement of NOx emissions 

from the affected boiler, in accordance with the 

requirements of 40 CFR 75 Subpart B. 

d. Pursuant to Section 412 of the Clean Air Act and 40 

CFR Part 75, the source is required to operate 

continuous monitors for the affected boiler for 

various parameters, including SO2, NOx, volumetric 

flow and opacity, along with a computerized data 
83 

acquisition and handling system for collected data. 

(See also Condition 6.2.3) To the extent that 

applicable performance specifications and operating 

requirements for monitoring under 40 CFR Part 75 are 

inconsistent with the above requirements for 

monitoring, the procedures of 40 CFR Part 75 shall 

take precedence. (See also Condition 8.2) 

7.2.9 Recordkeeping Requirements 

a. Operational Records for the Affected Boiler 

Pursuant to Sections 39.5(7)(a) and (e) of the Act, 

the Permittee shall maintain the following operational 

records for the affected boiler: 

i. An operating log that includes the occurrence 

and duration of each startup, shutdown or 

malfunction of the boiler and any malfunction 

of the air pollution control equipment. [40 

CFR 60.7(b)] (See also Conditions 7.1.9(b), 

(f) and (g).] 

ii. A. Load (in terms of either gross megawatts 

output or steam flow) on an hourly basis. 

B. If the Permittee is relying on data for 

heat input for purposes of compliance with 

Condition 7.1.4(a)(ii), (c) or (d) that is 

different from that recorded pursuant to 

the federal Acid Rain Program, records of 

heat input (mmBtu, on an hourly basis) or 

the conversion factors that the Permittee 

relies upon to convert from boiler load as 

recorded above to hourly heat input. 

iii. Records for each day when a supplemental fuel 

(i.e., a commercial fuel other coal, coal 

refuse, oil or gas) or an alternative fuel 

(i.e., a fuel material that is not a 

commercial fuel) was burned, including the 

estimated amount of each such material burned 

iv. Total operating hours of eth boiler 

(hrs/quarter). 

v. A. Consumption of coal (tons/quarter). 

B. Consumption of coal refuse (tons/quarter). 

C. Amount of each other fuel material 

consumed (tons, gallons, cubic feet per 

quarter, as appropriate). 

vi. A. Records of agreements with suppliers of 

supplemental fuel(s) and alternative 

fuel(s) for the boiler, including origin 

of material, specifications for heat and 
84 

ash content, and representative data for 

elemental composition of such material, 

including mercury and other heavy metals, 

chlorine and fluorine. 

B. Records for each load of such material 

received at the source, which at a minimum 

shall include date, supplier name, type of 

material and amount (tons). 

vii. An operating log, maintenance and repair log, 

or other records for the affected boiler 

documenting the performance of the combustion 

evaluation required by Condition 7.2.6(a), 

including the date of the evaluation, the 

concentrations of CO measured at the start and 

conclusion of the evaluation, and a 

description of adjustments and preventative 

and corrective measures undertaken for the 

combustion systems of the boiler. 

b. Records for Control Equipment 

Pursuant to Sections 39.5(7)(a) and (e) of the Act, 

the Permittee shall maintain the following operating 

records for the air pollution control equipment on the 

affected boiler: 

i. Maintenance and Repair Log 

A maintenance and repair log for each control 

device, which shall list the activities performed, 

with date and description. (See also Condition 

9.6.1, Control Equipment Maintenance Records.) 

ii. Selective Catalytic Reduction (SCR) System 

A. Manufacture/vendor or Permittee developed 

operating and maintenance procedures. 

B. Operating log including system settings. 

Note: These records for the SCR system are 

only required during periods when the 

Permittee operates this system, which is 

operated at its discretion as needed to 

facilitate compliance with the 

requirements of the NOx Trading Program. 

C. Usage of reagent (tons/month). 

D. The maintenance and repair log for the SCR 

system shall also address activities 

related to the SCR catalyst, including 

addition or replacement of catalyst. 
85 

ii. Electrostatic precipitator (ESP) 

When the affected boiler is in operation: 

A. The status of each ESP field shall be 

recorded at least once per shift. 

B. The following numerical data shall be 

recorded at least once per day: (1) 

Primary voltages and currents; and (2) 

Secondary voltages and currents. 

iii. Flue gas desulfurization (FGD) scrubber system 

A. Manufacture/vendor or Permittee developed 

operating and maintenance procedures. 

B. An operating log including usage of 

limestone and system settings. 

c. Records for Continuous Opacity Monitoring Systems 

Pursuant to 40 CFR 60.45, 40 CFR 75.50, and Section 

39.5(7)(e) of the Act, the Permittee shall maintain 

records for the opacity monitoring system on the 

affected boiler required by Condition 7.2.8(a) that as 

a minimum shall include: 

i. Operating records for each opacity monitoring 

system, including: 

A. Opacity measurements. 

B. Continuous monitoring system performance 

testing measurements. 

C. Performance evaluations and other quality 

assurance/control activities. 

D. Calibration checks. 

E. Maintenance and adjustment performed. 

F. Periods other than performance of quality 

assurance, calibration, and maintenance, 

as addressed above, when the monitor was 

inoperative, with reason. 

G. Quarterly reports submitted in accordance 

with NSPS, 40 CFR 60.7(c) and Condition 

7.2.10-2(a) and (d). 

ii. Records for the affected boiler that identify 

the upper bound of the 95% confidence interval 

(using a normal distribution and 1 minute 

averages) for opacity measurements from the 

boiler, considering an hour of operation, 

within which compliance with Conditions 
86 

7.2.4(a)(ii) and 7.2.4(b) is assured, with 

supporting explanation and documentation, 

including results of historic emission tests. 

At a minimum, these records shall be reviewed 

and revised as necessary following performance 

of each subsequent PM emission test on the 

affected boiler. Copies of these records 

shall be submitted to the Illinois EPA in 

accordance with Condition 5.6.2(d). 

iii. Records to address compliance with Conditions 

7.2.4(a)(ii), (a)(iii), (b), and (c) 

including: 

A. Each 6-minute period when the opacity was 

above the limitation of Conditions 

7.2.4(a)(iii) and 7.2.4(b) (20 percent 

opacity) with date, time, whether it 

occurred during startup, malfunction 

(malfunction/breakdown), or shutdown, and 

further explanation of the incident. 

B. Each hour when the measured opacity of the 

affected boiler was above the upper bound, 

as specified above in Condition 

7.2.9(c)(ii), with date, time, operating 

condition if startup, malfunction, 

(malfunction/breakdown), or shutdown, 

further explanation of the incident, and 

whether PM emissions may have exceeded the 

limit of Conditions 7.2.4(a)(ii) and (c), 

with explanation. 

d. Records for Continuous SO2 Monitoring Systems 

Pursuant to Section 39.5(7)(e) of the Act and the 

NSPS, 40 CFR 60.45, the Permittee shall maintain 

records for the SO2 CEMS on the affected boiler 

required by Condition 7.2.8(b) that as a minimum shall 

include the following: 

i. Operating records for the SO2 CEMS, including: 

A. SO2 emission data into units of the 

applicable standards (lb/mmBtu) calculated 

in accordance with NSPS, 40 CFR 60.45(e). 

B. Continuous monitoring system performance 

testing measurements. 

C. Performance evaluations and other quality 

assurance/control activities. 

D. Calibration checks. 

E. Maintenance and adjustments performed. 
87 

F. Periods when the SO2 CEMS was inoperative, 

with date, time and reason. 

G. Data reduction information. 

H. Quarterly reports submitted in accordance 

with NSPS, 40 CFR 60.7(c) and Condition 

7.2.10-2(a) and (b). 

ii. Records to verify compliance with the SO2

limit of Conditions 7.2.4(a)(ii) and (d), 

including: 

A. SO2 emissions in the terms of the 

applicable limit (lb/mmBtu) from the 

affected boiler on an hourly basis, as 

derived from the data obtained by the SO2

CEMS. 

B. The date and time of any three-hour 

rolling averaging period when the total 

SO2 emission rate, as recorded above, 

exceeded 1.2 lb/mmBtu as allowed by 

Condition 7.2.4(a)(ii) and 7.2.4(d), with 

the calculated SO2 emission rate. 

e. Records for Continuous NOx Monitoring 

Pursuant to 40 CFR 60.45, 40 CFR 75.50, 35 IAC 

217.712(a), and Section 39.5(7)(e) of the Act, the 

Permittee shall maintain records for the NOx CEMS on 

the affected boiler required by Condition 7.2.8(c) in 

accordance with the applicable recordkeeping 

requirements of 40 CFR 75, that as a minimum shall 

include the following: 

i. Operating records for the NOx CEMS, including: 

A. NOx emission data into units of the 

applicable standards (lb/mmBtu) calculated 

in accordance with NSPS, 40 CFR 60.45(e). 

B. Continuous monitoring system performance 

testing measurements. 

C. Performance evaluations and other quality 

assurance /control activities. 

D. Calibration checks. 

E. Maintenance and adjustments performed. 

F. Periods when the CEMS was inoperative, 

with date, time and reason. 

G. Data reduction information. 
88 

H. Quarterly reports submitted in accordance 

with Condition 7.2.10-2(a) and (c). 

ii. Records to verify compliance with any shortterm NOx limit that is applicable, including: 

A. NOx emissions in lb/mmBtu from the 

affected boiler on an hourly basis, as 

derived from the data obtained by the NOx 

monitoring equipment. 

B. The date and time of any period when the 

NOx emission rate exceeded the applicable 

limit. 

f. Records for Startups 

Pursuant to 35 IAC 201.263 and Sections 39.5(7)(a) and 

(e) of the Act, the Permittee shall maintain the 

following records related to startup of the affected 

boiler: 

i. The Permittee’s startup procedures for the 

affected boiler (as required by Condition 

7.2.3(b)(ii)), accompanied by the Permittee’s 

estimate of both total and excess opacity and 

emissions of PM, NOx, CO and SO2 during 

typical startup(s), with supporting 

information and calculations. 

ii. Records for each startup of the affected 

boiler that, as a minimum, include the 

following information: 

A. Date, time, duration and description of 

the startup. 

B. The elapsed time from initial firing of 

auxiliary fuel to achievement of stable 

operation of the boiler with the principal 

fuel and with boiler systems and control 

devices operating to enable compliance 

with applicable standards for opacity and 

emissions of PM, NOx, CO and SO2. 

C. If this elapsed time is more than 6 hours 

or if the Permittee’s startup procedures 

are not followed: 

I. A detailed explanation why startup 

of the boiler was not completed 

sooner or startup procedures were 

not followed. 

II. Documentation for the startup 

procedures that were followed. 
89 

III. The elapsed time from initial firing 

of auxiliary fuel until firing of 

the principal fuel was begun. 

IV. The flue gas temperature at which 

the ESP was energized, if coal was 

fired before the ESP was energized. 

V. Estimates of the magnitude of 

emissions of PM and CO during the 

startup, including whether emissions 

may have exceeded any applicable 

hourly standard, as listed in 

Condition 7.2.4. 

VI. Emissions of NOx and boiler load 

during the startup, on an hourly 

basis, as monitored. 

g. Records for Continued Operation During Malfunctions 

And Breakdowns 

Pursuant to 35 IAC 201.263 and Sections 39.5(7)(a) and 

(e) of the Act, the Permittee shall maintain the 

following records related to malfunction and breakdown 

of the affected boiler: 

i. Maintenance and repair log(s) for the affected 

boiler that, at a minimum, address aspects or 

components of the boiler for which malfunction 

or breakdown has resulted in excess emissions, 

which shall list the activities performed on 

such aspects or components, with date, 

description and reason for the activity. In 

addition, in the maintenance and repair log(s) 

for control equipment required by Condition 

7.2.9(b)(i), the Permittee shall also list the 

reason for the activities that are performed. 

ii. Records for each incident when operation of 

the affected boiler continued with excess 

opacity or emissions, including malfunction or 

breakdown as addressed by Condition 7.2.3(c), 

that, at a minimum, include the following 

information: 

A. Date, time, duration and description of 

the incident. 

B. The corrective actions used to reduce the 

quantity of emissions and the duration of 

the incident. 

C. Confirmation of fulfillment of the 

requirements of Condition 7.2.10-3(a), as 

applicable, including copies of follow-up 

reports submitted pursuant to Condition 

7.2.10-3(a)(ii). 
90 

D. If opacity exceeded the applicable 

standard for two or more hours or 

emissions exceeded or may have exceeded an 

applicable hourly standard, as listed in 

Condition 7.2.4, during the incident: 

I. A detailed explanation why continued 

operation of the affected boiler was 

necessary. 

II. The preventative measures that have 

been or will be taken to prevent 

similar incidents or reduce their 

frequency and severity, including 

any repairs to the affected boiler 

and associated equipment and any 

changes to operating and maintenance 

procedures. 

III. Estimates of magnitude of emissions of 

PM and CO during the incident, as 

emissions exceeded or may have exceeded 

any applicable hourly standard. 

IV. Emissions of NOx of SO2during the 

incident, on an hourly basis, if 

monitored emissions exceeded the 

applicable hourly standard. 

h. Acid Rain Program 

Records for the continuous emission monitoring 

required for the affected boiler by the Acid Rain 

Program should be kept by the source in accordance 

with 40 CFR Part 75, including the General 

Recordkeeping Provisions; the General Recordkeeping 

Provisions for Specific Situations, if applicable; and 

Certification, Quality Assurance and Quality Control 

Record Provisions. [See Condition 6.3.3] 

7.2.10-1 Reporting Requirements – Reporting of Deviations 

a. Prompt Reporting of Deviations 

For the affected boiler, the Permittee shall promptly 

notify the Illinois EPA of deviations from permit 

requirements as follows. At a minimum, these 

notifications shall include a description of such 

deviations, including whether they occurred during 

startup or malfunction/breakdown, and a discussion of 

the possible cause of such deviations, any corrective 

actions and any preventative measures taken. [Section 

39.5(7)(f)(ii) of the Act] 

i. Notification and reporting as specified in 

Condition 7.2.10-3(a) for certain deviations 

from the PM limit in the PM limits in 

Condition 7.2.4(a)(ii) and (c). 
91 

ii. Notification and reporting as specified in 

Condition 7.2.10-3(a) for certain deviations 

from the opacity limits in the opacity limit 

in Conditions 7.2.4(a)(iii) and (b). 

iii. Notification with the reports required by 

Conditions 7.2.10-2(b), (c), (d) and (e) for 

deviations from Conditions 7.2.4(a), (b), (c), 

(d) and (f) and from the requirements of 

Condition 7.1.8 for emissions monitoring. 

iv. Notification with the quarterly reports 

required by Condition 7.2.10-2(a) for 

deviations not addressed above by Condition 

7.2.10-1(a)(i), (ii) or (iii), including 

deviations from other applicable requirements, 

e.g., the applicable CO emission standard, 

work practice requirements, and recordkeeping 

requirements. 

b. Periodic Reporting of Deviations 

The quarterly reports required by Condition 7.1.10-2(a) 

shall include the following information for the 

affected boiler related to deviations from permit 

requirements during the quarter. [Sections 39.5(7)(a) 

and (f)(i) of the Act] 

i. A listing of all instances of deviations that 

have been reported in writing to the Illinois 

EPA as provided by Condition 7.2.10-2(g)(i) 

and (ii), including identification of each 

such written notification or report. For this 

purpose, the Permittee need not resubmit 

copies of these previous notifications or 

reports but may elect to supplement such 

material. 

ii. Detailed information, as required by Condition 

7.2.10-2(g)(iii) or (iv), for all other 

deviations not addressed in the above listing. 

7.2.10-2 Reporting Requirements – Periodic Reporting 

a. Quarterly Reports 

In place of the semi-annual monitoring reports 

required by Condition 8.6.1, the Permittee shall 

submit quarterly reports to the Illinois EPA pursuant 

to Sections 39.5(7)(a) and (f) of the Act. 

i. These report shall include the following 

information for operation of the affected 

boiler during the quarter: 
92 

A. The total operating hours for the affected 

boiler, as also reported in accordance 

with 40 CFR Part 75. 

B. The greatest load achieved by the affected 

boiler (steam flow or gross megawatts). 

C. A discussion of significant changes in the 

fuel supply to the affected boiler, if 

any, including changes in the source of 

coal, the introduction of new fuel 

materials other than coal, gas and oil, 

and changes in the source of such other 

fuel materials or the maximum rate at 

which they will be fired. 

D. A list of the startups of the affected 

boiler, including the date, duration and 

description of each startup, accompanied 

by a copy of the records pursuant to 

Condition 7.2.9(g)(ii)(C) for each startup 

for which such records were required. 

E. A copy of the records required by 

Condition 7.2.9(c)(iii)(B) identifying the 

date and time that the upper bound, as 

specified above in Condition 7.2.9(c)(ii), 

was exceeded, with operating condition if 

startup, malfunction, breakdown, or 

shutdown; with further explanation of the 

incident and whether particulate matter 

emissions may have exceeded the PM limit. 

ii. These report shall include the information for SO2, 

NOx, and PM emissions and opacity from the affected 

boiler during the quarter and the operation of 

required continuous monitoring systems specified by 

Conditions 7.2.10-2(b), (c) and (d). 

iii. A. These reports shall be submitted after the 

end of every calendar quarter as follows: 

Monitoring Period Submittal Deadline 

 

January - March April 30 

 

April – June July 30 

 

July – September October 30 

 

October - December January 30 

b. Reporting of SO2 Emissions 

Pursuant to Sections 39.5(7) (a) and (f) of the Act 

and the NSPS 40 CFR 60.45(g), the Permittee shall 

report the following information to the Illinois EPA 

in accordance with 40 CFR 60.7(c) for the affected 

boiler with its quarterly reports pursuant to 

Condition 7.2.10-2(a): 
93 

i. Summary information on the performance of the 

SO2 CEMS, including the information for a 

“Summary Report” specified by 40 CFR 60.7(d). 

 When the SO2 CEMS was not inoperative, 

repaired or adjusted except for zero and span 

checks, this shall be stated in the report. 

ii. If specifically requested by the Illinois EPA 

or the CEMS downtime was more than 5 percent 

of the total operating time for the affected 

boiler, the date and time identifying each 

period during which the CEMS was inoperative 

except for zero and span checks, and the 

nature of CEMS repairs or adjustments and a 

summary of quality assurance data consistent 

with 40 CFR Part 75, i.e., the dates and 

results of the Linearity Test(s) and any 

Relative Accuracy Test Audit(s) during the 

quarter, a listing of any days when a required 

daily calibration was not performed, and the 

date and duration of any periods when the CEMS 

was out-of-control as addressed by 40 CFR 

75.24. 

iii. The following information for each period when 

SO2 emissions were in excess of the applicable 

standards specified in Condition 7.2.4(a)(ii) 

and 7.2.4(d)*. When there were no such 

exceedances, this shall be stated in the 

report. 

A. The starting date and time of the SO2

excess emissions. 

B. The duration of the excess emissions. 

C. A copy of the records for the excess 

emissions, as maintained pursuant to 

Condition 7.2.9(d)(ii), including the 

measured emission rate. 

D. A detailed explanation of the cause of the 

excess emissions. 

E. A detailed explanation of corrective 

actions and actions taken to lessen the 

emissions. 

* For SO2 emissions, the averaging period is 

a three-hour rolling average, as used to 

determine compliance with the limitations 

of Condition 7.2.4(d). The records for 

excess emissions shall consist of threehour rolling emission averages during 

which the limitation was exceeded. 
94 

c. Reporting of NOx Emissions 

Pursuant to Sections 39.5(7) (a) and (f) of the Act 

and 40 CFR 60.45(g), if applicable, the Permittee 

shall report the following information for the 

affected boiler to the Illinois EPA in accordance with 

40 CFR 60.7(c) with its quarterly reports pursuant to 

Condition 7.2.10-2(a): 

i. Summary information on the performance of the 

NOx CEMS, including the information for a 

“Summary Report” specified by 40 CFR 60.7(d). 

 When the NOx CEMS was not inoperative, 

repaired or adjusted except for zero and span 

checks, this shall be stated in the report. 

ii. If specifically requested by the Illinois EPA 

or the CEMS downtime was more than 5 percent 

of the total operating time for the affected 

boiler: the date and time identifying each 

period during which the CEMS was inoperative 

except for zero and span checks, and the 

nature of CEMS repairs or adjustments and a 

summary of quality assurance data consistent 

with 40 CFR Part 75, i.e., the dates and 

results of the Linearity Test(s) and any 

Relative Accuracy Test Audit(s) during the 

quarter, a listing of any days when a required 

daily calibration was not performed, and the 

date and duration of any periods when the CEMS 

was out-of-control as addressed by 40 CFR 

75.24. 

iii. The following information for each period when 

NOx emissions were subject to an hourly 

emission standard and emission were in excess 

of the limit of such standard. When there 

were no such exceedances or a short-term NOx 

limit was not applicable during all or part of 

the quarter, this shall be stated in the 

report: 

A. The starting date and time of the NOx 

excess emissions. 

B. The duration of the excess emissions. 

C. A copy of the records for the excess 

emissions, as maintained pursuant to 

Condition 7.2.9(e)(ii), including the 

measured emission rate. 

D. A detailed explanation of the cause of the 

excess emissions. 

E. A detailed explanation of corrective 

actions and actions taken to lessen the 

emissions. 
95 

F. Identification of the previous report for 

the incident submitted to the Illinois EPA 

pursuant to Condition 7.2.10-3(a)(ii). 

For this purpose, the Permittee need not 

resubmit copies of such report but may 

elect to supplement such material. 

G. A summary of the records required by 

Condition 7.2.9(h)(ii) for incidents when 

operation of the affected boiler continued 

during malfunction or breakdown with 

excess emissions that are not addressed by 

individual reports submitted pursuant to 

Condition 7.2.10-3(a)(ii). 

d. Reporting Related to Opacity and PM Emissions 

Pursuant to Sections 39.5(7)(b) and (f) of the Act and 

the NSPS, 40 CFR 60.45(g), the Permittee shall report 

the following information for the affected boiler to 

the Illinois EPA with its quarterly reports pursuant 

to Condition 7.2.10-2(a): 

i. Summary information on the performance of the 

opacity monitoring system and excess 

emissions, as required for a “Summary Report” 

in accordance with 40 CFR 60.7(d). When no 

excess opacity occurred or the continuous 

opacity monitoring system was not inoperative, 

repaired or adjusted except for zero and span 

checks, this shall be stated in the report. 

ii. The operating status of the opacity monitoring 

system, including the dates and times of any 

periods during which it was inoperative, if 

requested by the Illinois EPA or the opacity 

monitoring system downtime was more than 5 

percent of the total operating time for the 

affected boiler during the quarter. 

iii. The following information for each period when 

opacity was in excess of the applicable 

standards specified in Conditions 

7.2.4(a)(iii) and 7.2.4(b), for any six-minute 

period during which the average opacity of 

emissions exceeds 20 percent opacity. 

A. The starting dates and time of the 

exceedance. 

B. The duration of the excess opacity. 

C. The magnitude of excess opacity, based on 

six minute average opacity, including: 

I. The percent opacity for each sixminute period. 
96 

II. The start and stop time of each sixminute period in excess of the 

limitation. 

D. The cause of excess opacity, if known, 

including whether such excess opacity 

occurred during startup, malfunction or 

breakdown of the boiler. 

E. Corrective actions and actions taken to 

lessen the opacity. 

F. Identification of the previous report for 

the incident submitted to the Illinois EPA 

pursuant to Condition 7.2.10-3(a)(ii). 

For this purpose, the Permittee need not 

resubmit copies of such report but may 

elect to supplement such material. 

G. A summary of the records required by 

Condition 7.2.9(g)(ii) for incidents when 

operation of the affected boiler continued 

during malfunction or breakdown with 

excess emissions that are not addressed by 

individual reports submitted pursuant to 

Condition 7.2.10-3(a)(ii). 

Note: While the NSPS provides that one sixminute period per hour during which the 

average opacity of emissions exceeds 20 

percent opacity, but not more than 27 percent 

opacity need not be reported (40 CFR 

60.45(g)(1)), such a provision does not 

accompany 35 IAC 212.122. 

iv. The following information for periods when PM 

emissions were in excess of the limitation in 

Conditions 7.2.4(a)(ii) and 7.2.4(c). If 

there were no such exceedances during the 

reporting period, the quarterly report shall 

so state. 

A. A summary of information for each period 

of exceedance that includes: 

I. The starting date and time of the 

exceedance. 

II. The duration of the exceedance. 

III. The magnitude of the exceedance. 

IV. The percent opacity measured for 

each six-minute period during the 

exceedance. 
97 

V. The means by which the exceedance 

was indicated or identified, in 

addition to the level of opacity. 

VI. The cause of the exceedance, 

including whether the exceedance 

occurred during startup, malfunction 

or breakdown. 

VII. Corrective actions and actions taken 

to lessen the emissions. 

B. Identification of the previous reports for 

the incidents submitted to the Illinois 

EPA pursuant to Condition 7.1.10-3(a)(ii). 

For this purpose, the Permittee need not 

resubmit copies of such report but may 

elect to supplement such material. 

v. The following summary information related to 

opacity and PM exceedances: 

A. Further information for each type of 

recurring opacity exceedance that occurred 

during the quarter, including: a 

discussion of any circumstances or events 

during the quarter that generally affected 

the number or magnitude of such 

exceedances; a discussion of any 

additional understanding of the causes for 

such exceedances gained during the 

quarter, including the role of component 

failure or degradation, maintenance 

practices, and operating procedures; a 

general discussion of the effectiveness of 

the corrective actions that were taken in 

response to such exceedances; and a 

general discussion of further actions that 

are being considered to address such 

exceedances. 

B. Further information for any new type(s) of 

opacity exceedances that occurred during 

the quarter including: a general narrative 

description for the type(s) of exceedance; 

a general explanation of the cause(s) for 

such exceedances, including the role of 

component failure or degradation, 

maintenance practices, and operating 

procedures; a detailed explanation of the 

corrective actions that have been taken 

for such exceedances, including the 

reasons that the selected actions were 

taken, the effectiveness of those actions, 

and the likelihood of future occurrence of 

similar exceedances; and a general 

discussion of possible further actions 

that could be taken to address such 
98 

exceedances. For this purpose, new 

type(s) of exceedance are ones that have 

not been addressed in the preceding four 

quarterly opacity reports. 

C. Other information relevant to generally 

explaining the number and magnitude of 

opacity and PM exceedances during the 

quarter, e.g., a further discussion of 

specific events or circumstances that 

occurred that affected the number of 

magnitude or exceedances during the quarter. 

D. Information describing actions taken 

during the quarter that should generally 

act to significantly reduce the number or 

magnitude of future opacity or PM 

exceedances, e.g., a summary of relevant 

upgrades or replacements of components 

that were completed, with a description of 

such actions, an explanation of their 

relationship to exceedances, and a 

discussion of their anticipated effect on 

future exceedances. 

vi. A glossary of common technical terms used by 

the Permittee in its reports pursuant to this 

Condition 7.2.10-2(d), including the 

definitions for the categories used by the 

Permittee to classify exceedance events. 

e. Reporting of NOx Emissions for the Ozone Control Period 

The Permittee shall submit a report to the Illinois 

EPA by November 30 of each year that demonstrates 

whether the affected boiler has complied with 

Condition 7.2.4(f), pursuant to 35 IAC 217.712(d) and 

(e). 

i. If the Permittee is demonstrating compliance 

on a unit-specific basis with Condition 

7.2.4(g)(i)(A), this report shall contain the 

information specified by 35 IAC 217.712(d) 

including the heat input and NOx emissions of 

the unit for the ozone control period. 

ii. If the Permittee is demonstrating compliance 

by means of “NOx averaging” as authorized by 

Condition 7.2.4(g)(ii)(B), this report shall 

contain the information specified by 35 IAC 

217.712(e) and other related information as 

follows: 

A. In all cases, for the affected boiler or 

unit covered by this permit that is 

participating in the NOx averaging 

demonstration, the Permittee shall report 

the following: 
99 

I. Identification of the other EGU that 

are participating in the 

demonstration, including 

identification of the source that is 

the lead party for the demonstration 

and that is also taking 

responsibility for submitting the 

information required by Condition 

7.2.10-2(e)(ii)(B) below. 

II. A statement confirming that the unit 

is eligible to participate in an 

averaging demonstration, i.e., the 

unit is included in only one 

demonstration [35 IAC 217.708(d)] and 

the Permittee is complying with 

applicable recordkeeping and reporting 

requirements for the unit, pursuant to 

35 IAC 217.708(c) and (g). 

III. The average NOx emission rate for 

the unit, with calculations and 

supporting information, as required 

by 35 IAC 217.712(e)(2) and (3), 

including the heat input and NOx 

emissions of the unit for the ozone 

control period. 

IV. A statement whether the unit would 

show compliance on its own in the 

absence of averaging. 

B. If the Permittee is the lead party for a 

NOx averaging demonstration, the Permittee 

shall report the following: 

I. Copies of the information submitted 

by other parties for the EGU 

participating in the demonstration, 

which include all material required 

by Condition 7.2.10-2(e)(ii)(A) 

above (unless or except as this 

information is provided with the 

submittal by a person who is a 

responsible official for the EGU 

participating in the demonstration). 

II. The averaged NOx emission rate for 

all EGU participating in the 

demonstration, with complete 

supporting calculations, as required 

by 35 IAC 217.712(e)(1). 

III. A statement whether the 

demonstration shows compliance. 
100 

f. Submittal of Supplemental Information Related to NOx 

Emissions during the Ozone Control Period 

The Permittee shall submit copies of any records and 

data required by 35 IAC 217.712 to the Illinois EPA 

within 30 days after receipt of a written request by 

the Illinois EPA. [35 IAC 217.712(g)] 

g. Acid Rain Program Reporting 

Pursuant to Sections 412 of the Clean Air Act and 40 

CFR Parts 72 and 75, the source is subject to the 

reporting requirements of 40 CFR Part 75, which 

includes General Provisions; Notifications; Initial 

Certification or Recertification Application; 

Quarterly Reports; and Opacity Reports. [See 

Condition 6.2.3] Pursuant to Section 39.5(17)(m) of 

the Act, the designated representative of the source 

must concurrently submit to the Illinois EPA in the 

same electronic format specified by the USEPA, the 

data and information submitted to USEPA on a quarterly 

basis pursuant to 40 CFR 75.64. 

7.2.10-3 Reporting Requirements - Notifications 

a. Reporting of Continued Operation During Malfunctions 

and Breakdowns 

Pursuant to 35 IAC 201.263 and Sections 39.5(7)(a) and 

(f) of the Act, the Permittee shall provide the 

following notifications and reports to the Illinois 

EPA, Compliance Section and Regional Office, 

concerning incidents when operation of the affected 

boiler continued with excess emissions, including 

continued operation during malfunction or breakdown as 

addressed by Condition 7.2.3(c). These requirements 

do not apply to such excess emissions, if any, that 

occur during startup or shutdown of the affected 

boiler. 

i. The Permittee shall immediately notify the 

Illinois EPA’s Regional Office, by telephone 

(voice, facsimile or electronic) for each 

incident in which the applicable PM emissions 

standards (Condition 7.2.4(a)(ii) and (c)) 

could be exceeded or in which the opacity from 

the affected boiler exceeds 20 percent for 

five or more 6-minute averaging periods unless 

the Permittee has begun the shutdown of the 

affected boiler by such time. (Otherwise, as 

related to opacity, if opacity during a 

incident only exceeds 20 percent for no more 

than five 6-minute averaging periods, the 

Permittee need only report the incident in 

accordance with Condition 7.2.10-1(a)(iii) and 

7.2.10-2(d).) 
101 

ii. Upon conclusion of each incident in which the 

applicable PM emission standards may have been 

exceeded or in which exceedances of the 

opacity standards are two hours or more in 

duration, the Permittee shall submit a followup report to the Illinois EPA, Compliance 

Section and Regional Office, within 15 days 

that includes: a detailed description of the 

incident and its cause(s); an explanation why 

continued operation of the affected boiler was 

necessary, the length of time during which 

operation continued under such conditions, 

until repairs were completed or the boiler was 

taken out of service; a description of the 

measures taken to minimize and correct 

deficiencies with chronology; and a 

description of the preventative measures that 

have been and are being taken. 

7.2.11 Anticipated Operating Scenarios/Operating Flexibility 

The Permittee is authorized to make the following 

operational changes with respect to the affected boiler 

without prior notification to the Illinois EPA or revision 

of this permit, pursuant to Section 39.5(7)(a) and (l) of 

the Act. This condition does not affect the Permittee’s 

obligation to continue to comply with applicable 

requirements; to properly obtain a construction permit in 

a timely manner for any activity constituting construction 

or modification as defined in 35 IAC 201.102 or, as 

applicable, 40 CFR 52.21(a)(2) or 35 IAC 203.207; and to 

comply with other legal requirements that apply to such a 

change: 

a. Operation of additional air pollution control 

equipment, which is addressed by a separate 

construction permit. 

b. Firing of coal or a mix of coal from different 

suppliers. 

c. Firing of the following materials in conjunction with 

firing of standard fuels, provided that such materials 

can be accommodated with the existing fuel handling 

system and the burners in the affected boiler, and 

that such materials do not make up more than 10 

percent by weight of the fuel supply to the boiler on 

a quarterly basis: 

i. Other process wastes generated at the source 

in addition to used oil and boiler cleaning 

residue. 

ii. Alternative fuels that do not constitute waste 

and were not generated from municipal waste or 

hazardous waste, such as petroleum coke, tire 

derived fuel (as defined at Section 54.10b of the 

Act), clean lumber and wood waste (as defined at 
102 

40 CFR 60.2265), shredded polyethylene 

agricultural containers, and seed corn, provided 

that such materials are shipped to the source in 

homogeneous form prepared for use as fuel (e.g., 

a shipment of tire derived fuel). 

Note: Other requirements unrelated to air pollution 

control may apply to firing of alternative fuels, such as 

Standards for Management of Used Oil, 35 IAC Part 739. 

7.2.12 Compliance Procedures 

a. i. Compliance with the opacity limits of 

Conditions 7.2.4(a)(iii) and (b) (20 percent 

opacity) is addressed by the average opacity 

calculated from 6-minute periods of opacity 

measurements from the continuous opacity 

monitoring system operated in accordance with 

the requirements of Condition 7.2.8(a) and the 

recordkeeping requirements of Conditions 

7.2.9. 

ii. Notwithstanding Condition 7.2.12(a)(i) above, 

should the Permittee choose to rely on 35 IAC 

212.122(b) to allow opacity greater than 20 

percent (6-minute average) from an affected 

boiler, the Permittee shall do the following: 

A. Maintain records for the affected boiler 

of short-term opacity data, that is, 

either a continuous chart recording of 

measured opacity, a record of discrete 

measurements of opacity taken no more than 

10 seconds apart, or a record of 1-minute 

average opacity data determined from six 

or more data points equally spaced during 

each minute period, to determine whether 

opacity from the boiler exceeded 20 

percent opacity. 

B. Have the capability to review such shortterm opacity data for the affected boiler 

to identify: 

I. Any hour in which opacity exceeded 

20 percent, and then, in such hour: 

(1) the duration of opacity in 

excess of 20 percent; (2) whether 

opacity ever exceeded 40 percent; 

and (3) whether the duration of 

opacity in excess of 20 percent was 

more than 3 minutes in aggregate. 

II. For the affected boiler, whether 

opacity in excess of 20 percent 

occurred in more than three hours in 

a 24 hour period. 
103 

C. For other emission units at the source, 

have the ability to review short-term 

opacity data representative of such units 

during hours in which the opacity of the 

affected boiler on a short-term basis may 

exceed 20 percent, to confirm that the 

opacity of any other unit at the source 

did not exceed 20 percent in any minute 

during an hour in which the short-term 

opacity of the affected boiler may have 

exceeded 20 percent. 

D. In the reports required by Condition 

7.2.10-2(e), confirm that the relevant 

short-term opacity data, reviewed as 

above, shows that the terms of 35 IAC 

212.122(b) are satisfied, when 35 IAC 

212.122(b) is relied upon as the basis to 

claim that an affected boiler did not 

violate Condition 7.2.4(b) even though 

opacity on a 6-minute average exceeded 20 

percent. 

E. Notify the Illinois EPA at least 15 days 

prior to changing its procedures 

associated with reliance on 35 IAC 

212.122(b), to allow the Illinois EPA to 

review the new recordkeeping and data 

handling practices planned by the 

Permittee. 

b. Compliance with PM emission limits of Conditions 

7.2.4(a)(ii) and (c) is addressed by continuous 

opacity monitoring in accordance with Condition 

7.2.8(a), PM testing in accordance with Condition 

7.2.7, and the recordkeeping required by Conditions 

7.2.9. 

c. Compliance with the SO2 emission limits of Condition 

7.2.4(a)(ii) and (d) is addressed by continuous 

emission monitoring in accordance with Condition 

7.2.8(b) and the recordkeeping required by Condition 

7.2.9(d). 

d. Compliance with the CO emission limitation of 

Condition 7.2.4(e) is addressed by the required work 

practices in Condition 7.2.6(a), emission testing in 

accordance with Conditions 7.2.7 and the recordkeeping 

required by Condition 7.2.9. 

e. Compliance with NOx emission limits of Conditions 

7.2.5(b)(ii), if applicable, and 7.2.4(f) is addressed 

by continuous emissions monitoring in accordance with 

Condition 7.2.8(c) and the recordkeeping required by 

Condition 7.2.9. 
104 

f. Compliance with the work practices required by 

Condition 7.2.6(a) is addressed by the recordkeeping 

required by Condition 7.2.9. 

Note: This condition is included in this permit pursuant 

to Section 39.5(7)(p)(v) of the Act. 
105 

7.3 Coal Handling Equipment 

7.3.1 Description 

The Permittee transfers and stores coal in a series of 

operations, including truck unloading, various conveyor 

belts (with associated hoppers, diverters, and transfer 

points), storage piles (with stackers and feeders), and 

bunkers. These operations first handle coal, as supplied 

by the mine and then, after the crushers, coal that has 

been processed at the source by the coal processing 

equipment (See Section 7.4). Particulate matter (PM) 

emissions associated with these operations are controlled 

by various measures including the moisture content of the 

coal, enclosures and covers, and dust collection devices. 

7.3.2 List of Emission Units and Air Pollution Control Equipment 

The following is a list of the coal handling operations 

and associated emission control systems at the source: 

Coal Receiving Operations

Truck Unloading 

Coal Transfer Conveyors 

Dust Suppressant Application System, Dust Collection 

Devices, Enclosures and Covers 

Coal Crushing House

Coal Transfer Conveyors 

Dust Suppressant Application System, Enclosures and Covers 

Coal Storage Operations

Outdoor Storage Piles 

Coal Transfer Conveyors 

Coal Storage Bunkers 

Coal Silo 

Controls - None 

7.3.3 Applicability Provisions 

a. The “affected operations” for the purpose of these 

unit-specific conditions, are the emission units that 

are used solely for the purpose of transferring coal 

or other solid fuel from one location to another or 

for storage of coal or other solid fuel, without 

changing the size of the fuel, e.g., by crushing or 

screening, as described in Conditions 7.3.1 and 7.3.2. 

7.3.4 Applicable Emission Standards 

a. The affected operations shall comply with the standard 

in Condition 5.2.2(a), which generally addresses 

visible emissions of fugitive particulate matter, as 

defined by 35 IAC 211.2490, pursuant to 35 IAC 

212.301. 
106 

b. The affected operations shall comply with the 

standard, i.e., 30 percent opacity, in Condition 

5.2.2(b), which generally addresses the opacity of the 

emission of smoke or other particulate matter, 

pursuant to 35 IAC 212.123. 

7.3.5 Non-Applicability of Regulations of Concern 

a. The affected operations are not subject to 35 IAC 

212.321 or 212.322 because of the disperse nature of 

the operations, as generally addressed by 35 IAC 

212.323. 

7.3.6 Work Practices, Operational and Production Limits, and 

Emission Limitations 

a. i. The Permittee shall implement and maintain 

control measures for the affected operations, 

such as enclosure, natural surface moisture, 

application of dust suppressant, and use of 

dust collection devices, that minimize visible 

emissions of particulate matter and provide 

assurance of compliance with the applicable 

emission control requirements in Conditions 

7.3.4 and 7.3.6(b), pursuant to Section 

39.5(7)(a) of the Act. 

ii. The Permittee shall operate and maintain each 

affected operation with the control measures 

identified in the records required by 

Condition 7.3.9(b). 

b. i. A. The fuel silos associated with Boiler 123 

(Silos 1 through 4) shall each be 

controlled with a baghouse (fabric filter) 

to control PM emissions. [T1] 

B. Good air pollution control practices shall 

be employed to minimize the emissions of 

PM from storage piles. [T1] 

ii. PM emissions from the fuel silos associated 

with Boiler 123 (Silos S1 through S4) shall 

each not exceed 0.137 lb/hr. [T1] 

Note: The above requirements were established in 

Construction Permit 00070030. 

7.3.7 Opacity Testing Requirements 

a. i. The Permittee shall have the opacity of the 

emissions from the affected operations during 

representative weather and operating 

conditions determined by a qualified observer 

in accordance with USEPA Test Method 9, as 

further specified below, pursuant to Section 

39.5(7)(d) of the Act. 
107 

A. For each affected operation, testing shall 

be conducted at least annually. For this 

purpose, testing shall first be conducted 

within three months after the effective 

date of this Condition 7.3.7(a). 

B. Upon written request by the Illinois EPA, 

such testing shall be conducted for 

specific affected operation(s) within 45 

calendar days of the request or on the 

date agreed upon by the Illinois EPA, 

whichever is later. 

ii. The duration of opacity observations for each 

test shall be at least 30 minutes (five 6-

minute averages) unless the average opacities 

for the first 12 minutes of observations (two 

six-minute averages) are both less than 10.0 

percent. 

iii. A. The Permittee shall notify the Illinois 

EPA at least 7 days in advance of the date 

and time of these tests, in order to allow 

the Illinois EPA to witness testing. This 

notification shall include the name and 

employer of the qualified observer(s). 

B. The Permittee shall promptly notify the 

Illinois EPA of any changes in the time or 

date for testing. 

iv. The Permittee shall provide a copy of its 

observer’s readings to the Illinois EPA at the 

time of testing, if Illinois EPA personnel are 

present. 

v. The Permittee shall submit a written report 

for this testing within 15 days of the date of 

testing. This report shall include: 

A. Date and time of testing. 

B. Name and employer of qualified observer. 

C. Copy of current certification. 

D. Description of observation condition, 

including recent weather. 

E. Description of the operating conditions of 

the affected operations. 

F. Raw data. 

G. Opacity determinations. 

H. Conclusions. 
108 

7.3.8 Inspection Requirements 

a. The Permittee shall perform inspections of the 

affected operations on at least a monthly basis, 

including associated control measures, while the 

affected operations are in use, to confirm compliance 

with the requirements of Condition 7.3.6(a). These 

inspections shall be performed with personnel not 

directly involved in the day-to day operation of the 

affected operations and may be scheduled so that only 

a number of affected operations are reviewed during 

each inspection, provided however, that all affected 

operations that are in routine service shall be 

inspected at least once during each calendar month, 

[Section 39.5(7)(a) and (d) of the Act.] 

b. The Permittee shall perform detailed inspections of 

the dust collection equipment for the affected 

operations at least every 15 months while the 

processes are out of service, with an initial 

inspection performed before any maintenance and repair 

activities are conducted during the period the process 

is out of service and a follow-up inspection performed 

after any such activities are completed. [Section 

39.5(7)(a) and (d) of the Act] 

7.3.9 Recordkeeping Requirements 

The Permittee shall maintain records of the following 

items for the affected operations, pursuant to Sections 

39.5(7)(a) and (e) of the Act. 

a. The Permittee shall keep the following file(s) and 

log(s): 

i. File(s) containing the following information 

for the affected operations, with supporting 

information, which information shall be kept 

up to date. 

A. Information related to any dust collection 

equipment associated with the affected 

operations, including the design control 

efficiency or performance specifications 

and maximum design particulate matter 

emissions, gr/dscf. 

B. The maximum operating capacity of each 

affected operation, (ton/hour). 

b. i. The Permittee shall maintain a record, which 

shall be kept up to date, of the control 

measures currently being implemented for the 

affected operations pursuant to Condition 

7.3.6(a). These control measures are referred 

to as the “established control measures” in 

this subsection of this permit. 
109 

ii. Accompanying this record, the Permittee shall 

maintain a demonstration that confirms that 

the above established control measures are 

sufficient to assure compliance with the 

emission limitations in Condition 7.3.6(b), 

with supporting emission calculations and 

documentation for the emission factors and the 

efficiency of the control measures being 

relied upon by the Permittee. Except as 

addressed by Condition 7.3.9(a)(i), this 

demonstration shall be developed using 

emission factors for uncontrolled PM 

emissions, efficiency of control measures, and 

controlled PM emissions published by USEPA. 

iii. Copies of these records shall be submitted to the 

Illinois EPA in accordance with Condition 5.6.2(d). 

c. The Permittee shall maintain the following operating 

records: 

i. The amount of coal and other solid fuels 

received at the source, by type of fuel 

(tons/month and tons/year). 

ii. The amount of coal and other solid fuels sent 

to the fuel silos, by type of fuel (tons/month 

and tons/year). 

d. The Permittee shall maintain records of the following 

for the inspections required by Condition 7.3.8: 

i. For the inspections required by Condition 

7.3.8(a) for each affected operation: 

A. Date and time the inspection was performed 

and name(s) of inspection personnel. 

B. The observed condition of the control measures 

for each affected operation, including the 

presence of any visible emissions. 

C. A description of any maintenance or repair 

associated with established control 

measures that is recommended as a result 

of the inspection and a review of 

outstanding recommendations for 

maintenance or repair from previous 

inspection(s), i.e., whether recommended 

action has been taken, is yet to be 

performed or no longer appears to be 

required. 

D. A summary of the observed implementation 

or status of actual control measures, as 

compared to the established control 

measures. 
110 

ii. For the inspections required by Condition 

7.3.8(b) for the dust collection equipment for 

affected operations: 

A. Date and time the inspection was performed 

and name(s) of inspection personnel. 

B. The observed condition of the equipment. 

C. A summary of the maintenance and repair 

that is to be or was conducted on the 

equipment. 

D. A description of any maintenance or repair 

that is recommended as a result of the 

inspection and a review of outstanding 

recommendations for maintenance or repair 

from previous inspection(s), i.e., whether 

recommended action has been taken, is yet 

to be performed or no longer appears to be 

required. 

E. A summary of the observed condition of the 

equipment as related to its ability to 

reliably and effectively control 

emissions. 

e. The Permittee shall maintain records of the following 

for each incident when any affected operation operated 

without the established control measures: 

i. The date of the incident and identification of 

the affected operations that were involved. 

ii. A description of the incident, including the 

established control measures that were not 

present or implemented; the established control 

measures that were present, if any; other control 

measures or mitigation measures that were 

implemented, if any; and the magnitude of the PM 

emissions during the incident. 

iii. The time at and means by which the incident 

was identified, e.g., scheduled inspection or 

observation by operating personnel. 

iv. The length of time after the incident was 

identified that the affected operations 

continued to operate before established 

control measures were in place or the 

operations were shutdown (to resume operation 

only after established control measures were 

in place) and, if this time was more than one 

hour, an explanation why this time was not 

shorter, including a description of any 

mitigation measures that were implemented 

during the incident. 
111 

v. The estimated total duration of the incident, 

i.e., the total length of time that the 

affected operations ran without established 

control measures and the estimated amount of 

coal handled during the incident. 

vi. A discussion of the probable cause of the 

incident and any preventative measures taken. 

vii. A discussion whether any applicable emissions 

standards, as listed in Condition 7.3.4, or 

the PM emission limits in Condition 7.3.6(b) 

may have been violated during the incident, 

with an estimate of the amount of any 

additional or excess PM emissions (lbs) from 

the incident, with supporting explanation. 

f. The Permittee shall keep records for all opacity 

measurements made in accordance with USEPA Method 9 

for the affected operations that it conducts or that 

are conducted on its behest by individuals who are 

qualified to make such observations. For each 

occasion on which such measurements are made, these 

records shall include the formal report for the 

measurements if conducted pursuant to Condition 

7.3.7(a), or otherwise the identity of the observer, a 

description of the measurements that were made, the 

operating condition of the affected operations, the 

observed opacity, and copies of the raw data sheets 

for the measurements. 

g. To demonstrate compliance with Condition 7.3.6(b), the 

Permittee shall keep records for PM emissions of the 

fuel silos PM emissions (tons/month and tons/year), 

based on the records, with supporting calculations. 

7.3.10 Reporting Requirements 

a. Reporting of Deviations 

For the affected operations, the Permittee shall 

promptly notify the Illinois EPA of deviations from 

permit requirements as follows. Such notifications 

shall include a description of each incident and a 

discussion of the probable cause of deviation, any 

corrective actions taken and any preventative measures 

taken, pursuant to Section 39.5(7)(f)(ii) of the Act: 

i. The Permittee shall provide the following 

notifications and reports to the Illinois EPA 

concerning incidents when operation of 

continued with excess emissions, including 

continued operation during malfunction or 

breakdown of equipment. 
112 

A. The Permittee shall immediately notify the 

Illinois EPA’s Regional Office, by 

telephone (voice, facsimile or electronic) 

for each incident in which the opacity 

from an affected operation exceeds or may 

have exceeded the applicable opacity 

standard for three or more 6-minute 

averaging periods. (Otherwise, if opacity 

during a malfunction or breakdown incident 

only exceeds or may have exceeded the 

applicable standard for one or two 6-

minute averaging periods, the Permittee 

need only report the incident in 

accordance with Condition 7.3.10(a)(iii).) 

B. Upon conclusion of each such incident for 

which notification is required, the 

Permittee shall submit a written follow-up 

notice to the Illinois EPA, Compliance 

Section and Regional Office, within 15 

days providing a detailed description of 

the incident and its cause(s), an 

explanation why continued operation of an 

affected operation was necessary, the 

length of time during which operation 

continued under such conditions, the 

measures taken by the Permittee to 

minimize and correct deficiencies with 

chronology, and when the repairs were 

completed or when the affected operation 

was taken out of service. 

ii. Notification within 30 days for operation of 

an affected operation that did not fulfill the 

applicable requirements in Conditions 7.3.6(a) 

that continued for more than 12 operating 

hours from the time that it was identified. 

Such notifications shall be accompanied by a 

copy of the records for the incident required 

by Condition 7.3.9(e). 

iii. A. Notification with the next deviation 

quarterly reports required by Condition 

7.1.10-1(a)(iv) for other deviations not 

addressed by Conditions 7.3.10(a)(i) and 

(ii), including deviations from applicable 

emission standards, inspection requirements 

and recordkeeping requirements. 

B. With the deviation quarterly report, the 

Permittee shall also address deviations 

that occurred during the reporting period 

quarter that have been separately reported 

to the Illinois EPA, with a summary of 

such deviations. For this purpose, the 

Permittee need not resubmit the detailed 

information provided in the initial 

notifications and reports for such 

deviations. 
113 

7.3.11 Operational Flexibility/Anticipated Operating Scenarios 

The Permittee is authorized to make the following physical 

or operational change with respect to the affected 

operations without prior notification to the Illinois EPA 

or revision of this permit, pursuant to Section 39.5(7)(a) 

and (l) of the Act. This condition does not affect the 

Permittee’s obligation to continue to comply with 

applicable requirements or to properly obtain a 

construction permit in a timely manner for any activity 

constituting a modification as defined by 40 CFR 52.21 or 

35 IAC 203.207, as applicable, or for an activity for 

which a permit is required pursuant to 35 IAC 201.142. 

a. Handling of solid fuels other than coal. 

b. Operation of additional dust suppressant systems. 

c. Operation of additional dust collection equipment. 

d. Operation of replacement dust suppression systems or 

dust collection equipment that is of equal or greater 

effectiveness in controlling PM emissions than the 

device(s) being replaced, as recognized in a 

Construction Permit for such system or equipment. 

7.3.12 Compliance Procedures 

a. Compliance with Conditions 7.3.4is addressed by the 

control, testing, inspection, and recordkeeping 

required by Conditions 7.3.6(a), 7.3.7, 7.3.8, and 

7.3.9, respectively. 

b. Compliance with Condition 7.3.6(a) is addressed by the 

testing, inspection, and recordkeeping required by 

Conditions 7.3.7, 7.3.8, and 7.3.9, respectively. 

c. Compliance with Condition 7.3.6(b) is addressed by the 

control, inspection, and recordkeeping required by 

Conditions 7.3.6(a), 7.3.8, and 7.3.9, respectively. 

Note: This condition is included in this permit pursuant 

to Section 39.5(7)(p)(v) of the Act. 
114 

7.4 Coal Processing Equipment 

7.4.1 Description 

The Permittee prepares or processes coal for use as fuel 

in its boilers with crushers that reduce the size of the 

coal. Associated particulate matter (PM) emissions are 

controlled by various control measures including moisture 

content of the coal, application of dust suppressant to 

the coal, and enclosures and covers. 

7.4.2 List of Emission Units and Air Pollution Control Equipment 

Emission 

Unit Description 

Emission Control 

Equipment 

Crusher House Coal Crushing 

Operation 

Enclosures and Covers, 

and Dust Suppressant 

Application 

7.4.3 Applicability Provisions 

a. An “affected process” for the purpose of these unitspecific conditions, is an individual process emission 

unit that prepares coal for use as a fuel by crushing 

the coal as described in Conditions 7.4.1 and 7.4.2. 

7.4.4 Applicable Emission Standards 

a. The affected processes shall comply with the standard 

in Condition 5.2.2(a), which addresses visible 

emissions of fugitive particulate matter, as defined 

by 35 IAC 211.2490, from the affected processes, 

pursuant to 35 IAC 212.301. 

b. The affected processes shall comply with the standard, 

i.e., 30 percent opacity, in Condition 5.2.2(b), which 

addresses the opacity of the emission of smoke or 

other particulate matter from the affected processes, 

pursuant to 35 IAC 212.123. 

c. The affected processes shall comply with 35 IAC 

212.321(a), which provides that: 

No person shall cause or allow the emission of 

particulate matter into the atmosphere in any one hour 

period from any new process emission unit which, 

either alone or in combination with the emission of 

particulate matter from all other similar process 

emission units for which construction or modification 

commenced on or after April 14, 1972, at a source or 

premises, exceeds the allowable emission rates 

specified in 35 IAC 212.321(c) of 35 IAC 212.321 [35 

IAC 212.321(a)]. (See also Attachment 1) 

7.4.5 Non-Applicability of Regulations of Concern 

None 
115 

7.4.6 Work Practices, Operational and Production Limits, and 

Emission Limitations 

a. i. The Permittee shall implement and maintain 

control measures for the affected processes, 

such as enclosure, natural surface moisture, 

application of dust suppressant, and use of 

dust collection devices, that minimize visible 

emissions of particulate matter and provide 

assurance of compliance with the applicable 

emission standards in Condition 7.4.4 pursuant 

to Section 39.5(7)(a) of the Act. 

ii. The Permittee shall operate and maintain each 

affected process with the control measures 

identified in the records required by 

Condition 7.4.9(b)(i). 

7.4.7 Opacity and Emission Testing Requirements 

a. i. The Permittee shall have the opacity of the 

emissions from the affected processes during 

representative weather and operating conditions 

determined by a qualified observer in accordance 

with USEPA Test Method 9, as further specified 

below, pursuant to Section 39.5(7)(d) of the Act. 

A. For each affected process, testing shall 

be conducted at least annually. For this 

purpose, testing shall first be conducted 

within three months after the effective 

date of this Condition 7.4.7(a). 

B. Upon written request by the Illinois EPA, 

such testing shall be conducted for 

specific affected process(es) within 45 

calendar days of the request or on the 

date agreed upon by the Illinois EPA, 

whichever is later. 

ii. The duration of opacity observations for each 

test shall be at least 30 minutes (five 6-

minute averages) unless the average opacities 

for the first 12 minutes of observations (two 

six-minute averages) are both less than 10.0 

percent. 

iii. A. The Permittee shall notify the Illinois 

EPA at least 7 days in advance of the date 

and time of these tests, in order to allow 

the Illinois EPA to witness testing. This 

notification shall include the name and 

employer of the qualified observer(s). 

B. The Permittee shall promptly notify the 

Illinois EPA of any changes in the time or 

date for testing. 
116 

iv. The Permittee shall provide a copy of its 

observer’s readings to the Illinois EPA at the 

time of testing, if Illinois EPA personnel are 

present. 

v. The Permittee shall submit a written report 

for this testing within 15 days of the date of 

testing. This report shall include: 

A. Date and time of testing. 

B. Name and employer of qualified observer. 

C. Copy of current certification. 

D. Description of observation condition, 

including recent weather. 

E. Description of the operating conditions of 

the affected processes. 

F. Raw data. 

G. Opacity determinations. 

H. Conclusions. 

b. i. Within 90 days of a written request from the 

Illinois EPA, the Permittee shall have the PM 

emissions at the stacks or vents of the 

affected processes, as specified in such 

request, measured during representative 

operating conditions, as set forth below, 

pursuant to Section 39.5(7)(d) of the Act. 

ii. A. Testing shall be conducted using 

appropriate USEPA Reference Test Methods, 

including Method 5 for PM emissions. 

B. Compliance may be determined from the 

average of three valid test runs, subject 

to the limitations and conditions 

contained in 35 IAC Part 283. 

iii. The Permittee shall submit a test plan to the 

Illinois EPA at least 60 days prior to 

testing, which plan shall include the 

information specified by Condition 8.6.2. 

iv. The Illinois EPA shall be notified prior to 

these tests to enable the Illinois EPA to 

observe these tests. Notification of the 

expected date of testing shall be submitted a 

minimum of 30 days prior to the expected date. 

Notification of the actual date and expected 

time of testing shall be submitted a minimum 

of 5 working days prior to the actual date of 

the test. The Illinois EPA may, at its 
117 

discretion, accept notification with shorter 

advance notice provided that the Illinois EPA 

will not accept such notification if it 

interferes with the Illinois EPA’s ability to 

observe the testing. 

v. The Permittee shall expeditiously submit 

complete Final Report(s) for required emission 

testing to the Illinois EPA, no later than 90 

days after the date of testing. These reports 

shall include the information specified in 

Condition 8.6.3 and the following information: 

A. A summary of results. 

B. Detailed description of test method(s), 

including description of sampling points, 

sampling train, analysis equipment, and 

test schedule. 

C. Detailed description of the operating 

conditions of the affected process during 

testing, including operating rate 

(tons/hr) and the control measures being 

used. 

D. Detailed data and calculations, including 

copies of all raw data sheets and records 

of laboratory analyses, sample 

calculations, and data on equipment 

calibration. 

E. Representative opacity data (6-minute 

average) measured during testing. 

7.4.8 Inspection Requirements 

a. The Permittee shall perform inspections of each 

affected process on at least a weekly basis, including 

associated control measures, to confirm compliance 

with the requirements of Condition 7.4.6(a). These 

inspections shall be performed with personnel not 

directly involved in the day-to day operation of the 

affected processes. [Sections 39.5(7)(a) and (d) of 

the Act] 

b. The Permittee shall perform detailed inspections of 

the dust collection equipment for affected processes 

at least every 15 months while the processes are out 

of service, with an initial inspection performed 

before any maintenance and repair activities are 

conducted during the period the process is out of 

service and a follow-up inspection performed after any 

such activities are completed. [Sections 39.5(7)(a) 

and (d) of the Act]. 
118 

7.4.9 Recordkeeping Requirements 

The Permittee shall maintain records of the following 

items for the affected processes, pursuant to Sections 

39.5(7)(a) and (e) of the Act: 

a. The Permittee shall keep the following records: 

i. The following information for the affected 

process, with supporting information, which 

shall be kept up to date: 

A. Information related to the dust collection 

equipment associated with the affected 

processes, including the performance 

specifications for filter material and 

maximum design particulate matter 

emissions, gr/dscf. 

B. The maximum operating capacity of each 

element of the affected process, (ton/hr). 

ii. Operating log(s) for the affected process, 

which shall include information for any 

incident in which the operation of the process 

continued during malfunction or breakdown, 

including: date, time, and duration; a 

description of the incident; whether emissions 

exceeded or may have exceeded any applicable 

standard; a description of the corrective 

actions taken to reduce emissions and the 

duration of the incident; and a description of 

the preventative actions taken. 

iii. A maintenance and repair log for the process, 

including each item of air pollution control 

equipment, i.e., each dust suppressant 

application system and each dust collection 

device associated with the process, which 

lists the date and nature of maintenance and 

repair activities performed. (See also 

Condition 9.6.1, Control Equipment Maintenance 

Records.) 

b. i. The Permittee shall maintain a record, which 

shall be kept up to date, of the control 

measures currently being implemented for the 

affected processes pursuant to Condition 

7.4.6(a). These control measures are referred 

to as the “established control measures” in 

this subsection of this permit. 

ii. Accompanying this record, the Permittee shall 

maintain a demonstration that confirms that 

the above established control measures are 

sufficient to assure compliance with Condition 

7.4.4(c) at the maximum process weight rate at 

which each affected process can be operated 
119 

(tons coal/hour), with supporting emission 

calculations and documentation for the 

emission factors and the efficiency of the 

control measures being relied upon by the 

Permittee. Except as addressed by Condition 

7.4.9(a)(i) or testing of an affected process 

is conducted in accordance with Condition 

7.4.7(b), this demonstration shall be 

developed using emission factors for 

uncontrolled PM emissions, efficiency of 

control measures, and controlled PM emissions 

published by USEPA. 

iii. Copies of these records shall be submitted to 

the Illinois EPA in accordance with Condition 

5.6.2(d). 

c. The Permittee shall maintain records of the following 

for the inspections required by Condition 7.4.8: 

i. For the inspections required by Condition 

7.4.8(a) for each affected process: 

A. Date and time the inspection was performed 

and name(s) of inspection personnel. 

B. The observed condition of the control 

measures for each affected process, 

including the presence of any visible 

emissions. 

C. A description of any maintenance or repair 

associated with established control 

measures that is recommended as a result 

of the inspection and a review of 

outstanding recommendations for 

maintenance or repair from previous 

inspection(s), i.e., whether recommended 

action has been taken, is yet to be 

performed or no longer appears to be 

required. 

D. A summary of the observed implementation or 

status of actual control measures, as compared 

to the established control measures. 

ii. For the inspections required by Condition 

7.4.8(b) for the dust collection equipment for 

affected processes: 

A. Date and time the inspection was performed 

and name(s) of inspection personnel. 

B. The observed condition of the equipment. 

C. A summary of the maintenance and repair 

that is to be or was conducted on the 

equipment. 
120 

D. A description of any maintenance or repair that 

is recommended as a result of the inspection and 

a review of outstanding recommendations for 

maintenance or repair from previous 

inspection(s), i.e., whether recommended action 

has been taken, is yet to be performed or no 

longer appears to be required. 

E. A summary of the observed condition of the 

equipment as related to its ability to 

reliably and effectively control 

emissions. 

d. The Permittee shall maintain records of the following 

for each incident when any affected process operated 

without the established control measures: 

i. The date of the incident and identification of 

the affected process(es) that were involved. 

ii. A description of the incident, including the 

established control measures that were not 

present or implemented; the established control 

measures that were present, if any; other control 

measures or mitigation measures that were 

implemented, if any; and the magnitude of the PM 

emissions during the incident. 

iii. The time at and means by which the incident 

was identified, e.g., scheduled inspection or 

observation by operating personnel. 

iv. The length of time after the incident was 

identified that the affected process(es) 

continued to operate before established 

control measures were in place or the 

operations were shutdown (to resume operation 

only after established control measures were 

in place) and, if this time was more than one 

hour, an explanation why this time was not 

shorter, including a description of any 

mitigation measures that were implemented 

during the incident. 

v. The estimated total duration of the incident, 

i.e., the total length of time that the 

affected process(es) ran without established 

control measures and the estimated amount of 

coal processed during the incident. 

vi. A discussion of the probable cause of the 

incident and any preventative measures taken. 

vii. A discussion whether any applicable emission 

standards, as listed in, Condition 7.4.4, may 

have been violated during the incident, with 

supporting explanation. 
121 

e. The Permittee shall keep a maintenance and repair log 

for each item of air pollution control equipment, 

i.e., each dust suppressant application system and 

each dust collection device, associated with affected 

process(es). This log shall list the date and nature 

of maintenance and repair activities performed on the 

item of equipment. (See also Condition 9.6.1, Control 

Equipment Maintenance Records.) 

f. The Permittee shall keep records for all opacity 

measurements made in accordance with USEPA Method 9 

for the affected processes that it conducts or that 

are conducted on its behest by individuals who are 

qualified to make such observations. For each 

occasion on which such measurements are made, these 

records shall include the formal report for the 

measurements if conducted pursuant to Condition 

7.4.7(a), or otherwise the identity of the observer, a 

description of the measurements that were made, the 

operating condition of the affected process, the 

observed opacity, and copies of the raw data sheets 

for the measurements. 

7.4.10 Reporting Requirements 

a. Reporting of Deviations 

For the affected processes, the Permittee shall 

promptly notify the Illinois EPA of deviations from 

permit requirements as follows. Such notifications 

shall include a description of each incident and a 

discussion of the probable cause of deviation, any 

corrective actions taken and any preventative measures 

taken, pursuant to Section 39.5(7)(f)(ii) of the Act: 

i. The Permittee shall provide the following 

notifications and reports to the Illinois EPA 

concerning incidents when operation continued 

with excess emissions, including continued 

operation of an affected process during 

malfunction or breakdown of equipment. 

A. The Permittee shall immediately notify the 

Illinois EPA’s Regional Office, by 

telephone (voice, facsimile or electronic) 

for each incident in which the opacity 

from an affected process exceeds or may 

have exceeded 30 percent for three or more 

6-minute averaging periods. (Otherwise, 

if opacity during a malfunction or 

breakdown incident only exceeds or may 

have exceeded 30 percent for one or two 6-

minute averaging periods, the Permittee 

need only report the incident in 

accordance with Condition 7.4.10(a)(iii).) 
122 

B. Upon conclusion of each such incident for 

which notification is required, the 

Permittee shall submit a written follow-up 

notice to the Illinois EPA, Compliance 

Section and Regional Office, within 15 

days providing a detailed description of 

the incident and its cause(s), an 

explanation why continued operation was 

necessary, the length of time during which 

operation continued under such conditions, 

the measures taken by the Permittee to 

minimize and correct deficiencies with 

chronology, and when the repairs were 

completed or when the affected operation 

was taken out of service. 

ii. Notification within 30 days for operation of 

an affected process that was not in compliance 

with applicable requirements in Conditions 

7.4.6(a) that continued for more than 12 

operating hours from the time that it was 

identified. Such notifications shall be 

accompanied by a copy of the records for the 

incident required by Condition 7.4.9(e). 

iii. A. Notification with the next deviation 

report required by Condition 7.1.10-

1(a)(iv) for other deviations not 

addressed by Conditions 7.4.10(a)(i) and 

(ii), including deviations from applicable 

emission standards, inspection 

requirements and recordkeeping 

requirements. 

B. With the deviation report, the Permittee 

shall also address deviations that 

occurred during the reporting period that 

have been separately reported to the 

Illinois EPA, with a summary of such 

deviations. For this purpose, the 

Permittee need not resubmit the detailed 

information provided in the initial 

notifications and reports for such 

deviations. 

7.4.11 Operational Flexibility/Anticipated Operating Scenarios 

The Permittee is authorized to make the following physical 

or operational change with respect to the affected 

processes without prior notification to the Illinois EPA 

or revision of this permit, pursuant to Section 39.5(7)(a) 

and (l) of the Act. This condition does not affect the 

Permittee’s obligation to continue to comply with 

applicable requirements or to properly obtain a 

construction permit in a timely manner for any activity 

constituting a modification as defined by 40 CFR 52.21 or 

35 IAC 203.207, as applicable, or for an activity for 

which a permit is required pursuant to 35 IAC 201.142. 
123 

a. Handling of solid fuels other than coal. 

b. Operation of additional dust suppressant systems. 

c. Operation of additional dust collection equipment. 

d. Operation of replacement dust suppression systems or 

dust collection equipment that is of equal or greater 

effectiveness in controlling PM emissions than the 

device(s) being replaced as recognized in a 

Construction Permit for such system or equipment. 

7.4.12 Compliance Procedures 

a. Compliance with Conditions 7.4.4(a) and (b) is 

addressed by the control, testing, inspection, and 

recordkeeping required by Conditions 7.4.6(a), 

7.4.7(a), 7.4.8, and 7.4.9, respectively. 

b. Compliance with Conditions 7.4.4(c) is addressed by 

the control, testing, inspection, and recordkeeping 

required by Conditions 7.4.6(a), 7.4.7, 7.4.8, and 

7.4.9, respectively. 

c. Compliance with Condition 7.4.6(a) is addressed by 

testing, inspection, and recordkeeping required by 

Conditions 7.4.7, 7.4.8, and 7.4.9, respectively. 

Note: This condition is included in this permit pursuant 

to Section 39.5(7)(p)(v) of the Act. 
124 

7.5 Ash Equipment 

7.5.1 Description 

The Permittee operates ash removal systems that handle and 

store ash collected at the coal-fired boilers. 

A pug mill is used to combine dry fly ash with wet sludge 

from the scrubber on Boiler 4, in preparation for landfill 

disposal, when there is not a market for the dry fly ash 

material. Associated particulate matter (PM) emissions 

are controlled by various control measures including 

moisture content of the fly ash, and enclosures and 

covers. 

7.5.2 List of Emission Units and Air Pollution Control Equipment 

The following is a list of the fly ash equipment and 

associated emission control systems at the source: 

Emission 

Unit Description 

Control 

Equipment 

Ash 1 Fly Ash Conveyor Baghouse 

Silo 6 

(Unit 123) 

Fly Ash Silo and Loadout Baghouse 

Silo 7 

(Unit 123) 

Bottom Ash Silo and 

Loadout 

Baghouse 

Pug Mill 

(Unit 4) 

Fly Ash/Scrubber Sludge 

Mixing Operation 

Moisture Content, 

Enclosures and 

Covers 

7.5.3 Applicability Provisions 

a. An “affected process” for the purpose of these unitspecific conditions, is an individual process emission 

unit that handles fly ash as described in Conditions 

7.5.1 and 7.5.2. 

7.5.4 Applicable Emission Standards 

a. The affected processes shall comply with the standard, 

i.e. 30 percent opacity, in Condition 5.2.2(a), which 

addresses visible emissions of fugitive particulate 

matter, as defined by 35 IAC 211.2490, from the 

affected processes, pursuant to 35 IAC 212.301. 

b. The affected processes shall comply with the standard 

in Condition 5.2.2(b), which addresses the opacity of 

the emission of smoke or other particulate matter from 

the affected processes, pursuant to 35 IAC 212.123. 

c. The affected processes shall comply with 35 IAC 

212.321(a), which provides that: 

No person shall cause or allow the emission of 

particulate matter into the atmosphere in any one hour 

period from any new process emission unit which, 
125 

either alone or in combination with the emission of 

particulate matter from all other similar process 

emission units for which construction or modification 

commenced on or after April 14, 1972, at a source or 

premises, exceeds the allowable emission rates 

specified in 35 IAC 212.321(c) [35 IAC 212.321(a)] 

(See also Attachment 1.) 

7.5.5 Non-Applicability of Regulations of Concern 

a. This permit is issued based on the affected processes 

not being subject to the New Source Performance 

Standards (NSPS) for Nonmetallic Mineral Processing 

Plants, 40 CFR Part 60, Subparts A and OOO, because 

the affected processes do not meet the definition of a 

nonmetallic mineral processing plant because there is 

no equipment used to crush or grind ash. 

7.5.6 Work Practices, Operational and Production Limits, and 

Emission Limitations 

a. i. The Permittee shall implement and maintain 

control measures for the affected processes, 

including enclosure and filtration-type dust 

collection devices, that minimize visible 

emissions of particulate matter and provide 

assurance of compliance with the applicable 

emission control requirements in Conditions 

7.5.4, and 7.5.6(b), pursuant to Section 

39.5(7)(a) of the Act. 

ii. The Permittee shall operate and maintain each 

affected process with the control measures 

identified in the records required by 

Condition 7.5.9(b)(i). 

b. i. The ash silos (Silos 6 and 7) associated with 

Boiler 123 shall each be controlled with a 

baghouse (fabric filter) to control PM 

emissions. [T1] 

ii. PM emissions from the ash silos associated 

with Boiler 123 (Silos 6 and 7) shall each not 

exceed 0.645 lb/hr. [T1] 

Note: The above requirements were established in 

Construction Permits 00070030. 

7.5.7 Opacity and Emission Testing Requirements 

a. i. The Permittee shall have the opacity of the 

emissions from the affected processes during 

representative weather and operating conditions 

determined by a qualified observer in accordance 

with USEPA Test Method 9, as further specified 

below, pursuant to Section 39.5(7)(d) of the Act. 
126 

A. For each affected process, testing shall 

be conducted at least annually. For this 

purpose, testing shall first be conducted 

within three months after the effective 

date of this Condition 7.5.7(a). 

B. Upon written request by the Illinois EPA, 

such testing shall be conducted for 

specific affected process(es) within 45 

calendar days of the request or on the 

date agreed upon by the Illinois EPA, 

whichever is later. 

ii. The duration of opacity observations for each 

test shall be at least 30 minutes (five 6-

minute averages) unless the average opacities 

for the first 12 minutes of observations (two 

six-minute averages) are both less than 5.0 

percent. 

iii. A. The Permittee shall notify the Illinois 

EPA at least 7 days in advance of the date 

and time of these tests, in order to allow 

the Illinois EPA to witness testing. This 

notification shall include the name and 

employer of the qualified observer(s). 

B. The Permittee shall promptly notify the 

Illinois EPA of any changes in the time or 

date for testing. 

iv. The Permittee shall provide a copy of its 

observer’s readings to the Illinois EPA at the 

time of testing, if Illinois EPA personnel are 

present. 

v. The Permittee shall submit a written report 

for this testing within 15 days of the date of 

testing. This report shall include: 

A. Date and time of testing. 

B. Name and employer of qualified observer. 

C. Copy of current certification. 

D. Description of observation condition, 

including recent weather. 

E. Description of the operating conditions of 

the affected processes. 

F. Raw data. 

G. Opacity determinations. 

H. Conclusions. 
127 

b. i. Within 90 days of a written request from the 

Illinois EPA, the Permittee shall have the PM 

emissions at the stacks or vents of the 

affected processes, as specified in such 

request, measured during representative 

operating conditions, as set forth below, 

pursuant to Section 39.5(7)(d) of the Act. 

ii. A. Testing shall be conducted using 

appropriate USEPA Reference Test Methods, 

including Method 5 for PM emissions. 

B. Compliance may be determined from the 

average of three valid test runs, subject 

to the limitations and conditions 

contained in 35 IAC Part 283. 

iii. The Permittee shall submit a test plan to the 

Illinois EPA at least 60 days prior to 

testing, which plan shall include the 

information specified by Condition 8.6.2. 

iv. The Illinois EPA shall be notified prior to 

these tests to enable the Illinois EPA to 

observe these tests. Notification of the 

expected date of testing shall be submitted a 

minimum of 30 days prior to the expected date. 

Notification of the actual date and expected 

time of testing shall be submitted a minimum 

of 5 working days prior to the actual date of 

the test. The Illinois EPA may, at its 

discretion, accept notification with shorter 

advance notice provided that the Illinois EPA 

will not accept such notification if it 

interferes with the Illinois EPA’s ability to 

observe the testing. 

v. The Permittee shall expeditiously submit 

complete Final Report(s) for required emission 

testing to the Illinois EPA, no later than 90 

days after the date of testing. These reports 

shall include the information specified in 

Condition 8.6.3 and the following information: 

A. A summary of results. 

B. Detailed description of test method(s), 

including description of sampling points, 

sampling train, analysis equipment, and 

test schedule. 

C. Detailed description of the operating 

conditions of the affected process during 

testing, including operating rate 

(tons/hr) and the control measures being 

used. 
128 

D. Detailed data and calculations, including 

copies of all raw data sheets and records 

of laboratory analyses, sample 

calculations, and data on equipment 

calibration. 

E. Representative opacity data (6-minute 

average) measured during testing. 

7.5.8 Inspection Requirements 

a. The Permittee shall perform inspections of the 

affected processes on at least a weekly basis, 

including associated control measures, while the 

affected processes are in use, to confirm compliance 

with the requirements of Condition 7.5.6(a). These 

inspections shall be performed by personnel who are 

not directly involved in the day-to day operation of 

the affected processes. [Sections 39.5(7)(a) and (d) 

of the Act] 

b. The Permittee shall perform detailed inspections of 

the dust collection equipment for affected processes 

at least every nine months while the processes are out 

of service, with an initial inspection performed 

before any maintenance and repair activities are 

conducted during the period the process is out of 

service and a follow-up inspection performed after any 

such activities are completed. [Sections 39.5(7)(a) 

and (d) of the Act] 

7.5.9 Recordkeeping Requirements 

The Permittee shall maintain records of the following 

items, pursuant to Sections 39.5(7)(a) and (e) of the Act: 

a. The Permittee shall keep the following file(s) and 

log(s): 

i. File(s) containing the following information 

for the affected processes, with supporting 

information, which information shall be kept 

up to date. 

A. Information related to the dust collection 

equipment associated with the affected 

processes, including the performance 

specifications for filter material and 

maximum design particulate matter 

emissions, gr/dscf. 

B. The maximum operating capacity of each 

affected process (ton/hour). 

ii. Maintenance and repair log(s) for the air 

pollution control equipment associated with 

the affected processes, including dust 

suppressant application systems, which log(s) 
129 

shall list the activities performed on each 

item of equipment or system, with date and 

description. (See also Condition 9.6.1, 

Control Equipment Maintenance Records.) 

b. i. The Permittee shall maintain a record, which 

shall be kept up to date, of the control 

measures currently being implemented for the 

affected processes pursuant to Condition 

7.5.6(a). These control measures are referred 

to as the “established control measures” in 

this subsection of this permit. 

ii. Accompanying this record, the Permittee shall 

maintain a demonstration that confirms that 

the above established control measures are 

sufficient to assure compliance with Condition 

7.5.4(c) at the maximum process weight rate at 

which each affected process can be operated 

(tons ash/hour) and with the PM emission 

limitations in Condition 7.5.6(b) (lb /hour 

and ton/yr), with supporting emission 

calculations and documentation for the 

emission factors and the efficiency of the 

control measures being relied upon by the 

Permittee. Except as addressed by Condition 

7.5.9(a)(i) or testing of an affected process 

is conducted in accordance with Condition 

7.5.7(b), this demonstration shall be 

developed using emission factors for 

uncontrolled PM emissions, efficiency of 

control measures, and controlled PM emissions 

published by USEPA. 

iii. Copies of these records shall be submitted to 

the Illinois EPA in accordance with Condition 

5.6.2(d). 

c. The Permittee shall maintain a record of the amount of 

fly ash sent to the fly ash silos, (tons/month and 

tons/year). 

d. The Permittee shall maintain records of the following 

for the inspections required by Condition 7.5.8: 

i. For the inspections required by Condition 

7.5.8(a) for each affected process: 

A. Date and time the inspection was performed 

and name(s) of inspection personnel. 

B. The observed condition of the control 

measures for each affected process, 

including the presence of any emissions or 

accumulations of fly ash in the vicinity 

of the process. 
130 

C. A description of any maintenance or repair 

associated with established control 

measures that is recommended as a result 

of the inspection and a review of 

outstanding recommendations for 

maintenance or repair from previous 

inspection(s), i.e., whether recommended 

action has been taken, is yet to be 

performed or no longer appears to be 

required. 

D. A summary of the observed implementation 

or status of actual control measures, as 

compared to the established control 

measures. 

ii. For the inspections required by Condition 

7.5.8(b) for the dust collection equipment for 

affected processes: 

A. Date and time the inspection was performed 

and name(s) of inspection personnel. 

B. The observed condition of the equipment. 

C. A summary of the maintenance and repair 

that is to be or was conducted on the 

equipment. 

D. A description of any maintenance or repair 

that is recommended as a result of the 

inspection and a review of outstanding 

recommendations for maintenance or repair 

from previous inspection(s), i.e., whether 

recommended action has been taken, is yet 

to be performed or no longer appears to be 

required. 

E. A summary of the observed condition of the 

equipment as related to its ability to 

reliably and effectively control 

emissions. 

e. The Permittee shall maintain records of the following 

for each incident when any affected process operated 

without the established control measures: 

i. The date of the incident and identification of 

the affected process(es) that were involved. 

ii. A description of the incident, including: the 

established control measures that were not 

present or implemented; the established 

control measures that were present, if any; 

other control measures or mitigation measures 

that were implemented, if any; and the 

magnitude of the PM emissions during the 

incident. 
131 

iii. The time at and means by which the incident 

was identified, e.g., scheduled inspection or 

observation by operating personnel. 

iv. The length of time after the incident was 

identified that the affected process(es) 

continued to operate before established 

control measures were in place or the 

operations were shutdown (to resume operation 

only after established control measures were 

in place) and, if this time was more than one 

hour, an explanation why this time was not 

shorter, including a description of any 

mitigation measures that were implemented 

during the incident. 

v. The estimated total duration of the incident, 

i.e., the total length of time that the 

affected process(es) ran without established 

control measures and the estimated amount of 

material handled during the incident. 

vi. A discussion of the probable cause of the 

incident and any preventative measures taken. 

vii. A discussion whether applicable emission 

standards, as listed in Condition 7.5.4, or 

the PM emission limits in Condition 7.5.6(b) 

may have been violated during the incident, 

with an estimate of the amount of any 

additional or excess PM emissions (lbs) and 

supporting explanation. 

f. The Permittee shall keep records for all opacity 

measurements made in accordance with USEPA Method 9 

for the affected processes that it conducts or that 

are conducted on its behest by individuals who are 

qualified to make such observations. For each 

occasion on which such measurements are made, these 

records shall include the formal report for the 

measurements if conducted pursuant to Condition 

7.4.7(a), or otherwise the identity of the observer, a 

description of the measurements that were made, the 

operating condition of the affected process, the 

observed opacity, and copies of the raw data sheets 

for the measurements. 

g. To demonstrate compliance with Condition 7.5.6(b), the 

Permittee shall keep records for PM emissions of the 

ash silos associated with Boiler 123 (Silos 6 and 7) 

(tons/month and tons/year) based on the above records, 

with supporting calculations. 
132 

7.5.10 Reporting Requirements 

a. Reporting of Deviations 

For the affected processes, the Permittee shall 

promptly notify the Illinois EPA of deviations from 

permit requirements as follows. Such notifications 

shall include a description of each incident and a 

discussion of the probable cause of deviation, any 

corrective actions taken and any preventative measures 

taken, pursuant to Section 39.5(7)(f)(ii) of the Act: 

i. The Permittee shall provide the following 

notifications and reports to the Illinois EPA 

concerning incidents when operation continued 

with excess emissions, including continued 

operation of an affected process during 

malfunction or breakdown of equipment. 

A. The Permittee shall immediately notify the 

Illinois EPA’s Regional Office, by 

telephone (voice, facsimile or electronic) 

for each incident in which the opacity 

from an affected process exceeds or may 

have exceeded 30 percent for three or more 

6-minute averaging periods. (Otherwise, 

if opacity during a malfunction or 

breakdown incident only exceeds or may 

have exceeded 30 percent for one or two 6-

minute averaging periods, the Permittee 

need only report the incident in 

accordance with Condition 7.5.10(a)(iii).) 

B. Upon conclusion of each such incident for 

which notification is required, the 

Permittee shall submit a written follow-up 

notice to the Illinois EPA, Compliance 

Section and Regional Office, within 15 

days providing a detailed description of 

the incident and its cause(s), an 

explanation why continued operation was 

necessary, the length of time during which 

operation continued under such conditions, 

the measures taken by the Permittee to 

minimize and correct deficiencies with 

chronology, and when the repairs were 

completed or when the affected operation 

was taken out of service. 

ii. Notification within 30 days for operation of 

an affected process that was not in compliance 

with applicable requirements in Conditions 

7.5.6(a) that continued for more than 12 

operating hours from the time that it was 

identified. Such notifications shall be 

accompanied by a copy of the records for the 

incident required by Condition 7.5.9(e). 
133 

iii. A. Notification with the next deviation report 

required by Condition 7.1.10-1(a)(iv) for other 

deviations not addressed by Conditions 

7.5.10(a)(i) and (ii), including deviations from 

applicable emission standards, inspection 

requirements and recordkeeping requirements. 

B. With the deviation report, the Permittee shall 

also address deviations that occurred during the 

reporting period that have been separately 

reported to the Illinois EPA, with a summary of 

such deviations. For this purpose, the 

Permittee need not resubmit the detailed 

information provided in the initial 

notifications and reports for such deviations. 

7.5.11 Operational Flexibility/Anticipated Operating Scenarios 

The Permittee is authorized to make the following physical 

or operational change with respect to the affected 

processes without prior notification to the Illinois EPA 

or revision of this permit, pursuant to Section 39.5(7)(a) 

and (l) of the Act. This condition does not affect the 

Permittee’s obligation to continue to comply with 

applicable requirements or to properly obtain a 

construction permit in a timely manner for any activity 

constituting a modification as defined by 40 CFR 52.21 or 

35 IAC 203.207, as applicable, or for an activity for 

which a permit is required pursuant to 35 IAC 201.142. 

a. Operation of additional dust suppressant systems. 

b. Operation of additional dust collection equipment. 

c. Operation of replacement dust suppression systems or 

dust collection equipment that is of equal or greater 

effectiveness in controlling PM emissions than the 

device(s) being replaced, as recognized in a 

Construction Permit for such system or equipment. 

7.5.12 Compliance Procedures 

a. Compliance with Conditions 7.5.4 is addressed by the 

control, testing, inspection, and recordkeeping 

required by Conditions 7.5.6(a), 7.5.7, 7.5.8, and 

7.5.9, respectively. 

b. Compliance with Conditions 7.5.6(a) is addressed by 

the testing, inspection, and recordkeeping required by 

Conditions 7.4.7, 7.4.8, and 7.4.9, respectively. 

c. Compliance with Condition 7.5.6(b) is addressed by the 

control, inspection, and recordkeeping required by 

Conditions 7.5.6(a), 7.5.7, 7.5.8, and 7.5.9, respectively. 

Note: This condition is included in this permit pursuant 

to Section 39.5(7)(p)(v) of the Act. 
134 

7.6 Limestone Handling Equipment 

7.6.1 Description 

The Permittee operates limestone handling and storage 

equipment that handles limestone for the coal-fired 

boilers’ SO2 control systems. The original facilities 

were was installed with Boiler 4 and includes a ball mill 

in which limestone is ground to a powder for use in the 

SO2 scrubber for that boiler. Separate limestone handling 

and storage facilities were installed with Boiler 123, to 

handle the limestone that is injected into the bed of this 

fluidized bed boiler for control of SO2 emissions. 

Particulate matter (PM) emissions from these facilities 

are controlled by various control measures including 

moisture content of the limestone, enclosures and covers, 

and dust control equipment. 

7.6.2 List of Emission Units and Air Pollution Control Equipment 

Emission 

Unit Description 

Control 

Equipment 

Limestone 

Handling 

Receiving and 

Conveyors 

Enclosure and Covers 

Limestone 

Storage 

Storage Silos Enclosure and Filter 

System 

Ball Mill Grinding Operation Moisture Content, 

Enclosures and 

Covers 

7.6.3 Applicability Provisions 

a. i. The “affected units” for the purpose of these 

unit-specific conditions are the units 

described in Conditions 7.6.1 and 7.6.2. 

ii. Certain affected units, as follows, for which 

construction or modification commenced after 

August 31, 1983 are also “affected facilities” 

for purposes of the New Source Performance 

Standards (NSPS) for Nonmetallic Mineral 

Processing Plants, 40 CFR 60 Subpart OOO, 

pursuant to 40 CFR 60.670(a) and 60.671. This 

is because this source processes limestone, a 

nonmetallic mineral, in a grinding mill, as 

addressed by Section 7.7 of this permit. 

These “affected facilities” are subject to 

applicable requirements of the NSPS, 40 CFR 60 

Subpart OOO and related requirements in the 

NSPS, 40 CFR 60 Subpart A, General Provisions. 

A. Bucket elevators and belt conveyors. 

B. Storage Bins. 

C. Grinding Mills 
135 

D. Enclosed truck or railcar loading stations. 

7.6.4 Applicable Emission Standards 

a. The affected units shall comply with the standard in 

Condition 5.2.2(a), which addresses visible emissions 

of fugitive particulate matter, as defined by 35 IAC 

211.2490, from the affected units, pursuant to 35 IAC 

212.301. 

b. The affected units shall comply with the standard, 

i.e., 30 percent opacity, in Condition 5.2.2(b), which 

addresses the opacity of the emission of smoke or 

other particulate matter from the units, pursuant to 

35 IAC 212.123. 

c. The affected units are subject to 35 IAC 212.321(a), 

which provides that no person shall cause or allow the 

emission of particulate matter into the atmosphere in 

any one hour period from any new emission unit, either 

alone or in combination with the emission of 

particulate matter from all other similar process 

emission units for which construction or modification 

commenced on or after April 14, 1972, at a source or 

premises, exceeds the allowable emission rates 

specified in 35 IAC 212.321(c). (See also Attachment 

1.) [35 IAC 212.321(a)] 

d. The affected units that are subject to the NSPS, 40 

CFR 60 Subpart OOO, shall comply with the following 

standards pursuant to 40 CFR 60.672, except during 

periods of startup, shutdown and malfunction, as 

defined in 40 CFR 60.2, pursuant to 40 CFR 60.11(c) 

and 60.672. 

i. Fugitive emissions, i.e., emissions that are 

not collected by a control system and are 

released at the point of generation, from 

transfer point on belt conveyors and from 

other affected facilities shall not exceed 10 

percent opacity, pursuant to 40 CFR 60.672(b). 

ii. Stack emissions, i.e., emissions discharged 

through a control device, from transfer point 

on belt conveyors and from other affected 

facilities shall comply with the following 

limits, pursuant to 40 CR 60.672(a)(1) and (2): 

A. Particulate matter emissions shall not 

exceed 0.05 g/dscm. 

B. Opacity shall not exceed 7 percent, unless 

emission are discharged using a wet 

scrubbing control device. 

iii. If a transfer point on a belt conveyor or 

other affected facility is enclosed in a 

building, then the enclosed affected facility 
136 

must comply with the applicable limits above 

or there shall be no visible emissions from 

the building except from vents or stacks, 

which shall comply with the applicable limits 

for stack emissions, pursuant to 40 CFR 

60.672(e). 

Note: These standards do not apply to truck dumping 

of limestone into an affected unit, pursuant to 40 CFR 

60.672(c). 

7.6.5 Non-Applicability of Regulations of Concern 

None 

7.6.6 Work Practices, Operational and Production Limits, and 

Emission Limitations 

a. i. The Permittee shall implement and maintain 

control measures for the affected units, such 

as enclosure, natural surface moisture, water 

spray, application of dust suppressant and 

dust collection devices, that minimize visible 

emissions of particulate matter and provide 

assurance of compliance with the applicable 

emission control requirements in Conditions 

7.6.4 and 7.6.6(b), pursuant to Section 

39.5(7)(a) of the Act. 

ii. The Permittee shall operate and maintain each 

affected units with the control measures 

identified in the records required by 

Condition 7.6.9(b)(i). 

b. i. A. The PM emissions from Silo 5 (the 

limestone silo associated with Boiler 123) 

shall be controlled with a baghouse 

(fabric filter). [T1] 

B. Good air pollution control practices shall 

be employed to minimize the emissions of 

PM from limestone storage piles. [T1] 

ii. PM emissions from the limestone Silo 5 shall 

not exceed 0.137 lb/hr. [T1] 

Note: The above requirements were established in 

Construction Permit 00070030. 

7.6.7 Opacity and Emission Testing Requirements 

a. i. The Permittee shall have the opacity of the 

emissions from the affected units during 

representative weather and operating conditions 

determined by a qualified observer in accordance 

with USEPA Test Method 9, as further specified 

below, pursuant to Section 39.5(7)(d) of the Act. 
137 

A. For each affected unit, testing shall be 

conducted at least annually. For this 

purpose, testing shall first be conducted 

within three months after the effective 

date of this Condition 7.6.7(a). 

B. Upon written request by the Illinois EPA, 

such testing shall be conducted for 

specific affected units within 45 calendar 

days of the request or on the date agreed 

upon by the Illinois EPA, whichever is 

later. 

ii. The duration of opacity observations for each 

test shall be at least 30 minutes (five 6-

minute averages) unless the average opacities 

for the first 12 minutes of observations (two 

six-minute averages) are both less than 10.0 

percent. 

iii. A. The Permittee shall notify the Illinois 

EPA at least 7 days in advance of the date 

and time of these tests, in order to allow 

the Illinois EPA to witness testing. This 

notification shall include the name and 

employer of the qualified observer(s). 

B. The Permittee shall promptly notify the 

Illinois EPA of any changes in the time or 

date for testing. 

iv. The Permittee shall provide a copy of its 

observer’s readings to the Illinois EPA at the 

time of testing, if Illinois EPA personnel are 

present. 

v. The Permittee shall submit a written report 

for this testing within 15 days of the date of 

testing. This report shall include: 

A. Date and time of testing. 

B. Name and employer of qualified observer. 

C. Copy of current certification. 

D. Description of observation condition, 

including recent weather. 

E. Description of the operating conditions of 

the affected units. 

F. Raw data. 

G. Opacity determinations. 

H. Conclusions. 
138 

b. i. Within 90 days of a written request from the 

Illinois EPA, the Permittee shall have the PM 

emissions at the stacks or vents of the 

affected units, as specified in such request, 

measured during representative operating 

conditions, as set forth below, pursuant to 

Section 39.5(7)(d) of the Act. 

ii. A. Testing shall be conducted using 

appropriate USEPA Reference Test Methods, 

including Method 5 for PM emissions. 

B. Compliance may be determined from the average 

of three valid test runs, subject to the 

limitations and conditions contained in 35 

IAC Part 283. 

iii. The Permittee shall submit a test plan to the 

Illinois EPA at least 60 days prior to 

testing, which plan shall include the 

information specified by Condition 8.6.2. 

iv. The Illinois EPA shall be notified prior to 

these tests to enable the Illinois EPA to 

observe these tests. Notification of the 

expected date of testing shall be submitted a 

minimum of 30 days prior to the expected date. 

Notification of the actual date and expected 

time of testing shall be submitted a minimum 

of 5 working days prior to the actual date of 

the test. The Illinois EPA may, at its 

discretion, accept notification with shorter 

advance notice provided that the Illinois EPA 

will not accept such notification if it 

interferes with the Illinois EPA’s ability to 

observe the testing. 

v. The Permittee shall expeditiously submit a 

complete Test Report to the Illinois EPA, no 

later than 90 days after the date of testing. 

This report shall include the information 

specified in Condition 8.6.3 and the following 

information: 

A. A summary of results. 

B. Detailed description of test method(s), 

including description of sampling points, 

sampling train, analysis equipment, and 

test schedule. 

C. Detailed description of the operation of 

the affected operations during testing, 

including operating rate (tons/hr) and the 

control measures being used. 
139 

D. Detailed data and calculations, including 

copies of all raw data sheets and records 

of laboratory analyses, sample 

calculations, and data on equipment 

calibration 

E. Representative opacity data (6-minute 

averages) measured during testing. 

7.6.8 Inspection Requirements 

a. The Permittee shall perform inspections of affected 

units on at least a bi-weekly basis, including 

associated control measures, while the affected units 

are in use, to confirm compliance with the 

requirements of Condition 7.6.6(a). These inspections 

shall be performed by personnel who are not directly 

involved in the day-to-day operation of the affected 

units and may be scheduled so that only a number of 

affected units are reviewed during each inspection, 

provided however, that all affected units that are in 

routine service shall be inspected at least once 

during each two-week period. [Sections 39.5(7)(a) and 

(d) of the Act] 

b. The Permittee shall perform detailed inspections of 

the dust collection equipment for affected units at 

least every 15 months while the units are out of 

service, with an initial inspection performed before 

any maintenance and repair activities are conducted 

during the period the unit is out of service and a 

follow-up inspection performed after any such 

activities are completed. [Sections 39.5(7)(a) and 

(d) of the Act] 

7.6.9 Recordkeeping Requirements 

The Permittee shall maintain the following records for the 

affected units, pursuant to Sections 39.5(7)(a) and (e) of 

the Act: 

a. The Permittee shall keep the following file(s) and 

log(s): 

i. File(s) containing the following information 

for the affected units, with supporting 

information, which information shall be kept 

up to date. 

A. Information related to the dust collection 

equipment associated with the affected 

units, including the design control 

efficiency or performance specifications 

for filter material and maximum design 

particulate matter emissions, gr/dscf. 

B. The maximum operating capacity of each 

affected unit (ton/hour). 
140 

C. The aggregate capacity of the grinding 

equipment (ball mills). 

D. A list identifying any affected unit that 

the Permittee does not consider to be an 

“affected facility” for purposes of the 

NSPS, with copies of supporting 

documentation for the date on which 

construction of the unit was commenced and 

its original design capacity. 

ii. Maintenance and repair log(s) for the air 

pollution control equipment associated with 

the affected units, including dust suppressant 

application systems, that, at a minimum, shall 

list the activities performed on each item of 

equipment or facility, with date and 

description. (See also Condition 9.6.1, 

Control Equipment Maintenance Records.) 

b. i. The Permittee shall maintain a record, which 

shall be kept up to date, of the control 

measures currently being implemented for the 

affected units pursuant to Condition 7.6.6(a). 

 These control measures, as defined by the 

Permittee through these records, are referred 

to as the “established control measures” in 

this section of this permit. 

ii. Accompanying this record, the Permittee shall 

maintain a demonstration that confirms that 

the above established control measures are 

sufficient to assure compliance with Condition 

7.6.4(c) at the maximum process weight rate at 

which each affected unit can be operated 

(tons/hour), and with the applicable PM 

emission limitation in Condition 7.6.6(b), 

with supporting emission calculations and 

documentation for the emission factors and the 

efficiency of the control measures being 

relied upon by the Permittee. Except as 

addressed by Condition 7.6.9(a)(i) or testing 

of an affected unit is conducted in accordance 

with Condition 7.6.7(b), this demonstration 

shall developed using emission factors for 

uncontrolled PM emissions, efficiency of 

control measures, and controlled PM emissions 

published by USEPA. 

iii. Copies of these records shall be submitted to 

the Illinois EPA in accordance with Condition 

5.6.2(d). 

c. The Permittee shall maintain a record of the amount of 

limestone received by the source (tons/month and 

tons/year). 
141 

d. The Permittee shall maintain records of the following 

for the inspections required by Condition 7.6.8: 

i. For the inspections required by Condition 

7.6.8(a) for each affected unit: 

A. Date and time the inspection was performed 

and name(s) of inspection personnel. 

B. The observed condition of the control 

measures for the affected unit, including 

the presence of any visible emissions. 

C. A description of any maintenance or repair 

associated with established control 

measures that is recommended as a result 

of the inspection and a review of 

outstanding recommendations for 

maintenance or repair from previous 

inspection(s), i.e., whether recommended 

action has been taken, is yet to be 

performed or no longer appears to be 

required. 

D. A summary of the observed implementation 

of status of actual control measures, as 

compared to the established control 

measures. 

ii. For the inspections required by Condition 

7.6.8(b) for the dust collection equipment for 

the affected units: 

A. Date and time the inspection was performed 

and name(s) of inspection personnel. 

B. The observed condition of the equipment. 

C. A summary of the maintenance and repair 

that is to be or was conducted on the 

equipment. 

D. A description of any maintenance or repair 

that is recommended as a result of the 

inspection and a review of outstanding 

recommendations for maintenance or repair 

from previous inspection(s), i.e., whether 

recommended action has been taken, is yet 

to be performed or no longer appears to be 

required. 

E. A summary of the observed condition of the 

equipment as related to its ability to 

reliably and effectively control emissions. 

e. The Permittee shall maintain records of the following 

for each incident when any affected unit operated 

without the established control measures:. 
142 

i. The date of the incident and identification of 

the affected unit(s) that were involved. 

ii. A description of the incident, including the 

established control measures that were not 

present or implemented; the established 

control measures that were present, if any; 

other control measures or mitigation measures 

that were implemented, if any; and the 

magnitude of the PM emissions during the 

incident. 

iii. The time at and means by which the incident 

was identified, e.g., scheduled inspection or 

observation by operating personnel. 

iv. The length of time after the incident was 

identified that the affected unit(s) continued 

to operate before established control measures 

were in place or the units were shutdown (to 

resume operation only after established 

control measures were in place) and, if this 

time was more than one hour, an explanation 

why this time was not shorter, including a 

description of any mitigation measures that 

were implemented during the incident. 

v. The estimated total duration of the incident, 

i.e., the total length of time that the 

affected unit(s) ran without established 

control measures and the estimated amount of 

limestone handled during the incident. 

vi. A discussion of the probable cause of the 

incident and any preventative measures taken. 

vii. A discussion whether applicable emission 

standards, as listed in Condition 7.6.4, or 

the PM emission limits in Condition 7.6.6(b) 

may have been violated during the incident, 

with an estimate of the amount of any 

additional or excess PM emissions (lbs) from 

the incident, with supporting explanation. 

f. The Permittee shall keep records for all opacity 

measurements made in accordance with USEPA Method 9 

for the affected unit that it conducts or that are 

conducted on its behest by individuals who are 

qualified to make such observations. For each 

occasion on which such measurements are made, these 

records shall include the formal report for the 

measurements if conducted pursuant to Condition 7.6.7, 

or otherwise the identity of the observer, a 

description of the measurements that were made, the 

operating condition of the affected unit, the observed 

opacity, and copies of the raw data sheets for the 

measurements. 
143 

g. To demonstrate compliance with Condition 7.6.6(b), the 

Permittee shall keep records for PM emissions of Silo 

5 (tons/month and tons/year) based on the above 

records, with supporting calculations. 

7.6.10 Reporting Requirements 

a. Reporting of Deviations 

For the affected units, the Permittee shall promptly 

notify the Illinois EPA of deviations from permit 

requirements as follows. Such notifications shall 

include a description of each deviation and a 

discussion of the probable cause of such deviation, 

any corrective actions taken and any preventative 

measures taken, pursuant to Section 39.5(7)(f)(ii) of 

the Act: 

i. The Permittee shall provide the following 

notifications and reports to the Illinois EPA 

concerning incidents when operation of an 

affected unit continued with excess emissions, 

including continued operation during 

malfunction or breakdown of equipment. 

A. The Permittee shall immediately notify the 

Illinois EPA’s Regional Office, by 

telephone (voice, facsimile or electronic) 

for each incident in which the opacity 

from an affected unit exceeds or may have 

exceeded the applicable opacity standard 

for three or more 6-minute averaging 

periods. (Otherwise, if opacity during a 

malfunction or breakdown incident only 

exceeds or may have exceeded the 

applicable standard for no more than one 

or two 6-minute averaging periods, the 

Permittee need only report the incident in 

accordance with Condition 7.6.10(a)(iii).) 

B. Upon conclusion of each such incident for 

which notification is required, the 

Permittee shall submit a written follow-up 

notice to the Illinois EPA, Compliance 

Section and Regional Office, within 15 

days providing a detailed description of 

the incident and its cause(s), an 

explanation why continued operation of the 

affected unit was necessary, the length of 

time during which operation continued 

under such conditions, the measures taken 

by the Permittee to minimize and correct 

deficiencies with chronology, and when the 

repairs were completed or when the 

affected unit was taken out of service. 
144 

ii. Notification within 30 days for operation of 

an affected unit that did not fulfill the 

applicable requirements in Conditions 7.6.6(a) 

that continued for more than 12 operating 

hours from the time that it was identified. 

Such notifications shall be accompanied by a 

copy of the records for the incident required 

by Condition 7.6.9(e). 

iii. A. Notification with the quarterly reports 

required for Coal-fired Boiler 123 by 

Condition 7.1.10-2(a) for other deviations 

not addressed by Conditions 7.6.10(a)(i) 

and (ii), including deviations from the 

applicable PM emission standard, 

inspection requirements, and recordkeeping 

requirements. 

B. With these reports, the Permittee shall 

also address deviations that occurred 

during the quarter that have been 

separately reported to the Illinois EPA, 

with a summary of such deviations. For 

this purpose, the Permittee need not 

resubmit the detailed information provided 

in the initial notifications and reports 

for such deviations. 

7.6.11 Operational Flexibility/Anticipated Operating Scenarios 

The Permittee is authorized to make the following physical 

or operational change with respect to the affected units 

without prior notification to the Illinois EPA or revision 

of this permit, pursuant to Section 39.5(7)(a) and (l) of 

the Act. This condition does not affect the Permittee’s 

obligation to continue to comply with applicable 

requirements or to properly obtain a construction permit 

in a timely manner for any activity constituting a 

modification as defined by 40 CFR 52.21 or 35 IAC 203.207, 

as applicable, or for an activity for which a permit is 

required pursuant to 35 IAC 201.142. 

a. Operation of additional dust suppressant systems. 

b. Operation of additional dust collection equipment. 

c. Operation of replacement dust suppression systems or 

dust collection equipment that is of equal or greater 

effectiveness in controlling PM emissions than the 

device(s) being replaced. 

7.6.12 Compliance Procedures 

a. Compliance with Condition 7.6.4 is addressed by the 

control, testing, inspection, and recordkeeping 

required by Conditions 7.6.6(a), 7.6.7, 7.6.8, and 

7.6.9, respectively. 
145 

b. Compliance with Condition 7.6.6(a) is addressed by the 

inspection, and recordkeeping required by Conditions 

7.6.7, 7.6.8, and 7.6.9, respectively. 

c. Compliance with Condition 7.6.6(b) is addressed by the 

control, inspection, and recordkeeping required by 

Conditions 7.6.6(a), 7.6.8, and 7.6.9, respectively. 

Note: This condition is included in this permit pursuant 

to Section 39.5(7)(p)(v) of the Act. 
146 

7.7 Combustion Turbines 

7.7.1 Description 

The combustion turbines are process emission units used to 

provide electricity to meet peak power demands. The 

turbines are fired with natural gas, with distillate fuel 

oil as a backup fuel. The turbines were install pursuant 

to Construction Permit/PSD Approval 00070029. 

7.7.2 List of Emission Units and Air Pollution Control Equipment 

Emission

Unit Description 

Control 

 Measures 

Turbine 

Unit 5 

Natural Gas Fired 

Combustion Turbine Nominal 

969 mmBtu/hr 

Turbine 

Unit 6 

Natural Gas Fired 

Combustion Turbine Nominal 

969 mmBtu/hr 

Low NOx 

Combustion System 

When Gas Fired, 

Water Injection 

for Firing Backup 

Oil 

7.7.3 Applicability Provisions 

a. i. An “affected turbine” for the purpose of 

these unit-specific conditions is a turbine 

described in Conditions 7.7.1 and 7.7.2. 

ii. The affected turbines are also affected 

facilities under the federal NSPS for 

Stationary Gas Turbines, 40 CFR 60 Subpart GG, 

because the construction of the affected 

turbines commenced after October 3, 1977 and 

the affected turbines have a heat input 

capacity greater than 10.7 gigajoules/hour 

(approximately 10 mmBtu/hr). As the turbines 

are also affected facilities subject toe the 

NSPS, the Permittee must comply with 

applicable requirements of the NSPS, 40 CFR 60 

Subpart GG, and related requirements of 40 CFR 

60, Subpart A, General Provisions, for the 

affected turbines. 

7.7.4 Applicable Emission Standards 

a. i. The affected turbines are subject to the NSPS 

for Stationary Gas Turbines, 40 CFR 60 Subpart 

GG. 

ii. Each affected turbine is subject to 40 CFR 

60.332(a)(1) and (b), which provide that, no 

owner or operator of an affected turbine shall 

cause to be discharged into the atmosphere 

from such gas turbine, any gases which contain 

nitrogen oxides (NOx) in excess of: 

STD = 0.0075 (14.4) + F 

 Y 

Where: 
147 

STD = Allowable NOx emissions (percent by 

volume at 15 percent oxygen and on a 

dry basis). 

Y = Manufacturer's rated heat rate at 

manufacturer's rated load (kilojoules 

per watt hour) or, actual measured 

heat rate based on lower heating 

value of fuel as measured at actual 

peak load for the turbine. The value 

of Y shall not exceed 14.4 kilojoules 

per watt hour. 

F = An allowance for fuel-bound 

nitrogen, which may be applicable 

for firing of oil, that is 

calculated from the nitrogen content 

of the fuel as follows: 

Fuel-bound nitrogen 

(Percent by Weight) 

F 

(NOx percent by volume)

N < 0.015 0

0.015 < N < 0.1 0.04 (N)

0.1 < N < 0.25 0.04 + 0.0067(N - 0.1)

N > 0.25 0.005

Where: 

N = The nitrogen content of the fuel 

(percent by weight) determined in 

accordance with Condition 7.1.8. 

iii. Each affected turbine is subject to 40 CFR 

60.333, which provides that for a turbine 

subject to the NSPS either: 

A. The owner or operator of the turbine shall 

not cause to be discharged into the 

atmosphere from the turbine any gases that 

contain sulfur dioxide (SO2) in excess of 

0.015 percent by volume at 15 percent 

oxygen and on a dry basis [40 CFR 

60.333(a)], or. 

B. The owner or operator of the turbine shall 

not burn in the turbine any fuel that 

contains sulfur in excess of 0.8 percent 

by weight [40 CFR 60.333(b)]. 

b. The affected turbines shall comply with the standard 

in Condition 5.2.2(b), i.e. 30 percent opacity, 

pursuant to 35 IAC 212.123. 

c. Each affected turbine shall comply with 35 IAC 

214.301, which provides that no person shall cause or 

allow the emission of sulfur dioxide into the 

atmosphere from any process emission source to excess 

2,000 ppm. 
148 

d. During each ozone control period (May 1 through 

September 30) of each year. The emissions of NOx from 

each affected turbine shall not exceed 0.25 lb/mmBtu 

of actual heat input based on a ozone control period 

average for that unit, pursuant to 35 IAC 217.706(a). 

Note: Given the applicable emission determination 

method (See Condition 7.7.8), the calculated NOx 

emissions of the turbines for purposes of this 

standard may be different than the emissions 

determined for other purposes, e.g., Annual Emission 

Reports. 

7.7.5 Non-Applicability of Regulations of Concern 

a. This permit is issued based on the affected turbines 

not being subject to the requirements of 35 IAC 

212.321 because, due to the nature of such unit, a 

process weight rate can not be set so that such rules 

can not reasonably be applied, pursuant to 35 IAC 

212.323. 

b. The affected turbines are not subject to 35 IAC 

216.121 or 217.141 because the affected turbines are 

not fuel combustion units, as defined by 35 IAC 

211.2470. 

c. i. This permit is issued based on the affected 

turbines being gas and oil-fired peaking 

units, as specified in 40 CFR Part 75, so that 

continuous emission monitoring is not required 

for NOx. To maintain this status for an 

affected turbine, the three year rolling 

average annual capacity factor of the turbine 

shall not be greater than 10 percent, and the 

highest annual capacity factor shall not be 

greater than 20 percent in any one of the 

three averaging years. 

ii. Should the operation of an affected turbine 

exceed the above requirements relating to the 

definition of a peaking unit in 40 CFR Part 

75, the Permittee shall install the 

appropriate Continuous Emissions Monitoring 

System(s) on the turbine by December 31 of the 

following calendar year, as defined in 40 CFR 

75, in order to remain in compliance with the 

provisions of the Acid Rain Program. 

d. This permit is issued based on the affected turbines 

not being subject to the control requirements of 40 

CFR 63, Subpart YYYY, the NESHAP for Stationary 

Combustion Turbines. This is because the turbines 

were constructed prior January 15, 2003 so that they 

are considered existing sources for purposes of this 

NESHAP. [40 CFR 63.6090(b)(4)] 
149 

7.7.6 Work Practices, Operational and Production Limits, and 

Emission Limitations 

a. At all times, including periods of startup, shutdown, 

and malfunction, the Permittee shall, to the extent 

practicable, maintain and operate any affected turbine 

in a manner consistent with good air pollution control 

practice for minimizing emissions. Determination of 

whether acceptable operating and maintenance 

procedures are being used will be based on information 

available to the Illinois EPA or the USEPA which may 

include, but is not limited to, monitoring results, 

opacity observations, review of operating and 

maintenance procedures, and inspection of the source. 

[40 CFR 60.11(d)] 

b. i. Each affected turbine shall be equipped, 

operated and maintained with dry low-NOx 

combustors and water injection for controlling 

NOx emissions during natural gas firing and 

oil firing, respectively. [T1] 

ii. The affected turbines shall utilize good 

combustion practices to reduce emissions of 

volatile organic material (VOM) and CO, which 

practices shall include routine maintenance 

and repair practices and other periodic 

assessments of the combustion performance of 

the affected turbines to reasonably minimize 

emissions. [T1] 

c. i. The fuels fired in the affected turbines shall 

be only natural gas and distillate oil, as 

defined in 40 CFR 60.41c. [T1] 

ii. The annual usage of fuel by the affected 

turbines shall not exceed 3,747 million 

standard cubic feet per year based on 901 

Btu/scf LHV. Compliance with this limit shall 

be determined based on a running total of 12 

months of data and considering one gallon of 

oil equivalent to 420 standard cubic feet, 

based on equivalent NOx emissions. [T1] 

iv. The sulfur content of the distillate oil shall 

be limited to a maximum of 0.05 percent by 

weight. [T1] 

v. Distillate oil shall only be fired as a backup 

fuel, that is: [T1] 

A. For purposes of shakedown, evaluation of 

operation and emission testing of emission 

units; and 

B. At other times when and to the extent that 

circumstances such as natural gas supply 

curtailment or breakdown of natural gas 
150 

delivery systems make it infeasible or 

impractical for the Permittee to fire 

natural gas in one or both of the affected 

turbines. However, this requirement does 

not require that the affected turbines, 

once operating on oil, be shutdown if 

natural gas becomes available for the unit 

during a day if the unit would then be 

restarted with natural gas on that same 

day. 

d. Each affected turbine shall be operated in a manner 

consistent with good air pollution control practices 

to minimize emissions during startup and shutdown, 

including: [T1] 

i. The Permittee shall manage the operation of 

the affected turbines to minimize multiple 

startups of the affected turbines in a single 

day, unless a the affected turbines are 

tripped off, and to provide adequate time to 

follow the procedures for normal startup of 

the affected turbines, except for requests for 

immediate delivery of power as would result 

from unexpected loss of a transmission line or 

other generating capacity. 

ii. Operation in accordance with the 

manufacturer's written instructions or other 

written instructions developed and maintained 

by the Permittee that shall include at a 

minimum the following measures: 

A. Review of operating parameters of the 

affected turbines during startup or 

shutdown as necessary to make adjustments 

to reduce or eliminate excess emissions. 

B. Implementation of inspection and repair 

procedures for the affected turbines prior to 

attempting startup following repeated trips. 

iii. The Permittee shall maintain each affected 

turbine in accordance with the manufacturer's 

written instructions or other written procedures 

developed and maintained by Permittee. 

iv. These written procedures shall be reviewed at 

least annually and enhanced consistent with 

good air pollution control practice based on 

actual operating experience and performance of 

the affected turbines. 

e. i. Emissions of carbon monoxide (CO) from each 

affected turbine shall not exceed 25 ppm by 

volume at 15 percent oxygen, except during 

startup, shutdown, or malfunction, as 

addressed by Condition 7.7.6(f). [T1] 
151 

ii. A. Emissions from the affected turbines shall 

not exceed the following limits: [T1] 

Natural Gas Firing 

(Per Unit) 

Oil Firing 

(Per Unit) 

Pollutant Concentration 

(ppmvd) 

Hourly 

(Lb/Hr) 

Concentration

(ppmvd) 

Hourly

(Lb/Hr)

Annual 

Total for 

Both Units)

(T/Yr) 

NOx 15 @ 15% O2 67.0 42 @ 15% O2 204.8 119 

CO 25 @ Actual O2 65.5 20 @ Actual O2 51.9 106 

VOM 1.4 @ Actual O2 2.2 3.5 @ Actual O2 5.6 4 

SO2 ---- 4.0 ---- 60.8 11 

PM/PM10* ---- 5.0 ---- 10.0 10 

* PM and PM10 limits only address front 

half (filterable) particulates. 

Notes: Compliance with concentration 

(ppmvd) and hourly (lb/hr) limits shall be 

determined on a 3-hour block average, 

consistent with applicable procedures for 

testing. These limits do not apply during 

startup, malfunction, or shutdown, which 

are addressed by Condition 7.7.6(f). 

Compliance with the annual limits shall be 

determined from a running total of 12 

months of data and shall include emissions 

during startup, malfunction, or shutdown. 

B. For purposes of determining compliance 

with the above limitations: 

I. Unless emission monitoring is 

performed for a pollutant, emissions 

during periods other than startup 

shall be determined from emission 

factors developed from testing of 

the turbines (NOx, CO, VOM and 

PM/PM10) and standard factors (SO2). 

II. Unless an alternative factor is 

established for the pollutant or emission 

monitoring is performed for the pollutant, 

emissions of NOx, CO and VOM during an 

hour that includes a startup shall be 

following emission rates. Any alternative 

factor for emissions during startup of 

affected turbines shall be based on 

representative emission testing conducted 

with USEPA Reference Test Methods. 

 Natural Gas Firing Distillate Oil Firing 

Pollutant (Lb/Hr) (Lb/Hr) 

 

NOx 60.0 170.0 

CO 76.0 67.0 

VOM 2.0 6.0 

f. Each affected turbine shall be operated in a manner 

consistent with good air pollution control practice to 

minimize emissions during startup, malfunction, and 
152 

shutdown, including: [T1] 

i. Upon malfunction of an affected turbine that 

will result in emissions in excess of the 

applicable limits in Condition 7.7.6(e), the 

Permittee shall, as soon as practicable, 

repair the affected turbine or remove the 

affected turbine from service so that excess 

emissions cease. 

ii. Consistent with the above, if the Permittee 

has maintained and operated the affected 

turbines including the water injection system 

so that malfunctions are infrequent, sudden, 

not caused by poor maintenance or careless 

operation, and in general are not reasonably 

preventable, the Permittee shall begin 

shutdown of the malfunctioning affected 

turbine within 90 minutes, unless the 

malfunction is expected to be repaired within 

120 minutes or such shutdown could threaten 

the stability of the regional electrical power 

system. In such case, shutdown of the 

affected turbine shall be undertaken when it 

is apparent that repair will not be 

accomplished within 120 minutes or shutdown 

will not endanger the regional power system. 

In no case shall shutdown of the gas be 

delayed solely for the economic benefit of the 

Permittee. 

iii. Notwithstanding the above, if the Permittee 

determines that the continuous emission 

monitoring system (CEMS), if required, is 

inaccurately reporting excess emissions, the 

Permittee may continue operation provided the 

Permittee records the information it is 

relying upon to conclude that the affected 

turbine is functioning properly and the CEMS 

is reporting inaccurate data, and the 

Permittee takes prompt action to resolve the 

accuracy of the CEMS. 

Note: The above requirements of Conditions 7.7.6(b) 

through (f) were originally established in Construction 

Permit 00070029. Conditions 7.7.6(d), (e)(i) [CO limit in 

ppm], and (f), as applicable to emissions of CO, represent 

the application of Best Available Control Technology for 

CO, as required by PSD. The requirements for pollutants 

other than CO were intended to ensure that the 

construction and operation of the affected turbines do not 

constitute a major modification pursuant to the federal 

PSD rules. 

g. i. If an affected turbine is routinely operated 

or exercised to confirm that the turbine will 

operate when needed, the operation and opacity 

of the turbine shall be formally observed by 
153 

operating personnel for the turbine or a 

member of Permittee’s environmental staff on a 

regular basis to assure that the turbine is 

operating properly, which observations shall 

be made at least every six months. 

ii. If an affected turbine is not routinely 

operated or exercised, i.e., the time interval 

between operation of an affected turbine is 

typically greater than six months, the 

operation and opacity of the affected turbine 

shall be formally observed as provided above 

each time the Permittee carries out a 

scheduled exercise of the affected turbine. 

iii. The Permittee shall also conduct formal 

observations of operation and opacity of an 

affected turbine upon written request by the 

Illinois EPA. With the agreement of the 

Illinois EPA, the Permittee may schedule these 

observations to take place during periods when 

it would otherwise be operating the affected 

turbine. 

7.7.7-1 Opacity and Emissions Testing Requirements 

a. The Permittee shall have the opacity of the exhaust from the 

affected turbines during representative operating conditions 

determined by a qualified observer in accordance with USEPA 

Test Method 9, as further specified below, pursuant to 

Section 39.5(7)(b) of the Act. 

i. A. For each affected turbine, once for every 

500 hours of operation. For this purpose, 

testing shall first be conducted within 

the initial 50 hours of operation of the 

turbine pursuant to this permit. 

B. Upon written request by the Illinois EPA, 

Such testing shall be conducted for 

specific turbine(s) within 45 calendar 

days of the request, or on the date 

turbine(s) next operates, or on the date 

agreed upon by the Illinois EPA, whichever 

is later. 

ii. The duration of opacity observations for each test 

shall be at least 30 minutes (five 6-minute 

averages) unless the average opacities for the first 

12 minutes of observations (two six-minute averages) 

are both less than 10.0 percent. 

iii. A. The Permittee shall notify the Illinois EPA at 

least 7 days in advance of the date and time of 

these tests, in order to allow the Illinois EPA 

to witness testing. This notification shall 

include the name and employer of the qualified 

observer(s). 
154 

B. The Permittee shall promptly notify the 

Illinois EPA of any changes in the time or 

date for testing. 

C. The Permittee shall provide a copy of its 

observer’s readings to the Illinois EPA at 

the time of testing, if Illinois EPA 

personnel are present. 

iv. The Permittee shall submit a written report for this 

testing within 15 days of the date of testing. This 

report shall include: 

A. Date and time of testing. 

B. Name and employer of qualified observer. 

C. Copy of current certification. 

D. Description of observation conditions. 

E. Description of turbine operating 

conditions. 

F. Raw data. 

G. Opacity determinations. 

H. Conclusions. 

7.7.7-2 Fuel Oil Sampling and Analysis 

a. i. The Permittee shall have the sulfur content of 

the oil supply to the affected turbines, in 

lb/mmBtu, determined from an analysis of 

representative sample of the oil supply, as 

follows, pursuant to Section 39.5(7)(d): 

A. From a sample taken no later than 90 days 

after first operating the affected 

turbines pursuant to this permit, 

provided, however, that if such sample is 

taken following operation of the affected 

turbines, the sample shall be taken prior 

to adding more oil to the storage tank. 

B. From a sample taken no later than 30 days 

after acceptance of a shipment of fuel 

whose sulfur content would not meet 

Condition 7.7.4(c) based upon supplier 

data, provided however, that if the 

affected turbines are operated following 

acceptance of such a shipment, the sample 

shall be taken prior to adding a 

subsequent shipment of oil to the relevant 

storage tank. 
155 

C. From a sample taken no later than 30 days 

after a request for such a sample is made 

by the Illinois EPA, provided, however, 

that such sample shall be taken prior to 

adding more oil to the relevant storage 

tank. 

Sampling and analysis, including that which forms the 

basis for the suppliers’ data, shall be conducted 

using methods that would be acceptable under the 

federal New Source Performance Standards for 

Stationary Gas Turbines, 40 CFR 60.335(b)(2) and (c) 

or the federal Acid Rain Program, 40 CFR 75, 

Appendix D, Optional SO2 Emissions Data Protocol for 

Gas-Fired and Oil-Fired Units e.g., ASTM D4057-88 and 

ASTM D129-91. 

b. The Permittee shall have the NOx, CO, VOM and PM/PM10 

emissions of the affected turbines during 

representative operating conditions measured, as 

further specified below, pursuant to Section 

39.5(7)(d) of the Act. 

i. Measurements shall be conducted within 90 days 

of a written request from the Illinois EPA. 

ii. A. Testing for NOx shall be conducted using the 

applicable methods specified by 40 CFR 60.335 

unless alternative test procedures are 

approved by USEPA pursuant to 40 CFR 60.8. 

B. Testing for CO, VOM and PM/PM10 shall be 

conducted using appropriate USEPA Reference 

Test Methods, including Methods 5 and 202, 

10, and 25A and/or 18 for PM/PM10, CO and 

VOM emissions, respectively. 

C. For purposes of determining emissions of NOx 

for purposes of comparison to the limit in 

Condition 7.7.4(a)(ii), emissions shall be 

determined as the average of three separate 

test runs as provided by 40 CFR 60.8(f). 

D. For purposes of determining emissions for 

comparison with the limitations in Condition 

7.7.6(e)(i) and (e)(ii), emissions may be 

determined from the average of three separate 

runs as provided by 35 IAC Part 283. 

ii. The Permittee shall submit a test plan to the 

Illinois EPA at least 60 days prior to 

testing, which plan shall include the 

information specified by Condition 8.6.2. 

iv. The Illinois EPA shall be notified prior to 

these tests to enable the Illinois EPA to 

observe these tests. Notification of the 

expected date of testing shall be submitted a 
156 

minimum of 30 days prior to the expected date. 

Notification of the actual date and expected 

time of testing shall be submitted a minimum 

of 5 working days prior to the actual date of 

the test. The Illinois EPA may, at its 

discretion, accept notification with shorter 

advance notice provided that the Illinois EPA 

will not accept such notification if it 

interferes with the Illinois EPA’s ability to 

observe the testing. 

v. The Permittee shall submit the Final Report(s) 

for any required emission testing to the 

Illinois EPA within 45 days after the tests 

results are compiled and finalized but no 

later than 120 days after the date of testing. 

The Final Report shall include the information 

specified in Condition 8.6.3 and the following 

information: 

A. A summary of results. 

B. Detailed description of test method(s), 

including description of sampling points, 

sampling train, analysis equipment, and 

test schedule. 

C. Detailed description of the operating 

conditions of the affected turbine during 

testing, including fuel consumption 

(scf/hr or gal/hr), firing rate 

(mmBtu/hr), and combustion system 

information, i.e., settings for 

combustion air. 

D. Detailed data and calculations, including 

copies of all raw data sheets and records 

of laboratory analyses, sample 

calculations, and data on equipment 

calibration. 

E. Opacity data (6-minute average and hourly 

average) measured during testing. 

Note: Construction Permit 00070029 addressed the initial 

performance tests for the affected turbines including 

measurements for emissions of NOx, PM/PM10, CO and VOM. 

7.7.8-1 Operational Monitoring Requirements 

a. i. The Permittee shall install and operate a 

continuous monitoring system to monitor and 

record the fuel consumption in each affected 

turbine. [40 CFR 60.334(a)] 

ii. The Permittee shall install and operate a 

continuous monitoring system to monitor and 

record the ratio of water to fuel being fired 
157 

in each affected turbine when water is being 

injected into the turbine to control NOx 

emissions, i.e., oil is being fired. [40 CFR 

60.334(a)] 

b. i. This permit is issued based on the affected 

turbines being peaking units, as specified in 

40 CFR Part 75, so that continuous emission 

monitoring is not required for NOx. To 

maintain this status, the three year rolling 

average annual capacity factor of turbine 

shall not be greater than 10 percent, and the 

highest annual capacity factor shall not be 

greater than 20 percent in any one of the 

three averaging years. 

ii. Should the operation of an affected turbine 

exceed the above requirements relating to the 

definition of a peaking unit in 40 CFR 75, the 

Permittee shall install the appropriate 

Continuous Monitoring System(s) on the turbine 

by December 31 of the following calendar year, 

as defined in 40 CFR 75, in order to remain in 

compliance with the provisions of the Acid 

Rain Program. 

c. Pursuant to Sections 412 of the Clean Air Act and 40 

CFR Parts 72 and 75, the source is required to conduct 

monitoring for the affected turbines for SO2 and NOx 

emissions. (See also Condition 6.2.3) 

7.7.8-1 Sampling and Analysis of Fuels 

a. The Permittee shall comply with the applicable 

requirements of 40 CFR 60.334 for sampling and 

analysis of the sulfur and nitrogen content of the 

fuel supply to the affected turbines, except 

monitoring of fuel nitrogen content shall not be 

required if the Permittee does not rely on the 

adjustment factor for nitrogen content of fuel or 

during periods when natural gas is the only fuel fired 

in the affected turbines (This is because natural gas 

does not contain fuel-bound nitrogen and the free 

nitrogen in natural gas does not contribute 

appreciably to NOx emissions). 

7.7.9 Recordkeeping Requirements 

The Permittee shall maintain the following records for the affected 

turbines, pursuant to Sections 39.5(7)(a) and (e) of the Act: 

a. i. An operating log for each affected turbine, 

which shall include the following information: 

A. I. Identification of each time the 

turbine is operated, with date, 

time, duration, and purpose (i.e., 

exercise or power service). 
158 

II. Further information for each time 

that the turbine is operated on oil, 

including information explaining why 

natural gas was not or could not be 

used, to address compliance with 

Condition 7.7.6(c)(v), and 

information confirming proper 

operation of the water injection 

system. 

B. Information for the observations conducted 

pursuant to Condition 7.7.6(g), with date, 

time, personnel, and findings. 

C. Information for any incident in which the 

operation of the turbine continued during 

malfunction or breakdown, including: date, 

time, and duration; a description of the 

incident; whether emissions exceeded or 

may have exceeded any applicable standard; 

a description of the corrective actions 

taken to reduce emissions and the duration 

of the incident; and a description of the 

preventative actions taken. [40 CFR 

60.7(b)] 

ii. A maintenance and repair log for each affected 

turbine and associated equipment, listing 

activities performed with date. 

b. Records for each shipment of fuel for the affected 

turbines, including date, supplier, quantity (in 

gallons), sulfur content, heat content, and whether 

the SO2 emissions from the burning of such fuel would 

meet the standard in Condition 7.6.4(b). 

c. i. Records of the natural gas and distillate oil 

fuel usage for each affected turbine, 

scf/month and scf/year and gallons/month and 

gallons/year, respectively. 

ii. Records of the heat content of the fuels being 

fired in the affected turbines. 

iii. Records of the annual capacity factor of each 

affected each affected turbine, on annual 

basis, with supporting calculations. 

d. Records for all opacity measurements made in 

accordance with USEPA Method 9 for an affected turbine 

that the Permittee conducts or that are conducted on 

its behalf by individuals who are qualified to make 

such observations. For each occasion on which such 

observations are made, these records shall include the 

identity of the observer, a description of the various 

observations that were made, the observed opacity, and 

copies of the raw data sheets for the observations. 
159 

e. The Permittee shall comply with the recordkeeping and 

reporting requirements of 40 CFR 75 applicable to NOx 

emissions during the ozone control period, including, 

but not limited to, 40 CFR 75.54(b) and (d) [35 IAC 

217.712(a) and (b)] including maintaining records of 

the heat input and NOx emissions of the turbine as 

determined in accordance with 35 IAC 217.710(c), and 

records of metered fuel use or operating hours used to 

determine heat input. [35 IAC 217.712(b)(1)] 

f. Records of the operating hours and for the affected 

turbines, hr/day and hr/year. 

g. Records of emissions of NOx from each affected 

turbine, with supporting data and calculations, 

tons/ozone season and tons/year (See also Conditions 

7.7.8(a) and 7.7.10(c)). 

h. The following records for a NOx CEMS if continuous 

monitoring required: 

i. Any periods during which a continuous 

monitoring system was not operational, with 

explanation. 

ii. Any day in which emissions exceeded an 

applicable standard. 

i. Records of emissions (ton/month and ton/yr) of PM, 

NOx, CO, VOM and SO2, from each affected turbine with 

supporting calculations including documentation for 

the emission factors used. 

7.7.10 Reporting Requirements 

a. Reporting of Deviations 

For each affected turbine, the Permittee shall 

promptly notify the Illinois EPA of deviations from 

permit requirements as follows. At a minimum, such 

notifications shall include a description of such 

deviations, including whether they occurred during 

startup or malfunction/breakdown, and a discussion of 

the probable cause of such deviations, the corrective 

actions taken, and the preventative measures taken. 

[Sections 39.5(7)(a) and (f) of the Act] 

i. A. The Permittee shall immediately notify the 

Illinois EPA’s Regional Office, by 

telephone (voice, facsimile or electronic) 

for each incident in which the opacity 

from an affected turbine exceeds or may 

have exceeded the limit in Condition 

7.7.4(b) (30 percent) for three or more 6-

minute averaging periods. (Otherwise, if 

opacity during an incident only exceeds or 

may have exceeded 30 percent for no more 
160 

than one or two 6-minute averaging 

periods, the Permittee need only report 

the incident in accordance with Condition 

7.7.10(a)(iii)(A).) 

B. Upon conclusion of such incident, the 

Permittee shall submit a follow-up report 

to the Illinois EPA, Compliance Section 

and Regional Office, within 15 days 

providing a detailed description of the 

incident and its cause(s), an explanation 

why continued operation of the turbine was 

necessary, the length of time during which 

operation continued under such conditions, 

the measures taken by the Permittee to 

minimize and correct deficiencies with 

chronology, and when the repairs were 

completed or when the turbine was taken 

out of service. 

ii. Notification within 30 days for a deviation 

from Condition 7.7.4(c) or 7.7.6(c)(i), with a 

copy of the applicable records for the 

incident. 

iii. A. Reporting with the quarterly reports 

required for Boiler 123 by Condition 

7.1.10-2(a) for other deviations from 

permit requirements not addressed by 

Condition 7.7.10(a)(i) or (ii), including 

deviations from applicable emission 

standards, inspection requirements, and 

recordkeeping requirements. 

B. With these reports, the Permittee shall 

also address other instances of deviations 

that occurred during the quarter that have 

been separately reported in writing to the 

Illinois EPA as provided by Conditions 

7.7.10(a)(i) and (ii), with a listing of 

such deviations and identification of each 

such written notification or report. For 

this purpose, the Permittee need not 

resubmit the detailed information provided 

in the initial written notifications and 

reports for such deviations. 

b. i. The Permittee shall submit a report by 

November 30 of each year, to the Illinois EPA 

that demonstrates that each affected turbine 

has complied with Condition 7.7.4(d), pursuant 

to 35 IAC 217.712(d). This report shall 

contain the information specified by 35 IAC 

217.712(d) including the heat input and NOx 

emissions of the unit for the ozone control 

period. 
161 

ii. For the affected turbines, The Permittee shall 

submit copies of any records and data required 

by 35 IAC 217.712 to the Illinois EPA within 

30 days after receipt of a written request 

from the Illinois EPA. [35 IAC 217.712(g)] 

c. The Permittee shall furnish the Illinois EPA with 

written notification within 30 days as follows with 

respect to firing backup fuel: 

i. Use of backup fuel in a turbine for more than 

180 hours in a rolling 12 month period, 

ii. Use of backup fuel in a turbine for a period 

of more than 6 hours other than for purposes 

of emissions testing or backup fuel system 

evaluation. 

d. In conjunction with the Annual Emissions Report 

required by 35 IAC Part 254, the Permittee shall 

provide the following information for the preceding 

calendar year: 

i. The operating hours of each turbine; 

ii. The operating hours of each turbine with oil 

iii. The total number of startups for each turbine; 

and 

iv. The total natural gas and oil consumption of 

the combustion turbines. 

e. Acid Rain Program Reporting 

Pursuant to Section 412 of the Clean Air Act and 40 CFR 

Parts 72 and 75, for the affected turbines, the source is 

subject to the reporting requirements of 40 CFR Part 75, 

which includes General Provisions; Notifications; Initial 

Certification or Recertification Application; and 

Quarterly Reports; and Opacity Reports. [See Condition 

6.2.3] Pursuant to Section 39.5(17)(m) of the Act, the 

designated representative of the source must concurrently 

submit to the Illinois EPA in the same electronic format 

specified by the USEPA, the data and information 

submitted to USEPA on a quarterly basis pursuant to 40 

CFR 75.64. 

7.7.11 Operational Flexibility/Anticipated Operating Scenarios 

None 

7.7.12 Compliance Procedures 

a. i. Compliance with NOx emission limits of 

Condition 7.7.4(a)(i) is demonstrated by the 

monitoring requirements of 7.7.8 and by the 

recordkeeping requirements of 7.7.9. 
162 

ii. Compliance with Condition 7.7.4(a)(ii) is 

demonstrated by the monitoring requirements of 

7.7.8 and by the recordkeeping requirements of 

7.7.9. 

b. Compliance with opacity limitation of Condition 

7.7.4(b) is addressed by the inspection, testing and 

recordkeeping requirements in Conditions 7.7.6, 7.7.7, 

and 7.7.9(d). 

c. Compliance with the SO2 limits in Conditions 7.7.4(a)(iii) 

and 7.7.4(c) is addressed by the sampling and analysis 

required by Condition 7.7.7-2 and the records required by 

Condition 7.7.9(c). For this purpose, complete conversion 

of sulfur to SO2 shall be assumed, e.g., SO2 emissions in 

lb/mmBtu are twice the sulfur content of the fuel supply, 

in lb/mmBtu. 

Note: Stoichiometric combustion of distillate oil in 

the affected turbine with the maximum allowed sulfur 

content, i.e., 0.05 percent pursuant to Condition 

7.8.6(c)(iv) would result in an SO2 concentration in 

the exhaust of only about 30 ppm based on the F-factor 

for oil in USEPA’s Reference Method 19, which is a 

fraction of the 2000 ppm limit in Condition 7.7.4(c). 

d. Compliance with NOx emission limit of Conditions 

7.7.4(a)(ii) and 7.7.4(d) is addressed by the 

monitoring and recordkeeping required by Conditions 

7.7.8-1 and 7.7.9(b). 

e. Compliance with the emission limitations of Condition 

7.7.6(e) is addressed by the testing, monitoring and 

recordkeeping required by Conditions 7.7.7(b), 7.7.8-1(b), 

and 7.7.9. 

f. Compliance with the operational requirements of Condition 

7.7.6 is addressed by the recordkeeping required by 

Condition 7.7.9. 

Note: This condition is included in this permit pursuant 

to Section 39.5(7)(p)(v) of the Act. 
163 

8.0 GENERAL PERMIT CONDITIONS 

8.1 Permit Shield 

Pursuant to Section 39.5(7)(j) of the Act, the Permittee has 

requested and has been granted a permit shield. This permit 

shield provides that compliance with the conditions of this permit 

shall be deemed compliance with applicable requirements which were 

applicable as of the date the proposed permit for this source was 

issued, provided that either the applicable requirements are 

specifically identified within this permit, or the Illinois EPA, 

in acting on this permit application, has determined that other 

requirements specifically identified are not applicable to this 

source and this determination (or a concise summary thereof) is 

included in this permit. 

8.2 Applicability of Title IV Requirements (Acid Deposition Control) 

This source is an affected source under Title IV of the CAA and is 

subject to requirements pursuant to Title IV of the CAA as 

specified in Section 6.2. To the extent that the federal 

regulations promulgated under Title IV of the CAA, are 

inconsistent with the requirements of this permit, the federal 

regulations promulgated under Title IV of the CAA shall take 

precedence pursuant to Section 39.5(17)(j) of the Act. 

8.3 Emissions Trading Programs 

No permit revision shall be required for increases in emissions 

allowed under any USEPA approved economic incentives, marketable 

permits, emissions trading, and other similar programs or 

processes for changes that are provided for elsewhere in this 

permit and that are authorized by the applicable requirement 

[Section 39.5(7)(o)(vii) of the Act]. 

8.4 Operational Flexibility/Anticipated Operating Scenarios 

8.4.1 Changes Specifically Addressed by Permit 

Physical or operational changes specifically addressed by 

the Conditions of this permit that have been identified as 

not requiring Illinois EPA notification may be implemented 

without prior notice to the Illinois EPA. 

8.4.2 Changes Requiring Prior Notification 

The Permittee is authorized to make physical or 

operational changes that contravene express permit terms 

without applying for or obtaining an amendment to this 

permit, provided that [Section 39.5(12)(a)(i) of the 

Act]: 

a. The changes do not violate applicable requirements; 

b. The changes do not contravene federally enforceable 

permit terms or conditions that are monitoring 

(including test methods), recordkeeping, reporting, or 

compliance certification requirements; 
164 

c. The changes do not constitute a modification under 

Title I of the CAA; 

d. Emissions will not exceed the emissions allowed under 

this permit following implementation of the physical 

or operational change; and 

e. The Permittee provides written notice to the Illinois 

EPA, Division of Air Pollution Control, Permit 

Section, at least 7 days before commencement of the 

change. This notice shall: 

i. Describe the physical or operational change; 

ii. Identify the schedule for implementing the 

physical or operational change; 

iii. Provide a statement of whether or not any New 

Source Performance Standard (NSPS) is 

applicable to the physical or operational 

change and the reason why the NSPS does or 

does not apply; 

iv. Provide emission calculations which 

demonstrate that the physical or operational 

change will not result in a modification; and 

v. Provide a certification that the physical or 

operational change will not result in 

emissions greater than authorized under the 

Conditions of this permit. 

8.5 Testing Procedures 

Tests conducted to measure composition of materials, efficiency of 

pollution control devices, emissions from process or control 

equipment, or other parameters shall be conducted using standard 

test methods if applicable test methods are not specified by the 

applicable regulations or otherwise identified in the condition of 

this permit. Documentation of the test date, conditions, 

methodologies, calculations, and test results shall be retained 

pursuant to the recordkeeping procedures of this permit. Reports 

of any tests conducted as required by this permit or as the result 

of a request by the Illinois EPA shall be submitted as specified 

in Conditions 8.6.3 and 8.6.4. 

8.6 Reporting Requirements 

8.6.1 Monitoring Reports 

Reports summarizing required monitoring as specified in 

the conditions of this permit shall be submitted to the 

Illinois EPA every six months as follows, unless more 

frequent submittal of such reports is required in Section 

7 of this permit [Section 39.5(7)(f) of the Act]: 
165 

Monitoring Period Report Due Date

 

January - June September 1 

July - December March 1 

All instances of deviations from permit requirements must 

be clearly identified in such reports. All such reports 

shall be certified in accordance with Condition 9.9. 

8.6.2 Test Notifications 

Unless otherwise specified elsewhere in this permit, a 

written test plan for any test required by this permit 

shall be submitted to the Illinois EPA for review at least 

60 days prior to the testing pursuant to Section 

39.5(7)(a) of the Act. The notification shall include at 

a minimum: 

a. The name and identification of the affected unit(s); 

b. The person(s) who will be performing sampling and 

analysis and their experience with similar tests; 

c. The specific conditions under which testing will be 

performed, including a discussion of why these 

conditions will be representative of maximum emissions 

and the means by which the operating parameters for 

the source and any control equipment will be 

determined; 

d. The specific determinations of emissions and operation 

that are intended to be made, including sampling and 

monitoring locations; 

e. The test method(s) that will be used, with the 

specific analysis method, if the method can be used 

with different analysis methods; 

f. Any minor changes in standard methodology proposed to 

accommodate the specific circumstances of testing, 

with justification; and 

g. Any proposed use of an alternative test method, with 

detailed justification. 

8.6.3 Test Reports 

Unless otherwise specified elsewhere in this permit, the 

results of any test required by this permit shall be 

submitted to the Illinois EPA within 60 days of completion 

of the testing. The test report shall include at a 

minimum [Section 39.5(7)(e)(i) of the Act]: 

a. The name and identification of the affected unit(s); 

b. The date and time of the sampling or measurements; 
166 

c. The date any analyses were performed; 

d. The name of the company that performed the tests 

and/or analyses; 

e. The test and analytical methodologies used; 

f. The results of the tests including raw data, and/or 

analyses including sample calculations; 

g. The operating conditions at the time of the sampling 

or measurements; and 

h. The name of any relevant observers present including 

the testing company’s representatives, any Illinois 

EPA or USEPA representatives, and the representatives 

of the source. 

8.6.4 Reporting Addresses 

a. Unless otherwise specified in the particular provision 

of this permit or in the written instructions 

distributed by the Illinois EPA for particular 

reports, reports and notifications shall be sent to 

the Illinois EPA - Air Compliance Section with a copy 

sent to the Illinois EPA - Air Regional Field Office. 

b. As of the date of issuance of this permit, the 

addresses of the offices that should generally be 

utilized for the submittal of reports and 

notifications are as follows: 

i. Illinois EPA - Air Compliance Section 

Illinois Environmental Protection Agency (MC 40) 

Bureau of Air 

Compliance & Enforcement Section (MC 40) 

1021 North Grand Avenue East 

P.O. Box 19276 

Springfield, Illinois 62794-9276 

ii. Illinois EPA - Air Regional Field Office 

Illinois Environmental Protection Agency 

Division of Air Pollution Control 

2009 Mall Street 

Collinsville, Illinois 62234 

iii. USEPA Region 5 - Air Branch 

USEPA (AR - 17J) 

Air & Radiation Division 

77 West Jackson Boulevard 

Chicago, Illinois 60604 
167 

c. Permit applications should be addressed to the Air 

Permit Section. As of the date of issuance of this 

permit, the address of the Air Permit Section is as 

follows: 

Illinois Environmental Protection Agency 

Division of Air Pollution Control 

Permit Section (MC 11) 

1021 North Grand Avenue East 

P.O. Box 19506 

Springfield, Illinois 62794-9506 

8.7 Title I Conditions 

Notwithstanding the expiration date on the first page of this 

CAAPP permit, Title I conditions in this permit, which are 

identified by a T1, T1N, or T1R designation, remain in effect 

until such time as the Illinois EPA takes action to revise or 

terminate them in accordance with applicable procedures for action 

on Title I conditions. This is because these conditions either: 

(a) incorporate conditions of earlier permits that were issued by 

the Illinois EPA pursuant to authority that includes authority 

found in Title I of the Clean Air Act (T1 conditions), (b) were 

newly established in this CAAPP permit pursuant to authority that 

includes such Title I authority (T1N conditions), or (c) reflect a 

combination of conditions of such previous permits and revisions 

to those conditions established in this CAAPP permit (T1R 

conditions). (See also Condition 1.5.) 
168 

9.0 STANDARD PERMIT CONDITIONS 

9.1 Effect of Permit 

9.1.1 The issuance of this permit does not release the Permittee 

from compliance with State and Federal regulations which 

are part of the Illinois State Implementation Plan, as 

well as with other applicable statutes and regulations of 

the United States or the State of Illinois or applicable 

ordinances, except as specifically stated in this permit 

and as allowed by law and rule. [Section 39.5(7)(j)(iv) 

of the Act] 

9.1.2 In particular, this permit does not alter or affect the 

following: 

a. The provisions of Section 303 (emergency powers) of 

the CAA, including USEPA's authority under that 

Section; 

b. The liability of an owner or operator of a source for 

any violation of applicable requirements prior to or 

at the time of permit issuance; 

c. The applicable requirements of the acid rain program 

consistent with Section 408(a) of the CAA; and 

d. The ability of USEPA to obtain information from a 

source pursuant to Section 114 (inspections, 

monitoring, and entry) of the CAA. 

9.1.3 Notwithstanding the conditions of this permit specifying 

compliance practices for applicable requirements, any 

person (including the Permittee) may also use other 

credible evidence to establish compliance with, or 

violation of, any applicable requirement to the extent 

authorized by law. Nothing in this permit shall be 

construed to waive any defenses otherwise available to the 

Permittee, including, but not limited to, challenging the 

use of the USEPA’s credible evidence rule in the context 

of any future proceeding consistent with Clean Air 

Implementation Project v. EPA, 150 F3d 1200 (D.C. Circuit 

1998). 

9.2 General Obligations of Permittee 

9.2.1 Duty to Comply 

The Permittee must comply with all terms and conditions of 

this permit. Any permit noncompliance constitutes a 

violation of the CAA and the Act, and is grounds for any 

or all of the following: enforcement action, permit 

termination, revocation and reissuance, modification, or 

denial of a permit renewal application. [Section 

39.5(7)(o)(i) of the Act] 
169 

The Permittee shall meet applicable requirements that 

become effective during the permit term in a timely manner 

unless an alternate schedule for compliance with the 

applicable requirement is established. 

9.2.2 Duty to Maintain Equipment 

The Permittee shall maintain all equipment covered under 

this permit in such a manner that the performance or 

operation of such equipment shall not cause a violation of 

applicable requirements. 

9.2.3 Duty to Cease Operation 

No person shall cause, threaten or allow the continued 

operation of any emission unit during malfunction or 

breakdown of the emission unit or related air pollution 

control equipment if such operation would cause a 

violation of an applicable emission standard, regulatory 

requirement, ambient air quality standard or permit 

limitation unless this permit provides for such continued 

operation consistent with the Act and applicable Board 

regulations. [Section 39.5(6)(c) of the Act] 

9.2.4 Disposal Operations 

The source shall be operated in such a manner that the 

disposal of air contaminants collected by the equipment 

operations, or activities shall not cause a violation of 

the Act or regulations promulgated thereunder. 

9.3 Obligation to Allow Illinois EPA Surveillance 

Upon presentation of proper credentials and other documents, the 

Permittee shall allow the Illinois EPA, or an authorized 

representative to perform the following. [Sections 4 and 

39.5(7)(a) and (p)(ii) of the Act] 

a. Enter upon the Permittee's premises where an actual or 

potential emission unit is located; where any regulated 

equipment, operation, or activity is located or where 

records must be kept under the conditions of this permit; 

b. Have access to and copy, at reasonable times, any records 

that must be kept under the conditions of this permit; 

c. Inspect during hours of operation any sources, equipment 

(including monitoring and air pollution control 

equipment), practices, or operations regulated or required 

under this permit; 

d. Sample or monitor any substances or parameters at any 

location: 

i. At reasonable times, for the purposes of assuring 

permit compliance; or 

ii. As otherwise authorized by the CAA or the Act; 
170 

e. Obtain and remove samples of any discharge or emission of 

pollutants authorized by this permit; and 

f. Enter and utilize any photographic, recording, testing, 

monitoring, or other equipment for the purposes of 

preserving, testing, monitoring, or recording any 

activity, discharge or emission at the source authorized 

by this permit. 

9.4 Fees 

The Permittee shall pay fees to the Illinois EPA consistent with 

the fee schedule approved pursuant to Section 39.5(18) of the Act, 

and submit any information relevant thereto. [Section 

39.5(7)(o)(vi) of the Act] Fees shall be paid by check sent to 

the Fiscal Services Section, Illinois Environmental Protection 

Agency, P.O. Box 19276, Springfield, Illinois 62794-9276. 

9.5 Property Rights 

This permit does not convey any property rights of any sort, or 

any exclusive privilege. [Section 39.5(7)(o)(iv) of the Act] 

9.6 Recordkeeping 

9.6.1 Control Equipment Maintenance Records 

A maintenance record shall be kept on the premises for 

each item of air pollution control equipment. As a 

minimum, this record shall show the dates of performance 

and nature of preventative maintenance activities. 

9.6.2 Records of Changes in Operation 

A record shall be kept describing changes made at the 

source that result in emissions of a regulated air 

pollutant subject to an applicable requirement, but not 

otherwise regulated under this permit, and the emissions 

resulting from those changes. [Section 39.5(12)(b)(iv) of 

the Act] 

9.6.3 Retention of Records 

a. Records of all monitoring data and support information 

shall be retained for a period of at least 5 years 

from the date of the monitoring sample, measurement, 

report, or application. Support information includes 

all calibration and maintenance records, original 

strip-chart recordings for continuous monitoring 

instrumentation, and copies of all reports required by 

this permit. [Section 39.5(7)(e)(ii) of the Act] 

b. Other records required by this permit including any 

logs, plans, procedures, or instructions required to be 

kept by this permit shall be retained for a period of at 

least 5 years from the date of entry unless a longer 

period is specified by a particular permit provision. 
171 

9.7 Annual Emissions Report 

The Permittee shall submit an annual emissions report to the Illinois 

EPA, Compliance Section no later than May 1 of the following year, as 

required by 35 IAC Part 254 and Section 4(b) of the Act. 

9.8 Requirements for Compliance Certification 

Pursuant to Section 39.5(7)(p)(v) of the Act, the Permittee shall 

submit annual compliance certifications. The compliance 

certifications shall be submitted no later than May 1 or more 

frequently as specified in the applicable requirements or by 

permit condition. The compliance certifications shall be 

submitted to: (1) the Illinois EPA, Air Compliance Section, (2) 

the Illinois EPA, Air Regional Field Office, and (3) USEPA Region 

5 – Air Branch. (The addresses for the submittal of these 

compliance certifications are provided in Condition 8.6.4.) 

a. The certification shall include the identification of each 

term or condition of this permit that is the basis of the 

certification; the compliance status; whether compliance 

was continuous or intermittent; the method(s) used for 

determining the compliance status of the source, both 

currently and over the reporting period consistent with 

the conditions of this permit. 

b. All compliance certifications shall be submitted to USEPA 

Region 5 in Chicago as well as to the Illinois EPA. 

c. All compliance reports required to be submitted shall 

include a certification in accordance with Condition 9.9. 

9.9 Certification 

Any document (including reports) required to be submitted by this 

permit shall contain a certification by a responsible official of 

the Permittee that meets the requirements of Section 39.5(5) of 

the Act. [Section 39.5(7)(p)(i) of the Act] An example 

Certification by a Responsible Official is included as an 

attachment to this permit. 

9.10 Defense to Enforcement Actions 

9.10.1 Need to Halt or Reduce Activity Not a Defense 

It shall not be a defense for the Permittee in an 

enforcement action that it would have been necessary to 

halt or reduce the permitted activity in order to maintain 

compliance with the conditions of this permit. [Section 

39.5(7)(o)(ii) of the Act] 

9.10.2 Emergency Provision 

a. An emergency shall be an affirmative defense to an action 

brought for noncompliance with the technology-based 

emission limitations under this permit if the following 

conditions are met through properly signed, contemporaneous 

operating logs, or other relevant evidence: 
172 

i. An emergency occurred as provided in Section 

39.5(7)(k) of the Act and the Permittee can 

identify the cause(s) of the emergency; 

Note: For this purpose, emergency means a situation 

arising from sudden and reasonably unforeseeable 

events beyond the control of the source, as further 

defined by Section 39.5(7)(k)(iv) of the Act. 

ii. The permitted source was at the time being 

properly operated; 

iii. The Permittee submitted notice of the 

emergency to the Illinois EPA within two 

working days of the time when emission 

limitations were exceeded due to the 

emergency. This notice must contain a 

detailed description of the emergency, any 

steps taken to mitigate emissions, and 

corrective actions taken; and 

iv. During the period of the emergency the 

Permittee took all reasonable steps to 

minimize levels of emissions that exceeded the 

emission limitations, standards, or 

regulations in this permit. 

b. This provision is in addition to any emergency or 

upset provision contained in any applicable 

requirement. This provision does not relieve a 

Permittee of any reporting obligations under existing 

federal or state laws or regulations. 

9.11 Permanent Shutdown 

This permit only covers emission units and control equipment while 

physically present at the indicated source location(s). Unless 

this permit specifically provides for equipment relocation, this 

permit is void for the operation or activity of any item of 

equipment on the date it is removed from the permitted location(s) 

or permanently shut down. This permit expires if all equipment is 

removed from the permitted location(s), notwithstanding the 

expiration date specified on this permit. 

9.12 Reopening and Reissuing Permit for Cause 

9.12.1 Permit Actions 

This permit may be modified, revoked, reopened and 

reissued, or terminated for cause in accordance with 

applicable provisions of Section 39.5 of the Act. The 

filing of a request by the Permittee for a permit 

modification, revocation and reissuance, or termination, 

or of a notification of planned changes or anticipated 

noncompliance does not stay any permit condition. 

[Section 39.5(7)(o)(iii) of the Act] 
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9.12.2 Reopening and Revision 

This permit must be reopened and revised if any of the 

following occur: [Section 39.5(15)(a) of the Act] 

a. Additional requirements become applicable to the 

equipment covered by this permit and three or more 

years remain before expiration of this permit; 

b. Additional requirements become applicable to an 

affected source for acid deposition under the acid 

rain program; 

c. The Illinois EPA or USEPA determines that this permit 

contains a material mistake or that inaccurate 

statement were made in establishing the emission 

standards or limitations, or other terms or conditions 

of this permit; and 

d. The Illinois EPA or USEPA determines that this permit 

must be revised or revoked to ensure compliance with 

the applicable requirements. 

9.12.3 Inaccurate Application 

The Illinois EPA has issued this permit based upon the 

information submitted by the Permittee in the permit 

application. Any misinformation, false statement or 

misrepresentation in the application shall be grounds for 

revocation and reissuance under Section 39.5(15) of the 

Act, pursuant to Sections 39.5(5)(e) and (i) of the Act. 

9.12.4 Duty to Provide Information 

The Permittee shall furnish to the Illinois EPA, within a 

reasonable time specified by the Illinois EPA any 

information that the Illinois EPA may request in writing 

to determine whether cause exists for modifying, revoking 

and reissuing, or terminating this permit, or to determine 

compliance with this permit. Upon request, the Permittee 

shall also furnish to the Illinois EPA copies of records 

required to be kept by this permit, or for information 

claimed to be confidential, the Permittee may furnish such 

records directly to USEPA along with a claim of 

confidentiality. [Section 39.5(7)(o)(v) of the Act] 

9.13 Severability Clause 

The provisions of this permit are severable. In the event of a 

challenge to any portion of this permit, other portions of this 

permit may continue to be in effect. Should any portion of this 

permit be determined to be illegal or unenforceable, the validity 

of the other provisions shall not be affected and the rights and 

obligations of the Permittee shall be construed and enforced as if 

this permit did not contain the particular provisions held to be 

invalid and the applicable requirements underlying these 

provisions shall remain in force. [Section 39.5(7)(i) of the Act] 
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9.14 Permit Expiration and Renewal 

Upon the expiration of this permit, if the source is operated, it 

shall be deemed to be operating without a permit unless a timely 

and complete CAAPP application has been submitted for renewal of 

this permit. However, if a timely and complete application to 

renew this CAAPP permit has been submitted, the terms and all 

conditions of this CAAPP permit will remain in effect until the 

issuance of a renewal permit. [Sections 39.5(5)(l) and (o) of the 

Act] 

Note: Pursuant to Sections 39.5(5)(h) and (n) of the Act, upon 

submittal of a timely and complete renewal application, the 

permitted source may continue to operate until final action is 

taken by the Illinois EPA on the renewal application, provided, 

however, that this protection shall cease if the applicant fails 

to submit any additional information necessary to evaluate or take 

final action on the renewal application as requested by the 

Illinois EPA in writing. For a renewal application to be timely, 

it must be submitted no later than 9 months prior to the date of 

permit expiration. 

9.15 General Authority for the Terms and Conditions of this Permit 

The authority for terms and conditions of this permit that do not 

include a citation for their authority is Section 39.5(7)(a) of 

the Act, which provides that the Illinois EPA shall include such 

provisions in a CAAPP permit as are necessary to accomplish the 

purposes of the Act and to assure compliance with all applicable 

requirements. Section 39.5(7)(a) of the Act is also another basis 

of authority for terms and conditions of this permit that do 

include a specific citation for their authority. 

Note: This condition is included in this permit pursuant to 

Section 39.5(7)(n) of the Act. 
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10.0 ATTACHMENTS 

10.1 Attachment 1 Emissions of Particulate Matter from New 

Process Emission Units 

35 IAC 212.321 - Process Emission Units for Which Construction or 

Modification Commenced On or After April 14, 1972 

a. No person shall cause or allow the emission of particulate 

matter into the atmosphere in any one hour period from any 

new process emission unit which, either alone or in 

combination with the emission of particulate matter from 

all other similar process emission units for which 

construction or modification commenced on or after April 

14, 1972, at a source or premises, exceeds the allowable 

emission rates specified in subsection (c) of 35 IAC 

212.321 [35 IAC 212.321(a)]. 

b. Interpolated and extrapolated values of the data in 

subsection (c) of 35 IAC 212.321 shall be determined by 

using the equation [35 IAC 212.321(b)]: 

E = A(P)B

Where: 

P = Process weight rate; and 

E = Allowable emission rate; and, 

i. Up to process weight rates of 408 Mg/hr (450 T/hr): 

 Metric English 

P Mg/hr T/hr 

E kg/hr lb/hr 

A 1.214 2.54 

B 0.534 0.534 

ii. For process weight rate greater than or equal to 408 

Mg/hr (450 T/hr): 

 Metric English 

P Mg/hr T/hr 

E kg/hr lb/hr 

A 11.42 24.8 

B 0.16 0.16 

c. Limits for Process Emission Units For Which Construction 

or Modification Commenced On or After April 19, 1972 [35 

IAC 212.321(c)]: 

Metric English 

P E P E 

Mg/hr kg/hr T/hr lb/hr 

0.05 0.25 0.05 0.55 

0.1 0.29 0.10 0.77 

0.2 0.42 0.2 1.10 

0.3 0.64 0.30 1.35 
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Metric English 

P E P E 

Mg/hr kg/hr T/hr lb/hr 

0.4 0.74 0.40 1.58 

0.5 0.84 0.50 1.75 

0.7 1.00 0.75 2.40 

0.9 1.15 1.00 2.60 

1.8 1.66 2.00 3.70 

2.7 2.1 3.00 4.60 

3.6 2.4 4.00 5.35 

4.5 2.7 5.00 6.00 

9.0 3.9 10.00 8.70 

13.0 4.8 15.00 10.80 

18.0 5.7 20.00 12.50 

23.0 6.5 25.00 14.00 

27.0 7.1 30.00 15.60 

32.0 7.7 35.00 17.00 

36.0 8.2 40.00 18.20 

41.0 8.8 45.00 19.20 

45.0 9.3 50.00 20.50 

90.0 13.4 100.00 29.50 

140.0 17.0 150.00 37.00 

180.0 19.4 200.00 43.00 

230.0 22.0 250.00 48.50 

270.0 24.0 300.00 53.00 

320.0 26.0 350.00 58.00 

360.0 28.0 400.00 62.00 

408.0 30.1 450.00 66.00 

454.0 30.4 500.00 67.00 
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10.2 Attachment 2 Emissions of Particulate Matter from Existing 

Process Emission Units 

35 IAC 212.322 - Process Emission Units for Which Construction or 

Modification Commenced Prior to April 14, 1972 

a. No person shall cause or allow the emission of particulate 

matter into the atmosphere in any one hour period from any 

process emission unit for which construction or 

modification commenced prior to April 14, 1972, which, 

either alone or in combination with the emission of 

particulate matter from all other similar process emission 

at a source or premises, exceeds the allowable emission 

rates specified in subsection (c) of 35 IAC 212.322 [35 

IAC 212.322(a)]. 

b. Interpolated and extrapolated values of the data in 

subsection (c) of 35 IAC 212.321 shall be determined by 

using the equation [35 IAC 212.322(b)]: 

E = C + A(P)B

Where: 

P = Process weight rate; and 

E = Allowable emission rate; and, 

i. Up to process weight rates up to 27.2 Mg/hr (30 T/hr): 

 Metric English 

P Mg/hr T/hr 

E kg/hr lb/hr 

A 1.985 4.10 

B 0.67 0.67 

C 0 0 

ii. For process weight rate in excess of 27.2 Mg/hr (30 

T/hr): 

 Metric English 

P Mg/hr T/hr 

E kg/hr lb/hr 

A 25.21 55.0 

B 0.11 0.11 

C - 18.4 - 40.0 

c. Limits for Process Emission Units For Which Construction 

or Modification Commenced Prior to April 14, 1972 [35 IAC 

212.322(c)]: 

Metric English 

P E P E 

Mg/hr kg/hr T/hr lb/hr 

0.05 0.27 0.05 0.55 

0.1 0.42 0.10 0.87 

0.2 0.68 0.2 1.40 

0.3 0.89 0.30 1.83 
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Metric English 

P E P E 

Mg/hr kg/hr T/hr lb/hr 

0.4 1.07 0.40 2.22 

0.5 1.25 0.50 2.58 

0.7 1.56 0.75 3.38 

0.9 1.85 1.00 4.10 

1.8 2.9 2.00 6.52 

2.7 3.9 3.00 8.56 

3.6 4.7 4.00 10.40 

4.5 5.4 5.00 12.00 

9.0 8.7 10.00 19.20 

13.0 11.1 15.00 25.20 

18.0 13.8 20.00 30.50 

23.0 16.2 25.00 35.40 

27.2 18.15 30.00 40.00 

32.0 18.8 35.00 41.30 

36.0 19.3 40.00 42.50 

41.0 19.8 45.00 43.60 

45.0 20.2 50.00 44.60 

90.0 23.2 100.00 51.20 

140.0 25.3 150.00 55.40 

180.0 26.5 200.00 58.60 

230.0 27.7 250.00 61.00 

270.0 28.5 300.00 63.10 

320.0 29.4 350.00 64.90 

360.0 30.0 400.00 66.20 

400.0 30.6 450.00 67.70 

454.0 31.3 500.00 69.00 
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10.3 Attachment 3 - Example Certification by a Responsible Official 

I certify under penalty of law that this document and all 

attachments were prepared under my direction or supervision in 

accordance with a system designed to assure that qualified 

personnel properly gather and evaluate the information submitted. 

Based on my inquiry of the person or persons directly responsible 

for gathering the information, the information submitted is, to 

the best of my knowledge and belief, true, accurate, and complete. 

I am aware that there are significant penalties for submitting 

false information, including the possibility of fine and 

imprisonment for knowing violations. 

Signature: ______________________________________________ 

Name: ______________________________________________ 

Official Title: ______________________________________________ 

Telephone No.: ______________________________________________ 

Date Signed: ______________________________________________ 
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10.4 Attachment 4 - Guidance 

The Illinois has prepared guidance for sources on the Clean Air 

Act Permit Program (CAAPP) that is available on the Internet site 

maintained by the Illinois EPA, www.epa.state.il.us. This 

guidance includes instructions on applying for a revision or 

renewal of the CAAPP permit. 

Guidance On Revising A CAAPP Permit: 

www.epa.state.il.us/air/caapp/caapp-revising.pdf

Guidance On Renewing A CAAPP Permit: 

www.epa.state.il.us/air/caapp/caapp-renewing.pdf

The application forms prepared by the Illinois EPA for the CAAPP 

are also available from the Illinois EPA’s Internet site: 

www.epa.state.il.us/air/caapp/index.html

These CAAPP application forms should also be used by a CAAPP 

source when it applies for a construction permit. For this 

purpose, the appropriate CAAPP application forms and other 

supporting information, should be accompanied by a completed 

Application For A Construction Permit Form (CAAPP Form-199). 

Application For A Construction Permit Form (CAAPP Form-199): 

www.epa.state.il.us/air/caapp/199-caapp.pdf
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10.5 Attachment 5 - Acid Rain Program Permit 

217-782-2113

ACID RAIN PROGRAM 

PERMIT 

Southern Illinois Power Cooperative 

Attn: Leonard F. Hopkins, Designated Representative 

11543 Lake of Egypt Road 

Marion, Illinois 

Oris No.: 976 

IEPA I.D. No.: 199856AAC 

Source/Unit: Marion/Unit 4, CFB Unit 123, Combustion Turbine 

(CT) Units 5 & 6 

Date Received: December 16, 2004 

Date Issued: March 21, 2005 

Effective Date: January 1, 2005 

Expiration Date: December 31, 2009 

STATEMENT OF BASIS:

In accordance with Titles IV and V of the Clean Air Act, the 

Illinois Environmental Protection Agency is issuing this Acid Rain 

Program permit to the Southern Illinois Power Cooperative for its 

Marion facility. 

SULFUR DIOXIDE (SO2) ALLOCATIONS AND NITROGEN OXIDES (NOx) LIMITS 

FOR EACH AFFECTED UNIT:

SO2 Allowances, 2005 2006 2007 2008 2009 

Under Tables 2, 

3, or 4 of 40 

CFR Part 73* 6,517 6,517 6,517 6,517 6,517 

CFB Unit 

123

Nitrogen Oxide 

(NOx) Limit 

These units are not subject to a NOx emissions 

limitation pursuant to 40 CFR Part 76. 

* SO2 allocations for Boilers 1, 2, and 3, which were 

repowered by new CFB Boiler 123. 

SO 2005 2006 2007 2008 2009 2 Allowances, 

under Tables 

2, 3, or 4 of 

40 CFR Part 73 

6,839 6,839 6,839 6,839 6,839 

UNIT 4 

NOx Limit 

0.86 Lb/mmBtu (Standard Limit for Cyclone Fired 

Boilers) 

SO 2005 2006 2007 2008 2009 2 Allowances, 

under Tables 

2, 3, or 4 of 

40 CFR Part 73 

CT 5 None None None None None 

and 6 

NOx Limit These units are not subject to a NOx emissions 

limitation pursuant to 40 CFR Part 76. 
5-2 

PERMIT APPLICATION: The permit application, which includes the 

NOx compliance plan, SO2 allowance requirements and other standard 

requirements is attached and incorporated as part of this permit. 

The owners and operators of this source must comply with the 

standard requirements and special provisions set forth in the 

application. 

COMMENTS, NOTES, AND JUSTIFICATIONS: 

This permit contains provisions related to SO2 emissions and 

requires the owners and operators to hold SO2 allowances to 

account for SO2 emissions from the affected units. An allowance 

is a limited authorization to emit up to one ton of SO2 during or 

after a specified calendar year. Although Marion Units CT 5 and 6 

are not eligible for an allowance allocated by USEPA, the owners 

or operators may obtain SO2 allowances to cover emissions from 

other sources under a marketable allowance program. The transfer 

of allowances to and from a unit account does not necessitate a 

revision to the unit SO2 allocations denoted in this permit (See 

40 CFR 72.84). 

This permit contains provisions related to NOx emissions requiring 

Marion Unit 4 to comply with applicable emission limitations for 

NOx under the Acid Rain program. Pursuant to 40 CFR 76, the 

Illinois EPA is approving NOx standard emission limitation 

compliance plan for Marion Unit 4. The compliance plan is 

effective for calendar years 2005 through 2009. Under the 

compliance plan, annual average NOx emission rate for each year for 

Marion Unit 4, shall not exceed the applicable emission limitation, 

under 40 CFR 76.6(a)(2), of 0.86 lb/million Btu for cyclone fired 

boilers, determined in accordance with 40 CFR Part 75. 

In addition to the described NOX compliance plan, each unit shall 

comply with all other applicable requirements of 40 CFR Part 75 

and 76, including, the duty to reapply for a NOX compliance plan, 

and requirements covering excess emissions. 

This permit does not affect the source’s responsibility to meet all 

other applicable local, state and federal requirements, including 

state requirements under 35 Ill. Adm. Code Part 217 Subpart W, which 

addresses NOx emissions from Marion Units, Unit 4, CFB Unit 123, and 

Combustion Turbine (CT) Units 5 and 6. 

If you have any questions regarding this permit, please contact 

Kunj Patel at 217/782-2113. 

Donald E. Sutton, P.E. 

Manager, Permits Section 

Division of Air Pollution Control 

cc: Cecilia Mijares, USEPA Region V 

John Justice, IEPA Region 3 
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