INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

We Protect Hoosiers and Our Environment.

Mitchell E. Daniels Jr. 100 North Senate Avenue

Governor Indianapolis, Indiana 46204

(317) 232-8603

Thomas W. Easterly Toll Free (800) 451-6027

Commissioner www.idem.IN.gov

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 FNTVOP.dot 03/23/06

 Recycled Paper An Equal Opportunity Employer Please Recycle 

TO: Interested Parties / Applicant

DATE: December 3, 2012

RE: St. Joseph Energy Center, LLC / 141-31003-00579

FROM: Matthew Stuckey, Branch Chief

Permits Branch

Office of Air Quality

Notice of Decision: Approval – Effective Immediately

Please be advised that on behalf of the Commissioner of the Department of Environmental Management, 

I have issued a decision regarding the enclosed matter. Pursuant to IC 13-15-5-3, this permit is effective 

immediately, unless a petition for stay of effectiveness is filed and granted, and may be revoked or 

modified in accordance with the provisions of IC 13-15-7-1.

If you wish to challenge this decision, IC 4-21.5-3-7 and IC 13-15-6-1(b) or IC 13-15-6-1(a) require that 

you file a petition for administrative review. This petition may include a request for stay of effectiveness 

and must be submitted to the Office of Environmental Adjudication, 100 North Senate Avenue, 

Government Center North, Suite N 501E, Indianapolis, IN 46204.

For an initial Title V Operating Permit, a petition for administrative review must be submitted to the 

Office of Environmental Adjudication within thirty (30) days from the receipt of this notice provided under 

IC 13-15-5-3, pursuant to IC 13-15-6-1(b).

For a Title V Operating Permit renewal, a petition for administrative review must be submitted to the 

Office of Environmental Adjudication within fifteen (15) days from the receipt of this notice provided under 

IC 13-15-5-3, pursuant to IC 13-15-6-1(a).

The filing of a petition for administrative review is complete on the earliest of the following dates that apply 

to the filing: 

(1) the date the document is delivered to the Office of Environmental Adjudication (OEA);

(2) the date of the postmark on the envelope containing the document, if the document is mailed to 

OEA by U.S. mail; or

(3) The date on which the document is deposited with a private carrier, as shown by receipt issued 

by the carrier, if the document is sent to the OEA by private carrier.

The petition must include facts demonstrating that you are either the applicant, a person aggrieved or 

adversely affected by the decision or otherwise entitled to review by law. Please identify the permit, 

decision, or other order for which you seek review by permit number, name of the applicant, location, date 

of this notice and all of the following: 
(1) the name and address of the person making the request;

(2) the interest of the person making the request;

(3) identification of any persons represented by the person making the request;

(4) the reasons, with particularity, for the request;

(5) the issues, with particularity, proposed for considerations at any hearing; and

(6) identification of the terms and conditions which, in the judgment of the person making the 

request, would be appropriate in the case in question to satisfy the requirements of the law 

governing documents of the type issued by the Commissioner.

Pursuant to 326 IAC 2-7-18(d), any person may petition the U.S. EPA to object to the issuance of an 

initial Title V operating permit, permit renewal, or modification within sixty (60) days of the end of the fortyfive (45) day EPA review period. Such an objection must be based only on issues that were raised with 

reasonable specificity during the public comment period, unless the petitioner demonstrates that it was 

impractible to raise such issues, or if the grounds for such objection arose after the comment period. 

To petition the U.S. EPA to object to the issuance of a Title V operating permit, contact:

U.S. Environmental Protection Agency

401 M Street

Washington, D.C. 20406

If you have technical questions regarding the enclosed documents, please contact the Office of Air 

Quality, Permits Branch at (317) 233-0178. Callers from within Indiana may call toll-free at 1-800-451-

6027, ext. 3-0178.

Enclosures

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Permit Reviewer: Josiah Balogun

TABLE OF CONTENTS

A. SOURCE SUMMARY

A.1 General Information [326 IAC 2-7-4(c)][326 IAC 2-7-5(14)][326 IAC 2-7-1(22)]

A.2 Emission Units and Pollution Control Equipment Summary [326 IAC 2-7-4(c)(3)]

[326 IAC 2-7-5(14)]

A.3 Specifically Regulated Insignificant Activities [326 IAC 2-7-1(21)][326 IAC 2-7-4(c)]

[326 IAC 2-7-5(14)]

A.4 Part 70 Permit Applicability [326 IAC 2-7-2]

B. GENERAL CONDITIONS

B.1 Definitions [326 IAC 2-7-1]

B.2 Revocation of Permits [326 IAC 2-1.1-9(5)]

B.3 Affidavit of Construction [326 IAC 2-5.1-3(h)] [326 IAC 2-5.1-4]

B.4 Permit Term [326 IAC 2-7-5(2)][326 IAC 2-1.1-9.5][326 IAC 2-7-4(a)(1)(D)]

[IC 13-15-3-6(a)]

B.5 Term of Conditions [326 IAC 2-1.1-9.5]

B.6 Enforceability [326 IAC 2-7-7] [IC 13-17-12]

B.7 Severability [326 IAC 2-7-5(5)]

B.8 Property Rights or Exclusive Privilege [326 IAC 2-7-5(6)(D)]

B.9 Duty to Provide Information [326 IAC 2-7-5(6)(E)]

B.10 Certification [326 IAC 2-7-4(f)][326 IAC 2-7-6(1)][326 IAC 2-7-5(3)(C)]

B.11 Annual Compliance Certification [326 IAC 2-7-6(5)]

B.12 Preventive Maintenance Plan [326 IAC 2-7-5(12)][326 IAC 1-6-3]

B.13 Emergency Provisions [326 IAC 2-7-16]

B.14 Permit Shield [326 IAC 2-7-15][326 IAC 2-7-20][326 IAC 2-7-12]

B.15 Prior Permits Superseded [326 IAC 2-1.1-9.5][326 IAC 2-7-10.5]

B.16 Termination of Right to Operate [326 IAC 2-7-10][326 IAC 2-7-4(a)]

B.17 Permit Modification, Reopening, Revocation and Reissuance, or Termination 

[326 IAC 2-7-5(6)(C)][326 IAC 2-7-8(a)][326 IAC 2-7-9]

B.18 Permit Renewal [326 IAC 2-7-3][326 IAC 2-7-4][326 IAC 2-7-8(e)]

B.19 Permit Amendment or Modification [326 IAC 2-7-11][326 IAC 2-7-12] [40 CFR 72]

B.20 Permit Revision Under Economic Incentives and Other Programs [326 IAC 2-7-5(8)]

[326 IAC 2-7-12(b)(2)]

B.21 Operational Flexibility [326 IAC 2-7-20][326 IAC 2-7-10.5]

B.22 Source Modification Requirement [326 IAC 2-7-10.5]

B.23 Inspection and Entry [326 IAC 2-7-6][IC 13-14-2-2][IC 13-30-3-1][IC 13-17-3-2]

B.24 Transfer of Ownership or Operational Control [326 IAC 2-7-11]

B.25 Annual Fee Payment [326 IAC 2-7-19] [326 IAC 2-7-5(7)][326 IAC 2-1.1-7]

B.26 Credible Evidence [326 IAC 2-7-5(3)][326 IAC 2-7-6][62 FR 8314] [326 IAC 1-1-6]

C. SOURCE OPERATION CONDITIONS

Emission Limitations and Standards [326 IAC 2-7-5(1)]

C.1 Opacity [326 IAC 5-1]

C.2 Open Burning [326 IAC 4-1] [IC 13-17-9]

C.3 Incineration [326 IAC 4-2] [326 IAC 9-1-2]
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C.4 Fugitive Dust Emissions [326 IAC 6-4]

C.5 Stack Height [326 IAC 1-7]

C.6 Asbestos Abatement Projects [326 IAC 14-10] [326 IAC 18] [40 CFR 61, Subpart M]

Testing Requirements [326 IAC 2-7-6(1)]

C.7 Performance Testing [326 IAC 3-6]

Compliance Requirements [326 IAC 2-1.1-11]

C.8 Compliance Requirements [326 IAC 2-1.1-11]

Compliance Monitoring Requirements [326 IAC 2-7-5(1)][326 IAC 2-7-6(1)]

C.9 Compliance Monitoring [326 IAC 2-7-5(3)][326 IAC 2-7-6(1)][40 CFR 64][326 IAC 3-8]

C.10 Instrument Specifications [326 IAC 2-1.1-11] [326 IAC 2-7-5(3)] 

[326 IAC 2-7-6(1)]

Corrective Actions and Response Steps [326 IAC 2-7-5][326 IAC 2-7-6]

C.11 Emergency Reduction Plans [326 IAC 1-5-2] [326 IAC 1-5-3]

C.12 Risk Management Plan [326 IAC 2-7-5(11)] [40 CFR 68]

C.13 Response to Excursions or Exceedances [40 CFR 64][326 IAC 3-8] [326 IAC 2-7-5] 

[326 IAC 2-7-6]

C.14 Actions Related to Noncompliance Demonstrated by a Stack Test [326 IAC 2-7-5]

[326 IAC 2-7-6]

Record Keeping and Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-19]

C.15 Emission Statement [326 IAC 2-7-5(3)(C)(iii)][326 IAC 2-7-5(7)][326 IAC 2-7-19(c)]

[326 IAC 2-6]

C.16 General Record Keeping Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-6] [326 IAC 2-2]

[326 IAC 2-3]

C.17 General Reporting Requirements [326 IAC 2-7-5(3)(C)] [326 IAC 2-1.1-11] 

[326 IAC 2-2] [40 CFR 64][326 IAC 3-8]

Stratospheric Ozone Protection

C.18 Compliance with 40 CFR 82 and 326 IAC 22-1

D.1. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.1.1 Permit No Defense 

Effective Date of the Permit

D.1.2 Effective Date of the Permit [IC 13-15-5-3]

D.1.3 Modification to Construction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.1.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

D.1.5 H2SO4 PSD BACT [326 IAC 2-2-3]

D.1.6 CO PSD BACT [326 IAC 2-2-3]

D.1.7 SO2 PSD BACT [326 IAC 2-2-3]
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D.1.8 VOC PSD BACT [326 IAC 2-2-3]

D.1.9 NOx PSD BACT [326 IAC 2-2-3]

D.1.10 GHGs PSD BACT [326 IAC 2-2-3]

D.1.11 Startup, Shutdown and Other Opacity Limits [326 IAC 5-1-3]

D.1.12 Preventive Maintenance Plan [326 IAC 2-7-5(12)]

Compliance Determination Requirements

D.1.13 Nitrogen Oxide Control 

D.1.14 Oxidation Catalyst Control

D.1.15 Greenhouse Gases (GHGs) Calculations 

D.1.16 Maintenance of Continuous Emission Monitoring Equipment [326 IAC 3-5][326 IAC 2-2-3]

D.1.17 Testing Requirements [326 IAC 2-1.1-11]

Compliance Monitoring Requirements [326 IAC 2-7-5(1)][326 IAC 2-7-6(1)]

D.1.18 Oxidation Catalyst Parametric Monitoring 

Record Keeping and Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-19]

D.1.19 Record Keeping Requirement

D.1.20 Reporting Requirements

D.2. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.2.1 Permit No Defense 

Effective Date of the Permit

D.2.2 Effective Date of the Permit [IC 13-15-5-3]

D.2.3 Modification to Construction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.2.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

D.2.5 CO PSD BACT [326 IAC 2-2-3]

D.2.6 SO2 PSD BACT [326 IAC 2-2-3]

D.2.7 NOx PSD BACT [326 IAC 2-2-3]

D.2.8 VOC PSD BACT [326 IAC 2-2-3]

D.2.9 GHGs PSD BACT [326 IAC 2-2-3]

D.2.10 Startup, Shutdown and Other Opacity Limits [326 IAC 5-1-3]

D.2.11 Preventive Maintenance Plan [326 IAC 2-7-5(12)]

Compliance Determination Requirements

D.2.12 Nitrogen Oxide Control 

D.2.13 Testing Requirements [326 IAC 2-1.1-11]

D.2.14 Compliance Determination Requirements [326 IAC 2-2-3]

D.2.15 Greenhouse Gases (GHGs) Calculations 

Record Keeping and Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-19]

D.2.16 Record Keeping Requirement

D.2.17 Reporting Requirements
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D.3. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.3.1 Permit No Defense 

Effective Date of the Permit

D.3.2 Effective Date of the Permit [IC 13-15-5-3]

D.3.3 Modification to Construction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.3.4 PM, PM10, PM2.5, NOx, VOC, CO, SO2, and GHGs PSD BACT [326 IAC 2-2-3]

D.3.5 PM, PM10, PM2.5, NOx, VOC, CO, SO2, and GHGs PSD BACT [326 IAC 2-2-3]

Compliance Determination Requirements

D.3.6 Greenhouse Gases (GHGs) Calculations

Record Keeping and Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-19]

D.3.7 Record Keeping Requirement

D.3.8 Reporting Requirements

D.4. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.4.1 Permit No Defense 

Effective Date of the Permit

D.4.2 Effective Date of the Permit [IC 13-15-5-3]

D.4.3 Modification to Construction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.4.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Compliance Determination Requirements

D.4.5 PM, PM10 and PM2.5 Control [326 IAC 2-1.1-11]

D.5. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.5.1 Permit No Defense 

Effective Date of the Permit

D.5.2 Effective Date of the Permit [IC 13-15-5-3]

D.5.3 Modification to Construction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.5.4 PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

D.5.5 Volatile Organic Compounds (VOC) PSD BACT [326 IAC 2-2-3]
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D.6. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.6.1 Permit No Defense 

Effective Date of the Permit

D.6.2 Effective Date of the Permit [IC 13-15-5-3]

D.6.3 Modification to Construction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.6.4 Volatile Organic Compounds (VOC) PSD BACT [326 IAC 2-2-3]

D.6.5 Prevention of Significant Deterioration (PSD) - Best Available Control Technology for 

Volatile Organic Compounds (VOC) [326 IAC 2-2-3][326 IAC 8-4-6]

D.6.6 Preventive Maintenance Plan [326 IAC 2-7-5(12)]

Compliance Determination Requirements

D.6.7 Volatile Organic Compounds Control 

Compliance Monitoring Requirements [326 IAC 2-7-5(1)][326 IAC 2-7-6(1)]

D.6.8 Vapor Recovery System Operation 

Record Keeping and Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-19]

D.6.9 Record Keeping Requirement

D.7. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.7.1 Permit No Defense 

Effective Date of the Permit

D.7.2 Effective Date of the Permit [IC 13-15-5-3]

D.7.3 Modification to Construction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.7.4 GHGs PSD BACT [326 IAC 2-2-3]

D.8. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.8.1 Permit No Defense 

Effective Date of the Permit

D.8.2 Effective Date of the Permit [IC 13-15-5-3]

D.8.3 Modification to Construction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.8.4 Particulate Matter Limitations [326 IAC 6.5-1-2]

D.9. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.9.1 Permit No Defense 
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Effective Date of the Permit

D.9.2 Effective Date of the Permit [IC 13-15-5-3]

D.9.3 Modification to Construction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.9.4 Volatile Organic Compounds (VOC) [326 IAC 8-3-2]

D.9.5 Volatile Organic Compounds (VOC) [326 IAC 8-3-5]

E.1. EMISSIONS UNIT OPERATION CONDITIONS

New Source Performance Standards [326 IAC 12][40 CFR 60, Subpart KKKK]

E.1.1 General Provisions Relating to New Source Performance Standard [326 IAC 12-1][40 CFR 

Part 60, Subpart A]

E.1.2 New Source Performance Standard for Stationary Combustion Turbines Requirements 

[40 CFR Part 60, Subpart KKKK] [326 IAC 12]

E.2. EMISSIONS UNIT OPERATION CONDITIONS

New Source Performance Standards [326 IAC 12][40 CFR 60, Subpart Dc]

E.2.1 General Provisions Relating to New Source Performance Standard [326 IAC 12-1][40 CFR 

Part 60, Subpart A]

E.2.2 New Source Performance Standard for Small-Commercial-Institutional Steam Generating 

Units Requirements [40 CFR Part 60, Subpart Dc] [326 IAC 12]

E.3. EMISSIONS UNIT OPERATION CONDITIONS

New Source Performance Standards [326 IAC 12][40 CFR 60, Subpart IIII]

E.3.1 General Provisions Relating to NSPS IIII [326 IAC 12][40 CFR Part 60, Subpart A]

E.3.2 Standard of Performance for Stationary Compression Inginition Internal Combustion 

Engines [326 IAC 12][40 CFR Part 60, Subpart IIII]

E.4. EMISSIONS UNIT OPERATION CONDITIONS

National Emission Standard for Hazardous Air Pollutants [326 IAC 20][40 CFR 63, Subpart ZZZZ]

E.4.1 General Provisions Relating to National Emissions Standard for Hazardous Air Pollutants 

for Stationary Reciprocating Internal Combustion Engines [326 IAC 20-1][40 CFR Part 

63, Subpart A]

E.4.1 National Emissions Standard for Hazardous Air Pollutants for Stationary 

Reciprocating Internal Combustion Engines [40 CFR Part 63, Subpart ZZZZ] [326 IAC 

20-82-1]

SECTION F Clean Air Interstate (CAIR) Nitrogen Oxides Annual, Sulfur Dioxide, and Nitrogen 

Oxides Ozone Season Trading Programs – CAIR Permit for CAIR Units Under 326 

IAC 24-1-1(a), 326 IAC 24-2-1(a), and 326 IAC 24-3-1(a)

F.1 Automatic Incorporation of Definitions [326 IAC 24-1-7(e)] [326 IAC 24-2-7(e)] 
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[326 IAC 24-3-7(e)] [40 CFR 97.123(b)] [40 CFR 97.223(b)] [40 CFR 97.323(b)]

F.2 Standard Permit Requirements [326 IAC 24-1-4(a)] [326 IAC 24-2-4(a)]

[326 IAC 24-3-4(a)] [40 CFR 97.106(a)] [40 CFR 97.206(a)] [40 CFR 97.306(a)]

F.3 Monitoring, Reporting, and Record Keeping Requirements [326 IAC 24-1-4(b)] 

[326 IAC 24-2-4(b)] [326 IAC 24-3-4(b)] [40 CFR 97.106(b)] [40 CFR 97.206(b)] 

[40 CFR 97.306(b)]

F.4.1 Nitrogen Oxides Emission Requirements [326 IAC 24-1-4(c)] [40 CFR 97.106(c)]

F.4.2 Sulfur Dioxide Emission Requirements [326 IAC 24-2-4(c)] [40 CFR 97.206(c)]

F.4.3 Nitrogen Oxides Ozone Season Emission Requirements [326 IAC 24-3-4(c)] 

[40 CFR 97.306(c)]

F.5 Excess Emissions Requirements [326 IAC 24-1-4(d)] [326 IAC 24-2-4(d)] 

[326 IAC 24-3-4(d)] [40 CFR 97.106(d)] [40 CFR 97.206(d)] [40 CFR 97.306(d)]

F.6 Record Keeping Requirements [326 IAC 24-1-4(e)] [326 IAC 24-2-4(e)]

[326 IAC 24-3-4(e)] [326 IAC 2-7-5(3)] [40 CFR 97.106(e)] [40 CFR 97.206(e)] 

[40 CFR 97.306(e)]

F.7 Reporting Requirements [326 IAC 24-1-4(e)] [326 IAC 24-2-4(e)] [326 IAC 24-3-4(e)]

[40 CFR 97.106(e)] [40 CFR 97.206(e)] [40 CFR 97.306(e)]

F.8 Liability [326 IAC 24-1-4(f)] [326 IAC 24-2-4(f)] [326 IAC 24-3-4(f)] [40 CFR 97.106(f)] 

[40 CFR 97.206(f)] [40 CFR 97.306(f)]

F.9 Effect on Other Authorities [326 IAC 24-1-4(g)] [326 IAC 24-2-4(g)] [326 IAC 24-3-4(g)]

[40 CFR 97.106(g)] [40 CFR 97.206(g)] [40 CFR 97.306(g)]

F.10 CAIR Designated Representative and Alternate CAIR Designated Representative 

[326 IAC 24-1-6] [326 IAC 24-2-6] [326 IAC 24-3-6] [40 CFR 97, Subpart BB] [40 CFR 97, 

Subpart BBB] [40 CFR 97, Subpart BBBB]

Certification

Emergency Occurrence Report

Quarterly Report

Quarterly Deviation and Compliance Monitoring Report

Affidavit of Construction

Attachment A - NSPS 40 CFR 60, Subpart Dc

Attachment B - NSPS 40 CFR 60, Subpart IIII

Attachment C - NSPS 40 CFR 60, Subpart KKKK 

Attachment D - NESHAP 40 CFR 63, Subpart ZZZZ
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SECTION A SOURCE SUMMARY

This permit is based on information requested by the Indiana Department of Environmental Management 

(IDEM), Office of Air Quality (OAQ). The information describing the source contained in conditions A.1 

through A.3 is descriptive information and does not constitute enforceable conditions. However, the 

Permittee should be aware that a physical change or a change in the method of operation that may 

render this descriptive information obsolete or inaccurate may trigger requirements for the Permittee to 

obtain additional permits or seek modification of this permit pursuant to 326 IAC 2, or change other 

applicable requirements presented in the permit application.

A.1 General Information [326 IAC 2-7-4(c)][326 IAC 2-7-5(14)][326 IAC 2-7-1(22)]

The Permittee owns and operates a stationary electric utility generating station. 

Source Address: Corner of Walnut and Edison Roads, New Carlisle, 

Indiana 46552

General Source Phone Number: 914-468-2402

SIC Code: 4991

County Location: St. Joseph

Source Location Status: Attainment for all criteria pollutants 

Source Status: Part 70 Operating Permit Program 

Major Source, under PSD Rules

Minor Source, Section 112 of the Clean Air Act

1 of 28 Source Categories

A.2 Emission Units and Pollution Control Equipment Summary [326 IAC 2-7-4(c)(3)]

[326 IAC 2-7-5(14)]

This stationary source consists of the following emission units and pollution control devices:

(a) Four (4) natural gas-fired combined cycle combustion turbines, identified as units 

CCCT1, CCCT2, CCCT3, and CCCT4, permitted in 2012, each with a combustion turbine 

equipped with dry low NOx burners, natural gas fired duct burners, and a heat recovery 

steam generator identified as HRSG1, HRSG2, HRSG3, and HRSG4, NOx emissions 

controlled by four (4) selective catalytic reduction (SCR) systems (SCR01, SCR02, 

SCR03 and SCR04), CO and VOC emissions controlled by oxidation catalyst systems

(CAT01, CAT02, CAT03 and CAT04) and exhausting to stacks CCCT01, CCCT02, 

CCCT03, and CCCT04, respectively. Each stack has continuous emissions monitors 

(CEMS) for NOx and CO. The nominal heat input for each CCCT is 2,300 MMBtu/hr

(higher heating value (HHV)). The combined nominal power output is 1,350 megawatts 

(MW). 

*Note: The heat recovery steam generators are not a source of emissions. They have 

been included for clarity as they are a part of the entire source and operate in 

conjunction with the duct burners which are a source of emissions.

(b) Two (2) natural gas fired auxiliary boilers, identified as B001 and B002, permitted in 

2012, each, with a maximum heat input capacity of 80 MMBtu/hr (HHV), equipped with 

low NOx burners (LNB) with flue gas recirculation (FGR) to reduce NOx emissions, and 

exhausting to stacks B001 and B002. Under 40 CFR Part 60, Subpart Dc, the auxiliary 

boiler is considered a steam generating unit.
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(c) One (1) emergency diesel generator, nominally rated at 2012 horsepower, identified as 

EG03, permitted in 2012, exhausting through one (1) vent, identified as EG03. [Under 40 

CFR 60, Subpart IIII, the emergency diesel fired generator is considered a new affected 

source.][Under 40 CFR 63, Subpart ZZZZ, the emergency diesel fired generator is 

considered a new affected source.]

A.3 Specifically Regulated Insignificant Activities [326 IAC 2-7-1(21)] [326 IAC 2-7-4(c)]

[326 IAC 2-7-5(14)]

This stationary source also includes the following insignificant activities which are specifically 

regulated, as defined in 326 IAC 2-7-1(21):

(a) Two (2) firewater pump engines, each nominally rated at 371 brake horsepower (bph)

and identified as FP01 and FP02, permitted in 2012, exhausting through two (2) vents, 

identified as FP01 and FP02, respectively. [Under 40 CFR 60, Subpart IIII, the firewater 

pump engines are considered new affected sources.][Under 40 CFR 63, Subpart ZZZZ, 

the firewater pump engines are considered new affected sources.]

(b) Two (2) emergency diesel generators, each nominally rated at 1,006 horsepower, 

identified as EG01 and EG02, permitted in 2012, exhausting through two (2) vents, 

identified as EG01 and EG02, respectively. [Under 40 CFR 60, Subpart IIII, the 

emergency diesel fired generators are considered new affected sources.][Under 40 CFR 

63, Subpart ZZZZ, the emergency diesel fired generators are considered new affected 

source.]

(c) Two (2) cooling towers, each nominally rated with a circulation rate of 170,000 gpm , 

identified as CT01 and CT02, permitted in 2012, with high efficiency drift/mist eliminators, 

and exhausting through ten vents each, identified as CT01A – CT01J and CT02A –

CT02J.

(d) Six (6) Turbine Lube Demister Vents, identified as DM01 - DM06, permitted in 2012, 

exhausting through vents DM01 – DM06.

(e) Six (6) Turbine Lube Oil storage tanks, identified as TK01 - TK06, permitted in 2012, 

each with a nominal capacity of 6,800 gallons.

(f) Two (2) Emergency Generator ULSD Tanks, identified as TK07 and TK08, permitted in 

2012, each with a nominal capacity of 550 gallons.

(g) Two (2) Fire Pump Engine ULSD Tanks, identified as TK09 and TK10, permitted in 2012, 

each with a nominal capacity of 70 gallons.

(h) One (1) Vehicle Gasoline dispensing Tank, identified as TK11, permitted in 2012, with a 

nominal capacity of 650 gallons, equipped with submerged fill and stage 1 vapor balance.

(i) One (1) Vehicle Diesel Tank, identified as TK12, permitted in 2012, with a nominal 

capacity of 650 gallons.
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(j) One (1) Emergency Generator ULSD Tank, identified as TK50, permitted in 2012, with a 

nominal capacity of 300 gallons;

(k) two (2) lime storage silos, capable of handling a maximum loading rate of 20 tons per 

hour combined, permitted in 2012 and with particulate matter controlled by bin vent 

filters exhausting to Stacks S1 and S2; 

(l) Six (6) Electrical Circuit Breakers containing sulfur hexafluoride (SF6) identified as 

emissions unit SF6, permitted in 2012, with fugitive GHG emissions;

(m) Degreasing operations that do not exceed one hundred forty-five (145) gallons per 12 

months, except if subject to 326 IAC 20-6. [326 IAC 8-3]; and 

(n) Paved and unpaved roads and parking lots with public access. [326 IAC 6-4]

A.4 Part 70 Permit Applicability [326 IAC 2-7-2]

This stationary source is required to have a Part 70 permit by 326 IAC 2-7-2 (Applicability) 

because: 

(a) It is a major source, as defined in 326 IAC 2-7-1(22);

(b) It is a source in a source category designated by the United States Environmental 

Protection Agency (U.S. EPA) under 40 CFR 70.3 (Part 70 - Applicability); and

(c) It is an affected source under Title IV (Acid Deposition Control) of the Clean Air Act, as 

defined in 326 IAC 2-7-1(3).
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SECTION B GENERAL CONDITIONS

B.1 Definitions [326 IAC 2-7-1]

Terms in this permit shall have the definition assigned to such terms in the referenced regulation. 

In the absence of definitions in the referenced regulation, the applicable definitions found in the 

statutes or regulations (IC 13-11, 326 IAC 1-2 and 326 IAC 2-7) shall prevail. 

B.2 Revocation of Permits [326 IAC 2-1.1-9(5)]

Pursuant to 326 IAC 2-1.1-9(5)(Revocation of Permits), the Commissioner may revoke this permit 

if construction is not commenced within eighteen (18) months after receipt of this approval or if 

construction is suspended for a continuous period of one (1) year or more.

B.3 Affidavit of Construction [326 IAC 2-5.1-3(h)] [326 IAC 2-5.1-4]

This document shall also become the approval to operate pursuant to 326 IAC 2-5.1-4 when prior 

to the start of operation, the following requirements are met:

(a) The attached Affidavit of Construction shall be submitted to the Office of Air Quality 

(OAQ), verifying that the emission units were constructed as proposed in the application 

or the permit. The emission units covered in this permit may begin operating on the date 

the Affidavit of Construction is postmarked or hand delivered to IDEM if constructed as 

proposed.

(b) If actual construction of the emission units differs from the construction proposed in the 

application, the source may not begin operation until the permit has been revised 

pursuant to 326 IAC 2 and an Operation Permit Validation Letter is issued.

(c) The Permittee shall attach the Operation Permit Validation Letter received from the Office 

of Air Quality (OAQ) to this permit.

B.4 Permit Term [326 IAC 2-7-5(2)][326 IAC 2-1.1-9.5][326 IAC 2-7-4(a)(1)(D)][IC 13-15-3-6(a)]

(a) This permit, T141-31003-00579, is issued for a fixed term of five (5) years from the 

issuance date of this permit, as determined in accordance with IC 4-21.5-3-5(f) and 

IC 13-15-5-3. Subsequent revisions, modifications, or amendments of this permit do not 

affect the expiration date of this permit or of permits issued pursuant to Title IV of the 

Clean Air Act and 326 IAC 21 (Acid Deposition Control).

(b) If IDEM, OAQ, upon receiving a timely and complete renewal permit application, fails to 

issue or deny the permit renewal prior to the expiration date of this permit, this existing 

permit shall not expire and all terms and conditions shall continue in effect, including any 

permit shield provided in 326 IAC 2-7-15, until the renewal permit has been issued or 

denied.

B.5 Term of Conditions [326 IAC 2-1.1-9.5]

Notwithstanding the permit term of a permit to construct, a permit to operate, or a permit 

modification, any condition established in a permit issued pursuant to a permitting program 

approved in the state implementation plan shall remain in effect until:

(a) the condition is modified in a subsequent permit action pursuant to Title I of the Clean Air 

Act; or
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(b) the emission unit to which the condition pertains permanently ceases operation.

B.6 Enforceability [326 IAC 2-7-7] [IC 13-17-12]

Unless otherwise stated, all terms and conditions in this permit, including any provisions designed 

to limit the source's potential to emit, are enforceable by IDEM, the United States Environmental 

Protection Agency (U.S. EPA) and by citizens in accordance with the Clean Air Act. 

B.7 Severability [326 IAC 2-7-5(5)]

The provisions of this permit are severable; a determination that any portion of this permit is 

invalid shall not affect the validity of the remainder of the permit.

B.8 Property Rights or Exclusive Privilege [326 IAC 2-7-5(6)(D)]

This permit does not convey any property rights of any sort or any exclusive privilege.

B.9 Duty to Provide Information [326 IAC 2-7-5(6)(E)]

(a) The Permittee shall furnish to IDEM, OAQ, within a reasonable time, any information that 

IDEM, OAQ 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 IDEM, OAQ copies of records 

required to be kept by this permit.

(b) For information furnished by the Permittee to IDEM, OAQ, the Permittee may include a 

claim of confidentiality in accordance with 326 IAC 17.1. When furnishing copies of 

requested records directly to U. S. EPA, the Permittee may assert a claim of 

confidentiality in accordance with 40 CFR 2, Subpart B.

B.10 Certification [326 IAC 2-7-4(f)][326 IAC 2-7-6(1)][326 IAC 2-7-5(3)(C)]

(a) A certification required by this permit meets the requirements of 326 IAC 2-7-6(1) if: 

(1) it contains a certification by a "responsible official" as defined by 

326 IAC 2-7-1(34), and

(2) the certification states that, based on information and belief formed after 

reasonable inquiry, the statements and information in the document are true, 

accurate, and complete. 

(b) The Permittee may use the attached Certification Form, or its equivalent with each 

submittal requiring certification. One (1) certification may cover multiple forms in one (1) 

submittal.

(c) A "responsible official" is defined at 326 IAC 2-7-1(34).

B.11 Annual Compliance Certification [326 IAC 2-7-6(5)]

(a) The Permittee shall annually submit a compliance certification report which addresses 

the status of the source’s compliance with the terms and conditions contained in this 

permit, including emission limitations, standards, or work practices. The initial 

certification shall cover the time period from the date of final permit issuance through 

December 31 of the same year. All subsequent certifications shall cover the time period 
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from January 1 to December 31 of the previous year, and shall be submitted no later than 

April 15 of each year to:

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

and

United States Environmental Protection Agency, Region V

Air and Radiation Division, Air Enforcement Branch - Indiana (AE-17J)

77 West Jackson Boulevard

Chicago, Illinois 60604-3590

(b) The annual compliance certification report required by this permit shall be considered 

timely if the date postmarked on the envelope or certified mail receipt, or affixed by the 

shipper on the private shipping receipt, is on or before the date it is due. If the document 

is submitted by any other means, it shall be considered timely if received by IDEM, OAQ, 

on or before the date it is due.

(c) The annual compliance certification report shall include the following:

(1) The appropriate identification of each term or condition of this permit that is the 

basis of the certification;

(2) The compliance status;

(3) Whether compliance was continuous or intermittent;

(4) The methods used for determining the compliance status of the source, currently 

and over the reporting period consistent with 326 IAC 2-7-5(3); and

(5) Such other facts, as specified in Sections D of this permit, as IDEM, OAQ may 

require to determine the compliance status of the source.

The submittal by the Permittee does require a certification that meets the requirements of 

326 IAC 2-7-6(1) by a "responsible official" as defined by 326 IAC 2-7-1(34).

B.12 Preventive Maintenance Plan [326 IAC 2-7-5(12)][326 IAC 1-6-3]

(a) If required by specific condition(s) in Section D of this permit, the Permittee shall prepare 

and maintain Preventive Maintenance Plans (PMPs) no later than ninety (90) days after 

issuance of this permit or ninety (90) days after initial start-up, whichever is later, 

including the following information on each facility:

(1) Identification of the individual(s) responsible for inspecting, maintaining, and 

repairing emission control devices;
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(2) A description of the items or conditions that will be inspected and the inspection 

schedule for said items or conditions; and

(3) Identification and quantification of the replacement parts that will be maintained 

in inventory for quick replacement.

If, due to circumstances beyond the Permittee’s control, the PMPs cannot be prepared 

and maintained within the above time frame, the Permittee may extend the date an 

additional ninety (90) days provided the Permittee notifies:

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

The PMP extension notification does not require a certification that meets the 

requirements of 326 IAC 2-7-6(1) by a "responsible official" as defined by 

326 IAC 2-7-1(34).

The Permittee shall implement the PMPs.

(b) A copy of the PMPs shall be submitted to IDEM, OAQ upon request and within a 

reasonable time, and shall be subject to review and approval by IDEM, OAQ. IDEM, 

OAQ may require the Permittee to revise its PMPs whenever lack of proper maintenance 

causes or is the primary contributor to an exceedance of any limitation on emissions. The 

PMPs and their submittal do not require a certification that meets the requirements of

326 IAC 2-7-6(1) by a "responsible official" as defined by 326 IAC 2-7-1(34).

(c) To the extent the Permittee is required by 40 CFR Part 60/63 to have an Operation 

Maintenance, and Monitoring (OMM) Plan for a unit, such Plan is deemed to satisfy the 

PMP requirements of 326 IAC 1-6-3 for that unit.

B.13 Emergency Provisions [326 IAC 2-7-16]

(a) An emergency, as defined in 326 IAC 2-7-1(12), is not an affirmative defense for an 

action brought for noncompliance with a federal or state health-based emission limitation.

(b) An emergency, as defined in 326 IAC 2-7-1(12), constitutes an affirmative defense to an 

action brought for noncompliance with a technology-based emission limitation if the 

affirmative defense of an emergency is demonstrated through properly signed, 

contemporaneous operating logs or other relevant evidence that describe the following:

(1) An emergency occurred and the Permittee can, to the extent possible, identify 

the causes of the emergency;

(2) The permitted facility was at the time being properly operated;
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(3) During the period of an emergency, the Permittee took all reasonable steps to 

minimize levels of emissions that exceeded the emission standards or other 

requirements in this permit;

(4) For each emergency lasting one (1) hour or more, the Permittee notified IDEM, 

OAQ, or Northern Regional Office within four (4) daytime business hours after 

the beginning of the emergency, or after the emergency was discovered or 

reasonably should have been discovered; 

Telephone Number: 1-800-451-6027 (ask for Office of Air Quality, 

Compliance and Enforcement Branch), or

Telephone Number: 317-233-0178 (ask for Office of Air Quality, 

Compliance and Enforcement Branch)

Facsimile Number: 317-233-6865

Northern Regional Office phone: (574) 245-4870; fax: (574) 245-4877.

(5) For each emergency lasting one (1) hour or more, the Permittee submitted the 

attached Emergency Occurrence Report Form or its equivalent, either by mail or 

facsimile to:

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

within two (2) working days of the time when emission limitations were exceeded 

due to the emergency.

The notice fulfills the requirement of 326 IAC 2-7-5(3)(C)(ii) and must contain the 

following:

(A) A description of the emergency;

(B) Any steps taken to mitigate the emissions; and

(C) Corrective actions taken.

The notification which shall be submitted by the Permittee does not require a 

certification that meets the requirements of 326 IAC 2-7-6(1) by a "responsible 

official" as defined by 326 IAC 2-7-1(34).

(6) The Permittee immediately took all reasonable steps to correct the emergency.

(c) In any enforcement proceeding, the Permittee seeking to establish the occurrence of an 

emergency has the burden of proof.
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(d) This emergency provision supersedes 326 IAC 1-6 (Malfunctions). This permit condition 

is in addition to any emergency or upset provision contained in any applicable 

requirement.

(e) The Permittee seeking to establish the occurrence of an emergency shall make records 

available upon request to ensure that failure to implement a PMP did not cause or 

contribute to an exceedance of any limitations on emissions. However, IDEM, OAQ may 

require that the Preventive Maintenance Plans required under 326 IAC 2-7-4(c)(8) be 

revised in response to an emergency.

(f) Failure to notify IDEM, OAQ by telephone or facsimile of an emergency lasting more than 

one (1) hour in accordance with (b)(4) and (5) of this condition shall constitute a violation 

of 326 IAC 2-7 and any other applicable rules.

(g) If the emergency situation causes a deviation from a technology-based limit, the 

Permittee may continue to operate the affected emitting facilities during the emergency 

provided the Permittee immediately takes all reasonable steps to correct the emergency 

and minimize emissions.

B.14 Permit Shield [326 IAC 2-7-15][326 IAC 2-7-20][326 IAC 2-7-12]

(a) Pursuant to 326 IAC 2-7-15, the Permittee has been granted a permit shield. The permit 

shield provides that compliance with the conditions of this permit shall be deemed 

compliance with any applicable requirements as of the date of permit issuance, provided 

that either the applicable requirements are included and specifically identified in this 

permit or the permit contains an explicit determination or concise summary of a 

determination that other specifically identified requirements are not applicable. The 

Indiana statutes from IC 13 and rules from 326 IAC, referenced in conditions in this 

permit, are those applicable at the time the permit was issued. The issuance or 

possession of this permit shall not alone constitute a defense against an alleged violation 

of any law, regulation or standard, except for the requirement to obtain a Part 70 permit 

under 326 IAC 2-7 or for applicable requirements for which a permit shield has been 

granted.

This permit shield does not extend to applicable requirements which are promulgated 

after the date of issuance of this permit unless this permit has been modified to reflect 

such new requirements.

(b) If, after issuance of this permit, it is determined that the permit is in nonconformance with 

an applicable requirement that applied to the source on the date of permit issuance, 

IDEM, OAQ, shall immediately take steps to reopen and revise this permit and issue a 

compliance order to the Permittee to ensure expeditious compliance with the applicable 

requirement until the permit is reissued. The permit shield shall continue in effect so long 

as the Permittee is in compliance with the compliance order.

(c) No permit shield shall apply to any permit term or condition that is determined after 

issuance of this permit to have been based on erroneous information supplied in the 

permit application. Erroneous information means information that the Permittee knew to 

be false, or in the exercise of reasonable care should have been known to be false, at the 

time the information was submitted.
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(d) Nothing in 326 IAC 2-7-15 or in this permit shall alter or affect the following:

(1) The provisions of Section 303 of the Clean Air Act (emergency orders), including 

the authority of the U.S. EPA under Section 303 of the Clean Air Act;

(2) The liability of the Permittee for any violation of applicable requirements prior to 

or at the time of this permit's issuance;

(3) The applicable requirements of the acid rain program, consistent with Section 

408(a) of the Clean Air Act; and

(4) The ability of U.S. EPA to obtain information from the Permittee under Section 

114 of the Clean Air Act.

(e) This permit shield is not applicable to any change made under 326 IAC 2-7-20(b)(2) 

(Sections 502(b)(10) of the Clean Air Act changes) and 326 IAC 2-7-20(c)(2) (trading 

based on State Implementation Plan (SIP) provisions).

(f) This permit shield is not applicable to modifications eligible for group processing until 

after IDEM, OAQ, has issued the modifications. [326 IAC 2-7-12(c)(7)]

(g) This permit shield is not applicable to minor Part 70 permit modifications until after IDEM, 

OAQ, has issued the modification. [326 IAC 2-7-12(b)(8)]

B.15 Prior Permits Superseded [326 IAC 2-1.1-9.5][326 IAC 2-7-10.5]

(a) All terms and conditions of permits established prior to T141-31003-00579 and issued 

pursuant to permitting programs approved into the state implementation plan have been 

either:

(1) incorporated as originally stated,

(2) revised under 326 IAC 2-7-10.5, or

(3) deleted under 326 IAC 2-7-10.5.

(b) Provided that all terms and conditions are accurately reflected in this combined permit, all 

previous registrations and permits are superseded by this combined new source review 

and part 70 operating permit, except for permits issued pursuant to Title IV of the Clean 

Air Act and 326 IAC 21 (Acid Deposition Control)

B.16 Termination of Right to Operate [326 IAC 2-7-10][326 IAC 2-7-4(a)]

The Permittee's right to operate this source terminates with the expiration of this permit unless a 

timely and complete renewal application is submitted at least nine (9) months prior to the date of 

expiration of the source’s existing permit, consistent with 326 IAC 2-7-3 and 326 IAC 2-7-4(a).
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B.17 Permit Modification, Reopening, Revocation and Reissuance, or Termination 

[326 IAC 2-7-5(6)(C)][326 IAC 2-7-8(a)][326 IAC 2-7-9]

(a) This permit may be modified, reopened, revoked and reissued, or terminated for cause. 

The filing of a request by the Permittee for a Part 70 Operating Permit modification, 

revocation and reissuance, or termination, or of a notification of planned changes or 

anticipated noncompliance does not stay any condition of this permit. 

[326 IAC 2-7-5(6)(C)] The notification by the Permittee does require a certification that 

meets the requirements of 326 IAC 2-7-6(1) by a "responsible official" as defined by 

326 IAC 2-7-1(34).

(b) This permit shall be reopened and revised under any of the circumstances listed in 

IC 13-15-7-2 or if IDEM, OAQ determines any of the following:

(1) That this permit contains a material mistake.

(2) That inaccurate statements were made in establishing the emissions standards 

or other terms or conditions.

(3) That this permit must be revised or revoked to assure compliance with an 

applicable requirement. [326 IAC 2-7-9(a)(3)]

(c) Proceedings by IDEM, OAQ to reopen and revise this permit shall follow the same 

procedures as apply to initial permit issuance and shall affect only those parts of this 

permit for which cause to reopen exists. Such reopening and revision shall be made as 

expeditiously as practicable. [326 IAC 2-7-9(b)]

(d) The reopening and revision of this permit, under 326 IAC 2-7-9(a), shall not be initiated 

before notice of such intent is provided to the Permittee by IDEM, OAQ at least thirty (30) 

days in advance of the date this permit is to be reopened, except that IDEM, OAQ may 

provide a shorter time period in the case of an emergency. [326 IAC 2-7-9(c)]

B.18 Permit Renewal [326 IAC 2-7-3][326 IAC 2-7-4][326 IAC 2-7-8(e)]

(a) The application for renewal shall be submitted using the application form or forms 

prescribed by IDEM, OAQ and shall include the information specified in 326 IAC 2-7-4. 

Such information shall be included in the application for each emission unit at this source, 

except those emission units included on the trivial or insignificant activities list contained 

in 326 IAC 2-7-1(21) and 326 IAC 2-7-1(40). The renewal application does require a 

certification that meets the requirements of 326 IAC 2-7-6(1) by a "responsible official" as 

defined by 326 IAC 2-7-1(34).

Request for renewal shall be submitted to:

Indiana Department of Environmental Management

Permit Administration and Support Section, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

(b) A timely renewal application is one that is:
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(1) Submitted at least nine (9) months prior to the date of the expiration of this 

permit; and

(2) If the date postmarked on the envelope or certified mail receipt, or affixed by the 

shipper on the private shipping receipt, is on or before the date it is due. If the 

document is submitted by any other means, it shall be considered timely if 

received by IDEM, OAQ on or before the date it is due.

(c) If the Permittee submits a timely and complete application for renewal of this permit, the 

source’s failure to have a permit is not a violation of 326 IAC 2-7 until IDEM, OAQ takes 

final action on the renewal application, except that this protection shall cease to apply if,

subsequent to the completeness determination, the Permittee fails to submit by the 

deadline specified, pursuant to 326 IAC 2-7-4(a)(2)(D), in writing by IDEM, OAQ any 

additional information identified as being needed to process the application.

B.19 Permit Amendment or Modification [326 IAC 2-7-11][326 IAC 2-7-12] [40 CFR 72]

(a) Permit amendments and modifications are governed by the requirements of

326 IAC 2-7-11 or 326 IAC 2-7-12 whenever the Permittee seeks to amend or modify 

this permit.

(b) Pursuant to 326 IAC 2-7-11(b) and 326 IAC 2-7-12(a), administrative Part 70 operating 

permit amendments and permit modifications for purposes of the acid rain portion of a 

Part 70 permit shall be governed by regulations promulgated under Title IV of the Clean 

Air Act. [40 CFR 72]

(c) Any application requesting an amendment or modification of this permit shall be 

submitted to:

Indiana Department of Environmental Management

Permit Administration and Support Section, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

Any such application does require a certification that meets the requirements of 

326 IAC 2-7-6(1) by a "responsible official" as defined by 326 IAC 2-7-1(34).

(d) The Permittee may implement administrative amendment changes addressed in the 

request for an administrative amendment immediately upon submittal of the request. 

[326 IAC 2-7-11(c)(3)]
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B.20 Permit Revision Under Economic Incentives and Other Programs [326 IAC 2-7-5(8)]

[326 IAC 2-7-12(b)(2)]

(a) No Part 70 permit revision or notice shall be required under any approved economic 

incentives, marketable Part 70 permits, emissions trading, and other similar programs or 

processes for changes that are provided for in a Part 70 permit.

(b) Notwithstanding 326 IAC 2-7-12(b)(1) and 326 IAC 2-7-12(c)(1), minor Part 70 permit 

modification procedures may be used for Part 70 modifications involving the use of 

economic incentives, marketable Part 70 permits, emissions trading, and other similar 

approaches to the extent that such minor Part 70 permit modification procedures are 

explicitly provided for in the applicable State Implementation Plan (SIP) or in applicable 

requirements promulgated or approved by the U.S. EPA.

B.21 Operational Flexibility [326 IAC 2-7-20][326 IAC 2-7-10.5]

(a) The Permittee may make any change or changes at the source that are described in 

326 IAC 2-7-20(b) or (c) without a prior permit revision, if each of the following conditions 

is met:

(1) The changes are not modifications under any provision of Title I of the Clean Air 

Act;

(2) Any preconstruction approval required by 326 IAC 2-7-10.5 has been obtained;

(3) The changes do not result in emissions which exceed the limitations provided in 

this permit (whether expressed herein as a rate of emissions or in terms of total 

emissions);

(4) The Permittee notifies the:

Indiana Department of Environmental Management

Permit Administration and Support Section, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

and

United States Environmental Protection Agency, Region V

Air and Radiation Division, Regulation Development Branch - Indiana (AR-18J)

77 West Jackson Boulevard

Chicago, Illinois 60604-3590

in advance of the change by written notification at least ten (10) days in advance 

of the proposed change. The Permittee shall attach every such notice to the 

Permittee's copy of this permit; and

(5) The Permittee maintains records on-site, on a rolling five (5) year basis, which 

document all such changes and emission trades that are subject to 
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326 IAC 2-7-20(b) or (c). The Permittee shall make such records available, upon 

reasonable request, for public review. 

Such records shall consist of all information required to be submitted to IDEM, 

OAQ in the notices specified in 326 IAC 2-7-20(b)(1) and (c)(1).

(b) The Permittee may make Section 502(b)(10) of the Clean Air Act changes (this term is 

defined at 326 IAC 2-7-1(36)) without a permit revision, subject to the constraint of 

326 IAC 2-7-20(a). For each such Section 502(b)(10) of the Clean Air Act change, the 

required written notification shall include the following:

(1) A brief description of the change within the source;

(2) The date on which the change will occur;

(3) Any change in emissions; and 

(4) Any permit term or condition that is no longer applicable as a result of the 

change.

The notification which shall be submitted is not considered an application form, report or 

compliance certification. Therefore, the notification by the Permittee does not require a 

certification that meets the requirements of 326 IAC 2-7-6(1) by a "responsible official" as 

defined by 326 IAC 2-7-1(34).

(c) Emission Trades [326 IAC 2-7-20(c)]

The Permittee may trade emissions increases and decreases at the source, where the 

applicable SIP provides for such emission trades without requiring a permit revision, 

subject to the constraints of Section (a) of this condition and those in 326 IAC 2-7-20(c).

(d) Alternative Operating Scenarios [326 IAC 2-7-20(d)]

The Permittee may make changes at the source within the range of alternative operating 

scenarios that are described in the terms and conditions of this permit in accordance with 

326 IAC 2-7-5(9). No prior notification of IDEM, OAQ, or U.S. EPA is required.

(e) Backup fuel switches specifically addressed in, and limited under, Section D of this permit 

shall not be considered alternative operating scenarios. Therefore, the notification 

requirements of part (a) of this condition do not apply.

(f) This condition does not apply to emission trades of SO2 or NOX under 326 IAC 21 or 

326 IAC 10-4.

B.22 Source Modification Requirement [326 IAC 2-7-10.5]

A modification, construction, or reconstruction is governed by the requirements of 326 IAC 2.

B.23 Inspection and Entry [326 IAC 2-7-6][IC 13-14-2-2][IC 13-30-3-1][IC 13-17-3-2]

Upon presentation of proper identification cards, credentials, and other documents as may be 

required by law, and subject to the Permittee's right under all applicable laws and regulations to 

assert that the information collected by the agency is confidential and entitled to be treated as 
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Permit Reviewer: Josiah Balogun

such, the Permittee shall allow IDEM, OAQ, U.S. EPA, or an authorized representative to perform 

the following:

(a) Enter upon the Permittee's premises where a Part 70 source is located, or emissions 

related activity is conducted, or where records must be kept under the conditions of this 

permit;

(b) As authorized by the Clean Air Act, IC 13-14-2-2, IC 13-17-3-2, and IC 13-30-3-1, have 

access to and copy any records that must be kept under the conditions of this permit;

(c) As authorized by the Clean Air Act, IC 13-14-2-2, IC 13-17-3-2, and IC 13-30-3-1, inspect 

any facilities, equipment (including monitoring and air pollution control equipment), 

practices, or operations regulated or required under this permit; 

(d) As authorized by the Clean Air Act, IC 13-14-2-2, IC 13-17-3-2, and IC 13-30-3-1, sample 

or monitor substances or parameters for the purpose of assuring compliance with this 

permit or applicable requirements; and

(e) As authorized by the Clean Air Act, IC 13-14-2-2, IC 13-17-3-2, and IC 13-30-3-1, utilize 

any photographic, recording, testing, monitoring, or other equipment for the purpose of 

assuring compliance with this permit or applicable requirements.

B.24 Transfer of Ownership or Operational Control [326 IAC 2-7-11]

(a) The Permittee must comply with the requirements of 326 IAC 2-7-11 whenever the 

Permittee seeks to change the ownership or operational control of the source and no 

other change in the permit is necessary.

(b) Any application requesting a change in the ownership or operational control of the source 

shall contain a written agreement containing a specific date for transfer of permit 

responsibility, coverage and liability between the current and new Permittee. The 

application shall be submitted to:

Indiana Department of Environmental Management

Permit Administration and Support Section, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

Any such application does require a certification that meets the requirements of 

326 IAC 2-7-6(1) by a "responsible official" as defined by 326 IAC 2-7-1(34).

(c) The Permittee may implement administrative amendment changes addressed in the 

request for an administrative amendment immediately upon submittal of the request. 

[326 IAC 2-7-11(c)(3)]

B.25 Annual Fee Payment [326 IAC 2-7-19] [326 IAC 2-7-5(7)][326 IAC 2-1.1-7]

(a) The Permittee shall pay annual fees to IDEM, OAQ within thirty (30) calendar days of 

receipt of a billing. Pursuant to 326 IAC 2-7-19(b), if the Permittee does not receive a bill 

from IDEM, OAQ the applicable fee is due April 1 of each year.
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(b) Except as provided in 326 IAC 2-7-19(e), failure to pay may result in administrative 

enforcement action or revocation of this permit.

(c) The Permittee may call the following telephone numbers: 1-800-451-6027 or 

317-233-4230 (ask for OAQ, Billing, Licensing, and Training Section), to determine the 

appropriate permit fee. 

B.26 Credible Evidence [326 IAC 2-7-5(3)][326 IAC 2-7-6][62 FR 8314] [326 IAC 1-1-6]

For the purpose of submitting compliance certifications or establishing whether or not the 

Permittee has violated or is in violation of any condition of this permit, nothing in this permit shall 

preclude the use, including the exclusive use, of any credible evidence or information relevant to 

whether the Permittee would have been in compliance with the condition of this permit if the 

appropriate performance or compliance test or procedure had been performed.
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SECTION C SOURCE OPERATION CONDITIONS

Entire Source

Emission Limitations and Standards [326 IAC 2-7-5(1)]

C.1 Opacity [326 IAC 5-1] 

Pursuant to 326 IAC 5-1-2 (Opacity Limitations), except as provided in 326 IAC 5-1-1 

(Applicability) and 326 IAC 5-1-3 (Temporary Alternative Opacity Limitations), opacity shall meet 

the following, unless otherwise stated in this permit:

(a) Opacity shall not exceed an average of thirty percent (30%) in any one (1) six (6) minute 

averaging period as determined in 326 IAC 5-1-4. 

(b) Opacity shall not exceed sixty percent (60%) for more than a cumulative total of fifteen 

(15) minutes (sixty (60) readings as measured according to 40 CFR 60, Appendix A, 

Method 9 or fifteen (15) one (1) minute nonoverlapping integrated averages for a 

continuous opacity monitor) in a six (6) hour period.

C.2 Open Burning [326 IAC 4-1] [IC 13-17-9] 

The Permittee shall not open burn any material except as provided in 326 IAC 4-1-3, 

326 IAC 4-1-4 or 326 IAC 4-1-6. The previous sentence notwithstanding, the Permittee may 

open burn in accordance with an open burning approval issued by the Commissioner under 

326 IAC 4-1-4.1.

C.3 Incineration [326 IAC 4-2] [326 IAC 9-1-2] 

The Permittee shall not operate an incinerator except as provided in 326 IAC 4-2 or in this permit. 

The Permittee shall not operate a refuse incinerator or refuse burning equipment except as 

provided in 326 IAC 9-1-2 or in this permit.

C.4 Fugitive Dust Emissions [326 IAC 6-4]

The Permittee shall not allow fugitive dust to escape beyond the property line or boundaries of 

the property, right-of-way, or easement on which the source is located, in a manner that would 

violate 326 IAC 6-4 (Fugitive Dust Emissions). 326 IAC 6-4-2(4) is not federally enforceable. 

C.5 Stack Height [326 IAC 1-7]

The Permittee shall comply with the applicable provisions of 326 IAC 1-7 (Stack Height 

Provisions), for all exhaust stacks through which a potential (before controls) of twenty-five (25) 

tons per year or more of particulate matter or sulfur dioxide is emitted. The provisions of 

326 IAC 1-7-1(3), 326 IAC 1-7-2, 326 IAC 1-7-3(c) and (d), 326 IAC 1-7-4, and 326 IAC 1-7-5(a), 

(b), and (d) are not federally enforceable.

C.6 Asbestos Abatement Projects [326 IAC 14-10] [326 IAC 18] [40 CFR 61, Subpart M]

(a) Notification requirements apply to each owner or operator. If the combined amount of 

regulated asbestos containing material (RACM) to be stripped, removed or disturbed is at 

least 260 linear feet on pipes or 160 square feet on other facility components, or at least 

thirty-five (35) cubic feet on all facility components, then the notification requirements of 
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326 IAC 14-10-3 are mandatory. All demolition projects require notification whether or 

not asbestos is present.

(b) The Permittee shall ensure that a written notification is sent on a form provided by the 

Commissioner at least ten (10) working days before asbestos stripping or removal work 

or before demolition begins, per 326 IAC 14-10-3, and shall update such notice as 

necessary, including, but not limited to the following:

(1) When the amount of affected asbestos containing material increases or 

decreases by at least twenty percent (20%); or

(2) If there is a change in the following:

(A) Asbestos removal or demolition start date;

(B) Removal or demolition contractor; or

(C) Waste disposal site.

(c) The Permittee shall ensure that the notice is postmarked or delivered according to the 

guidelines set forth in 326 IAC 14-10-3(2).

(d) The notice to be submitted shall include the information enumerated in 

326 IAC 14-10-3(3).

All required notifications shall be submitted to:

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

The notice shall include a signed certification from the owner or operator that the 

information provided in this notification is correct and that only Indiana licensed workers 

and project supervisors will be used to implement the asbestos removal project. The 

notifications do not require a certification that meets the requirements of 326 IAC 2-7-6(1)

by a "responsible official" as defined by 326 IAC 2-7-1(34).

(e) Procedures for Asbestos Emission Control

The Permittee shall comply with the applicable emission control procedures in 

326 IAC 14-10-4 and 40 CFR 61.145(c). Per 326 IAC 14-10-1, emission control 

requirements are applicable for any removal or disturbance of RACM greater than three 

(3) linear feet on pipes or three (3) square feet on any other facility components or a total 

of at least 0.75 cubic feet on all facility components.
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(f) Demolition and Renovation

The Permittee shall thoroughly inspect the affected facility or part of the facility where the 

demolition or renovation will occur for the presence of asbestos pursuant to 

40 CFR 61.145(a).

(g) Indiana Licensed Asbestos Inspector

The Permittee shall comply with 326 IAC 14-10-1(a) that requires the owner or operator, 

prior to a renovation/demolition, to use an Indiana Licensed Asbestos Inspector to 

thoroughly inspect the affected portion of the facility for the presence of asbestos. The 

requirement to use an Indiana Licensed Asbestos inspector is not federally enforceable.

Testing Requirements [326 IAC 2-7-6(1)]

C.7 Performance Testing [326 IAC 3-6]

(a) For performance testing required by this permit, a test protocol, except as provided 

elsewhere in this permit, shall be submitted to:

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

no later than thirty-five (35) days prior to the intended test date. The protocol submitted 

by the Permittee does not require a certification that meets the requirements of 

326 IAC 2-7-6(1) by a "responsible official" as defined by 326 IAC 2-7-1(34).

(b) The Permittee shall notify IDEM, OAQ of the actual test date at least fourteen (14) days 

prior to the actual test date. The notification submitted by the Permittee does not require 

a certification that meets the requirements of 326 IAC 2-7-6(1) by a "responsible official"

as defined by 326 IAC 2-7-1(34).

(c) Pursuant to 326 IAC 3-6-4(b), all test reports must be received by IDEM, OAQ not later 

than forty-five (45) days after the completion of the testing. An extension may be granted 

by IDEM, OAQ if the Permittee submits to IDEM, OAQ a reasonable written explanation 

not later than five (5) days prior to the end of the initial forty-five (45) day period.

Compliance Requirements [326 IAC 2-1.1-11]

C.8 Compliance Requirements [326 IAC 2-1.1-11]

The commissioner may require stack testing, monitoring, or reporting at any time to assure 

compliance with all applicable requirements by issuing an order under 326 IAC 2-1.1-11. Any 

monitoring or testing shall be performed in accordance with 326 IAC 3 or other methods approved 

by the commissioner or the U. S. EPA.
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Compliance Monitoring Requirements [326 IAC 2-7-5(1)][326 IAC 2-7-6(1)]

C.9 Compliance Monitoring [326 IAC 2-7-5(3)][326 IAC 2-7-6(1)]

Unless otherwise specified in this permit, for all monitoring requirements not already legally 

required, the Permittee shall be allowed up to ninety (90) days from the date of permit issuance or 

of initial start-up, whichever is later, to begin such monitoring. If due to circumstances beyond the 

Permittee's control, any monitoring equipment required by this permit cannot be installed and 

operated no later than ninety (90) days after permit issuance or the date of initial startup, 

whichever is later, the Permittee may extend the compliance schedule related to the equipment 

for an additional ninety (90) days provided the Permittee notifies:

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

in writing, prior to the end of the initial ninety (90) day compliance schedule, with full justification 

of the reasons for the inability to meet this date.

The notification which shall be submitted by the Permittee does require a certification that meets 

the requirements of 326 IAC 2-7-6(1) by a "responsible official" as defined by 326 IAC 2-7-1(34).

Unless otherwise specified in the approval for the new emission unit(s), compliance monitoring for 

new emission units or emission units added through a source modification shall be implemented 

when operation begins.

C.10 Instrument Specifications [326 IAC 2-1.1-11] [326 IAC 2-7-5(3)] [326 IAC 2-7-6(1)]

(a) When required by any condition of this permit, an analog instrument used to measure a 

parameter related to the operation of an air pollution control device shall have a scale 

such that the expected maximum reading for the normal range shall be no less than 

twenty percent (20%) of full scale.

(b) The Permittee may request that the IDEM, OAQ approve the use of an instrument that 

does not meet the above specifications provided the Permittee can demonstrate that an 

alternative instrument specification will adequately ensure compliance with permit 

conditions requiring the measurement of the parameters.

Corrective Actions and Response Steps [326 IAC 2-7-5][326 IAC 2-7-6]

C.11 Emergency Reduction Plans [326 IAC 1-5-2] [326 IAC 1-5-3] 

Pursuant to 326 IAC 1-5-2 (Emergency Reduction Plans; Submission):

(a) The Permittee shall prepare written emergency reduction plans (ERPs) consistent with 

safe operating procedures.

(b) These ERPs shall be submitted for approval to:

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality
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100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

no later than 180 days from the date on which this source commences operation.

The ERP does require a certification that meets the requirements of 326 IAC 2-7-6(1) by 

a "responsible official" as defined by 326 IAC 2-7-1(34).

(c) If the ERP is disapproved by IDEM, OAQ, the Permittee shall have an additional thirty 

(30) days to resolve the differences and submit an approvable ERP.

(d) These ERPs shall state those actions that will be taken, when each episode level is 

declared, to reduce or eliminate emissions of the appropriate air pollutants.

(e) Said ERPs shall also identify the sources of air pollutants, the approximate amount of 

reduction of the pollutants, and a brief description of the manner in which the reduction 

will be achieved.

(f) Upon direct notification by IDEM, OAQ that a specific air pollution episode level is in 

effect, the Permittee shall immediately put into effect the actions stipulated in the 

approved ERP for the appropriate episode level. [326 IAC 1-5-3]

C.12 Risk Management Plan [326 IAC 2-7-5(11)] [40 CFR 68]

If a regulated substance, as defined in 40 CFR 68, is present at a source in more than a threshold 

quantity, the Permittee must comply with the applicable requirements of 40 CFR 68.

C.13 Response to Excursions or Exceedances[326 IAC 2-7-5] [326 IAC 2-7-6]

Upon detecting an excursion where a response step is required by the D Section or an 

exceedance of a limitation in this permit:

(a) The Permittee shall take reasonable response steps to restore operation of the emissions 

unit (including any control device and associated capture system) to its normal or usual 

manner of operation as expeditiously as practicable in accordance with good air pollution 

control practices for minimizing excess emissions.

(b) The response shall include minimizing the period of any startup, shutdown or 

malfunction. The response may include, but is not limited to, the following:

(1) initial inspection and evaluation;

(2) recording that operations returned or are returning to normal without operator 

action (such as through response by a computerized distribution control system); 

or

(3) any necessary follow-up actions to return operation to normal or usual manner of 

operation. 
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(c) A determination of whether the Permittee has used acceptable procedures in response to 

an excursion or exceedance will be based on information available, which may include, 

but is not limited to, the following:

(1) monitoring results;

(2) review of operation and maintenance procedures and records; and/or

(3) inspection of the control device, associated capture system, and the process.

(d) Failure to take reasonable response steps shall be considered a deviation from the 

permit.

(e) The Permittee shall record the reasonable response steps taken.

C.14 Actions Related to Noncompliance Demonstrated by a Stack Test [326 IAC 2-7-5][326 IAC 2-7-6]

(a) When the results of a stack test performed in conformance with Section C - Performance 

Testing, of this permit exceed the level specified in any condition of this permit, the 

Permittee shall submit a description of its response actions to IDEM, OAQ, no later than 

seventy-five (75) days after the date of the test.

(b) A retest to demonstrate compliance shall be performed no later than one hundred eighty 

(180) days after the date of the test. Should the Permittee demonstrate to IDEM, OAQ 

that retesting in one hundred eighty (180) days is not practicable, IDEM, OAQ may 

extend the retesting deadline

(c) IDEM, OAQ reserves the authority to take any actions allowed under law in response to 

noncompliant stack tests.

The response action documents submitted pursuant to this condition do require a certification that 

meets the requirements of 326 IAC 2-7-6(1) by a "responsible official" as defined by 

326 IAC 2-7-1(34).

Record Keeping and Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-19]

C.15 Emission Statement [326 IAC 2-7-5(3)(C)(iii)][326 IAC 2-7-5(7)][326 IAC 2-7-19(c)][326 IAC 2-6]

Pursuant to 326 IAC 2-6-3(a)(1), the Permittee shall submit by July 1 of each year an emission 

statement covering the previous calendar year. The emission statement shall contain, at a 

minimum, the information specified in 326 IAC 2-6-4(c) and shall meet the following requirements:

(1) Indicate estimated actual emissions of all pollutants listed in 326 IAC 2-6-4(a);

(2) Indicate estimated actual emissions of regulated pollutants as defined by 

326 IAC 2-7-1(32) (“Regulated pollutant, which is used only for purposes of Section 19 of 

this rule”) from the source, for purpose of fee assessment.

The statement must be submitted to:
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New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

Indiana Department of Environmental Management

Technical Support and Modeling Section, Office of Air Quality

100 North Senate Avenue

MC 61-50 IGCN 1003

Indianapolis, Indiana 46204-2251

The emission statement does require a certification that meets the requirements of 

326 IAC 2-7-6(1) by a "responsible official" as defined by 326 IAC 2-7-1(34).

C.16 General Record Keeping Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-6] [326 IAC 2-2]

[326 IAC 2-3]

(a) Records of all required monitoring data, reports and support information required by this 

permit shall be retained for a period of at least five (5) years from the date of monitoring 

sample, measurement, report, or application. Support information includes the following:

(AA) All calibration and maintenance records.

(BB) All original strip chart recordings for continuous monitoring instrumentation.

(CC) Copies of all reports required by the Part 70 permit. 

Records of required monitoring information include the following:

(AA) The date, place, as defined in this permit, and time of sampling or 

measurements.

(BB) The dates analyses were performed.

(CC) The company or entity that performed the analyses.

(DD) The analytical techniques or methods used.

(EE) The results of such analyses.

(FF) The operating conditions as existing at the time of sampling or measurement.

These records shall be physically present or electronically accessible at the source 

location for a minimum of three (3) years. The records may be stored elsewhere for the 

remaining two (2) years as long as they are available upon request. If the Commissioner 

makes a request for records to the Permittee, the Permittee shall furnish the records to 

the Commissioner within a reasonable time.

(b) Unless otherwise specified in this permit, for all record keeping requirements not already 

legally required, the Permittee shall be allowed up to ninety (90) days from the date of 

permit issuance or the date of initial start-up, whichever is later, to begin such record 

keeping.

(c) If there is a reasonable possibility (as defined in 326 IAC 2-2-8 (b)(6)(A), 326 IAC 2-2-8 

(b)(6)(B), 326 IAC 2-3-2 (l)(6)(A), and/or 326 IAC 2-3-2 (l)(6)(B)) that a “project” (as 

defined in 326 IAC 2-2-1(oo) and/or 326 IAC 2-3-1(jj)) at an existing emissions unit, other 

than projects at a source with a Plantwide Applicability Limitation (PAL), which is not part 

of a “major modification” (as defined in 326 IAC 2-2-1(dd) and/or 326 IAC 2-3-1(y)) may 

result in significant emissions increase and the Permittee elects to utilize the “projected 

actual emissions” (as defined in 326 IAC 2-2-1(pp) and/or 326 IAC 2-3-1(kk)), the 

Permittee shall comply with following:
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(1) Before beginning actual construction of the “project” (as defined in

326 IAC 2-2-1(oo) and/or 326 IAC 2-3-1(jj)) at an existing emissions unit, 

document and maintain the following records:

(A) A description of the project.

(B) Identification of any emissions unit whose emissions of a regulated new 

source review pollutant could be affected by the project.

(C) A description of the applicability test used to determine that the project is 

not a major modification for any regulated NSR pollutant, including:

(i) Baseline actual emissions;

(ii) Projected actual emissions;

(iii) Amount of emissions excluded under section 

326 IAC 2-2-1(pp)(2)(A)(iii) and/or 326 IAC 2-3-1 (kk)(2)(A)(iii); 

and

(iv) An explanation for why the amount was excluded, and any 

netting calculations, if applicable.

(d) If there is a reasonable possibility (326 IAC 2-2-8 (b)(6)(A) and/or 326 IAC 2-3-2 (l)(6)(A)) 

that a “project” (as defined in 326 IAC 2-2-1(oo) and/or 326 IAC 2-3-1(jj)) at an existing 

emissions unit, other than projects at a source with a Plantwide Applicability Limitation 

(PAL), which is not part of a “major modification” (as defined in 326 IAC 2-2-1(dd) and/or 

326 IAC 2-3-1(y)) may result in significant emissions increase and the Permittee elects to 

utilize the “projected actual emissions” (as defined in 326 IAC 2-2-1(pp) and/or 

326 IAC 2-3-1(kk)), the Permittee shall comply with following:

(1) Monitor the emissions of any regulated NSR pollutant that could increase as a 

result of the project and that is emitted by any existing emissions unit identified in 

(1)(B) above; and

(2) Calculate and maintain a record of the annual emissions, in tons per year on a 

calendar year basis, for a period of five (5) years following resumption of regular 

operations after the change, or for a period of ten (10) years following resumption 

of regular operations after the change if the project increases the design capacity 

of or the potential to emit that regulated NSR pollutant at the emissions unit.

C.17 General Reporting Requirements [326 IAC 2-7-5(3)(C)] [326 IAC 2-1.1-11] [326 IAC 2-2]

(a) The Permittee shall submit the attached Quarterly Deviation and Compliance Monitoring 

Report or its equivalent. Proper notice submittal under Section B –Emergency Provisions 

satisfies the reporting requirements of this paragraph. Any deviation from permit 

requirements, the date(s) of each deviation, the cause of the deviation, and the response 

steps taken must be reported except that a deviation required to be reported pursuant to 

an applicable requirement that exists independent of this permit, shall be reported 
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according to the schedule stated in the applicable requirement and does not need to be 

included in this report. This report shall be submitted not later than thirty (30) days after 

the end of the reporting period. The Quarterly Deviation and Compliance Monitoring 

Report shall include a certification that meets the requirements of 326 IAC 2-7-6(1) by a 

"responsible official" as defined by 326 IAC 2-7-1(34). A deviation is an exceedance of a 

permit limitation or a failure to comply with a requirement of the permit.

(b) The address for report submittal is: 

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

(c) Unless otherwise specified in this permit, any notice, report, or other submission required 

by this permit shall be considered timely if the date postmarked on the envelope or 

certified mail receipt, or affixed by the shipper on the private shipping receipt, is on or 

before the date it is due. If the document is submitted by any other means, it shall be 

considered timely if received by IDEM, OAQ on or before the date it is due.

(d) The first report shall cover the period commencing on the date of issuance of this permit 

or the date of initial start-up, whichever is later, and ending on the last day of the 

reporting period. Reporting periods are based on calendar years, unless otherwise 

specified in this permit. For the purpose of this permit, “calendar year” means the twelve 

(12) month period from January 1 to December 31 inclusive.

(e) If the Permittee is required to comply with the recordkeeping provisions of (d) in Section 

C - General Record Keeping Requirements for any “project” (as defined in 326 IAC 2-2-1 

(oo) and/or 326 IAC 2-3-1 (jj)) at an existing emissions unit, and the project meets the 

following criteria, then the Permittee shall submit a report to IDEM, OAQ:

(1) The annual emissions, in tons per year, from the project identified in (c)(1) in 

Section C- General Record Keeping Requirements exceed the baseline actual 

emissions, as documented and maintained under Section C- General Record 

Keeping Requirements (c)(1)(C)(i), by a significant amount, as defined in 

326 IAC 2-2-1 (ww) and/or 326 IAC 2-3-1 (pp), for that regulated NSR pollutant, 

and

(2) The emissions differ from the preconstruction projection as documented and 

maintained under Section C - General Record Keeping Requirements

(c)(1)(C)(ii). 

(f) The report for project at an existing emissions unit shall be submitted no later than sixty 

(60) days after the end of the year and contain the following:

(1) The name, address, and telephone number of the major stationary source.
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(2) The annual emissions calculated in accordance with (d)(1) and (2) in Section C -

General Record Keeping Requirements.

(3) The emissions calculated under the actual-to-projected actual test stated in 

326 IAC 2-2-2(d)(3) and/or 326 IAC 2-3-2(c)(3).

(4) Any other information that the Permittee wishes to include in this report such as 

an explanation as to why the emissions differ from the preconstruction projection.

Reports required in this part shall be submitted to:

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

(g) The Permittee shall make the information required to be documented and maintained in 

accordance with (c) in Section C- General Record Keeping Requirements available for 

review upon a request for inspection by IDEM, OAQ. The general public may request 

this information from the IDEM, OAQ under 326 IAC 17.1.

Stratospheric Ozone Protection

C.18 Compliance with 40 CFR 82 and 326 IAC 22-1

Pursuant to 40 CFR 82 (Protection of Stratospheric Ozone), Subpart F, except as provided for 

motor vehicle air conditioners in Subpart B, the Permittee shall comply with applicable standards 

for recycling and emissions reduction.
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SECTION D.1 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: [326 IAC 2-7-5(14):

(a) Four (4) natural gas-fired combined cycle combustion turbines, identified as units CCCT1, 

CCCT2, CCCT3, and CCCT4, permitted in 2012, each with a combustion turbine equipped with 

dry low NOx burners, natural gas fired duct burners, and a heat recovery steam generator 

identified as HRSG1, HRSG2, HRSG3, and HRSG4, NOx emissions controlled by four (4) 

selective catalytic reduction (SCR) systems (SCR01, SCR02, SCR03 and SCR04), CO and 

VOC emissions controlled by oxidation catalyst systems (CAT01, CAT02, CAT03 and CAT04) 

and exhausting to stacks CCCT01, CCCT02, CCCT03, and CCCT04, respectively. Each stack 

has continuous emissions monitors (CEMS) for NOx and CO. The nominal heat input for each 

CCCT is 2,300 MMBtu/hr (higher heating value (HHV)). The combined nominal power output 

is 1,350 megawatts (MW). 

*Note: The heat recovery steam generators are not a source of emissions. They have been 

included for clarity as they are a part of the entire source and operate in conjunction 

with the duct burners which are a source of emissions.

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.1.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.1.2 Effective Date of the Permit [IC 13-15-5-3]

Pursuant to IC 13-15-5-3, this section of this permit becomes effective upon its issuance.

D.1.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.
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Operating Conditions

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.1.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the natural 

gas-fired combined cycle combustion turbines, identified as CCCT1, CCCT2, CCCT3, and 

CCCT4 shall be as follows:

(a) The PM, PM10 and PM2.5 emissions from the combined cycle combustion turbines

identified as CCCT1 -CCCT4 shall not exceed 18 pounds per hour and 0.0078 

lbs/MMBtu, with duct firing based on 3-hr average through the use of good combustion 

practices and fuel specification. 

(b) The PM, PM10 and PM2.5 emissions from the combined cycle combustion turbines

identified as CCCT1 -CCCT4 shall not exceed 15 pounds per hour and 0.0092

lbs/MMBtu, without duct firing based on 3-hr average through the use of good 

combustion practices and fuel specification. 

D.1.5 H2SO4 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the natural 

gas-fired combined cycle combustion turbines , identified as CCCT1, CCCT2, CCCT3, and 

CCCT4 shall be as follows:

The H2SO4 emissions from the combined cycle combustion turbines identified as CCCT1 -

CCCT4 shall be limited by a fuel sulfur limit of 0.75 gr S/100 scf fuel. 

D.1.6 CO PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the natural 

gas-fired combined cycle combustion turbines , identified as CCCT1, CCCT2, CCCT3, and 

CCCT4 shall be as follows:

(a) The CO emissions from the CCCTs shall be controlled by a catalytic oxidation; and

(b) The CO emissions shall not exceed 2.0 ppmv @15% O2 based on a 3-hr

average.

These conditions do not apply during startup and shutdown, as defined in Condition D.1.11.

D.1.7 SO2 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the natural 

gas-fired combined cycle combustion turbines , identified as CCCT1, CCCT2, CCCT3, and 

CCCT4 shall be as follows:

The SO2 emissions from the combined cycle combustion turbines identified as CCCT1 - CCCT4 

shall be limited by a fuel sulfur limit of 0.75 gr S/100 scf fuel. 
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D.1.8 VOC PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the natural 

gas-fired combined cycle combustion turbines , identified as CCCT1, CCCT2, CCCT3, and 

CCCT4 shall be as follows:

(a) The VOC emissions from the CCCTs shall be controlled by a catalytic oxidation

(b) The VOC emissions shall not exceed 2.0 ppmvd @15% O2, with duct burners based on 

3-hr average.

(c) The VOC emissions shall not exceed 1.0 ppmvd @15% O2, without duct burners based 

on 3-hr average.

These conditions do not apply during startup and shutdown, as defined in Condition D.1.11.

D.1.9 NOx PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the natural 

gas-fired combined cycle combustion turbines, identified as CCCT1, CCCT2, CCCT3, and 

CCCT4 shall be as follows:

(a) The NOx emissions from the CCCTs shall be controlled by a Selective Catalytic 

Reduction and DLN Burners.

(b) The NOx emissions shall not exceed 2.0ppmv @15% O2 with duct burners based on a 3-

hr average.

These conditions do not apply during startup and shutdown, as defined in Condition D.1.11.

D.1.10 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the natural 

gas-fired combined cycle combustion turbines, identified as CCCT1, CCCT2, CCCT3, and 

CCCT4 shall be as follows:

(a) The net heat rate shall not exceed 7,646 Btu/kW-hr (HHV-net) for each CCCT block (ISO 

conditions, baseload operation without duct firing or inlet evaporative cooling, and not 

accounting for transformer losses).

(b) The total CO2 emissions from all four CCCT blocks shall not exceed 4,736,936 tons of 

CO2e per twelve (12) consecutive month period with compliance determined at the end 

of the month.

D.1.11 Startup and Shutdown Limitations for Combustion Turbines [326 IAC 2-2-3]

Pursuant to PSD/New Source Review Permit No. 141-31003-00579 and 326 IAC 2-2-3 (PSD 

Requirements), following applies to each combustion turbine:
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(a) A startup is defined as the operation in the period beginning when continuous fuel flow to 

the combustion turbine is initiated and ending when the CCCT achieves consecutive 

CEMS data points in compliance with the primary BACT limits.

(b) Steady-state operating condition shall be defined as the period of time that the 

combustion turbine is operating in dry low NOx (premix) mode and in compliance with the 

primary BACT limit.

(c) A shutdown is defined as operation beginning when the combustion turbine exits dry lowNOx (premix) mode and ending with termination of continuous fuel flow to each turbine.

(d) A startup/shutdown cycle is a pair of subsequent shutdown and startup events (i.e., one 

startup followed by one shutdown represents one startup/shutdown cycle).

(e) Unit Offline is represented by the Unit on-line Time being 0. 

(f) The following records shall be kept by the source:

(1) Number of minutes in each hour that the unit is in startup mode. 

 

(2) Number of minutes in each hour that the unit is in shutdown mode. 

(3) Records shall be maintained at any time the unit is off-line. 

(g) An event is defined as: 

(1) exactly one (1) startup or exactly one (1) shutdown

For CO and NOX, the source determined the worst-case operating scenario that results in 

the highest modeled impacts to be a cold start of the CCCTs. The modeled cold start 

emission rates are based on startup emission totals provided by the turbine vendor. 

Therefore, the source proposes to use the cold start emission totals, per CCCT as a 

short-term limit during startup/shutdown events, as follows:

CO - 2,125 lb/event

NOx - 443 lb/event

(h) The NOX emissions from the combined cycle combustion turbines stacks shall not 

exceed 81.6 tons per twelve (12) consecutive month period, for the duration of the 

combined startup and shutdown events, with compliance determined at the end of each 

month. 

(i) The CO emissions from the combined cycle combustion turbines stacks shall not exceed 

407.5 tons per twelve (12) consecutive month period, for the duration of the combined 

startup and shutdown events, with compliance determined at the end of each month. 

(j) The VOC emissions from the combined cycle combustion turbines stacks shall not 

exceed 22.0 tons per twelve (12) consecutive month period, for the duration of the 

combined startup and shutdown events, with compliance determined at the end of each 

month. 
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D.1.12 Preventive Maintenance Plan [326 IAC 1-6-3]

A Preventive Maintenance Plan (PMP) is required for these units and their control devices. 

Section B - Preventive Maintenance Plan contains the Permittee's obligations with regard to the 

preventive maintenance plan required by this condition.

Compliance Determination Requirements

D.1.13 Nitrogen Oxide Control

In order to ensure compliance with Condition D.1.9 - NOx PSD BACT, the Low NOx burner shall 

be in operation and control emissions from the natural gas-fired combustion turbines at all times 

that the natural gas-fired combined cycle combustion turbines are in operation.

D.1.14 Oxidation Catalyst

In order to ensure compliance with Conditions D.1.6 and D.1.8, the oxidation catalyst shall be in 

operation at all times when the natural gas-fired combined cycle combustion turbinesare in 

operation.

D.1.15 Greenhouse Gases (GHGs) Calculations

To determine the compliance status with Condition D.1.10, the following equation shall be used to 

determine the CO2e emissions from the natural gas-fired combined cycle combustion turbines, 

identified as CCCT1, CCCT2, CCCT3, and CCCT4:

CO2e emissions (tons/month) = [(Fuel Usage (mmscf/month) x Heat Content (mmbtu/mmscf)) x

(CO2 EF (lb/mmbtu) x CO2 GWP + CH4 EF (lb/mmbtu) x CH4

GWP + N2O EF (lb/mmbtu) x N2O GWP)] x 1/2000 (ton/lb)

Where:

Fuel Usage (mmscf/month) = monthly fuel usage data from company records

Heat Content (mmbtu/mmscf) = standard value in AP-42 for natural gas or vendor data, if 

available

CO2 EF (lb/mmbtu) = emission factor from GHG Mandatory Reporting Rule (MRR) (40 CFR 98, 

Subpart C) for natural gas

CH4 EF (lb/mmbtu) = emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas

N2O EF (lb/mmbtu) = emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas

CO2 GWP = global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH4 GWP = global warming potential from GHG MRR (40 CFR 98, Subpart A)

N2O GWP = global warming potential from GHG MRR (40 CFR 98, Subpart A)

D.1.16 Maintenance of Continuous Emission Monitoring Equipment [326 IAC 3-5][326 IAC-2-2-3]

(a) The Permittee shall install, calibrate, maintain, and operate all necessary continuous 

emission monitoring systems (CEMS) and related equipment for NOx and CO emissions. 

(b) All CEMS required by this permit shall meet all applicable performance specifications of 

40 CFR 60 and 40 CFR 75 or any other applicable performance specifications, and are 

subject to monitor system certification requirements pursuant to 326 IAC 3-5-3.

(c) In the event that a breakdown of a continuous emission monitoring system occurs, a 

record shall be made of the times and reasons of the breakdown and efforts made to 

correct the problem.
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(d) Whenever a NOx, or CO CEM is down for more than twenty-four (24) hours, the 

Permittee shall follow good air pollution control practices.

(e) Nothing in this permit shall excuse the Permittee from complying with the requirements to 

operate a continuous emission monitoring system pursuant to 40 CFR 60, 40 CFR 75 

and 40 CFR 96.

D.1.17 Testing Requirements [326 IAC 2-1.1-11]

(a) In order to demonstrate compliance with Condition D.1.4 - PM, PM10 and PM2.5 PSD 

BACT, within sixty (60) days of reaching maximum capacity but no later than one 

hundred and eighty (180) days after initial startup, the Permittee shall conduct PM, PM10

and PM2.5 emissions stack testing of the emissions from the combined cycle combustion 

turbines utilizing methods as approved by the commissioner. Testing shall be conducted 

with and without the duct burners in operation. This test shall be repeated at least once 

every five years from the date of the most recent valid compliance demonstration. Testing 

shall be conducted in accordance with the provisions of 326 IAC 3-6 (Source Sampling 

Procedures). Section C - Performance Testing contains the Permittee's obligation with 

regard to the performance testing required by this condition.

(b) In order to demonstrate compliance with Condition D.1.8 - VOC PSD BACT, within sixty 

(60) days of reaching maximum capacity but no later than one hundred and eighty (180) 

days after initial startup, the Permittee shall conduct VOC emissions stack testing of the 

emissions from the combined cycle combustion turbines utilizing methods as approved 

by the commissioner. Testing shall be conducted with and without the duct burners in 

operation. This test shall be repeated at least once every five years from the date of the 

most recent valid compliance demonstration. Testing shall be conducted in accordance 

with the provisions of 326 IAC 3-6 (Source Sampling Procedures). Section C -

Performance Testing contains the Permittee's obligation with regard to the performance 

testing required by this condition.

(c) In order to demonstrate compliance with Condition D.1.10(a) - GHGs PSD BACT, within 

sixty (60) days of reaching maximum capacity but no later than one hundred and eighty 

(180) days after initial startup, the Permittee shall conduct net heat rate performance

testing for combined cycle combustion turbines utilizing methods as approved by the 

commissioner. This test shall be repeated at least once every five years from the date of 

the most recent valid compliance demonstration. Testing shall be conducted in 

accordance with the provisions of 326 IAC 3-6 (Source Sampling Procedures). Section C 

- Performance Testing contains the Permittee's obligation with regard to the performance 

testing required by this condition.

Compliance Monitoring Requirements [326 IAC 2-7-5(1)][326 IAC 2-7-6(1)]

D.1.18 Oxidation Catalyst Parametric Monitoring

(a) In order to ensure compliance with Condition D.1.8 - VOC PSD BACT, a continuous 

monitoring system shall be calibrated, maintained, and operated on each oxidation 

catalyst for measuring operating temperature. For the purposes of this condition, 

continuous monitoring means recording the temperature no less often than every 15 

minutes. The output of this system shall be recorded as a three (3) hour average. From 

the date of the start up of the oxidation catalyst until the approved stack test results are 
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available, the Permittee shall operate the oxidation catalyst at or above the 3-hour 

average temperature of 500o

F.

(b) On and after the date the approved stack test results are available, the Permittee shall 

operate the oxidation catalyst at or above the three (3) hour average temperature 

specified by the catalyst manufacturer for VOC control or as established during the most 

recent compliant stack test.

(c) Section C - Response to Excursions or Exceedences contains the Permittee's obligation 

with regard to the reasonable response steps required by this condition. A temperature 

average below the three hour average specified by the catalyst manufacturer for VOC 

control or as established in the most recent compliance stack test is not considered a 

deviation from this permit. Failure to take response steps shall be considered a deviation 

from this permit.

Record Keeping and Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-19]

D.1.19 Record Keeping Requirement

(a) To document the compliance status with Condition D.1.16 - Maintenance of Continuous 

Emission Monitoring Equipment, the Permittee shall record the output of the continuous 

monitoring systems and shall perform the required record keeping and reporting, 

pursuant to 326 IAC 3-5-6 and 326 IAC 3-5-7.

(b) In the event that a breakdown of the NOx or CO continuous emission monitoring system 

(CEMS) occurs in Condition D.1.16 - Maintenance of Continuous Emission Monitoring 

Equipment, the Permittee shall maintain records of all CEMS malfunctions, out of control 

periods, calibration and adjustment activities, and repair or maintenance activities.

(c) To document the compliance status with Conditions D.1.16 - Maintenance of Continuous 

Emission Monitoring Equipment, the Permittee shall maintain the monthly records of the 

CO and NOx emissions from each of the combined cycle combustion turbines CCCT1 

through CCCT4 based the CEM data. Compliance with the CO emissions shall satisfy for 

the VOC emissions.

(d) To document compliance with Condition D.1.11 - Startup and Shutdown Limitations for 

Combustion Turbines, the Permittee shall maintain records of the following:

(1) The type of operation (i.e. startup, shutdown) with 

supporting operational data;

(2) The total number of minutes for startup and shutdown

operation per event; and 

(3) The CEMS data, fuel flow meter data, and/or Method 19 calculations used to 

determine the mass emissions rate corresponding to each startup and shutdown 

operating period.
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(e) In order to document the compliance status with Conditions D.1.4, D.1.5, D.1.6, D.1.7, 

D.1.8, D.1.9 and D.1.10, the Permittee shall maintain monthly records of the amount and 

type of fuel combusted in the combined cycle combustion turbines.

(f) To document the compliance status with Condition D.1.10 - GHGs PSD BACT, the 

Permittee shall maintain monthly records of the CO2e emissions.

(g) In order to document the compliance status with Condition D.1.18 - Oxidation Catalyst 

Parametric Monitoring, the Permittee shall maintain continuous temperature records (on 

a three- (3-) hourly average basis) for each oxidation catalyst to demonstrate compliance.

(h) To document the compliance status with Condition D.1.5 - H2SO4 PSD BACT and D.1.7 -

SO2 PSD BACT, the Permittee shall maintain the monthly records of the fuel sulfur 

content of the natural gas combusted in the turbines and the associated duct burners.

(i) Section C - General Record Keeping Requirements contains the Permittee's obligations 

with regard to the record keeping required by this condition.

D.1.20 Reporting Requirements 

A quarterly summary of the information to document the compliance status with Conditions 

D.1.10(b), D.1.11(i), D.1.11(j), D.1.11(k) and D.1.11(l) shall be submitted using the reporting 

forms located at the end of this permit, or their equivalent, not later than thirty (30) days following 

the end of each calendar quarter. The report submitted by the Permittee does require a 

certification that meets the requirements of 326 IAC 2-7-6(1) by a “responsible official” as defined 

by 326 IAC 2-7-1(34). Section C - General Reporting Requirements contains the Permittee's 

obligations with regard to the reporting required by this condition
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SECTION D.2 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: [326 IAC 2-7-5(14)

(b) Two (2) natural gas fired auxiliary boilers, identified as B001 and B002, permitted in 2012, 

each, with a maximum heat input capacity of 80 MMBtu/hr (HHV), equipped with low NOx 

burners (LNB) with flue gas recirculation (FGR) to reduce NOx emissions, and exhausting to 

stacks B001 and B002. Under 40 CFR Part 60, Subpart Dc, the auxiliary boiler is considered a 

steam generating unit.

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.2.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.2.2 Effective Date of the Permit [IC 13-15-5-3]

Pursuant to IC 13-15-5-3, this section of this permit becomes effective upon its issuance.

D.2.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.2.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the natural 

gas-fired auxiliary boiler, identified as B001 and B002 shall be as follows:

The PM, PM10 and PM2.5 emissions from the Auxiliary Boilers, identified as B001-B002 shall not 

exceed 0.0075 lb/MMBtu (HHV) and 0.6 lbs/hour, each, based on a 3-hr average period through 

the use of good combustion practices and fuel specification. 

D.2.5 CO PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the natural 

gas-fired auxiliary boiler, identified as B001 and B002 shall be as follows:
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The CO emissions from the Auxiliary Boilers (B001-B002) operation shall not exceed 0.083 

lb/MMBtu (HHV) and 6.64 lbs/hr, each, based on a 3 - hour average through Good Combustion 

Practices.

 

D.2.6 SO2 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the natural 

gas-fired auxiliary boiler, identified as B001 and B002 shall be as follows:

The SO2 emissions from the Auxiliary Boilers, identified as B001-B002 shall not exceed 0.0022 

lb/MMBtu (HHV) and 0.176 lbs/hr each, based on a 3-hr average through the use of fuel 

specification. 

D.2.7 NOx PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the natural 

gas-fired auxiliary boiler, identified as B001 and B002 shall be as follows:

(a) The NOx emissions from the Auxiliary Boilers, identified as B001-B002 shall be controlled 

by a Low NOx Burner with Flue Gas Recirculation.

(b) The NOx emissions shall not exceed 0.032 lb/MMBtu (HHV) and 2.56 pounds per hour

each, based on a 3-hr average period.

D.2.8 VOC PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the natural 

gas-fired auxiliary boiler, identified as B001 and B002 shall be as follows:

The VOC emissions from the Auxiliary Boilers, identified as B001-B002 shall not exceed 0.005 

lb/MMBtu (HHV) and 0.4 lbs/hr each based on a 3-hr average period through the use of good 

combustion practices. 

D.2.9 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the natural 

gas-fired auxiliary boiler, identified as B001 and B002 shall be as follows:

The GHGs BACT for the Auxiliary Boilers shall be as follows:

(a) Operating and Maintenance (O&M) Practices;

(b) Combustion Turning; 

(c) The boiler will be equipped with oxygen trim controls and oxygen analyzers;

(d) The boiler will be equipped with an economizer;

(e) Energy efficient refractory will be installed;
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(f) The boiler will be equipped with a condensate return system (recovery);

(g) Steam and hot lines will be insulated;

(h) Boiler designed for 80% thermal efficiency (HHV); and

(i) The total CO2e emissions from the two auxiliary boilers shall be limited to less than

81,996 tons of CO2e per twelve (12) consecutive month period with compliance 

determined at the end of the month.

D.2.10 Startup, Shutdown and Other Opacity Limits [326 IAC 5-1-3]

(a) Pursuant to 326 IAC 5-1-3 (a) (Temporary Alternative Opacity Limitations), when building 

a new fire in a boiler, or shutting down a boiler, opacity may exceed the applicable 

opacity limit established in 326 IAC 5-1-2. However, opacity levels shall not exceed sixty 

percent (60%) for any six (6)-minute averaging period. Opacity in excess of the 

applicable opacity limit established in 326 IAC 5-1-2 shall not continue for more than two 

(2) six (6)-minute averaging periods in any twenty-four (24) hour period. 

(b) If a facility cannot meet the opacity limitations of 326 IAC 5-1-3(a) or (b), the Permittee 

may submit a written request to IDEM, OAQ, for a temporary alternative opacity limitation 

in accordance with 326 IAC 5-1-3(d). The Permittee must demonstrate that the 

alternative limit is needed and justifiable.

D.2.11 Preventive Maintenance Plan [326 IAC 1-6-3]

A Preventive Maintenance Plan (PMP) is required for these units and control devices. Section B -

Preventive Maintenance Plan contains the Permittee's obligations with regard to the preventive 

maintenance plan required by this condition.

Compliance Determination Requirements

D.2.12 Nitrogen Oxide Control

In order to ensure compliance with Condition D.2.7 - NOx PSD BACT, the low NOx burner shall 

be installed and utilized at all times that the auxiliary boilers are in operation.

D.2.13 Testing Requirements [326 IAC 2-1.1-11]

(a) In order to demonstrate compliance with Condition D.2.4 - PM, PM10 and PM2.5 PSD 

BACT, within sixty (60) days of reaching maximum capacity but no later than one 

hundred and eighty (180) days after initial startup, the Permittee shall conduct PM, PM10

and PM2.5 emissions stack testing of the emissions from the boilers utilizing methods as 

approved by the commissioner. This test shall be performed once. Testing shall be 

conducted in accordance with the provisions of 326 IAC 3-6 (Source Sampling 

Procedures). Section C - Performance Testing contains the Permittee's obligation with 

regard to the performance testing required by this condition.

(b) In order to demonstrate compliance with Condition D.2.5 - CO PSD BACT, within sixty 

(60) days of reaching maximum capacity but no later than one hundred and eighty (180) 

days after initial startup, the Permittee shall conduct CO emissions stack testing of the 

emissions from the boilers utilizing methods as approved by the commissioner. This test 

shall be performed once. Testing shall be conducted in accordance with the provisions of 

326 IAC 3-6 (Source Sampling Procedures). Section C - Performance Testing contains 

the Permittee's obligation with regard to the performance testing required by this 

condition.
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New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

(c) In order to demonstrate compliance with Condition D.2.7 - NOx PSD BACT, within sixty 

(60) days of reaching maximum capacity but no later than one hundred and eighty (180) 

days after initial startup, the Permittee shall conduct NOx emissions stack testing of the 

emissions from the boilers utilizing methods as approved by the commissioner. This test 

shall be repeated at least once every five years from the date of the most recent valid 

compliance demonstration. Testing shall be conducted in accordance with the provisions 

of 326 IAC 3-6 (Source Sampling Procedures). Section C - Performance Testing 

contains the Permittee's obligation with regard to the performance testing required by this 

condition.

(d) In order to demonstrate compliance with Condition D.2.8 - VOC PSD BACT, within sixty 

(60) days of reaching maximum capacity but no later than one hundred and eighty (180) 

days after initial startup, the Permittee shall conduct VOC emissions stack testing of the 

emissions from the boilers utilizing methods as approved by the commissioner. This test 

shall be repeated at least once every five years from the date of the most recent valid 

compliance demonstration. Testing shall be conducted in accordance with the provisions 

of 326 IAC 3-6 (Source Sampling Procedures). Section C - Performance Testing 

contains the Permittee's obligation with regard to the performance testing required by this 

condition.

(e) In order to demonstrate compliance with Condition D.2.9(h) – GHGs PSD BACT, within 

sixty (60) days of reaching maximum capacity but no later than 180 days after initial 

startup, the Permittee shall perform thermal efficiency testing of the auxiliary boilers, 

identified as B001 and B002 utilizing methods approved by the Commissioner. These 

tests shall be conducted once. Testing shall be conducted in accordance with the 

provisions of 326 IAC 3-6 (Source Sampling Procedures). Section C - Performance 

Testing contains the Permittee's obligation with regard to the performance testing 

required by this condition.

D.2.14 Compliance Determination Requirements [326 IAC 2-2]

In order to determine compliance status with Conditions D.2.4 - PM, PM10 and PM2.5 PSD BACT 

and D.2.6 - SO2 PSD BACT, the Permittee shall only use natural gas in the auxiliary boilers B001

and B002. 

D.2.15 Greenhouse Gases (GHGs) Calculations

To determine the compliance status with Condition D.2.9(i), the following equation shall be used 

to determine the CO2e emissions from the Auxiliary Boilers:

CO2e emissions (ton/month) = [(Fuel Usage (mmscf/month) x Heat Content (mmbtu/mmscf)) x

(CO2 EF (lb/mmbtu) x CO2 GWP + CH4 EF (lb/mmbtu) x CH4

GWP + N2O EF (lb/mmbtu) x N2O GWP)] x 1/2000 (ton/lb)

Where:

Fuel Usage (mmscf/month) = monthly auxiliary boiler fuel usage data from company records

Heat Content (mmbtu/mmscf) = standard value in AP-42 for natural gas, or vendor data, if 

available

CO2 EF (lb/mmbtu) = emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas

CH4 EF (lb/mmbtu) = emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas

N2O EF (lb/mmbtu) = emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas
St. Joseph Energy Center, LLC Page 47 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

CO2 GWP = global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH4 GWP = global warming potential from GHG MRR (40 CFR 98, Subpart A)

N2O GWP = global warming potential from GHG MRR (40 CFR 98, Subpart A)

Record Keeping and Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-19]

D.2.16 Record Keeping Requirements

(a) In order to document the compliance status with Conditions D.2.4, D.2.5, D.2.6, D.2.7, 

D.2.8, D.2.9, and D.2.14, the Permittee shall maintain monthly records of the type and 

amount of fuel combusted in the auxiliary boilers.

(b) To document the compliance status with Condition D.2.9(i) - GHGs PSD BACT, the 

Permittee shall maintain the monthly records of the total CO2e emissions from the 

auxiliary boilers.

(c) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition.

D.2.17 Reporting Requirements

A quarterly summary of the information to document the compliance status with Condition D.2.9(i)

shall be submitted, using the reporting forms located at the end of this permit, or their equivalent, 

not later than thirty (30) days following the end of each calendar quarter. The report submitted by 

the Permittee does require a certification that meets the requirements of 326 IAC 2-7-6(1) by a 

“responsible official” as defined by 326 IAC 2-7-1(34). Section C - General Reporting 

Requirements contains the Permittee's obligations with regard to the reporting required by this 

condition.
St. Joseph Energy Center, LLC Page 48 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

SECTION D.3 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: [326 IAC 2-7-5(14) Insignificant Activities

(a) Two (2) firewater pump engines, each nominally rated at 371 brake horsepower (bph) and 

identified as FP01 and FP02, permitted in 2012, exhausting through two (2) vents, identified as 

FP01 and FP02, respectively. [Under 40 CFR 60, Subpart IIII, the firewater pump engines are

considered new affected sources.][Under 40 CFR 63, Subpart ZZZZ, the firewater pump 

engines are considered new affected sources.]

(b) Two (2) emergency diesel generators, each nominally rated at 1,006 horsepower, identified as 

EG01 and EG02, permitted in 2012, exhausting through two (2) vents, identified as EG01 and 

EG02, respectively. [Under 40 CFR 60, Subpart IIII, the emergency diesel fired generators are

considered new affected sources.][Under 40 CFR 63, Subpart ZZZZ, the emergency diesel 

fired generators are considered new affected source.]

(c) One (1) emergency diesel generator, nominally rated at 2012 horsepower, identified as EG03, 

permitted in 2012, exhausting through one (1) vent, identified as EG03. [Under 40 CFR 60, 

Subpart IIII, the emergency diesel fired generator is considered a new affected source.][Under 

40 CFR 63, Subpart ZZZZ, the emergency diesel fired generator is considered a new affected 

source.]

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.3.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.3.2 Effective Date of the Permit [IC 13-15-5-3]

Pursuant to IC 13-15-5-3, this section of this permit becomes effective upon its issuance.

D.3.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.
St. Joseph Energy Center, LLC Page 49 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

Operating Conditions

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.3.4 PM, PM10, PM2.5, NOx, CO, SO2 and GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the two (2) 

firewater pump diesel engines, identified as FP01 and FP02 shall be as follows:

Firewater Pump Engines, identified as FP01 - FP02:

(a) The PM, PM10 and PM2.5 emissions from the Firewater Pump Engines identified as FP01 

- FP02 shall be limited to less than 0.15 g/hp-hr through the use of combustion design 

control and usage limitation. 

(b) The CO emissions from the Firewater Pump Engines identified as FP01 - FP02 shall not 

exceed 2.6 g/hp-hr through the use of combustion design control and usage limitation. 

(c) The SO2 emissions from the Firewater Pump Engines identified as FP01 - FP02 shall not 

exceed 0.0015 % S and 0.043 lb/hr, each through the use of ultra low sulfur distillate 

(ULSD) and usage limitation. 

(d) The VOC emissions from the Firewater Pump Engines identified as FP01 - FP02 shall 

not exceed 0.16 pounds per hour, each through the use of Combustion Design Controls

and usage limitation. 

(e) The NOx emissions from the Firewater Pump Engines identified as FP01 - FP02 shall not 

exceed 3.0 g/bhp-hr for NOx + NMHC through the use of Combustion Design Controls

and usage limitation. 

(f) The GHGs BACT for the Firewater Pump Engines identified as FP01 - FP02 shall be as 

follows;

(1) The use of a good engineering design and fuel efficient design; and 

(2) The total CO2e emissions from all the two (2) firewater pump engines shall not 

exceed 172 tons of CO2e per twelve (12) consecutive month period with 

compliance determined at the end of the month.

(g) The Firewater Pumps identified as FP01 - FP02 shall not exceed 500 hours per year, 

each.
St. Joseph Energy Center, LLC Page 50 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

D.3.5 PM, PM10, PM2.5, NOx, CO, SO2 and GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the three (3)

emergency diesel generators, identified as EG01, EG02 and EG03 shall be as follows:

Emergency Diesel Generators, identified as (EG01 - EG03):

(a) The PM, PM10 and PM2.5 emissions from the Emergency Diesel Generators, Identified as 

EG01, EG02 and EG03 shall not exceed 0.15 g/hp-hr, each through the use of 

combustion design control and usage limitation. 

(b) The CO emissions from the Emergency Diesel Generators, Identified as EG01, EG02 

and EG03 shall not exceed 2.6 g/hp-hr, each through the use of combustion design 

controls and usage limitation. 

(c) The SO2 emissions from the Emergency Diesel Generators, Identified as EG01 and 

EG02 shall not exceed 0.012 lb/hr, each, through the use of ultra low sulfur distillate 

(ULSD) and usage limitation. 

(d) The SO2 emissions from the Emergency Diesel Generator, Identified as EG03 shall not 

exceed 0.024 lb/hr through the use of ultra low sulfur distillate (ULSD) and usage 

limitation.

 

(e) The VOC emissions from the Emergency Diesel Generators, Identified as EG01 and 

EG02 shall not exceed 1.04 lbs/hr, each, through the use of Combustion Design Controls

and usage limitation. 

(f) The VOC emissions from the Emergency Diesel Generator, Identified as EG03 shall not 

exceed 1.04 lbs/hr through the use of Combustion Design Controls and usage limitation. 

(g) The NOx emissions from the Emergency Diesel Generators shall not exceed 4.8 g/bhp-hr 

for NOx + NMHC through the use of Combustion Design Controls and usage limitation. 

(h) The GHGs BACT for the Emergency Diesel Generators, Identified as EG01, EG02 and 

EG03 shall be as follows;

(1) The use of a good engineering design and fuel efficient design; and 

(2) The total CO2 emissions from all the three (3) emergency diesel generators shall 

not exceed 1,186 tons of CO2e per twelve (12) consecutive month period with 

compliance determined at the end of the month.

(i) The Emergency Diesel Generators, Identified as EG01, EG02 and EG03 shall not exceed 

500 hours per year, each.
St. Joseph Energy Center, LLC Page 51 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

Compliance Determination Requirements

D.3.6 Greenhouse Gases (GHGs) Calculations

To determine the compliance status with Conditions D.3.4(f)(2) and D.3.5(h)(2), the following 

equation shall be used to determine the CO2e emissions from the emergency diesel engines 

(FP01-FP02 and EG01 - EG03):

CO2e emissions (ton/month) = [(Fuel Usage (gal/month) x Heat Content (mmbtu/gal)) x (CO2 EF 

(lb/mmbtu) x CO2 GWP + CH4 EF (lb/mmbtu) x CH4 GWP + 

N2O EF (lb/mmbtu) x N2O GWP)] x 1/2000 (ton/lb)

Where:

Fuel Usage (gal/month) = monthly fire pump engine/emergency generator fuel usage data from 

company records

Heat Content (mmbtu/gal) = standard value in AP-42 for diesel fuel, or vendor data, if available

CO2 EF (lb/mmbtu) = emission factor from GHG MRR (40 CFR 98, Subpart C) for diesel fuel

CH4 EF (lb/mmbtu) = emission factor from GHG MRR (40 CFR 98, Subpart C) for diesel fuel

N2O EF (lb/mmbtu) = emission factor from GHG MRR (40 CFR 98, Subpart C) for diesel fuel

CO2 GWP = global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH4 GWP = global warming potential from GHG MRR (40 CFR 98, Subpart A)

N2O GWP = global warming potential from GHG MRR (40 CFR 98, Subpart A)

Record Keeping and Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-19]

D.3.7 Record Keeping Requirements

(a) In order to document the compliance status with Conditions D.3.4(c), D3.5(c) and (d), the 

Permittee shall maintain monthly records of the percent sulfur content of the fuel used in 

the emergency diesel engines and the firewater pump diesel engines.

(b) To document compliance with Conditions D.3.4(g) and D.3.5(i), the Permittee shall 

maintain monthly records of hours of operation of the emergency diesel engines and the 

firewater pump diesel engines.

(c) To document the compliance status with Conditions D.3.4(f)(2), D.3.5(h)(2) and D.3.6, 

the Permittee shall maintain records of the total amount of fuel used each month in the 

emergency diesel engines (FP01-FP02 and EG01-EG03) and the total CO2 emissions 

from the emergency diesel engines (FP01-FP02 and EG01-EG03).

(e) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition

D.3.8 Reporting Requirements

A quarterly summary of the information to document the compliance status with Conditions 

D.3.4(f)(2), D.3.4(g), D.3.5(h)(2) and D.3.5(i) shall be submitted, using the reporting forms located 

at the end of this permit, or their equivalent, not later than thirty (30) days following the end of 

each calendar quarter. The report submitted by the Permittee does require a certification that 

meets the requirements of 326 IAC 2-7-6(1) by a “responsible official” as defined by 

326 IAC 2-7-1(34). Section C - General Reporting Requirements contains the Permittee's 

obligations with regard to the reporting required by this condition.
St. Joseph Energy Center, LLC Page 52 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

SECTION D.4 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: [326 IAC 2-7-5(14) Insignificant Activities

(c) Two (2) cooling towers, each nominally rated with a circulation rate of 170,000 gpm , identified 

as CT01 and CT02, permitted in 2012, with high efficiency drift/mist eliminators, and 

exhausting through ten vents each, identified as CT01A – CT01J and CT02A – CT02J.

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.4.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.4.2 Effective Date of the Permit [IC 13-15-5-3]

Pursuant to IC 13-15-5-3, this section of this permit becomes effective upon its issuance.

D.4.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.4.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Cooling 

Tower CT01 and CT02 shall be as follows:

The PM, PM10 and PM2.5 emissions from the Cooling Towers, identified as CT01 and CT02 shall 

be controlled by High efficiency drift eliminators designed with a drift loss rate of less than 

0.0005%.

Compliance Determination

D.4.5 PM, PM10 and PM2.5 Control

In order to ensure compliance with Condition D.4.4 - PM, PM10 and PM2.5 PSD BACT, the high 

efficiency drift eliminators for particulate control shall be in operation and control emissions from 

each cooling tower at all times that the cooling towers are in operation.
St. Joseph Energy Center, LLC Page 53 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

SECTION D.5 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: [326 IAC 2-7-5(14) Insignificant Activities

(e) Six (6) Turbine Lube Demister Vents, identified as DM01 - DM06, permitted in 2012, 

exhausting through vents DM01 – DM06.

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.5.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.5.2 Effective Date of the Permit [IC 13-15-5-3]

Pursuant to IC 13-15-5-3, this section of this permit becomes effective upon its issuance.

D.5.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.5.4 PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Storage 

Tanks, identified as DM01 – DM06 shall be as follows:

The organic PM, PM10 and PM2.5 emissions from the Turbine Lube Oil Demister Vents, identified 

as DM01 – DM06, shall be the use of good design and operating practices. 

D.5.5 Volatile Organic Compounds (VOC) PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Turbine 

Lube Oil Demister Vents, identified as DM01 – DM06, shall be as follows:

The VOC emissions from the Lubrication Turbine Lube Oil Demister Vents, identified as DM01 –

DM06, shall be the use of good design and operating practices. 
St. Joseph Energy Center, LLC Page 54 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

SECTION D.6 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: [326 IAC 2-7-5(14) Insignificant Activities

(e) Six (6) Turbine Lube Oil storage tanks, identified as TK01 - TK06, permitted in 2012, each with 

a nominal capacity of 6,800 gallons.

(f) Two (2) Emergency Generator ULSD Tanks, identified as TK07 and TK08, permitted in 2012, 

each, with a nominal capacity of 550 gallons.

(g) Two (2) Fire Pump Engine ULSD Tanks, identified as TK09 and TK10, permitted in 2012, each, 

with a nominal capacity of 70 gallons.

(h) One (1) Vehicle Gasoline dispensing Tank, identified as TK11, permitted in 2012, with a 

nominal capacity of 650 gallons, equipped with submerged fill and stage 1 vapor balance.

(i) One (1) Vehicle Diesel Tank, identified as TK12, permitted in 2012, with a nominal capacity of 

650 gallons.

(j) One (1) Emergency Generator ULSD Tank, identified as TK50, permitted in 2012, with a 

nominal capacity of 300 gallons.

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.6.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.6.2 Effective Date of the Permit [IC 13-15-5-3]

Pursuant to IC 13-15-5-3, this section of this permit becomes effective upon its issuance.

D.6.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions
St. Joseph Energy Center, LLC Page 55 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.6.4 Volatile Organic Compounds (VOC) PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Turbine 

Lube Oil storage tanks, identified as TK01 - TK06, and Diesel Storage Tanks, identified as TK07, 

TK08, TK09, TK10, TK12 and TK50 shall be as follows:

The VOC emissions from the Turbine Lube Oil storage tanks, identified as TK01 - TK06, and 

Diesel Storage Tanks, identified as TK07, TK08, TK09, TK10, TK12 and TK50 shall be the use of 

good design and operating practices. 

D.6.5 Prevention of Significant Deterioration (PSD) – Best Available Control Technology for Volatile 

Organic Compounds (VOC) [326 IAC 2-2-3] [326 IAC 8-4-6]

Pursuant to 326 IAC 2-2-3, the Best Available Control Technology (PSD BACT) for the Gasoline 

Dispensing Facility, identified as TK11 shall be as follows:

(a) The Permittee shall not allow the transfer of gasoline between any transport and 

any gasoline storage tank unless such tank is equipped with the following:

(1) A submerged fill pipe.

(2) Either a pressure relief valve set to release at no less than seven-tenths 

(0.7) pounds per square inch or an orifice of five-tenths (0.5) inch in 

diameter.

(b) If the owner or employees of the owner of a gasoline dispensing facility are not 

present during loading, it shall be the responsibility of the owner or the operator 

of the transport to make certain the vapor recovery system is connected between 

the transport and the storage tank and is operating according to manufacturer's 

specifications.

Compliance with this condition shall satisfy the requirements of 326 IAC 8-4-6.

D.6.6 Preventive Maintenance Plan [326 IAC 2-7-5(12)]

A Preventive Maintenance Plan (PMP) is required for the gasoline storage tanks (TK11), and its

control device. Section B - Preventive Maintenance Plan contains the Permittee's obligations 

with regard to the preventive maintenance plan required by this condition.

Compliance Determination Requirements

D.6.7 Volatile Organic Compounds Control

In order to comply with Condition D.6.5, the Stage I vapor recovery systems for VOC control shall 

be in operation at all times when gasoline is being transferred.

Compliance Monitoring Requirements [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)]

D.6.8 Vapor Recovery System Operation

For the Stage I vapor recovery systems in order to document compliance with Condition D.6.5, 

the Permittee shall perform daily checks of the key operating parameters on days in which the 

filling of gasoline storage tanks is conducted, including venting for the Stage I vapor recovery 

system.
St. Joseph Energy Center, LLC Page 56 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

Record Keeping and Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-19]

D.6.9 Record Keeping Requirements

(a) In order to document the compliance status with Conditions D.6.8 - Vapor Recovery 

System Operation, the Permittee shall maintain records of the key operating parameters 

when Stage 1 vapor recovery system is in use.

(b) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition
St. Joseph Energy Center, LLC Page 57 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

SECTION D.7 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: [326 IAC 2-7-5(14) Insignificant Activities

(l) Six (6) Electrical Circuit Breakers containing sulfur hexafluoride (SF6) identified as emissions 

unit SF6, permitted in 2012, with fugitive GHG emissions.

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.7.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.7.2 Effective Date of the Permit [IC 13-15-5-3]

Pursuant to IC 13-15-5-3, this section of this permit becomes effective upon its issuance.

D.7.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.7.4 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the six (6) 

Electrical Circuit Breakers, identified as SF6 shall be as follows:

(1) The use of a totally enclosed pressure system with a design leak rate of 0.5% and a 

density alarm for leak detection.

(2) The total SF6 emissions from all the circuit breakers shall not exceed 0.0009 tons of SF6

per twelve (12) consecutive month period with compliance determined at the end of the 

month.
St. Joseph Energy Center, LLC Page 58 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

SECTION D.8 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: [326 IAC 2-7-5(14) Insignificant Activities

(k) two (2) lime storage silos, capable of handling a maximum loading rate of 20 tons per hour 

combined, permitted in 2012 and with particulate matter controlled by bin vent filters exhausting 

to Stacks S1 and S2; 

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.8.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.8.2 Effective Date of the Permit [IC 13-15-5-3]

Pursuant to IC 13-15-5-3, this section of this permit becomes effective upon its issuance.

D.8.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.8.4 Particulate Matter Limitations [326 IAC 6.5-1-2]

Pursuant to 326 IAC 6.5-1-2(a), the particulate emission from the lime silos shall not exceed 0.03 

grains per dry standard cubic feet (gr/dscf) of exhaust air. 
St. Joseph Energy Center, LLC Page 59 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

SECTION D.9 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: [326 IAC 2-7-5(14) Insignificant Activities

(o) Degreasing operations that do not exceed one hundred forty-five (145) gallons per 12 

months, except if subject to 326 IAC 20-6. [326 IAC 8-3];

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.9.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.9.2 Effective Date of the Permit [IC 13-15-5-3]

Pursuant to IC 13-15-5-3, this section of this permit becomes effective upon its issuance.

D.9.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.9.4 Volatile Organic Compounds (VOC) [326 IAC 8-3-2]

Pursuant to 326 IAC 8-3-2 (Cold Cleaner Operations), for cold cleaning operations constructed 

after January 1, 1980, the Permittee shall:

(a) Equip the cleaner with a cover;

(b) Equip the cleaner with a facility for draining cleaned parts;

(c) Close the degreaser cover whenever parts are not being handled in the cleaner; 

(d) Drain cleaned parts for at least fifteen (15) seconds or until dripping ceases; 

(e) Provide a permanent, conspicuous label summarizing the operation requirements;

(f) Store waste solvent only in covered containers and not dispose of waste solvent or 

transfer it to another party, in such a manner that greater than twenty percent (20%) of 

the waste solvent (by weight) can evaporate into the atmosphere.
St. Joseph Energy Center, LLC Page 60 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

D.9.5 Volatile Organic Compounds (VOC) [326 IAC 8-3-5]

(a) Pursuant to 326 IAC 8-3-5(a) (Cold Cleaner Degreaser Operation and Control), for cold 

cleaner degreaser operations without remote solvent reservoirs constructed after July 1, 

1990, the Permittee shall ensure that the following control equipment requirements are 

met:

(1) Equip the degreaser with a cover. The cover must be designed so that it can be 

easily operated with one (1) hand if:

(A) The solvent volatility is greater than two (2) kiloPascals (fifteen (15) 

millimeters of mercury or three-tenths (0.3) pounds per square inch) 

measured at thirty-eight degrees Celsius (38°C) (one hundred degrees 

Fahrenheit (100°F));

(B) The solvent is agitated; or

(C) The solvent is heated.

(2) Equip the degreaser with a facility for draining cleaned articles. If the solvent 

volatility is greater than four and three-tenths (4.3) kiloPascals (thirty-two (32) 

millimeters of mercury or six-tenths (0.6) pounds per square inch) measured at 

thirty-eight degrees Celsius (38°C) (one hundred degrees Fahrenheit (100°F)), 

then the drainage facility must be internal such that articles are enclosed under 

the cover while draining. The drainage facility may be external for applications 

where an internal type cannot fit into the cleaning system.

(3) Provide a permanent, conspicuous label which lists the operating requirements 

outlined in subsection (b).

(4) The solvent spray, if used, must be a solid, fluid stream and shall be applied at a 

pressure which does not cause excessive splashing.

(5) Equip the degreaser with one (1) of the following control devices if the solvent 

volatility is greater than four and three-tenths (4.3) kiloPascals (thirty-two (32) 

millimeters of mercury or six-tenths (0.6) pounds per square inch) measured at 

thirty-eight degrees Celsius (38°C) (one hundred degrees Fahrenheit (100°F)), or 

if the solvent is heated to a temperature greater than forty-eight and nine-tenths 

degrees Celsius (48.9°C) (one hundred twenty degrees Fahrenheit (120°F)):

(A) A freeboard that attains a freeboard ratio of seventy-five hundredths 

(0.75) or greater.

(B) A water cover when solvent is used is insoluble in, and heavier than, 

water.

(C) Other systems of demonstrated equivalent control such as a refrigerated 

chiller of carbon adsorption. Such systems shall be submitted to the 

U.S. EPA as a SIP revision. 
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New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

(b) Pursuant to 326 IAC 8-3-5(b) (Cold Cleaner Degreaser Operation and Control), the 

owner or operator of a cold cleaning facility construction of which commenced after July 

1, 1990, shall ensure that the following operating requirements are met:

(1) Close the cover whenever articles are not being handled in the degreaser.

(2) Drain cleaned articles for at least fifteen (15) seconds or until dripping ceases.

(3) Store waste solvent only in covered containers and prohibit the disposal or 

transfer of waste solvent in any manner in which greater than twenty percent 

(20%) of the waste solvent by weight could evaporate.
St. Joseph Energy Center, LLC Page 62 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

SECTION E.1 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(a) Four (4) natural gas-fired combined cycle combustion turbines, identified as units CCCT1, 

CCCT2, CCCT3, and CCCT4, permitted in 2012, each with a combustion turbine equipped with 

dry low NOx burners, natural gas fired duct burners, and a heat recovery steam generator 

identified as HRSG1, HRSG2, HRSG3, and HRSG4, NOx emissions controlled by four (4) 

selective catalytic reduction (SCR) systems (SCR01, SCR02, SCR03 and SCR04), CO and 

VOC emissions controlled by oxidation catalyst systems (CAT01, CAT02, CAT03 and CAT04) 

and exhausting to stacks CCCT01, CCCT02, CCCT03, and CCCT04, respectively. Each stack 

has continuous emissions monitors (CEMS) for NOx and CO. The nominal heat input for each 

CCCT is 2,300 MMBtu/hr (higher heating value (HHV)). The combined nominal power output 

is 1,350 megawatts (MW). 

*Note: The heat recovery steam generators are not a source of emissions. They have been 

included for clarity as they are a part of the entire source and operate in conjunction 

with the duct burners which are a source of emissions.

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

New Source Performance Standards (NSPS) Requirements [326 IAC 12][40 CFR 60, Subpart 

KKKK]

E.1.1 General Provisions Relating to New Source Performance Standards [326 IAC 12-1] [40 CFR Part 

60, Subpart A]

Pursuant to 40 CFR 60.1, the Permittee shall comply with the provisions of 40 CFR Part 60 

Subpart A – General Provisions, which are incorporated by reference as 326 IAC 12-1 for the four 

(4) natural gas combustion turbines CCCT1 through CCCT4 and four (4) duct burners associated 

with the heat recovery steam generators HRSG1 through HRSG4, except as otherwise specified 

in 40 CFR Part 60, Subparts KKKK.

E.1.2 New Source Performance Standards for Stationary Combustion Turbines Requirements [40 CFR 

Part 60, Subpart KKKK] [326 IAC 12] 

Pursuant to 40 CFR Part 60, Subpart KKKK, the Permittee shall comply with the provisions of 

New Source Performance Standards for Stationary Combustions Turbines, which are 

incorporated by reference as 326 IAC 12, for the four (4) natural gas combustion turbines CCCT1 

through CCCT4 and four (4) duct burners associated with the heat recovery steam generators 

HRSG1 through HRSG4 as specified as follows:

1. 40 CFR 60.4300

2. 40 CFR 60.4305

3. 40 CFR 60.4320

4. 40 CFR 60.4330(a)(1) or (2)

5. 40 CFR 60.4333

6. 40 CFR 60.4340(b)(1)

7. 40 CFR 60.4345

8. 40 CFR 60.4350(a)-(e), (f)(1)(2), (h)

9. 40 CFR 60.4360
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New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

10. 40 CFR 60.4365

11. 40 CFR 60.4370(b), (c)

12. 40 CFR 60.4375(a)

13. 40 CFR 60.4380(b)

14. 40 CFR 60.4385(a), (c)

15. 40 CFR 60.4395

16. 40 CFR 60.4400(a), (b)(2), (b)(4)-(6)

17. 40 CFR 60.4405

18. 40 CFR 60.4415

19. 40 CFR 60.4420
St. Joseph Energy Center, LLC Page 64 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

SECTION E.2 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(b) Two (2) natural gas fired auxiliary boilers, identified as B001 and B002, permitted in 2012, 

each, with a maximum heat input capacity of 80 MMBtu/hr (HHV), equipped with low NOx 

burners (LNB) with flue gas recirculation (FGR) to reduce NOx emissions, and exhausting to 

stacks B001 and B002. Under 40 CFR Part 60, Subpart Dc, the auxiliary boiler is considered a 

steam generating unit.

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

New Source Performance Standards (NSPS) Requirements [326 IAC 12][40 CFR 60, Subpart Dc]

E.2.1 General Provisions Relating to New Source Performance Standards [326 IAC 12-1] [40 CFR Part 

60, Subpart A]

(a) Pursuant to 40 CFR 60.1, the Permittee shall comply with the provisions of 40 CFR Part 

60 Subpart A – General Provisions, which are incorporated by reference as 326 IAC 12-1 

for the natural gas fired auxiliary boiler, except as otherwise specified in 40 CFR Part 60, 

Subpart Dc.

E.2.2 New Source Performance Standards for Small-Commercial-Institutional Steam Generating Units

Requirements [40 CFR Part 60, Subpart Dc] [326 IAC 12] 

Pursuant to 40 CFR Part 60, Subpart Dc, the Permittee shall comply with the provisions of New 

Source Performance Standards for Small-Commercial-Institutional Steam Generating Units, 

which are incorporated by reference as 326 IAC 12, for the natural gas fired auxiliary boiler as 

specified as follows:

1. 40 CFR 60.40c(a)-(d)

2. 40 CFR 60.41c

3. 40 CFR 60.48c(a)(1), (3)

4. 40 CFR 60.48c(g),(i) 
St. Joseph Energy Center, LLC Page 65 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

SECTION E.3 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(a) Two (2) firewater pump engines, each nominally rated at 371 brake horsepower (bph)and 

identified as FP01 and FP02, permitted in 2012, exhausting through two (2) vents, identified as 

FP01 and FP02, respectively. [Under 40 CFR 60, Subpart IIII, the firewater pump engines are

considered new affected sources.][Under 40 CFR 63, Subpart ZZZZ, the firewater pump 

engines are considered new affected sources.]

(b) Two (2) emergency diesel generators, each nominally rated at 1,006 horsepower, identified as 

EG01 and EG02, permitted in 2012, exhausting through two (2) vents, identified as EG01 and 

EG02, respectively. [Under 40 CFR 60, Subpart IIII, the emergency diesel fired generators are

considered new affected sources.][Under 40 CFR 63, Subpart ZZZZ, the emergency diesel 

fired generators are considered new affected source.]

(c) One (1) emergency diesel generator, nominally rated at 2012 horsepower, identified as EG03, 

permitted in 2012, exhausting through one (1) vent, identified as EG03. [Under 40 CFR 60, 

Subpart IIII, the emergency diesel fired generator is considered a new affected source.][Under 

40 CFR 63, Subpart ZZZZ, the emergency diesel fired generator is considered a new affected 

source.]

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

New Source Performance Standards [326 IAC 12] [40 CFR 60, Subpart IIII]

E.3.1 General Provisions Relating to NSPS IIII [326 IAC 12][40 CFR Part 60, Subpart A]

The provisions of 40 CFR Part 60, Subpart A – General Provisions, which are incorporated by 

reference in 326 IAC 12-1, apply to the emergency diesel generators and the firewater pump 

diesel engines described in this section except when otherwise specified in 40 CFR Part 60, 

Subpart IIII.

E.3.2 Standards of Performance for Stationary Compression Ingnition Internal Combustion Engines

[326 IAC 12][40 CFR Part 60, Subpart IIII]

The Permittee who owns and operates stationary compression ignition (CI) internal combustion 

engines (ICE) shall comply with the following provisions of 40 CFR Part 60, Subpart IIII, included 

as Attachment C of this permit. The source is subject to the following portions of Subpart IIII:

The firewater pump engines are subject to the following Sections of 40 CFR Part 60, Subpart IIII.

1. 40 CFR 60.4200(a)(2)(ii)

2. 40 CFR 60.4205(c)

3. 40 CFR 60.4206

4. 401 CFR 60.4207

5. 40 CFR 60.4211(a), (c)

6. 40 CFR 60.4218

7. 401 CFR 60.4219
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New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

The emergency diesel generators are subject to the following Sections of 40 CFR Part 60, 

Subpart IIII.

1. 40 CFR 60.4200(a)(2)(i)

2. 40 CFR 60.4205(b)

3. 40 CFR 60.4206

4. 401 CFR 60.4207

5. 40 CFR 60.4211(a), (c)

6. 40 CFR 60.4218

7. 401 CFR 60.4219
St. Joseph Energy Center, LLC Page 67 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

SECTION E.4 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(b) Two (2) emergency diesel generators, each nominally rated at 1,006 horsepower, identified as 

EG01 and EG02, permitted in 2012, exhausting through two (2) vents, identified as EG01 and 

EG02, respectively. [Under 40 CFR 60, Subpart IIII, the emergency diesel fired generators are

considered new affected sources.][Under 40 CFR 63, Subpart ZZZZ, the emergency diesel 

fired generators are considered new affected source.]

(c) One (1) emergency diesel generator, nominally rated at 2012 horsepower, identified as EG03, 

permitted in 2012, exhausting through one (1) vent, identified as EG03. [Under 40 CFR 60, 

Subpart IIII, the emergency diesel fired generator is considered a new affected source.][Under 

40 CFR 63, Subpart ZZZZ, the emergency diesel fired generator is considered a new affected 

source.]

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

National Emissions Standard for Hazardous Air Pollutants [326 IAC 20] [40 CFR 63, Subpart ZZZZ]

E.4.1 General Provisions Relating to National Emissions Standard for Hazardous Air Pollutants for 

Stationary Reciprocating Internal Combustion Engines [326 IAC 20-1][40 CFR Part 63, Subpart 

A]

Pursuant to 40 CFR 63.6590, the Permittee shall comply with the provisions of 40 CFR Part 63, 

Subpart A – General Provisions, which are incorporated by reference as 326 IAC 20-1-1 for the 

affected source, as specified in Appendix A of 40 CFR Part 63, Subpart ZZZZ, in accordance 

with the schedule in 40 CFR 63 Subpart ZZZZ.

E.4.2 National Emissions Standard for Hazardous Air Pollutants for stationary Reciprocating Internal 

Combustion Engines [40 CFR Part 63, Subpart ZZZZ][326 IAC 20-82-1]

Pursuant to CFR Part 63, Subpart ZZZZ, the Permittee shall comply with the provisions of 40 

CFR Part 63.6590, for the affected source, as specified as follows:

1. 40 CFR 63.6580

2. 40 CFR 63.6585(a), (c)-(d)

3. 40 CFR 63.6590(a)(2)(iii)

4. 40 CFR 63.6590(c)(1)

5. 40 CFR 63.6665

6. 40 CFR 63.6670

7. 40 CFR 63.6675
St. Joseph Energy Center, LLC Page 68 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

SECTION F Clean Air Interstate (CAIR) Nitrogen Oxides Annual, Sulfur Dioxide, and Nitrogen 

Oxides Ozone Season Trading Programs – CAIR Permit for CAIR Units Under 326 

IAC 24-1-1(a), 326 IAC 24-2-1(a), and 326 IAC 24-3-1(a)

Emissions Unit Description:

(a) Four (4) natural gas-fired combined cycle combustion turbines, identified as units CCCT1, 

CCCT2, CCCT3, and CCCT4, permitted in 2012, each with a combustion turbine equipped with 

dry low NOx burners, natural gas fired duct burners, and a heat recovery steam generator 

identified as HRSG1, HRSG2, HRSG3, and HRSG4, NOx emissions controlled by four (4) 

selective catalytic reduction (SCR) systems (SCR01, SCR02, SCR03 and SCR04), CO and 

VOC emissions controlled by oxidation catalyst systems (CAT01, CAT02, CAT03 and CAT04) 

and exhausting to stacks CCCT01, CCCT02, CCCT03, and CCCT04, respectively. Each stack 

has continuous emissions monitors (CEMS) for NOx and CO. The nominal heat input for each 

CCCT is 2,300 MMBtu/hr (higher heating value (HHV)). The combined nominal power output 

is 1,350 megawatts (MW). 

*Note: The heat recovery steam generators are not a source of emissions. They have been 

included for clarity as they are a part of the entire source and operate in conjunction 

with the duct burners which are a source of emissions.

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

F.1 Automatic Incorporation of Definitions [326 IAC 24-1-7(e)] [326 IAC 24-2-7(e)] [326 IAC 24-3-7(e)] 

[40 CFR 97.123(b)] [40 CFR 97.223(b)] [40 CFR 97.323(b)]

This CAIR permit is deemed to incorporate automatically the definitions of terms under 326 IAC 

24-1-2, 326 IAC 24-2-2, and 326 IAC 24-3-2.

F.2 Standard Permit Requirements [326 IAC 24-1-4(a)] [326 IAC 24-2-4(a)] [326 IAC 24-3-4(a)] 

[40 CFR 97.106(a)] [40 CFR 97.206(a)] [40 CFR 97.306(a)]

(a) The owners and operators of the CAIR NOX source, CAIR SO2 source, and CAIR NOX

ozone season source and CAIR NOX units, CAIR SO2 unit(s), and CAIR NOX ozone 

season units shall operate each unit in compliance with this CAIR permit.

(b) The CAIR NOX units, CAIR SO2 units, and CAIR NOX ozone season units subject to this 

CAIR permit are units CCCT1, CCCT2, CCCT3, and CCCT4.

F.3 Monitoring, Reporting, and Record Keeping Requirements [326 IAC 24-1-4(b)] 

[326 IAC 24-2-4(b)] [326 IAC 24-3-4(b)] [40 CFR 97.106(b)] [40 CFR 97.206(b)] 

[40 CFR 97.306(b)]

(a) The owners and operators, and the CAIR designated representative, of each CAIR NOX

source, CAIR SO2 source, and CAIR NOX ozone season source and CAIR NOX unit,

CAIR SO2 unit, and CAIR NOX ozone season unit at the source shall comply with the 

monitoring, reporting, and record keeping requirements of 326 IAC 24-1-11, 326 IAC 24-

2-10, and 326 IAC 24-3-11.
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New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

(b) The emissions measurements recorded and reported in accordance with 326 IAC 24-1-

11, 326 IAC 24-2-10, and 326 IAC 24-3-11 shall be used to determine compliance by 

each CAIR NOX source, CAIR SO2 source, and CAIR NOX ozone season source with 

the CAIR NOX emissions limitation under 326 IAC 24-1-4(c), CAIR SO2 emissions 

limitation under 326 IAC 24-2-4(c), and CAIR NOX ozone season emissions limitation 

under 326 IAC 24-3-4(c) and Condition F.4.1, Nitrogen Oxides Emission Requirements, 

Condition F.4.2, Sulfur Dioxide Emission Requirements, and Condition F.4.3, Nitrogen 

Oxides Ozone Season Emission Requirements.

F.4.1 Nitrogen Oxides Emission Requirements [326 IAC 24-1-4(c)] [40 CFR 97.106(c)]

(a) As of the allowance transfer deadline, the owners and operators of each CAIR NOX

source and each CAIR NOX unit at the source shall hold, in the source’s compliance 

account, CAIR NOX allowances available for compliance deductions for the control period 

under 326 IAC 24-1-9(i) in an amount not less than the tons of total nitrogen oxides 

emissions for the control period from all CAIR NOX units at the source, as determined in 

accordance with 326 IAC 24-1-11.

(b) A CAIR NOX unit shall be subject to the requirements under (a) above for the control 

period starting on the later of January 1, 2009, or the deadline for meeting the unit's 

monitor certification requirements under section 326 IAC 24-1-11(c)(1), 11(c)(2), or 

11(c)(5) and for each control period thereafter.

(c) A CAIR NOX allowance shall not be deducted for compliance with the requirements 

under (a) above and 326 IAC 24-1-4(c)(1), for a control period in a calendar year before 

the year for which the CAIR NOX allowance was allocated.

(d) CAIR NOX allowances shall be held in, deducted from, or transferred into or among CAIR 

NOX allowance tracking system accounts in accordance with 326 IAC 24-1-9, 326 IAC 

24-1-10, and 326 IAC 24-1-12.

(e) A CAIR NOX allowance is a limited authorization to emit one (1) ton of nitrogen oxides in 

accordance with the CAIR NOX annual trading program. No provision of the CAIR NOX

annual trading program, the CAIR permit application, the CAIR permit, or an exemption 

under 326 IAC 24-1-3 and no provision of law shall be construed to limit the authority of 

the State of Indiana or the United States to terminate or limit the authorization.

(f) A CAIR NOX allowance does not constitute a property right.

(g) Upon recordation by the U.S. EPA under 326 IAC 24-1-8, 326 IAC 24-1-9, 326 IAC 24-1-

10, or 326 IAC 24-1-12, every allocation, transfer, or deduction of a CAIR NOX allowance 

to or from a CAIR NOX source's compliance account is incorporated automatically in this 

CAIR permit.

F.4.2 Sulfur Dioxide Emission Requirements [326 IAC 24-2-4(c)] [40 CFR 97.206(c)]

(a) As of the allowance transfer deadline, the owners and operators of the CAIR SO2 source 

and each CAIR SO2 unit at the source shall hold, in the source’s compliance account, a 

tonnage equivalent of CAIR SO2 allowances available for compliance deductions for the 

control period under 326 IAC 24-2-8(j) and 326 IAC 24-2-8(k) not less than the tons of 

total sulfur dioxide emissions for the control period from all CAIR SO2 units at the source, 

as determined in accordance with 326 IAC 24-2-10.
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New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

(b) A CAIR SO2 unit shall be subject to the requirements under (a) above for the control 

period starting on the later of January 1, 2010 or the deadline for meeting the unit's 

monitor certification requirements under section 326 IAC 24-2-10(c)(1), 10(c)(2), or 

10(c)(5) and for each control period thereafter.

(c) A CAIR SO2 allowance shall not be deducted for compliance with the requirements under 

(a) above and 326 IAC 24-2-4(c)(1), for a control period in a calendar year before the 

year for which the CAIR SO2 allowance was allocated.

(d) CAIR SO2 allowances shall be held in, deducted from, or transferred into or among CAIR 

SO2 allowance tracking system accounts in accordance with 326 IAC 24-2-8, 326 IAC 

24-2-9, and 326 IAC 24-2-11.

(e) A CAIR SO2 allowance is a limited authorization to emit sulfur dioxide in accordance with 

the CAIR SO2 trading program. No provision of the CAIR SO2 trading program, the CAIR 

permit application, the CAIR permit, or an exemption under 326 IAC 24-2-3 and no 

provision of law shall be construed to limit the authority of the State of Indiana or the 

United States to terminate or limit the authorization.

(f) A CAIR SO2 allowance does not constitute a property right.

(g) Upon recordation by the U.S. EPA under 326 IAC 24-2-8, 326 IAC 24-2-9, or 326 IAC 24-

2-11, every allocation, transfer or deduction of a CAIR SO2 allowance to or from a CAIR 

SO2 source's compliance account is incorporated automatically in this CAIR permit.

F.4.3 Nitrogen Oxides Ozone Season Emission Requirements [326 IAC 24-3-4(c)] [40 CFR 97.306(c)]

(a) As of the allowance transfer deadline, the owners and operators of the each CAIR NOX

ozone season source and each CAIR NOX ozone season unit at the source shall hold, in 

the source’s compliance account, CAIR NOX ozone season allowances available for 

compliance deductions for the control period under 326 IAC 24-3-9(i) in an amount not 

less than the tons of total nitrogen oxides emissions for the control period from all CAIR 

NOX ozone season units at the source, as determined in accordance with 326 IAC 24-3-

11.

(b) A CAIR NOX unit shall be subject to the requirements under (a) above for the control 

period starting on the later of May 1, 2009 or the deadline for meeting the unit's monitor 

certification requirements under section 326 IAC 24-3-11(c)(1), 11(c)(2), 11(c)(3), or 

11(c)(7) and for each control period thereafter.

(c) A CAIR NOX ozone season allowance shall not be deducted for compliance with the 

requirements under (a) above and 326 IAC 24-3-4(c)(1), for a control period in a calendar 

year before the year for which the CAIR NOX ozone season allowance was allocated.

(d) CAIR NOX ozone season allowances shall be held in, deducted from, or transferred into 

or among CAIR NOX ozone season allowance tracking system accounts in accordance 

with 326 IAC 24-3-9, 326 IAC 24-3-10, and 326 IAC 24-3-12.

(e) A CAIR NOX allowance is a limited authorization to emit one (1) ton of nitrogen oxides in 

accordance with the CAIR NOX ozone season trading program. No provision of the CAIR 
St. Joseph Energy Center, LLC Page 71 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

NOX ozone season trading program, the CAIR permit application, the CAIR permit, or an 

exemption under 326 IAC 24-3-3 and no provision of law shall be construed to limit the 

authority of the State of Indiana or the United States to terminate or limit the 

authorization.

(f) A CAIR NOX allowance does not constitute a property right.

(g) Upon recordation by the U.S. EPA under 326 IAC 24-3-8, 326 IAC 24-3-9, 326 IAC 24-3-

10, or 326 IAC 24-3-12, every allocation, transfer, or deduction of a CAIR NOX ozone 

season allowance to or from a CAIR NOX ozone season source's compliance account is 

incorporated automatically in this CAIR permit.

F.5 Excess Emissions Requirements [326 IAC 24-1-4(d)] [326 IAC 24-2-4(d)] [326 IAC 24-3-4(d)]

[40 CFR 97.106(d)] [40 CFR 97.206(d)] [40 CFR 97.306(d)]

The owners and operators of a CAIR NOX source and each CAIR NOX unit that emits nitrogen 

oxides during any control period in excess of the CAIR NOX emissions limitation shall do the 

following:

(a) Surrender the CAIR NOX allowances required for deduction under 326 IAC 24-1-9(j)(4).

(b) Pay any fine, penalty, or assessment or comply with any other remedy imposed, for the 

same violations, the Clean Air Act (CAA) or applicable state law.

Each ton of such excess emissions and each day of such control period shall constitute a 

separate violation of 326 IAC 24-1-4, the Clean Air Act (CAA), and applicable state law.

The owners and operators of a CAIR SO2 source and each CAIR SO2 unit that emits sulfur 

dioxide during any control period in excess of the CAIR SO2 emissions limitation shall do the 

following:

(a) Surrender the CAIR SO2 allowances required for deduction under 326 IAC 24-2-8(k)(4).

(b) Pay any fine, penalty, or assessment or comply with any other remedy imposed, for the 

same violations, the Clean Air Act (CAA) or applicable state law.

Each ton of such excess emissions and each day of such control period shall constitute a 

separate violation of 326 IAC 24-2-4, the Clean Air Act (CAA), and applicable state law.

The owners and operators of a CAIR NOX ozone season source and each CAIR NOX ozone 

season unit that emits nitrogen oxides during any control period in excess of the CAIR NOX

ozone season emissions limitation shall do the following:

(a) Surrender the CAIR NOX ozone season allowances required for deduction under 326 IAC 

24-3-9(j)(4).

(b) Pay any fine, penalty, or assessment or comply with any other remedy imposed, for the 

same violations, the Clean Air Act (CAA) or applicable state law.

Each ton of such excess emissions and each day of such control period shall constitute a 

separate violation of 326 IAC 24-3-4, the Clean Air Act (CAA), and applicable state law.
St. Joseph Energy Center, LLC Page 72 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

F.6 Record Keeping Requirements [326 IAC 24-1-4(e)] [326 IAC 24-2-4(e)] [326 IAC 24-3-4(e)] 

[326 IAC 2-7-5(3)] [40 CFR 97.106(e)] [40 CFR 97.206(e)] [40 CFR 97.306(e)]

Unless otherwise provided, the owners and operators of the CAIR NOX source, CAIR SO2

source, and CAIR NOX ozone season source and each CAIR NOX unit, CAIR SO2 unit, and 

CAIR NOX ozone season unit at the source shall keep on site at the source or at a central 

location within Indiana for those owners or operators with unattended sources, each of the 

following documents for a period of five (5) years from the date the document was created:

(a) The certificate of representation under 326 IAC 24-1-6(h), 326 IAC 24-2-6(h), 326 IAC 

24-3-6(h) for the CAIR designated representative for the source and each CAIR NOX

unit, CAIR SO2 unit, and CAIR NOX ozone season unit at the source and all documents 

that demonstrate the truth of the statements in the certificate of representation. The 

certificate and documents shall be retained on site at the source or at a central location 

within Indiana for those owners or operators with unattended sources beyond such five 

(5) year period until such documents are superseded because of the submission of a new 

account certificate of representation under 326 IAC 24-1-6(h), 326 IAC 24-2-6(h), 326 

IAC 24-3-6(h) changing the CAIR designated representative.

(b) All emissions monitoring information, in accordance with 326 IAC 24-1-11, 326 IAC 24-2-

10, and 326 IAC 24-3-11, provided that to the extent that 326 IAC 24-1-11, 326 IAC 24-2-

10, and 326 IAC 24-3-11 provides for a three (3) year period for record keeping, the 

three (3) year period shall apply.

(c) Copies of all reports, compliance certifications, and other submissions and all records 

made or required under the CAIR NOX annual trading program, CAIR SO2 trading 

program, and CAIR NOX ozone season trading program.

(d) Copies of all documents used to complete a CAIR permit application and any other 

submission under the CAIR NOX annual trading program, CAIR SO2 trading program, 

and CAIR NOX ozone season trading program or to demonstrate compliance with the 

requirements of the CAIR NOX annual trading program, CAIR SO2 trading program, and 

CAIR NOX ozone season trading program.

This period may be extended for cause, at any time before the end of five (5) years, in writing by 

IDEM, OAQ or the U.S. EPA. Unless otherwise provided, all records shall be maintained in 

accordance with Section C - General Record Keeping Requirements, of this permit.

F.7 Reporting Requirements [326 IAC 24-1-4(e)] [326 IAC 24-2-4(e)] [326 IAC 24-3-4(e)]

[40 CFR 97.106(e)] [40 CFR 97.206(e)] [40 CFR 97.306(e)]

(a) The CAIR designated representative of the CAIR NOX source, CAIR SO2 source, and 

CAIR NOX ozone season source and each CAIR NOX unit, CAIR SO2 unit, and CAIR 

NOX ozone season unit at the source shall submit the reports required under the CAIR 

NOX annual trading program, CAIR SO2 trading program, and CAIR NOX ozone season 

trading program, including those under 326 IAC 24-1-11, 326 IAC 24-2-10, and 326 IAC 

24-3-11.

(b) Pursuant to 326 IAC 24-1-4(e), 326 IAC 24-2-4(e), and 326 IAC 24-3-4(e) and 326 IAC 

24-1-6(e)(1), 326 IAC 24-2-6(e)(1), and 326 IAC 24-3-6(e)(1), each submission under the 

CAIR NOX annual trading program, CAIR SO2 trading program, and CAIR NOX ozone 
St. Joseph Energy Center, LLC Page 73 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

season trading program shall include the following certification statement by the CAIR 

designated representative: “I am authorized to make this submission on behalf of the 

owners and operators of the source or units for which the submission is made. I certify 

under penalty of law that I have personally examined, and am familiar with, the 

statements and information submitted in this document and all its attachments. Based on 

my inquiry of those individuals with primary responsibility for obtaining the information, I 

certify that the statements and information are to the best of my knowledge and belief 

true, accurate, and complete. I am aware that there are significant penalties for 

submitting false statements and information or omitting required statements and 

information, including the possibility of fine or imprisonment."

(c) Where 326 IAC 24-1, 326 IAC 24-2, and 326 IAC 24-3 requires a submission to IDEM, 

OAQ, the CAIR designated representative shall submit required information to:

Indiana Department of Environmental Management

Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

(d) Where 326 IAC 24-1, 326 IAC 24-2, and 326 IAC 24-3 requires a submission to U.S. 

EPA, the CAIR designated representative shall submit required information to:

U.S. Environmental Protection Agency

Clean Air Markets Division

1200 Pennsylvania Avenue, NW

Mail Code 6204N

Washington, DC 20460

F.8 Liability [326 IAC 24-1-4(f)] [326 IAC 24-2-4(f)] [326 IAC 24-3-4(f)] [40 CFR 97.106(f)] 

[40 CFR 97.206(f)] [40 CFR 97.306(f)]

The owners and operators of each CAIR NOX source, CAIR SO2 source, and CAIR NOX ozone 

season source and each CAIR NOX unit, CAIR SO2 unit, and CAIR NOX ozone season unit shall 

be liable as follows:

(a) Each CAIR NOX source, CAIR SO2 source, and CAIR NOX ozone season source and 

each CAIR NOX unit, CAIR SO2 unit, and CAIR NOX ozone season unit shall meet the 

requirements of the CAIR NOX annual trading program, CAIR SO2 trading program, and 

CAIR NOX ozone season trading program.

(b) Any provision of the CAIR NOX annual trading program, CAIR SO2 trading program, and 

CAIR NOX ozone season trading program that applies to a CAIR NOX source, CAIR SO2

source, and CAIR NOX ozone season source or the CAIR designated representative of a 

CAIR NOX source, CAIR SO2 source, and CAIR NOX ozone season source shall also 

apply to the owners and operators of such source and of the CAIR NOX units, CAIR SO2

units, and CAIR NOX ozone season units at the source

(c) Any provision of the CAIR NOX annual trading program, CAIR SO2 trading program, and 

CAIR NOX ozone season trading program that applies to a CAIR NOX unit, CAIR SO2

unit, and CAIR NOX ozone season unit or the CAIR designated representative of a CAIR 
St. Joseph Energy Center, LLC Page 74 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

NOX unit, CAIR SO2 unit, and CAIR NOX ozone season unit shall also apply to the 

owners and operators of such units.

F.9 Effect on Other Authorities [326 IAC 24-1-4(g)] [326 IAC 24-2-4(g)] [326 IAC 24-3-4(g)]

[40 CFR 97.106(g)] [40 CFR 97.206(g)] [40 CFR 97.306(g)]

No provision of the CAIR NOX annual trading program, CAIR SO2 trading program, and CAIR 

NOX ozone season trading program, a CAIR permit application, a CAIR permit, or an exemption 

under 326 IAC 24-1-3, 326 IAC 24-2-3, and 326 IAC 24-3-3 shall be construed as exempting or 

excluding the owners and operators, and the CAIR designated representative, of a CAIR NOX

source, CAIR SO2 source, and CAIR NOX ozone season source or CAIR NOX unit(s), CAIR SO2

unit(s), and CAIR NOX ozone season unit(s) from compliance with any other provision of the 

applicable, approved state implementation plan, a federally enforceable permit, or the Clean Air 

Act (CAA).

F.10 CAIR Designated Representative and Alternate CAIR Designated Representative 

[326 IAC 24-1-6] [326 IAC 24-2-6] [326 IAC 24-3-6] [40 CFR 97, Subpart BB] [40 CFR 97, 

Subpart BBB] [40 CFR 97, Subpart BBBB]

Pursuant to 326 IAC 24-1-6, 326 IAC 24-2-6, and 326 IAC 24-3-6:

(a) Except as specified in 326 IAC 24-1-6(f)(3), 326 IAC 24-2-6(f)(3), and 

326 IAC 24-3-6(f)(3), each CAIR NOX source, CAIR SO2 source, and CAIR NOX ozone 

season source, including all CAIR NOX units, CAIR SO2 units, and CAIR NOX ozone 

season units at the source, shall have one (1) and only one (1) CAIR designated 

representative, with regard to all matters under the CAIR NOX annual trading 

program, CAIR SO2 trading program, and CAIR NOX ozone season trading program 

concerning the source or any CAIR NOX unit, CAIR SO2 unit, and CAIR NOX ozone 

season unit at the source.

(b) The provisions of 326 IAC 24-1-6(f), 326 IAC 24-2-6(f), and 326 IAC 24-3-6(f) shall apply 

where the owners or operators of a CAIR NOX source, CAIR SO2 source, and CAIR NOX

ozone season source choose to designate an alternate CAIR designated representative.
St. Joseph Energy Center, LLC Page 75 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY

COMPLIANCE AND ENFORCEMENT BRANCH

PART 70 OPERATING PERMIT

CERTIFICATION

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

This certification shall be included when submitting monitoring, testing reports/results or other 

documents as required by this permit.

Please check what document is being certified:

 Annual Compliance Certification Letter

 Test Result (specify) 

 Report (specify) 

 Notification (specify) 

 Affidavit (specify) 

 Other (specify) 

I certify that, based on information and belief formed after reasonable inquiry, the statements and 

information in the document are true, accurate, and complete.

Signature:

Printed Name:

Title/Position:

Phone:

Date:
St. Joseph Energy Center, LLC Page 76 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

Phone: (317) 233-0178

Fax: (317) 233-6865

PART 70 OPERATING PERMIT

EMERGENCY OCCURRENCE REPORT

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

This form consists of 2 pages Page 1 of 2 

 This is an emergency as defined in 326 IAC 2-7-1(12)

• The Permittee must notify the Office of Air Quality (OAQ), within four (4) business 

hours (1-800-451-6027 or 317-233-0178, ask for Compliance Section); and

• The Permittee must submit notice in writing or by facsimile within two (2) working days 

(Facsimile Number: 317-233-6865), and follow the other requirements of 

326 IAC 2-7-16.

If any of the following are not applicable, mark N/A

Facility/Equipment/Operation:

Control Equipment:

Permit Condition or Operation Limitation in Permit:

Description of the Emergency:

Describe the cause of the Emergency: 
St. Joseph Energy Center, LLC Page 77 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

If any of the following are not applicable, mark N/A Page 2 of 2

Date/Time Emergency started:

Date/Time Emergency was corrected:

Was the facility being properly operated at the time of the emergency? Y N

Type of Pollutants Emitted: TSP, PM-10, SO2, VOC, NOX, CO, Pb, other:

Estimated amount of pollutant(s) emitted during emergency:

Describe the steps taken to mitigate the problem:

Describe the corrective actions/response steps taken:

Describe the measures taken to minimize emissions:

If applicable, describe the reasons why continued operation of the facilities are necessary to prevent 

imminent injury to persons, severe damage to equipment, substantial loss of capital investment, or loss 

of product or raw materials of substantial economic value:

Form Completed by:

Title / Position:

Date:

Phone: 
St. Joseph Energy Center, LLC Page 78 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combined Cycle Combustion Turbine CCCT1

Parameter: NOx Emissions

Limit: shall not exceed 81.6 tons per twelve (12) consecutive month period, for the 

duration of the combined startup and shutdown events, with compliance 

determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 79 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combined Cycle Combustion TurbineCCCT2

Parameter: NOx Emissions

Limit: shall not exceed 81.6 tons per twelve (12) consecutive month period, for the 

duration of the combined startup and shutdown events, with compliance 

determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 80 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combined Cycle Combustion TurbineCCCT3

Parameter: NOx Emissions

Limit: shall not exceed 81.6 tons per twelve (12) consecutive month period, for the 

duration of the combined startup and shutdown events, with compliance 

determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 81 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combined Cycle Combustion TurbineCCCT4

Parameter: NOx Emissions

Limit: shall not exceed 81.6 tons per twelve (12) consecutive month period, for the 

duration of the combined startup and shutdown events, with compliance 

determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 82 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combined Cycle Combustion TurbineCCCT1

Parameter: CO Emissions

Limit: shall not exceed 407.5 tons per twelve (12) consecutive month period, for the 

duration of the combined startup and shutdown events, with compliance 

determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 83 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combined Cycle Combustion TurbineCCCT2

Parameter: CO Emissions

Limit: shall not exceed 407.5 tons per twelve (12) consecutive month period, for the 

duration of the combined startup and shutdown events, with compliance 

determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 84 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combined Cycle Combustion Turbine CCCT3

Parameter: CO Emissions

Limit: shall not exceed 407.5 tons per twelve (12) consecutive month period, for the 

duration of the combined startup and shutdown events, with compliance 

determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 85 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combined Cycle Combustion Turbine CCCT4

Parameter: CO Emissions

Limit: shall not exceed 407.5 tons per twelve (12) consecutive month period, for the 

duration of the combined startup and shutdown events, with compliance 

determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 86 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combustion Turbine CCCT1

Parameter: VOC Emissions

Limit: shall not exceed 22.0 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 87 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combustion Turbine CCCT2

Parameter: VOC Emissions

Limit: shall not exceed 22.0 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 88 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combustion Turbine CCCT3

Parameter: VOC Emissions

Limit: shall not exceed 22.0 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 89 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combustion Turbine CCCT4

Parameter: VOC Emissions

Limit: shall not exceed 22.0 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 90 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combined Cycle Combustion Turbine CCCT1

Parameter: Hours of Operation

Limit: shall not exceed 365.0 tons per twelve (12) consecutive month period, for the 

duration of the combined startup and shutdown events, with compliance 

determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 91 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combined Cycle Combustion Turbine CCCT2

Parameter: Hours of Operation

Limit: shall not exceed 365.0 tons per twelve (12) consecutive month period, for the 

duration of the combined startup and shutdown events, with compliance 

determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 92 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combined Cycle Combustion Turbine CCCT3

Parameter: Hours of Operation

Limit: shall not exceed 365.0 tons per twelve (12) consecutive month period, for the 

duration of the combined startup and shutdown events, with compliance 

determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 93 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combined Cycle Combustion Turbine CCCT4

Parameter: Hours of Operation

Limit: shall not exceed 365.0 tons per twelve (12) consecutive month period, for the 

duration of the combined startup and shutdown events, with compliance 

determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 94 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Firewater Pump Engines FP01

Parameter: Hours of Operation

Limit: shall not exceed 500 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 95 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Firewater Pump Engines FP02

Parameter: Hours of Operation

Limit: shall not exceed 500 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 96 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Emergency Diesel Generator EG01

Parameter: Hours of Operation

Limit: shall not exceed 500 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 97 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Emergency Diesel Generator EG02

Parameter: Hours of Operation

Limit: shall not exceed 500 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 98 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Emergency Diesel Generator EG03

Parameter: Hours of Operation

Limit: shall not exceed 500 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 99 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Combined Cycle Combustion Turbine CCCT1 - CCCT4

Parameter: CO2e 

Limit: shall not exceed 4,885,512 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 100 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Auxiliary Boilers B001-B002

Parameter: CO2e

Limit: shall not exceed 81,996 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 101 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Emergency Generator EG01 -EG03

Parameter: CO2e

Limit: shall not exceed 1,186 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 102 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Facility: Firewater Pumps FP01-FP02

Parameter: Hours of Operation

Limit: shall not exceed 172 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
St. Joseph Energy Center, LLC Page 103 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

PART 70 OPERATING PERMIT

QUARTERLY DEVIATION AND COMPLIANCE MONITORING REPORT

Source Name: St. Joseph Energy Center, LLC

Source Address: Corner of Walnut and Edison Roads, New Carlisle, Indiana 46552

Part 70 Permit No.: T141-31003-00579

Months: to Year: 

Page 1 of 2

This report shall be submitted quarterly based on a calendar year. Any deviation from the 

requirements of this permit, the date(s) of each deviation, the probable cause of the deviation, and 

the response steps taken must be reported. A deviation required to be reported pursuant to an 

applicable requirement that exists independent of the permit, shall be reported according to the 

schedule stated in the applicable requirement and does not need to be included in this report. 

Additional pages may be attached if necessary. If no deviations occurred, please specify in the box 

marked "No deviations occurred this reporting period".

 NO DEVIATIONS OCCURRED THIS REPORTING PERIOD.

 THE FOLLOWING DEVIATIONS OCCURRED THIS REPORTING PERIOD

Permit Requirement (specify permit condition #)

Date of Deviation: Duration of Deviation:

Number of Deviations:

Probable Cause of Deviation:

Response Steps Taken:

Permit Requirement (specify permit condition #)

Date of Deviation: Duration of Deviation:

Number of Deviations:

Probable Cause of Deviation:

Response Steps Taken:
St. Joseph Energy Center, LLC Page 104 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

Page 2 of 2

Permit Requirement (specify permit condition #)

Date of Deviation: Duration of Deviation:

Number of Deviations:

Probable Cause of Deviation:

Response Steps Taken:

Permit Requirement (specify permit condition #)

Date of Deviation: Duration of Deviation:

Number of Deviations:

Probable Cause of Deviation:

Response Steps Taken:

Permit Requirement (specify permit condition #)

Date of Deviation: Duration of Deviation:

Number of Deviations:

Probable Cause of Deviation:

Response Steps Taken:

Form Completed by:

Title / Position:

Date:

Phone: 

 
St. Joseph Energy Center, LLC Page 105 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

Mail to: Permit Administration and Support Section

Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

St. Joseph Energy Center, LLC

Corner of Walnut and Edison Roads

New Carlisle, Indiana 46552

Affidavit of Construction

I, , being duly sworn upon my oath, depose and say:

(Name of the Authorized Representative)

1. I live in County, Indiana and being of sound mind 

and over twenty-one (21) years of age, I am competent to give this affidavit.

2. I hold the position of for .

 (Title) (Company Name)

3. By virtue of my position with , I have personal

(Company Name)

knowledge of the representations contained in this affidavit and am authorized to make

these representations on behalf of .

(Company Name)

4. I hereby certify that St. Joseph Energy Center, LLC Corner of Walnut and Edison Roads, 

New Carlisle, Indiana 46552, completed construction of the electric utility generating 

station on in conformity with the requirements and intent of the 

construction permit application received by the Office of Air Quality on Reviewer: Insert 

date application received at IDEM and as permitted pursuant to New Source 

Construction Permit and Part 70 Operating Permit No. T141-31003-00579, Plant ID No. 

141-00579 issued on .

5. Permittee, please cross out the following statement if it does not apply: Additional 

(operations/facilities) were constructed/substituted as described in the attachment to this 

document and were not made in accordance with the construction permit. 
St. Joseph Energy Center, LLC Page 106 of 106

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

Further Affiant said not.

I affirm under penalties of perjury that the representations contained in this affidavit are true, to the best of 

my information and belief.

Signature

Date

STATE OF INDIANA)

 )SS

COUNTY OF )

Subscribed and sworn to me, a notary public in and for County and 

State of Indiana on this day of , 20 . My 

Commission expires: .

Signature

Name (typed or 

printed)
Attachment A to a PSD/Part 70 Operating Permit

Standards of Performance for Small Industrial-Commercial-Institutional 

Steam Generating Units [40 CFR Part 60, Subpart Dc] [326 IAC 12]

Source Name: St. Joseph Energy Center, LLC

Source Location: Corner of Walnut and Edison Roads, 

New Carlisle, Indiana 46552

County: St. Joseph

SIC Code: 4911

Operation Permit No.: T 141-31003-00579

Operation Permit Issuance Date: Yet to be issued

Permit Reviewer: Josiah Balogun

Subpart Dc—Standards of Performance for Small Industrial-CommercialInstitutional Steam Generating Units

Source: 72 FR 32759, June 13, 2007, unless otherwise noted.

§ 60.40c Applicability and delegation of authority.

(a) Except as provided in paragraphs (d), (e), (f), and (g) of this section, the affected facility to which this subpart 

applies is each steam generating unit for which construction, modification, or reconstruction is commenced after June 

9, 1989 and that has a maximum design heat input capacity of 29 megawatts (MW) (100 million British thermal units 

per hour (MMBtu/hr)) or less, but greater than or equal to 2.9 MW (10 MMBtu/hr).

(b) In delegating implementation and enforcement authority to a State under section 111(c) of the Clean Air Act, 

§60.48c(a)(4) shall be retained by the Administrator and not transferred to a State.

(c) Steam generating units that meet the applicability requirements in paragraph (a) of this section are not subject to 

the sulfur dioxide (SO2) or particulate matter (PM) emission limits, performance testing requirements, or monitoring 

requirements under this subpart (§§60.42c, 60.43c, 60.44c, 60.45c, 60.46c, or 60.47c) during periods of combustion 

research, as defined in §60.41c.

(d) Any temporary change to an existing steam generating unit for the purpose of conducting combustion research is 

not considered a modification under §60.14.

(e) Heat recovery steam generators that are associated with combined cycle gas turbines and meet the applicability 

requirements of subpart KKKK of this part are not subject to this subpart. This subpart will continue to apply to all 

other heat recovery steam generators that are capable of combusting more than or equal to 2.9 MW (10 MMBtu/hr) 

heat input of fossil fuel but less than or equal to 29 MW (100 MMBtu/hr) heat input of fossil fuel. If the heat recovery 

steam generator is subject to this subpart, only emissions resulting from combustion of fuels in the steam generating 

unit are subject to this subpart. (The gas turbine emissions are subject to subpart GG or KKKK, as applicable, of this 

part).

(f) Any facility covered by subpart AAAA of this part is not subject by this subpart.

(g) Any facility covered by an EPA approved State or Federal section 111(d)/129 plan implementing subpart BBBB of 

this part is not subject by this subpart.

[72 FR 32759, June 13, 2007, as amended at 74 FR 5090, Jan. 28, 2009]
St. Joseph Energy Center, LLC Page 2 of 19

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

§ 60.41c Definitions.

As used in this subpart, all terms not defined herein shall have the meaning given them in the Clean Air Act and in 

subpart A of this part.

Annual capacity factor means the ratio between the actual heat input to a steam generating unit from an individual 

fuel or combination of fuels during a period of 12 consecutive calendar months and the potential heat input to the 

steam generating unit from all fuels had the steam generating unit been operated for 8,760 hours during that 12-

month period at the maximum design heat input capacity. In the case of steam generating units that are rented or 

leased, the actual heat input shall be determined based on the combined heat input from all operations of the affected 

facility during a period of 12 consecutive calendar months.

Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of 

Testing and Materials in ASTM D388 (incorporated by reference, see §60.17), coal refuse, and petroleum coke. Coalderived synthetic fuels derived from coal for the purposes of creating useful heat, including but not limited to solvent 

refined coal, gasified coal not meeting the definition of natural gas, coal-oil mixtures, and coal-water mixtures, are 

also included in this definition for the purposes of this subpart.

Coal refuse means any by-product of coal mining or coal cleaning operations with an ash content greater than 50 

percent (by weight) and a heating value less than 13,900 kilojoules per kilogram (kJ/kg) (6,000 Btu per pound (Btu/lb) 

on a dry basis.

Cogeneration steam generating unit means a steam generating unit that simultaneously produces both electrical (or 

mechanical) and thermal energy from the same primary energy source.

Combined cycle system means a system in which a separate source (such as a stationary gas turbine, internal 

combustion engine, or kiln) provides exhaust gas to a steam generating unit.

Combustion research means the experimental firing of any fuel or combination of fuels in a steam generating unit for 

the purpose of conducting research and development of more efficient combustion or more effective prevention or 

control of air pollutant emissions from combustion, provided that, during these periods of research and development, 

the heat generated is not used for any purpose other than preheating combustion air for use by that steam generating 

unit ( i.e. , the heat generated is released to the atmosphere without being used for space heating, process heating, 

driving pumps, preheating combustion air for other units, generating electricity, or any other purpose).

Conventional technology means wet flue gas desulfurization technology, dry flue gas desulfurization technology, 

atmospheric fluidized bed combustion technology, and oil hydrodesulfurization technology.

Distillate oil means fuel oil that complies with the specifications for fuel oil numbers 1 or 2, as defined by the American 

Society for Testing and Materials in ASTM D396 (incorporated by reference, see §60.17) or diesel fuel oil numbers 1 

or 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see 

§60.17).

Dry flue gas desulfurization technology means a SO2control system that is located between the steam generating 

unit and the exhaust vent or stack, and that removes sulfur oxides from the combustion gases of the steam 

generating unit by contacting the combustion gases with an alkaline reagent and water, whether introduced 

separately or as a premixed slurry or solution and forming a dry powder material. This definition includes devices 

where the dry powder material is subsequently converted to another form. Alkaline reagents used in dry flue gas 

desulfurization systems include, but are not limited to, lime and sodium compounds.

Duct burner means a device that combusts fuel and that is placed in the exhaust duct from another source (such as a 

stationary gas turbine, internal combustion engine, kiln, etc.) to allow the firing of additional fuel to heat the exhaust 

gases before the exhaust gases enter a steam generating unit.

Emerging technology means any SO2control system that is not defined as a conventional technology under this 

section, and for which the owner or operator of the affected facility has received approval from the Administrator to 

operate as an emerging technology under §60.48c(a)(4).
St. Joseph Energy Center, LLC Page 3 of 19

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Federally enforceable means all limitations and conditions that are enforceable by the Administrator, including the 

requirements of 40 CFR parts 60 and 61, requirements within any applicable State implementation plan, and any 

permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 51.24.

Fluidized bed combustion technology means a device wherein fuel is distributed onto a bed (or series of beds) of 

limestone aggregate (or other sorbent materials) for combustion; and these materials are forced upward in the device 

by the flow of combustion air and the gaseous products of combustion. Fluidized bed combustion technology 

includes, but is not limited to, bubbling bed units and circulating bed units.

Fuel pretreatment means a process that removes a portion of the sulfur in a fuel before combustion of the fuel in a 

steam generating unit.

Heat input means heat derived from combustion of fuel in a steam generating unit and does not include the heat 

derived from preheated combustion air, recirculated flue gases, or exhaust gases from other sources (such as 

stationary gas turbines, internal combustion engines, and kilns).

Heat transfer medium means any material that is used to transfer heat from one point to another point.

Maximum design heat input capacity means the ability of a steam generating unit to combust a stated maximum 

amount of fuel (or combination of fuels) on a steady state basis as determined by the physical design and 

characteristics of the steam generating unit.

Natural gas means:

(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the 

earth's surface, of which the principal constituent is methane; or

(2) Liquefied petroleum (LP) gas, as defined by the American Society for Testing and Materials in ASTM D1835 

(incorporated by reference, see §60.17); or

(3) A mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additionally, natural gas must either 

be composed of at least 70 percent methane by volume or have a gross calorific value between 34 and 43 

megajoules (MJ) per dry standard cubic meter (910 and 1,150 Btu per dry standard cubic foot).

Noncontinental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of 

Puerto Rico, or the Northern Mariana Islands.

Oil means crude oil or petroleum, or a liquid fuel derived from crude oil or petroleum, including distillate oil and 

residual oil.

Potential sulfur dioxide emission rate means the theoretical SO2emissions (nanograms per joule (ng/J) or lb/MMBtu 

heat input) that would result from combusting fuel in an uncleaned state and without using emission control systems.

Process heater means a device that is primarily used to heat a material to initiate or promote a chemical reaction in 

which the material participates as a reactant or catalyst.

Residual oil means crude oil, fuel oil that does not comply with the specifications under the definition of distillate oil, 

and all fuel oil numbers 4, 5, and 6, as defined by the American Society for Testing and Materials in ASTM D396 

(incorporated by reference, see §60.17).

Steam generating unit means a device that combusts any fuel and produces steam or heats water or heats any heat 

transfer medium. This term includes any duct burner that combusts fuel and is part of a combined cycle system. This 

term does not include process heaters as defined in this subpart.
St. Joseph Energy Center, LLC Page 4 of 19

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Steam generating unit operating day means a 24-hour period between 12:00 midnight and the following midnight 

during which any fuel is combusted at any time in the steam generating unit. It is not necessary for fuel to be 

combusted continuously for the entire 24-hour period.

Wet flue gas desulfurization technology means an SO2control system that is located between the steam generating 

unit and the exhaust vent or stack, and that removes sulfur oxides from the combustion gases of the steam 

generating unit by contacting the combustion gases with an alkaline slurry or solution and forming a liquid material. 

This definition includes devices where the liquid material is subsequently converted to another form. Alkaline 

reagents used in wet flue gas desulfurization systems include, but are not limited to, lime, limestone, and sodium 

compounds.

Wet scrubber system means any emission control device that mixes an aqueous stream or slurry with the exhaust 

gases from a steam generating unit to control emissions of PM or SO2.

Wood means wood, wood residue, bark, or any derivative fuel or residue thereof, in any form, including but not limited 

to sawdust, sanderdust, wood chips, scraps, slabs, millings, shavings, and processed pellets made from wood or 

other forest residues.

[72 FR 32759, June 13, 2007, as amended at 74 FR 5090, Jan. 28, 2009]

§ 60.42c Standard for sulfur dioxide (SO2).

(a) Except as provided in paragraphs (b), (c), and (e) of this section, on and after the date on which the performance 

test is completed or required to be completed under §60.8, whichever date comes first, the owner or operator of an 

affected facility that combusts only coal shall neither: cause to be discharged into the atmosphere from the affected 

facility any gases that contain SO2in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the 

potential SO2emission rate (90 percent reduction), nor cause to be discharged into the atmosphere from the affected 

facility any gases that contain SO2in excess of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is combusted with other 

fuels, the affected facility shall neither: cause to be discharged into the atmosphere from the affected facility any 

gases that contain SO2in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential 

SO2emission rate (90 percent reduction), nor cause to be discharged into the atmosphere from the affected facility 

any gases that contain SO2in excess of the emission limit is determined pursuant to paragraph (e)(2) of this section.

(b) Except as provided in paragraphs (c) and (e) of this section, on and after the date on which the performance test 

is completed or required to be completed under §60.8, whichever date comes first, the owner or operator of an 

affected facility that:

(1) Combusts only coal refuse alone in a fluidized bed combustion steam generating unit shall neither:

(i) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2in excess of 87 

ng/J (0.20 lb/MMBtu) heat input or 20 percent (0.20) of the potential SO2emission rate (80 percent reduction); nor

(ii) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2in excess of 

SO2in excess of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is fired with coal refuse, the affected facility subject to 

paragraph (a) of this section. If oil or any other fuel (except coal) is fired with coal refuse, the affected facility is 

subject to the 87 ng/J (0.20 lb/MMBtu) heat input SO2emissions limit or the 90 percent SO2reduction requirement 

specified in paragraph (a) of this section and the emission limit is determined pursuant to paragraph (e)(2) of this 

section.

(2) Combusts only coal and that uses an emerging technology for the control of SO2emissions shall neither:

(i) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2in excess of 50 

percent (0.50) of the potential SO2emission rate (50 percent reduction); nor

(ii) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2in excess of 260 

ng/J (0.60 lb/MMBtu) heat input. If coal is combusted with other fuels, the affected facility is subject to the 50 percent 
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SO2reduction requirement specified in this paragraph and the emission limit determined pursuant to paragraph (e)(2) 

of this section.

(c) On and after the date on which the initial performance test is completed or required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected facility that combusts coal, alone or in combination 

with any other fuel, and is listed in paragraphs (c)(1), (2), (3), or (4) of this section shall cause to be discharged into 

the atmosphere from that affected facility any gases that contain SO2in excess of the emission limit determined 

pursuant to paragraph (e)(2) of this section. Percent reduction requirements are not applicable to affected facilities 

under paragraphs (c)(1), (2), (3), or (4).

(1) Affected facilities that have a heat input capacity of 22 MW (75 MMBtu/hr) or less.

(2) Affected facilities that have an annual capacity for coal of 55 percent (0.55) or less and are subject to a federally 

enforceable requirement limiting operation of the affected facility to an annual capacity factor for coal of 55 percent 

(0.55) or less.

(3) Affected facilities located in a noncontinental area.

(4) Affected facilities that combust coal in a duct burner as part of a combined cycle system where 30 percent (0.30) 

or less of the heat entering the steam generating unit is from combustion of coal in the duct burner and 70 percent 

(0.70) or more of the heat entering the steam generating unit is from exhaust gases entering the duct burner.

(d) On and after the date on which the initial performance test is completed or required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected facility that combusts oil shall cause to be discharged 

into the atmosphere from that affected facility any gases that contain SO2in excess of 215 ng/J (0.50 lb/MMBtu) heat 

input; or, as an alternative, no owner or operator of an affected facility that combusts oil shall combust oil in the 

affected facility that contains greater than 0.5 weight percent sulfur. The percent reduction requirements are not 

applicable to affected facilities under this paragraph.

(e) On and after the date on which the initial performance test is completed or required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected facility that combusts coal, oil, or coal and oil with any 

other fuel shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO2in 

excess of the following:

(1) The percent of potential SO2emission rate or numerical SO2emission rate required under paragraph (a) or (b)(2) 

of this section, as applicable, for any affected facility that

(i) Combusts coal in combination with any other fuel;

(ii) Has a heat input capacity greater than 22 MW (75 MMBtu/hr); and

(iii) Has an annual capacity factor for coal greater than 55 percent (0.55); and

(2) The emission limit determined according to the following formula for any affected facility that combusts coal, oil, or 

coal and oil with any other fuel:

Where:

Es= SO2emission limit, expressed in ng/J or lb/MMBtu heat input;

Ka= 520 ng/J (1.2 lb/MMBtu);
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Kb= 260 ng/J (0.60 lb/MMBtu);

Kc= 215 ng/J (0.50 lb/MMBtu);

Ha= Heat input from the combustion of coal, except coal combusted in an affected facility subject to 

paragraph (b)(2) of this section, in Joules (J) [MMBtu];

Hb= Heat input from the combustion of coal in an affected facility subject to paragraph (b)(2) of this 

section, in J (MMBtu); and

Hc= Heat input from the combustion of oil, in J (MMBtu).

(f) Reduction in the potential SO2emission rate through fuel pretreatment is not credited toward the percent reduction 

requirement under paragraph (b)(2) of this section unless:

(1) Fuel pretreatment results in a 50 percent (0.50) or greater reduction in the potential SO2emission rate; and

(2) Emissions from the pretreated fuel (without either combustion or post-combustion SO2control) are equal to or less 

than the emission limits specified under paragraph (b)(2) of this section.

(g) Except as provided in paragraph (h) of this section, compliance with the percent reduction requirements, fuel oil 

sulfur limits, and emission limits of this section shall be determined on a 30-day rolling average basis.

(h) For affected facilities listed under paragraphs (h)(1), (2), or (3) of this section, compliance with the emission limits 

or fuel oil sulfur limits under this section may be determined based on a certification from the fuel supplier, as 

described under §60.48c(f), as applicable.

(1) Distillate oil-fired affected facilities with heat input capacities between 2.9 and 29 MW (10 and 100 MMBtu/hr).

(2) Residual oil-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/hr).

(3) Coal-fired facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/hr).

(i) The SO2emission limits, fuel oil sulfur limits, and percent reduction requirements under this section apply at all 

times, including periods of startup, shutdown, and malfunction.

(j) For affected facilities located in noncontinental areas and affected facilities complying with the percent reduction 

standard, only the heat input supplied to the affected facility from the combustion of coal and oil is counted under this 

section. No credit is provided for the heat input to the affected facility from wood or other fuels or for heat derived 

from exhaust gases from other sources, such as stationary gas turbines, internal combustion engines, and kilns.

[72 FR 32759, June 13, 2007, as amended at 74 FR 5090, Jan. 28, 2009]

§ 60.43c Standard for particulate matter (PM).

(a) On and after the date on which the initial performance test is completed or required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, 

or modification on or before February 28, 2005, that combusts coal or combusts mixtures of coal with other fuels and 

has a heat input capacity of 8.7 MW (30 MMBtu/hr) or greater, shall cause to be discharged into the atmosphere from 

that affected facility any gases that contain PM in excess of the following emission limits:

(1) 22 ng/J (0.051 lb/MMBtu) heat input if the affected facility combusts only coal, or combusts coal with other fuels 

and has an annual capacity factor for the other fuels of 10 percent (0.10) or less.
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(2) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility combusts coal with other fuels, has an annual capacity 

factor for the other fuels greater than 10 percent (0.10), and is subject to a federally enforceable requirement limiting 

operation of the affected facility to an annual capacity factor greater than 10 percent (0.10) for fuels other than coal.

(b) On and after the date on which the initial performance test is completed or required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, 

or modification on or before February 28, 2005, that combusts wood or combusts mixtures of wood with other fuels 

(except coal) and has a heat input capacity of 8.7 MW (30 MMBtu/hr) or greater, shall cause to be discharged into the 

atmosphere from that affected facility any gases that contain PM in excess of the following emissions limits:

(1) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has an annual capacity factor for wood greater than 30 

percent (0.30); or

(2) 130 ng/J (0.30 lb/MMBtu) heat input if the affected facility has an annual capacity factor for wood of 30 percent 

(0.30) or less and is subject to a federally enforceable requirement limiting operation of the affected facility to an 

annual capacity factor for wood of 30 percent (0.30) or less.

(c) On and after the date on which the initial performance test is completed or required to be completed under §60.8, 

whichever date comes first, no owner or operator of an affected facility that can combust coal, wood, or oil and has a 

heat input capacity of 8.7 MW (30 MMBtu/hr) or greater shall cause to be discharged into the atmosphere from that

affected facility any gases that exhibit greater than 20 percent opacity (6-minute average), except for one 6-minute 

period per hour of not more than 27 percent opacity. Owners and operators of an affected facility that elect to install, 

calibrate, maintain, and operate a continuous emissions monitoring system (CEMS) for measuring PM emissions 

according to the requirements of this subpart and are subject to a federally enforceable PM limit of 0.030 lb/MMBtu or 

less are exempt from the opacity standard specified in this paragraph.

(d) The PM and opacity standards under this section apply at all times, except during periods of startup, shutdown, or 

malfunction.

(e)(1) On and after the date on which the initial performance test is completed or is required to be completed under 

§60.8, whichever date comes first, no owner or operator of an affected facility that commences construction, 

reconstruction, or modification after February 28, 2005, and that combusts coal, oil, wood, a mixture of these fuels, or 

a mixture of these fuels with any other fuels and has a heat input capacity of 8.7 MW (30 MMBtu/hr) or greater shall 

cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 13 ng/J 

(0.030 lb/MMBtu) heat input, except as provided in paragraphs (e)(2), (e)(3), and (e)(4) of this section.

(2) As an alternative to meeting the requirements of paragraph (e)(1) of this section, the owner or operator of an 

affected facility for which modification commenced after February 28, 2005, may elect to meet the requirements of 

this paragraph. On and after the date on which the initial performance test is completed or required to be completed 

under §60.8, whichever date comes first, no owner or operator of an affected facility that commences modification 

after February 28, 2005 shall cause to be discharged into the atmosphere from that affected facility any gases that 

contain PM in excess of both:

(i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion of coal, oil, wood, a mixture of these fuels, or a 

mixture of these fuels with any other fuels; and

(ii) 0.2 percent of the combustion concentration (99.8 percent reduction) when combusting coal, oil, wood, a mixture 

of these fuels, or a mixture of these fuels with any other fuels.

(3) On and after the date on which the initial performance test is completed or is required to be completed under 

§60.8, whichever date comes first, no owner or operator of an affected facility that commences modification after 

February 28, 2005, and that combusts over 30 percent wood (by heat input) on an annual basis and has a heat input 

capacity of 8.7 MW (30 MMBtu/hr) or greater shall cause to be discharged into the atmosphere from that affected 

facility any gases that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.

(4) On and after the date on which the initial performance test is completed or is required to be completed under 

§60.8, whichever date comes first, an owner or operator of an affected facility that commences construction, 

reconstruction, or modification after February 28, 2005, and that combusts only oil that contains no more than 0.50 
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weight percent sulfur or a mixture of 0.50 weight percent sulfur oil with other fuels not subject to a PM standard under 

§60.43c and not using a post-combustion technology (except a wet scrubber) to reduce PM or SO2emissions is not 

subject to the PM limit in this section.

[72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009]

§ 60.44c Compliance and performance test methods and procedures for 

sulfur dioxide.

(a) Except as provided in paragraphs (g) and (h) of this section and §60.8(b), performance tests required under §60.8 

shall be conducted following the procedures specified in paragraphs (b), (c), (d), (e), and (f) of this section, as 

applicable. Section 60.8(f) does not apply to this section. The 30-day notice required in §60.8(d) applies only to the 

initial performance test unless otherwise specified by the Administrator.

(b) The initial performance test required under §60.8 shall be conducted over 30 consecutive operating days of the 

steam generating unit. Compliance with the percent reduction requirements and SO2emission limits under §60.42c 

shall be determined using a 30-day average. The first operating day included in the initial performance test shall be 

scheduled within 30 days after achieving the maximum production rate at which the affect facility will be operated, but 

not later than 180 days after the initial startup of the facility. The steam generating unit load during the 30-day period 

does not have to be the maximum design heat input capacity, but must be representative of future operating 

conditions.

(c) After the initial performance test required under paragraph (b) of this section and §60.8, compliance with the 

percent reduction requirements and SO2emission limits under §60.42c is based on the average percent reduction 

and the average SO2emission rates for 30 consecutive steam generating unit operating days. A separate 

performance test is completed at the end of each steam generating unit operating day, and a new 30-day average 

percent reduction and SO2emission rate are calculated to show compliance with the standard.

(d) If only coal, only oil, or a mixture of coal and oil is combusted in an affected facility, the procedures in Method 19 

of appendix A of this part are used to determine the hourly SO2emission rate (Eho) and the 30-day average 

SO2emission rate (Eao). The hourly averages used to compute the 30-day averages are obtained from the CEMS. 

Method 19 of appendix A of this part shall be used to calculate Eaowhen using daily fuel sampling or Method 6B of 

appendix A of this part.

(e) If coal, oil, or coal and oil are combusted with other fuels:

(1) An adjusted Eho(Ehoo) is used in Equation 19–19 of Method 19 of appendix A of this part to compute the adjusted 

Eao(Eaoo). The Ehoo is computed using the following formula:

Where:

Ehoo = Adjusted Eho, ng/J (lb/MMBtu);

Eho= Hourly SO2emission rate, ng/J (lb/MMBtu);

Ew= SO2concentration in fuels other than coal and oil combusted in the affected facility, as determined by 

fuel sampling and analysis procedures in Method 9 of appendix A of this part, ng/J (lb/MMBtu). The value 

Ewfor each fuel lot is used for each hourly average during the time that the lot is being combusted. The 

owner or operator does not have to measure Ewif the owner or operator elects to assume Ew= 0.
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Xk= Fraction of the total heat input from fuel combustion derived from coal and oil, as determined by 

applicable procedures in Method 19 of appendix A of this part.

(2) The owner or operator of an affected facility that qualifies under the provisions of §60.42c(c) or (d) (where percent 

reduction is not required) does not have to measure the parameters Ewor Xkif the owner or operator of the affected 

facility elects to measure emission rates of the coal or oil using the fuel sampling and analysis procedures under 

Method 19 of appendix A of this part.

(f) Affected facilities subject to the percent reduction requirements under §60.42c(a) or (b) shall determine 

compliance with the SO2emission limits under §60.42c pursuant to paragraphs (d) or (e) of this section, and shall 

determine compliance with the percent reduction requirements using the following procedures:

(1) If only coal is combusted, the percent of potential SO2emission rate is computed using the following formula:

Where:

%Ps= Potential SO2emission rate, in percent;

%Rg= SO2removal efficiency of the control device as determined by Method 19 of appendix A of this part, 

in percent; and

%Rf= SO2removal efficiency of fuel pretreatment as determined by Method 19 of appendix A of this part, 

in percent.

(2) If coal, oil, or coal and oil are combusted with other fuels, the same procedures required in paragraph (f)(1) of this 

section are used, except as provided for in the following:

(i) To compute the %Ps, an adjusted %Rg(%Rgo) is computed from Eaoo from paragraph (e)(1) of this section and an 

adjusted average SO2inlet rate (Eaio) using the following formula:

Where:

%Rgo = Adjusted %Rg, in percent;

Eaoo = Adjusted Eao, ng/J (lb/MMBtu); and

Eaio = Adjusted average SO2inlet rate, ng/J (lb/MMBtu).

(ii) To compute Eaio, an adjusted hourly SO2inlet rate (Ehio) is used. The Ehio is computed using the following 

formula:

Where:
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Ehio = Adjusted Ehi, ng/J (lb/MMBtu);

Ehi= Hourly SO2inlet rate, ng/J (lb/MMBtu);

Ew= SO2concentration in fuels other than coal and oil combusted in the affected facility, as determined by 

fuel sampling and analysis procedures in Method 19 of appendix A of this part, ng/J (lb/MMBtu). The 

value Ewfor each fuel lot is used for each hourly average during the time that the lot is being combusted. 

The owner or operator does not have to measure Ewif the owner or operator elects to assume Ew= 0; and

Xk= Fraction of the total heat input from fuel combustion derived from coal and oil, as determined by 

applicable procedures in Method 19 of appendix A of this part.

(g) For oil-fired affected facilities where the owner or operator seeks to demonstrate compliance with the fuel oil sulfur 

limits under §60.42c based on shipment fuel sampling, the initial performance test shall consist of sampling and 

analyzing the oil in the initial tank of oil to be fired in the steam generating unit to demonstrate that the oil contains 0.5 

weight percent sulfur or less. Thereafter, the owner or operator of the affected facility shall sample the oil in the fuel 

tank after each new shipment of oil is received, as described under §60.46c(d)(2).

(h) For affected facilities subject to §60.42c(h)(1), (2), or (3) where the owner or operator seeks to demonstrate 

compliance with the SO2standards based on fuel supplier certification, the performance test shall consist of the 

certification from the fuel supplier, as described in §60.48c(f), as applicable.

(i) The owner or operator of an affected facility seeking to demonstrate compliance with the SO2standards under 

§60.42c(c)(2) shall demonstrate the maximum design heat input capacity of the steam generating unit by operating 

the steam generating unit at this capacity for 24 hours. This demonstration shall be made during the initial 

performance test, and a subsequent demonstration may be requested at any other time. If the demonstrated 24-hour 

average firing rate for the affected facility is less than the maximum design heat input capacity stated by the 

manufacturer of the affected facility, the demonstrated 24-hour average firing rate shall be used to determine the 

annual capacity factor for the affected facility; otherwise, the maximum design heat input capacity provided by the 

manufacturer shall be used.

(j) The owner or operator of an affected facility shall use all valid SO2emissions data in calculating %Psand Ehounder 

paragraphs (d), (e), or (f) of this section, as applicable, whether or not the minimum emissions data requirements 

under §60.46c(f) are achieved. All valid emissions data, including valid data collected during periods of startup, 

shutdown, and malfunction, shall be used in calculating %Psor Ehopursuant to paragraphs (d), (e), or (f) of this 

section, as applicable.

[72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009]

§ 60.45c Compliance and performance test methods and procedures for 

particulate matter.

(a) The owner or operator of an affected facility subject to the PM and/or opacity standards under §60.43c shall 

conduct an initial performance test as required under §60.8, and shall conduct subsequent performance tests as 

requested by the Administrator, to determine compliance with the standards using the following procedures and 

reference methods, except as specified in paragraph (c) of this section.

(1) Method 1 of appendix A of this part shall be used to select the sampling site and the number of traverse sampling 

points.

(2) Method 3A or 3B of appendix A–2 of this part shall be used for gas analysis when applying Method 5 or 5B of 

appendix A–3 of this part or 17 of appendix A–6 of this part.

(3) Method 5, 5B, or 17 of appendix A of this part shall be used to measure the concentration of PM as follows:
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(i) Method 5 of appendix A of this part may be used only at affected facilities without wet scrubber systems.

(ii) Method 17 of appendix A of this part may be used at affected facilities with or without wet scrubber systems 

provided the stack gas temperature does not exceed a temperature of 160 °C (320 °F). The procedures of Sections 

8.1 and 11.1 of Method 5B of appendix A of this part may be used in Method 17 of appendix A of this part only if 

Method 17 of appendix A of this part is used in conjunction with a wet scrubber system. Method 17 of appendix A of 

this part shall not be used in conjunction with a wet scrubber system if the effluent is saturated or laden with water 

droplets.

(iii) Method 5B of appendix A of this part may be used in conjunction with a wet scrubber system.

(4) The sampling time for each run shall be at least 120 minutes and the minimum sampling volume shall be 1.7 dry 

standard cubic meters (dscm) [60 dry standard cubic feet (dscf)] except that smaller sampling times or volumes may 

be approved by the Administrator when necessitated by process variables or other factors.

(5) For Method 5 or 5B of appendix A of this part, the temperature of the sample gas in the probe and filter holder 

shall be monitored and maintained at 160 ±14 °C (320±25 °F).

(6) For determination of PM emissions, an oxygen (O2) or carbon dioxide (CO2) measurement shall be obtained 

simultaneously with each run of Method 5, 5B, or 17 of appendix A of this part by traversing the duct at the same 

sampling location.

(7) For each run using Method 5, 5B, or 17 of appendix A of this part, the emission rates expressed in ng/J 

(lb/MMBtu) heat input shall be determined using:

(i) The O2or CO2measurements and PM measurements obtained under this section, (ii) The dry basis F factor, and

(iii) The dry basis emission rate calculation procedure contained in Method 19 of appendix A of this part.

(8) Method 9 of appendix A–4 of this part shall be used for determining the opacity of stack emissions.

(b) The owner or operator of an affected facility seeking to demonstrate compliance with the PM standards under 

§60.43c(b)(2) shall demonstrate the maximum design heat input capacity of the steam generating unit by operating 

the steam generating unit at this capacity for 24 hours. This demonstration shall be made during the initial 

performance test, and a subsequent demonstration may be requested at any other time. If the demonstrated 24-hour 

average firing rate for the affected facility is less than the maximum design heat input capacity stated by the 

manufacturer of the affected facility, the demonstrated 24-hour average firing rate shall be used to determine the 

annual capacity factor for the affected facility; otherwise, the maximum design heat input capacity provided by the 

manufacturer shall be used.

(c) In place of PM testing with Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part, 

an owner or operator may elect to install, calibrate, maintain, and operate a CEMS for monitoring PM emissions 

discharged to the atmosphere and record the output of the system. The owner or operator of an affected facility who 

elects to continuously monitor PM emissions instead of conducting performance testing using Method 5 or 5B of 

appendix A–3 of this part or Method 17 of appendix A–6 of this part shall install, calibrate, maintain, and operate a 

CEMS and shall comply with the requirements specified in paragraphs (c)(1) through (c)(14) of this section.

(1) Notify the Administrator 1 month before starting use of the system.

(2) Notify the Administrator 1 month before stopping use of the system.

(3) The monitor shall be installed, evaluated, and operated in accordance with §60.13 of subpart A of this part.

(4) The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the 

affected facility, as specified under §60.8 of subpart A of this part or within 180 days of notification to the 

Administrator of use of CEMS if the owner or operator was previously determining compliance by Method 5, 5B, or 17 

of appendix A of this part performance tests, whichever is later.
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(5) The owner or operator of an affected facility shall conduct an initial performance test for PM emissions as required 

under §60.8 of subpart A of this part. Compliance with the PM emission limit shall be determined by using the CEMS 

specified in paragraph (d) of this section to measure PM and calculating a 24-hour block arithmetic average emission 

concentration using EPA Reference Method 19 of appendix A of this part, section 4.1.

(6) Compliance with the PM emission limit shall be determined based on the 24-hour daily (block) average of the 

hourly arithmetic average emission concentrations using CEMS outlet data.

(7) At a minimum, valid CEMS hourly averages shall be obtained as specified in paragraph (c)(7)(i) of this section for 

75 percent of the total operating hours per 30-day rolling average.

(i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average.

(ii) [Reserved]

(8) The 1-hour arithmetic averages required under paragraph (c)(7) of this section shall be expressed in ng/J or 

lb/MMBtu heat input and shall be used to calculate the boiler operating day daily arithmetic average emission 

concentrations. The 1-hour arithmetic averages shall be calculated using the data points required under §60.13(e)(2) 

of subpart A of this part.

(9) All valid CEMS data shall be used in calculating average emission concentrations even if the minimum CEMS 

data requirements of paragraph (c)(7) of this section are not met.

(10) The CEMS shall be operated according to Performance Specification 11 in appendix B of this part.

(11) During the correlation testing runs of the CEMS required by Performance Specification 11 in appendix B of this 

part, PM and O2(or CO2) data shall be collected concurrently (or within a 30- to 60-minute period) by both the 

continuous emission monitors and performance tests conducted using the following test methods.

(i) For PM, Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part shall be used; and

(ii) For O2 (or CO2), Method 3A or 3B of appendix A–2 of this part, as applicable shall be used.

(12) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with 

procedure 2 in appendix F of this part. Relative Response Audit's must be performed annually and Response 

Correlation Audits must be performed every 3 years.

(13) When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibration checks, and zero 

and span adjustments, emissions data shall be obtained by using other monitoring systems as approved by the 

Administrator or EPA Reference Method 19 of appendix A of this part to provide, as necessary, valid emissions data 

for a minimum of 75 percent of total operating hours on a 30-day rolling average.

(14) After July 1, 2011, within 90 days after the date of completing each performance evaluation required by 

paragraph (c)(11) of this section, the owner or operator of the affected facility must either submit the test data to EPA 

by successfully entering the data electronically into EPA's WebFIRE data base available at 

http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main or mail a copy to: United States Environmental Protection 

Agency; Energy Strategies Group; 109 TW Alexander DR; Mail Code: D243–01; RTP, NC 27711.

(d) The owner or operator of an affected facility seeking to demonstrate compliance under §60.43c(e)(4) shall follow 

the applicable procedures under §60.48c(f). For residual oil-fired affected facilities, fuel supplier certifications are only 

allowed for facilities with heat input capacities between 2.9 and 8.7 MW (10 to 30 MMBtu/hr).

[72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009; 76 FR 3523, Jan. 20, 2011]

§ 60.46c Emission monitoring for sulfur dioxide.
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(a) Except as provided in paragraphs (d) and (e) of this section, the owner or operator of an affected facility subject to 

the SO2emission limits under §60.42c shall install, calibrate, maintain, and operate a CEMS for measuring 

SO2concentrations and either O2or CO2concentrations at the outlet of the SO2control device (or the outlet of the 

steam generating unit if no SO2control device is used), and shall record the output of the system. The owner or 

operator of an affected facility subject to the percent reduction requirements under §60.42c shall measure 

SO2concentrations and either O2or CO2concentrations at both the inlet and outlet of the SO2control device.

(b) The 1-hour average SO2emission rates measured by a CEMS shall be expressed in ng/J or lb/MMBtu heat input 

and shall be used to calculate the average emission rates under §60.42c. Each 1-hour average SO2emission rate 

must be based on at least 30 minutes of operation, and shall be calculated using the data points required under 

§60.13(h)(2). Hourly SO2emission rates are not calculated if the affected facility is operated less than 30 minutes in a 

1-hour period and are not counted toward determination of a steam generating unit operating day.

(c) The procedures under §60.13 shall be followed for installation, evaluation, and operation of the CEMS.

(1) All CEMS shall be operated in accordance with the applicable procedures under Performance Specifications 1, 2, 

and 3 of appendix B of this part.

(2) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with 

Procedure 1 of appendix F of this part.

(3) For affected facilities subject to the percent reduction requirements under §60.42c, the span value of the 

SO2CEMS at the inlet to the SO2control device shall be 125 percent of the maximum estimated hourly potential 

SO2emission rate of the fuel combusted, and the span value of the SO2CEMS at the outlet from the SO2control 

device shall be 50 percent of the maximum estimated hourly potential SO2emission rate of the fuel combusted.

(4) For affected facilities that are not subject to the percent reduction requirements of §60.42c, the span value of the 

SO2CEMS at the outlet from the SO2control device (or outlet of the steam generating unit if no SO2control device is 

used) shall be 125 percent of the maximum estimated hourly potential SO2emission rate of the fuel combusted.

(d) As an alternative to operating a CEMS at the inlet to the SO2control device (or outlet of the steam generating unit 

if no SO2control device is used) as required under paragraph (a) of this section, an owner or operator may elect to 

determine the average SO2emission rate by sampling the fuel prior to combustion. As an alternative to operating a 

CEMS at the outlet from the SO2control device (or outlet of the steam generating unit if no SO2control device is used) 

as required under paragraph (a) of this section, an owner or operator may elect to determine the average 

SO2emission rate by using Method 6B of appendix A of this part. Fuel sampling shall be conducted pursuant to either 

paragraph (d)(1) or (d)(2) of this section. Method 6B of appendix A of this part shall be conducted pursuant to 

paragraph (d)(3) of this section.

(1) For affected facilities combusting coal or oil, coal or oil samples shall be collected daily in an as-fired condition at 

the inlet to the steam generating unit and analyzed for sulfur content and heat content according the Method 19 of 

appendix A of this part. Method 19 of appendix A of this part provides procedures for converting these measurements 

into the format to be used in calculating the average SO2input rate.

(2) As an alternative fuel sampling procedure for affected facilities combusting oil, oil samples may be collected from 

the fuel tank for each steam generating unit immediately after the fuel tank is filled and before any oil is combusted. 

The owner or operator of the affected facility shall analyze the oil sample to determine the sulfur content of the oil. If a 

partially empty fuel tank is refilled, a new sample and analysis of the fuel in the tank would be required upon filling. 

Results of the fuel analysis taken after each new shipment of oil is received shall be used as the daily value when 

calculating the 30-day rolling average until the next shipment is received. If the fuel analysis shows that the sulfur 

content in the fuel tank is greater than 0.5 weight percent sulfur, the owner or operator shall ensure that the sulfur 

content of subsequent oil shipments is low enough to cause the 30-day rolling average sulfur content to be 0.5 weight 

percent sulfur or less.

(3) Method 6B of appendix A of this part may be used in lieu of CEMS to measure SO2at the inlet or outlet of the 

SO2control system. An initial stratification test is required to verify the adequacy of the Method 6B of appendix A of 

this part sampling location. The stratification test shall consist of three paired runs of a suitable SO2and 

CO2measurement train operated at the candidate location and a second similar train operated according to the 

procedures in §3.2 and the applicable procedures in section 7 of Performance Specification 2 of appendix B of this 
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part. Method 6B of appendix A of this part, Method 6A of appendix A of this part, or a combination of Methods 6 and 3 

of appendix A of this part or Methods 6C and 3A of appendix A of this part are suitable measurement techniques. If 

Method 6B of appendix A of this part is used for the second train, sampling time and timer operation may be adjusted 

for the stratification test as long as an adequate sample volume is collected; however, both sampling trains are to be 

operated similarly. For the location to be adequate for Method 6B of appendix A of this part 24-hour tests, the mean 

of the absolute difference between the three paired runs must be less than 10 percent (0.10).

(e) The monitoring requirements of paragraphs (a) and (d) of this section shall not apply to affected facilities subject 

to §60.42c(h) (1), (2), or (3) where the owner or operator of the affected facility seeks to demonstrate compliance with 

the SO2standards based on fuel supplier certification, as described under §60.48c(f), as applicable.

(f) The owner or operator of an affected facility operating a CEMS pursuant to paragraph (a) of this section, or 

conducting as-fired fuel sampling pursuant to paragraph (d)(1) of this section, shall obtain emission data for at least 

75 percent of the operating hours in at least 22 out of 30 successive steam generating unit operating days. If this 

minimum data requirement is not met with a single monitoring system, the owner or operator of the affected facility 

shall supplement the emission data with data collected with other monitoring systems as approved by the 

Administrator.

§ 60.47c Emission monitoring for particulate matter.

(a) Except as provided in paragraphs (c), (d), (e), (f), and (g) of this section, the owner or operator of an affected 

facility combusting coal, oil, or wood that is subject to the opacity standards under §60.43c shall install, calibrate, 

maintain, and operate a continuous opacity monitoring system (COMS) for measuring the opacity of the emissions 

discharged to the atmosphere and record the output of the system. The owner or operator of an affected facility 

subject to an opacity standard in §60.43c(c) that is not required to use a COMS due to paragraphs (c), (d), (e), or (f) 

of this section that elects not to use a COMS shall conduct a performance test using Method 9 of appendix A–4 of 

this part and the procedures in §60.11 to demonstrate compliance with the applicable limit in §60.43c by April 29, 

2011, within 45 days of stopping use of an existing COMS, or 180 days after initial startup of the facility, whichever is 

later, and shall comply with either paragraphs (a)(1), (a)(2), or (a)(3) of this section. The observation period for 

Method 9 of appendix A–4 of this part performance tests may be reduced from 3 hours to 60 minutes if all 6-minute 

averages are less than 10 percent and all individual 15-second observations are less than or equal to 20 percent 

during the initial 60 minutes of observation.

(1) Except as provided in paragraph (a)(2) and (a)(3) of this section, the owner or operator shall conduct subsequent 

Method 9 of appendix A–4 of this part performance tests using the procedures in paragraph (a) of this section 

according to the applicable schedule in paragraphs (a)(1)(i) through (a)(1)(iv) of this section, as determined by the 

most recent Method 9 of appendix A–4 of this part performance test results.

(i) If no visible emissions are observed, a subsequent Method 9 of appendix A–4 of this part performance test must 

be completed within 12 calendar months from the date that the most recent performance test was conducted;

(ii) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal to 5 percent, a 

subsequent Method 9 of appendix A–4 of this part performance test must be completed within 6 calendar months 

from the date that the most recent performance test was conducted;

(iii) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a 

subsequent Method 9 of appendix A–4 of this part performance test must be completed within 3 calendar months 

from the date that the most recent performance test was conducted; or

(iv) If the maximum 6-minute average opacity is greater than 10 percent, a subsequent Method 9 of appendix A–4 of 

this part performance test must be completed within 45 calendar days from the date that the most recent performance 

test was conducted.

(2) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A–4 of this 

part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix 

A–4 of this part performance tests, elect to perform subsequent monitoring using Method 22 of appendix A–7 of this 

part according to the procedures specified in paragraphs (a)(2)(i) and (ii) of this section.
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(i) The owner or operator shall conduct 10 minute observations (during normal operation) each operating day the 

affected facility fires fuel for which an opacity standard is applicable using Method 22 of appendix A–7 of this part and 

demonstrate that the sum of the occurrences of any visible emissions is not in excess of 5 percent of the observation 

period ( i.e. , 30 seconds per 10 minute period). If the sum of the occurrence of any visible emissions is greater than 

30 seconds during the initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the 

occurrence of visible emissions is greater than 5 percent of the observation period ( i.e., 90 seconds per 30 minute 

period), the owner or operator shall either document and adjust the operation of the facility and demonstrate within 24 

hours that the sum of the occurrence of visible emissions is equal to or less than 5 percent during a 30 minute 

observation ( i.e., 90 seconds) or conduct a new Method 9 of appendix A–4 of this part performance test using the 

procedures in paragraph (a) of this section within 45 calendar days according to the requirements in §60.45c(a)(8).

(ii) If no visible emissions are observed for 30 operating days during which an opacity standard is applicable, 

observations can be reduced to once every 7 operating days during which an opacity standard is applicable. If any 

visible emissions are observed, daily observations shall be resumed.

(3) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A–4 of this 

part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix 

A–4 performance tests, elect to perform subsequent monitoring using a digital opacity compliance system according 

to a site-specific monitoring plan approved by the Administrator. The observations shall be similar, but not necessarily 

identical, to the requirements in paragraph (a)(2) of this section. For reference purposes in preparing the monitoring 

plan, see OAQPS “Determination of Visible Emission Opacity from Stationary Sources Using Computer-Based 

Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection Agency (U.S. 

EPA); Office of Air Quality and Planning Standards; Sector Policies and Programs Division; Measurement Policy 

Group (D243–02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer 

Network (TTN) under Emission Measurement Center Preliminary Methods.

(b) All COMS shall be operated in accordance with the applicable procedures under Performance Specification 1 of 

appendix B of this part. The span value of the opacity COMS shall be between 60 and 80 percent.

(c) Owners and operators of an affected facilities that burn only distillate oil that contains no more than 0.5 weight 

percent sulfur and/or liquid or gaseous fuels with potential sulfur dioxide emission rates of 26 ng/J (0.060 lb/MMBtu) 

heat input or less and that do not use a post-combustion technology to reduce SO2 or PM emissions and that are 

subject to an opacity standard in §60.43c(c) are not required to operate a COMS if they follow the applicable 

procedures in §60.48c(f).

(d) Owners or operators complying with the PM emission limit by using a PM CEMS must calibrate, maintain, 

operate, and record the output of the system for PM emissions discharged to the atmosphere as specified in 

§60.45c(c). The CEMS specified in paragraph §60.45c(c) shall be operated and data recorded during all periods of 

operation of the affected facility except for CEMS breakdowns and repairs. Data is recorded during calibration 

checks, and zero and span adjustments.

(e) Owners and operators of an affected facility that is subject to an opacity standard in §60.43c(c) and that does not 

use post-combustion technology (except a wet scrubber) for reducing PM, SO2, or carbon monoxide (CO) emissions, 

burns only gaseous fuels or fuel oils that contain less than or equal to 0.5 weight percent sulfur, and is operated such 

that emissions of CO discharged to the atmosphere from the affected facility are maintained at levels less than or 

equal to 0.15 lb/MMBtu on a boiler operating day average basis is not required to operate a COMS. Owners and 

operators of affected facilities electing to comply with this paragraph must demonstrate compliance according to the 

procedures specified in paragraphs (e)(1) through (4) of this section; or

(1) You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs (e)(1)(i) 

through (iv) of this section.

(i) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in §60.58b(i)(3) of 

subpart Eb of this part.

(ii) Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS expressed in 

parts per million by volume corrected to 3 percent oxygen (dry basis).
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(iii) At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the operating 

hours on a 30-day rolling average basis. The 1-hour averages are calculated using the data points required in 

§60.13(h)(2).

(iv) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be performed in 

accordance with procedure 1 in appendix F of this part.

(2) You must calculate the 1-hour average CO emissions levels for each steam generating unit operating day by 

multiplying the average hourly CO output concentration measured by the CO CEMS times the corresponding average 

hourly flue gas flow rate and divided by the corresponding average hourly heat input to the affected source. The 24-

hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission levels 

computed for each steam generating unit operating day.

(3) You must evaluate the preceding 24-hour average CO emission level each steam generating unit operating day 

excluding periods of affected source startup, shutdown, or malfunction. If the 24-hour average CO emission level is 

greater than 0.15 lb/MMBtu, you must initiate investigation of the relevant equipment and control systems within 24 

hours of the first discovery of the high emission incident and, take the appropriate corrective action as soon as 

practicable to adjust control settings or repair equipment to reduce the 24-hour average CO emission level to 0.15 

lb/MMBtu or less.

(4) You must record the CO measurements and calculations performed according to paragraph (e) of this section and 

any corrective actions taken. The record of corrective action taken must include the date and time during which the 

24-hour average CO emission level was greater than 0.15 lb/MMBtu, and the date, time, and description of the 

corrective action.

(f) Owners and operators of an affected facility that is subject to an opacity standard in §60.43c(c) and that uses a 

bag leak detection system to monitor the performance of a fabric filter (baghouse) according to the most recent 

requirements in section §60.48Da of this part is not required to operate a COMS.

(g) Owners and operators of an affected facility that is subject to an opacity standard in §60.43c(c) and that burns 

only gaseous fuels or fuel oils that contain less than or equal to 0.5 weight percent sulfur and operates according to a 

written site-specific monitoring plan approved by the permitting authority is not required to operate a COMS. This 

monitoring plan must include procedures and criteria for establishing and monitoring specific parameters for the 

affected facility indicative of compliance with the opacity standard.

[72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009; 76 FR 3523, Jan. 20, 2011]

§ 60.48c Reporting and recordkeeping requirements.

(a) The owner or operator of each affected facility shall submit notification of the date of construction or reconstruction 

and actual startup, as provided by §60.7 of this part. This notification shall include:

(1) The design heat input capacity of the affected facility and identification of fuels to be combusted in the affected 

facility.

(2) If applicable, a copy of any federally enforceable requirement that limits the annual capacity factor for any fuel or 

mixture of fuels under §60.42c, or §60.43c.

(3) The annual capacity factor at which the owner or operator anticipates operating the affected facility based on all 

fuels fired and based on each individual fuel fired.

(4) Notification if an emerging technology will be used for controlling SO2emissions. The Administrator will examine 

the description of the control device and will determine whether the technology qualifies as an emerging technology. 

In making this determination, the Administrator may require the owner or operator of the affected facility to submit 

additional information concerning the control device. The affected facility is subject to the provisions of §60.42c(a) or 

(b)(1), unless and until this determination is made by the Administrator.
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(b) The owner or operator of each affected facility subject to the SO2emission limits of §60.42c, or the PM or opacity 

limits of §60.43c, shall submit to the Administrator the performance test data from the initial and any subsequent 

performance tests and, if applicable, the performance evaluation of the CEMS and/or COMS using the applicable 

performance specifications in appendix B of this part.

(c) In addition to the applicable requirements in §60.7, the owner or operator of an affected facility subject to the 

opacity limits in §60.43c(c) shall submit excess emission reports for any excess emissions from the affected facility 

that occur during the reporting period and maintain records according to the requirements specified in paragraphs 

(c)(1) through (3) of this section, as applicable to the visible emissions monitoring method used.

(1) For each performance test conducted using Method 9 of appendix A–4 of this part, the owner or operator shall 

keep the records including the information specified in paragraphs (c)(1)(i) through (iii) of this section.

(i) Dates and time intervals of all opacity observation periods;

(ii) Name, affiliation, and copy of current visible emission reading certification for each visible emission observer 

participating in the performance test; and

(iii) Copies of all visible emission observer opacity field data sheets;

(2) For each performance test conducted using Method 22 of appendix A–4 of this part, the owner or operator shall 

keep the records including the information specified in paragraphs (c)(2)(i) through (iv) of this section.

(i) Dates and time intervals of all visible emissions observation periods;

(ii) Name and affiliation for each visible emission observer participating in the performance test;

(iii) Copies of all visible emission observer opacity field data sheets; and

(iv) Documentation of any adjustments made and the time the adjustments were completed to the affected facility 

operation by the owner or operator to demonstrate compliance with the applicable monitoring requirements.

(3) For each digital opacity compliance system, the owner or operator shall maintain records and submit reports 

according to the requirements specified in the site-specific monitoring plan approved by the Administrator

(d) The owner or operator of each affected facility subject to the SO2emission limits, fuel oil sulfur limits, or percent 

reduction requirements under §60.42c shall submit reports to the Administrator.

(e) The owner or operator of each affected facility subject to the SO2emission limits, fuel oil sulfur limits, or percent 

reduction requirements under §60.42c shall keep records and submit reports as required under paragraph (d) of this 

section, including the following information, as applicable.

(1) Calendar dates covered in the reporting period.

(2) Each 30-day average SO2emission rate (ng/J or lb/MMBtu), or 30-day average sulfur content (weight percent), 

calculated during the reporting period, ending with the last 30-day period; reasons for any noncompliance with the 

emission standards; and a description of corrective actions taken.

(3) Each 30-day average percent of potential SO2emission rate calculated during the reporting period, ending with 

the last 30-day period; reasons for any noncompliance with the emission standards; and a description of the 

corrective actions taken.

(4) Identification of any steam generating unit operating days for which SO2or diluent (O2or CO2) data have not been 

obtained by an approved method for at least 75 percent of the operating hours; justification for not obtaining sufficient 

data; and a description of corrective actions taken.
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(5) Identification of any times when emissions data have been excluded from the calculation of average emission 

rates; justification for excluding data; and a description of corrective actions taken if data have been excluded for 

periods other than those during which coal or oil were not combusted in the steam generating unit.

(6) Identification of the F factor used in calculations, method of determination, and type of fuel combusted.

(7) Identification of whether averages have been obtained based on CEMS rather than manual sampling methods.

(8) If a CEMS is used, identification of any times when the pollutant concentration exceeded the full span of the 

CEMS.

(9) If a CEMS is used, description of any modifications to the CEMS that could affect the ability of the CEMS to 

comply with Performance Specifications 2 or 3 of appendix B of this part.

(10) If a CEMS is used, results of daily CEMS drift tests and quarterly accuracy assessments as required under 

appendix F, Procedure 1 of this part.

(11) If fuel supplier certification is used to demonstrate compliance, records of fuel supplier certification as described 

under paragraph (f)(1), (2), (3), or (4) of this section, as applicable. In addition to records of fuel supplier certifications, 

the report shall include a certified statement signed by the owner or operator of the affected facility that the records of 

fuel supplier certifications submitted represent all of the fuel combusted during the reporting period.

(f) Fuel supplier certification shall include the following information:

(1) For distillate oil:

(i) The name of the oil supplier;

(ii) A statement from the oil supplier that the oil complies with the specifications under the definition of distillate oil in 

§60.41c; and

(iii) The sulfur content or maximum sulfur content of the oil.

(2) For residual oil:

(i) The name of the oil supplier;

(ii) The location of the oil when the sample was drawn for analysis to determine the sulfur content of the oil, 

specifically including whether the oil was sampled as delivered to the affected facility, or whether the sample was 

drawn from oil in storage at the oil supplier's or oil refiner's facility, or other location;

(iii) The sulfur content of the oil from which the shipment came (or of the shipment itself); and

(iv) The method used to determine the sulfur content of the oil.

(3) For coal:

(i) The name of the coal supplier;

(ii) The location of the coal when the sample was collected for analysis to determine the properties of the coal, 

specifically including whether the coal was sampled as delivered to the affected facility or whether the sample was 

collected from coal in storage at the mine, at a coal preparation plant, at a coal supplier's facility, or at another 

location. The certification shall include the name of the coal mine (and coal seam), coal storage facility, or coal 

preparation plant (where the sample was collected);
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(iii) The results of the analysis of the coal from which the shipment came (or of the shipment itself) including the sulfur 

content, moisture content, ash content, and heat content; and

(iv) The methods used to determine the properties of the coal.

(4) For other fuels:

(i) The name of the supplier of the fuel;

(ii) The potential sulfur emissions rate or maximum potential sulfur emissions rate of the fuel in ng/J heat input; and

(iii) The method used to determine the potential sulfur emissions rate of the fuel.

(g)(1) Except as provided under paragraphs (g)(2) and (g)(3) of this section, the owner or operator of each affected 

facility shall record and maintain records of the amount of each fuel combusted during each operating day.

(2) As an alternative to meeting the requirements of paragraph (g)(1) of this section, the owner or operator of an 

affected facility that combusts only natural gas, wood, fuels using fuel certification in §60.48c(f) to demonstrate 

compliance with the SO2standard, fuels not subject to an emissions standard (excluding opacity), or a mixture of 

these fuels may elect to record and maintain records of the amount of each fuel combusted during each calendar 

month.

(3) As an alternative to meeting the requirements of paragraph (g)(1) of this section, the owner or operator of an 

affected facility or multiple affected facilities located on a contiguous property unit where the only fuels combusted in 

any steam generating unit (including steam generating units not subject to this subpart) at that property are natural 

gas, wood, distillate oil meeting the most current requirements in §60.42C to use fuel certification to demonstrate 

compliance with the SO2standard, and/or fuels, excluding coal and residual oil, not subject to an emissions standard 

(excluding opacity) may elect to record and maintain records of the total amount of each steam generating unit fuel 

delivered to that property during each calendar month.

(h) The owner or operator of each affected facility subject to a federally enforceable requirement limiting the annual 

capacity factor for any fuel or mixture of fuels under §60.42c or §60.43c shall calculate the annual capacity factor 

individually for each fuel combusted. The annual capacity factor is determined on a 12-month rolling average basis 

with a new annual capacity factor calculated at the end of the calendar month.

(i) All records required under this section shall be maintained by the owner or operator of the affected facility for a 

period of two years following the date of such record.

(j) The reporting period for the reports required under this subpart is each six-month period. All reports shall be 

submitted to the Administrator and shall be postmarked by the 30th day following the end of the reporting period.

[72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009]
Attachment B to a PSD/Part 70 Operating Permit

Subpart IIII—Standards of Performance for Stationary Compression 

Ignition Internal Combustion Engines [40 CFR Part 60, Subpart IIII] 

[326 IAC 12]

Source Name: St. Joseph Energy Center, LLC

Source Location: Corner of Walnut and Edison Roads, 

New Carlisle, Indiana 46552

County: St. Joseph

SIC Code: 4911

Operation Permit No.: T 141-31003-00579

Operation Permit Issuance Date: Yet to be issued

Permit Reviewer: Josiah Balogun

Subpart IIII—Standards of Performance for Stationary Compression 

Ignition Internal Combustion Engines

Source: 71 FR 39172, July 11, 2006, unless otherwise noted.

What This Subpart Covers

§ 60.4200 Am I subject to this subpart?

(a) The provisions of this subpart are applicable to manufacturers, owners, and operators of stationary compression 

ignition (CI) internal combustion engines (ICE) as specified in paragraphs (a)(1) through (3) of this section. For the 

purposes of this subpart, the date that construction commences is the date the engine is ordered by the owner or 

operator.

(1) Manufacturers of stationary CI ICE with a displacement of less than 30 liters per cylinder where the model year is:

(i) 2007 or later, for engines that are not fire pump engines,

(ii) The model year listed in table 3 to this subpart or later model year, for fire pump engines.

(2) Owners and operators of stationary CI ICE that commence construction after July 11, 2005 where the stationary 

CI ICE are:

(i) Manufactured after April 1, 2006 and are not fire pump engines, or

(ii) Manufactured as a certified National Fire Protection Association (NFPA) fire pump engine after July 1, 2006.

(3) Owners and operators of stationary CI ICE that modify or reconstruct their stationary CI ICE after July 11, 2005.

(b) The provisions of this subpart are not applicable to stationary CI ICE being tested at a stationary CI ICE test 

cell/stand.

(c) If you are an owner or operator of an area source subject to this subpart, you are exempt from the obligation to 

obtain a permit under 40 CFR part 70 or 40 CFR part 71, provided you are not required to obtain a permit under 40 

CFR 70.3(a) or 40 CFR 71.3(a) for a reason other than your status as an area source under this subpart. 
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Notwithstanding the previous sentence, you must continue to comply with the provisions of this subpart applicable to 

area sources.

(d) Stationary CI ICE may be eligible for exemption from the requirements of this subpart as described in 40 CFR part 

1068, subpart C (or the exemptions described in 40 CFR part 89, subpart J and 40 CFR part 94, subpart J, for 

engines that would need to be certified to standards in those parts), except that owners and operators, as well as 

manufacturers, may be eligible to request an exemption for national security.

Emission Standards for Manufacturers

§ 60.4201 What emission standards must I meet for non-emergency 

engines if I am a stationary CI internal combustion engine manufacturer?

(a) Stationary CI internal combustion engine manufacturers must certify their 2007 model year and later nonemergency stationary CI ICE with a maximum engine power less than or equal to 2,237 kilowatt (KW) (3,000 

horsepower (HP)) and a displacement of less than 10 liters per cylinder to the certification emission standards for 

new nonroad CI engines in 40 CFR 89.112, 40 CFR 89.113, 40 CFR 1039.101, 40 CFR 1039.102, 40 CFR 1039.104, 

40 CFR 1039.105, 40 CFR 1039.107, and 40 CFR 1039.115, as applicable, for all pollutants, for the same model 

year and maximum engine power.

(b) Stationary CI internal combustion engine manufacturers must certify their 2007 through 2010 model year nonemergency stationary CI ICE with a maximum engine power greater than 2,237 KW (3,000 HP) and a displacement 

of less than 10 liters per cylinder to the emission standards in table 1 to this subpart, for all pollutants, for the same 

maximum engine power.

(c) Stationary CI internal combustion engine manufacturers must certify their 2011 model year and later nonemergency stationary CI ICE with a maximum engine power greater than 2,237 KW (3,000 HP) and a displacement 

of less than 10 liters per cylinder to the certification emission standards for new nonroad CI engines in 40 CFR 

1039.101, 40 CFR 1039.102, 40 CFR 1039.104, 40 CFR 1039.105, 40 CFR 1039.107, and 40 CFR 1039.115, as 

applicable, for all pollutants, for the same maximum engine power.

(d) Stationary CI internal combustion engine manufacturers must certify their 2007 model year and later nonemergency stationary CI ICE with a displacement of greater than or equal to 10 liters per cylinder and less than 30 

liters per cylinder to the certification emission standards for new marine CI engines in 40 CFR 94.8, as applicable, for 

all pollutants, for the same displacement and maximum engine power.

§ 60.4202 What emission standards must I meet for emergency engines if I 

am a stationary CI internal combustion engine manufacturer?

(a) Stationary CI internal combustion engine manufacturers must certify their 2007 model year and later emergency 

stationary CI ICE with a maximum engine power less than or equal to 2,237 KW (3,000 HP) and a displacement of 

less than 10 liters per cylinder that are not fire pump engines to the emission standards specified in paragraphs (a)(1) 

through (2) of this section.

(1) For engines with a maximum engine power less than 37 KW (50 HP):

(i) The certification emission standards for new nonroad CI engines for the same model year and maximum engine 

power in 40 CFR 89.112 and 40 CFR 89.113 for all pollutants for model year 2007 engines, and

(ii) The certification emission standards for new nonroad CI engines in 40 CFR 1039.104, 40 CFR 1039.105, 40 CFR 

1039.107, 40 CFR 1039.115, and table 2 to this subpart, for 2008 model year and later engines.

(2) For engines with a maximum engine power greater than or equal to 37 KW (50 HP), the certification emission 

standards for new nonroad CI engines for the same model year and maximum engine power in 40 CFR 89.112 and 

40 CFR 89.113 for all pollutants beginning in model year 2007.
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(b) Stationary CI internal combustion engine manufacturers must certify their 2007 model year and later emergency 

stationary CI ICE with a maximum engine power greater than 2,237 KW (3,000 HP) and a displacement of less than 

10 liters per cylinder that are not fire pump engines to the emission standards specified in paragraphs (b)(1) through 

(2) of this section.

(1) For 2007 through 2010 model years, the emission standards in table 1 to this subpart, for all pollutants, for the 

same maximum engine power.

(2) For 2011 model year and later, the certification emission standards for new nonroad CI engines for engines of the 

same model year and maximum engine power in 40 CFR 89.112 and 40 CFR 89.113 for all pollutants.

(c) Stationary CI internal combustion engine manufacturers must certify their 2007 model year and later emergency 

stationary CI ICE with a displacement of greater than or equal to 10 liters per cylinder and less than 30 liters per 

cylinder that are not fire pump engines to the certification emission standards for new marine CI engines in 40 CFR 

94.8, as applicable, for all pollutants, for the same displacement and maximum engine power.

(d) Beginning with the model years in table 3 to this subpart, stationary CI internal combustion engine manufacturers 

must certify their fire pump stationary CI ICE to the emission standards in table 4 to this subpart, for all pollutants, for 

the same model year and NFPA nameplate power.

§ 60.4203 How long must my engines meet the emission standards if I am 

a stationary CI internal combustion engine manufacturer?

Engines manufactured by stationary CI internal combustion engine manufacturers must meet the emission standards 

as required in §§60.4201 and 60.4202 during the useful life of the engines.

Emission Standards for Owners and Operators

§ 60.4204 What emission standards must I meet for non-emergency 

engines if I am an owner or operator of a stationary CI internal combustion 

engine?

(a) Owners and operators of pre-2007 model year non-emergency stationary CI ICE with a displacement of less than 

10 liters per cylinder must comply with the emission standards in table 1 to this subpart. Owners and operators of pre2007 model year non-emergency stationary CI ICE with a displacement of greater than or equal to 10 liters per 

cylinder and less than 30 liters per cylinder must comply with the emission standards in 40 CFR 94.8(a)(1).

(b) Owners and operators of 2007 model year and later non-emergency stationary CI ICE with a displacement of less 

than 30 liters per cylinder must comply with the emission standards for new CI engines in §60.4201 for their 2007 

model year and later stationary CI ICE, as applicable.

(c) Owners and operators of non-emergency stationary CI ICE with a displacement of greater than or equal to 30 

liters per cylinder must meet the requirements in paragraphs (c)(1) and (2) of this section.

(1) Reduce nitrogen oxides (NOX) emissions by 90 percent or more, or limit the emissions of NOXin the stationary CI 

internal combustion engine exhaust to 1.6 grams per KW-hour (g/KW-hr) (1.2 grams per HP-hour (g/HP-hr)).

(2) Reduce particulate matter (PM) emissions by 60 percent or more, or limit the emissions of PM in the stationary CI 

internal combustion engine exhaust to 0.15 g/KW-hr (0.11 g/HP-hr).

§ 60.4205 What emission standards must I meet for emergency engines if I 

am an owner or operator of a stationary CI internal combustion engine?
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(a) Owners and operators of pre-2007 model year emergency stationary CI ICE with a displacement of less than 10 

liters per cylinder that are not fire pump engines must comply with the emission standards in table 1 to this subpart. 

Owners and operators of pre-2007 model year non-emergency stationary CI ICE with a displacement of greater than 

or equal to 10 liters per cylinder and less than 30 liters per cylinder that are not fire pump engines must comply with 

the emission standards in 40 CFR 94.8(a)(1).

(b) Owners and operators of 2007 model year and later emergency stationary CI ICE with a displacement of less than 

30 liters per cylinder that are not fire pump engines must comply with the emission standards for new nonroad CI 

engines in §60.4202, for all pollutants, for the same model year and maximum engine power for their 2007 model 

year and later emergency stationary CI ICE.

(c) Owners and operators of fire pump engines with a displacement of less than 30 liters per cylinder must comply 

with the emission standards in table 4 to this subpart, for all pollutants.

(d) Owners and operators of emergency stationary CI ICE with a displacement of greater than or equal to 30 liters per 

cylinder must meet the requirements in paragraphs (d)(1) and (2) of this section.

(1) Reduce NOXemissions by 90 percent or more, or limit the emissions of NOXin the stationary CI internal 

combustion engine exhaust to 1.6 grams per KW-hour (1.2 grams per HP-hour).

(2) Reduce PM emissions by 60 percent or more, or limit the emissions of PM in the stationary CI internal combustion 

engine exhaust to 0.15 g/KW-hr (0.11 g/HP-hr).

§ 60.4206 How long must I meet the emission standards if I am an owner 

or operator of a stationary CI internal combustion engine?

Owners and operators of stationary CI ICE must operate and maintain stationary CI ICE that achieve the emission 

standards as required in §§60.4204 and 60.4205 according to the manufacturer's written instructions or procedures 

developed by the owner or operator that are approved by the engine manufacturer, over the entire life of the engine.

Fuel Requirements for Owners and Operators

§ 60.4207 What fuel requirements must I meet if I am an owner or operator 

of a stationary CI internal combustion engine subject to this subpart?

(a) Beginning October 1, 2007, owners and operators of stationary CI ICE subject to this subpart that use diesel fuel 

must use diesel fuel that meets the requirements of 40 CFR 80.510(a).

(b) Beginning October 1, 2010, owners and operators of stationary CI ICE subject to this subpart with a displacement 

of less than 30 liters per cylinder that use diesel fuel must use diesel fuel that meets the requirements of 40 CFR 

80.510(b) for nonroad diesel fuel.

(c) Owners and operators of pre-2011 model year stationary CI ICE subject to this subpart may petition the 

Administrator for approval to use remaining non-compliant fuel that does not meet the fuel requirements of 

paragraphs (a) and (b) of this section beyond the dates required for the purpose of using up existing fuel inventories. 

If approved, the petition will be valid for a period of up to 6 months. If additional time is needed, the owner or operator 

is required to submit a new petition to the Administrator.

(d) Owners and operators of pre-2011 model year stationary CI ICE subject to this subpart that are located in areas of 

Alaska not accessible by the Federal Aid Highway System may petition the Administrator for approval to use any 

fuels mixed with used lubricating oil that do not meet the fuel requirements of paragraphs (a) and (b) of this section. 

Owners and operators must demonstrate in their petition to the Administrator that there is no other place to use the 

lubricating oil. If approved, the petition will be valid for a period of up to 6 months. If additional time is needed, the 

owner or operator is required to submit a new petition to the Administrator.
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(e) Stationary CI ICE that have a national security exemption under §60.4200(d) are also exempt from the fuel 

requirements in this section.

Other Requirements for Owners and Operators

§ 60.4208 What is the deadline for importing or installing stationary CI ICE 

produced in the previous model year?

(a) After December 31, 2008, owners and operators may not install stationary CI ICE (excluding fire pump engines) 

that do not meet the applicable requirements for 2007 model year engines.

(b) After December 31, 2009, owners and operators may not install stationary CI ICE with a maximum engine power 

of less than 19 KW (25 HP) (excluding fire pump engines) that do not meet the applicable requirements for 2008 

model year engines.

(c) After December 31, 2014, owners and operators may not install non-emergency stationary CI ICE with a 

maximum engine power of greater than or equal to 19 KW (25 HP) and less than 56 KW (75 HP) that do not meet the 

applicable requirements for 2013 model year non-emergency engines.

(d) After December 31, 2013, owners and operators may not install non-emergency stationary CI ICE with a 

maximum engine power of greater than or equal to 56 KW (75 HP) and less than 130 KW (175 HP) that do not meet 

the applicable requirements for 2012 model year non-emergency engines.

(e) After December 31, 2012, owners and operators may not install non-emergency stationary CI ICE with a 

maximum engine power of greater than or equal to 130 KW (175 HP), including those above 560 KW (750 HP), that 

do not meet the applicable requirements for 2011 model year non-emergency engines.

(f) After December 31, 2016, owners and operators may not install non-emergency stationary CI ICE with a maximum 

engine power of greater than or equal to 560 KW (750 HP) that do not meet the applicable requirements for 2015 

model year non-emergency engines.

(g) In addition to the requirements specified in §§60.4201, 60.4202, 60.4204, and 60.4205, it is prohibited to import 

stationary CI ICE with a displacement of less than 30 liters per cylinder that do not meet the applicable requirements 

specified in paragraphs (a) through (f) of this section after the dates specified in paragraphs (a) through (f) of this 

section.

(h) The requirements of this section do not apply to owners or operators of stationary CI ICE that have been modified, 

reconstructed, and do not apply to engines that were removed from one existing location and reinstalled at a new 

location.

§ 60.4209 What are the monitoring requirements if I am an owner or 

operator of a stationary CI internal combustion engine?

If you are an owner or operator, you must meet the monitoring requirements of this section. In addition, you must also 

meet the monitoring requirements specified in §60.4211.

(a) If you are an owner or operator of an emergency stationary CI internal combustion engine, you must install a nonresettable hour meter prior to startup of the engine.

(b) If you are an owner or operator of a stationary CI internal combustion engine equipped with a diesel particulate 

filter to comply with the emission standards in §60.4204, the diesel particulate filter must be installed with a 

backpressure monitor that notifies the owner or operator when the high backpressure limit of the engine is 

approached.
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Compliance Requirements

§ 60.4210 What are my compliance requirements if I am a stationary CI 

internal combustion engine manufacturer?

(a) Stationary CI internal combustion engine manufacturers must certify their stationary CI ICE with a displacement of 

less than 10 liters per cylinder to the emission standards specified in §60.4201(a) through (c) and §60.4202(a), (b) 

and (d) using the certification procedures required in 40 CFR part 89, subpart B, or 40 CFR part 1039, subpart C, as 

applicable, and must test their engines as specified in those parts. For the purposes of this subpart, engines certified 

to the standards in table 1 to this subpart shall be subject to the same requirements as engines certified to the 

standards in 40 CFR part 89. For the purposes of this subpart, engines certified to the standards in table 4 to this 

subpart shall be subject to the same requirements as engines certified to the standards in 40 CFR part 89, except 

that engines with NFPA nameplate power of less than 37 KW (50 HP) certified to model year 2011 or later standards 

shall be subject to the same requirements as engines certified to the standards in 40 CFR part 1039.

(b) Stationary CI internal combustion engine manufacturers must certify their stationary CI ICE with a displacement of 

greater than or equal to 10 liters per cylinder and less than 30 liters per cylinder to the emission standards specified 

in §60.4201(d) and §60.4202(c) using the certification procedures required in 40 CFR part 94 subpart C, and must 

test their engines as specified in 40 CFR part 94.

(c) Stationary CI internal combustion engine manufacturers must meet the requirements of 40 CFR 1039.120, 40 

CFR 1039.125, 40 CFR 1039.130, 40 CFR 1039.135, and 40 CFR part 1068 for engines that are certified to the 

emission standards in 40 CFR part 1039. Stationary CI internal combustion engine manufacturers must meet the 

corresponding provisions of 40 CFR part 89 or 40 CFR part 94 for engines that would be covered by that part if they 

were nonroad (including marine) engines. Labels on such engines must refer to stationary engines, rather than or in 

addition to nonroad or marine engines, as appropriate. Stationary CI internal combustion engine manufacturers must 

label their engines according to paragraphs (c)(1) through (3) of this section.

(1) Stationary CI internal combustion engines manufactured from January 1, 2006 to March 31, 2006 (January 1, 

2006 to June 30, 2006 for fire pump engines), other than those that are part of certified engine families under the 

nonroad CI engine regulations, must be labeled according to 40 CFR 1039.20.

(2) Stationary CI internal combustion engines manufactured from April 1, 2006 to December 31, 2006 (or, for fire 

pump engines, July 1, 2006 to December 31 of the year preceding the year listed in table 3 to this subpart) must be 

labeled according to paragraphs (c)(2)(i) through (iii) of this section:

(i) Stationary CI internal combustion engines that are part of certified engine families under the nonroad regulations 

must meet the labeling requirements for nonroad CI engines, but do not have to meet the labeling requirements in 40 

CFR 1039.20.

(ii) Stationary CI internal combustion engines that meet Tier 1 requirements (or requirements for fire pumps) under 

this subpart, but do not meet the requirements applicable to nonroad CI engines must be labeled according to 40 

CFR 1039.20. The engine manufacturer may add language to the label clarifying that the engine meets Tier 1 

requirements (or requirements for fire pumps) of this subpart.

(iii) Stationary CI internal combustion engines manufactured after April 1, 2006 that do not meet Tier 1 requirements 

of this subpart, or fire pumps engines manufactured after July 1, 2006 that do not meet the requirements for fire 

pumps under this subpart, may not be used in the U.S. If any such engines are manufactured in the U.S. after April 1, 

2006 (July 1, 2006 for fire pump engines), they must be exported or must be brought into compliance with the 

appropriate standards prior to initial operation. The export provisions of 40 CFR 1068.230 would apply to engines for 

export and the manufacturers must label such engines according to 40 CFR 1068.230.

(3) Stationary CI internal combustion engines manufactured after January 1, 2007 (for fire pump engines, after 

January 1 of the year listed in table 3 to this subpart, as applicable) must be labeled according to paragraphs (c)(3)(i) 

through (iii) of this section.
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(i) Stationary CI internal combustion engines that meet the requirements of this subpart and the corresponding 

requirements for nonroad (including marine) engines of the same model year and HP must be labeled according to 

the provisions in part 89, 94 or 1039, as appropriate.

(ii) Stationary CI internal combustion engines that meet the requirements of this subpart, but are not certified to the 

standards applicable to nonroad (including marine) engines of the same model year and HP must be labeled 

according to the provisions in part 89, 94 or 1039, as appropriate, but the words “stationary” must be included instead 

of “nonroad” or “marine” on the label. In addition, such engines must be labeled according to 40 CFR 1039.20.

(iii) Stationary CI internal combustion engines that do not meet the requirements of this subpart must be labeled 

according to 40 CFR 1068.230 and must be exported under the provisions of 40 CFR 1068.230.

(d) An engine manufacturer certifying an engine family or families to standards under this subpart that are identical to 

standards applicable under parts 89, 94, or 1039 for that model year may certify any such family that contains both 

nonroad (including marine) and stationary engines as a single engine family and/or may include any such family 

containing stationary engines in the averaging, banking and trading provisions applicable for such engines under 

those parts.

(e) Manufacturers of engine families discussed in paragraph (d) of this section may meet the labeling requirements 

referred to in paragraph (c) of this section for stationary CI ICE by either adding a separate label containing the 

information required in paragraph (c) of this section or by adding the words “and stationary” after the word “nonroad” 

or “marine,” as appropriate, to the label.

(f) Starting with the model years shown in table 5 to this subpart, stationary CI internal combustion engine 

manufacturers must add a permanent label stating that the engine is for stationary emergency use only to each new 

emergency stationary CI internal combustion engine greater than or equal to 19 KW (25 HP) that meets all the 

emission standards for emergency engines in §60.4202 but does not meet all the emission standards for nonemergency engines in §60.4201. The label must be added according to the labeling requirements specified in 40 

CFR 1039.135(b). Engine manufacturers must specify in the owner's manual that operation of emergency engines is 

limited to emergency operations and required maintenance and testing.

(g) Manufacturers of fire pump engines may use the test cycle in table 6 to this subpart for testing fire pump engines 

and may test at the NFPA certified nameplate HP, provided that the engine is labeled as “Fire Pump Applications 

Only”.

(h) Engine manufacturers, including importers, may introduce into commerce uncertified engines or engines certified 

to earlier standards that were manufactured before the new or changed standards took effect until inventories are 

depleted, as long as such engines are part of normal inventory. For example, if the engine manufacturers' normal 

industry practice is to keep on hand a one-month supply of engines based on its projected sales, and a new tier of 

standards starts to apply for the 2009 model year, the engine manufacturer may manufacture engines based on the 

normal inventory requirements late in the 2008 model year, and sell those engines for installation. The engine 

manufacturer may not circumvent the provisions of §§60.4201 or 60.4202 by stockpiling engines that are built before 

new or changed standards take effect. Stockpiling of such engines beyond normal industry practice is a violation of 

this subpart.

(i) The replacement engine provisions of 40 CFR 89.1003(b)(7), 40 CFR 94.1103(b)(3), 40 CFR 94.1103(b)(4) and 40 

CFR 1068.240 are applicable to stationary CI engines replacing existing equipment that is less than 15 years old.

§ 60.4211 What are my compliance requirements if I am an owner or 

operator of a stationary CI internal combustion engine?

(a) If you are an owner or operator and must comply with the emission standards specified in this subpart, you must 

operate and maintain the stationary CI internal combustion engine and control device according to the manufacturer's 

written instructions or procedures developed by the owner or operator that are approved by the engine manufacturer. 

In addition, owners and operators may only change those settings that are permitted by the manufacturer. You must 

also meet the requirements of 40 CFR parts 89, 94 and/or 1068, as they apply to you.
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(b) If you are an owner or operator of a pre-2007 model year stationary CI internal combustion engine and must 

comply with the emission standards specified in §§60.4204(a) or 60.4205(a), or if you are an owner or operator of a 

CI fire pump engine that is manufactured prior to the model years in table 3 to this subpart and must comply with the 

emission standards specified in §60.4205(c), you must demonstrate compliance according to one of the methods 

specified in paragraphs (b)(1) through (5) of this section.

(1) Purchasing an engine certified according to 40 CFR part 89 or 40 CFR part 94, as applicable, for the same model 

year and maximum engine power. The engine must be installed and configured according to the manufacturer's 

specifications.

(2) Keeping records of performance test results for each pollutant for a test conducted on a similar engine. The test 

must have been conducted using the same methods specified in this subpart and these methods must have been 

followed correctly.

(3) Keeping records of engine manufacturer data indicating compliance with the standards.

(4) Keeping records of control device vendor data indicating compliance with the standards.

(5) Conducting an initial performance test to demonstrate compliance with the emission standards according to the 

requirements specified in §60.4212, as applicable.

(c) If you are an owner or operator of a 2007 model year and later stationary CI internal combustion engine and must 

comply with the emission standards specified in §60.4204(b) or §60.4205(b), or if you are an owner or operator of a 

CI fire pump engine that is manufactured during or after the model year that applies to your fire pump engine power 

rating in table 3 to this subpart and must comply with the emission standards specified in §60.4205(c), you must 

comply by purchasing an engine certified to the emission standards in §60.4204(b), or §60.4205(b) or (c), as 

applicable, for the same model year and maximum (or in the case of fire pumps, NFPA nameplate) engine power. 

The engine must be installed and configured according to the manufacturer's specifications.

(d) If you are an owner or operator and must comply with the emission standards specified in §60.4204(c) or 

§60.4205(d), you must demonstrate compliance according to the requirements specified in paragraphs (d)(1) through 

(3) of this section.

(1) Conducting an initial performance test to demonstrate initial compliance with the emission standards as specified 

in §60.4213.

(2) Establishing operating parameters to be monitored continuously to ensure the stationary internal combustion 

engine continues to meet the emission standards. The owner or operator must petition the Administrator for approval 

of operating parameters to be monitored continuously. The petition must include the information described in 

paragraphs (d)(2)(i) through (v) of this section.

(i) Identification of the specific parameters you propose to monitor continuously;

(ii) A discussion of the relationship between these parameters and NOXand PM emissions, identifying how the 

emissions of these pollutants change with changes in these parameters, and how limitations on these parameters will 

serve to limit NOXand PM emissions;

(iii) A discussion of how you will establish the upper and/or lower values for these parameters which will establish the 

limits on these parameters in the operating limitations;

(iv) A discussion identifying the methods and the instruments you will use to monitor these parameters, as well as the 

relative accuracy and precision of these methods and instruments; and

(v) A discussion identifying the frequency and methods for recalibrating the instruments you will use for monitoring 

these parameters.
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(3) For non-emergency engines with a displacement of greater than or equal to 30 liters per cylinder, conducting

annual performance tests to demonstrate continuous compliance with the emission standards as specified in 

§60.4213.

(e) Emergency stationary ICE may be operated for the purpose of maintenance checks and readiness testing, 

provided that the tests are recommended by Federal, State, or local government, the manufacturer, the vendor, or the 

insurance company associated with the engine. Maintenance checks and readiness testing of such units is limited to 

100 hours per year. There is no time limit on the use of emergency stationary ICE in emergency situations. Anyone 

may petition the Administrator for approval of additional hours to be used for maintenance checks and readiness 

testing, but a petition is not required if the owner or operator maintains records indicating that Federal, State, or local 

standards require maintenance and testing of emergency ICE beyond 100 hours per year. For owners and operators 

of emergency engines meeting standards under §60.4205 but not §60.4204, any operation other than emergency 

operation, and maintenance and testing as permitted in this section, is prohibited.

Testing Requirements for Owners and Operators

§ 60.4212 What test methods and other procedures must I use if I am an 

owner or operator of a stationary CI internal combustion engine with a 

displacement of less than 30 liters per cylinder?

Owners and operators of stationary CI ICE with a displacement of less than 30 liters per cylinder who conduct 

performance tests pursuant to this subpart must do so according to paragraphs (a) through (d) of this section.

(a) The performance test must be conducted according to the in-use testing procedures in 40 CFR part 1039, subpart 

F.

(b) Exhaust emissions from stationary CI ICE that are complying with the emission standards for new CI engines in 

40 CFR part 1039 must not exceed the not-to-exceed (NTE) standards for the same model year and maximum 

engine power as required in 40 CFR 1039.101(e) and 40 CFR 1039.102(g)(1), except as specified in 40 CFR 

1039.104(d). This requirement starts when NTE requirements take effect for nonroad diesel engines under 40 CFR 

part 1039.

(c) Exhaust emissions from stationary CI ICE that are complying with the emission standards for new CI engines in 

40 CFR 89.112 or 40 CFR 94.8, as applicable, must not exceed the NTE numerical requirements, rounded to the 

same number of decimal places as the applicable standard in 40 CFR 89.112 or 40 CFR 94.8, as applicable, 

determined from the following equation:

Where:

STD = The standard specified for that pollutant in 40 CFR 89.112 or 40 CFR 94.8, as applicable.

Alternatively, stationary CI ICE that are complying with the emission standards for new CI engines in 40 CFR 89.112 

or 40 CFR 94.8 may follow the testing procedures specified in §60.4213 of this subpart, as appropriate.

(d) Exhaust emissions from stationary CI ICE that are complying with the emission standards for pre-2007 model year 

engines in §60.4204(a), §60.4205(a), or §60.4205(c) must not exceed the NTE numerical requirements, rounded to 

the same number of decimal places as the applicable standard in §60.4204(a), §60.4205(a), or §60.4205(c), 

determined from the equation in paragraph (c) of this section.

Where:

STD = The standard specified for that pollutant in §60.4204(a), §60.4205(a), or §60.4205(c).
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Alternatively, stationary CI ICE that are complying with the emission standards for pre-2007 model year engines in 

§60.4204(a), §60.4205(a), or §60.4205(c) may follow the testing procedures specified in §60.4213, as appropriate.

§ 60.4213 What test methods and other procedures must I use if I am an 

owner or operator of a stationary CI internal combustion engine with a 

displacement of greater than or equal to 30 liters per cylinder?

Owners and operators of stationary CI ICE with a displacement of greater than or equal to 30 liters per cylinder must 

conduct performance tests according to paragraphs (a) through (d) of this section.

(a) Each performance test must be conducted according to the requirements in §60.8 and under the specific 

conditions that this subpart specifies in table 7. The test must be conducted within 10 percent of 100 percent peak (or 

the highest achievable) load.

(b) You may not conduct performance tests during periods of startup, shutdown, or malfunction, as specified in 

§60.8(c).

(c) You must conduct three separate test runs for each performance test required in this section, as specified in 

§60.8(f). Each test run must last at least 1 hour.

(d) To determine compliance with the percent reduction requirement, you must follow the requirements as specified in 

paragraphs (d)(1) through (3) of this section.

(1) You must use Equation 2 of this section to determine compliance with the percent reduction requirement:

Where:

Ci= concentration of NOXor PM at the control device inlet,

Co= concentration of NOXor PM at the control device outlet, and

R = percent reduction of NOXor PM emissions.

(2) You must normalize the NOXor PM concentrations at the inlet and outlet of the control device to a dry basis and to 

15 percent oxygen (O2) using Equation 3 of this section, or an equivalent percent carbon dioxide (CO2) using the 

procedures described in paragraph (d)(3) of this section.

Where:

Cadj= Calculated NOXor PM concentration adjusted to 15 percent O2.

Cd= Measured concentration of NOXor PM, uncorrected.

5.9 = 20.9 percent O2−15 percent O2, the defined O2correction value, percent.
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%O2= Measured O2concentration, dry basis, percent.

(3) If pollutant concentrations are to be corrected to 15 percent O2and CO2concentration is measured in lieu of 

O2concentration measurement, a CO2correction factor is needed. Calculate the CO2correction factor as described in 

paragraphs (d)(3)(i) through (iii) of this section.

(i) Calculate the fuel-specific Fovalue for the fuel burned during the test using values obtained from Method 19, 

Section 5.2, and the following equation:

Where:

Fo= Fuel factor based on the ratio of O2volume to the ultimate CO2volume produced by the fuel at zero 

percent excess air.

0.209 = Fraction of air that is O2, percent/100.

Fd= Ratio of the volume of dry effluent gas to the gross calorific value of the fuel from Method 19, dsm3 /J 

(dscf/106 Btu).

Fc= Ratio of the volume of CO2produced to the gross calorific value of the fuel from Method 19, dsm3 /J 

(dscf/106 Btu).

(ii) Calculate the CO2correction factor for correcting measurement data to 15 percent O2, as follows:

Where:

XCO2= CO2correction factor, percent.

5.9 = 20.9 percent O2−15 percent O2, the defined O2correction value, percent.

(iii) Calculate the NOXand PM gas concentrations adjusted to 15 percent O2using CO2as follows:

Where:

Cadj= Calculated NOXor PM concentration adjusted to 15 percent O2.

Cd= Measured concentration of NOXor PM, uncorrected.

%CO2= Measured CO2concentration, dry basis, percent.
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(e) To determine compliance with the NOXmass per unit output emission limitation, convert the concentration of 

NOXin the engine exhaust using Equation 7 of this section:

Where:

ER = Emission rate in grams per KW-hour.

Cd= Measured NOXconcentration in ppm.

1.912x10−3= Conversion constant for ppm NOXto grams per standard cubic meter at 25 degrees Celsius.

Q = Stack gas volumetric flow rate, in standard cubic meter per hour.

T = Time of test run, in hours.

KW-hour = Brake work of the engine, in KW-hour.

(f) To determine compliance with the PM mass per unit output emission limitation, convert the concentration of PM in 

the engine exhaust using Equation 8 of this section:

Where:

ER = Emission rate in grams per KW-hour.

Cadj= Calculated PM concentration in grams per standard cubic meter.

Q = Stack gas volumetric flow rate, in standard cubic meter per hour.

T = Time of test run, in hours.

KW-hour = Energy output of the engine, in KW.

Notification, Reports, and Records for Owners and Operators

§ 60.4214 What are my notification, reporting, and recordkeeping 

requirements if I am an owner or operator of a stationary CI internal 

combustion engine?

(a) Owners and operators of non-emergency stationary CI ICE that are greater than 2,237 KW (3,000 HP), or have a 

displacement of greater than or equal to 10 liters per cylinder, or are pre-2007 model year engines that are greater 

than 130 KW (175 HP) and not certified, must meet the requirements of paragraphs (a)(1) and (2) of this section.

(1) Submit an initial notification as required in §60.7(a)(1). The notification must include the information in paragraphs 

(a)(1)(i) through (v) of this section.
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(i) Name and address of the owner or operator;

(ii) The address of the affected source;

(iii) Engine information including make, model, engine family, serial number, model year, maximum engine power, 

and engine displacement;

(iv) Emission control equipment; and

(v) Fuel used.

(2) Keep records of the information in paragraphs (a)(2)(i) through (iv) of this section.

(i) All notifications submitted to comply with this subpart and all documentation supporting any notification.

(ii) Maintenance conducted on the engine.

(iii) If the stationary CI internal combustion is a certified engine, documentation from the manufacturer that the engine 

is certified to meet the emission standards.

(iv) If the stationary CI internal combustion is not a certified engine, documentation that the engine meets the 

emission standards.

(b) If the stationary CI internal combustion engine is an emergency stationary internal combustion engine, the owner 

or operator is not required to submit an initial notification. Starting with the model years in table 5 to this subpart, if the 

emergency engine does not meet the standards applicable to non-emergency engines in the applicable model year, 

the owner or operator must keep records of the operation of the engine in emergency and non-emergency service 

that are recorded through the non-resettable hour meter. The owner must record the time of operation of the engine 

and the reason the engine was in operation during that time.

(c) If the stationary CI internal combustion engine is equipped with a diesel particulate filter, the owner or operator 

must keep records of any corrective action taken after the backpressure monitor has notified the owner or operator 

that the high backpressure limit of the engine is approached.

Special Requirements

§ 60.4215 What requirements must I meet for engines used in Guam, 

American Samoa, or the Commonwealth of the Northern Mariana Islands?

(a) Stationary CI ICE that are used in Guam, American Samoa, or the Commonwealth of the Northern Mariana 

Islands are required to meet the applicable emission standards in §60.4205. Non-emergency stationary CI ICE with a 

displacement of greater than or equal to 30 liters per cylinder, must meet the applicable emission standards in 

§60.4204(c).

(b) Stationary CI ICE that are used in Guam, American Samoa, or the Commonwealth of the Northern Mariana 

Islands are not required to meet the fuel requirements in §60.4207.

§ 60.4216 What requirements must I meet for engines used in Alaska?

(a) Prior to December 1, 2010, owners and operators of stationary CI engines located in areas of Alaska not 

accessible by the Federal Aid Highway System should refer to 40 CFR part 69 to determine the diesel fuel 

requirements applicable to such engines.
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(b) The Governor of Alaska may submit for EPA approval, by no later than January 11, 2008, an alternative plan for 

implementing the requirements of 40 CFR part 60, subpart IIII, for public-sector electrical utilities located in rural 

areas of Alaska not accessible by the Federal Aid Highway System. This alternative plan must be based on the 

requirements of section 111 of the Clean Air Act including any increased risks to human health and the environment 

and must also be based on the unique circumstances related to remote power generation, climatic conditions, and 

serious economic impacts resulting from implementation of 40 CFR part 60, subpart IIII. If EPA approves by 

rulemaking process an alternative plan, the provisions as approved by EPA under that plan shall apply to the diesel 

engines used in new stationary internal combustion engines subject to this paragraph.

§ 60.4217 What emission standards must I meet if I am an owner or 

operator of a stationary internal combustion engine using special fuels?

(a) Owners and operators of stationary CI ICE that do not use diesel fuel, or who have been given authority by the 

Administrator under §60.4207(d) of this subpart to use fuels that do not meet the fuel requirements of paragraphs (a) 

and (b) of §60.4207, may petition the Administrator for approval of alternative emission standards, if they can 

demonstrate that they use a fuel that is not the fuel on which the manufacturer of the engine certified the engine and 

that the engine cannot meet the applicable standards required in §60.4202 or §60.4203 using such fuels.

(b) [Reserved]

General Provisions

§ 60.4218 What parts of the General Provisions apply to me?

Table 8 to this subpart shows which parts of the General Provisions in §§60.1 through 60.19 apply to you.

Definitions

§ 60.4219 What definitions apply to this subpart?

As used in this subpart, all terms not defined herein shall have the meaning given them in the CAA and in subpart A 

of this part.

Combustion turbine means all equipment, including but not limited to the turbine, the fuel, air, lubrication and exhaust 

gas systems, control systems (except emissions control equipment), and any ancillary components and subcomponents comprising any simple cycle combustion turbine, any regenerative/recuperative cycle combustion 

turbine, the combustion turbine portion of any cogeneration cycle combustion system, or the combustion turbine 

portion of any combined cycle steam/electric generating system.

Compression ignition means relating to a type of stationary internal combustion engine that is not a spark ignition 

engine.

Diesel fuel means any liquid obtained from the distillation of petroleum with a boiling point of approximately 150 to 

360 degrees Celsius. One commonly used form is number 2 distillate oil.

Diesel particulate filter means an emission control technology that reduces PM emissions by trapping the particles in 

a flow filter substrate and periodically removes the collected particles by either physical action or by oxidizing (burning 

off) the particles in a process called regeneration.

Emergency stationary internal combustion engine means any stationary internal combustion engine whose operation 

is limited to emergency situations and required testing and maintenance. Examples include stationary ICE used to 

produce power for critical networks or equipment (including power supplied to portions of a facility) when electric 

power from the local utility (or the normal power source, if the facility runs on its own power production) is interrupted, 

or stationary ICE used to pump water in the case of fire or flood, etc. Stationary CI ICE used to supply power to an 
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electric grid or that supply power as part of a financial arrangement with another entity are not considered to be 

emergency engines.

Engine manufacturer means the manufacturer of the engine. See the definition of “manufacturer” in this section.

Fire pump engine means an emergency stationary internal combustion engine certified to NFPA requirements that is 

used to provide power to pump water for fire suppression or protection.

Manufacturer has the meaning given in section 216(1) of the Act. In general, this term includes any person who 

manufactures a stationary engine for sale in the United States or otherwise introduces a new stationary engine into 

commerce in the United States. This includes importers who import stationary engines for sale or resale.

Maximum engine power means maximum engine power as defined in 40 CFR 1039.801.

Model year means either:

(1) The calendar year in which the engine was originally produced, or

(2) The annual new model production period of the engine manufacturer if it is different than the calendar year. This 

must include January 1 of the calendar year for which the model year is named. It may not begin before January 2 of 

the previous calendar year and it must end by December 31 of the named calendar year. For an engine that is 

converted to a stationary engine after being placed into service as a nonroad or other non-stationary engine, model 

year means the calendar year or new model production period in which the engine was originally produced.

Other internal combustion engine means any internal combustion engine, except combustion turbines, which is not a 

reciprocating internal combustion engine or rotary internal combustion engine.

Reciprocating internal combustion engine means any internal combustion engine which uses reciprocating motion to 

convert heat energy into mechanical work.

Rotary internal combustion engine means any internal combustion engine which uses rotary motion to convert heat 

energy into mechanical work.

Spark ignition means relating to a gasoline, natural gas, or liquefied petroleum gas fueled engine or any other type of 

engine with a spark plug (or other sparking device) and with operating characteristics significantly similar to the 

theoretical Otto combustion cycle. Spark ignition engines usually use a throttle to regulate intake air flow to control 

power during normal operation. Dual-fuel engines in which a liquid fuel (typically diesel fuel) is used for CI and 

gaseous fuel (typically natural gas) is used as the primary fuel at an annual average ratio of less than 2 parts diesel 

fuel to 100 parts total fuel on an energy equivalent basis are spark ignition engines.

Stationary internal combustion engine means any internal combustion engine, except combustion turbines, that 

converts heat energy into mechanical work and is not mobile. Stationary ICE differ from mobile ICE in that a 

stationary internal combustion engine is not a nonroad engine as defined at 40 CFR 1068.30 (excluding paragraph 

(2)(ii) of that definition), and is not used to propel a motor vehicle or a vehicle used solely for competition. Stationary 

ICE include reciprocating ICE, rotary ICE, and other ICE, except combustion turbines.

Subpart means 40 CFR part 60, subpart IIII.

Useful life means the period during which the engine is designed to properly function in terms of reliability and fuel 

consumption, without being remanufactured, specified as a number of hours of operation or calendar years, 

whichever comes first. The values for useful life for stationary CI ICE with a displacement of less than 10 liters per 

cylinder are given in 40 CFR 1039.101(g). The values for useful life for stationary CI ICE with a displacement of 

greater than or equal to 10 liters per cylinder and less than 30 liters per cylinder are given in 40 CFR 94.9(a).

Table 1 to Subpart IIII of Part 60—Emission Standards for Stationary Pre2007 Model Year Engines With a Displacement of <10 Liters per Cylinder 
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and 2007–2010 Model Year Engines >2,237 KW (3,000 HP) and With a 

Displacement of <10 Liters per Cylinder

[As stated in §§60.4201(b), 60.4202(b), 60.4204(a), and 60.4205(a), you must comply with the following emission 

standards]

Maximum 

engine power

Emission standards for stationary pre-2007 model year engines with a 

displacement of <10 liters per cylinder and 2007–2010 model year engines 

>2,237 KW (3,000 HP) and with a displacement of <10 liters per cylinder 

in g/KW-hr (g/HP-hr)

NMHC + NOX HC NOX CO PM

KW<8 (HP<11) 10.5 (7.8) 8.0 (6.0) 1.0 (0.75)

8≤KW<19 

(11≤HP<25)

9.5 (7.1) 6.6 (4.9) 0.80 (0.60)

19≤KW<37 

(25≤HP<50)

9.5 (7.1) 5.5 (4.1) 0.80 (0.60)

37≤KW<56 

(50≤HP<75)

9.2 (6.9)

56≤KW<75 

(75≤HP<100)

9.2 (6.9)

75≤KW<130 

(100≤HP<175)

9.2 (6.9)

130≤KW<225 

(175≤HP<300)

1.3 (1.0) 9.2 (6.9) 11.4 (8.5) 0.54 (0.40)

225≤KW<450 

(300≤HP<600)

1.3 (1.0) 9.2 (6.9) 11.4 (8.5) 0.54 (0.40)

450≤KW≤560 

(600≤HP≤750)

1.3 (1.0) 9.2 (6.9) 11.4 (8.5) 0.54 (0.40)

KW>560 

(HP>750)

1.3 (1.0) 9.2 (6.9) 11.4 (8.5) 0.54 (0.40)

Table 2 to Subpart IIII of Part 60—Emission Standards for 2008 Model Year 

and Later Emergency Stationary CI ICE <37 KW (50 HP) With a 

Displacement of <10 Liters per Cylinder

[As stated in §60.4202(a)(1), you must comply with the following emission standards]

Engine power

Emission standards for 2008 model year and later emergency stationary 

CI ICE <37 KW (50 HP) with a displacement of <10 liters per cylinder in 

g/KW-hr (g/HP-hr)
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Model year(s) NOX+ NMHC CO PM

KW<8 (HP<11) 2008+ 7.5 (5.6) 8.0 (6.0) 0.40 (0.30)

8≤KW<19 

(11≤HP<25)

2008+ 7.5 (5.6) 6.6 (4.9) 0.40 (0.30)

19≤KW<37 

(25≤HP<50)

2008+ 7.5 (5.6) 5.5 (4.1) 0.30 (0.22)

Table 3 to Subpart IIII of Part 60—Certification Requirements for Stationary 

Fire Pump Engines

[As stated in §60.4202(d), you must certify new stationary fire pump engines beginning with the following model 

years:]

Engine power

Starting model year engine manufacturers must certify new 

stationary fire pump engines according to §60.4202(d)

KW<75 (HP<100) 2011

75≤KW<130 

(100≤HP<175)

2010

130≤KW≤560 

(175≤HP≤750)

2009

KW>560 (HP>750) 2008

Table 4 to Subpart IIII of Part 60—Emission Standards for Stationary Fire 

Pump Engines

[As stated in §§60.4202(d) and 60.4205(c), you must comply with the following emission standards for stationary fire 

pump engines]

Maximum engine power Model year(s) NMHC + NOX CO PM

KW<8 (HP<11) 2010 and earlier 10.5 (7.8) 8.0 (6.0) 1.0 (0.75)

 2011+ 7.5 (5.6) 0.40 (0.30)

8≤KW<19 (11≤HP<25) 2010 and earlier 9.5 (7.1) 6.6 (4.9) 0.80 (0.60)

 2011+ 7.5 (5.6) 0.40 (0.30)

19≤KW<37 (25≤HP<50) 2010 and earlier 9.5 (7.1) 5.5 (4.1) 0.80 (0.60)

 2011+ 7.5 (5.6) 0.30 (0.22)

37≤KW<56 (50≤HP<75) 2010 and earlier 10.5 (7.8) 5.0 (3.7) 0.80 (0.60)

 2011+1 4.7 (3.5) 0.40 (0.30)
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56≤KW<75 (75≤HP<100) 2010 and earlier 10.5 (7.8) 5.0 (3.7) 0.80 (0.60)

 2011+1 4.7 (3.5) 0.40 (0.30)

75≤KW<130 (100≤HP<175) 2009 and earlier 10.5 (7.8) 5.0 (3.7) 0.80 (0.60)

 2010+2 4.0 (3.0) 0.30 (0.22)

130≤KW<225 (175≤HP<300) 2008 and earlier 10.5 (7.8) 3.5 (2.6) 0.54 (0.40)

 2009+3 4.0 (3.0) 0.20 (0.15)

225≤KW<450 (300≤HP<600) 2008 and earlier 10.5 (7.8) 3.5 (2.6) 0.54 (0.40)

 2009+3 4.0 (3.0) 0.20 (0.15)

450≤KW≤560 (600≤HP≤750) 2008 and earlier 10.5 (7.8) 3.5 (2.6) 0.54 (0.40)

 2009+ 4.0 (3.0) 0.20 (0.15)

KW>560 (HP>750) 2007 and earlier 10.5 (7.8) 3.5 (2.6) 0.54 (0.40)

 2008+ 6.4 (4.8) 0.20 (0.15)

1

For model years 2011–2013, manufacturers, owners and operators of fire pump stationary CI ICE in this engine 

power category with a rated speed of greater than 2,650 revolutions per minute (rpm) may comply with the emission 

limitations for 2010 model year engines.

2

For model years 2010–2012, manufacturers, owners and operators of fire pump stationary CI ICE in this engine 

power category with a rated speed of greater than 2,650 rpm may comply with the emission limitations for 2009 

model year engines.

3

In model years 2009–2011, manufacturers of fire pump stationary CI ICE in this engine power category with a rated 

speed of greater than 2,650 rpm may comply with the emission limitations for 2008 model year engines.

Table 5 to Subpart IIII of Part 60—Labeling and Recordkeeping 

Requirements for New Stationary Emergency Engines

[You must comply with the labeling requirements in §60.4210(f) and the recordkeeping requirements in §60.4214(b) 

for new emergency stationary CI ICE beginning in the following model years:]

Engine power Starting model year

19≤KW<56 (25≤HP<75) 2013

56≤KW<130 (75≤HP<175) 2012

KW≥130 (HP≥175) 2011

Table 6 to Subpart IIII of Part 60—Optional 3-Mode Test Cycle for Stationary 

Fire Pump Engines

[As stated in §60.4210(g), manufacturers of fire pump engines may use the following test cycle for testing fire pump 

engines:]
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Mode No. Engine speed1

Torque

(percent)2

Weighting

factors

1 Rated 100 0.30

2 Rated 75 0.50

3 Rated 50 0.20

1

Engine speed: ±2 percent of point.

2

Torque: NFPA certified nameplate HP for 100 percent point. All points should be ±2 percent of engine percent load 

value.

Table 7 to Subpart IIII of Part 60—Requirements for Performance Tests for 

Stationary CI ICE With a Displacement of ≥30 Liters per Cylinder

[As stated in §60.4213, you must comply with the following requirements for performance tests for stationary CI ICE 

with a displacement of ≥30 liters per cylinder:]

For each

Complying with 

the

requirement to You must Using

According to the 

following 

requirements

1. Stationary CI 

internal 

combustion 

engine with a 

displacement of 

≥30 liters per 

cylinder

a. Reduce 

NOXemissions 

by 90 percent or 

more

i. Select the 

sampling port 

location and the 

number of traverse 

points;

(1) Method 1 or 

1A of 40 CFR 

part 60, appendix 

A

(a) Sampling sites 

must be located at the 

inlet and outlet of the 

control device.

 ii. Measure O2at the 

inlet and outlet of 

the control device;

(2) Method 3, 3A, 

or 3B of 40 CFR 

part 60, appendix 

A

(b) Measurements to 

determine 

O2concentration must 

be made at the same 

time as the 

measurements for 

NOXconcentration.

 iii. If necessary, 

measure moisture 

content at the inlet 

and outlet of the 

control device; and,

(3) Method 4 of 

40 CFR part 60, 

appendix A, 

Method 320 of 40 

CFR part 63, 

appendix A, or 

ASTM D 6348–

03 (incorporated 

by reference, see 

(c) Measurements to 

determine moisture 

content must be made 

at the same time as the 

measurements for 

NOXconcentration.
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§60.17)

 iv. Measure NOXat 

the inlet and outlet 

of the control 

device

(4) Method 7E of 

40 CFR part 60, 

appendix A, 

Method 320 of 40 

CFR part 63, 

appendix A, or 

ASTM D 6348–

03 (incorporated 

by reference, see 

§60.17)

(d) NOXconcentration 

must be at 15 percent 

O2, dry basis. Results 

of this test consist of 

the average of the three 

1-hour or longer runs.

 b. Limit the 

concentration of 

NOXin the 

stationary CI 

internal 

combustion 

engine exhaust.

i. Select the 

sampling port 

location and the 

number of traverse 

points;

(1) Method 1 or 

1A of 40 CFR 

part 60, appendix 

A

(a) If using a control 

device, the sampling 

site must be located at 

the outlet of the control 

device.

 ii. Determine the 

O2concentration of 

the stationary 

internal combustion 

engine exhaust at 

the sampling port 

location; and,

(2) Method 3, 3A, 

or 3B of 40 CFR 

part 60, appendix 

A

(b) Measurements to 

determine 

O2concentration must 

be made at the same 

time as the 

measurement for 

NOXconcentration.

 iii. If necessary, 

measure moisture 

content of the 

stationary internal 

combustion engine 

exhaust at the 

sampling port 

location; and,

(3) Method 4 of 

40 CFR part 60, 

appendix A, 

Method 320 of 40 

CFR part 63, 

appendix A, or 

ASTM D 6348–

03 (incorporated 

by reference, see 

§60.17)

(c) Measurements to 

determine moisture 

content must be made 

at the same time as the 

measurement for 

NOXconcentration.

 iv. Measure NOXat 

the exhaust of the 

stationary internal 

combustion engine

(4) Method 7E of 

40 CFR part 60, 

appendix A, 

Method 320 of 40 

CFR part 63, 

appendix A, or

ASTM D 6348–

03 (incorporated 

(d) NOXconcentration 

must be at 15 percent 

O2, dry basis. Results 

of this test consist of 

the average of the three 

1-hour or longer runs.
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by reference, see 

§60.17)

 c. Reduce PM 

emissions by 60 

percent or more

i. Select the

sampling port 

location and the 

number of traverse 

points;

(1) Method 1 or 

1A of 40 CFR 

part 60, appendix 

A

(a) Sampling sites 

must be located at the 

inlet and outlet of the 

control device.

 ii. Measure O2at the 

inlet and outlet of 

the control device;

(2) Method 3, 3A, 

or 3B of 40 CFR 

part 60, appendix 

A

(b) Measurements to 

determine 

O2concentration must 

be made at the same 

time as the 

measurements for PM 

concentration.

 iii. If necessary, 

measure moisture 

content at the inlet 

and outlet of the 

control device; and

(3) Method 4 of 

40 CFR part 60, 

appendix A

(c) Measurements to 

determine and 

moisture content must 

be made at the same 

time as the 

measurements for PM 

concentration.

 iv. Measure PM at 

the inlet and outlet 

of the control 

device

(4) Method 5 of 

40 CFR part 60, 

appendix A

(d) PM concentration 

must be at 15 percent 

O2, dry basis. Results 

of this test consist of 

the average of the three 

1-hour or longer runs.

 d. Limit the 

concentration of 

PM in the 

stationary CI 

internal 

combustion 

engine exhaust

i. Select the 

sampling port 

location and the 

number of traverse 

points;

(1) Method 1 or 

1A of 40 CFR 

part 60, appendix 

A

(a) If using a control 

device, the sampling 

site must be located at 

the outlet of the control 

device.

 ii. Determine the 

O2concentration of 

the stationary 

internal combustion 

engine exhaust at 

the sampling port 

location; and

(2) Method 3, 3A, 

or 3B of 40 CFR 

part 60, appendix 

A

(b) Measurements to

determine 

O2concentration must 

be made at the same 

time as the 

measurements for PM 

concentration.

 iii. If necessary, (3) Method 4 of (c) Measurements to 
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measure moisture 

content of the 

stationary internal 

combustion engine 

exhaust at the 

sampling port 

location; and

40 CFR part 60, 

appendix A

determine moisture 

content must be made 

at the same time as the 

measurements for PM 

concentration.

 iv. Measure PM at 

the exhaust of the 

stationary internal 

combustion engine

(4) Method 5 of 

40 CFR part 60, 

appendix A

(d) PM concentration 

must be at 15 percent 

O2, dry basis. Results 

of this test consist of 

the average of the three 

1-hour or longer runs.

Table 8 to Subpart IIII of Part 60—Applicability of General Provisions to 

Subpart IIII

[As stated in §60.4218, you must comply with the following applicable General Provisions:]

General 

Provisions

citation Subject of citation

Applies

to

subpart Explanation

§60.1 General applicability of 

the General Provisions

Yes

§60.2 Definitions Yes Additional terms defined in §60.4219.

§60.3 Units and abbreviations Yes

§60.4 Address Yes

§60.5 Determination of 

construction or 

modification

Yes

§60.6 Review of plans Yes

§60.7 Notification and 

Recordkeeping

Yes Except that §60.7 only applies as specified in 

§60.4214(a).

§60.8 Performance tests Yes Except that §60.8 only applies to stationary CI 

ICE with a displacement of (≥30 liters per 

cylinder and engines that are not certified.

§60.9 Availability of information Yes

§60.10 State Authority Yes

§60.11 Compliance with standards No Requirements are specified in subpart IIII.
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and maintenance 

requirements

§60.12 Circumvention Yes

§60.13 Monitoring requirements Yes Except that §60.13 only applies to stationary 

CI ICE with a displacement of (≥30 liters per 

cylinder.

§60.14 Modification Yes

§60.15 Reconstruction Yes

§60.16 Priority list Yes

§60.17 Incorporations by 

reference

Yes

§60.18 General control device 

requirements

No

§60.19 General notification and 

reporting requirements

Yes

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Attachment C to a PSD/Part 70 Operating Permit

Standards of Performance for Performance for Stationary Combustion 

Turbines [40 CFR Part 60, Subpart KKKK] [326 IAC 12]

Source Name: St. Joseph Energy Center, LLC

Source Location: Corner of Walnut and Edison Roads, 

New Carlisle, Indiana 46552

County: St. Joseph

SIC Code: 4911

Operation Permit No.: T 141-31003-00579

Operation Permit Issuance Date: Yet to be issued

Permit Reviewer: Josiah Balogun

Subpart KKKK—Standards of Performance for Stationary Combustion 

Turbines

Source: 71 FR 38497, July 6, 2006, unless otherwise noted.

Introduction

§ 60.4300 What is the purpose of this subpart?

This subpart establishes emission standards and compliance schedules for the control of emissions from stationary 

combustion turbines that commenced construction, modification or reconstruction after February 18, 2005.

Applicability

§ 60.4305 Does this subpart apply to my stationary combustion turbine?

(a) If you are the owner or operator of a stationary combustion turbine with a heat input at peak load equal to or 

greater than 10.7 gigajoules (10 MMBtu) per hour, based on the higher heating value of the fuel, which commenced 

construction, modification, or reconstruction after February 18, 2005, your turbine is subject to this subpart. Only heat 

input to the combustion turbine should be included when determining whether or not this subpart is applicable to your 

turbine. Any additional heat input to associated heat recovery steam generators (HRSG) or duct burners should not

be included when determining your peak heat input. However, this subpart does apply to emissions from any 

associated HRSG and duct burners.

(b) Stationary combustion turbines regulated under this subpart are exempt from the requirements of subpart GG of 

this part. Heat recovery steam generators and duct burners regulated under this subpart are exempted from the 

requirements of subparts Da, Db, and Dc of this part.

§ 60.4310 What types of operations are exempt from these standards of 

performance?

(a) Emergency combustion turbines, as defined in §60.4420(i), are exempt from the nitrogen oxides (NOX) emission 

limits in §60.4320.

(b) Stationary combustion turbines engaged by manufacturers in research and development of equipment for both 

combustion turbine emission control techniques and combustion turbine efficiency improvements are exempt from the 

NOXemission limits in §60.4320 on a case-by-case basis as determined by the Administrator.
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(c) Stationary combustion turbines at integrated gasification combined cycle electric utility steam generating units that 

are subject to subpart Da of this part are exempt from this subpart.

(d) Combustion turbine test cells/stands are exempt from this subpart.

Emission Limits

§ 60.4315 What pollutants are regulated by this subpart?

The pollutants regulated by this subpart are nitrogen oxide (NOX) and sulfur dioxide (SO2).

§ 60.4320 What emission limits must I meet for nitrogen oxides (NOX)?

(a) You must meet the emission limits for NOXspecified in Table 1 to this subpart.

(b) If you have two or more turbines that are connected to a single generator, each turbine must meet the emission 

limits for NOX.

§ 60.4325 What emission limits must I meet for NOX if my turbine burns 

both natural gas and distillate oil (or some other combination of fuels)?

You must meet the emission limits specified in Table 1 to this subpart. If your total heat input is greater than or equal 

to 50 percent natural gas, you must meet the corresponding limit for a natural gas-fired turbine when you are burning 

that fuel. Similarly, when your total heat input is greater than 50 percent distillate oil and fuels other than natural gas, 

you must meet the corresponding limit for distillate oil and fuels other than natural gas for the duration of the time that 

you burn that particular fuel.

§ 60.4330 What emission limits must I meet for sulfur dioxide (SO2)?

(a) If your turbine is located in a continental area, you must comply with either paragraph (a)(1), (a)(2), or (a)(3) of this

section. If your turbine is located in Alaska, you do not have to comply with the requirements in paragraph (a) of this 

section until January 1, 2008.

(1) You must not cause to be discharged into the atmosphere from the subject stationary combustion turbine any 

gases which contain SO2in excess of 110 nanograms per Joule (ng/J) (0.90 pounds per megawatt-hour (lb/MWh)) 

gross output;

(2) You must not burn in the subject stationary combustion turbine any fuel which contains total potential sulfur 

emissions in excess of 26 ng SO2/J (0.060 lb SO2/MMBtu) heat input. If your turbine simultaneously fires multiple 

fuels, each fuel must meet this requirement; or

(3) For each stationary combustion turbine burning at least 50 percent biogas on a calendar month basis, as 

determined based on total heat input, you must not cause to be discharged into the atmosphere from the affected 

source any gases that contain SO2in excess of 65 ng SO2/J (0.15 lb SO2/MMBtu) heat input.

(b) If your turbine is located in a noncontinental area or a continental area that the Administrator determines does not 

have access to natural gas and that the removal of sulfur compounds would cause more environmental harm than 

benefit, you must comply with one or the other of the following conditions:

(1) You must not cause to be discharged into the atmosphere from the subject stationary combustion turbine any 

gases which contain SO2in excess of 780 ng/J (6.2 lb/MWh) gross output, or
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(2) You must not burn in the subject stationary combustion turbine any fuel which contains total sulfur with potential 

sulfur emissions in excess of 180 ng SO2/J (0.42 lb SO2/MMBtu) heat input. If your turbine simultaneously fires 

multiple fuels, each fuel must meet this requirement.

[71 FR 38497, July 6, 2006, as amended at 74 FR 11861, Mar. 20, 2009]

General Compliance Requirements

§ 60.4333 What are my general requirements for complying with this 

subpart?

(a) You must operate and maintain your stationary combustion turbine, air pollution control equipment, and 

monitoring equipment in a manner consistent with good air pollution control practices for minimizing emissions at all 

times including during startup, shutdown, and malfunction.

(b) When an affected unit with heat recovery utilizes a common steam header with one or more combustion turbines, 

the owner or operator shall either:

(1) Determine compliance with the applicable NOXemissions limits by measuring the emissions combined with the 

emissions from the other unit(s) utilizing the common heat recovery unit; or

(2) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the 

combined gross energy output from the heat recovery unit for each of the affected combustion turbines. The 

Administrator may approve such demonstrated substitute methods for apportioning the combined gross energy 

output measured at the steam turbine whenever the demonstration ensures accurate estimation of emissions related 

under this part.

Monitoring

§ 60.4335 How do I demonstrate compliance for NOXif I use water or 

steam injection?

(a) If you are using water or steam injection to control NOXemissions, you must install, calibrate, maintain and 

operate a continuous monitoring system to monitor and record the fuel consumption and the ratio of water or steam to 

fuel being fired in the turbine when burning a fuel that requires water or steam injection for compliance.

(b) Alternatively, you may use continuous emission monitoring, as follows:

(1) Install, certify, maintain, and operate a continuous emission monitoring system (CEMS) consisting of a 

NOXmonitor and a diluent gas (oxygen (O2) or carbon dioxide (CO2)) monitor, to determine the hourly NOXemission 

rate in parts per million (ppm) or pounds per million British thermal units (lb/MMBtu); and

(2) For units complying with the output-based standard, install, calibrate, maintain, and operate a fuel flow meter (or 

flow meters) to continuously measure the heat input to the affected unit; and

(3) For units complying with the output-based standard, install, calibrate, maintain, and operate a watt meter (or 

meters) to continuously measure the gross electrical output of the unit in megawatt-hours; and

(4) For combined heat and power units complying with the output-based standard, install, calibrate, maintain, and 

operate meters for useful recovered energy flow rate, temperature, and pressure, to continuously measure the total 

thermal energy output in British thermal units per hour (Btu/h).

§ 60.4340 How do I demonstrate continuous compliance for NOXif I do not 
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use water or steam injection?

(a) If you are not using water or steam injection to control NOXemissions, you must perform annual performance tests 

in accordance with §60.4400 to demonstrate continuous compliance. If the NOXemission result from the performance 

test is less than or equal to 75 percent of the NOXemission limit for the turbine, you may reduce the frequency of 

subsequent performance tests to once every 2 years (no more than 26 calendar months following the previous 

performance test). If the results of any subsequent performance test exceed 75 percent of the NOXemission limit for 

the turbine, you must resume annual performance tests.

(b) As an alternative, you may install, calibrate, maintain and operate one of the following continuous monitoring 

systems:

(1) Continuous emission monitoring as described in §§60.4335(b) and 60.4345, or

(2) Continuous parameter monitoring as follows:

(i) For a diffusion flame turbine without add-on selective catalytic reduction (SCR) controls, you must define 

parameters indicative of the unit's NOXformation characteristics, and you must monitor these parameters 

continuously.

(ii) For any lean premix stationary combustion turbine, you must continuously monitor the appropriate parameters to 

determine whether the unit is operating in low-NOXmode.

(iii) For any turbine that uses SCR to reduce NOXemissions, you must continuously monitor appropriate parameters 

to verify the proper operation of the emission controls.

(iv) For affected units that are also regulated under part 75 of this chapter, with state approval you can monitor the 

NOXemission rate using the methodology in appendix E to part 75 of this chapter, or the low mass emissions 

methodology in §75.19, the requirements of this paragraph (b) may be met by performing the parametric monitoring 

described in section 2.3 of part 75 appendix E or in §75.19(c)(1)(iv)(H).

§ 60.4345 What are the requirements for the continuous emission 

monitoring system equipment, if I choose to use this option?

If the option to use a NOXCEMS is chosen:

(a) Each NOXdiluent CEMS must be installed and certified according to Performance Specification 2 (PS 2) in 

appendix B to this part, except the 7-day calibration drift is based on unit operating days, not calendar days. With 

state approval, Procedure 1 in appendix F to this part is not required. Alternatively, a NOXdiluent CEMS that is 

installed and certified according to appendix A of part 75 of this chapter is acceptable for use under this subpart. The 

relative accuracy test audit (RATA) of the CEMS shall be performed on a lb/MMBtu basis.

(b) As specified in §60.13(e)(2), during each full unit operating hour, both the NOXmonitor and the diluent monitor 

must complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each 15-minute 

quadrant of the hour, to validate the hour. For partial unit operating hours, at least one valid data point must be 

obtained with each monitor for each quadrant of the hour in which the unit operates. For unit operating hours in which 

required quality assurance and maintenance activities are performed on the CEMS, a minimum of two valid data 

points (one in each of two quadrants) are required for each monitor to validate the NOXemission rate for the hour.

(c) Each fuel flowmeter shall be installed, calibrated, maintained, and operated according to the manufacturer's 

instructions. Alternatively, with state approval, fuel flowmeters that meet the installation, certification, and quality 

assurance requirements of appendix D to part 75 of this chapter are acceptable for use under this subpart.

(d) Each watt meter, steam flow meter, and each pressure or temperature measurement device shall be installed, 

calibrated, maintained, and operated according to manufacturer's instructions.
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(e) The owner or operator shall develop and keep on-site a quality assurance (QA) plan for all of the continuous 

monitoring equipment described in paragraphs (a), (c), and (d) of this section. For the CEMS and fuel flow meters, 

the owner or operator may, with state approval, satisfy the requirements of this paragraph by implementing the QA 

program and plan described in section 1 of appendix B to part 75 of this chapter.

§ 60.4350 How do I use data from the continuous emission monitoring 

equipment to identify excess emissions?

For purposes of identifying excess emissions:

(a) All CEMS data must be reduced to hourly averages as specified in §60.13(h).

(b) For each unit operating hour in which a valid hourly average, as described in §60.4345(b), is obtained for both 

NOXand diluent monitors, the data acquisition and handling system must calculate and record the hourly 

NOXemission rate in units of ppm or lb/MMBtu, using the appropriate equation from method 19 in appendix A of this 

part. For any hour in which the hourly average O2concentration exceeds 19.0 percent O2(or the hourly average 

CO2concentration is less than 1.0 percent CO2), a diluent cap value of 19.0 percent O2or 1.0 percent CO2(as 

applicable) may be used in the emission calculations.

(c) Correction of measured NOXconcentrations to 15 percent O2is not allowed.

(d) If you have installed and certified a NOXdiluent CEMS to meet the requirements of part 75 of this chapter, states 

can approve that only quality assured data from the CEMS shall be used to identify excess emissions under this 

subpart. Periods where the missing data substitution procedures in subpart D of part 75 are applied are to be 

reported as monitor downtime in the excess emissions and monitoring performance report required under §60.7(c).

(e) All required fuel flow rate, steam flow rate, temperature, pressure, and megawatt data must be reduced to hourly 

averages.

(f) Calculate the hourly average NOXemission rates, in units of the emission standards under §60.4320, using either 

ppm for units complying with the concentration limit or the following equation for units complying with the output 

based standard:

(1) For simple-cycle operation:

Where:

E = hourly NOXemission rate, in lb/MWh,

(NOX)h= hourly NOXemission rate, in lb/MMBtu,

(HI)h= hourly heat input rate to the unit, in MMBtu/h, measured using the fuel flowmeter(s), e.g. , 

calculated using Equation D–15a in appendix D to part 75 of this chapter, and

P = gross energy output of the combustion turbine in MW.

(2) For combined-cycle and combined heat and power complying with the output-based standard, use Equation 1 of 

this subpart, except that the gross energy output is calculated as the sum of the total electrical and mechanical 

energy generated by the combustion turbine, the additional electrical or mechanical energy (if any) generated by the 

steam turbine following the heat recovery steam generator, and 100 percent of the total useful thermal energy output 
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that is not used to generate additional electricity or mechanical output, expressed in equivalent MW, as in the 

following equations:

Where:

P = gross energy output of the stationary combustion turbine system in MW.

(Pe)t= electrical or mechanical energy output of the combustion turbine in MW,

(Pe)c= electrical or mechanical energy output (if any) of the steam turbine in MW, and

Where:

Ps = useful thermal energy of the steam, measured relative to ISO conditions, not used to generate 

additional electric or mechanical output, in MW,

Q = measured steam flow rate in lb/h,

H = enthalpy of the steam at measured temperature and pressure relative to ISO conditions, in Btu/lb, 

and 3.413 x 106= conversion from Btu/h to MW.

Po = other useful heat recovery, measured relative to ISO conditions, not used for steam generation or 

performance enhancement of the combustion turbine.

(3) For mechanical drive applications complying with the output-based standard, use the following equation:

Where:

E = NOXemission rate in lb/MWh,

(NOX)m= NOXemission rate in lb/h,

BL = manufacturer's base load rating of turbine, in MW, and

AL = actual load as a percentage of the base load.

(g) For simple cycle units without heat recovery, use the calculated hourly average emission rates from paragraph (f) 

of this section to assess excess emissions on a 4-hour rolling average basis, as described in §60.4380(b)(1).

(h) For combined cycle and combined heat and power units with heat recovery, use the calculated hourly average 

emission rates from paragraph (f) of this section to assess excess emissions on a 30 unit operating day rolling 

average basis, as described in §60.4380(b)(1).
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§ 60.4355 How do I establish and document a proper parameter 

monitoring plan?

(a) The steam or water to fuel ratio or other parameters that are continuously monitored as described in §§60.4335 

and 60.4340 must be monitored during the performance test required under §60.8, to establish acceptable values 

and ranges. You may supplement the performance test data with engineering analyses, design specifications, 

manufacturer's recommendations and other relevant information to define the acceptable parametric ranges more 

precisely. You must develop and keep on-site a parameter monitoring plan which explains the procedures used to 

document proper operation of the NOXemission controls. The plan must:

(1) Include the indicators to be monitored and show there is a significant relationship to emissions and proper 

operation of the NOXemission controls,

(2) Pick ranges (or designated conditions) of the indicators, or describe the process by which such range (or 

designated condition) will be established,

(3) Explain the process you will use to make certain that you obtain data that are representative of the emissions or 

parameters being monitored (such as detector location, installation specification if applicable),

(4) Describe quality assurance and control practices that are adequate to ensure the continuing validity of the data,

(5) Describe the frequency of monitoring and the data collection procedures which you will use (e.g., you are using a 

computerized data acquisition over a number of discrete data points with the average (or maximum value) being used 

for purposes of determining whether an exceedance has occurred), and

(6) Submit justification for the proposed elements of the monitoring. If a proposed performance specification differs 

from manufacturer recommendation, you must explain the reasons for the differences. You must submit the data 

supporting the justification, but you may refer to generally available sources of information used to support the 

justification. You may rely on engineering assessments and other data, provided you demonstrate factors which 

assure compliance or explain why performance testing is unnecessary to establish indicator ranges. When 

establishing indicator ranges, you may choose to simplify the process by treating the parameters as if they were 

correlated. Using this assumption, testing can be divided into two cases:

(i) All indicators are significant only on one end of range (e.g., for a thermal incinerator controlling volatile organic 

compounds (VOC) it is only important to insure a minimum temperature, not a maximum). In this case, you may 

conduct your study so that each parameter is at the significant limit of its range while you conduct your emissions 

testing. If the emissions tests show that the source is in compliance at the significant limit of each parameter, then as 

long as each parameter is within its limit, you are presumed to be in compliance.

(ii) Some or all indicators are significant on both ends of the range. In this case, you may conduct your study so that 

each parameter that is significant at both ends of its range assumes its extreme values in all possible combinations of 

the extreme values (either single or double) of all of the other parameters. For example, if there were only two 

parameters, A and B, and A had a range of values while B had only a minimum value, the combinations would be A 

high with B minimum and A low with B minimum. If both A and B had a range, the combinations would be A high and 

B high, A low and B low, A high and B low, A low and B high. For the case of four parameters all having a range, 

there are 16 possible combinations.

(b) For affected units that are also subject to part 75 of this chapter and that have state approval to use the low mass 

emissions methodology in §75.19 or the NOXemission measurement methodology in appendix E to part 75, you may 

meet the requirements of this paragraph by developing and keeping on-site (or at a central location for unmanned 

facilities) a QA plan, as described in §75.19(e)(5) or in section 2.3 of appendix E to part 75 of this chapter and section 

1.3.6 of appendix B to part 75 of this chapter.

§ 60.4360 How do I determine the total sulfur content of the turbine's 

combustion fuel?
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You must monitor the total sulfur content of the fuel being fired in the turbine, except as provided in §60.4365. The 

sulfur content of the fuel must be determined using total sulfur methods described in §60.4415. Alternatively, if the 

total sulfur content of the gaseous fuel during the most recent performance test was less than half the applicable limit, 

ASTM D4084, D4810, D5504, or D6228, or Gas Processors Association Standard 2377 (all of which are incorporated 

by reference, see §60.17), which measure the major sulfur compounds, may be used.

§ 60.4365 How can I be exempted from monitoring the total sulfur content 

of the fuel?

You may elect not to monitor the total sulfur content of the fuel combusted in the turbine, if the fuel is demonstrated 

not to exceed potential sulfur emissions of 26 ng SO2/J (0.060 lb SO2/MMBtu) heat input for units located in 

continental areas and 180 ng SO2/J (0.42 lb SO2/MMBtu) heat input for units located in noncontinental areas or a 

continental area that the Administrator determines does not have access to natural gas and that the removal of sulfur 

compounds would cause more environmental harm than benefit. You must use one of the following sources of 

information to make the required demonstration:

(a) The fuel quality characteristics in a current, valid purchase contract, tariff sheet or transportation contract for the 

fuel, specifying that the maximum total sulfur content for oil use in continental areas is 0.05 weight percent (500 

ppmw) or less and 0.4 weight percent (4,000 ppmw) or less for noncontinental areas, the total sulfur content for 

natural gas use in continental areas is 20 grains of sulfur or less per 100 standard cubic feet and 140 grains of sulfur 

or less per 100 standard cubic feet for noncontinental areas, has potential sulfur emissions of less than less than 26 

ng SO2/J (0.060 lb SO2/MMBtu) heat input for continental areas and has potential sulfur emissions of less than less 

than 180 ng SO2/J (0.42 lb SO2/MMBtu) heat input for noncontinental areas; or

(b) Representative fuel sampling data which show that the sulfur content of the fuel does not exceed 26 ng SO2/J 

(0.060 lb SO2/MMBtu) heat input for continental areas or 180 ng SO2/J (0.42 lb SO2/MMBtu) heat input for 

noncontinental areas. At a minimum, the amount of fuel sampling data specified in section 2.3.1.4 or 2.3.2.4 of 

appendix D to part 75 of this chapter is required.

§ 60.4370 How often must I determine the sulfur content of the fuel?

The frequency of determining the sulfur content of the fuel must be as follows:

(a) Fuel oil. For fuel oil, use one of the total sulfur sampling options and the associated sampling frequency described 

in sections 2.2.3, 2.2.4.1, 2.2.4.2, and 2.2.4.3 of appendix D to part 75 of this chapter ( i.e. , flow proportional 

sampling, daily sampling, sampling from the unit's storage tank after each addition of fuel to the tank, or sampling 

each delivery prior to combining it with fuel oil already in the intended storage tank).

(b) Gaseous fuel. If you elect not to demonstrate sulfur content using options in §60.4365, and the fuel is supplied 

without intermediate bulk storage, the sulfur content value of the gaseous fuel must be determined and recorded 

once per unit operating day.

(c) Custom schedules. Notwithstanding the requirements of paragraph (b) of this section, operators or fuel vendors 

may develop custom schedules for determination of the total sulfur content of gaseous fuels, based on the design 

and operation of the affected facility and the characteristics of the fuel supply. Except as provided in paragraphs 

(c)(1) and (c)(2) of this section, custom schedules shall be substantiated with data and shall be approved by the 

Administrator before they can be used to comply with the standard in §60.4330.

(1) The two custom sulfur monitoring schedules set forth in paragraphs (c)(1)(i) through (iv) and in paragraph (c)(2) of 

this section are acceptable, without prior Administrative approval:

(i) The owner or operator shall obtain daily total sulfur content measurements for 30 consecutive unit operating days, 

using the applicable methods specified in this subpart. Based on the results of the 30 daily samples, the required 

frequency for subsequent monitoring of the fuel's total sulfur content shall be as specified in paragraph (c)(1)(ii), (iii), 

or (iv) of this section, as applicable.
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(ii) If none of the 30 daily measurements of the fuel's total sulfur content exceeds half the applicable standard, 

subsequent sulfur content monitoring may be performed at 12-month intervals. If any of the samples taken at 12-

month intervals has a total sulfur content greater than half but less than the applicable limit, follow the procedures in 

paragraph (c)(1)(iii) of this section. If any measurement exceeds the applicable limit, follow the procedures in 

paragraph (c)(1)(iv) of this section.

(iii) If at least one of the 30 daily measurements of the fuel's total sulfur content is greater than half but less than the 

applicable limit, but none exceeds the applicable limit, then:

(A) Collect and analyze a sample every 30 days for 3 months. If any sulfur content measurement exceeds the 

applicable limit, follow the procedures in paragraph (c)(1)(iv) of this section. Otherwise, follow the procedures in 

paragraph (c)(1)(iii)(B) of this section.

(B) Begin monitoring at 6-month intervals for 12 months. If any sulfur content measurement exceeds the applicable 

limit, follow the procedures in paragraph (c)(1)(iv) of this section. Otherwise, follow the procedures in paragraph 

(c)(1)(iii)(C) of this section.

(C) Begin monitoring at 12-month intervals. If any sulfur content measurement exceeds the applicable limit, follow the 

procedures in paragraph (c)(1)(iv) of this section. Otherwise, continue to monitor at this frequency.

(iv) If a sulfur content measurement exceeds the applicable limit, immediately begin daily monitoring according to 

paragraph (c)(1)(i) of this section. Daily monitoring shall continue until 30 consecutive daily samples, each having a 

sulfur content no greater than the applicable limit, are obtained. At that point, the applicable procedures of paragraph 

(c)(1)(ii) or (iii) of this section shall be followed.

(2) The owner or operator may use the data collected from the 720-hour sulfur sampling demonstration described in 

section 2.3.6 of appendix D to part 75 of this chapter to determine a custom sulfur sampling schedule, as follows:

(i) If the maximum fuel sulfur content obtained from the 720 hourly samples does not exceed 20 grains/100 scf, no 

additional monitoring of the sulfur content of the gas is required, for the purposes of this subpart.

(ii) If the maximum fuel sulfur content obtained from any of the 720 hourly samples exceeds 20 grains/100 scf, but 

none of the sulfur content values (when converted to weight percent sulfur) exceeds half the applicable limit, then the 

minimum required sampling frequency shall be one sample at 12 month intervals.

(iii) If any sample result exceeds half the applicable limit, but none exceeds the applicable limit, follow the provisions 

of paragraph (c)(1)(iii) of this section.

(iv) If the sulfur content of any of the 720 hourly samples exceeds the applicable limit, follow the provisions of 

paragraph (c)(1)(iv) of this section.

Reporting

§ 60.4375 What reports must I submit?

(a) For each affected unit required to continuously monitor parameters or emissions, or to periodically determine the 

fuel sulfur content under this subpart, you must submit reports of excess emissions and monitor downtime, in 

accordance with §60.7(c). Excess emissions must be reported for all periods of unit operation, including start-up, 

shutdown, and malfunction.

(b) For each affected unit that performs annual performance tests in accordance with §60.4340(a), you must submit a 

written report of the results of each performance test before the close of business on the 60th day following the 

completion of the performance test.

§ 60.4380 How are excess emissions and monitor downtime defined for 
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NOX?

For the purpose of reports required under §60.7(c), periods of excess emissions and monitor downtime that must be 

reported are defined as follows:

(a) For turbines using water or steam to fuel ratio monitoring:

(1) An excess emission is any unit operating hour for which the 4-hour rolling average steam or water to fuel ratio, as 

measured by the continuous monitoring system, falls below the acceptable steam or water to fuel ratio needed to 

demonstrate compliance with §60.4320, as established during the performance test required in §60.8. Any unit 

operating hour in which no water or steam is injected into the turbine when a fuel is being burned that requires water 

or steam injection for NOXcontrol will also be considered an excess emission.

(2) A period of monitor downtime is any unit operating hour in which water or steam is injected into the turbine, but 

the essential parametric data needed to determine the steam or water to fuel ratio are unavailable or invalid.

(3) Each report must include the average steam or water to fuel ratio, average fuel consumption, and the combustion 

turbine load during each excess emission.

(b) For turbines using continuous emission monitoring, as described in §§60.4335(b) and 60.4345:

(1) An excess emissions is any unit operating period in which the 4-hour or 30-day rolling average NOXemission rate 

exceeds the applicable emission limit in §60.4320. For the purposes of this subpart, a “4-hour rolling average 

NOXemission rate” is the arithmetic average of the average NOXemission rate in ppm or ng/J (lb/MWh) measured by 

the continuous emission monitoring equipment for a given hour and the three unit operating hour average 

NOXemission rates immediately preceding that unit operating hour. Calculate the rolling average if a valid 

NOXemission rate is obtained for at least 3 of the 4 hours. For the purposes of this subpart, a “30-day rolling average 

NOXemission rate” is the arithmetic average of all hourly NOXemission data in ppm or ng/J (lb/MWh) measured by 

the continuous emission monitoring equipment for a given day and the twenty-nine unit operating days immediately 

preceding that unit operating day. A new 30-day average is calculated each unit operating day as the average of all 

hourly NOXemissions rates for the preceding 30 unit operating days if a valid NOXemission rate is obtained for at 

least 75 percent of all operating hours.

(2) A period of monitor downtime is any unit operating hour in which the data for any of the following parameters are 

either missing or invalid: NOXconcentration, CO2 or O2concentration, fuel flow rate, steam flow rate, steam 

temperature, steam pressure, or megawatts. The steam flow rate, steam temperature, and steam pressure are only 

required if you will use this information for compliance purposes.

(3) For operating periods during which multiple emissions standards apply, the applicable standard is the average of 

the applicable standards during each hour. For hours with multiple emissions standards, the applicable limit for that 

hour is determined based on the condition that corresponded to the highest emissions standard.

(c) For turbines required to monitor combustion parameters or parameters that document proper operation of the 

NOXemission controls:

(1) An excess emission is a 4-hour rolling unit operating hour average in which any monitored parameter does not 

achieve the target value or is outside the acceptable range defined in the parameter monitoring plan for the unit.

(2) A period of monitor downtime is a unit operating hour in which any of the required parametric data are either not 

recorded or are invalid.

§ 60.4385 How are excess emissions and monitoring downtime defined for 

SO2?

If you choose the option to monitor the sulfur content of the fuel, excess emissions and monitoring downtime are 

defined as follows:
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(a) For samples of gaseous fuel and for oil samples obtained using daily sampling, flow proportional sampling, or 

sampling from the unit's storage tank, an excess emission occurs each unit operating hour included in the period 

beginning on the date and hour of any sample for which the sulfur content of the fuel being fired in the combustion 

turbine exceeds the applicable limit and ending on the date and hour that a subsequent sample is taken that 

demonstrates compliance with the sulfur limit.

(b) If the option to sample each delivery of fuel oil has been selected, you must immediately switch to one of the other 

oil sampling options (i.e., daily sampling, flow proportional sampling, or sampling from the unit's storage tank) if the 

sulfur content of a delivery exceeds 0.05 weight percent. You must continue to use one of the other sampling options 

until all of the oil from the delivery has been combusted, and you must evaluate excess emissions according to 

paragraph (a) of this section. When all of the fuel from the delivery has been burned, you may resume using the asdelivered sampling option.

(c) A period of monitor downtime begins when a required sample is not taken by its due date. A period of monitor 

downtime also begins on the date and hour of a required sample, if invalid results are obtained. The period of monitor 

downtime ends on the date and hour of the next valid sample.

§ 60.4390 What are my reporting requirements if I operate an emergency 

combustion turbine or a research and development turbine?

(a) If you operate an emergency combustion turbine, you are exempt from the NOXlimit and must submit an initial 

report to the Administrator stating your case.

(b) Combustion turbines engaged by manufacturers in research and development of equipment for both combustion 

turbine emission control techniques and combustion turbine efficiency improvements may be exempted from the 

NOXlimit on a case-by-case basis as determined by the Administrator. You must petition for the exemption.

§ 60.4395 When must I submit my reports?

All reports required under §60.7(c) must be postmarked by the 30th day following the end of each 6-month period.

Performance Tests

§ 60.4400 How do I conduct the initial and subsequent performance tests, 

regarding NOX?

(a) You must conduct an initial performance test, as required in §60.8. Subsequent NOXperformance tests shall be 

conducted on an annual basis (no more than 14 calendar months following the previous performance test).

(1) There are two general methodologies that you may use to conduct the performance tests. For each test run:

(i) Measure the NOXconcentration (in parts per million (ppm)), using EPA Method 7E or EPA Method 20 in appendix 

A of this part. For units complying with the output based standard, concurrently measure the stack gas flow rate, 

using EPA Methods 1 and 2 in appendix A of this part, and measure and record the electrical and thermal output from 

the unit. Then, use the following equation to calculate the NOXemission rate:

Where:

E = NOXemission rate, in lb/MWh
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1.194 × 10−7= conversion constant, in lb/dscf-ppm

(NOX)c= average NOXconcentration for the run, in ppm

Qstd= stack gas volumetric flow rate, in dscf/hr

P = gross electrical and mechanical energy output of the combustion turbine, in MW (for simple-cycle 

operation), for combined-cycle operation, the sum of all electrical and mechanical output from the 

combustion and steam turbines, or, for combined heat and power operation, the sum of all electrical and 

mechanical output from the combustion and steam turbines plus all useful recovered thermal output not 

used for additional electric or mechanical generation, in MW, calculated according to §60.4350(f)(2); or

(ii) Measure the NOXand diluent gas concentrations, using either EPA Methods 7E and 3A, or EPA Method 20 in 

appendix A of this part. Concurrently measure the heat input to the unit, using a fuel flowmeter (or flowmeters), and 

measure the electrical and thermal output of the unit. Use EPA Method 19 in appendix A of this part to calculate the 

NOXemission rate in lb/MMBtu. Then, use Equations 1 and, if necessary, 2 and 3 in §60.4350(f) to calculate the 

NOXemission rate in lb/MWh.

(2) Sampling traverse points for NOXand (if applicable) diluent gas are to be selected following EPA Method 20 or 

EPA Method 1 (non-particulate procedures), and sampled for equal time intervals. The sampling must be performed 

with a traversing single-hole probe, or, if feasible, with a stationary multi-hole probe that samples each of the points 

sequentially. Alternatively, a multi-hole probe designed and documented to sample equal volumes from each hole 

may be used to sample simultaneously at the required points.

(3) Notwithstanding paragraph (a)(2) of this section, you may test at fewer points than are specified in EPA Method 1 

or EPA Method 20 in appendix A of this part if the following conditions are met:

(i) You may perform a stratification test for NOXand diluent pursuant to

(A) [Reserved], or

(B) The procedures specified in section 6.5.6.1(a) through (e) of appendix A of part 75 of this chapter.

(ii) Once the stratification sampling is completed, you may use the following alternative sample point selection criteria 

for the performance test:

(A) If each of the individual traverse point NOXconcentrations is within ±10 percent of the mean concentration for all 

traverse points, or the individual traverse point diluent concentrations differs by no more than ±5ppm or ±0.5 percent 

CO2(or O2) from the mean for all traverse points, then you may use three points (located either 16.7, 50.0 and 83.3 

percent of the way across the stack or duct, or, for circular stacks or ducts greater than 2.4 meters (7.8 feet) in 

diameter, at 0.4, 1.2, and 2.0 meters from the wall). The three points must be located along the measurement line 

that exhibited the highest average NOXconcentration during the stratification test; or

(B) For turbines with a NOXstandard greater than 15 ppm @ 15% O2, you may sample at a single point, located at 

least 1 meter from the stack wall or at the stack centroid if each of the individual traverse point NOXconcentrations is 

within ±5 percent of the mean concentration for all traverse points, or the individual traverse point diluent 

concentrations differs by no more than ±3ppm or ±0.3 percent CO2(or O2) from the mean for all traverse points; or

(C) For turbines with a NOXstandard less than or equal to 15 ppm @ 15% O2, you may sample at a single point, 

located at least 1 meter from the stack wall or at the stack centroid if each of the individual traverse point 

NOXconcentrations is within ±2.5 percent of the mean concentration for all traverse points, or the individual traverse 

point diluent concentrations differs by no more than ±1ppm or ±0.15 percent CO2(or O2) from the mean for all 

traverse points.

(b) The performance test must be done at any load condition within plus or minus 25 percent of 100 percent of peak 

load. You may perform testing at the highest achievable load point, if at least 75 percent of peak load cannot be 
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achieved in practice. You must conduct three separate test runs for each performance test. The minimum time per 

run is 20 minutes.

(1) If the stationary combustion turbine combusts both oil and gas as primary or backup fuels, separate performance 

testing is required for each fuel.

(2) For a combined cycle and CHP turbine systems with supplemental heat (duct burner), you must measure the total 

NOXemissions after the duct burner rather than directly after the turbine. The duct burner must be in operation during 

the performance test.

(3) If water or steam injection is used to control NOXwith no additional post-combustion NOXcontrol and you choose 

to monitor the steam or water to fuel ratio in accordance with §60.4335, then that monitoring system must be 

operated concurrently with each EPA Method 20 or EPA Method 7E run and must be used to determine the fuel 

consumption and the steam or water to fuel ratio necessary to comply with the applicable §60.4320 NOXemission 

limit.

(4) Compliance with the applicable emission limit in §60.4320 must be demonstrated at each tested load level. 

Compliance is achieved if the three-run arithmetic average NOXemission rate at each tested level meets the 

applicable emission limit in §60.4320.

(5) If you elect to install a CEMS, the performance evaluation of the CEMS may either be conducted separately or (as 

described in §60.4405) as part of the initial performance test of the affected unit.

(6) The ambient temperature must be greater than 0 °F during the performance test.

§ 60.4405 How do I perform the initial performance test if I have chosen to 

install a NOX-diluent CEMS?

If you elect to install and certify a NOX-diluent CEMS under §60.4345, then the initial performance test required under 

§60.8 may be performed in the following alternative manner:

(a) Perform a minimum of nine RATA reference method runs, with a minimum time per run of 21 minutes, at a single 

load level, within plus or minus 25 percent of 100 percent of peak load. The ambient temperature must be greater 

than 0 °F during the RATA runs.

(b) For each RATA run, concurrently measure the heat input to the unit using a fuel flow meter (or flow meters) and 

measure the electrical and thermal output from the unit.

(c) Use the test data both to demonstrate compliance with the applicable NOXemission limit under §60.4320 and to 

provide the required reference method data for the RATA of the CEMS described under §60.4335.

(d) Compliance with the applicable emission limit in §60.4320 is achieved if the arithmetic average of all of the 

NOXemission rates for the RATA runs, expressed in units of ppm or lb/MWh, does not exceed the emission limit.

§ 60.4410 How do I establish a valid parameter range if I have chosen to 

continuously monitor parameters?

If you have chosen to monitor combustion parameters or parameters indicative of proper operation of NOXemission 

controls in accordance with §60.4340, the appropriate parameters must be continuously monitored and recorded 

during each run of the initial performance test, to establish acceptable operating ranges, for purposes of the 

parameter monitoring plan for the affected unit, as specified in §60.4355.

§ 60.4415 How do I conduct the initial and subsequent performance tests 

for sulfur?
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(a) You must conduct an initial performance test, as required in §60.8. Subsequent SO2performance tests shall be

conducted on an annual basis (no more than 14 calendar months following the previous performance test). There are 

three methodologies that you may use to conduct the performance tests.

(1) If you choose to periodically determine the sulfur content of the fuel combusted in the turbine, a representative 

fuel sample would be collected following ASTM D5287 (incorporated by reference, see §60.17) for natural gas or 

ASTM D4177 (incorporated by reference, see §60.17) for oil. Alternatively, for oil, you may follow the procedures for 

manual pipeline sampling in section 14 of ASTM D4057 (incorporated by reference, see §60.17). The fuel analyses of 

this section may be performed either by you, a service contractor retained by you, the fuel vendor, or any other 

qualified agency. Analyze the samples for the total sulfur content of the fuel using:

(i) For liquid fuels, ASTM D129, or alternatively D1266, D1552, D2622, D4294, or D5453 (all of which are 

incorporated by reference, see §60.17); or

(ii) For gaseous fuels, ASTM D1072, or alternatively D3246, D4084, D4468, D4810, D6228, D6667, or Gas 

Processors Association Standard 2377 (all of which are incorporated by reference, see §60.17).

(2) Measure the SO2concentration (in parts per million (ppm)), using EPA Methods 6, 6C, 8, or 20 in appendix A of 

this part. In addition, the American Society of Mechanical Engineers (ASME) standard, ASME PTC 19–10–1981–Part 

10, “Flue and Exhaust Gas Analyses,” manual methods for sulfur dioxide (incorporated by reference, see §60.17) can 

be used instead of EPA Methods 6 or 20. For units complying with the output based standard, concurrently measure 

the stack gas flow rate, using EPA Methods 1 and 2 in appendix A of this part, and measure and record the electrical 

and thermal output from the unit. Then use the following equation to calculate the SO2emission rate:

Where:

E = SO2emission rate, in lb/MWh

1.664 × 10−7= conversion constant, in lb/dscf-ppm

(SO2)c= average SO2concentration for the run, in ppm

Qstd= stack gas volumetric flow rate, in dscf/hr

P = gross electrical and mechanical energy output of the combustion turbine, in MW (for simple-cycle 

operation), for combined-cycle operation, the sum of all electrical and mechanical output from the 

combustion and steam turbines, or, for combined heat and power operation, the sum of all electrical and 

mechanical output from the combustion and steam turbines plus all useful recovered thermal output not 

used for additional electric or mechanical generation, in MW, calculated according to §60.4350(f)(2); or

(3) Measure the SO2and diluent gas concentrations, using either EPA Methods 6, 6C, or 8 and 3A, or 20 in appendix 

A of this part. In addition, you may use the manual methods for sulfur dioxide ASME PTC 19–10–1981–Part 10 

(incorporated by reference, see §60.17). Concurrently measure the heat input to the unit, using a fuel flowmeter (or 

flowmeters), and measure the electrical and thermal output of the unit. Use EPA Method 19 in appendix A of this part 

to calculate the SO2emission rate in lb/MMBtu. Then, use Equations 1 and, if necessary, 2 and 3 in §60.4350(f) to 

calculate the SO2emission rate in lb/MWh.

(b) [Reserved]

Definitions
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§ 60.4420 What definitions apply to this subpart?

As used in this subpart, all terms not defined herein will have the meaning given them in the Clean Air Act and in 

subpart A (General Provisions) of this part.

Biogas means gas produced by the anaerobic digestion or fermentation of organic matter including manure, sewage 

sludge, municipal solid waste, biodegradable waste, or any other biodegradable feedstock, under anaerobic 

conditions. Biogas is comprised primarily of methane and CO2.

Combined cycle combustion turbine means any stationary combustion turbine which recovers heat from the 

combustion turbine exhaust gases to generate steam that is only used to create additional power output in a steam 

turbine.

Combined heat and power combustion turbine means any stationary combustion turbine which recovers heat from 

the exhaust gases to heat water or another medium, generate steam for useful purposes other than additional electric 

generation, or directly uses the heat in the exhaust gases for a useful purpose.

Combustion turbine model means a group of combustion turbines having the same nominal air flow, combustor inlet 

pressure, combustor inlet temperature, firing temperature, turbine inlet temperature and turbine inlet pressure.

Combustion turbine test cell/stand means any apparatus used for testing uninstalled stationary or uninstalled mobile 

(motive) combustion turbines.

Diffusion flame stationary combustion turbine means any stationary combustion turbine where fuel and air are 

injected at the combustor and are mixed only by diffusion prior to ignition.

Duct burner means a device that combusts fuel and that is placed in the exhaust duct from another source, such as a 

stationary combustion turbine, internal combustion engine, kiln, etc., to allow the firing of additional fuel to heat the 

exhaust gases before the exhaust gases enter a heat recovery steam generating unit.

Efficiency means the combustion turbine manufacturer's rated heat rate at peak load in terms of heat input per unit of 

power output—based on the higher heating value of the fuel.

Emergency combustion turbine means any stationary combustion turbine which operates in an emergency situation. 

Examples include stationary combustion turbines used to produce power for critical networks or equipment, including 

power supplied to portions of a facility, when electric power from the local utility is interrupted, or stationary 

combustion turbines used to pump water in the case of fire or flood, etc. Emergency stationary combustion turbines 

do not include stationary combustion turbines used as peaking units at electric utilities or stationary combustion 

turbines at industrial facilities that typically operate at low capacity factors. Emergency combustion turbines may be 

operated for the purpose of maintenance checks and readiness testing, provided that the tests are required by the 

manufacturer, the vendor, or the insurance company associated with the turbine. Required testing of such units 

should be minimized, but there is no time limit on the use of emergency combustion turbines.

Excess emissions means a specified averaging period over which either (1) the NOXemissions are higher than the 

applicable emission limit in §60.4320; (2) the total sulfur content of the fuel being combusted in the affected facility 

exceeds the limit specified in §60.4330; or (3) the recorded value of a particular monitored parameter is outside the 

acceptable range specified in the parameter monitoring plan for the affected unit.

Gross useful output means the gross useful work performed by the stationary combustion turbine system. For units 

using the mechanical energy directly or generating only electricity, the gross useful work performed is the gross 

electrical or mechanical output from the turbine/generator set. For combined heat and power units, the gross useful 

work performed is the gross electrical or mechanical output plus the useful thermal output (i.e., thermal energy 

delivered to a process).

Heat recovery steam generating unit means a unit where the hot exhaust gases from the combustion turbine are 

routed in order to extract heat from the gases and generate steam, for use in a steam turbine or other device that 

utilizes steam. Heat recovery steam generating units can be used with or without duct burners.
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Integrated gasification combined cycle electric utility steam generating unit means a coal-fired electric utility steam 

generating unit that burns a synthetic gas derived from coal in a combined-cycle gas turbine. No solid coal is directly 

burned in the unit during operation.

ISO conditions means 288 Kelvin, 60 percent relative humidity and 101.3 kilopascals pressure.

Lean premix stationary combustion turbine means any stationary combustion turbine where the air and fuel are 

thoroughly mixed to form a lean mixture before delivery to the combustor. Mixing may occur before or in the 

combustion chamber. A lean premixed turbine may operate in diffusion flame mode during operating conditions such 

as startup and shutdown, extreme ambient temperature, or low or transient load.

Natural gas means a naturally occurring fluid mixture of hydrocarbons (e.g., methane, ethane, or propane) produced 

in geological formations beneath the Earth's surface that maintains a gaseous state at standard atmospheric 

temperature and pressure under ordinary conditions. Additionally, natural gas must either be composed of at least 70 

percent methane by volume or have a gross calorific value between 950 and 1,100 British thermal units (Btu) per 

standard cubic foot. Natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, 

sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a 

process which might result in highly variable sulfur content or heating value.

Noncontinental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of 

Puerto Rico, the Northern Mariana Islands, or offshore platforms.

Peak load means 100 percent of the manufacturer's design capacity of the combustion turbine at ISO conditions.

Regenerative cycle combustion turbine means any stationary combustion turbine which recovers heat from the 

combustion turbine exhaust gases to preheat the inlet combustion air to the combustion turbine.

Simple cycle combustion turbine means any stationary combustion turbine which does not recover heat from the 

combustion turbine exhaust gases to preheat the inlet combustion air to the combustion turbine, or which does not 

recover heat from the combustion turbine exhaust gases for purposes other than enhancing the performance of the 

combustion turbine itself.

Stationary combustion turbine means all equipment, including but not limited to the turbine, the fuel, air, lubrication 

and exhaust gas systems, control systems (except emissions control equipment), heat recovery system, and any 

ancillary components and sub-components comprising any simple cycle stationary combustion turbine, any 

regenerative/recuperative cycle stationary combustion turbine, any combined cycle combustion turbine, and any 

combined heat and power combustion turbine based system. Stationary means that the combustion turbine is not self 

propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for 

portability.

Unit operating day means a 24-hour period between 12 midnight and the following midnight during which any fuel is 

combusted at any time in the unit. It is not necessary for fuel to be combusted continuously for the entire 24-hour 

period.

Unit operating hour means a clock hour during which any fuel is combusted in the affected unit. If the unit combusts 

fuel for the entire clock hour, it is considered to be a full unit operating hour. If the unit combusts fuel for only part of

the clock hour, it is considered to be a partial unit operating hour.

Useful thermal output means the thermal energy made available for use in any industrial or commercial process, or 

used in any heating or cooling application, i.e., total thermal energy made available for processes and applications 

other than electrical or mechanical generation. Thermal output for this subpart means the energy in recovered 

thermal output measured against the energy in the thermal output at 15 degrees Celsius and 101.325 kilopascals of 

pressure.

[71 FR 38497, July 6, 2006, as amended at 74 FR 11861, Mar. 20, 2009]

Table 1 to Subpart KKKK of Part 60—Nitrogen Oxide Emission Limits for 
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New Stationary Combustion Turbines

Combustion turbine type

Combustion 

turbine heat 

input at peak 

load

(HHV) NOXemission standard

New turbine firing natural gas, electric generating ≤ 50 MMBtu/h 42 ppm at 15 percent 

O2or 290 ng/J of useful 

output (2.3 lb/MWh).

New turbine firing natural gas, mechanical drive ≤ 50 MMBtu/h 100 ppm at 15 percent 

O2or 690 ng/J of useful 

output (5.5 lb/MWh).

New turbine firing natural gas > 50 MMBtu/h 

and ≤ 850 

MMBtu/h

25 ppm at 15 percent 

O2or 150 ng/J of useful 

output (1.2 lb/MWh).

New, modified, or reconstructed turbine firing 

natural gas

> 850 MMBtu/h 15 ppm at 15 percent 

O2or 54 ng/J of useful 

output (0.43 lb/MWh)

New turbine firing fuels other than natural gas, 

electric generating

≤ 50 MMBtu/h 96 ppm at 15 percent 

O2or 700 ng/J of useful 

output (5.5 lb/MWh).

New turbine firing fuels other than natural gas, 

mechanical drive

≤ 50 MMBtu/h 150 ppm at 15 percent 

O2or 1,100 ng/J of 

useful output (8.7 

lb/MWh).

New turbine firing fuels other than natural gas > 50 MMBtu/h 

and ≤ 850 

MMBtu/h

74 ppm at 15 percent 

O2or 460 ng/J of useful 

output (3.6 lb/MWh).

New, modified, or reconstructed turbine firing fuels 

other than natural gas

> 850 MMBtu/h 42 ppm at 15 percent 

O2or 160 ng/J of useful 

output (1.3 lb/MWh).

Modified or reconstructed turbine ≤ 50 MMBtu/h 150 ppm at 15 percent 

O2or 1,100 ng/J of 

useful output (8.7 

lb/MWh).

Modified or reconstructed turbine firing natural gas > 50 MMBtu/h 

and ≤ 850 

MMBtu/h

42 ppm at 15 percent 

O2or 250 ng/J of useful 

output (2.0 lb/MWh).

Modified or reconstructed turbine firing fuels other 

than natural gas

> 50 MMBtu/h 

and ≤ 850 

96 ppm at 15 percent 

O2or 590 ng/J of useful 
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MMBtu/h output (4.7 lb/MWh).

Turbines located north of the Arctic Circle (latitude 

66.5 degrees north), turbines operating at less than 

75 percent of peak load, modified and reconstructed 

offshore turbines, and turbine operating at 

temperatures less than 0 °F

≤ 30 MW output 150 ppm at 15 percent 

O2or 1,100 ng/J of 

useful output (8.7 

lb/MWh).

Turbines located north of the Arctic Circle (latitude 

66.5 degrees north), turbines operating at less than 

75 percent of peak load, modified and reconstructed 

offshore turbines, and turbine operating at 

temperatures less than 0 °F

> 30 MW output 96 ppm at 15 percent 

O2or 590 ng/J of useful 

output (4.7 lb/MWh).

Heat recovery units operating independent of the 

combustion turbine

All sizes 54 ppm at 15 percent 

O2or 110 ng/J of useful 

output (0.86 lb/MWh).
Attachment D to a PSD/Part 70 Operating Permit

40 CFR 63, Subpart ZZZZ—National Emission Standards for 

Hazardous Air Pollutants for Stationary Reciprocating Internal 

Combustion Engines:

Source Name: St. Joseph Energy Center, LLC

Source Location: Corner of Walnut and Edison Roads, 

New Carlisle, Indiana 46552

County: St. Joseph

SIC Code: 4911

Operation Permit No.: T 141-31003-00579

Operation Permit Issuance Date: Yet to be issued

Permit Reviewer: Josiah Balogun

Subpart ZZZZ—National Emissions Standards for Hazardous Air Pollutants 

for Stationary Reciprocating Internal Combustion Engines

Source: 69 FR 33506, June 15, 2004, unless otherwise noted.

What This Subpart Covers

§ 63.6580 What is the purpose of subpart ZZZZ?

Subpart ZZZZ establishes national emission limitations and operating limitations for hazardous air pollutants (HAP) 

emitted from stationary reciprocating internal combustion engines (RICE) located at major and area sources of HAP 

emissions. This subpart also establishes requirements to demonstrate initial and continuous compliance with the 

emission limitations and operating limitations.

[73 FR 3603, Jan. 18, 2008]

§ 63.6585 Am I subject to this subpart?

You are subject to this subpart if you own or operate a stationary RICE at a major or area source of HAP emissions, 

except if the stationary RICE is being tested at a stationary RICE test cell/stand.

(a) A stationary RICE is any internal combustion engine which uses reciprocating motion to convert heat energy into 

mechanical work and which is not mobile. Stationary RICE differ from mobile RICE in that a stationary RICE is not a 

non-road engine as defined at 40 CFR 1068.30, and is not used to propel a motor vehicle or a vehicle used solely for 

competition.

(b) A major source of HAP emissions is a plant site that emits or has the potential to emit any single HAP at a rate of 

10 tons (9.07 megagrams) or more per year or any combination of HAP at a rate of 25 tons (22.68 megagrams) or 

more per year, except that for oil and gas production facilities, a major source of HAP emissions is determined for 

each surface site.

(c) An area source of HAP emissions is a source that is not a major source.

(d) If you are an owner or operator of an area source subject to this subpart, your status as an entity subject to a 

standard or other requirements under this subpart does not subject you to the obligation to obtain a permit under 40 

CFR part 70 or 71, provided you are not required to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a) for a 
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reason other than your status as an area source under this subpart. Notwithstanding the previous sentence, you must 

continue to comply with the provisions of this subpart as applicable.

(e) If you are an owner or operator of a stationary RICE used for national security purposes, you may be eligible to 

request an exemption from the requirements of this subpart as described in 40 CFR part 1068, subpart C.

[69 FR 33506, June 15, 2004, as amended at 73 FR 3603, Jan. 18, 2008]

§ 63.6590 What parts of my plant does this subpart cover?

This subpart applies to each affected source.

(a) Affected source. An affected source is any existing, new, or reconstructed stationary RICE located at a major or 

area source of HAP emissions, excluding stationary RICE being tested at a stationary RICE test cell/stand.

(1) Existing stationary RICE. 

(i) For stationary RICE with a site rating of more than 500 brake horsepower (HP) located at a major source of HAP 

emissions, a stationary RICE is existing if you commenced construction or reconstruction of the stationary RICE 

before December 19, 2002.

(ii) For stationary RICE with a site rating of less than or equal to 500 brake HP located at a major source of HAP 

emissions, a stationary RICE is existing if you commenced construction or reconstruction of the stationary RICE 

before June 12, 2006.

(iii) For stationary RICE located at an area source of HAP emissions, a stationary RICE is existing if you commenced 

construction or reconstruction of the stationary RICE before June 12, 2006.

(iv) A change in ownership of an existing stationary RICE does not make that stationary RICE a new or reconstructed 

stationary RICE.

(2) New stationary RICE. (i) A stationary RICE with a site rating of more than 500 brake HP located at a major source 

of HAP emissions is new if you commenced construction of the stationary RICE on or after December 19, 2002.

(ii) A stationary RICE with a site rating of equal to or less than 500 brake HP located at a major source of HAP 

emissions is new if you commenced construction of the stationary RICE on or after June 12, 2006.

(iii) A stationary RICE located at an area source of HAP emissions is new if you commenced construction of the 

stationary RICE on or after June 12, 2006.

(3) Reconstructed stationary RICE. (i) A stationary RICE with a site rating of more than 500 brake HP located at a 

major source of HAP emissions is reconstructed if you meet the definition of reconstruction in §63.2 and 

reconstruction is commenced on or after December 19, 2002.

(ii) A stationary RICE with a site rating of equal to or less than 500 brake HP located at a major source of HAP 

emissions is reconstructed if you meet the definition of reconstruction in §63.2 and reconstruction is commenced on 

or after June 12, 2006.

(iii) A stationary RICE located at an area source of HAP emissions is reconstructed if you meet the definition of 

reconstruction in §63.2 and reconstruction is commenced on or after June 12, 2006.

(b) Stationary RICE subject to limited requirements. (1) An affected source which meets either of the criteria in 

paragraphs (b)(1)(i) through (ii) of this section does not have to meet the requirements of this subpart and of subpart 

A of this part except for the initial notification requirements of §63.6645(f).
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(i) The stationary RICE is a new or reconstructed emergency stationary RICE with a site rating of more than 500 

brake HP located at a major source of HAP emissions.

(ii) The stationary RICE is a new or reconstructed limited use stationary RICE with a site rating of more than 500 

brake HP located at a major source of HAP emissions.

(2) A new or reconstructed stationary RICE with a site rating of more than 500 brake HP located at a major source of 

HAP emissions which combusts landfill or digester gas equivalent to 10 percent or more of the gross heat input on an 

annual basis must meet the initial notification requirements of §63.6645(f) and the requirements of §§63.6625(c), 

63.6650(g), and 63.6655(c). These stationary RICE do not have to meet the emission limitations and operating 

limitations of this subpart.

(3) The following stationary RICE do not have to meet the requirements of this subpart and of subpart A of this part, 

including initial notification requirements:

(i) Existing spark ignition 2 stroke lean burn (2SLB) stationary RICE with a site rating of more than 500 brake HP 

located at a major source of HAP emissions;

(ii) Existing spark ignition 4 stroke lean burn (4SLB) stationary RICE with a site rating of more than 500 brake HP 

located at a major source of HAP emissions;

(iii) Existing emergency stationary RICE with a site rating of more than 500 brake HP located at a major source of 

HAP emissions;

(iv) Existing limited use stationary RICE with a site rating of more than 500 brake HP located at a major source of 

HAP emissions;

(v) Existing stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions 

that combusts landfill gas or digester gas equivalent to 10 percent or more of the gross heat input on an annual basis;

(vi) Existing residential emergency stationary RICE located at an area source of HAP emissions;

(vii) Existing commercial emergency stationary RICE located at an area source of HAP emissions; or

(viii) Existing institutional emergency stationary RICE located at an area source of HAP emissions.

(c) Stationary RICE subject to Regulations under 40 CFR Part 60. An affected source that meets any of the criteria in 

paragraphs (c)(1) through (7) of this section must meet the requirements of this part by meeting the requirements of 

40 CFR part 60 subpart IIII, for compression ignition engines or 40 CFR part 60 subpart JJJJ, for spark ignition 

engines. No further requirements apply for such engines under this part.

(1) A new or reconstructed stationary RICE located at an area source;

(2) A new or reconstructed 2SLB stationary RICE with a site rating of less than or equal to 500 brake HP located at a 

major source of HAP emissions;

(3) A new or reconstructed 4SLB stationary RICE with a site rating of less than 250 brake HP located at a major 

source of HAP emissions;

(4) A new or reconstructed spark ignition 4 stroke rich burn (4SRB) stationary RICE with a site rating of less than or 

equal to 500 brake HP located at a major source of HAP emissions;

(5) A new or reconstructed stationary RICE with a site rating of less than or equal to 500 brake HP located at a major 

source of HAP emissions which combusts landfill or digester gas equivalent to 10 percent or more of the gross heat 

input on an annual basis;
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(6) A new or reconstructed emergency or limited use stationary RICE with a site rating of less than or equal to 500 

brake HP located at a major source of HAP emissions;

(7) A new or reconstructed compression ignition (CI) stationary RICE with a site rating of less than or equal to 500 

brake HP located at a major source of HAP emissions.

[69 FR 33506, June 15, 2004, as amended at 73 FR 3604, Jan. 18, 2008; 75 FR 9674, Mar. 3, 2010; 75 FR 37733, 

June 30, 2010; 75 FR 51588, Aug. 20, 2010]

§ 63.6595 When do I have to comply with this subpart?

(a) Affected sources. (1) If you have an existing stationary RICE, excluding existing non-emergency CI stationary 

RICE, with a site rating of more than 500 brake HP located at a major source of HAP emissions, you must comply 

with the applicable emission limitations and operating limitations no later than June 15, 2007. If you have an existing 

non-emergency CI stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP 

emissions, an existing stationary CI RICE with a site rating of less than or equal to 500 brake HP located at a major 

source of HAP emissions, or an existing stationary CI RICE located at an area source of HAP emissions, you must 

comply with the applicable emission limitations and operating limitations no later than May 3, 2013. If you have an 

existing stationary SI RICE with a site rating of less than or equal to 500 brake HP located at a major source of HAP 

emissions, or an existing stationary SI RICE located at an area source of HAP emissions, you must comply with the 

applicable emission limitations and operating limitations no later than October 19, 2013.

(2) If you start up your new or reconstructed stationary RICE with a site rating of more than 500 brake HP located at a 

major source of HAP emissions before August 16, 2004, you must comply with the applicable emission limitations 

and operating limitations in this subpart no later than August 16, 2004.

(3) If you start up your new or reconstructed stationary RICE with a site rating of more than 500 brake HP located at a 

major source of HAP emissions after August 16, 2004, you must comply with the applicable emission limitations and 

operating limitations in this subpart upon startup of your affected source.

(4) If you start up your new or reconstructed stationary RICE with a site rating of less than or equal to 500 brake HP 

located at a major source of HAP emissions before January 18, 2008, you must comply with the applicable emission 

limitations and operating limitations in this subpart no later than January 18, 2008.

(5) If you start up your new or reconstructed stationary RICE with a site rating of less than or equal to 500 brake HP 

located at a major source of HAP emissions after January 18, 2008, you must comply with the applicable emission 

limitations and operating limitations in this subpart upon startup of your affected source.

(6) If you start up your new or reconstructed stationary RICE located at an area source of HAP emissions before 

January 18, 2008, you must comply with the applicable emission limitations and operating limitations in this subpart 

no later than January 18, 2008.

(7) If you start up your new or reconstructed stationary RICE located at an area source of HAP emissions after 

January 18, 2008, you must comply with the applicable emission limitations and operating limitations in this subpart 

upon startup of your affected source.

(b) Area sources that become major sources. If you have an area source that increases its emissions or its potential 

to emit such that it becomes a major source of HAP, the compliance dates in paragraphs (b)(1) and (2) of this section 

apply to you.

(1) Any stationary RICE for which construction or reconstruction is commenced after the date when your area source 

becomes a major source of HAP must be in compliance with this subpart upon startup of your affected source.

(2) Any stationary RICE for which construction or reconstruction is commenced before your area source becomes a 

major source of HAP must be in compliance with the provisions of this subpart that are applicable to RICE located at 

major sources within 3 years after your area source becomes a major source of HAP.
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(c) If you own or operate an affected source, you must meet the applicable notification requirements in §63.6645 and 

in 40 CFR part 63, subpart A.

[69 FR 33506, June 15, 2004, as amended at 73 FR 3604, Jan. 18, 2008; 75 FR 9675, Mar. 3, 2010; 75 FR 51589, 

Aug. 20, 2010]

Emission and Operating Limitations

§ 63.6600 What emission limitations and operating limitations must I meet 

if I own or operate a stationary RICE with a site rating of more than 500 

brake HP located at a major source of HAP emissions?

Compliance with the numerical emission limitations established in this subpart is based on the results of testing the 

average of three 1-hour runs using the testing requirements and procedures in §63.6620 and Table 4 to this subpart.

(a) If you own or operate an existing, new, or reconstructed spark ignition 4SRB stationary RICE with a site rating of 

more than 500 brake HP located at a major source of HAP emissions, you must comply with the emission limitations 

in Table 1a to this subpart and the operating limitations in Table 1b to this subpart which apply to you.

(b) If you own or operate a new or reconstructed 2SLB stationary RICE with a site rating of more than 500 brake HP 

located at major source of HAP emissions, a new or reconstructed 4SLB stationary RICE with a site rating of more 

than 500 brake HP located at major source of HAP emissions, or a new or reconstructed CI stationary RICE with a 

site rating of more than 500 brake HP located at a major source of HAP emissions, you must comply with the 

emission limitations in Table 2a to this subpart and the operating limitations in Table 2b to this subpart which apply to 

you.

(c) If you own or operate any of the following stationary RICE with a site rating of more than 500 brake HP located at 

a major source of HAP emissions, you do not need to comply with the emission limitations in Tables 1a, 2a, 2c, and 

2d to this subpart or operating limitations in Tables 1b and 2b to this subpart: an existing 2SLB stationary RICE; an 

existing 4SLB stationary RICE; a stationary RICE that combusts landfill gas or digester gas equivalent to 10 percent 

or more of the gross heat input on an annual basis; an emergency stationary RICE; or a limited use stationary RICE.

(d) If you own or operate an existing non-emergency stationary CI RICE with a site rating of more than 500 brake HP 

located at a major source of HAP emissions, you must comply with the emission limitations in Table 2c to this subpart

and the operating limitations in Table 2b to this subpart which apply to you.

[73 FR 3605, Jan. 18, 2008, as amended at 75 FR 9675, Mar. 3, 2010]

§ 63.6601 What emission limitations must I meet if I own or operate a new 

or reconstructed 4SLB stationary RICE with a site rating of greater than or 

equal to 250 brake HP and less than or equal to 500 brake HP located at a 

major source of HAP emissions?

Compliance with the numerical emission limitations established in this subpart is based on the results of testing the 

average of three 1-hour runs using the testing requirements and procedures in §63.6620 and Table 4 to this subpart. 

If you own or operate a new or reconstructed 4SLB stationary RICE with a site rating of greater than or equal to 250 

and less than or equal to 500 brake HP located at major source of HAP emissions manufactured on or after January 

1, 2008, you must comply with the emission limitations in Table 2a to this subpart and the operating limitations in 

Table 2b to this subpart which apply to you.

[73 FR 3605, Jan. 18, 2008, as amended at 75 FR 9675, Mar. 3, 2010; 75 FR 51589, Aug. 20, 2010]

§ 63.6602 What emission limitations must I meet if I own or operate an 
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existing stationary RICE with a site rating of equal to or less than 500 brake 

HP located at a major source of HAP emissions?

If you own or operate an existing stationary RICE with a site rating of equal to or less than 500 brake HP located at a 

major source of HAP emissions, you must comply with the emission limitations in Table 2c to this subpart which apply 

to you. Compliance with the numerical emission limitations established in this subpart is based on the results of 

testing the average of three 1-hour runs using the testing requirements and procedures in §63.6620 and Table 4 to 

this subpart.

[75 FR 51589, Aug. 20, 2010]

§ 63.6603 What emission limitations and operating limitations must I meet 

if I own or operate an existing stationary RICE located at an area source of 

HAP emissions?

Compliance with the numerical emission limitations established in this subpart is based on the results of testing the 

average of three 1-hour runs using the testing requirements and procedures in §63.6620 and Table 4 to this subpart.

(a) If you own or operate an existing stationary RICE located at an area source of HAP emissions, you must comply 

with the requirements in Table 2d to this subpart and the operating limitations in Table 1b and Table 2b to this 

subpart that apply to you.

(b) If you own or operate an existing stationary non-emergency CI RICE greater than 300 HP located at area sources 

in areas of Alaska not accessible by the Federal Aid Highway System (FAHS) you do not have to meet the numerical 

CO emission limitations specified in Table 2d to this subpart. Existing stationary non-emergency CI RICE greater than 

300 HP located at area sources in areas of Alaska not accessible by the FAHS must meet the management practices 

that are shown for stationary non-emergency CI RICE less than or equal to 300 HP in Table 2d to this subpart.

[75 FR 9675, Mar. 3, 2010, as amended at 75 FR 51589, Aug. 20, 2010; 76 FR 12866, Mar. 9, 2011]

§ 63.6604 What fuel requirements must I meet if I own or operate an 

existing stationary CI RICE?

If you own or operate an existing non-emergency, non-black start CI stationary RICE with a site rating of more than 

300 brake HP with a displacement of less than 30 liters per cylinder that uses diesel fuel, you must use diesel fuel 

that meets the requirements in 40 CFR 80.510(b) for nonroad diesel fuel. Existing non-emergency CI stationary RICE 

located in Guam, American Samoa, the Commonwealth of the Northern Mariana Islands, or at area sources in areas 

of Alaska not accessible by the FAHS are exempt from the requirements of this section.

[75 FR 51589, Aug. 20, 2010]

General Compliance Requirements

§ 63.6605 What are my general requirements for complying with this 

subpart?

(a) You must be in compliance with the emission limitations and operating limitations in this subpart that apply to you 

at all times.

(b) At all times you must operate and maintain any affected source, including associated air pollution control 

equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices for 

minimizing emissions. The general duty to minimize emissions does not require you to make any further efforts to 

reduce emissions if levels required by this standard have been achieved. Determination of whether such operation 
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and maintenance procedures are being used will be based on information available to the Administrator which may 

include, but is not limited to, monitoring results, review of operation and maintenance procedures, review of operation 

and maintenance records, and inspection of the source.

[75 FR 9675, Mar. 3, 2010]

Testing and Initial Compliance Requirements

§ 63.6610 By what date must I conduct the initial performance tests or 

other initial compliance demonstrations if I own or operate a stationary 

RICE with a site rating of more than 500 brake HP located at a major source 

of HAP emissions?

If you own or operate a stationary RICE with a site rating of more than 500 brake HP located at a major source of 

HAP emissions you are subject to the requirements of this section.

(a) You must conduct the initial performance test or other initial compliance demonstrations in Table 4 to this subpart 

that apply to you within 180 days after the compliance date that is specified for your stationary RICE in §63.6595 and 

according to the provisions in §63.7(a)(2).

(b) If you commenced construction or reconstruction between December 19, 2002 and June 15, 2004 and own or 

operate stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions, 

you must demonstrate initial compliance with either the proposed emission limitations or the promulgated emission 

limitations no later than February 10, 2005 or no later than 180 days after startup of the source, whichever is later, 

according to §63.7(a)(2)(ix).

(c) If you commenced construction or reconstruction between December 19, 2002 and June 15, 2004 and own or 

operate stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions, 

and you chose to comply with the proposed emission limitations when demonstrating initial compliance, you must 

conduct a second performance test to demonstrate compliance with the promulgated emission limitations by 

December 13, 2007 or after startup of the source, whichever is later, according to §63.7(a)(2)(ix).

(d) An owner or operator is not required to conduct an initial performance test on units for which a performance test 

has been previously conducted, but the test must meet all of the conditions described in paragraphs (d)(1) through (5) 

of this section.

(1) The test must have been conducted using the same methods specified in this subpart, and these methods must 

have been followed correctly.

(2) The test must not be older than 2 years.

(3) The test must be reviewed and accepted by the Administrator.

(4) Either no process or equipment changes must have been made since the test was performed, or the owner or 

operator must be able to demonstrate that the results of the performance test, with or without adjustments, reliably 

demonstrate compliance despite process or equipment changes.

(5) The test must be conducted at any load condition within plus or minus 10 percent of 100 percent load.

[69 FR 33506, June 15, 2004, as amended at 73 FR 3605, Jan. 18, 2008]

§ 63.6611 By what date must I conduct the initial performance tests or 

other initial compliance demonstrations if I own or operate a new or 
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reconstructed 4SLB SI stationary RICE with a site rating of greater than or 

equal to 250 and less than or equal to 500 brake HP located at a major 

source of HAP emissions?

If you own or operate a new or reconstructed 4SLB stationary RICE with a site rating of greater than or equal to 250 

and less than or equal to 500 brake HP located at a major source of HAP emissions, you must conduct an initial 

performance test within 240 days after the compliance date that is specified for your stationary RICE in §63.6595 and 

according to the provisions specified in Table 4 to this subpart, as appropriate.

[73 FR 3605, Jan. 18, 2008, as amended at 75 FR 51589, Aug. 20, 2010]

§ 63.6612 By what date must I conduct the initial performance tests or 

other initial compliance demonstrations if I own or operate an existing 

stationary RICE with a site rating of less than or equal to 500 brake HP 

located at a major source of HAP emissions or an existing stationary RICE 

located at an area source of HAP emissions?

If you own or operate an existing stationary RICE with a site rating of less than or equal to 500 brake HP located at a 

major source of HAP emissions or an existing stationary RICE located at an area source of HAP emissions you are 

subject to the requirements of this section.

(a) You must conduct any initial performance test or other initial compliance demonstration according to Tables 4 and 

5 to this subpart that apply to you within 180 days after the compliance date that is specified for your stationary RICE 

in §63.6595 and according to the provisions in §63.7(a)(2).

(b) An owner or operator is not required to conduct an initial performance test on a unit for which a performance test 

has been previously conducted, but the test must meet all of the conditions described in paragraphs (b)(1) through (4) 

of this section.

(1) The test must have been conducted using the same methods specified in this subpart, and these methods must 

have been followed correctly.

(2) The test must not be older than 2 years.

(3) The test must be reviewed and accepted by the Administrator.

(4) Either no process or equipment changes must have been made since the test was performed, or the owner or 

operator must be able to demonstrate that the results of the performance test, with or without adjustments, reliably 

demonstrate compliance despite process or equipment changes.

[75 FR 9676, Mar. 3, 2010, as amended at 75 FR 51589, Aug. 20, 2010]

§ 63.6615 When must I conduct subsequent performance tests?

If you must comply with the emission limitations and operating limitations, you must conduct subsequent performance 

tests as specified in Table 3 of this subpart.

§ 63.6620 What performance tests and other procedures must I use?

(a) You must conduct each performance test in Tables 3 and 4 of this subpart that applies to you.
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(b) Each performance test must be conducted according to the requirements that this subpart specifies in Table 4 to 

this subpart. If you own or operate a non-operational stationary RICE that is subject to performance testing, you do 

not need to start up the engine solely to conduct the performance test. Owners and operators of a non-operational 

engine can conduct the performance test when the engine is started up again.

(c) [Reserved]

(d) You must conduct three separate test runs for each performance test required in this section, as specified in 

§63.7(e)(3). Each test run must last at least 1 hour.

(e)(1) You must use Equation 1 of this section to determine compliance with the percent reduction requirement:

Where:

Ci= concentration of CO or formaldehyde at the control device inlet,

Co= concentration of CO or formaldehyde at the control device outlet, and

R = percent reduction of CO or formaldehyde emissions.

(2) You must normalize the carbon monoxide (CO) or formaldehyde concentrations at the inlet and outlet of the 

control device to a dry basis and to 15 percent oxygen, or an equivalent percent carbon dioxide (CO2). If pollutant 

concentrations are to be corrected to 15 percent oxygen and CO2concentration is measured in lieu of oxygen 

concentration measurement, a CO2correction factor is needed. Calculate the CO2correction factor as described in 

paragraphs (e)(2)(i) through (iii) of this section.

(i) Calculate the fuel-specific Fovalue for the fuel burned during the test using values obtained from Method 19, 

section 5.2, and the following equation:

Where:

Fo= Fuel factor based on the ratio of oxygen volume to the ultimate CO2volume produced by the fuel at 

zero percent excess air.

0.209 = Fraction of air that is oxygen, percent/100.

Fd= Ratio of the volume of dry effluent gas to the gross calorific value of the fuel from Method 19, dsm3 /J 

(dscf/106 Btu).

Fc= Ratio of the volume of CO2produced to the gross calorific value of the fuel from Method 19, dsm3 /J 

(dscf/106 Btu).

(ii) Calculate the CO2correction factor for correcting measurement data to 15 percent oxygen, as follows:
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Where:

Xco2= CO2correction factor, percent.

5.9 = 20.9 percent O2−15 percent O2, the defined O2correction value, percent.

(iii) Calculate the NOXand SO2gas concentrations adjusted to 15 percent O2using CO2as follows:

Where:

%CO2= Measured CO2concentration measured, dry basis, percent.

(f) If you comply with the emission limitation to reduce CO and you are not using an oxidation catalyst, if you comply 

with the emission limitation to reduce formaldehyde and you are not using NSCR, or if you comply with the emission 

limitation to limit the concentration of formaldehyde in the stationary RICE exhaust and you are not using an oxidation 

catalyst or NSCR, you must petition the Administrator for operating limitations to be established during the initial 

performance test and continuously monitored thereafter; or for approval of no operating limitations. You must not 

conduct the initial performance test until after the petition has been approved by the Administrator.

(g) If you petition the Administrator for approval of operating limitations, your petition must include the information 

described in paragraphs (g)(1) through (5) of this section.

(1) Identification of the specific parameters you propose to use as operating limitations;

(2) A discussion of the relationship between these parameters and HAP emissions, identifying how HAP emissions 

change with changes in these parameters, and how limitations on these parameters will serve to limit HAP emissions;

(3) A discussion of how you will establish the upper and/or lower values for these parameters which will establish the 

limits on these parameters in the operating limitations;

(4) A discussion identifying the methods you will use to measure and the instruments you will use to monitor these 

parameters, as well as the relative accuracy and precision of these methods and instruments; and

(5) A discussion identifying the frequency and methods for recalibrating the instruments you will use for monitoring 

these parameters.

(h) If you petition the Administrator for approval of no operating limitations, your petition must include the information 

described in paragraphs (h)(1) through (7) of this section.

(1) Identification of the parameters associated with operation of the stationary RICE and any emission control device 

which could change intentionally ( e.g., operator adjustment, automatic controller adjustment, etc.) or unintentionally ( 

e.g., wear and tear, error, etc.) on a routine basis or over time;

(2) A discussion of the relationship, if any, between changes in the parameters and changes in HAP emissions;
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(3) For the parameters which could change in such a way as to increase HAP emissions, a discussion of whether 

establishing limitations on the parameters would serve to limit HAP emissions;

(4) For the parameters which could change in such a way as to increase HAP emissions, a discussion of how you 

could establish upper and/or lower values for the parameters which would establish limits on the parameters in 

operating limitations;

(5) For the parameters, a discussion identifying the methods you could use to measure them and the instruments you 

could use to monitor them, as well as the relative accuracy and precision of the methods and instruments;

(6) For the parameters, a discussion identifying the frequency and methods for recalibrating the instruments you 

could use to monitor them; and

(7) A discussion of why, from your point of view, it is infeasible or unreasonable to adopt the parameters as operating 

limitations.

(i) The engine percent load during a performance test must be determined by documenting the calculations, 

assumptions, and measurement devices used to measure or estimate the percent load in a specific application. A 

written report of the average percent load determination must be included in the notification of compliance status. The 

following information must be included in the written report: the engine model number, the engine manufacturer, the 

year of purchase, the manufacturer's site-rated brake horsepower, the ambient temperature, pressure, and humidity 

during the performance test, and all assumptions that were made to estimate or calculate percent load during the 

performance test must be clearly explained. If measurement devices such as flow meters, kilowatt meters, beta 

analyzers, stain gauges, etc. are used, the model number of the measurement device, and an estimate of its accurate 

in percentage of true value must be provided.

[69 FR 33506, June 15, 2004, as amended at 75 FR 9676, Mar. 3, 2010]

§ 63.6625 What are my monitoring, installation, collection, operation, and 

maintenance requirements?

(a) If you elect to install a CEMS as specified in Table 5 of this subpart, you must install, operate, and maintain a 

CEMS to monitor CO and either oxygen or CO2at both the inlet and the outlet of the control device according to the 

requirements in paragraphs (a)(1) through (4) of this section.

(1) Each CEMS must be installed, operated, and maintained according to the applicable performance specifications 

of 40 CFR part 60, appendix B.

(2) You must conduct an initial performance evaluation and an annual relative accuracy test audit (RATA) of each 

CEMS according to the requirements in §63.8 and according to the applicable performance specifications of 40 CFR 

part 60, appendix B as well as daily and periodic data quality checks in accordance with 40 CFR part 60, appendix F, 

procedure 1.

(3) As specified in §63.8(c)(4)(ii), each CEMS must complete a minimum of one cycle of operation (sampling, 

analyzing, and data recording) for each successive 15-minute period. You must have at least two data points, with 

each representing a different 15-minute period, to have a valid hour of data.

(4) The CEMS data must be reduced as specified in §63.8(g)(2) and recorded in parts per million or parts per billion 

(as appropriate for the applicable limitation) at 15 percent oxygen or the equivalent CO2concentration.

(b) If you are required to install a continuous parameter monitoring system (CPMS) as specified in Table 5 of this 

subpart, you must install, operate, and maintain each CPMS according to the requirements in paragraphs (b)(1) 

through (5) of this section. For an affected source that is complying with the emission limitations and operating 

limitations on March 9, 2011, the requirements in paragraph (b) of this section are applicable September 6, 2011.
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(1) You must prepare a site-specific monitoring plan that addresses the monitoring system design, data collection, 

and the quality assurance and quality control elements outlined in paragraphs (b)(1)(i) through (v) of this section and 

in §63.8(d). As specified in §63.8(f)(4), you may request approval of monitoring system quality assurance and quality 

control procedures alternative to those specified in paragraphs (b)(1) through (5) of this section in your site-specific 

monitoring plan.

(i) The performance criteria and design specifications for the monitoring system equipment, including the sample 

interface, detector signal analyzer, and data acquisition and calculations;

(ii) Sampling interface ( e.g., thermocouple) location such that the monitoring system will provide representative 

measurements;

(iii) Equipment performance evaluations, system accuracy audits, or other audit procedures;

(iv) Ongoing operation and maintenance procedures in accordance with provisions in §63.8(c)(1) and (c)(3); and

(v) Ongoing reporting and recordkeeping procedures in accordance with provisions in §63.10(c), (e)(1), and (e)(2)(i).

(2) You must install, operate, and maintain each CPMS in continuous operation according to the procedures in your 

site-specific monitoring plan.

(3) The CPMS must collect data at least once every 15 minutes (see also §63.6635).

(4) For a CPMS for measuring temperature range, the temperature sensor must have a minimum tolerance of 2.8 

degrees Celsius (5 degrees Fahrenheit) or 1 percent of the measurement range, whichever is larger.

(5) You must conduct the CPMS equipment performance evaluation, system accuracy audits, or other audit 

procedures specified in your site-specific monitoring plan at least annually.

(6) You must conduct a performance evaluation of each CPMS in accordance with your site-specific monitoring plan.

(c) If you are operating a new or reconstructed stationary RICE which fires landfill gas or digester gas equivalent to 

10 percent or more of the gross heat input on an annual basis, you must monitor and record your fuel usage daily 

with separate fuel meters to measure the volumetric flow rate of each fuel. In addition, you must operate your 

stationary RICE in a manner which reasonably minimizes HAP emissions.

(d) If you are operating a new or reconstructed emergency 4SLB stationary RICE with a site rating of greater than or 

equal to 250 and less than or equal to 500 brake HP located at a major source of HAP emissions, you must install a 

non-resettable hour meter prior to the startup of the engine.

(e) If you own or operate any of the following stationary RICE, you must operate and maintain the stationary RICE 

and after-treatment control device (if any) according to the manufacturer's emission-related written instructions or 

develop your own maintenance plan which must provide to the extent practicable for the maintenance and operation 

of the engine in a manner consistent with good air pollution control practice for minimizing emissions:

(1) An existing stationary RICE with a site rating of less than 100 HP located at a major source of HAP emissions;

(2) An existing emergency or black start stationary RICE with a site rating of less than or equal to 500 HP located at a 

major source of HAP emissions;

(3) An existing emergency or black start stationary RICE located at an area source of HAP emissions;

(4) An existing non-emergency, non-black start stationary CI RICE with a site rating less than or equal to 300 HP 

located at an area source of HAP emissions;

(5) An existing non-emergency, non-black start 2SLB stationary RICE located at an area source of HAP emissions;
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(6) An existing non-emergency, non-black start landfill or digester gas stationary RICE located at an area source of 

HAP emissions;

(7) An existing non-emergency, non-black start 4SLB stationary RICE with a site rating less than or equal to 500 HP 

located at an area source of HAP emissions;

(8) An existing non-emergency, non-black start 4SRB stationary RICE with a site rating less than or equal to 500 HP 

located at an area source of HAP emissions;

(9) An existing, non-emergency, non-black start 4SLB stationary RICE with a site rating greater than 500 HP located 

at an area source of HAP emissions that is operated 24 hours or less per calendar year; and

(10) An existing, non-emergency, non-black start 4SRB stationary RICE with a site rating greater than 500 HP 

located at an area source of HAP emissions that is operated 24 hours or less per calendar year.

(f) If you own or operate an existing emergency stationary RICE with a site rating of less than or equal to 500 brake 

HP located at a major source of HAP emissions or an existing emergency stationary RICE located at an area source 

of HAP emissions, you must install a non-resettable hour meter if one is not already installed.

(g) If you own or operate an existing non-emergency, non-black start CI engine greater than or equal to 300 HP that 

is not equipped with a closed crankcase ventilation system, you must comply with either paragraph (g)(1) or 

paragraph (g)(2) of this section. Owners and operators must follow the manufacturer's specified maintenance 

requirements for operating and maintaining the open or closed crankcase ventilation systems and replacing the 

crankcase filters, or can request the Administrator to approve different maintenance requirements that are as 

protective as manufacturer requirements. Existing CI engines located at area sources in areas of Alaska not 

accessible by the FAHS do not have to meet the requirements of paragraph (g) of this section.

(1) Install a closed crankcase ventilation system that prevents crankcase emissions from being emitted to the 

atmosphere, or

(2) Install an open crankcase filtration emission control system that reduces emissions from the crankcase by filtering 

the exhaust stream to remove oil mist, particulates, and metals.

(h) If you operate a new, reconstructed, or existing stationary engine, you must minimize the engine's time spent at 

idle during startup and minimize the engine's startup time to a period needed for appropriate and safe loading of the

engine, not to exceed 30 minutes, after which time the emission standards applicable to all times other than startup in 

Tables 1a, 2a, 2c, and 2d to this subpart apply.

(i) If you own or operate a stationary CI engine that is subject to the work, operation or management practices in 

items 1 or 2 of Table 2c to this subpart or in items 1 or 4 of Table 2d to this subpart, you have the option of utilizing an 

oil analysis program in order to extend the specified oil change requirement in Tables 2c and 2d to this subpart. The 

oil analysis must be performed at the same frequency specified for changing the oil in Table 2c or 2d to this subpart. 

The analysis program must at a minimum analyze the following three parameters: Total Base Number, viscosity, and 

percent water content. The condemning limits for these parameters are as follows: Total Base Number is less than 30 

percent of the Total Base Number of the oil when new; viscosity of the oil has changed by more than 20 percent from 

the viscosity of the oil when new; or percent water content (by volume) is greater than 0.5. If all of these condemning 

limits are not exceeded, the engine owner or operator is not required to change the oil. If any of the limits are 

exceeded, the engine owner or operator must change the oil within 2 days of receiving the results of the analysis; if 

the engine is not in operation when the results of the analysis are received, the engine owner or operator must 

change the oil within 2 days or before commencing operation, whichever is later. The owner or operator must keep 

records of the parameters that are analyzed as part of the program, the results of the analysis, and the oil changes 

for the engine. The analysis program must be part of the maintenance plan for the engine.

(j) If you own or operate a stationary SI engine that is subject to the work, operation or management practices in 

items 6, 7, or 8 of Table 2c to this subpart or in items 5, 6, 7, 9, or 11 of Table 2d to this subpart, you have the option 

of utilizing an oil analysis program in order to extend the specified oil change requirement in Tables 2c and 2d to this 

subpart. The oil analysis must be performed at the same frequency specified for changing the oil in Table 2c or 2d to 

this subpart. The analysis program must at a minimum analyze the following three parameters: Total Acid Number, 
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viscosity, and percent water content. The condemning limits for these parameters are as follows: Total Acid Number 

increases by more than 3.0 milligrams of potassium hydroxide (KOH) per gram from Total Acid Number of the oil 

when new; viscosity of the oil has changed by more than 20 percent from the viscosity of the oil when new; or percent 

water content (by volume) is greater than 0.5. If all of these condemning limits are not exceeded, the engine owner or 

operator is not required to change the oil. If any of the limits are exceeded, the engine owner or operator must 

change the oil within 2 days of receiving the results of the analysis; if the engine is not in operation when the results 

of the analysis are received, the engine owner or operator must change the oil within 2 days or before commencing 

operation, whichever is later. The owner or operator must keep records of the parameters that are analyzed as part of 

the program, the results of the analysis, and the oil changes for the engine. The analysis program must be part of the 

maintenance plan for the engine.

[69 FR 33506, June 15, 2004, as amended at 73 FR 3606, Jan. 18, 2008; 75 FR 9676, Mar. 3, 2010; 75 FR 51589, 

Aug. 20, 2010; 76 FR 12866, Mar. 9, 2011]

§ 63.6630 How do I demonstrate initial compliance with the emission 

limitations and operating limitations?

(a) You must demonstrate initial compliance with each emission and operating limitation that applies to you according 

to Table 5 of this subpart.

(b) During the initial performance test, you must establish each operating limitation in Tables 1b and 2b of this 

subpart that applies to you.

(c) You must submit the Notification of Compliance Status containing the results of the initial compliance 

demonstration according to the requirements in §63.6645.

Continuous Compliance Requirements

§ 63.6635 How do I monitor and collect data to demonstrate continuous 

compliance?

(a) If you must comply with emission and operating limitations, you must monitor and collect data according to this 

section.

(b) Except for monitor malfunctions, associated repairs, required performance evaluations, and required quality 

assurance or control activities, you must monitor continuously at all times that the stationary RICE is operating. A 

monitoring malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring to provide valid 

data. Monitoring failures that are caused in part by poor maintenance or careless operation are not malfunctions.

(c) You may not use data recorded during monitoring malfunctions, associated repairs, and required quality 

assurance or control activities in data averages and calculations used to report emission or operating levels. You 

must, however, use all the valid data collected during all other periods.

[69 FR 33506, June 15, 2004, as amended at 76 FR 12867, Mar. 9, 2011]

§ 63.6640 How do I demonstrate continuous compliance with the emission 

limitations and operating limitations?

(a) You must demonstrate continuous compliance with each emission limitation and operating limitation in Tables 1a 

and 1b, Tables 2a and 2b, Table 2c, and Table 2d to this subpart that apply to you according to methods specified in 

Table 6 to this subpart.

(b) You must report each instance in which you did not meet each emission limitation or operating limitation in Tables 

1a and 1b, Tables 2a and 2b, Table 2c, and Table 2d to this subpart that apply to you. These instances are 
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deviations from the emission and operating limitations in this subpart. These deviations must be reported according to 

the requirements in §63.6650. If you change your catalyst, you must reestablish the values of the operating 

parameters measured during the initial performance test. When you reestablish the values of your operating 

parameters, you must also conduct a performance test to demonstrate that you are meeting the required emission 

limitation applicable to your stationary RICE.

(c) [Reserved]

(d) For new, reconstructed, and rebuilt stationary RICE, deviations from the emission or operating limitations that 

occur during the first 200 hours of operation from engine startup (engine burn-in period) are not violations. Rebuilt 

stationary RICE means a stationary RICE that has been rebuilt as that term is defined in 40 CFR 94.11(a).

(e) You must also report each instance in which you did not meet the requirements in Table 8 to this subpart that 

apply to you. If you own or operate a new or reconstructed stationary RICE with a site rating of less than or equal to 

500 brake HP located at a major source of HAP emissions (except new or reconstructed 4SLB engines greater than 

or equal to 250 and less than or equal to 500 brake HP), a new or reconstructed stationary RICE located at an area 

source of HAP emissions, or any of the following RICE with a site rating of more than 500 brake HP located at a 

major source of HAP emissions, you do not need to comply with the requirements in Table 8 to this subpart: An 

existing 2SLB stationary RICE, an existing 4SLB stationary RICE, an existing emergency stationary RICE, an existing 

limited use stationary RICE, or an existing stationary RICE which fires landfill gas or digester gas equivalent to 10 

percent or more of the gross heat input on an annual basis. If you own or operate any of the following RICE with a 

site rating of more than 500 brake HP located at a major source of HAP emissions, you do not need to comply with 

the requirements in Table 8 to this subpart, except for the initial notification requirements: a new or reconstructed 

stationary RICE that combusts landfill gas or digester gas equivalent to 10 percent or more of the gross heat input on 

an annual basis, a new or reconstructed emergency stationary RICE, or a new or reconstructed limited use stationary 

RICE.

(f) Requirements for emergency stationary RICE. (1) If you own or operate an existing emergency stationary RICE 

with a site rating of less than or equal to 500 brake HP located at a major source of HAP emissions, a new or 

reconstructed emergency stationary RICE with a site rating of more than 500 brake HP located at a major source of 

HAP emissions that was installed on or after June 12, 2006, or an existing emergency stationary RICE located at an 

area source of HAP emissions, you must operate the emergency stationary RICE according to the requirements in 

paragraphs (f)(1)(i) through (iii) of this section. Any operation other than emergency operation, maintenance and 

testing, and operation in non-emergency situations for 50 hours per year, as described in paragraphs (f)(1)(i) through 

(iii) of this section, is prohibited. If you do not operate the engine according to the requirements in paragraphs (f)(1)(i) 

through (iii) of this section, the engine will not be considered an emergency engine under this subpart and will need to

meet all requirements for non-emergency engines.

(i) There is no time limit on the use of emergency stationary RICE in emergency situations.

(ii) You may operate your emergency stationary RICE for the purpose of maintenance checks and readiness testing, 

provided that the tests are recommended by Federal, State or local government, the manufacturer, the vendor, or the 

insurance company associated with the engine. Maintenance checks and readiness testing of such units is limited to 

100 hours per year. The owner or operator may petition the Administrator for approval of additional hours to be used 

for maintenance checks and readiness testing, but a petition is not required if the owner or operator maintains 

records indicating that Federal, State, or local standards require maintenance and testing of emergency RICE beyond 

100 hours per year.

(iii) You may operate your emergency stationary RICE up to 50 hours per year in non-emergency situations, but 

those 50 hours are counted towards the 100 hours per year provided for maintenance and testing. The 50 hours per 

year for non-emergency situations cannot be used for peak shaving or to generate income for a facility to supply 

power to an electric grid or otherwise supply power as part of a financial arrangement with another entity; except that 

owners and operators may operate the emergency engine for a maximum of 15 hours per year as part of a demand 

response program if the regional transmission organization or equivalent balancing authority and transmission 

operator has determined there are emergency conditions that could lead to a potential electrical blackout, such as 

unusually low frequency, equipment overload, capacity or energy deficiency, or unacceptable voltage level. The 

engine may not be operated for more than 30 minutes prior to the time when the emergency condition is expected to 

occur, and the engine operation must be terminated immediately after the facility is notified that the emergency 

condition is no longer imminent. The 15 hours per year of demand response operation are counted as part of the 50 

hours of operation per year provided for non-emergency situations. The supply of emergency power to another entity 
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or entities pursuant to financial arrangement is not limited by this paragraph (f)(1)(iii), as long as the power provided 

by the financial arrangement is limited to emergency power.

(2) If you own or operate an emergency stationary RICE with a site rating of more than 500 brake HP located at a 

major source of HAP emissions that was installed prior to June 12, 2006, you must operate the engine according to 

the conditions described in paragraphs (f)(2)(i) through (iii) of this section. If you do not operate the engine according 

to the requirements in paragraphs (f)(2)(i) through (iii) of this section, the engine will not be considered an emergency 

engine under this subpart and will need to meet all requirements for non-emergency engines.

(i) There is no time limit on the use of emergency stationary RICE in emergency situations.

(ii) You may operate your emergency stationary RICE for the purpose of maintenance checks and readiness testing, 

provided that the tests are recommended by the manufacturer, the vendor, or the insurance company associated with 

the engine. Required testing of such units should be minimized, but there is no time limit on the use of emergency 

stationary RICE in emergency situations and for routine testing and maintenance.

(iii) You may operate your emergency stationary RICE for an additional 50 hours per year in non-emergency 

situations. The 50 hours per year for non-emergency situations cannot be used for peak shaving or to generate 

income for a facility to supply power to an electric grid or otherwise supply power as part of a financial arrangement 

with another entity.

[69 FR 33506, June 15, 2004, as amended at 71 FR 20467, Apr. 20, 2006; 73 FR 3606, Jan. 18, 2008; 75 FR 9676, 

Mar. 3, 2010; 75 FR 51591, Aug. 20, 2010]

Notifications, Reports, and Records

§ 63.6645 What notifications must I submit and when?

(a) You must submit all of the notifications in §§63.7(b) and (c), 63.8(e), (f)(4) and (f)(6), 63.9(b) through (e), and (g) 

and (h) that apply to you by the dates specified if you own or operate any of the following;

(1) An existing stationary RICE with a site rating of less than or equal to 500 brake HP located at a major source of 

HAP emissions.

(2) An existing stationary RICE located at an area source of HAP emissions.

(3) A stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions.

(4) A new or reconstructed 4SLB stationary RICE with a site rating of greater than or equal to 250 HP located at a 

major source of HAP emissions.

(5) This requirement does not apply if you own or operate an existing stationary RICE less than 100 HP, an existing 

stationary emergency RICE, or an existing stationary RICE that is not subject to any numerical emission standards.

(b) As specified in §63.9(b)(2), if you start up your stationary RICE with a site rating of more than 500 brake HP 

located at a major source of HAP emissions before the effective date of this subpart, you must submit an Initial 

Notification not later than December 13, 2004.

(c) If you start up your new or reconstructed stationary RICE with a site rating of more than 500 brake HP located at a

major source of HAP emissions on or after August 16, 2004, you must submit an Initial Notification not later than 120 

days after you become subject to this subpart.

(d) As specified in §63.9(b)(2), if you start up your stationary RICE with a site rating of equal to or less than 500 brake 

HP located at a major source of HAP emissions before the effective date of this subpart and you are required to 

submit an initial notification, you must submit an Initial Notification not later than July 16, 2008.
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(e) If you start up your new or reconstructed stationary RICE with a site rating of equal to or less than 500 brake HP 

located at a major source of HAP emissions on or after March 18, 2008 and you are required to submit an initial 

notification, you must submit an Initial Notification not later than 120 days after you become subject to this subpart.

(f) If you are required to submit an Initial Notification but are otherwise not affected by the requirements of this 

subpart, in accordance with §63.6590(b), your notification should include the information in §63.9(b)(2)(i) through (v), 

and a statement that your stationary RICE has no additional requirements and explain the basis of the exclusion (for 

example, that it operates exclusively as an emergency stationary RICE if it has a site rating of more than 500 brake 

HP located at a major source of HAP emissions).

(g) If you are required to conduct a performance test, you must submit a Notification of Intent to conduct a 

performance test at least 60 days before the performance test is scheduled to begin as required in §63.7(b)(1).

(h) If you are required to conduct a performance test or other initial compliance demonstration as specified in Tables 

4 and 5 to this subpart, you must submit a Notification of Compliance Status according to §63.9(h)(2)(ii).

(1) For each initial compliance demonstration required in Table 5 to this subpart that does not include a performance 

test, you must submit the Notification of Compliance Status before the close of business on the 30th day following the 

completion of the initial compliance demonstration.

(2) For each initial compliance demonstration required in Table 5 to this subpart that includes a performance test 

conducted according to the requirements in Table 3 to this subpart, you must submit the Notification of Compliance 

Status, including the performance test results, before the close of business on the 60th day following the completion 

of the performance test according to §63.10(d)(2).

[73 FR 3606, Jan. 18, 2008, as amended at 75 FR 9677, Mar. 3, 2010; 75 FR 51591, Aug. 20, 2010]

§ 63.6650 What reports must I submit and when?

(a) You must submit each report in Table 7 of this subpart that applies to you.

(b) Unless the Administrator has approved a different schedule for submission of reports under §63.10(a), you must 

submit each report by the date in Table 7 of this subpart and according to the requirements in paragraphs (b)(1) 

through (b)(9) of this section.

(1) For semiannual Compliance reports, the first Compliance report must cover the period beginning on the 

compliance date that is specified for your affected source in §63.6595 and ending on June 30 or December 31, 

whichever date is the first date following the end of the first calendar half after the compliance date that is specified 

for your source in §63.6595.

(2) For semiannual Compliance reports, the first Compliance report must be postmarked or delivered no later than 

July 31 or January 31, whichever date follows the end of the first calendar half after the compliance date that is 

specified for your affected source in §63.6595.

(3) For semiannual Compliance reports, each subsequent Compliance report must cover the semiannual reporting 

period from January 1 through June 30 or the semiannual reporting period from July 1 through December 31.

(4) For semiannual Compliance reports, each subsequent Compliance report must be postmarked or delivered no 

later than July 31 or January 31, whichever date is the first date following the end of the semiannual reporting period.

(5) For each stationary RICE that is subject to permitting regulations pursuant to 40 CFR part 70 or 71, and if the 

permitting authority has established dates for submitting semiannual reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 

40 CFR 71.6 (a)(3)(iii)(A), you may submit the first and subsequent Compliance reports according to the dates the 

permitting authority has established instead of according to the dates in paragraphs (b)(1) through (b)(4) of this 

section.
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(6) For annual Compliance reports, the first Compliance report must cover the period beginning on the compliance 

date that is specified for your affected source in §63.6595 and ending on December 31.

(7) For annual Compliance reports, the first Compliance report must be postmarked or delivered no later than 

January 31 following the end of the first calendar year after the compliance date that is specified for your affected 

source in §63.6595.

(8) For annual Compliance reports, each subsequent Compliance report must cover the annual reporting period from 

January 1 through December 31.

(9) For annual Compliance reports, each subsequent Compliance report must be postmarked or delivered no later 

than January 31.

(c) The Compliance report must contain the information in paragraphs (c)(1) through (6) of this section.

(1) Company name and address.

(2) Statement by a responsible official, with that official's name, title, and signature, certifying the accuracy of the 

content of the report.

(3) Date of report and beginning and ending dates of the reporting period.

(4) If you had a malfunction during the reporting period, the compliance report must include the number, duration, and 

a brief description for each type of malfunction which occurred during the reporting period and which caused or may 

have caused any applicable emission limitation to be exceeded. The report must also include a description of actions 

taken by an owner or operator during a malfunction of an affected source to minimize emissions in accordance with 

§63.6605(b), including actions taken to correct a malfunction.

(5) If there are no deviations from any emission or operating limitations that apply to you, a statement that there were 

no deviations from the emission or operating limitations during the reporting period.

(6) If there were no periods during which the continuous monitoring system (CMS), including CEMS and CPMS, was 

out-of-control, as specified in §63.8(c)(7), a statement that there were no periods during which the CMS was out-ofcontrol during the reporting period.

(d) For each deviation from an emission or operating limitation that occurs for a stationary RICE where you are not 

using a CMS to comply with the emission or operating limitations in this subpart, the Compliance report must contain 

the information in paragraphs (c)(1) through (4) of this section and the information in paragraphs (d)(1) and (2) of this 

section.

(1) The total operating time of the stationary RICE at which the deviation occurred during the reporting period.

(2) Information on the number, duration, and cause of deviations (including unknown cause, if applicable), as 

applicable, and the corrective action taken.

(e) For each deviation from an emission or operating limitation occurring for a stationary RICE where you are using a 

CMS to comply with the emission and operating limitations in this subpart, you must include information in 

paragraphs (c)(1) through (4) and (e)(1) through (12) of this section.

(1) The date and time that each malfunction started and stopped.

(2) The date, time, and duration that each CMS was inoperative, except for zero (low-level) and high-level checks.

(3) The date, time, and duration that each CMS was out-of-control, including the information in §63.8(c)(8).
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(4) The date and time that each deviation started and stopped, and whether each deviation occurred during a period 

of malfunction or during another period.

(5) A summary of the total duration of the deviation during the reporting period, and the total duration as a percent of 

the total source operating time during that reporting period.

(6) A breakdown of the total duration of the deviations during the reporting period into those that are due to control 

equipment problems, process problems, other known causes, and other unknown causes.

(7) A summary of the total duration of CMS downtime during the reporting period, and the total duration of CMS 

downtime as a percent of the total operating time of the stationary RICE at which the CMS downtime occurred during 

that reporting period.

(8) An identification of each parameter and pollutant (CO or formaldehyde) that was monitored at the stationary RICE.

(9) A brief description of the stationary RICE.

(10) A brief description of the CMS.

(11) The date of the latest CMS certification or audit.

(12) A description of any changes in CMS, processes, or controls since the last reporting period.

(f) Each affected source that has obtained a title V operating permit pursuant to 40 CFR part 70 or 71 must report all 

deviations as defined in this subpart in the semiannual monitoring report required by 40 CFR 70.6 (a)(3)(iii)(A) or 40 

CFR 71.6(a)(3)(iii)(A). If an affected source submits a Compliance report pursuant to Table 7 of this subpart along 

with, or as part of, the semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A), 

and the Compliance report includes all required information concerning deviations from any emission or operating 

limitation in this subpart, submission of the Compliance report shall be deemed to satisfy any obligation to report the 

same deviations in the semiannual monitoring report. However, submission of a Compliance report shall not 

otherwise affect any obligation the affected source may have to report deviations from permit requirements to the 

permit authority.

(g) If you are operating as a new or reconstructed stationary RICE which fires landfill gas or digester gas equivalent 

to 10 percent or more of the gross heat input on an annual basis, you must submit an annual report according to 

Table 7 of this subpart by the date specified unless the Administrator has approved a different schedule, according to 

the information described in paragraphs (b)(1) through (b)(5) of this section. You must report the data specified in 

(g)(1) through (g)(3) of this section.

(1) Fuel flow rate of each fuel and the heating values that were used in your calculations. You must also demonstrate 

that the percentage of heat input provided by landfill gas or digester gas is equivalent to 10 percent or more of the 

total fuel consumption on an annual basis.

(2) The operating limits provided in your federally enforceable permit, and any deviations from these limits.

(3) Any problems or errors suspected with the meters.

[69 FR 33506, June 15, 2004, as amended at 75 FR 9677, Mar. 3, 2010]

§ 63.6655 What records must I keep?

(a) If you must comply with the emission and operating limitations, you must keep the records described in 

paragraphs (a)(1) through (a)(5), (b)(1) through (b)(3) and (c) of this section.
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(1) A copy of each notification and report that you submitted to comply with this subpart, including all documentation 

supporting any Initial Notification or Notification of Compliance Status that you submitted, according to the 

requirement in §63.10(b)(2)(xiv).

(2) Records of the occurrence and duration of each malfunction of operation ( i.e., process equipment) or the air 

pollution control and monitoring equipment.

(3) Records of performance tests and performance evaluations as required in §63.10(b)(2)(viii).

(4) Records of all required maintenance performed on the air pollution control and monitoring equipment.

(5) Records of actions taken during periods of malfunction to minimize emissions in accordance with §63.6605(b), 

including corrective actions to restore malfunctioning process and air pollution control and monitoring equipment to its 

normal or usual manner of operation.

(b) For each CEMS or CPMS, you must keep the records listed in paragraphs (b)(1) through (3) of this section.

(1) Records described in §63.10(b)(2)(vi) through (xi).

(2) Previous ( i.e., superseded) versions of the performance evaluation plan as required in §63.8(d)(3).

(3) Requests for alternatives to the relative accuracy test for CEMS or CPMS as required in §63.8(f)(6)(i), if 

applicable.

(c) If you are operating a new or reconstructed stationary RICE which fires landfill gas or digester gas equivalent to 

10 percent or more of the gross heat input on an annual basis, you must keep the records of your daily fuel usage 

monitors.

(d) You must keep the records required in Table 6 of this subpart to show continuous compliance with each emission 

or operating limitation that applies to you.

(e) You must keep records of the maintenance conducted on the stationary RICE in order to demonstrate that you 

operated and maintained the stationary RICE and after-treatment control device (if any) according to your own 

maintenance plan if you own or operate any of the following stationary RICE;

(1) An existing stationary RICE with a site rating of less than 100 brake HP located at a major source of HAP 

emissions.

(2) An existing stationary emergency RICE.

(3) An existing stationary RICE located at an area source of HAP emissions subject to management practices as 

shown in Table 2d to this subpart.

(f) If you own or operate any of the stationary RICE in paragraphs (f)(1) or (2) of this section, you must keep records 

of the hours of operation of the engine that is recorded through the non-resettable hour meter. The owner or operator 

must document how many hours are spent for emergency operation, including what classified the operation as 

emergency and how many hours are spent for non-emergency operation. If the engines are used for demand 

response operation, the owner or operator must keep records of the notification of the emergency situation, and the 

time the engine was operated as part of demand response.

(1) An existing emergency stationary RICE with a site rating of less than or equal to 500 brake HP located at a major 

source of HAP emissions that does not meet the standards applicable to non-emergency engines.

(2) An existing emergency stationary RICE located at an area source of HAP emissions that does not meet the 

standards applicable to non-emergency engines.
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[69 FR 33506, June 15, 2004, as amended at 75 FR 9678, Mar. 3, 2010; 75 FR 51592, Aug. 20, 2010]

§ 63.6660 In what form and how long must I keep my records?

(a) Your records must be in a form suitable and readily available for expeditious review according to §63.10(b)(1).

(b) As specified in §63.10(b)(1), you must keep each record for 5 years following the date of each occurrence, 

measurement, maintenance, corrective action, report, or record.

(c) You must keep each record readily accessible in hard copy or electronic form for at least 5 years after the date of 

each occurrence, measurement, maintenance, corrective action, report, or record, according to §63.10(b)(1).

[69 FR 33506, June 15, 2004, as amended at 75 FR 9678, Mar. 3, 2010]

Other Requirements and Information

§ 63.6665 What parts of the General Provisions apply to me?

Table 8 to this subpart shows which parts of the General Provisions in §§63.1 through 63.15 apply to you. If you own 

or operate a new or reconstructed stationary RICE with a site rating of less than or equal to 500 brake HP located at 

a major source of HAP emissions (except new or reconstructed 4SLB engines greater than or equal to 250 and less 

than or equal to 500 brake HP), a new or reconstructed stationary RICE located at an area source of HAP emissions, 

or any of the following RICE with a site rating of more than 500 brake HP located at a major source of HAP 

emissions, you do not need to comply with any of the requirements of the General Provisions specified in Table 8: An 

existing 2SLB stationary RICE, an existing 4SLB stationary RICE, an existing stationary RICE that combusts landfill 

or digester gas equivalent to 10 percent or more of the gross heat input on an annual basis, an existing emergency 

stationary RICE, or an existing limited use stationary RICE. If you own or operate any of the following RICE with a 

site rating of more than 500 brake HP located at a major source of HAP emissions, you do not need to comply with 

the requirements in the General Provisions specified in Table 8 except for the initial notification requirements: A new 

stationary RICE that combusts landfill gas or digester gas equivalent to 10 percent or more of the gross heat input on 

an annual basis, a new emergency stationary RICE, or a new limited use stationary RICE.

[75 FR 9678, Mar. 3, 2010]

§ 63.6670 Who implements and enforces this subpart?

(a) This subpart is implemented and enforced by the U.S. EPA, or a delegated authority such as your State, local, or 

tribal agency. If the U.S. EPA Administrator has delegated authority to your State, local, or tribal agency, then that 

agency (as well as the U.S. EPA) has the authority to implement and enforce this subpart. You should contact your 

U.S. EPA Regional Office to find out whether this subpart is delegated to your State, local, or tribal agency.

(b) In delegating implementation and enforcement authority of this subpart to a State, local, or tribal agency under 40 

CFR part 63, subpart E, the authorities contained in paragraph (c) of this section are retained by the Administrator of 

the U.S. EPA and are not transferred to the State, local, or tribal agency.

(c) The authorities that will not be delegated to State, local, or tribal agencies are:

(1) Approval of alternatives to the non-opacity emission limitations and operating limitations in §63.6600 under 

§63.6(g).

(2) Approval of major alternatives to test methods under §63.7(e)(2)(ii) and (f) and as defined in §63.90.

(3) Approval of major alternatives to monitoring under §63.8(f) and as defined in §63.90.

(4) Approval of major alternatives to recordkeeping and reporting under §63.10(f) and as defined in §63.90.
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(5) Approval of a performance test which was conducted prior to the effective date of the rule, as specified in 

§63.6610(b).

§ 63.6675 What definitions apply to this subpart?

Terms used in this subpart are defined in the Clean Air Act (CAA); in 40 CFR 63.2, the General Provisions of this 

part; and in this section as follows:

Area source means any stationary source of HAP that is not a major source as defined in part 63.

Associated equipment as used in this subpart and as referred to in section 112(n)(4) of the CAA, means equipment 

associated with an oil or natural gas exploration or production well, and includes all equipment from the well bore to 

the point of custody transfer, except glycol dehydration units, storage vessels with potential for flash emissions, 

combustion turbines, and stationary RICE.

Black start engine means an engine whose only purpose is to start up a combustion turbine.

CAA means the Clean Air Act (42 U.S.C. 7401 et seq., as amended by Public Law 101–549, 104 Stat. 2399).

Commercial emergency stationary RICE means an emergency stationary RICE used in commercial establishments 

such as office buildings, hotels, stores, telecommunications facilities, restaurants, financial institutions such as banks, 

doctor's offices, and sports and performing arts facilities.

Compression ignition means relating to a type of stationary internal combustion engine that is not a spark ignition 

engine.

Custody transfer means the transfer of hydrocarbon liquids or natural gas: After processing and/or treatment in the 

producing operations, or from storage vessels or automatic transfer facilities or other such equipment, including 

product loading racks, to pipelines or any other forms of transportation. For the purposes of this subpart, the point at 

which such liquids or natural gas enters a natural gas processing plant is a point of custody transfer.

Deviation means any instance in which an affected source subject to this subpart, or an owner or operator of such a 

source:

(1) Fails to meet any requirement or obligation established by this subpart, including but not limited to any emission 

limitation or operating limitation;

(2) Fails to meet any term or condition that is adopted to implement an applicable requirement in this subpart and that 

is included in the operating permit for any affected source required to obtain such a permit; or

(3) Fails to meet any emission limitation or operating limitation in this subpart during malfunction, regardless or 

whether or not such failure is permitted by this subpart.

(4) Fails to satisfy the general duty to minimize emissions established by §63.6(e)(1)(i).

Diesel engine means any stationary RICE in which a high boiling point liquid fuel injected into the combustion 

chamber ignites when the air charge has been compressed to a temperature sufficiently high for auto-ignition. This 

process is also known as compression ignition.

Diesel fuel means any liquid obtained from the distillation of petroleum with a boiling point of approximately 150 to 

360 degrees Celsius. One commonly used form is fuel oil number 2. Diesel fuel also includes any non-distillate fuel 

with comparable physical and chemical properties ( e.g. biodiesel) that is suitable for use in compression ignition 

engines.

Digester gas means any gaseous by-product of wastewater treatment typically formed through the anaerobic 

decomposition of organic waste materials and composed principally of methane and CO2.
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Dual-fuel engine means any stationary RICE in which a liquid fuel (typically diesel fuel) is used for compression 

ignition and gaseous fuel (typically natural gas) is used as the primary fuel.

Emergency stationary RICE means any stationary internal combustion engine whose operation is limited to 

emergency situations and required testing and maintenance. Examples include stationary RICE used to produce 

power for critical networks or equipment (including power supplied to portions of a facility) when electric power from 

the local utility (or the normal power source, if the facility runs on its own power production) is interrupted, or 

stationary RICE used to pump water in the case of fire or flood, etc. Stationary RICE used for peak shaving are not 

considered emergency stationary RICE. Stationary RICE used to supply power to an electric grid or that supply nonemergency power as part of a financial arrangement with another entity are not considered to be emergency engines, 

except as permitted under §63.6640(f). All emergency stationary RICE must comply with the requirements specified 

in §63.6640(f) in order to be considered emergency stationary RICE. If the engine does not comply with the 

requirements specified in §63.6640(f), then it is not considered to be an emergency stationary RICE under this 

subpart.

Engine startup means the time from initial start until applied load and engine and associated equipment reaches 

steady state or normal operation. For stationary engine with catalytic controls, engine startup means the time from 

initial start until applied load and engine and associated equipment, including the catalyst, reaches steady state or 

normal operation.

Four-stroke engine means any type of engine which completes the power cycle in two crankshaft revolutions, with 

intake and compression strokes in the first revolution and power and exhaust strokes in the second revolution.

Gaseous fuel means a material used for combustion which is in the gaseous state at standard atmospheric 

temperature and pressure conditions.

Gasoline means any fuel sold in any State for use in motor vehicles and motor vehicle engines, or nonroad or 

stationary engines, and commonly or commercially known or sold as gasoline.

Glycol dehydration unit means a device in which a liquid glycol (including, but not limited to, ethylene glycol, 

diethylene glycol, or triethylene glycol) absorbent directly contacts a natural gas stream and absorbs water in a 

contact tower or absorption column (absorber). The glycol contacts and absorbs water vapor and other gas stream 

constituents from the natural gas and becomes “rich” glycol. This glycol is then regenerated in the glycol dehydration 

unit reboiler. The “lean” glycol is then recycled.

Hazardous air pollutants (HAP) means any air pollutants listed in or pursuant to section 112(b) of the CAA.

Institutional emergency stationary RICE means an emergency stationary RICE used in institutional establishments 

such as medical centers, nursing homes, research centers, institutions of higher education, correctional facilities, 

elementary and secondary schools, libraries, religious establishments, police stations, and fire stations.

ISO standard day conditions means 288 degrees Kelvin (15 degrees Celsius), 60 percent relative humidity and 101.3 

kilopascals pressure.

Landfill gas means a gaseous by-product of the land application of municipal refuse typically formed through the 

anaerobic decomposition of waste materials and composed principally of methane and CO2.

Lean burn engine means any two-stroke or four-stroke spark ignited engine that does not meet the definition of a rich 

burn engine.

Limited use stationary RICE means any stationary RICE that operates less than 100 hours per year.

Liquefied petroleum gas means any liquefied hydrocarbon gas obtained as a by-product in petroleum refining of 

natural gas production.

Liquid fuel means any fuel in liquid form at standard temperature and pressure, including but not limited to diesel, 

residual/crude oil, kerosene/naphtha (jet fuel), and gasoline.
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Major Source, as used in this subpart, shall have the same meaning as in §63.2, except that:

(1) Emissions from any oil or gas exploration or production well (with its associated equipment (as defined in this 

section)) and emissions from any pipeline compressor station or pump station shall not be aggregated with emissions 

from other similar units, to determine whether such emission points or stations are major sources, even when 

emission points are in a contiguous area or under common control;

(2) For oil and gas production facilities, emissions from processes, operations, or equipment that are not part of the 

same oil and gas production facility, as defined in §63.1271 of subpart HHH of this part, shall not be aggregated;

(3) For production field facilities, only HAP emissions from glycol dehydration units, storage vessel with the potential 

for flash emissions, combustion turbines and reciprocating internal combustion engines shall be aggregated for a 

major source determination; and

(4) Emissions from processes, operations, and equipment that are not part of the same natural gas transmission and 

storage facility, as defined in §63.1271 of subpart HHH of this part, shall not be aggregated.

Malfunction means any sudden, infrequent, and not reasonably preventable failure of air pollution control equipment, 

process equipment, or a process to operate in a normal or usual manner which causes, or has the potential to cause, 

the emission limitations in an applicable standard to be exceeded. Failures that are caused in part by poor 

maintenance or careless operation are not malfunctions.

Natural gas means a naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in geologic 

formations beneath the Earth's surface, of which the principal constituent is methane. Natural gas may be field or 

pipeline quality.

Non-selective catalytic reduction (NSCR) means an add-on catalytic nitrogen oxides (NOX) control device for rich 

burn engines that, in a two-step reaction, promotes the conversion of excess oxygen, NOX, CO, and volatile organic 

compounds (VOC) into CO2, nitrogen, and water.

Oil and gas production facility as used in this subpart means any grouping of equipment where hydrocarbon liquids 

are processed, upgraded ( i.e., remove impurities or other constituents to meet contract specifications), or stored prior 

to the point of custody transfer; or where natural gas is processed, upgraded, or stored prior to entering the natural 

gas transmission and storage source category. For purposes of a major source determination, facility (including a 

building, structure, or installation) means oil and natural gas production and processing equipment that is located 

within the boundaries of an individual surface site as defined in this section. Equipment that is part of a facility will 

typically be located within close proximity to other equipment located at the same facility. Pieces of production 

equipment or groupings of equipment located on different oil and gas leases, mineral fee tracts, lease tracts, 

subsurface or surface unit areas, surface fee tracts, surface lease tracts, or separate surface sites, whether or not 

connected by a road, waterway, power line or pipeline, shall not be considered part of the same facility. Examples of 

facilities in the oil and natural gas production source category include, but are not limited to, well sites, satellite tank 

batteries, central tank batteries, a compressor station that transports natural gas to a natural gas processing plant, 

and natural gas processing plants.

Oxidation catalyst means an add-on catalytic control device that controls CO and VOC by oxidation.

Peaking unit or engine means any standby engine intended for use during periods of high demand that are not 

emergencies.

Percent load means the fractional power of an engine compared to its maximum manufacturer's design capacity at 

engine site conditions. Percent load may range between 0 percent to above 100 percent.

Potential to emit means the maximum capacity of a stationary source to emit a pollutant under its physical and 

operational design. Any physical or operational limitation on the capacity of the stationary source to emit a pollutant, 

including air pollution control equipment and restrictions on hours of operation or on the type or amount of material 

combusted, stored, or processed, shall be treated as part of its design if the limitation or the effect it would have on 

emissions is federally enforceable. For oil and natural gas production facilities subject to subpart HH of this part, the 

potential to emit provisions in §63.760(a) may be used. For natural gas transmission and storage facilities subject to 
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subpart HHH of this part, the maximum annual facility gas throughput for storage facilities may be determined 

according to §63.1270(a)(1) and the maximum annual throughput for transmission facilities may be determined 

according to §63.1270(a)(2).

Production field facility means those oil and gas production facilities located prior to the point of custody transfer.

Production well means any hole drilled in the earth from which crude oil, condensate, or field natural gas is extracted.

Propane means a colorless gas derived from petroleum and natural gas, with the molecular structure C3H8.

Residential emergency stationary RICE means an emergency stationary RICE used in residential establishments 

such as homes or apartment buildings.

Responsible official means responsible official as defined in 40 CFR 70.2.

Rich burn engine means any four-stroke spark ignited engine where the manufacturer's recommended operating 

air/fuel ratio divided by the stoichiometric air/fuel ratio at full load conditions is less than or equal to 1.1. Engines 

originally manufactured as rich burn engines, but modified prior to December 19, 2002 with passive emission control 

technology for NOX(such as pre-combustion chambers) will be considered lean burn engines. Also, existing engines 

where there are no manufacturer's recommendations regarding air/fuel ratio will be considered a rich burn engine if 

the excess oxygen content of the exhaust at full load conditions is less than or equal to 2 percent.

Site-rated HP means the maximum manufacturer's design capacity at engine site conditions.

Spark ignition means relating to either: A gasoline-fueled engine; or any other type of engine with a spark plug (or 

other sparking device) and with operating characteristics significantly similar to the theoretical Otto combustion cycle. 

Spark ignition engines usually use a throttle to regulate intake air flow to control power during normal operation. Dualfuel engines in which a liquid fuel (typically diesel fuel) is used for CI and gaseous fuel (typically natural gas) is used 

as the primary fuel at an annual average ratio of less than 2 parts diesel fuel to 100 parts total fuel on an energy 

equivalent basis are spark ignition engines.

Stationary reciprocating internal combustion engine (RICE) means any reciprocating internal combustion engine 

which uses reciprocating motion to convert heat energy into mechanical work and which is not mobile. Stationary 

RICE differ from mobile RICE in that a stationary RICE is not a non-road engine as defined at 40 CFR 1068.30, and 

is not used to propel a motor vehicle or a vehicle used solely for competition.

Stationary RICE test cell/stand means an engine test cell/stand, as defined in subpart PPPPP of this part, that tests 

stationary RICE.

Stoichiometric means the theoretical air-to-fuel ratio required for complete combustion.

Storage vessel with the potential for flash emissions means any storage vessel that contains a hydrocarbon liquid 

with a stock tank gas-to-oil ratio equal to or greater than 0.31 cubic meters per liter and an American Petroleum 

Institute gravity equal to or greater than 40 degrees and an actual annual average hydrocarbon liquid throughput 

equal to or greater than 79,500 liters per day. Flash emissions occur when dissolved hydrocarbons in the fluid evolve 

from solution when the fluid pressure is reduced.

Subpart means 40 CFR part 63, subpart ZZZZ.

Surface site means any combination of one or more graded pad sites, gravel pad sites, foundations, platforms, or the 

immediate physical location upon which equipment is physically affixed.

Two-stroke engine means a type of engine which completes the power cycle in single crankshaft revolution by 

combining the intake and compression operations into one stroke and the power and exhaust operations into a 

second stroke. This system requires auxiliary scavenging and inherently runs lean of stoichiometric.
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[69 FR 33506, June 15, 2004, as amended at 71 FR 20467, Apr. 20, 2006; 73 FR 3607, Jan. 18, 2008; 75 FR 9679, 

Mar. 3, 2010; 75 FR 51592, Aug. 20, 2010; 76 FR 12867, Mar. 9, 2011]

Table 1ato Subpart ZZZZ of Part 63—Emission Limitations for Existing, 

New, and Reconstructed Spark Ignition, 4SRB Stationary RICE >500 HP 

Located at a Major Source of HAP Emissions

As stated in §§63.6600 and 63.6640, you must comply with the following emission limitations at 100 percent load plus 

or minus 10 percent for existing, new and reconstructed 4SRB stationary RICE >500 HP located at a major source of 

HAP emissions:

For each . 

. .

You must meet the following emission 

limitation, except during periods of 

startup . . .

During periods of startup you must . . 

.

1. 4SRB 

stationary 

RICE

a. Reduce formaldehyde emissions by 76 

percent or more. If you commenced 

construction or reconstruction between 

December 19, 2002 and June 15, 2004, you 

may reduce formaldehyde emissions by 75 

percent or more until June 15, 2007 or

Minimize the engine's time spent at idle 

and minimize the engine's startup time at 

startup to a period needed for 

appropriate and safe loading of the 

engine, not to exceed 30 minutes, after 

which time the non-startup emission 

limitations apply.1

 b. Limit the concentration of formaldehyde 

in the stationary RICE exhaust to 350 

ppbvd or less at 15 percent O2

1

Sources can petition the Administrator pursuant to the requirements of 40 CFR 63.6(g) for alternative work practices.

[75 FR 9679, Mar. 3, 2010, as amended at 75 FR 51592, Aug. 20, 2010]

Table 1bto Subpart ZZZZ of Part 63—Operating Limitations for Existing, 

New, and Reconstructed Spark Ignition 4SRB Stationary RICE >500 HP 

Located at a Major Source of HAP Emissions and Existing Spark Ignition 

4SRB Stationary RICE >500 HP Located at an Area Source of HAP 

Emissions

As stated in §§63.6600, 63.6603, 63.6630 and 63.6640, you must comply with the following operating limitations for 

existing, new and reconstructed 4SRB stationary RICE >500 HP located at a major source of HAP emissions and 

existing 4SRB stationary RICE >500 HP located at an area source of HAP emissions that operate more than 24 

hours per calendar year:

For each . . .

You must meet the following operating limitation . 

. .

1. 4SRB stationary RICE complying with 

the requirement to reduce formaldehyde 

emissions by 76 percent or more (or by 75 

percent or more, if applicable) and using 

a. Maintain your catalyst so that the pressure drop 

across the catalyst does not change by more than 2 

inches of water at 100 percent load plus or minus 10 

percent from the pressure drop across the catalyst 
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NSCR; or

4SRB stationary RICE complying with the 

requirement to limit the concentration of 

formaldehyde in the stationary RICE 

exhaust to 350 ppbvd or less at 15 percent 

O2 and using NSCR; or

4SRB stationary RICE complying with the 

requirement to limit the concentration of 

formaldehyde in the stationary RICE 

exhaust to 2.7 ppmvd or less at 15 percent 

O2 and using NSCR.

measured during the initial performance test; and

b. Maintain the temperature of your stationary RICE 

exhaust so that the catalyst inlet temperature is 

greater than or equal to 750 °F and less than or equal 

to 1250 °F.

2. 4SRB stationary RICE complying with 

the requirement to reduce formaldehyde 

emissions by 76 percent or more (or by 75 

percent or more, if applicable) and not 

using NSCR; or

4SRB stationary RICE complying with the 

requirement to limit the concentration of 

formaldehyde in the stationary RICE 

exhaust to 350 ppbvd or less at 15 percent 

O2 and not using NSCR; or

4SRB stationary RICE complying with the 

requirement to limit the concentration of 

formaldehyde in the stationary RICE 

exhaust to 2.7 ppmvd or less at 15 percent 

O2 and not using NSCR.

Comply with any operating limitations approved by 

the Administrator.

[76 FR 12867, Mar. 9, 2011]

Table 2ato Subpart ZZZZ of Part 63—Emission Limitations for New and 

Reconstructed 2SLB and Compression Ignition Stationary RICE >500 HP 

and New and Reconstructed 4SLB Stationary RICE ≥250 HP Located at a 

Major Source of HAP Emissions

As stated in §§63.6600 and 63.6640, you must comply with the following emission limitations for new and 

reconstructed lean burn and new and reconstructed compression ignition stationary RICE at 100 percent load plus or 

minus 10 percent:

For each . 

. .

You must meet the following emission 

limitation, except during periods of startup . 

. .

During periods of startup you 

must . . .

1. 2SLB 

stationary 

RICE

a. Reduce CO emissions by 58 percent or 

more; or

b. Limit concentration of formaldehyde in the 

stationary RICE exhaust to 12 ppmvd or less at 

Minimize the engine's time spent at 

idle and minimize the engine's 

startup time at startup to a period 

needed for appropriate and safe 
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15 percent O2. If you commenced construction 

or reconstruction between December 19, 2002 

and June 15, 2004, you may limit concentration 

of formaldehyde to 17 ppmvd or less at 15 

percent O2until June 15, 2007

loading of the engine, not to exceed 

30 minutes, after which time the 

non-startup emission limitations 

apply.1

2. 4SLB 

stationary 

RICE

a. Reduce CO emissions by 93 percent or 

more; or

 b. Limit concentration of formaldehyde in the 

stationary RICE exhaust to 14 ppmvd or less at 

15 percent O2

3. CI 

stationary 

RICE

a. Reduce CO emissions by 70 percent or 

more; or

 b. Limit concentration of formaldehyde in the 

stationary RICE exhaust to 580 ppbvd or less at 

15 percent O2

1

Sources can petition the Administrator pursuant to the requirements of 40 CFR 63.6(g) for alternative work practices.

[75 FR 9680, Mar. 3, 2010]

Table 2bto Subpart ZZZZ of Part 63— Operating Limitations for New and 

Reconstructed 2SLB and Compression Ignition Stationary RICE >500 HP 

Located at a Major Source of HAP Emissions, New and Reconstructed 

4SLB Stationary RICE ≥250 HP Located at a Major Source of HAP 

Emissions, Existing Compression Ignition Stationary RICE >500 HP, and 

Existing 4SLB Stationary RICE >500 HP Located at an Area Source of HAP 

Emissions

As stated in §§63.6600, 63.6601, 63.6603, 63.6630, and 63.6640, you must comply with the following operating 

limitations for new and reconstructed 2SLB and compression ignition stationary RICE located at a major source of 

HAP emissions; new and reconstructed 4SLB stationary RICE ≥250 HP located at a major source of HAP emissions; 

existing compression ignition stationary RICE >500 HP; and existing 4SLB stationary RICE >500 HP located at an 

area source of HAP emissions that operate more than 24 hours per calendar year:

For each . . .

You must meet the following operating 

limitation . . .

1. 2SLB and 4SLB stationary RICE and CI 

stationary RICE complying with the requirement to 

reduce CO emissions and using an oxidation 

catalyst; or 2SLB and 4SLB stationary RICE and 

CI stationary RICE complying with the requirement 

to limit the concentration of formaldehyde in the 

a. maintain your catalyst so that the pressure 

drop across the catalyst does not change by 

more than 2 inches of water at 100 percent 

load plus or minus 10 percent from the 

pressure drop across the catalyst that was 

measured during the initial performance 
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stationary RICE exhaust and using an oxidation 

catalyst; or 4SLB stationary RICE and CI stationary 

RICE complying with the requirement to limit the 

concentration of CO in the stationary RICE exhaust 

and using an oxidation catalyst

test; and

b. maintain the temperature of your 

stationary RICE exhaust so that the catalyst 

inlet temperature is greater than or equal to 

450 °F and less than or equal to 1350 °F.1

2. 2SLB and 4SLB stationary RICE and CI 

stationary RICE complying with the requirement to 

reduce CO emissions and not using an oxidation 

catalyst; or 2SLB and 4SLB stationary RICE and 

CI stationary RICE complying with the requirement 

to limit the concentration of formaldehyde in the 

stationary RICE exhaust and not using an oxidation 

catalyst; or 4SLB stationary RICE and CI stationary 

RICE complying with the requirement to limit the 

concentration of CO in the stationary RICE exhaust 

and not using an oxidation catalyst

Comply with any operating limitations 

approved by the Administrator.

1

Sources can petition the Administrator pursuant to the requirements of 40 CFR 63.8(g) for a different temperature 

range.

[75 FR 51593, Aug. 20, 2010, as amended at 76 FR 12867, Mar. 9, 2011]

Table 2cto Subpart ZZZZ of Part 63—Requirements for Existing 

Compression Ignition Stationary RICE Located at a Major Source of HAP 

Emissions and Existing Spark Ignition Stationary RICE ≤500 HP Located at 

a Major Source of HAP Emissions

As stated in §§63.6600, 63.6602, and 63.6640, you must comply with the following requirements for existing 

compression ignition stationary RICE located at a major source of HAP emissions and existing spark ignition 

stationary RICE ≤500 HP located at a major source of HAP emissions:

For each . . .

You must meet the 

following requirement, 

except during periods of 

startup . . . During periods of startup you must . . .

1. Emergency stationary 

CI RICE and black start 

stationary CI RICE.1

a. Change oil and filter 

every 500 hours of 

operation or annually, 

whichever comes first;2

b. Inspect air cleaner every 

1,000 hours of operation or 

annually, whichever comes 

first;

c. Inspect all hoses and belts 

every 500 hours of 

Minimize the engine's time spent at idle 

and minimize the engine's startup time at 

startup to a period needed for appropriate 

and safe loading of the engine, not to 

exceed 30 minutes, after which time the 

non-startup emission limitations apply.3
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operation or annually, 

whichever comes first, and 

replace as necessary.3

2. Non-Emergency, nonblack start stationary CI 

RICE <100 HP

a. Change oil and filter 

every 1,000 hours of 

operation or annually, 

whichever comes first;2

 b. Inspect air cleaner every 

1,000 hours of operation or 

annually, whichever comes 

first;

 c. Inspect all hoses and belts 

every 500 hours of 

operation or annually, 

whichever comes first, and 

replace as necessary.3

3. Non-Emergency, nonblack start CI stationary 

RICE 100≤HP≤300 HP

Limit concentration of CO 

in the stationary RICE 

exhaust to 230 ppmvd or 

less at 15 percent O2

4. Non-Emergency, nonblack start CI stationary 

RICE 300<HP≤500

a. Limit concentration of 

CO in the stationary RICE 

exhaust to 49 ppmvd or less 

at 15 percent O2; or

 b. Reduce CO emissions by 

70 percent or more.

5. Non-Emergency, nonblack start stationary CI 

RICE >500 HP

a. Limit concentration of 

CO in the stationary RICE 

exhaust to 23 ppmvd or less 

at 15 percent O2; or

 b. Reduce CO emissions by 

70 percent or more.

6. Emergency stationary 

SI RICE and black start 

stationary SI RICE.1

a. Change oil and filter 

every 500 hours of 

operation or annually, 

whichever comes first;2

 b. Inspect spark plugs every 

1,000 hours of operation or 

annually, whichever comes 

first;
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 c. Inspect all hoses and belts 

every 500 hours of 

operation or annually, 

whichever comes first, and 

replace as necessary.3

7. Non-Emergency, nonblack start stationary SI 

RICE <100 HP that are 

not 2SLB stationary 

RICE

a. Change oil and filter 

every 1,440 hours of 

operation or annually, 

whichever comes first;2

 b. Inspect spark plugs every 

1,440 hours of operation or 

annually, whichever comes 

first;

 c. Inspect all hoses and belts 

every 1,440 hours of 

operation or annually, 

whichever comes first, and 

replace as necessary.3

8. Non-Emergency, nonblack start 2SLB 

stationary SI RICE <100 

HP

a. Change oil and filter 

every 4,320 hours of 

operation or annually, 

whichever comes first;2

 b. Inspect spark plugs every 

4,320 hours of operation or 

annually, whichever comes 

first;

 c. Inspect all hoses and belts 

every 4,320 hours of 

operation or annually, 

whichever comes first, and 

replace as necessary.3

9. Non-emergency, nonblack start 2SLB 

stationary RICE 

100≤HP≤500

Limit concentration of CO 

in the stationary RICE 

exhaust to 225 ppmvd or 

less at 15 percent O2

10. Non-emergency, 

non-black start 4SLB 

stationary RICE 

100≤HP≤500

Limit concentration of CO 

in the stationary RICE 

exhaust to 47 ppmvd or less 

at 15 percent O2

11. Non-emergency, Limit concentration of 
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non-black start 4SRB 

stationary RICE 

100≤HP≤500

formaldehyde in the 

stationary RICE exhaust to 

10.3 ppmvd or less at 15 

percent O2

12. Non-emergency, 

non-black start landfill 

or digester gas-fired 

stationary RICE 

100≤HP≤500

Limit concentration of CO 

in the stationary RICE 

exhaust to 177 ppmvd or 

less at 15 percent O2

1

If an emergency engine is operating during an emergency and it is not possible to shut down the engine in order to 

perform the work practice requirements on the schedule required in Table 2c of this subpart, or if performing the work 

practice on the required schedule would otherwise pose an unacceptable risk under Federal, State, or local law, the 

work practice can be delayed until the emergency is over or the unacceptable risk under Federal, State, or local law 

has abated. The work practice should be performed as soon as practicable after the emergency has ended or the 

unacceptable risk under Federal, State, or local law has abated. Sources must report any failure to perform the work 

practice on the schedule required and the Federal, State or local law under which the risk was deemed unacceptable.

2

Sources have the option to utilize an oil analysis program as described in §63.6625(i) in order to extend the specified 

oil change requirement in Table 2c of this subpart.

3

Sources can petition the Administrator pursuant to the requirements of 40 CFR 63.6(g) for alternative work practices.

[75 FR 51593, Aug. 20, 2010]

Table 2dto Subpart ZZZZ of Part 63— Requirements for Existing Stationary 

RICE Located at Area Sources of HAP Emissions

As stated in §§63.6603 and 63.6640, you must comply with the following requirements for existing stationary RICE 

located at area sources of HAP emissions:

For each . . .

You must meet the 

following 

requirement,

except during periods 

of startup . . .

During periods of startup you 

must . . .

1. Non-Emergency, non-black start CI 

stationary RICE ≤300 HP

a. Change oil and filter 

every 1,000 hours of 

operation or annually, 

whichever comes first;1

Minimize the engine's time spent 

at idle and minimize the engine's 

startup time at startup to a period

needed for appropriate and safe 

loading of the engine, not to 

exceed 30 minutes, after which 

time the non-startup emission 

limitations apply.

 b. Inspect air cleaner 

every 1,000 hours of 

operation or annually, 
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whichever comes first;

c. Inspect all hoses and 

belts every 500 hours 

of operation or 

annually, whichever 

comes first, and replace 

as necessary.

2. Non-Emergency, non-black start CI 

stationary RICE 300<HP≤500

a. Limit concentration 

of CO in the stationary 

RICE exhaust to 49 

ppmvd at 15 percent 

O2; or

 b. Reduce CO 

emissions by 70 percent 

or more.

3. Non-Emergency, non-black start CI 

stationary RICE >500 HP

a. Limit concentration 

of CO in the stationary 

RICE exhaust to 23 

ppmvd at 15 percent 

O2; or

 b. Reduce CO 

emissions by 70 percent 

or more.

4. Emergency stationary CI RICE and 

black start stationary CI RICE.2

a. Change oil and filter 

every 500 hours of 

operation or annually, 

whichever comes first;1

 b. Inspect air cleaner 

every 1,000 hours of 

operation or annually, 

whichever comes first; 

and

 c. Inspect all hoses and 

belts every 500 hours 

of operation or 

annually, whichever 

comes first, and replace 

as necessary.

5. Emergency stationary SI RICE; 

black start stationary SI RICE; nonemergency, non-black start 4SLB 

stationary RICE >500 HP that operate 

a. Change oil and filter 

every 500 hours of 

operation or annually, 

whichever comes first;1
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24 hours or less per calendar year; nonemergency, non-black start 4SRB 

stationary RICE >500 HP that operate 

24 hours or less per calendar year.2

b. Inspect spark plugs 

every 1,000 hours of 

operation or annually, 

whichever comes first; 

and

c. Inspect all hoses and 

belts every 500 hours 

of operation or 

annually, whichever 

comes first, and replace 

as necessary.

6. Non-emergency, non-black start 

2SLB stationary RICE

a. Change oil and filter 

every 4,320 hours of 

operation or annually, 

whichever comes first;1

 b. Inspect spark plugs 

every 4,320 hours of 

operation or annually, 

whichever comes first; 

and

 c. Inspect all hoses and 

belts every 4,320 hours 

of operation or 

annually, whichever 

comes first, and replace 

as necessary.

7. Non-emergency, non-black start 

4SLB stationary RICE ≤500 HP

a. Change oil and filter 

every 1,440 hours of 

operation or annually, 

whichever comes first;1

 b. Inspect spark plugs 

every 1,440 hours of 

operation or annually, 

whichever comes first; 

and

 c. Inspect all hoses and 

belts every 1,440 hours 

of operation or 

annually, whichever 

comes first, and replace 

as necessary.

8. Non-emergency, non-black start a. Limit concentration 
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4SLB stationary RICE >500 HP of CO in the stationary 

RICE exhaust to 47 

ppmvd at 15 percent 

O2; or

 b. Reduce CO 

emissions by 93 percent 

or more.

9. Non-emergency, non-black start 

4SRB stationary RICE ≤500 HP

a. Change oil and filter 

every 1,440 hours of 

operation or annually, 

whichever comes first;1

 b. Inspect spark plugs 

every 1,440 hours of 

operation or annually, 

whichever comes first; 

and

 c. Inspect all hoses and 

belts every 1,440 hours 

of operation or 

annually, whichever 

comes first, and replace 

as necessary.

10. Non-emergency, non-black start 

4SRB stationary RICE >500 HP

a. Limit concentration 

of formaldehyde in the 

stationary RICE 

exhaust to 2.7 ppmvd at 

15 percent O2; or

 b. Reduce 

formaldehyde 

emissions by 76 percent 

or more.

11. Non-emergency, non-black start 

landfill or digester gas-fired stationary 

RICE

a. Change oil and filter 

every 1,440 hours of 

operation or annually, 

whichever comes first;1

 b. Inspect spark plugs 

every 1,440 hours of 

operation or annually, 

whichever comes first; 

and

 c. Inspect all hoses and 
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belts every 1,440 hours 

of operation or 

annually, whichever 

comes first, and replace 

as necessary.

1

Sources have the option to utilize an oil analysis program as described in §63.6625(i) in order to extend the specified 

oil change requirement in Table 2d of this subpart.

2

If an emergency engine is operating during an emergency and it is not possible to shut down the engine in order to 

perform the management practice requirements on the schedule required in Table 2d of this subpart, or if performing 

the management practice on the required schedule would otherwise pose an unacceptable risk under Federal, State, 

or local law, the management practice can be delayed until the emergency is over or the unacceptable risk under 

Federal, State, or local law has abated. The management practice should be performed as soon as practicable after 

the emergency has ended or the unacceptable risk under Federal, State, or local law has abated. Sources must 

report any failure to perform the management practice on the schedule required and the Federal, State or local law 

under which the risk was deemed unacceptable.

[75 FR 51595, Aug. 20, 2010]

Table 3 to Subpart ZZZZ of Part 63—Subsequent Performance Tests

As stated in §§63.6615 and 63.6620, you must comply with the following subsequent performance test requirements:

For each . . .

Complying with 

the requirement to 

. . . You must . . .

1. New or reconstructed 2SLB stationary RICE 

with a brake horsepower >500 located at major 

sources; new or reconstructed 4SLB stationary 

RICE with a brake horsepower ≥250 located at 

major sources; and new or reconstructed CI 

stationary RICE with a brake horsepower >500 

located at major sources

Reduce CO 

emissions and not 

using a CEMS

Conduct subsequent 

performance tests 

semiannually.1

2. 4SRB stationary RICE with a brake horsepower 

≥5,000 located at major sources

Reduce 

formaldehyde 

emissions

Conduct subsequent 

performance tests 

semiannually.1

3. Stationary RICE with a brake horsepower >500 

located at major sources and new or reconstructed 

4SLB stationary RICE with a brake horsepower 

250≤HP≤500 located at major sources

Limit the 

concentration of 

formaldehyde in the 

stationary RICE 

exhaust

Conduct subsequent 

performance tests 

semiannually.1

4. Existing non-emergency, non-black start CI 

stationary RICE with a brake horsepower >500 that 

are not limited use stationary RICE; existing nonemergency, non-black start 4SLB and 4SRB 

Limit or reduce CO 

or formaldehyde 

emissions

Conduct subsequent 

performance tests every 

8,760 hrs. or 3 years, 

whichever comes first.
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stationary RICE located at an area source of HAP 

emissions with a brake horsepower >500 that are 

operated more than 24 hours per calendar year that 

are not limited use stationary RICE

5. Existing non-emergency, non-black start CI 

stationary RICE with a brake horsepower >500 that 

are limited use stationary RICE; existing nonemergency, non-black start 4SLB and 4SRB 

stationary RICE located at an area source of HAP 

emissions with a brake horsepower >500 that are 

operated more than 24 hours per calendar year and 

are limited use stationary RICE

Limit or reduce CO 

or formaldehyde 

emissions

Conduct subsequent 

performance tests every 

8,760 hrs. or 5 years, 

whichever comes first.

1

After you have demonstrated compliance for two consecutive tests, you may reduce the frequency of subsequent 

performance tests to annually. If the results of any subsequent annual performance test indicate the stationary RICE 

is not in compliance with the CO or formaldehyde emission limitation, or you deviate from any of your operating 

limitations, you must resume semiannual performance tests.

[75 FR 51596, Aug. 20, 2010]

Table 4 to Subpart ZZZZ of Part 63—Requirements for Performance Tests

As stated in §§63.6610, 63.6611, 63.6612, 63.6620, and 63.6640, you must comply with the following requirements 

for performance tests for stationary RICE:

For each . 

. .

Complying 

with the

requirement to 

. . . You must . . . Using . . .

According to the 

following requirements . 

. .

1. 2SLB, 

4SLB, and 

CI 

stationary 

RICE

a. Reduce CO 

emissions

i. Measure the 

O2at the inlet and 

outlet of the 

control device; and

(1) Portable CO and 

O2analyzer

(a) Using ASTM D6522–

00 (2005)a(incorporated 

by reference, see §63.14). 

Measurements to 

determine O2must be 

made at the same time as 

the measurements for CO 

concentration.

 ii. Measure the CO 

at the inlet and the 

outlet of the 

control device

(1) Portable CO and 

O2analyzer

(a) Using ASTM D6522–

00 (2005)ab(incorporated 

by reference, see §63.14) 

or Method 10 of 40 CFR 

appendix A. The CO 

concentration must be at 

15 percent O2, dry basis.

2. 4SRB a. Reduce i. Select the (1) Method 1 or 1A of (a) Sampling sites must be 
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stationary 

RICE

formaldehyde 

emissions

sampling port 

location and the 

number of traverse 

points; and

40 CFR part 60, 

appendix A 

§63.7(d)(1)(i)

located at the inlet and 

outlet of the control 

device.

 ii. Measure O2at 

the inlet and outlet 

of the control 

device; and

(1) Method 3 or 3A or 

3B of 40 CFR part 60, 

appendix A, or ASTM 

Method D6522–00m 

(2005)

(a) Measurements to 

determine 

O2concentration must be 

made at the same time as 

the measurements for 

formaldehyde 

concentration.

 iii. Measure 

moisture content at 

the inlet and outlet 

of the control 

device; and

(1) Method 4 of 40 

CFR part 60, 

appendix A, or Test 

Method 320 of 40 

CFR part 63, 

appendix A, or ASTM 

D 6348–03

(a) Measurements to 

determine moisture 

content must be made at 

the same time and location 

as the measurements for 

formaldehyde 

concentration.

 iv. Measure 

formaldehyde at 

the inlet and the 

outlet of the 

control device

(1) Method 320 or 

323 of 40 CFR part 

63, appendix A; or 

ASTM D6348–

03,c

provided in 

ASTM D6348–03 

Annex A5 (Analyte 

Spiking Technique), 

the percent R must be 

greater than or equal 

to 70 and less than or 

equal to 130

(a) Formaldehyde 

concentration must be at 

15 percent O2, dry basis. 

Results of this test consist 

of the average of the three 

1-hour or longer runs.

3. 

Stationary 

RICE

a. Limit the 

concentration 

of 

formaldehyde 

or CO in the 

stationary 

RICE exhaust

i. Select the 

sampling port 

location and the 

number of traverse 

points; and

(1) Method 1 or 1A of 

40 CFR part 60, 

appendix A 

§63.7(d)(1)(i)

(a) If using a control 

device, the sampling site 

must be located at the 

outlet of the control 

device.

 ii. Determine the 

O2concentration of 

the stationary 

RICE exhaust at 

the sampling port 

location; and

(1) Method 3 or 3A or 

3B of 40 CFR part 60, 

appendix A, or ASTM 

Method D6522–00 

(2005)

(a) Measurements to 

determine 

O2concentration must be 

made at the same time and 

location as the 

measurements for 
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formaldehyde 

concentration.

 iii. Measure 

moisture content 

of the stationary 

RICE exhaust at 

the sampling port 

location; and

(1) Method 4 of 40 

CFR part 60, 

appendix A, or Test 

Method 320 of 40 

CFR part 63, 

appendix A, or ASTM 

D 6348–03

(a) Measurements to 

determine moisture 

content must be made at 

the same time and location 

as the measurements for 

formaldehyde 

concentration.

 iv. Measure 

formaldehyde at 

the exhaust of the 

stationary RICE; 

or

(1) Method 320 or 

323 of 40 CFR part 

63, appendix A; or 

ASTM D6348–

03,c

provided in 

ASTM D6348–03 

Annex A5 (Analyte 

Spiking Technique), 

the percent R must be 

greater than or equal 

to 70 and less than or 

equal to 130

(a) Formaldehyde 

concentration must be at 

15 percent O2, dry basis. 

Results of this test consist 

of the average of the three 

1-hour or longer runs.

 v. Measure CO at 

the exhaust of the 

stationary RICE

(1) Method 10 of 40 

CFR part 60, 

appendix A, ASTM 

Method D6522–00 

(2005),aMethod 320 

of 40 CFR part 63, 

appendix A, or ASTM 

D6348–03

(a) CO Concentration 

must be at 15 percent O2, 

dry basis. Results of this 

test consist of the average 

of the three 1-hour longer 

runs.

a

You may also use Methods 3A and 10 as options to ASTM–D6522–00 (2005). You may obtain a copy of ASTM–

D6522–00 (2005) from at least one of the following addresses: American Society for Testing and Materials, 100 Barr 

Harbor Drive, West Conshohocken, PA 19428–2959, or University Microfilms International, 300 North Zeeb Road, 

Ann Arbor, MI 48106. ASTM–D6522–00 (2005) may be used to test both CI and SI stationary RICE.

b

You may also use Method 320 of 40 CFR part 63, appendix A, or ASTM D6348–03.

c

You may obtain a copy of ASTM–D6348–03 from at least one of the following addresses: American Society for 

Testing and Materials, 100 Barr Harbor Drive, West Conshohocken, PA 19428–2959, or University Microfilms 

International, 300 North Zeeb Road, Ann Arbor, MI 48106.

[75 FR 51597, Aug. 20, 2010]

Table 5 to Subpart ZZZZ of Part 63—Initial Compliance With Emission 

Limitations and Operating Limitations
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As stated in §§63.6612, 63.6625 and 63.6630, you must initially comply with the emission and operating limitations as 

required by the following:

For each . . .

Complying with the 

requirement to . . .

You have demonstrated initial 

compliance if. . .

1. New or reconstructed nonemergency 2SLB stationary RICE 

>500 HP located at a major source of 

HAP, new or reconstructed nonemergency 4SLB stationary RICE 

≥250 HP located at a major source of 

HAP, non-emergency stationary CI 

RICE >500 HP located at a major 

source of HAP, existing nonemergency stationary CI RICE >500 

HP located at an area source of HAP, 

and existing non-emergency 4SLB 

stationary RICE >500 HP located at 

an area source of HAP that are 

operated more than 24 hours per 

calendar year

a. Reduce CO 

emissions and using 

oxidation catalyst, 

and using a CPMS

i. The average reduction of 

emissions of CO determined from 

the initial performance test achieves 

the required CO percent reduction; 

and

ii. You have installed a CPMS to 

continuously monitor catalyst inlet 

temperature according to the 

requirements in §63.6625(b); and

iii. You have recorded the catalyst 

pressure drop and catalyst inlet 

temperature during the initial 

performance test.

2. Non-emergency stationary CI 

RICE >500 HP located at a major 

source of HAP, existing nonemergency stationary CI RICE >500 

HP located at an area source of HAP, 

and existing non-emergency 4SLB 

stationary RICE >500 HP located at 

an area source of HAP that are 

operated more than 24 hours per 

calendar year

a. Limit the 

concentration of CO, 

using oxidation 

catalyst, and using a 

CPMS

i. The average CO concentration 

determined from the initial 

performance test is less than or 

equal to the CO emission limitation; 

and

ii. You have installed a CPMS to 

continuously monitor catalyst inlet 

temperature according to the 

requirements in §63.6625(b); and

iii. You have recorded the catalyst 

pressure drop and catalyst inlet 

temperature during the initial 

performance test.

3. New or reconstructed nonemergency 2SLB stationary RICE 

>500 HP located at a major source of 

HAP, new or reconstructed nonemergency 4SLB stationary RICE 

≥250 HP located at a major source of 

HAP, non-emergency stationary CI 

RICE >500 HP located at a major 

source of HAP, existing nonemergency stationary CI RICE >500 

HP located at an area source of HAP, 

a. Reduce CO 

emissions and not 

using oxidation 

catalyst

i. The average reduction of 

emissions of CO determined from 

the initial performance test achieves 

the required CO percent reduction; 

and

ii. You have installed a CPMS to 

continuously monitor operating 

parameters approved by the 

Administrator (if any) according to 

the requirements in §63.6625(b); 

and
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and existing non-emergency 4SLB 

stationary RICE >500 HP located at 

an area source of HAP that are 

operated more than 24 hours per 

calendar year

iii. You have recorded the approved 

operating parameters (if any) during 

the initial performance test.

4. Non-emergency stationary CI 

RICE >500 HP located at a major 

source of HAP, existing nonemergency stationary CI RICE >500 

HP located at an area source of HAP, 

and existing non-emergency 4SLB 

stationary RICE >500 HP located at 

an area source of HAP that are 

operated more than 24 hours per 

calendar year

a. Limit the 

concentration of CO, 

and not using 

oxidation catalyst

i. The average CO concentration 

determined from the initial 

performance test is less than or 

equal to the CO emission limitation; 

and

ii. You have installed a CPMS to 

continuously monitor operating 

parameters approved by the 

Administrator (if any) according to 

the requirements in §63.6625(b); 

and

iii. You have recorded the approved 

operating parameters (if any) during 

the initial performance test.

5. New or reconstructed nonemergency 2SLB stationary RICE 

>500 HP located at a major source of 

HAP, new or reconstructed nonemergency 4SLB stationary RICE 

≥250 HP located at a major source of 

HAP, non-emergency stationary CI 

RICE >500 HP located at a major 

source of HAP, existing nonemergency stationary CI RICE >500 

HP located at an area source of HAP, 

and existing non-emergency 4SLB 

stationary RICE >500 HP located at 

an area source of HAP that are 

operated more than 24 hours per 

calendar year

a. Reduce CO 

emissions, and using 

a CEMS

i. You have installed a CEMS to 

continuously monitor CO and either 

O2or CO2at both the inlet and outlet 

of the oxidation catalyst according 

to the requirements in §63.6625(a); 

and

ii. You have conducted a 

performance evaluation of your 

CEMS using PS 3 and 4A of 40 

CFR part 60, appendix B; and

iii. The average reduction of CO 

calculated using §63.6620 equals or 

exceeds the required percent 

reduction. The initial test comprises 

the first 4-hour period after 

successful validation of the CEMS. 

Compliance is based on the average 

percent reduction achieved during 

the 4-hour period.

6. Non-emergency stationary CI 

RICE >500 HP located at a major 

source of HAP, existing nonemergency stationary CI RICE >500 

HP located at an area source of HAP, 

and existing non-emergency 4SLB 

a. Limit the 

concentration of CO, 

and using a CEMS

i. You have installed a CEMS to 

continuously monitor CO and either 

O2or CO2at the outlet of the 

oxidation catalyst according to the 

requirements in §63.6625(a); and

ii. You have conducted a 
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stationary RICE >500 HP located at 

an area source of HAP that are 

operated more than 24 hours per 

calendar year

performance evaluation of your 

CEMS using PS 3 and 4A of 40 

CFR part 60, appendix B; and

 iii. The average concentration of 

CO calculated using §63.6620 is 

less than or equal to the CO 

emission limitation. The initial test 

comprises the first 4-hour period 

after successful validation of the 

CEMS. Compliance is based on the 

average concentration measured 

during the 4-hour period.

7. Non-emergency 4SRB stationary 

RICE >500 HP located at a major 

source of HAP, and existing nonemergency 4SRB stationary RICE 

>500 HP located at an area source of 

HAP that are operated more than 24 

hours per calendar year

a. Reduce 

formaldehyde 

emissions and using 

NSCR

i. The average reduction of 

emissions of formaldehyde 

determined from the initial 

performance test is equal to or 

greater than the required 

formaldehyde percent reduction; 

and

ii. You have installed a CPMS to 

continuously monitor catalyst inlet 

temperature according to the 

requirements in §63.6625(b); and

 iii. You have recorded the catalyst 

pressure drop and catalyst inlet 

temperature during the initial 

performance test.

8. Non-emergency 4SRB stationary 

RICE >500 HP located at a major 

source of HAP, and existing nonemergency 4SRB stationary RICE 

>500 HP located at an area source of 

HAP that are operated more than 24 

hours per calendar year

a. Reduce 

formaldehyde 

emissions and not 

using NSCR

i. The average reduction of 

emissions of formaldehyde 

determined from the initial 

performance test is equal to or 

greater than the required 

formaldehyde percent reduction; 

and

ii. You have installed a CPMS to 

continuously monitor operating 

parameters approved by the 

Administrator (if any) according to 

the requirements in §63.6625(b); 

and

iii. You have recorded the approved 

operating parameters (if any) during 
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the initial performance test.

9. Existing non-emergency 4SRB 

stationary RICE >500 HP located at 

an area source of HAP that are 

operated more than 24 hours per 

calendar year

a. Limit the 

concentration of 

formaldehyde and not 

using NSCR

i. The average formaldehyde 

concentration determined from the 

initial performance test is less than 

or equal to the formaldehyde 

emission limitation; and

 ii. You have installed a CPMS to 

continuously monitor operating 

parameters approved by the 

Administrator (if any) according to 

the requirements in §63.6625(b); 

and

 iii. You have recorded the approved 

operating parameters (if any) during 

the initial performance test.

10. New or reconstructed nonemergency stationary RICE >500 HP 

located at a major source of HAP, 

new or reconstructed non-emergency 

4SLB stationary RICE 250≤HP≤500 

located at a major source of HAP, and 

existing non-emergency 4SRB 

stationary RICE >500 HP

a. Limit the 

concentration of 

formaldehyde in the 

stationary RICE 

exhaust and using 

oxidation catalyst or 

NSCR

i. The average formaldehyde 

concentration, corrected to 15 

percent O2, dry basis, from the three 

test runs is less than or equal to the 

formaldehyde emission limitation; 

and

ii. You have installed a CPMS to 

continuously monitor catalyst inlet 

temperature according to the 

requirements in §63.6625(b); and

 iii. You have recorded the catalyst 

pressure drop and catalyst inlet 

temperature during the initial 

performance test.

11. New or reconstructed nonemergency stationary RICE >500 HP 

located at a major source of HAP, 

new or reconstructed non-emergency 

4SLB stationary RICE 250≤HP≤500 

located at a major source of HAP, and 

existing non-emergency 4SRB 

stationary RICE >500 HP

a. Limit the 

concentration of 

formaldehyde in the 

stationary RICE 

exhaust and not using 

oxidation catalyst or 

NSCR

i. The average formaldehyde 

concentration, corrected to 15 

percent O2, dry basis, from the three 

test runs is less than or equal to the 

formaldehyde emission limitation; 

and

ii. You have installed a CPMS to 

continuously monitor operating 

parameters approved by the 

Administrator (if any) according to 

the requirements in §63.6625(b); 

and

 iii. You have recorded the approved 
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operating parameters (if any) during 

the initial performance test.

12. Existing non-emergency 

stationary RICE 100≤HP≤500 located 

at a major source of HAP, and 

existing non-emergency stationary CI 

RICE 300<HP≤500 located at an area 

source of HAP

a. Reduce CO or 

formaldehyde 

emissions

i. The average reduction of 

emissions of CO or formaldehyde, 

as applicable determined from the 

initial performance test is equal to 

or greater than the required CO or 

formaldehyde, as applicable, 

percent reduction.

13. Existing non-emergency 

stationary RICE 100≤HP≤500 located 

at a major source of HAP, and 

existing non-emergency stationary CI 

RICE 300<HP≤500 located at an area 

source of HAP

a. Limit the 

concentration of 

formaldehyde or CO 

in the stationary 

RICE exhaust

i. The average formaldehyde or CO 

concentration, as applicable, 

corrected to 15 percent O2, dry 

basis, from the three test runs is less 

than or equal to the formaldehyde 

or CO emission limitation, as 

applicable.

[76 FR 12867, Mar. 9, 2011]

Table 6 to Subpart ZZZZ of Part 63—Continuous Compliance With Emission 

Limitations, Operating Limitations, Work Practices, and Management 

Practices

As stated in §63.6640, you must continuously comply with the emissions and operating limitations and work or 

management practices as required by the following:

For each . . .

Complying with the 

requirement to . . .

You must demonstrate 

continuous compliance by . . .

1. New or reconstructed nonemergency 2SLB stationary RICE 

>500 HP located at a major source 

of HAP, new or reconstructed nonemergency 4SLB stationary RICE 

≥250 HP located at a major source 

of HAP, and new or reconstructed 

non-emergency CI stationary RICE 

>500 HP located at a major source 

of HAP

a. Reduce CO emissions 

and using an oxidation 

catalyst, and using a 

CPMS

i. Conducting semiannual 

performance tests for CO to 

demonstrate that the required CO 

percent reduction is achieved;a

and

ii. Collecting the catalyst inlet 

temperature data according to 

§63.6625(b); and

iii. Reducing these data to 4-hour 

rolling averages; and

iv. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the catalyst inlet 

temperature; and

 v. Measuring the pressure drop 

across the catalyst once per month 

and demonstrating that the pressure 
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drop across the catalyst is within 

the operating limitation established 

during the performance test.

2. New or reconstructed nonemergency 2SLB stationary RICE 

>500 HP located at a major source 

of HAP, new or reconstructed nonemergency 4SLB stationary RICE 

≥250 HP located at a major source 

of HAP, and new or reconstructed 

non-emergency CI stationary RICE 

>500 HP located at a major source 

of HAP

a. Reduce CO emissions 

and not using an 

oxidation catalyst, and 

using a CPMS

i. Conducting semiannual 

performance tests for CO to 

demonstrate that the required CO 

percent reduction is achieved;a

and

ii. Collecting the approved 

operating parameter (if any) data 

according to §63.6625(b); and

iii. Reducing these data to 4-hour 

rolling averages; and

 iv. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the operating 

parameters established during the 

performance test.

3. New or reconstructed nonemergency 2SLB stationary RICE 

>500 HP located at a major source 

of HAP, new or reconstructed nonemergency 4SLB stationary RICE 

≥250 HP located at a major source 

of HAP, new or reconstructed nonemergency stationary CI RICE 

>500 HP located at a major source 

of HAP, existing non-emergency 

stationary CI RICE >500 HP, 

existing non-emergency 4SLB 

stationary RICE >500 HP located 

at an area source of HAP that are 

operated more than 24 hours per 

calendar year

a. Reduce CO emissions 

or limit the 

concentration of CO in 

the stationary RICE 

exhaust, and using a 

CEMS

i. Collecting the monitoring data 

according to §63.6625(a), reducing 

the measurements to 1-hour 

averages, calculating the percent 

reduction or concentration of CO 

emissions according to §63.6620; 

and

ii. Demonstrating that the catalyst 

achieves the required percent 

reduction of CO emissions over the 

4-hour averaging period, or that the 

emission remain at or below the CO 

concentration limit; and

iii. Conducting an annual RATA of 

your CEMS using PS 3 and 4A of 

40 CFR part 60, appendix B, as 

well as daily and periodic data 

quality checks in accordance with 

40 CFR part 60, appendix F, 

procedure 1.

4. Non-emergency 4SRB stationary 

RICE >500 HP located at a major 

source of HAP

a. Reduce formaldehyde 

emissions and using 

NSCR

i. Collecting the catalyst inlet 

temperature data according to 

§63.6625(b); and

 ii. Reducing these data to 4-hour 

rolling averages; and
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 iii. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the catalyst inlet 

temperature; and

 iv. Measuring the pressure drop 

across the catalyst once per month 

and demonstrating that the pressure 

drop across the catalyst is within 

the operating limitation established 

during the performance test.

5. Non-emergency 4SRB stationary 

RICE >500 HP located at a major 

source of HAP

a. Reduce formaldehyde 

emissions and not using 

NSCR

i. Collecting the approved operating 

parameter (if any) data according to 

§63.6625(b); and

ii. Reducing these data to 4-hour 

rolling averages; and

 iii. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the operating 

parameters established during the 

performance test.

6. Non-emergency 4SRB stationary 

RICE with a brake HP ≥5,000 

located at a major source of HAP

a. Reduce formaldehyde 

emissions

Conducting semiannual 

performance tests for formaldehyde 

to demonstrate that the required 

formaldehyde percent reduction is 

achieved.a

7. New or reconstructed nonemergency stationary RICE >500 

HP located at a major source of 

HAP and new or reconstructed 

non-emergency 4SLB stationary 

RICE 250 ≤HP≤500 located at a 

major source of HAP

a. Limit the 

concentration of 

formaldehyde in the

stationary RICE exhaust 

and using oxidation 

catalyst or NSCR

i. Conducting semiannual 

performance tests for formaldehyde 

to demonstrate that your emissions 

remain at or below the 

formaldehyde concentration 

limit;a

and

ii. Collecting the catalyst inlet 

temperature data according to 

§63.6625(b); and

 iii. Reducing these data to 4-hour 

rolling averages; and

 iv. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the catalyst inlet 

temperature; and

 v. Measuring the pressure drop 

across the catalyst once per month 
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and demonstrating that the pressure 

drop across the catalyst is within 

the operating limitation established 

during the performance test.

8. New or reconstructed nonemergency stationary RICE >500 

HP located at a major source of 

HAP and new or reconstructed 

non-emergency 4SLB stationary 

RICE 250 ≤HP≤500 located at a 

major source of HAP

a. Limit the 

concentration of 

formaldehyde in the 

stationary RICE exhaust 

and not using oxidation 

catalyst or NSCR

i. Conducting semiannual 

performance tests for formaldehyde 

to demonstrate that your emissions 

remain at or below the 

formaldehyde concentration 

limit;aand

ii. Collecting the approved 

operating parameter (if any) data 

according to §63.6625(b); and

 iii. Reducing these data to 4-hour 

rolling averages; and

 iv. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the operating 

parameters established during the 

performance test.

9. Existing emergency and black 

start stationary RICE ≤500 HP 

located at a major source of HAP, 

existing non-emergency stationary 

RICE <100 HP located at a major 

source of HAP, existing emergency 

and black start stationary RICE 

located at an area source of HAP, 

existing non-emergency stationary 

CI RICE ≤300 HP located at an 

area source of HAP, existing nonemergency 2SLB stationary RICE 

located at an area source of HAP, 

existing non-emergency landfill or 

digester gas stationary SI RICE 

located at an area source of HAP, 

existing non-emergency 4SLB and 

4SRB stationary RICE ≤500 HP 

located at an area source of HAP, 

existing non-emergency 4SLB and 

4SRB stationary RICE >500 HP 

located at an area source of HAP 

that operate 24 hours or less per 

calendar year

a. Work or Management 

practices

i. Operating and maintaining the 

stationary RICE according to the 

manufacturer's emission-related 

operation and maintenance 

instructions; or

ii. Develop and follow your own 

maintenance plan which must 

provide to the extent practicable for 

the maintenance and operation of 

the engine in a manner consistent 

with good air pollution control 

practice for minimizing emissions.
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10. Existing stationary CI RICE 

>500 HP that are not limited use 

stationary RICE, and existing 

4SLB and 4SRB stationary RICE 

>500 HP located at an area source 

of HAP that operate more than 24 

hours per calendar year and are not 

limited use stationary RICE

a. Reduce CO or 

formaldehyde 

emissions, or limit the 

concentration of 

formaldehyde or CO in 

the stationary RICE 

exhaust, and using 

oxidation catalyst or 

NSCR

i. Conducting performance tests 

every 8,760 hours or 3 years, 

whichever comes first, for CO or 

formaldehyde, as appropriate, to 

demonstrate that the required CO or 

formaldehyde, as appropriate, 

percent reduction is achieved or 

that your emissions remain at or 

below the CO or formaldehyde 

concentration limit; and

 ii. Collecting the catalyst inlet 

temperature data according to 

§63.6625(b); and

 iii. Reducing these data to 4-hour 

rolling averages; and

 iv. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the catalyst inlet 

temperature; and

 v. Measuring the pressure drop 

across the catalyst once per month 

and demonstrating that the pressure 

drop across the catalyst is within 

the operating limitation established 

during the performance test.

11. Existing stationary CI RICE 

>500 HP that are not limited use 

stationary RICE, and existing 

4SLB and 4SRB stationary RICE 

>500 HP located at an area source 

of HAP that operate more than 24 

hours per calendar year and are not 

limited use stationary RICE

a. Reduce CO or 

formaldehyde 

emissions, or limit the 

concentration of 

formaldehyde or CO in 

the stationary RICE 

exhaust, and not using 

oxidation catalyst or 

NSCR

i. Conducting performance tests 

every 8,760 hours or 3 years, 

whichever comes first, for CO or 

formaldehyde, as appropriate, to 

demonstrate that the required CO or 

formaldehyde, as appropriate, 

percent reduction is achieved or 

that your emissions remain at or 

below the CO or formaldehyde 

concentration limit; and

 ii. Collecting the approved 

operating parameter (if any) data 

according to §63.6625(b); and

 iii. Reducing these data to 4-hour 

rolling averages; and

 iv. Maintaining the 4-hour rolling 

averages within the operating 
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limitations for the operating 

parameters established during the 

performance test.

12. Existing limited use CI 

stationary RICE >500 HP and 

existing limited use 4SLB and 

4SRB stationary RICE >500 HP 

located at an area source of HAP 

that operate more than 24 hours per 

calendar year

a. Reduce CO or 

formaldehyde emissions 

or limit the 

concentration of 

formaldehyde or CO in 

the stationary RICE 

exhaust, and using an 

oxidation catalyst or 

NSCR

i. Conducting performance tests 

every 8,760 hours or 5 years, 

whichever comes first, for CO or 

formaldehyde, as appropriate, to 

demonstrate that the required CO or 

formaldehyde, as appropriate, 

percent reduction is achieved or 

that your emissions remain at or 

below the CO or formaldehyde 

concentration limit; and

 ii. Collecting the catalyst inlet 

temperature data according to 

§63.6625(b); and

 iii. Reducing these data to 4-hour 

rolling averages; and

 iv. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the catalyst inlet 

temperature; and

 v. Measuring the pressure drop 

across the catalyst once per month 

and demonstrating that the pressure 

drop across the catalyst is within 

the operating limitation established 

during the performance test.

13. Existing limited use CI 

stationary RICE >500 HP and 

existing limited use 4SLB and 

4SRB stationary RICE >500 HP 

located at an area source of HAP 

that operate more than 24 hours per 

calendar year

a. Reduce CO or 

formaldehyde emissions 

or limit the 

concentration of 

formaldehyde or CO in 

the stationary RICE 

exhaust, and not using 

an oxidation catalyst or 

NSCR

i. Conducting performance tests 

every 8,760 hours or 5 years, 

whichever comes first, for CO or 

formaldehyde, as appropriate, to 

demonstrate that the required CO or 

formaldehyde, as appropriate, 

percent reduction is achieved or 

that your emissions remain at or 

below the CO or formaldehyde 

concentration limit; and

 ii. Collecting the approved 

operating parameter (if any) data 

according to §63.6625(b); and

 iii. Reducing these data to 4-hour 
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Permit Reviewer: Josiah Balogun

rolling averages; and

 iv. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the operating 

parameters established during the 

performance test.

a

After you have demonstrated compliance for two consecutive tests, you may reduce the frequency of subsequent 

performance tests to annually. If the results of any subsequent annual performance test indicate the stationary RICE 

is not in compliance with the CO or formaldehyde emission limitation, or you deviate from any of your operating 

limitations, you must resume semiannual performance tests.

[76 FR 12870, Mar. 9, 2011]

Table 7 to Subpart ZZZZ of Part 63—Requirements for Reports

As stated in §63.6650, you must comply with the following requirements for reports:

For each ...

You must 

submit a ... The report must contain ...

You 

must 

submit 

the 

report 

...

1. Existing non-emergency, nonblack start stationary RICE 

100≤HP≤500 located at a major 

source of HAP; existing nonemergency, non-black start 

stationary CI RICE >500 HP 

located at a major source of HAP; 

existing non-emergency 4SRB 

stationary RICE >500 HP located 

at a major source of HAP; existing 

non-emergency, non-black start 

stationary CI RICE >300 HP 

located at an area source of HAP; 

existing non-emergency, non-black 

start 4SLB and 4SRB stationary 

RICE >500 HP located at an area 

source of HAP and operated more 

than 24 hours per calendar year; 

new or reconstructed nonemergency stationary RICE >500 

HP located at a major source of 

HAP; and new or reconstructed 

Compliance 

report

a. If there are no deviations from any 

emission limitations or operating 

limitations that apply to you, a 

statement that there were no 

deviations from the emission 

limitations or operating limitations 

during the reporting period. If there 

were no periods during which the 

CMS, including CEMS and CPMS, 

was out-of-control, as specified in 

§63.8(c)(7), a statement that there 

were not periods during which the 

CMS was out-of-control during the 

reporting period; or

b. If you had a deviation from any 

emission limitation or operating 

limitation during the reporting period, 

the information in §63.6650(d). If 

there were periods during which the 

CMS, including CEMS and CPMS, 

was out-of-control, as specified in 

§63.8(c)(7), the information in 
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Permit Reviewer: Josiah Balogun

non-emergency 4SLB stationary 

RICE 250≤HP≤500 located at a 

major source of HAP

§63.6650(e); or

c. If you had a malfunction during the 

reporting period, the information in 

§63.6650(c)(4)

i. Semiannually according to the 

requirements in §63.6650(b)(1)–(5) 

for engines that are not limited use 

stationary RICE subject to numerical 

emission limitations; and

ii. Annually according to the 

requirements in §63.6650(b)(6)–(9) 

for engines that are limited use 

stationary RICE subject to numerical 

emission limitations.

i. Semiannually according to the 

requirements in §63.6650(b).

i. Semiannually according to the 

requirements in §63.6650(b).

2. New or reconstructed nonemergency stationary RICE that 

combusts landfill gas or digester 

gas equivalent to 10 percent or 

more of the gross heat input on an 

annual basis

Report a. The fuel flow rate of each fuel and 

the heating values that were used in 

your calculations, and you must 

demonstrate that the percentage of 

heat input provided by landfill gas or 

digester gas, is equivalent to 10 

percent or more of the gross heat input 

on an annual basis; and

i. Annually, according to the 

requirements in §63.6650.

 b. The operating limits provided in 

your federally enforceable permit, and 

any deviations from these limits; and

i. See item 2.a.i.

 c. Any problems or errors suspected 

with the meters.

i. See item 2.a.i.

[75 FR 51603, Aug. 20, 2010]

Table 8 to Subpart ZZZZ of Part 63—Applicability of General Provisions to 

Subpart ZZZZ.

As stated in §63.6665, you must comply with the following applicable general provisions.

General Subject of citation Applies to Explanation
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Permit Reviewer: Josiah Balogun

provisions 

citation

subpart

§63.1 General applicability of the 

General Provisions

Yes.

§63.2 Definitions Yes Additional terms defined in 

§63.6675.

§63.3 Units and abbreviations Yes.

§63.4 Prohibited activities and 

circumvention

Yes.

§63.5 Construction and 

reconstruction

Yes.

§63.6(a) Applicability Yes.

§63.6(b)(1)–(4) Compliance dates for new and 

reconstructed sources

Yes.

§63.6(b)(5) Notification Yes.

§63.6(b)(6) [Reserved]

§63.6(b)(7) Compliance dates for new and 

reconstructed area sources that 

become major sources

Yes.

§63.6(c)(1)–(2) Compliance dates for existing 

sources

Yes.

§63.6(c)(3)–(4) [Reserved]

§63.6(c)(5) Compliance dates for existing 

area sources that become 

major sources

Yes.

§63.6(d) [Reserved]

§63.6(e) Operation and maintenance No.

§63.6(f)(1) Applicability of standards No.

§63.6(f)(2) Methods for determining 

compliance

Yes.

§63.6(f)(3) Finding of compliance Yes.

§63.6(g)(1)–(3) Use of alternate standard Yes.

§63.6(h) Opacity and visible emission 

standards

No Subpart ZZZZ does not 

contain opacity or visible 

emission standards.
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§63.6(i) Compliance extension 

procedures and criteria

Yes.

§63.6(j) Presidential compliance 

exemption

Yes.

§63.7(a)(1)–(2) Performance test dates Yes Subpart ZZZZ contains 

performance test dates at 

§§63.6610, 63.6611, and 

63.6612.

§63.7(a)(3) CAA section 114 authority Yes.

§63.7(b)(1) Notification of performance 

test

Yes Except that §63.7(b)(1) only 

applies as specified in 

§63.6645.

§63.7(b)(2) Notification of rescheduling Yes Except that §63.7(b)(2) only 

applies as specified in 

§63.6645.

§63.7(c) Quality assurance/test plan Yes Except that §63.7(c) only 

applies as specified in 

§63.6645.

§63.7(d) Testing facilities Yes.

§63.7(e)(1) Conditions for conducting 

performance tests

No. Subpart ZZZZ specifies 

conditions for conducting 

performance tests at 

§63.6620.

§63.7(e)(2) Conduct of performance tests 

and reduction of data

Yes Subpart ZZZZ specifies test 

methods at §63.6620.

§63.7(e)(3) Test run duration Yes.

§63.7(e)(4) Administrator may require 

other testing under section 114 

of the CAA

Yes.

§63.7(f) Alternative test method 

provisions

Yes.

§63.7(g) Performance test data analysis, 

recordkeeping, and reporting

Yes.

§63.7(h) Waiver of tests Yes.

§63.8(a)(1) Applicability of monitoring 

requirements

Yes Subpart ZZZZ contains 

specific requirements for 

monitoring at §63.6625.
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§63.8(a)(2) Performance specifications Yes.

§63.8(a)(3) [Reserved]

§63.8(a)(4) Monitoring for control devices No.

§63.8(b)(1) Monitoring Yes.

§63.8(b)(2)–(3) Multiple effluents and multiple 

monitoring systems

Yes.

§63.8(c)(1) Monitoring system operation 

and maintenance

Yes.

§63.8(c)(1)(i) Routine and predictable SSM Yes.

§63.8(c)(1)(ii) SSM not in Startup Shutdown 

Malfunction Plan

Yes.

§63.8(c)(1)(iii) Compliance with operation 

and maintenance requirements

Yes.

§63.8(c)(2)–(3) Monitoring system installation Yes.

§63.8(c)(4) Continuous monitoring system 

(CMS) requirements

Yes Except that subpart ZZZZ 

does not require Continuous 

Opacity Monitoring System 

(COMS).

§63.8(c)(5) COMS minimum procedures No Subpart ZZZZ does not 

require COMS.

§63.8(c)(6)–(8) CMS requirements Yes Except that subpart ZZZZ 

does not require COMS.

§63.8(d) CMS quality control Yes.

§63.8(e) CMS performance evaluation Yes Except for §63.8(e)(5)(ii), 

which applies to COMS.

 Except that 

§63.8(e) only 

applies as 

specified in 

§63.6645.

§63.8(f)(1)–(5) Alternative monitoring method Yes Except that §63.8(f)(4) only 

applies as specified in 

§63.6645.

§63.8(f)(6) Alternative to relative 

accuracy test

Yes Except that §63.8(f)(6) only 

applies as specified in 

§63.6645.
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§63.8(g) Data reduction Yes Except that provisions for 

COMS are not applicable. 

Averaging periods for 

demonstrating compliance are 

specified at §§63.6635 and 

63.6640.

§63.9(a) Applicability and State 

delegation of notification 

requirements

Yes.

§63.9(b)(1)–(5) Initial notifications Yes Except that §63.9(b)(3) is 

reserved.

 Except that 

§63.9(b) only 

applies as 

specified in 

§63.6645.

§63.9(c) Request for compliance 

extension

Yes Except that §63.9(c) only 

applies as specified in 

§63.6645.

§63.9(d) Notification of special 

compliance requirements for 

new sources

Yes Except that §63.9(d) only 

applies as specified in 

§63.6645.

§63.9(e) Notification of performance 

test

Yes Except that §63.9(e) only 

applies as specified in 

§63.6645.

§63.9(f) Notification of visible 

emission (VE)/opacity test

No Subpart ZZZZ does not 

contain opacity or VE 

standards.

§63.9(g)(1) Notification of performance 

evaluation

Yes Except that §63.9(g) only 

applies as specified in 

§63.6645.

§63.9(g)(2) Notification of use of COMS 

data

No Subpart ZZZZ does not 

contain opacity or VE 

standards.

§63.9(g)(3) Notification that criterion for 

alternative to RATA is 

exceeded

Yes If alternative is in use.

 Except that 

§63.9(g) only 

applies as 
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specified in 

§63.6645.

§63.9(h)(1)–(6) Notification of compliance 

status

Yes Except that notifications for 

sources using a CEMS are 

due 30 days after completion 

of performance evaluations. 

§63.9(h)(4) is reserved.

 Except that §63.9(h) only 

applies as specified in 

§63.6645.

§63.9(i) Adjustment of submittal 

deadlines

Yes.

§63.9(j) Change in previous 

information

Yes.

§63.10(a) Administrative provisions for 

recordkeeping/reporting

Yes.

§63.10(b)(1) Record retention Yes.

§63.10(b)(2)(i)–

(v)

Records related to SSM No.

§63.10(b)(2)(vi)–

(xi)

Records Yes.

§63.10(b)(2)(xii) Record when under waiver Yes.

§63.10(b)(2)(xiii) Records when using 

alternative to RATA

Yes For CO standard if using 

RATA alternative.

§63.10(b)(2)(xiv) Records of supporting 

documentation

Yes.

§63.10(b)(3) Records of applicability 

determination

Yes.

§63.10(c) Additional records for sources 

using CEMS

Yes Except that §63.10(c)(2)–(4) 

and (9) are reserved.

§63.10(d)(1) General reporting 

requirements

Yes.

§63.10(d)(2) Report of performance test 

results

Yes.

§63.10(d)(3) Reporting opacity or VE 

observations

No Subpart ZZZZ does not 

contain opacity or VE 

standards.
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§63.10(d)(4) Progress reports Yes.

§63.10(d)(5) Startup, shutdown, and 

malfunction reports

No.

§63.10(e)(1) and 

(2)(i)

Additional CMS Reports Yes.

§63.10(e)(2)(ii) COMS-related report No Subpart ZZZZ does not 

require COMS.

§63.10(e)(3) Excess emission and parameter 

exceedances reports

Yes. Except that §63.10(e)(3)(i) 

(C) is reserved.

§63.10(e)(4) Reporting COMS data No Subpart ZZZZ does not 

require COMS.

§63.10(f) Waiver for 

recordkeeping/reporting

Yes.

§63.11 Flares No.

§63.12 State authority and delegations Yes.

§63.13 Addresses Yes.

§63.14 Incorporation by reference Yes.

§63.15 Availability of information Yes.

[75 FR 9688, Mar. 3, 2010]
St. Joseph Energy Center, LLC Page 58 of 58

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun
Indiana Department of Environmental Management

Office of Air Quality

Addendum to the Technical Support Document (ATSD) for a PSD/New Source 

Construction and Part 70 Operating Permit (TITLE V)

Source Description and Location

Source Name: St. Joseph Energy Center, LLC

Source Location: Corner of Walnut and Edison Roads, 

New Carlisle, Indiana 46552

County: St. Joseph

SIC Code: 4911

Operation Permit No.: T 141-31003-00579

Operation Permit Issuance Date: Yet to be issued

Permit Reviewer: Josiah Balogun

Public Notice Information

On August 29, 2012, the Office of Air Quality (OAQ) had a notice published in the South Bend Tribune in South 

Bend, Indiana, stating that St. Joseph Energy Center, LLC had applied for a Part 70 Operating Permit (TITLE 

V) to operate a nominal 1,350 megawatt (MW) combined cycle combustion turbine (CCCT) electric generating 

facility (CCCT Facility). The notice also stated that OAQ proposed to issue a Title V permit for this operation 

and provided information on how the public could review the proposed Title V permit and other documentation. 

Finally, the notice informed interested parties that there was a period of forty two (42) days to provide 

comments on whether or not this Title V permit should be issued as proposed.

On October 4, 2012, the Office of Air Quality (OAQ) held a public meeting and hearing at the New 

Prairie High School Auditorium in New Carlisle, Indiana, for citizens and interested parties to discuss 

questions and concerns related to the project.

No changes have been made to the TSD because the OAQ prefers that the Technical Support 

Document reflects the permit that was on public notice. Changes that occur after the public 

notice are documented in this Addendum to the Technical Support Document. This 

 accomplishes the desired result, ensuring that these types of concerns are documented and 

part of the record regarding this permit decision.

Comments Received from USEPA

On February 2, 2012, Sam Portanova of USEPA submitted comments on the proposed Title V 

Operating Permit. The comments are summarized in the subsequent pages, with IDEM’s corresponding 

responses.

The Combined Cycle Combustion Turbine (CCCT) startup/shutdown Best Available Control 

Technology (BACT) limits in permit condition D.1.11 are as follows: 22 tons of Volatile Organic 

Compounds (VOC) per 12-month period, 407.5 tons of Carbon Monoxide (CO) per 12-month period, 

and 81.6 tons of Nitrogen Oxides (NOx) per 12-month period. In addition, this permit condition limits 

CO emissions to 2,125 pounds per event and NOx emissions to 443 pounds per event (where an 

"event" is defined as a single startup or shutdown). 

Comment 1: The BACT analysis in Appendix B of the Technical Support Document (TSD) does not 

include an analysis of the startup/shutdown limits selected as BACT for VOC, CO, and

NOx emissions from the CCCTs. The permit should include an analysis for the selection 
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New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

of these BACT limits for startup and shutdown events. 

Response 1: The secondary BACT limits are justified for NOX, CO, and VOC emissions during startup 

and shutdown events in the permit application submitted by St. Joseph Energy Center, 

LLC. The secondary NOX, CO, and VOC limits for startup and shutdown events are 

mass-based limits on a ton per year basis. Annual mass limits are based on 4 hot starts, 

198 warm starts, 16 cold starts, and 218 shutdowns per year for each turbine, using per 

event emission rates provided by the combustion turbine vendor. The number of each 

type of startup is not suitable as a permit condition as the number and blend of hot, warm, 

and cold starts and plant shutdowns will vary over the plant life based on market demand 

for power. 

As stated above, BACT for startup and shutdown emissions are established as rolling, 12-

month emission limits. However, the pounds per event emission limits for NOX and CO 

were not established as BACT. These limits were incorporated into the permit to 

demonstrate continuous compliance with the emission rates used to demonstrate 

compliance with the National Ambient Air Quality Standards (NAAQS) during startup and 

shutdown events. 

Comment 2: The potential to emit table on page 7 of the TSD lists total CO emissions from the four 

CCCTs as 130 tons per year (tpy) per turbine, which is a total 520 tpy for the CCCTs. 

Does this amount account for the 407.5 tons of CO per 12-month period allowed in permit 

condition D.1.11(i) during startup/shutdown events?

The potential to emit table on page 7 of the TSD lists total VOC emissions from the four 

CCCTs as 24.97 tpy per turbine, which is a total 99.88 tpy for the CCCTs. Does this 

amount account for the 22.0 tons of VOC per 12-month period allowed in permit condition 

D.1.11(j) during startup/shutdown events?

The potential to emit table on page 7 of the TSD lists total NOx emissions from the four 

CCCTs as 71.8 tpy per turbine, which is a total 287.2 for the CCCTs. Does this amount 

account for the 81.6 tons of NOx per 12-month period allowed in permit condition 

D.1.11(h) during startup/shutdown events?

Response 2: The CCCT potential to emit (PTE) for CO, NOX, and VOC include emissions during both 

startup/shutdown events and emissions during steady state operation. See page 9 of 22 

TSD App A of the calculations.

Comment 3: The Greenhouse Gas (GHG) BACT emission calculations in permit condition D.1.15 are 

based on emission factors from 40 C.F.R. Part 98, Subpart C. Permit condition D.1.17 

requires GHG stack testing once every 5 years. While EPA agrees with the use of the 40 

C.F.R. Part 98 emission factors in calculating GHG emissions, the Indiana Department of 

Environmental Management (IDEM) should clarify in the permit that the results of future 

stack tests can be used to determine a source-specific emission factor to calculate GHG 

emissions from this facility.

Response 3: Permit condition D.1.17(c) requires a heat rate performance test for the CCCTs to verify 

compliance with the greenhouse gas (GHG) limit in condition D.1.10(a). The heat rate 

performance test will evaluate efficiency of the CCCT by comparing heat input from 

natural gas to the net power output, but will not monitor actual GHG emissions from the 

CCCT stacks. Therefore, there is no current need to revise permit condition D.1.17 to 

allow for use of future stack tests to determine source-specific GHG emissions factors. 

Should any future need to establish source-specific emissions factors for demonstrating 

compliance with Condition D.1.10(b) arise in the future, any necessary permit updates 

can be incorporated at that time. 
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New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

Comment 4: The permit does not include monitoring for the sulfuric acid mist and sulfur dioxide BACT 

emission limits for the CCCTs. The permit should include a method of demonstrating 

compliance with the fuel sulfur limit of 0.75 grains of sulfur/100 standard cubic feet fuel 

listed in permit conditions D.1.5 and D.1.7.

Response 4: IDEM has added a record keeping requirements to demonstrate compliance with the SO2

and H2SO4 BACT limits established for the CCCTs.

D.1.19 Record Keeping Requirement

***********************************

(e) In order to document the compliance status with Conditions D.1.4, D.1.5, D.1.6, D.1.7, 

D.1.8, D.1.9 and D.1.10 - GHGs PSD BACT, the Permittee shall maintain monthly 

records of the amount and type of fuel combusted in the combined cycle combustion 

turbines.

...............................................................................................................................................

(h) To document the compliance status with Condition D.1.5 - H2SO4 PSD BACT and 

D.1.7 - SO2 PSD BACT, the Permittee shall maintain the monthly records of the fuel 

sulfur content of the natural gas combusted in the turbines and the associated 

duct burners.

(hi) Section C - General Record Keeping Requirements contains the Permittee's obligations 

with regard to the record keeping required by this condition.

Comment 5: Permit condition D.1.17(a) requires a Particulate Matter (PM) stack test every five years to 

demonstrate compliance with the BACT limits in permit condition D.1.4. However, the 

permit does not require periodic monitoring to demonstrate compliance with the PM limits 

in between the stack tests. IDEM should either demonstrate how compliance with the PM 

limits is sufficiently assured with the stack test or require additional periodic monitoring in 

the intervening period between stack tests.

Response 5: Additional compliance monitoring for particulate matter (PM) BACT limits is not required 

because the CCCTs have no control device to control PM emissions. The BACT limits are 

met using natural gas as fuel and good combustion practices. Since only natural gas may 

be used as fuel for the CCCT and the continuous emissions monitoring systems (CEMS) 

for CO will verify good combustion practices on a continuous basis, additional compliance 

monitoring specifically for PM is not necessary. This approach is consistent with recent 

permits issued with PM BACT limits for CCCT facilities. 

Comments Received from the Source 

On September 27, 2012, David Dempsey of Trinity Consultant submitted comments on the 

proposed Title V Operating Permit. The comments are summarized in the subsequent pages, with IDEM’s 

corresponding responses.

The summary of the comments and IDEM, OAQ responses, including changes to the permit No. 

141-31003-00579 (language deleted is shown in strikeout and language added is shown in bold) are as 

follows:

Comment 1: Permit Condition D.6.7

Condition D.6.5 only applies during transfer of gasoline between any transport and any 

gasoline storage tank. Since permit condition D.6.7 serves as the compliance 

determination requirement for condition D.6.5, we request the condition be updated as 

follows - "In order to comply with Condition D.6.5, the Stage I vapor recovery systems for 

VOC control shall be in operation at all times when gasoline is being transferred, or 
St. Joseph Energy Center, LLC Page 4 of 8

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

dispensed."

Response 1: The typo in Condition D.6.7 - Volatile Organic Compounds Control has been corrected in 

the permit accordingly.

D.6.7 Volatile Organic Compounds Control

In order to comply with Condition D.6.5, the Stage I vapor recovery systems for VOC control shall 

be in operation at all times when gasoline is being transferred, or dispensed.

Comment 2: Permit Condition F.4.1(b)

Please add the following clarification - "... monitor certification requirements under section 

326 IAC 24-1-11(c)(1), 11(c)(2), or 11(c)(5) of this rule and for each control period 

thereafter."

Response 2: The rule citation has been added to Condition F.4.1(b) of the permit.

F.4.1 Nitrogen Oxides Emission Requirements [326 IAC 24-1-4(c)] [40 CFR 97.106(c)]

.......................................................................................................................................................

(b) A CAIR NOX unit shall be subject to the requirements under (a) above for the control 

period starting on the later of January 1, 2009, or the deadline for meeting the unit's 

monitor certification requirements under section 326 IAC 24-1-11(c)(1), 11(c)(2), or 

11(c)(5) of this rule and for each control period thereafter.

Comment 3: Permit Condition F.4.2(b)

Please add the following clarification - "... monitor certification requirements under 

section326 IAC 24-2-10(c)(1), 10(c)(2), or 10(c)(5) of this rule and for each control period 

thereafter."

Response 3: The rule citation has been added to Condition F.4.2(b) of the permit.

F.4.2 Sulfur Dioxide Emission Requirements [326 IAC 24-2-4(c)] [40 CFR 97.206(c)]

..........................................................................................................................................

(b) A CAIR SO2 unit shall be subject to the requirements under (a) above for the control 

period starting on the later of January 1, 2010 or the deadline for meeting the unit's 

monitor certification requirements under section 326 IAC 24-2-10(c)(1), 10(c)(2), or 

10(c)(5) of this rule and for each control period thereafter.

Comment 4: Permit Condition F.4.3(b)

Please add the following clarification - "... certification requirements under section 326 

IAC 24-3-11(c)(1), 11(c)(2), 11(c)(3), or 11(c)(7) of this rule and for each control period 

thereafter."

Response 4: The rule citation has been added to Condition F.4.3(b) of the permit.

F.4.3 Nitrogen Oxides Ozone Season Emission Requirements [326 IAC 24-3-4(c)] [40 CFR 97.306(c)]

........................................................................................................................................................

(b) A CAIR NOX unit shall be subject to the requirements under (a) above for the control 

period starting on the later of May 1, 2009 or the deadline for meeting the unit's monitor 

certification requirements under section 326 IAC 24-3-11(c)(1), 11(c)(2), 11(c)(3), or 

11(c)(7) of this rule and for each control period thereafter.
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New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

Comment 5: TSD Page 16 of 27

The PM, PM10, and PM2.5 emission limit for the CCCT is incorrectly listed as 0.0065 lb 

per MMBtu without duct firing. Per condition D.1.4(b) of the draft permit, the correct limit 

is 0.0092 lbs/MMBtu without duct firing.

Response 5: IDEM agrees, however no changes shall be made to the Technical Support Document 

(TSD) because the OAQ prefers that the TSD reflects the permit that was public noticed.

The correction is documented here as part of this addendum.

Comment 6: TSD Pages 16 and 17 of 27

As noted in conditions D.1.6, D.1.8, and D.1.9 of the draft Title V permit, the control 

requirements and emission limits for CO (item 3), VOC (item 5), and NOx (item 6) do not 

apply during startup and shutdown events.

Response 6: IDEM agrees, however no changes shall be made to the Technical Support Document 

(TSD) because the OAQ prefers that the TSD reflects the permit that was public noticed. 

Comments Received from the Public 

OAQ received comments from the following people (and groups of people) during the public 

meeting and public hearing:

Speakers Present at the Public Hearing and Public Meeting

1. Mike Campton

2. Jeff Rea

3. Robert Kovach

4. Rafael Morton

5. Donald Fozo

6. James Scheetz

7. Charles Dadlow

The summary of the comments and IDEM, OAQ responses, including changes to the permit No. 

141-31003-00579 (language deleted is shown in strikeout and language added is shown in bold) are as 

follows:

Comment 1: Which agency monitors the pipeline, please provide the contact name and information?

(Susan Jones) 

Response 1: The Indiana Utility Regulatory Commission’s Pipeline Safety Division receives federal 

authority from the U.S. Department of Transportation to conduct inspections, investigate 

incidents, and enforce federal safety regulations and state statutes and rules regarding 

natural gas pipelines. The division also monitors and evaluates regulatory and policy 

initiatives and advises the Commission about proceedings initiated by Indiana’s system 

operators. It is also responsible for educating public officials and emergency responders 

on how to recognize, report, and respond to gas-related emergencies. 

The Pipeline Safety Division’s mailing address is:

Indiana Utility Regulatory Commission

Pipeline Safety Division

101 W. Washington St, STE 1500E

Indianapolis, Indiana 46204
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New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

Steve Allen, the Pipeline Safety Director, can be reached at 317-232-2785. William "Bill" 

Boyd, the Pipeline Safety Program Manager, can be reached at 317-232-2718.

More information about the IURC’s Pipeline Safety Division can be found at 

http://www.in.gov/iurc/2335.htm on the Internet. 

Comment 2: Who within the IDEM office of Air Quality is responsible for monitoring the cumulative 

impact of these IDEM-approved operations? (Jack Daly)

Response 2: The cumulative impact of the combined emissions from all sources in the ambient air is 

monitored by IDEM’s Office of Air Quality, Air Monitoring Branch. Air quality monitoring is 

conducted at monitoring sites across the state. The monitoring sites collect ambient air 

data on an hourly basis regarding the concentration of ozone, particulate matter (PM10), 

fine particulate matter (PM2.5), oxides of nitrogen (NOx), carbon monoxide (CO), sulfur 

dioxide (SO2) and toxics. The air quality data from these monitoring sites can be viewed 

at http://www.in.gov/idem/airfacts/ on IDEM’s website. More information about the air 

quality monitoring network is available at http://www.in.gov/idem/4652.htm on IDEM’s 

website.

Comment 3: Who in the IDEM hierarchy watches that the total emission levels remain within the 

acceptable limits? (Jack Daly)

Response 3: The mission of IDEM’s Office of Air Quality is to assure all Hoosiers ambient air quality 

that meets the National Ambient Air Quality Standards. The U.S. Environmental 

Protection Agency (U.S. EPA) sets National Ambient Air Quality Standards (NAAQS) for 

six common air pollutants, also called "criteria" pollutants. The criteria pollutants are 

carbon monoxide, nitrogen dioxide, ozone, lead, particulate matter and sulfur dioxide. 

NAAQS are often referred to as federal health standards for outdoor air. More 

information about these pollutants is available at www.epa.gov/air/airpollutants.html on 

U.S. EPA’s website. The complete table of the NAAQS can be found at the 

www.epa.gov/air/criteria.html website. As described in Response 2, above, IDEM’s Office 

of Air Quality, Air Monitoring Branch, conducts ambient air monitoring that measures

whether the standards are being met

IDEM’s Office of Air Quality, Programs Branch, conducts computer modeling of ambient 

air emission levels using emission information and other data to determine if each area in 

Indiana will meet all the NAAQS. If an area is found to not meet a health standard, the 

area will be designated as a nonattainment area. The Programs Branch works with 

businesses, local governments, and the public to reduce the emissions from air emission 

sources in order to bring a nonattainment area back into attainment. These reductions are 

proposed in rulemakings before the Indiana Air Pollution Control Board. More information 

about attainment and nonattainment areas is available at 

http://www.in.gov/idem/4654.htm#howdo on IDEM’s website. More information about the 

Indiana Air Pollution Control Board and the rulemaking process is available at 

http://www.in.gov/idem/4087.htm on the Internet.

IDEM’s Office of Air Quality, Air Compliance and Enforcement Branch, uses all 

compliance tools and resources available to improve air quality by ensuring that all air 

pollution sources are in compliance with all state and federal air pollution laws, rules and 

permits. The branch determines compliance of regulated sources of air emissions by 

inspecting, monitoring, testing, and reviewing records. The branch has inspectors that 

conduct inspections, respond to complaints, provide compliance assistance to sources 

and provide input on permits and rules. The branch’s Compliance Data section reviews 

and approves stack tests and emissions monitors. All branch sections coordinate with the 

four IDEM regional offices.
St. Joseph Energy Center, LLC Page 7 of 8

New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

The air inspector for this source is Rick Reynolds. Mr. Reynolds works out of IDEM’s 

Northern Regional Office, 300 N Michigan St, Suite 450, South Bend, Indiana 46601-

1295, telephone (574) 245-4888, toll free (800) 753-5519, fax (574) 245-4877. Anyone 

concerned about a possible emission violation should contact Mr. Reynolds with their 

complaint. Environmental complaints may also be filed on-line at 

www.idem.IN.gov/5274.htm or by calling IDEM’s Complaint Coordinator at (800) 451-

6027, ext. 2-4464.

Comment 4: Who in IDEM’s Air Quality Division ensures that the date on which a decision to approve 

or deny a permit application is accurate? (Jack Daly)

Response 4: Air permit application decisions are reviewed by the Permits Branch in IDEM’s Office of Air 

Quality. The Permits Branch Chief, Matt Stuckey, ensures that the date placed on all final 

permit application decisions is accurate.

Comment 5: We are writing as the St. Joseph County Board of Commissioners in support of the St. 

Joseph Energy Center project in New Carlisle, Indiana. This is the type of project that can 

positively impact not only our local economy but the entire region as a whole.

(Robert Kovach on behalf of St. Joseph County Board of Commissioners)

Response 5: IDEM acknowledges that these comments are important to the commenter. However, 

these comments do not have any direct impact on how IDEM reviews and makes

decisions on air permit applications.

Comment 6: This project would be a very nice and well needed project for the construction industry in 

this area. (Mike Campton)

Response 6: IDEM acknowledges that these comments are important to the commenter. However, 

these comments do not have any direct impact on how IDEM reviews and makes

decisions on air permit applications.

Comment 7: The problems with air quality impact our economic development efforts in this area, so 

we feel convinced with our conversation and the time we've spent with the developers 

here, the understanding of the IDEM process, that this meets all their criteria and should 

be approved, and we would urge you to support the granting of an air permit for this 

project. (Jeff Rea)

Response 7: IDEM acknowledges that these comments are important to the commenter. However, 

these comments do not have any direct impact on how IDEM reviews and makes

decisions on air permit applications.

Comment 8: I want to say we totally support the project, pending the passing of all of the environmental 

standards. (Morton Rafael representative of the St. Joseph County Council)

Response 8: IDEM acknowledges that these comments are important to the commenter. However, 

these comments do not have any direct impact on how IDEM reviews and makes

decisions on air permit applications.

Comment 9: This project would just be a tremendous boost for not only our industry, but to this

community. We look forward to supporting it. (Donald Fozo)

Response 9: IDEM acknowledges that these comments are important to the commenter. However, 
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New Carlisle, Indiana T141-31003-00579

Permit Reviewer: Josiah Balogun

these comments do not have any direct impact on how IDEM reviews and makes

decisions on air permit applications.

Comment 10: On behalf of the Building Trade, we would like to see this project move forward and we 

hope this permit process works well. (James Scheetz on behalf of Building Trades)

Response 10: IDEM acknowledges that these comments are important to the commenter. However, 

these comments do not have any direct impact on how IDEM reviews and makes

decisions on air permit applications.

Comment 11: My biggest concern is that this project has taken three years since it's begun and I don't 

see anything happening. Somebody, I think is asleep on the job someplace along the line. 

Do you have any answer to that, why it should take so long to get a couple of permits that 

had been done ten years ago, and nothing's changed that much since ten years ago?

(Charles Dadlow)

Response 11: St. Joseph Energy Center, LLC submitted its application for this permit to IDEM on 

October 3, 2011. The area where St. Joseph Energy Center, LLC will construct this 

electrical generating plant has been the subject of a previous proposal for construction of a 

power plant. On December 7, 2001, IDEM issued an air permit to Allegheny Energy Supply 

Company LLC to construct a generating plant at this location. Construction was started on 

that plant but never completed. The Allegheny Energy construction permit expired in 2004.

Other Changes

Upon further review IDEM, OAQ has made the following changes to the Title V permit No. T141-

31003-00579. (deleted language appears as strikout and the new language bolded):

Change 1: IDEM has corrected the typo in Condition D.2.13 (d) - Testing Requirements in the permit 

accordingly.

D.2.13 Testing Requirements [326 IAC 2-1.1-11]

..........................................................................................................................................................

(d) In order to demonstrate compliance with Condition D.2.8 - VOC PSD BACT, within sixty 

(60) days of reaching maximum capacity but no later than one hundred and eighty (180) 

days after initial startup, the Permittee shall conduct VOC emissions stack testing of the 

emissions from the boilers utilizing methods as approved by the commissioner. This test

shall be performed This test shall be repeated at least once every five years from the 

date of the most recent valid compliance demonstration. Testing shall be conducted 

in accordance with the provisions of 326 IAC 3-6 (Source Sampling Procedures). Section 

C - Performance Testing contains the Permittee's obligation with regard to the 

performance testing required by this condition.
St. Joseph Energy Center, LLC Page 1 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

 

Indiana Department of Environmental Management

Office of Air Quality

Technical Support Document (TSD) for a PSD/New Source Construction

and Part 70 Permit

Source Description and Location

Source Name: St. Joseph Energy Center, LLC

Source Location: Corner of Walnut and Edison Roads, 

New Carlisle, Indiana 46552

County: St. Joseph

SIC Code: 4911

Operation Permit No.: T 141-31003-00579

Operation Permit Issuance Date: Yet to be issued

Permit Reviewer: Josiah Balogun

The Office of Air Quality (OAQ) has reviewed a New Source Construction and Part 70 operating 

permit application submitted by St. Joseph Energy Center, LLC on October 3, 2011, relating to 

construction and operation of a nominal 1,350 megawatt (MW) combined cycle combustion 

turbine (CCCT) electric generating facility (CCCT Facility).

History

St. Joseph Energy Center, LLC (SJEC) is proposing to construction and operation of a nominal 

1,350 megawatt (MW) combined cycle combustion turbine (CCCT) electric generating facility 

(CCCT Facility). The proposed CCCT Facility will consist of a nominal net 1,350 MW natural gasfired CCCT operation that includes two natural gas-fired 2x1 CCCT blocks and ancillary 

equipment to produce steam for the generation of electricity. A water treatment facility will be 

constructed on-site to supply SJEC operations. This facility will be operated by the town of New 

Carlisle, but is considered as part of the CCCT Facility for purposes of evaluating PSD air 

permitting requirements.

Existing Approvals

There have been no previous approvals issued to this source.

County Attainment Status

The source is located in St. Joseph County.

Pollutant Designation

SO2 Better than national standards.

CO Unclassifiable or attainment effective November 15, 1990.

O3 Attainment effective July 19, 2007, for the 8-hour ozone standard.1

PM10 Unclassifiable effective November 15, 1990.

NO2 Cannot be classified or better than national standards.

Pb Not designated.

1

Attainment effective October 18, 2000, for the 1-hour ozone standard for the South 

Bend-Elkhart area, including St. Joseph County, and is a maintenance area for the 1-

hour ozone National Ambient Air Quality Standards (NAAQS) for purposes of 40 CFR 

51, Subpart X*. The 1-hour standard was revoked effective June 15, 2005.
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New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Pollutant Designation

Unclassifiable or attainment effective April 5, 2005, for PM2.5.

(a) Ozone Standards

Volatile organic compounds (VOC) and Nitrogen Oxides (NOx) are regulated under the 

Clean Air Act (CAA) for the purposes of attaining and maintaining the National Ambient 

Air Quality Standards (NAAQS) for ozone. Therefore, VOC and NOx emissions are 

considered when evaluating the rule applicability relating to ozone. St. Joseph County has 

been designated as attainment or unclassifiable for ozone. Therefore, VOC and NOx 

emissions were reviewed pursuant to the requirements for Prevention of Significant 

Deterioration (PSD), 326 IAC 2-2.

(b) PM2.5

St. Joseph County has been classified as attainment for PM2.5. On May 8, 2008 U.S. 

EPA promulgated the requirements for Prevention of Significant Deterioration (PSD) for 

PM2.5 emissions. These rules became effective on July 15, 2008. On May 4, 2011 the air 

pollution control board issued an emergency rule establishing the direct PM2.5 significant 

level at ten (10) tons per year. This rule became effective, June 28, 2011. Therefore, 

direct PM2.5 and SO2 emissions were reviewed pursuant to the requirements for 

Prevention of Significant Deterioration (PSD), 326 IAC 2-2. See the State Rule 

Applicability – Entire Source section.

(c) Other Criteria Pollutants

St. Joseph County has been classified as attainment or unclassifiable in Indiana for all 

other pollutants. Therefore, these emissions were reviewed pursuant to the requirements 

for Prevention of Significant Deterioration (PSD), 326 IAC 2-2.

Fugitive Emissions

Since this source is classified as a power plant, it is considered one of the twenty-eight (28) listed 

source categories, as specified in 326 IAC 2-2, 326 IAC 2-3, or 326 IAC 2-7. Therefore, fugitive 

emissions are counted toward the determination of PSD, Emission Offset, and Part 70 Permit 

applicability.

Description of New Source and Emission Units with Control Equipment Summary

The Office of Air Quality (OAQ) has reviewed a New Source Construction application, submitted 

by St. Joseph Energy Center, LLC on October 3, 2011, relating to relating to construction and 

operation of a nominal 1,350 megawatt (MW) combined cycle combustion turbine (CCCT) electric 

generating facility (CCCT Facility). The following is a list of the proposed emission unit(s) and 

pollution control device(s): 

(a) Four (4) natural gas-fired combined cycle combustion turbines, identified as units CCCT1, 

CCCT2, CCCT3, and CCCT4, permitted in 2012, each with a combustion turbine 

equipped with dry low NOx burners, natural gas fired duct burners, and a heat recovery 

steam generator identified as HRSG1, HRSG2, HRSG3, and HRSG4, NOx emissions 

controlled by four (4) selective catalytic reduction (SCR) systems (SCR01, SCR02, 

SCR03 and SCR04), CO and VOC emissions controlled by oxidation catalyst systems

(CAT01, CAT02, CAT03 and CAT04) and exhausting to stacks CCCT01, CCCT02, 

CCCT03, and CCCT04, respectively. Each stack has continuous emissions monitors 

(CEMS) for NOx and CO. The nominal heat input for each CCCT is 2,300 MMBtu/hr 

(higher heating value (HHV)). The combined nominal power output is 1,350 megawatts 

(MW). 

*Note: The heat recovery steam generators are not a source of emissions. They have 

been included for clarity as they are a part of the entire source and operate in 

conjunction with the duct burners which are a source of emissions.
St. Joseph Energy Center, LLC Page 3 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(b) Two (2) natural gas fired auxiliary boilers, identified as B001 and B002, permitted in 2012, 

each, with a maximum heat input capacity of 80 MMBtu/hr (HHV), equipped with low NOx 

burners (LNB) with flue gas recirculation (FGR) to reduce NOx emissions, and exhausting 

to stacks B001 and B002. Under 40 CFR Part 60, Subpart Dc, the auxiliary boiler is 

considered a steam generating unit.

(c) One (1) emergency diesel generator, nominally rated at 2012 horsepower, identified as 

EG03, permitted in 2012, exhausting through one (1) vent, identified as EG03. [Under 40 

CFR 60, Subpart IIII, the emergency diesel fired generator is considered a new affected 

source.][Under 40 CFR 63, Subpart ZZZZ, the emergency diesel fired generator is 

considered a new affected source.]

Insignificant and Trivial Activities 

The source also consists of the following insignificant activities as defined in 326 IAC 2-7-1(21):

(a) Two (2) firewater pump engines, each nominally rated at 371 brake horsepower (bph) and 

identified as FP01 and FP02, permitted in 2012, exhausting through two (2) vents, 

identified as FP01 and FP02, respectively. [Under 40 CFR 60, Subpart IIII, the firewater 

pump engines are considered new affected sources.][Under 40 CFR 63, Subpart ZZZZ, 

the firewater pump engines are considered new affected sources.]

(b) Two (2) emergency diesel generators, each nominally rated at 1,006 horsepower, 

identified as EG01 and EG02, permitted in 2012, exhausting through two (2) vents, 

identified as EG01 and EG02, respectively. [Under 40 CFR 60, Subpart IIII, the 

emergency diesel fired generators are considered new affected sources.][Under 40 CFR 

63, Subpart ZZZZ, the emergency diesel fired generators are considered new affected 

source.]

(c) Two (2) cooling towers, each nominally rated with a circulation rate of 170,000 gpm , 

identified as CT01 and CT02, permitted in 2012, with high efficiency drift/mist eliminators, 

and exhausting through ten vents each, identified as CT01A – CT01J and CT02A –

CT02J.

(d) Six (6) Turbine Lube Demister Vents, identified as DM01 - DM06, permitted in 2012, 

exhausting through vents DM01 – DM06.

(e) Six (6) Turbine Lube Oil storage tanks, identified as TK01 - TK06, permitted in 2012, each 

with a nominal capacity of 6,800 gallons.

(f) Two (2) Emergency Generator ULSD Tanks, identified as TK07 and TK08, permitted in 

2012, each with a nominal capacity of 550 gallons.

(g) Two (2) Fire Pump Engine ULSD Tanks, identified as TK09 and TK10, permitted in 2012, 

each with a nominal capacity of 70 gallons.

(h) One (1) Vehicle Gasoline Tank, identified as TK11, permitted in 2012, with a nominal 

capacity of 650 gallons.

(i) One (1) Vehicle Diesel Tank, identified as TK12, permitted in 2012, with a nominal 

capacity of 650 gallons.

(j) One (1) Emergency Generator ULSD Tank, identified as TK50, permitted in 2012, with a 

nominal capacity of 300 gallons.

(k) two (2) lime storage silos, capable of handling a maximum loading rate of 20 tons per 

hour combined, permitted in 2012 and with particulate matter controlled by bin vent filters

exhausting to Stacks S1 and S2; 
St. Joseph Energy Center, LLC Page 4 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(l) Six (6) Electrical Circuit Breakers containing sulfur hexafluoride (SF6) identified as 

emissions unit SF6, permitted in 2012, with fugitive GHG emissions.

(m) Space heaters, process heaters, or boilers using the following fuels: Natural gas-fired 

combustion sources with heat input equal to or less than ten million (10,000,000) Btu per 

hour.

(n) The following VOC and HAP storage containers: Vessels storing lubricating oils, hydraulic 

oils, and machining oils.

(o) Application of the following as temporary protective coatings: greases, lubricants, 

nonvolatile materials, and oils.

(p) Degreasing operations that do not exceed one hundred forty-five (145) gallons per 12 

months, except if subject to 326 IAC 20-6. [326 IAC 8-3];

(q) Cleaners and solvents characterized as follows where the use of which, for all cleaners 

and solvents combined, does not exceed one hundred forty-five (145) gallons per 12 

months:

(1) Having a vapor pressure equal to or less than 2 kPa; 15 mm Hg; or 0.3 psi 

measured at 38 degrees C (100O

F) or;

(2) Having a vapor pressure equal to or less than 0.7 kPa; 5 mm Hg; or 0.1 psi 

measured at 20OC (68OF); 

(r) Closed loop heating and cooling systems.

(s) Activities associated with the treatment of wastewater streams with an oil and grease 

content less than or equal to 1% by volume.

(t) Any operation using aqueous solutons containing less than one percent (1%) by weight of 

VOCs excluding HAPs.

(u) Heat exchanger cleaning and repair.

(v) Routine maintenance and repair of buildings, structure, or vehicles at the source where air 

emissions from those activities would not be associated with any production process, 

including the following: Purging of gas lines and Purging of vessels.

(w) Flue gas conditioning systems and associated chemicals such as the following: Ammonia.

(x) Blowdown for any of the following: sight glass; boiler; compressors; pumps; and cooling 

tower.

(y) Paved and unpaved roads and parking lots with public access. [326 IAC 6-4]

(z) Grinding and machining operations controlled with fabric filters, scrubbers, mist collectors, 

wet collectors and electrostatic precipitators with a design grain loading of less than or 

equal to 0.03 grains per actual cubic foot and a gas flow rate less than or equal to 4000 

actual cubic feet per minute, including the following: deburring; buffing; polishing; abrasive 

blasting; pneumatic conveying; and woodworking operations. [326 IAC 6-3]

Enforcement Issues

There are no pending enforcement actions.
St. Joseph Energy Center, LLC Page 5 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Emission Calculations

See Appendix A of this Technical Support Document for detailed emission calculations.

Unrestricted Potential Emissions

Pursuant to 326 IAC 2-1.1-1(10), Potential to Emit is defined as “the maximum capacity of a 

stationary source or emission unit to emit any air pollutant under its physical and operational 

design. Any physical or operational limitation on the capacity of a source to emit an air pollutant, 

including air pollution control equipment and restrictions on hours of operation or type or amount 

of material combusted, stored, or processed shall be treated as part of its design if the limitation is 

enforceable by the U. S. EPA, IDEM, or the appropriate local air pollution control agency.” 

The following table is used to determine the appropriate permit level under 326 IAC 2-7-10.5. This 

table reflects the PTE before controls. Control equipment is not considered federally enforceable 

until it has been required in a federally enforceable permit.

Unrestricted Potential Emissions

Pollutant Tons/year

PM 329

PM10 326

PM2.5 321

SO2 102

VOC 137.4

CO 1032.70

NOx 1465.60

GHGs as CO2e 4,820,312

Pb 0.00016

H2SO4 78.76

HAPs tons/year

Acetaldehyde 1.68

Acrolein 0.22

Benzene 0.52

Ethylbenzene 0.90

Formaldehyde 6.82

Hexane 0.57

Lead 0.00016

Propylene Oxide 1.12

Toluene 2.66

Xylenes 2.54

Other HAPs < 0.04

Total 17.07

(a) The potential to emit (as defined in 326 IAC 2-7-1(30)) of PM10, PM2.5, SO2, VOC, CO 

and NOx are equal to or greater than 100 tons per year. Therefore, the source is subject 

to the provisions of 326 IAC 2-7 and will be issued a Part 70 Operating Permit Renewal. 
St. Joseph Energy Center, LLC Page 6 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(b) The potential to emit (as defined in 326 IAC 2-7-1(30)) of GHGs is equal to or greater than 

one hundred thousand (100,000) tons of CO2 equivalent emissions (CO2e) per year. 

Therefore, the source is subject to the provisions of 326 IAC 2-7 and will be issued a Part 

70 Operating Permit Renewal. 

(c) The potential to emit (as defined in 326 IAC 2-7-1(30)) of any single HAP is less than ten 

(10) tons per year and the potential to emit (as defined in 326 IAC 2-7-1(30)) of a 

combination of HAPs is less than twenty-five (25) tons per year.

Actual Emissions

No previous emission data has been received from the source.

Part 70 Permit Conditions

This source is subject to the requirements of 326 IAC 2-7, because the source met the following:

(a) Emission limitations and standards, including those operational requirements and 

limitations that assure compliance with all applicable requirements at the time of issuance 

of Part 70 permits.

(b) Monitoring and related record keeping requirements which assume that all reasonable 

information is provided to evaluate continuous compliance with the applicable 

requirements.
St. Joseph Energy Center, LLC Page 7 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Potential to Emit After Issuance

The table below summarizes the potential to emit, reflecting all limits, of the emission units at the St. Joseph Energy Center, LLC. Any new control 

equipment is considered federally enforceable only after issuance of this Part 70 permit, and only to the extent that the effect of the control 

equipment is made practically enforceable in the permit.

Process/

Emission Unit

Potential To Emit (tons/year)

PM PM10* PM2.5** SO2 VOC CO NOx

H2SO

4 NH3 SF6 CH4 N2O CO2

GHGs as 

CO2e

HAPs

Combustion 

Turbine CCCT1 78.8 78.8 78.8 24.97 24.97 130 71.8 19.7 69.4 0 21.7 2.17 1,183,104 1,184,234 3.09

Combustion 

Turbine CCCT2 78.8 78.8 78.8 24.97 24.97 130 71.8 19.7 69.4 0 21.7 2.17 1,183,104 1,184,234 3.09

Combustion 

Turbine CCCT3 78.8 78.8 78.8 24.97 24.97 130 71.8 19.7 69.4 0 21.7 2.17 1,183,104 1,184,234 3.09

Combustion 

Turbine CCCT4 78.8 78.8 78.8 24.97 24.97 130 71.8 19.7 69.4 0 21.7 2.17 1,183,104 1,184,234 3.09

Aux. Boiler 

B001 2.63 2.63 2.63 0.77 1.75 28.91 10.99 0 0 0 0.77 0.08 40,958 40,998 0.3

Aux. Boiler 

B002 2.63 2.63 2.63 0.77 1.75 28.91 10.99 0 0 0 0.77 0.08 40,958 40,998 0.3

Cooling Tower 

CT01 3.73 2.37 0.01 0 0 0 0 0 0 0 0 0 0 0 0

Cooling Tower 

CT02 3.73 2.37 0.01 0 0 0 0 0 0 0 0 0 0 0 0

Firewater Pump 

FP01 0.03 0.03 0.03 0.19 0.03 0.43 0.5 0 0 0 0.003 0.001 86 86 0.0025

Firewater Pump 

PF02 0.03 0.03 0.03 0.19 0.03 0.43 0.5 0 0 0 0.003 0.001 86 86 0.0025

Emergency 

Gen. EG01 0.08 0.08 0.08 0 0.05 1.45 2.65 0 0 0 0.01 0.002 229 300 0.003

Emergency 

Gen. EG02 0.08 0.08 0.08 0 0.05 1.45 2.65 0 0 0 0.01 0.002 229 300 0.003

Emergency 

Gen. EG03 0.03 0.03 0.03 0.01 0.12 0.49 0.64 0 0 0 0.02 0.005 584 586 0.01
St. Joseph Energy Center, LLC Page 8 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Process/

Emission Unit

Potential To Emit (tons/year)

PM PM10* PM2.5** SO2 VOC CO NOx

H2SO

4 NH3 SF6 CH4 N2O CO2

GHGs as 

CO2e

HAPs

Turbine Lube Oil

Demister Vents 

DM01 – DM06

0.35 0.35 0.35 0 0.35 0 0 0 0 0 0

0 0 0 0

Storage Tanks 0 0 0 0 0.11 0 0 0 0 0 0 0 0 0 0

Six (6) Circuit 

Breakers 0 0 0 0 0 0 0 0 0 0.0009 0 0 0 22 0

Two (2) Lime 

Silos 0.11 0.11 0.11 0 0 0 0 0 0 0 0 0 0 0 0

Total Emission 

for New Source 

Construction

329 326 321 102 104 582 316 79 277 0.0009 89 8.9 4,815,686 4,820,312 12.98

Title V Major 

Source 

Thresholds

NA 100 100 100 100 100 100 -- -- -- -- -- --

100,000 

CO2e

10/25

Significant Level 25 15 10 40 40 100 40 7 -- -- -- -- --

75,000 

CO2e

---

negl. = negligible

*Under the Part 70 Permit program (40 CFR 70), particulate matter with an aerodynamic diameter less than or equal to a nominal 10 micrometers (PM10), not 

particulate matter (PM), is considered as a "regulated air pollutant".

**PM2.5 listed is direct PM2.5.

This new stationary source is a major stationary source, under PSD (236 IAC 2-2), because a regulated pollutant is emitted at a rate of 100 

tons per year or more, emissions of GHGs are equal to or greater than one hundred thousand (> 100,000) tons of CO2 equivalent 

emissions (CO2e) per year, which is greater than the PSD threshold and it is one of the twenty-eight (28) listed source categories, as 

specified in 326 IAC 2-2-1(ff)(1). Therefore, pursuant to 326 IAC 2-2, the PSD requirements do apply to the new source.
St. Joseph Energy Center, LLC Page 9 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Federal Rule Applicability

(a) Pursuant to 40 CFR 64.2, Compliance Assurance Monitoring (CAM) is applicable to each 

existing pollutant-specific emission unit that meets the following criteria:

(1) has a potential to emit before controls equal to or greater than the major source 

threshold for the pollutant involved;

(2) is subject to an emission limitation or standard for that pollutant; and

(3) uses a control device, as defined in 40 CFR 64.1, to comply with that emission 

limitation or standard.

The following table is used to identify the applicability of each of the criteria, under 40 CFR 64.1, to 

each existing emission unit and specified pollutant subject to CAM:

Emission Unit / 

Pollutant

Control

Device

Used

Emission

Limitation

(Y/N)

Uncontrolled

PTE

(tons/year)

Controlled

PTE

(tons/year)

Major

Source

Threshold

(tons/year)

CAM 

Applicable 

(Y/N)

Large

Unit

(Y/N)

Combustion 

Turbine CCCT1 

(CO)

Y Y 242.65 130.03 100 Y Y

Combustion 

Turbine CCCT2 

(CO)

Y Y 242.65 130.03 100 Y Y

Combustion 

Turbine CCCT3 

(CO)

Y Y 242.65 130.03 100 Y Y

Combustion 

Turbine CCCT4 

(CO)

Y Y 242.65 130.03 100 Y Y

Combustion 

Turbine CCCT1 

(NOx)

Y Y 359.16 71.83 100 Y N

Combustion 

Turbine CCCT2 

(NOx)

Y Y 359.16 71.83 100 Y N

Combustion 

Turbine CCCT3 

(NOx)

Y Y 359.16 71.83 100 Y N

Combustion 

Turbine CCCT4 

(NOx)

Y Y 359.16 71.83 100 Y N

The CCCTs have pre-controlled emissions greater than 100 tpy for NOX and CO and will utilize 

SCR to control NOX emissions and oxidation catalyst to control CO emissions in order to meet 

federally enforceable BACT emission limits. Compliance with these limits will be demonstrated 

through use of NOx and CO CEMS. Upon incorporation into a Title V permit, the use of CEMS is 

considered a continuous compliance determination method. Therefore, the BACT limits for NOx

and CO are exempt from CAM in accordance with 40 CFR 64.2(b)(1)(vi). The only other PSDregulated pollutant from the CCCTs utilizing a control device to meet an emission limit is VOC. 

However, pre-controlled emissions of VOC will not exceed 100 tpy, and will not be subject to 

CAM.
St. Joseph Energy Center, LLC Page 10 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

All other units at the CCCT Facility have pre-controlled emissions less than the major source 

threshold and/or do not use a control device as defined by the CAM regulations.

Based on this evaluation, the requirements of 40 CFR Part 64, CAM is not applicable to any 

emission units as part of this Part 70 operating permit.

(b) The requirements of Standards of Performance for Fossil-Fuel Fired Steam Generators 

for which construction is commenced after August 17, 1971, 40 CFR 60, Subpart D is not 

applicable to any sources in this project. The requirements of this rule apply to steamgenerating units that commence construction, modification, or reconstruction after August 

17, 1971, and that have a heat input capacity from fuels combusted in the steam 

generating unit of greater than 73 MW (250 million Btu/hour). The auxiliary boilers have a 

heat input capacity less than 250 MMBtu/hr, each; therefore, the auxiliary boilers are 

exempt from the requirements of NSPS Subpart D.

(c) The requirements of Standards of Performance for Electric Utility Steam Generating Units 

for which construction is commenced after September 18, 1978, 40 CFR 60, Subpart Da 

(NSPS Da) applies to certain electric utility steam generating units (EUSGU). EUSGU is 

defined as any steam electric generating unit that is constructed to supply more than onethird of its potential electric output capacity (PEOC) and 25 MW net electric output to a 

utility power distribution system for sale (40 CFR 60.41Da). EUSGU that are capable of 

combusting more than 250 MMBtu/hr of fossil fuel and that commence construction or 

modification after September 18, 1978, are subject to NSPS Da unless exempted [40 

CFR 60.40Da(a)]. Furthermore, under 40 CFR 60.40Da(e)(1), HRSGs used with duct 

burners and associated with electric utility combined cycle gas turbines that are capable 

of combusting more than 250 MMBtu/hr of fossil fuel are subject to NSPS Da unless the 

HRSG meets the applicability requirements and is subject to NSPS KKKK. The HRSG 

meets the applicability requirements and is subject to NSPS KKKK. Therefore, the 

proposed duct burners are not subject to the requirements of NSPS Da. 

(d) The requirements of the New Source Performance Standard, 40 CFR 60, Subpart Db, 

Standard of Performance for Industrial -Commercial-Institutional Steam Generating Units, 

which is incorporated by reference as 326 IAC 12, applies to each steam generating unit 

with a heat input capacity greater than 100 MMBtu/hr unless the unit meets any of the 

exemptions identified in 40 CFR 60.40Db. Per 40 CFR 60.40Db(i), HRSGs that are 

associated with combined cycle gas turbines and that meet the applicability requirements 

of NSPS KKKK are not subject to NSPS Subpart Db. The proposed duct burners have a 

heat input capacity greater than 100 MMBtu/hr, but the HRSGs are associated with 

combined cycle gas turbines and meet the applicability requirements of NSPS KKKK. 

Therefore, the proposed duct burners are not subject to the requirements of NSPS Db.

(e) The requirements of the New Source Performance Standard, 40 CFR 60, Subpart GG, 

Standard of Performance for Stationary Gas Turbines apply to combustion turbines 

constructed or modified after October 3, 1977, with heat input equal to or greater than 10 

MMBtu/hr [40 CFR 60.330]. However, NSPS GG has been supplanted by a newer 

subpart (NSPS KKKK) that exempts subject units from NSPS GG [40 CFR 60.4305(b)]. 

The CCCTs at SJEC are subject to the requirements of NSPS KKKK and are, therefore, 

exempt from NSPS GG.

(f) The requirements of Standards of Performance for Volatile Organic Liquid Storage 

Vessels (including Petroleum Liquid Storage Vessels) for Which Construction, 

Reconstruction, or Modification Commenced after July 23, 1984, 40 CFR 60, Subpart Kb, 

regulates storage vessels with a capacity greater than 75 cubic meters (m3

) 

(19,813 gallons) that are used to store volatile organic liquids for which construction, 

reconstruction, or modification is commenced after July 23, 1984 [40 CFR 60.110b(a)]. 

The various lubrication oil, gasoline, and diesel storage tanks at the proposed CCCT 

Facility have capacities less than 19,813 gallons. Therefore, these storage tanks are not 

subject to the requirements of this subpart. The materials stored in the water treatment 

storage tanks (i.e., sulfuric acid solution, sodium hypochlorite solution, and ammonia 
St. Joseph Energy Center, LLC Page 11 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

solution) do not meet the definition of a volatile organic liquids per 40 CFR 60.111b. 

Therefore, no tanks at the proposed SJEC Facility are subject to the requirements of 

NSPS Kb. 

(g) The requirements of National Emission Standards for Hazardous Air Pollutants for 

Stationary Combustion Turbines, 40 CFR 63, Subpart YYYY establishes emission and 

operating limitations for HAP emitted from stationary combustion turbines located at 

major sources of HAP emissions. SJEC will be an area source of HAP and as such is not 

subject to this standard.

(h) The requirements of National Emission Standards for Hazardous Air Pollutants for

Industrial Process Cooling Towers 40 CFR 63 Subpart Q for Industrial Process Cooling 

Towers, applies to cooling towers operating with chromium-based water treatment 

chemicals that are either major sources of HAP or are integral parts of a facility that is a 

major source of HAP. The only requirement for affected sources is to utilize water 

treatment chemicals that are not chromium based. The new cooling tower water 

treatment chemicals will not be chromium based, so this regulation will not apply to the 

proposed cooling towers. 

(i) The requirements of Area Source MACT - National Emission Standards for Hazardous Air 

Pollutants – Industrial, Commercial, and Institutional Boilers at Area Sources 40 CFR Part 

63 Subpart JJJJJJ regulates HAP emissions from industrial, commercial, and institutional 

boilers at area sources of HAP. Pursuant to 40 CFR 63.11195(e), gas-fired boilers are not 

subject to any requirements. Therefore, the proposed auxiliary boilers at SJEC will not 

have any applicable requirements under this standard.

(j) The requirements of the New Source Performance Standard, 40 CFR 60, Subpart Dc, 

Standard of Performance for Small -Commercial-Institutional Steam Generating Units, 

which is incorporated by reference as 326 IAC 12 NSPS, applies to steam generating 

units constructed or modified after June 9, 1989, with heat input equal to or greater than 

10 MMBtu/hr but less than 100 MMBtu/hr [40 CFR 60.40c(a)]. A steam generating unit is

defined as a device that combusts any fuel that is used to heat an indirect heat transfer 

medium [40 CFR 60.41c].

The proposed CCCT Facility will include auxiliary boilers with a maximum heat input 

capacity of 80 MMBtu/hr each. Since the auxiliary boilers combust natural gas to heat a 

heat transfer medium, the boilers meet the definition of steam generating units and are

regulated by NSPS Dc.

The auxiliary boilers will fire only natural gas. Pursuant to 40 CFR 60.42c, NSPS Dc SO2

emission limitations are not specified for affected sources that combust only natural gas 

(as defined in 40 CFR 60.41c). Similarly, pursuant to 40 CFR 60.43c, NSPS Dc PM 

emission limitations are not specified for affected sources that combust only natural gas. 

As such, NSPS Dc SO2 and PM emission limitations do not apply to the auxiliary boilers. 

Pursuant to 40 CFR 60.48c(g)(2), affected sources that combust only natural gas are 

required to record and maintain records of the amount of natural gas combusted during 

each calendar month. According to 40 CFR 60.48c(i), the monthly fuel usage records 

must be maintained for a minimum of two (2) years.

These emission units are subject to the following portions of Subpart Dc: 

(1) Two (2) natural gas fired auxiliary boilers, identified as B001 and B002, permitted 

in 2012, each, with a maximum heat input capacity of 80 MMBtu/hr (HHV), 

equipped with low NOx burners (LNB) with flue gas recirculation (FGR) to reduce 

NOx emissions, and exhausting to stacks B001 and B002. Under 40 CFR Part 

60, Subpart Dc, the auxiliary boiler is considered a steam generating unit.
St. Joseph Energy Center, LLC Page 12 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

The auxiliary boilers are subject to the following Sections of 40 CFR Part 60, Subpart Dc.

1. 40 CFR 60.40c(a)-(d)

2. 40 CFR 60.41c

3. 40 CFR 60.48c(a)(1), (3)

4. 40 CFR 60.48c(g),(i) 

The provisions of 40 CFR 60 Subpart A – General Provisions, which are incorporated as 

326 IAC 12-1, apply to the facilities described in this section except when otherwise 

specified in 40 CFR 60 Subpart Dc.

(k) The requirements of 40 CFR, Subpart IIII - Standard of Performance for Stationary 

Compression Ignition Internal Combustion Engines 40 CFR 60, apply to owners or 

operators of stationary compression ignition (CI) internal combustion engines (ICE) that 

commence construction after July 11, 2005, and that were manufactured after April 1, 

2006, and are not fire pump engines, or were manufactured as a certified National Fire 

Protection Association (NFPA) fire pump engine after July 1, 2006. 

SJEC proposes to install two nominal 371 bhp fire pump engines and two nominal 750 

kW emergency generators that will combust ULSD that will be subject to the provisions of 

NSPS IIII. In addition, a nominal 1,500 kW emergency generator that will combust ULSD 

will be installed at the water treatment plant and will be subject to the provisions of this 

rule.

In accordance with 40 CFR 60.4205(b), owners and operators of 2007 model year and 

later emergency stationary CI ICE with a displacement of less than 30 litres per cylinder 

that are not fire pumps must comply with the emission standards for new CI engines in 40 

CFR 60.4202. In accordance with 40 CFR 60.4202(a)(2), engines manufactured after 

2007 with displacement less than 10 litres per cylinder and with a maximum engine power 

greater than or equal to 37 kilowatts (kw) (50 bhp) and less than or equal to 2,237 kw 

(3,000 bhp) must comply with the certification emission standards in 40 CFR 89.112, 

Table 1 (Tier 2 requirements for engines > 560 kW after 2006), and the opacity standards 

in 40 CFR 89.113. Note that constant-speed engines are exempt from the opacity 

standards. As provided in 40 CFR 60.4211(c), to demonstrate compliance with these 

emission standards, SJEC will purchase an emergency generator certified to the Tier 2 

emission limits, and install and configure the engine according to the manufacturer’s 

specifications.

In accordance with 40 CFR 60.4205(c), owners and operators of fire pump engines with a 

displacement of less than 30 litres per cylinder must comply with the emission standards 

in Table 4 of NSPS IIII for all pollutants. As provided in 40 CFR 60.4211(c), to 

demonstrate compliance with these emission standards, SJEC will purchase a fire pump 

engine certified to the emission limits listed in Table 4 of NSPS IIII, and install and 

configure the engine according to the manufacturer’s specifications. 

Both the emergency generators and fire pumps must utilize nonroad diesel fuel with a 

sulfur content less than or equal to 15 parts per million (ppm). The fuel must also have 

either a minimum cetane index of 40 or a maximum aromatic content of 35 volume 

percent (per 40 CFR 60.4207(b) and 40 CFR 80.510(b)).

These emission units are subject to the following portions of Subpart IIII: 

(1) Two (2) firewater pump engines, each nominally rated at 371 brake horsepower 

(bph)and identified as FP01 and FP02, permitted in 2012, exhausting through two 

(2) vents, identified as FP01 and FP02, respectively. [Under 40 CFR 60, Subpart 

IIII, the firewater pump engines are considered new affected sources.][Under 40 

CFR 63, Subpart ZZZZ, the firewater pump engines are considered new affected 

sources.]
St. Joseph Energy Center, LLC Page 13 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

The firewater pump engines are subject to the following Sections of 40 CFR Part 60, 

Subpart IIII.

1. 40 CFR 60.4200(a)(2)(ii)

2. 40 CFR 60.4205(c)

3. 40 CFR 60.4206

4. 401 CFR 60.4207

5. 40 CFR 60.4211(a), (c)

6. 40 CFR 60.4218

7. 401 CFR 60.4219

These emission units are subject to the following portions of Subpart IIII: 

(1) Two (2) emergency diesel generators, each nominally rated at 1,006 horsepower, 

identified as EG01 and EG02, permitted in 2012, exhausting through two (2) 

vents, identified as EG01 and EG02, respectively. [Under 40 CFR 60, Subpart IIII, 

the emergency diesel fired generators are considered new affected 

sources.][Under 40 CFR 63, Subpart ZZZZ, the emergency diesel fired 

generators are considered new affected source.]

(2) One (1) emergency diesel generator, nominally rated at 2012 horsepower, 

identified as EG03, permitted in 2012, exhausting through one (1) vent, identified 

as EG03. [Under 40 CFR 60, Subpart IIII, the emergency diesel fired generator is 

considered a new affected source.][Under 40 CFR 63, Subpart ZZZZ, the 

emergency diesel fired generator is considered a new affected source.]

The emergency diesel generators are subject to the following Sections of 40 CFR Part 60, 

Subpart IIII.

1. 40 CFR 60.4200(a)(2)(i)

2. 40 CFR 60.4205(b)

3. 40 CFR 60.4206

4. 401 CFR 60.4207

5. 40 CFR 60.4211(a), (c)

6. 40 CFR 60.4218

7. 401 CFR 60.4219

The provisions of 40 CFR 60 Subpart A – General Provisions, which are incorporated as 

326 IAC 12-1, apply to the facilities described in this section except when otherwise 

specified in 40 CFR 60 Subpart IIII.

(l) The requirements of the New Source Performance Standard of Performance for 

Stationary Combustion Turbines, 40 CFR 60, Subpart KKKK applies to combustion 

turbines constructed, modified, or reconstructed after February 18, 2005, with heat input 

equal to or greater than 10 MMBtu/hr based on the higher heating value of the fuel [40 

CFR 60.4305(a)]. The heat input from associated HRSGs and duct burners is not 

included in the applicability determination; however, the subpart applies to emissions from 

the combustion turbines, HRSGs, and duct burners if the heat input of the combustion 

turbines exceeds 10 MMBtu/hr. The proposed combustion turbines for SJEC have peak 

heat inputs greater than 10 MMBtu/hr. Therefore, the combustion turbines, HRSGs, and 

duct burners are subject to the requirements of 40 CFR 60, Subpart KKKK. 

These emission units are subject to the following portions of Subpart KKKK: 

(1) Four (4) natural gas-fired combined cycle combustion turbines, identified as units 

CCCT1, CCCT2, CCCT3, and CCCT4, permitted in 2012, each with a 

combustion turbine equipped with dry low NOx burners, natural gas fired duct 

burners, and a heat recovery steam generator identified as HRSG1, HRSG2, 

HRSG3, and HRSG4, NOx emissions controlled by four (4) selective catalytic 
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New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

reduction (SCR) systems (SCR01, SCR02, SCR03 and SCR04), CO and VOC 

emissions controlled by oxidation catalyst systems (CAT01, CAT02, CAT03 and 

CAT04) and exhausting to stacks CCCT01, CCCT02, CCCT03, and CCCT04, 

respectively. Each stack has continuous emissions monitors (CEMS) for NOx 

and CO. The nominal heat input for each CCCT is 2,300 MMBtu/hr (higher 

heating value (HHV)). The combined nominal power output is 1,350 megawatts 

(MW). 

*Note: The heat recovery steam generators are not a source of emissions. They have 

been included for clarity as they are a part of the entire source and operate in 

conjunction with the duct burners which are a source of emissions.

The combustion turbines, HRSGs and duct burners are subject to the following Sections 

of 40 CFR Part 60, Subpart KKKK.

1. 40 CFR 60.4300

2. 40 CFR 60.4305

3. 40 CFR 60.4320

4. 40 CFR 60.4330(a)(1) or (2)

5. 40 CFR 60.4333

6. 40 CFR 60.4340(b)(1)

7. 40 CFR 60.4345

8. 40 CFR 60.4350(a)-(e), (f)(1)-(2), (h)

9. 40 CFR 60.4360

10. 40 CFR 60.4365

11. 40 CFR 60.4370(b), (c)

12. 40 CFR 60.4375(a)

13. 40 CFR 60.4380(b)

14. 40 CFR 60.4385(a), (c)

15. 40 CFR 60.4395

16. 40 CFR 60.4400(a), (b)(2), (b)(4)-(6)

17. 40 CFR 60.4405

18. 40 CFR 60.4415

19. 40 CFR 60.4420

The provisions of 40 CFR 60 Subpart A – General Provisions, which are incorporated as 

326 IAC 12-1, apply to the facilities described in this section except when otherwise 

specified in 40 CFR 60 Subpart KKKK.

(m) The requirements of National Emission Standards for Hazardous Air Pollutants for 

Stationary Reciprocating Internal Combustion Engines (NESHAPs) (326 IAC 20 and 40 

CFR Part 63 Subpart ZZZZ) apply to the emergency generators. These Standards apply

to stationary reciprocating internal combusting engines (RICE) that are located at facilities 

that are major and area sources of HAPs. The specific facilities subject to this rule 

includes the following.

(1) Two (2) emergency diesel generators, each nominally rated at 1,006 horsepower, 

identified as EG01 and EG02, permitted in 2012, exhausting through two (2) 

vents, identified as EG01 and EG02, respectively. [Under 40 CFR 60, Subpart IIII, 

the emergency diesel fired generators are considered new affected 

sources.][Under 40 CFR 63, Subpart ZZZZ, the emergency diesel fired 

generators are considered new affected source.]

(1) One (1) emergency diesel generator, nominally rated at 2012 horsepower, 

identified as EG03, permitted in 2012, exhausting through one (1) vent, identified 

as EG03. [Under 40 CFR 60, Subpart IIII, the emergency diesel fired generator is 

considered a new affected source.][Under 40 CFR 63, Subpart ZZZZ, the 

emergency diesel fired generator is considered a new affected source.]
St. Joseph Energy Center, LLC Page 15 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

These emission units are subject to the following portions of Subpart ZZZZ: 

1. 40 CFR 63.6580

2. 40 CFR 63.6585(a), (c)-(d)

3. 40 CFR 63.6590(a)(2)(iii)

4. 40 CFR 63.6590(c)(1)

5. 40 CFR 63.6665

6. 40 CFR 63.6670

7. 40 CFR 63.6675

The provisions of 40 CFR 63 Subpart A – General Provisions, which are incorporated as 

326 IAC 20-1-1, apply to the facilities described in this section except when otherwise 

specified in 40 CFR 63 Subpart ZZZZ.

(n) 40 CFR Part 68 Risk Management Program 

The Risk Management Program (RMP) in Section 112(r) of the 1990 Clean Air Act 

Amendments was established to prevent accidental releases of hazardous substances. 

Applicability of the RMP program is determined by comparing the quantity of each 

hazardous material stored in a vessel to the 112(r) threshold quantity. 

There is a 112(r) threshold quantity for ammonia with a concentration of 20 percent or 

greater per 40 CFR 68.130. The proposed CCCT Facility will install and operate two (2) 

30,000 gallon tanks storing a 19 percent ammonia solution. The CCCT Facility is not 

proposing to utilize any other 112(r) regulated substances. Therefore, the CCCT Facility 

is not subject to the requirements of the RMP program.

(o) 40 CFR Part 70 Title V Operating Permit Program 

40 CFR 70 establishes the federal Title V operating permit program. Indiana has 

incorporated the provisions of the federal program in 326 IAC 2-7. The major source 

thresholds with respect to the Indiana Title V operating permit program for sources in 

attainment areas are 10 tpy of a single HAP, 25 tpy of any combination of HAP, 100 tpy of 

a criteria pollutant, or 100,000 tpy of GHG, expressed as CO2e. 

With emissions greater than the major source thresholds for criteria pollutants and GHG, 

SJEC will require a Title V permit. Under this submittal, SJEC is requesting a combined 

Title V permit for the CCCT facility and the associated on-site water treatment plant.

 (p) 40 CFR Part 72-78 Acid Rain Program 

The Acid Rain Program (ARP) found at 40 CFR 72-78 applies to utility units. A utility unit 

is defined as a unit owned or operated by a utility that serves a generator in any state that 

produces electricity for sale. The CCCTs at the proposed facility are utility units subject to 

the ARP. The proposed auxiliary boilers do not provide steam that subsequently 

generates electricity from the steam turbines; thus, the boilers cannot generate electricity 

for sale and are not subject to the ARP. The ARP requires pollutant monitors in addition to

possession of SO2 allowances for each ton of SO2 emitted. Possession of the SO2

allowances is not required until after the end of the year in which the SO2 is emitted. 

Therefore, this source is subject to the requirements of 326 IAC 21 and shall submit an 

application for a significant permit modification for the incorporation of the requirements of 

326 IAC 21. Operation of CCCT1 - CCCT4 shall not be permitted until the Acid Rain 

Permit has been issued.

(q) 40 CFR Part 82 Stratospheric Ozone Protection Regulations 

The requirements originating from Title VI of the Clean Air Act, entitled Protection of 

Stratospheric Ozone, are contained in 40 CFR 82. Subparts A through E and Subparts G 

through I of 40 CFR 82 are not applicable to SJEC. 40 CFR 82, Subpart F, Recycling and 

Emissions Reduction, potentially applies if the facility operates, maintains, repairs, 

services, or disposes of appliances that utilize Class I or Class II ozone depleting 

substances. Subpart F generally requires persons completing the repairs, service, or 
St. Joseph Energy Center, LLC Page 16 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

disposal to be properly certified. All repairs, service, and disposal of ozone depleting 

substances from such equipment (air conditioners, refrigerators, etc.) at SJEC will be 

completed by a certified technician.

(r) Clean Air Interstate Rule (CAIR)

The four (4) natural gas-fired combined cycle combustion turbines identified as CCCT1 -

CCCT4 and four (4) heat recovery steam generator identified as HRSG1, HRSG2, 

HRSG3, and HRSG4 are subject to the Clean Air Interstate Rule (CAIR) Nitrogen Oxides 

Annual, Sulfur Dioxide, and Nitrogen Oxides Ozone Season Trading Programs – CAIR 

Permit for CAIR Units Under 40 CFR 97 because the proposed CCCTs are serve a 

generator rated at 25 MW or more and will produce electricity for sale.

State Rule Applicability - Entire Source

326 IAC 2-2 (Prevention of Significant Deterioration)

This new stationary source is one of the 28 listed source categories and has potential to emit of at 

least one regulated pollutant greater than 100 tons per year. This source is a major source 

pursuant to 326 IAC 2-2 (PSD).

326 IAC 2-2-3 (PSD BACT: Control Technology Review Requirements)

Pursuant to PSD/Operating Permit T141-31003-00579 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the source 

shall be as follows:

Natural Gas-Fired Combined Cycle Combustion Turbines, identified as CCCT1 through 

CCCT4:

1. The PM, PM10 and PM2.5 emissions;

(a) The PM, PM10 and PM2.5 emissions from the combined cycle combustion 

turbines identified as CCCT1 -CCCT4 shall not exceed 18 lb/hour and 0.0078 lbs 

per MMBtu with duct firing based on 3-hr average through the use of good 

combustion practices and fuel specification. 

(b) The PM, PM10 and PM2.5 emissions from the combined cycle combustion 

turbines identified as CCCT1 -CCCT4 shall not exceed 15 pounds per hour and 

0.0065 lbs per MMBtu without duct firing based on 3-hr average through the use of 

good combustion practices and fuel specification. 

(2) The H2SO4 emissions from the combined cycle combustion turbines identified as CCCT1 

-CCCT4 shall be limited by a fuel sulfur limit of 0.75 gr S/100 scf fuel. 

(3) The CO emissions;

(a) The CO emissions from the CCCTs shall be controlled by a catalytic oxidation

(b) The CO emissions shall not exceed 2.0 ppmv @15% O2 based on a 3-hr

average.

(4) The SO2 emissions from the combined cycle combustion turbines identified as CCCT1 -

CCCT4 shall be limited by a fuel sulfur limit of 0.75 gr S/100 scf fuel. 

(5) The VOC emissions;

(a) The VOC emissions from the CCCTs shall be controlled by a catalytic oxidation

(b) The VOC emissions shall not exceed 2.0 ppmvd @15% O2, with duct burners 

based on 3-hr average.
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New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(c) The VOC emissions shall not exceed 1.0 ppmvd @15% O2, without duct burners 

based on 3-hr average.

(6) The NOx emissions;

(a) The NOx emissions from the CCCTs shall be controlled by a Selective Catalytic 

Reduction and DLN Burners.

(b) The NOx emissions shall not exceed 2.0ppmv @15% O2 with duct burners based 

on a 3-hr average.

(7) The GHGs BACT for the Combined Cycle Combustion Turbines identified as CCCT1 -

CCCT4 shall be as follows;

(a) The net heat rate shall not exceed 7,646 Btu/kW-hr (HHV-net) for each CCCT 

block (ISO conditions, baseload operation without duct firing or inlet evaporative 

cooling, and not accounting for transformer losses).

(b) The total CO2 emissions from all four CCCT blocks shall not exceed 4,736,936

tons of CO2e per twelve (12) consecutive month period with compliance 

determined at the end of the month.

 

Startup and Shutdown Limitations for Combined Cycle Combustion Turbines

(a) A startup is defined as the operation in the period beginning when continuous fuel flow to 

the combustion turbine is initiated and ending when the CCCT achieves consecutive 

CEMS data points in compliance with the primary BACT limits.

(b) Steady-state operating condition shall be defined as the period of time that the 

combustion turbine is operating in dry low NOx (premix) mode and in compliance with the 

primary BACT limit.

(c) A shutdown is defined as operation beginning when the combustion turbine exits dry lowNOx (premix) mode and ending with termination of continuous fuel flow to each turbine.

(d) A startup/shutdown cycle is a pair of subsequent shutdown and startup events (i.e., one 

startup followed by one shutdown represents one startup/shutdown cycle).

(e) Unit Offline is represented by the Unit on-line Time being 0. 

(f) The following records shall be kept by the source:

(1) Number of minutes in each hour that the unit is in startup mode. 

 

(2) Number of minutes in each hour that the unit is in shutdown mode. 

(3) Records shall be maintained at any time the unit is off-line. 

(g) An event is defined as: 

(1) exactly one (1) startup or exactly one (1) shutdown

For CO and NOX, the source determined the worst-case operating scenario that results in 

the highest modeled impacts to be a cold start of the CCCTs. The modeled cold start 

emission rates are based on startup emission totals provided by the turbine vendor. 

Therefore, the source proposes to use the cold start emission totals, per CCCT as a 

short-term limit during startup/shutdown events, as follows:
St. Joseph Energy Center, LLC Page 18 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

CO - 2,125 lb/event

NOx - 443 lb/event

(h) The NOX emissions from the combined cycle combustion turbines stacks shall not 

exceed 81.6 tons per twelve (12) consecutive month period, for the duration of the 

combined startup and shutdown events, with compliance determined at the end of each 

month. 

(i) The CO emissions from the combined cycle combustion turbines stacks shall not exceed 

407.5 tons per twelve (12) consecutive month period, for the duration of the combined 

startup and shutdown events, with compliance determined at the end of each month. 

(j) The VOC emissions from the combined cycle combustion turbines stacks shall not 

exceed 22.0 tons per twelve (12) consecutive month period, for the duration of the 

combined startup and shutdown events, with compliance determined at the end of each 

month. 

Natural Gas-Fired Auxiliary Boilers, identified as B001 - B002:

(1) The PM, PM10 and PM2.5 emissions from the Auxiliary Boilers, identified as B001-B002 

shall not exceed 0.0075 lb/MMBtu (HHV) and 0.6 lbs/hour, each, based on a 3-hr average

period through the use of good combustion practices and fuel specification. 

 

(2) The CO emissions from the Auxiliary Boilers (B001-B002) operation shall not exceed 

0.083 lb/MMBtu (HHV) and 6.64 lbs/hr, each, based on a 3 - hour average through Good 

Combustion Practices.

(3) The SO2 emissions from the Auxiliary Boilers, identified as B001-B002 shall not exceed 

0.0022 lb/MMBtu (HHV) and 0.176 lbs/hr, each, based on a 3-hr average through the use 

of fuel specification. 

(4) The VOC emissions from the Auxiliary Boilers, identified as B001-B002 shall not exceed 

0.005 lb/MMBtu (HHV) and 0.4 lbs/hr, each, based on a 3-hr average period through the 

use of good combustion practices. 

(5) The NOx emissions;

(a) The NOx emissions from the Auxiliary Boilers, identified as B001-B002 shall be 

controlled by Low NOx Burners with Flue Gas Recirculation.

(b) The NOx emissions shall not exceed 0.032 lb/MMBtu (HHV) and 2.56 pounds per 

hour each, based on a 3-hr average period.

(6) The GHGs BACT for the Auxiliary Boilers, identified as B001-B002 shall be as follows

(a) Operating and Maintenance (O&M) Practices;

(b) Combustion Turning; 

(c) The boiler will be equipped with oxygen trim controls and oxygen analyzers;

(d) The boiler will be equipped with an economizer;

(e) Energy efficient refractory will be installed;

(f) The boiler will be equipped with a condensate return system (recovery);

(g) Steam and hot lines will be insulated;

(h) Boiler designed for 80% thermal efficiency (HHV); and
St. Joseph Energy Center, LLC Page 19 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(i) The total CO2 emissions from the two auxiliary boilers shall be limited to less than

81,996 tons of CO2e per twelve (12) consecutive month period with compliance 

determined at the end of the month.

Firewater Pump Engines, identified as FP01 - FP02:

(1) The PM, PM10 and PM2.5 emissions from the Firewater Pump Engines identified as FP01 

- FP02 shall be limited to less than 0.15 g/hp-hr through the use of combustion design 

control and usage limitation. 

(2) The CO emissions from the Firewater Pump Engines identified as FP01 - FP02 shall not 

exceed 2.6 g/hp-hr through the use of combustion design control and usage limitation. 

(3) The SO2 emissions from the Firewater Pump Engines identified as FP01 - FP02 shall not 

exceed 0.0015 % S and 0.043 lb/hr, each through the use of ultra low sulfur distillate 

(ULSD) and usage limitation. 

(4) The VOC emissions from the Firewater Pump Engines identified as FP01 - FP02 shall not 

exceed 0.16 pounds per hour,each through the use of Combustion Design Controls and

usage limitation. 

(5) The NOx emissions from the Firewater Pump Engines identified as FP01 - FP02 shall not 

exceed 3.0 g/bhp-hr for NOx + NMHC through the use of Combustion Design Controls

and usage limitation. 

(6) The GHGs BACT for the Firewater Pump Engines identified as FP01 - FP02 shall be as 

follows;

(A) The use of a good engineering design and fuel efficient design; and 

(B) The total CO2 emissions from the two (2) firewater pump engines shall not 

exceed 172 tons of CO2e per twelve (12) consecutive month period with 

compliance determined at the end of the month.

(7) The Firewater Pumps identified as FP01 - FP02 shall not exceed 500 hours per year, 

each.

Emergency Diesel Generators, identified as (EG01 - EG03):

(1) The PM, PM10 and PM2.5 emissions from the Emergency Generators, Identified as EG01, 

EG02 and EG03 shall not exceed 0.15 g/hp-hr, each through the use of combustion 

design control and usage limitation. 

(2) The CO emissions from the Emergency Diesel Generators, Identified as EG01, EG02 and 

EG03 shall not exceed 2.6 g/hp-hr, each through the use of combustion design controls 

and usage limitation. 

(3) The SO2 emissions from the Emergency Diesel Generators, Identified as EG01 and 

EG02 shall not exceed 0.012 lb/hr through the use of ultra low sulfur distillate (ULSD) and

usage limitation. 

(4) The SO2 emissions from the Emergency Diesel Generator, Identified as EG03 shall not 

exceed 0.024 lb/hr through the use of ultra low sulfur distillate (ULSD) and usage 

limitation. 

(5) The VOC emissions from the Emergency Diesel Generators, Identified as EG01 and 

EG02 shall not exceed 1.04 lbs/hr, each, through the use of Combustion Design Controls

and usage limitation. 
St. Joseph Energy Center, LLC Page 20 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(6) The VOC emissions from the Emergency Diesel Generator, Identified as EG03 shall not 

exceed 1.04 lbs/hr through the use of Combustion Design Controls and usage limitation. 

(7) The NOx emissions from the Emergency Diesel Generators shall not exceed 4.8 g/bhp-hr 

for NOx + NMHC through the use of Combustion Design Controls and usage limitation. 

(8) The GHGs BACT for the Emergency Diesel Generators, Identified as EG01, EG02 and 

EG03 shall be as follows

(1) The use of a good engineering design and fuel efficient design; and 

(2) The total CO2 emissions from all the three (3) emergency diesel generators shall 

not exceed 1,186 tons of CO2e per twelve (12) consecutive month period with 

compliance determined at the end of the month.

(9) The Emergency Diesel Generators, Identified as EG01, EG02 and EG03 shall not exceed 

500 hours per year, each.

Cooling Tower CT01-CT02:

The PM, PM10 and PM2.5 emissions from the Cooling Towers, identified as CT01 and CT02 shall 

be controlled by High efficiency drift eliminators designed with a drift loss rate of less than 

0.0005%.

Turbine Lube Oil Demister Vents DM01 – DM06:

1. The VOC emissions from the Turbine Lube Oil Demister Vents, identified as DM01 –

DM06 shall be the use of good design and operating practices. 

2. The organic PM, PM10 and PM2.5 emissions from the Turbine Lube Oil Demister Vents, 

identified as DM01 – DM06, shall be the use of good design and operating practices. 

Storage Tanks TK01-TK10, TK12 and TK50:

The VOC emissions from the Turbine Lube Oil storage tanks, identified as TK01 - TK06, and 

Diesel Storage Tanks, identified as TK07, TK08, TK09, TK10, TK12 and TK50 shall be limited by 

the use of good design and operating practices. 

Gasoline Dispensing Storage Tank TK11:

The VOC emissions from the Vehicle Gasoline Dispensing Operation, identified as TK11 shall be

limited by the use of submerged fill pipes and Stage I vapor control.

Electric Circuit Breaker (FUG-SF6):

(1) The use of totally enclosed pressure system with a design leak rate of 0.5% and a density 

alarm for leak detection.

(2) The total SF6 emissions from all the circuit breakers shall not exceed 0.0009 tons of SF6

per twelve (12) consecutive month period with compliance determined at the end of the 

month.

326 IAC 2-4.1 (Major Sources of Hazardous Air Pollutants (HAP))

The operation of these emission units in the plant will emit less than ten (10) tons per year for a 

single HAP and less than twenty-five (25) tons per year for a combination of HAPs. Therefore, 326 

IAC 2-4.1 does not apply.
St. Joseph Energy Center, LLC Page 21 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

326 IAC 1-7 (Actual Stack Height Provisions)

The stack height provisions in this rule apply to sources for which construction commenced after 

June 19, 1979 and that emit SO2 or PM emissions in levels greater than 25 tons per year. The

combined cycle combustion turbine stacks, are subject to these requirements. As such, these 

stacks are subject to the height provisions listed in 326 IAC 1-7-3, which prohibits excessive 

concentrations of PM and SO2.

326 IAC 2-6 (Emission Reporting)

This source is subject to 326 IAC 2-6 (Emission Reporting) because it is required to have an 

operating permit pursuant to 326 IAC 2-7 (Part 70). The potential to emit of PM10 is greater than 

250 tons per year. Therefore, pursuant to 326 IAC 2-6-3(a)(1), annual reporting is required. An 

emission statement shall be submitted each year by July 1. The emission statement shall contain, 

at a minimum, the information specified in 326 IAC 2-6-4.

326 IAC 5-1 (Opacity Limitations)

This source is subject to the opacity limitations specified in 326 IAC 5-1-2(1) 

326 IAC 6.5 PM Limitations Except Lake County

This source is subject to 326 IAC 6.5 because it is located in St. Joseph County, its PM PTE (or 

limited PM PTE) is equal to or greater than 100 tons per year or actual emissions are greater than 

10 tons per year. However, this source is not one of the sources specifically listed in 326 IAC 6.5-2 

through 326 IAC 6.5-10. Therefore, 326 IAC 6.5-1-2(a) applies. Applicability for individual facilities 

is noted is noted in subsequent sections. 

326 IAC 6-4 (Fugitive Dust Emissions)

The Permittee shall not allow fugitive dust to escape beyond the property line or boundaries of the 

property, right-of-way, or easement on which the source is located, in a manner that would violate

326 IAC 6-4 (Fugitive Dust Emissions). 

326 IAC 6-5 (Fugitive Particulate Matter Emission Limitations)

The source is not subject to the requirements of 326 IAC 6-5 because the amounts of fugitive 

particulate matter emissions from paved roadways are less than 25 tons per year.

State Rule Applicability – Individual Facilities

326 IAC 3-5 (Continuous Monitoring of Emissions)

The natural gas-fired combined cycle combustion turbine, identified as units CCCT1, CCCT2, 

CCCT3, and CCCT4 are subject to the monitoring requirements of 326 IAC 3-5 because they are 

fossil fuel fired steam generators that have a heat input capacity of greater than 100 MMBtu per 

hour, each. 

Pursuant to 326 IAC 3-5-1(b)(2)(C) and 326 IAC 3-5-1(a)(1), a continuous monitoring system shall 

be installed, calibrated, operate and maintain Nitrogen Oxide (NOx) for each of the stacks,

CCCT01, CCCT02, CCCT03, and CCCT04 in accordance with 326 IAC 3-5-2 and 326 IAC 3-5-3.

326 IAC 5-1-3 (Temporary Alternative Opacity Limitations)

Pursuant to 326 IAC 5-1-3 (a) (Temporary Alternative Opacity Limitations), when building a new 

fire in a boiler, or shutting down a boiler, opacity may exceed the applicable opacity limitation 

established in 326 IAC 5-1-2. However, opacity levels shall not exceed sixty percent (60%) for any 

six (6)-minute averaging period. Opacity in excess of the applicable opacity limitation established 

in 326 IAC 5-1-2 shall not continue for more than two (2) six (6)-minute averaging periods in any 

twenty-four (24) hour period. 

If a facility cannot meet the opacity limitations of 326 IAC 5-1-3(a) or (b), the Permittee may 

submit a written request to IDEM, OAQ, for a temporary alternative opacity limitation in 

accordance with 326 IAC 5-1-3(d). The Permittee must demonstrate that the alternative limit is 

needed and justifiable.
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New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

326 IAC 6.5 Particulate Matter Limitations Except Lake County

(a) Pursuant to 326 IAC 6.5-1-1(b), this rule does not apply to the CTs, duct burners, and 

auxiliary boilers as these units combust only natural gas. 

(b) Pursuant to 326 IAC 6.5-1-1(c), this rule does not apply to the firewater pumps and 

emergency generators as they are subject to more stringent particulate matter limits 

under NSPS IIII.

(c) Pursuant to 326 IAC 6.5-1-2(a), the particulate emission from the lime silos and demister 

vents shall not exceed 0.03 grains per dry standard cubic feet (gr/dscf).

326 IAC 6-2-4 (Particulate Emission Limitations for Sources of Indirect Heating)

Pursuant to 326 IAC 6-2-4 (Particulate Emission Limitations for Sources of Indirect Heating: 

Emission Limitations for facilities specified in 326 IAC 6-2-1(d)), the PM emissions from the 

auxilliary boilers, identified as B001 and B002 and the duct burners shall not exceed 0.2 pounds 

per million Btu heat input (lb/MMBtu), each. This limitation was calculated using the following 

equation:

0.26 Q

1.09

Pt =

Where:

Q = total source heat input capacity (MMBtu/hr). 

For these units, Q = 748.0 MMBtu/hr.

However, 326 IAC 6-2-1(h) states that if a limitation established by this rule is inconsistent with a 

limitation required by the permit regulations, then the permit regulation limit will prevail. Since the 

BACT emissions limit is significantly more stringent than the above calculated limit, compliance with 

the BACT particulate matter limits renders the above rule 326 IAC 6-2-4 not applicable to these 

auxiliary boilers.

326 IAC 6-3-2 (Particulate Emission Limitations for Manufacturing Processes) 

Pursuant to 326 IAC 6-3-1(c), the particulate emission limitations for manufacturing processes 

contained in 326 IAC 6-3 do not apply to any of the emission units because particulate matter 

emission limitations established under 326 IAC 2-2-3 (PSD) are more stringent and are exempt 

from the requirements of this rule.

326 IAC 7-1.1 Sulfur Dioxide Emission Limitations 

(a) The emergency diesel generators and firewater pump engines are not subject to the 

requirements of 326 IAC 7-1.1 because each of them has the potential to emit SO2

emissions less than 25 tons per year. 

(b) The potential to emit SO2 emissions from each of the heat recovery steam generators 

(HRSG1 through HRSG4) is less than 25 tons per year. Therefore, these units are not 

subject to the requirements of 326 IAC 7-1.1. 

(c) The potential to emit SO2 emissions from each of the combined cycle combustion 

turbines, identified as CCCT1, CCCT2, CCCT3, and CCCT4 is less than 25 tons per year. 

Therefore, these units are not subject to the requirements of 326 IAC 7-1. 

326 IAC 8-1-6 (New facilities; general reduction requirements)

(a) Each of the heat recovery steam generators with duct burners (HRSG1 through HRSG4) 

at this source was constructed after January 1, 1980 and has potential VOC emissions 

less than 25 tons per year. Therefore, the requirements of 326 IAC 8-1-6 (BACT) are not 

applicable to these units. 
St. Joseph Energy Center, LLC Page 23 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(b) The two (2) auxiliary boilers were constructed after January 1, 1980 and have potential 

VOC emissions less than 25 tons per year, each. Therefore, the requirements of 326 IAC 

8-1-6 (BACT) are not applicable to these boilers.

(c) Each of the combustion turbines at this source was constructed after January 1, 1980 and 

has potential VOC emissions less than 25 tons per year. Therefore, the requirements of 

326 IAC 8-1-6 (BACT) are not applicable to these combustion turbines.

326 IAC 8-3-2 (Cold Cleaner Operations)

The cold cleaning operations are subject to 326 IAC 8-3-2 (Cold Cleaner Operations). This rule 

applies to cold cleaner type degreasing facilities constructed after January 1, 1980. The cold 

cleaning operations at this source were constructed after 1980; therefore, the requirements of 326 

IAC 8-3-2 shall apply to these facilities.

326 IAC 8-3-5 (Cold Cleaner Degreaser Operation and Control)

The cold cleaning operations are subject to 326 IAC 8-3-5 (Cold Cleaner Degreaser Operation 

and Control). This rule applies to cold cleaner type degreasing facilities constructed after July 1, 

1990. The cold cleaning operations at this source were constructed after to 1990, and do not have 

remote solvent reservoirs, therefore, the requirements of 326 IAC 8-3-5 shall apply to these 

facilities.

326 IAC 8-4-6 (Gasoline Dispensing Facilities)

The gasoline dispensing storage tank with storage capacity greater than five hundred seventy five 

(575) gallons is subject to this rule. However the gasoline dispensing tank is subject to 

requirements 326 IAC 2-2-3 (PSD). Therefore, compliance with requirements of 326 IAC 2-2-3 will 

satisfy the requirements of 326 IAC 8-4-6.

326 IAC 9-1 (Carbon Monoxide Emission Limits)

This source is subject to 326 IAC 9-1 because it is a stationary source of CO emissions commencing 

operation after March 21, 1972 and has CO emissions of more than 100 tons per year. There are no 

applicable CO emission limits, under this state rule, established for this type of operation and the 

source is not proposing to install any of the source types regulated under this rule at the CCCT 

Facility.

326 IAC 2-2-4 (Air Quality Analysis Requirements)

Section (4)(a) of this rule, requires that the PSD application shall contain an analysis of ambient 

air quality in the area that the major stationary source would affect for pollutants that are emitted 

at major levels or significant amount. St. Joseph Energy Center, LLC has submitted an air quality 

analysis, which has been evaluated by IDEM's Technical Support and Modeling Section. See 

details in Appendix C.

NAAQs modeling for the appropriate time-averaging periods was conducted. OAQ modeling 

results are shown in Appendix C. All maximum-modeled concentrations were compared to the 

respective NAAQS limit. All maximum-modeled concentrations during the five years were below 

the NAAQS limit except for the 24-hour PM2.5 and a culpability analysis was required and is shown 

in Table 6 of Appendix C. Results were based from worst operating scenario determined in SIA 

modeling.

326 IAC 2-2-5 (Air Quality Impact Requirements)

326 IAC 2-2-5(e)(1) of this rule, requires that the air quality impact analysis required by this 

section shall be conducted in accordance with the following provisions:

(1) Any estimates of ambient air concentrations used in the demonstration processes 

required by this section shall be based upon the applicable air quality models, data bases, 

and other requirements specified in 40 CFR Part 51, Appendix W (Requirements for 

Preparation, Adoption, and Submittal of Implementation Plans, Guideline on Air Quality 

Models)*.
St. Joseph Energy Center, LLC Page 24 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(2) Where an air quality impact model specified in the guidelines cited in subdivision (1) is 

inappropriate, a model may be modified or another model substituted provided that all 

applicable guidelines are satisfied.

(3) Modifications or substitution of any model may only be done in accordance with guideline 

documents and with written approval from U.S. EPA and shall be subject to public 

comment procedures set forth in 326 IAC 2-1.1-6.

Economic Growth

The purpose of the growth analysis is to quantify project associated growth and estimate the air 

quality impacts from this growth either quantitatively or qualitatively.

It is estimated that 23 additional jobs will be created as a result of the proposed project. Most of 

the employees will be drawn from nearby areas. Since the area is predominately rural, it is not 

expected the growth impacts will cause a violation of the NAAQs or the PSD increment.

Soils and Vegetation Analysis

Soil types included a variety of loamy soils. Due to the agricultural nature of the land, crops in the 

St. Joseph County area consist mainly of corn and soybeans. (2007 Agricultural Census for St. 

Joseph County). The maximum modeled concentrations for SJEC are well below the threshold 

limits necessary to have adverse impacts on the surrounding vegetation. Livestock in St. Joseph 

County consist mainly of hogs, cattle and dairy (2007 Agricultural Census for St. Joseph County) 

and will not be adversely impacted from the facility. Trees in the area are mainly hardwoods. 

These are hardy trees and no significant adverse impacts are expected due to modeled 

concentrations.

Federal and State Endangered Species Analysis

Federal and state endangered species are listed by the U.S. Fish and Wildlife Service; Division of 

Endangered Species for Indiana, and include 5 amphibians, 27 birds, 10 fishes, 7 mammals, 15 

mollusks, and 15 reptiles. Of the federal and state endangered species on the list, 5 reptiles, 3 

mollusks, 1 fish, 1 insect, 18 birds, 3 amphibians and 7 mammals have habitat within St. Joseph 

County. The mollusks, fish, amphibians, and certain species of birds and mammals are found 

along rivers and lakes while the other species of birds and mammals are found in forested areas. 

The facility is not expected to have any additional adverse effects on the habitats of the species 

than what has already occurred from the industrial, farming, and residential activities in the area.

Federal and state endangered plants are listed by the U.S. Fish and Wildlife Service, Division of 

Endangered Species for Indiana. At this time 27 state endangered plant species (including the 

Goose-foot Corn-salad and Running Serviceberry) are found in St. Joseph County. The 

endangered plants do not thrive in industrialized and residential areas. The facility is not expected 

to adversely affect any plant on the endangered species list.

326 IAC 2-2-6 (Increment Consumption Requirements)

326 IAC 2-2-6(a) requires that any demonstration under section 5 of this rule shall demonstrate 

that increased emissions caused by the proposed major stationary source will not exceed eighty 

percent (80%) of the available maximum allowable increases (MAI) over the baseline 

concentration of sulfur dioxide, particulate matter, and nitrogen dioxide indicated in subsection 

(b)(1) of this rule.

326 IAC 2-2-7 (Additional Analysis, Requirements)

326 IAC 2-2-7(a) requires an analysis of the impairment to visibility, soils and vegetation. An 

analysis of the air quality impact projected for the area as a result of general commercial, 

residential, industrial, and other growth associated with the source was performed. See detailed 

analysis in Appendix C.

326 IAC 2-2-8 (Source Obligation)

(1) Pursuant to 2-2-8(1), approval to construct shall become invalid if construction is not 

commenced within eighteen (18) months after receipt of the approval, if construction is 
St. Joseph Energy Center, LLC Page 25 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

discontinued for a period of eighteen (18) months or more, or if construction is not 

completed within a reasonable time. 

(2) Approval for construction shall not relieve the Permittee of the responsibility to comply 

fully with applicable provisions of the state implementation plan and any other 

requirements under local, state, or federal law.

326IAC 2-2-10 (Source Information)

The Permittee has submitted all information necessary to perform an analysis or make the 

determination required under this rule.

326 IAC 2-2-12 (Permit Rescission)

The permit issued under this rule shall remain in effect unless and until it is rescinded, modified, 

revoked, or it expires in accordance with 326 IAC 2-1.1-9.5 or section 8 of this rule.

Compliance Determination and Monitoring Requirements

Permits issued under 326 IAC 2-7 are required to ensure that sources can demonstrate 

compliance with all applicable state and federal rules on a continuous basis. All state and federal 

rules contain compliance provisions; however, these provisions do not always fulfill the 

requirement for a continuous demonstration. When this occurs, IDEM, OAQ, in conjunction with 

the source, must develop specific conditions to satisfy 326 IAC 2-7-5. As a result, Compliance 

Determination Requirements are included in the permit. The Compliance Determination 

Requirements in Section D of the permit are those conditions that are found directly within state 

and federal rules and the violation of which serves as grounds for enforcement action. 

If the Compliance Determination Requirements are not sufficient to demonstrate continuous 

compliance, they will be supplemented with Compliance Monitoring Requirements, also in Section 

D of the permit. Unlike Compliance Determination Requirements, failure to meet Compliance 

Monitoring conditions would serve as a trigger for corrective actions and not grounds for 

enforcement action. However, a violation in relation to a compliance monitoring condition will 

arise through a source's failure to take the appropriate corrective actions within a specific time 

period.

The compliance determination and monitoring requirements applicable to this modification are as 

follows:
St. Joseph Energy Center, LLC Page 26 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Testing Requirements

(a) Testing Requirements

Note: Compliance with the NOx and CO emission limits for the combustion turbines are demonstrated by using the NOx 

and CO CEMs data.

No stack testing are required for the emergency diesel generators and the firewater pump engines

because these units are emergency use units and/or insignificant activities and compliance with 

the BACT limits are demonstrated through keeping records of the fuel used. Operations of the 

high efficiency drift eliminators at all times will ensure compliance with PM/PM10/PM2.5 limit for the 

insignificant cooling towers. Therefore, no testing is required for the cooling towers.

(b) The compliance monitoring requirements applicable to this source are as follows: 

Control Parameter Frequency Range/

Value

Excursions 

and

Exceedances

Limit or 

Requirement

Oxidation 

Catalyst Temperature Continuous

Value provided by 

catalyst vendor or as 

determined from the 

last compliance stack 

test

Response 

steps

326 IAC 2-2-3 

Emission units Control device When to test Pollutants Frequency

of testing

Limit or 

Requirement

CCCT1, CCCT2, 

CCCT3, and 

CCCT4

With Duct Burner 60 days / no later 

than 180 days

PM, PM10

and PM2.5

5 year 326 IAC 2-2-3

Without Duct 

Burner

CCCT1, CCCT2, 

CCCT3, and 

CCCT4

Oxidation 

Catalyst with Duct

Burner 60 days / no later 

than 180 days

VOC 5 year 326 IAC 2-2-3

Oxidation 

Catalyst without 

Duct Burner

CCCT1, CCCT2, 

CCCT3, and 

CCCT4

No control

60 days / no later 

than 180 days CO2

(Heat Rate 

Performance)

5 year 326 IAC 2-2-3

Auxiliary Boiler No Control 60 days / no later 

than 180 days

PM, PM10

and PM2.5

One time 

testing

326 IAC 2-2-3

Auxiliary Boiler No Control 60 days / no later 

than 180 days

VOC One time 

testing

326 IAC 2-2-3

Auxiliary Boiler

Low NOx Burner 

with Flue Gas 

Recirculation

60 days / no later 

than 180 days

NOx 5 year 326 IAC 2-2-3

Auxiliary Boiler No Control

60 days / no later 

than 180 days CO One time 

testing 326 IAC 2-2-3

Auxiliary Boiler No control

60 days / no later 

than 180 days

Thermal 

Efficiency

one time 

testing

326 IAC -2-2-3 
St. Joseph Energy Center, LLC Page 27 of 27

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(c) The compliance monitoring requirements applicable to this source are as follows: 

Control Parameter Frequency Value Excursions and 

Exceedances

Requirement

CCCT1, CCCT2, 

CCCT3, and CCCT4 

(SCR with DLN)

NOx CEMS Continuous N/A

Continuous emission 

monitoring system 

measurement data.

326 IAC 2-2-3

CCCT1, CCCT2, 

CCCT3, and CCCT4 

(Oxidation Catalyst)

CO CEMS Continuous N/A

Continuous emission 

monitoring system 

measurement data.

326 IAC 2-2-3

Recommendation

The staff recommends to the Commissioner that the Part 70 Operating Permit be approved. This 

recommendation is based on the following facts and conditions:

Unless otherwise stated, information used in this review was derived from the application and 

additional information submitted by the applicant.

An application for the purposes of this review was received on October 3, 2011. 

Conclusion

The operation of this power plant shall be subject to the conditions of the attached Part 70 

Operating Permit No. 141-31003-00579. 

IDEM Contact

(a) Questions regarding this proposed permit can be directed to Josiah Balogun at the Indiana 

Department Environmental Management, Office of Air Quality, Permits Branch, 100 North Senate 

Avenue, MC 61-53 IGCN 1003, Indianapolis, Indiana 46204-2251 or by telephone at (317) 234-

5257 or toll free at 1-800-451-6027 extension 4-5257.

(b) A copy of the findings is available on the Internet at: http://www.in.gov/ai/appfiles/idem-caats/.

(c) For additional information about air permits and how the public and interested parties can 

participate, refer to the IDEM’s Guide for Citizen Participation and Permit Guide on the Internet at: 

www.idem.in.gov.
St. Joseph Energy Center, LLCConer of Walnut and Edison Roads, New Calisle, IN 46552141-31003-00579Josiah Balogun

Date: 2-Nov-2011

PM 

(tons/yr)

PM10 

(tons/yr) 

PM2.5 

(tons/yr)

SO2 

(tons/yr)

VOC 

(tons/yr) 

CO 

(tons/yr)

NOx 

(tons/yr)

H2SO4 

(tons/yr)

NH3 

(tons/yr)

SF6 

(tons/yr)

CH4 

(tons/yr)

N2O 

(tons/yr)

Emission UnitCombustion Turbine CCCT1 78.84 78.84 78.84 24.97 33.29 242.65 359.16 19.69 69.42 0.00 21.74 2.17 Combustion Turbine CCCT2 78.84 78.84 78.84 24.97 33.29 242.65 359.16 19.69 69.42 0.00 21.74 2.17 Combustion Turbine CCCT3 78.84 78.84 78.84 24.97 33.29 242.65 359.16 19.69 69.42 0.00 21.74 2.17 Combustion Turbine CCCT4 78.84 78.84 78.84 24.97 33.29 242.65 359.16 19.69 69.42 0.00 21.74 2.17  Aux. Boiler B001 2.63 2.63 2.63 0.77 1.75 28.91 10.99 0.00 0.00 0.00 0.77 0.08 

Aux. Boiler B002 2.63 2.63 2.63 0.77 1.75 28.91 10.99 0.00 0.00 0.00 0.77 0.08 

Cooling Tower CT01 3.73 2.37 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Cooling Tower CT02 3.73 2.37 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Firewater pump FP01 0.03 0.03 0.03 0.19 0.03 0.43 0.5 0.00 0.00 0.00 0.003 0.001 Firewater Pump FP02 0.03 0.03 0.03 0.19 0.03 0.43 0.5 0.00 0.00 0.00 0.003 0.001 Emergency Gen. EG01 0.08 0.08 0.08 0.00 0.05 1.45 2.65 0.00 0.00 0.00 0.01 0.002 Emergency Gen. EG02 0.08 0.08 0.08 0.00 0.05 1.45 2.65 0.00 0.00 0.00 0.01 0.002 Emergency Gen. EG03 0.03 0.03 0.03 0.01 0.12 0.49 0.64 0.00 0.00 0.00 0.02 0.005 Turbine Lube Oil Demister Vent DM01-DM06 0.35 0.35 0.35 0.00 0.35 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Storage Tanks 0.00 0.00 0.00 0.00 0.11 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Six (6) Circuit Breakers 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.0009 0.00 0.00 Two (2) Lime Silos 0.66 0.31 0.05 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Total Emissions 329.34 326.27 321.29 101.81 137.40 1032.67 1465.56 78.76 277.68 0.0009 88.55 8.85 

Appendix A: Emissions Calculations

Emission Summary

Source Name:

Source Location:

Uncontrolled Potential to Emit 

Permit Number:

Permit Reviewer:
St. Joseph Energy Center, LLCConer of Walnut and Edison Roads, New Calisle, IN 46552141-31003-00579Josiah Balogun

Date: 2-Nov-2011

PM 

(tons/yr)

PM10 

(tons/yr) 

PM2.5 

(tons/yr)

SO2 

(tons/yr)

VOC 

(tons/yr) 

CO 

(tons/yr)

NOx 

(tons/yr)

H2SO4 

(tons/yr)

NH3 

(tons/yr)

SF6 

(tons/yr)

CH4 

(tons/yr)

N2O 

(tons/yr)

Emission UnitCombustion Turbine CCCT1 78.84 78.84 78.84 24.97 24.97 130.03 71.83 19.69 69.42 0.00 21.74 2.17 Combustion Turbine CCCT2 78.84 78.84 78.84 24.97 24.97 130.03 71.83 19.69 69.42 0.00 21.74 2.17 Combustion Turbine CCCT3 78.84 78.84 78.84 24.97 24.97 130.03 71.83 19.69 69.42 0.00 21.74 2.17 Combustion Turbine CCCT4 78.84 78.84 78.84 24.97 24.97 130.03 71.83 19.69 69.42 0.00 21.74 2.17  Aux. Boiler B001 2.63 2.63 2.63 0.77 1.75 28.91 10.99 0.00 0.00 0.00 0.77 0.08 

Aux. Boiler B002 2.63 2.63 2.63 0.77 1.75 28.91 10.99 0.00 0.00 0.00 0.77 0.08 

Cooling Tower CT01 3.73 2.37 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Cooling Tower CT02 3.73 2.37 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Firewater pump FP01 0.03 0.03 0.03 0.19 0.03 0.43 0.5 0.00 0.00 0.00 0.003 0.001 Firewater Pump FP02 0.03 0.03 0.03 0.19 0.03 0.43 0.5 0.00 0.00 0.00 0.003 0.001 Emergency Gen. EG01 0.08 0.08 0.08 0.00 0.05 1.45 2.65 0.00 0.00 0.00 0.01 0.002 Emergency Gen. EG02 0.08 0.08 0.08 0.00 0.05 1.45 2.65 0.00 0.00 0.00 0.01 0.002 Emergency Gen. EG03 0.03 0.03 0.03 0.01 0.12 0.49 0.64 0.00 0.00 0.00 0.02 0.005 Turbine Lube Oil Demister Vent DM01-DM06 0.35 0.35 0.35 0.00 0.35 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Storage Tanks 0.00 0.00 0.00 0.00 0.11 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Six (6) Circuit Breakers 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.0009 0.00 0.00 Two (2) Lime Silos 0.11 0.11 0.11 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Total Emissions 328.79 326.07 321.35 101.81 104.12 582.19 316.24 78.76 277.68 0.0009 88.55 8.85 

Limited Potential to Emit 

Appendix A: Emissions Calculations

Emission Summary

Source Name:

Source Location:

Permit Number:

Permit Reviewer:
Emission Calculations

Facility Wide Potential Emissions Summary 

CCCT1 CCCT2 CCCT3 CCCT4 B001 B002 CT01 CT02 EG01 EG02 EG03 FP01 FP02

DM01-

DM06

S

Pollutant (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) CO 130.03 130.03 130.03 130.03 28.91 28.91 - - 1.45 1.45 0.49 0.43 0.43 - NOX 71.83 71.83 71.83 71.83 10.99 10.99 - - 2.65 2.65 0.64 0.50 0.50 - 

TSP 78.84 78.84 78.84 78.84 2.63 2.63 3.73 3.73 0.08 0.08 0.03 0.03 0.03 0.35 Total PM10 78.84 78.84 78.84 78.84 2.63 2.63 2.37 2.37 0.08 0.08 0.03 0.03 0.03 0.35 Total PM2.5 78.84 78.84 78.84 78.84 2.63 2.63 0.01 0.01 0.08 0.08 0.03 0.03 0.03 0.35 SO2 24.97 24.97 24.97 24.97 0.77 0.77 - - 0.00 0.00 0.01 0.19 0.19 - VOC 24.97 24.97 24.97 24.97 1.75 1.75 - - 0.05 0.05 0.12 0.03 0.03 0.35 H2SO4 19.69 19.69 19.69 19.69 0.00 0.00 - - ----- - 

Fluorides (Other than HF) 0.00 0.00 0.00 0.00 0.00 0.00 - - ----- - 

NH3 69.42 69.42 69.42 69.42 0.00 0.00 - - ----- - 

CO2 1,183,104 1,183,104 1,183,104 1,183,104 40,958 40,958 - - 299 299 584 86 86 - 

CH4 21.74 21.74 21.74 21.74 0.77 0.77 - - 0.01 0.01 0.02 0.003 0.003 - 

N2O 2.17 2.17 2.17 2.17 0.08 0.08 - - 0.002 0.002 0.005 0.001 0.001 - 

SF6 - - - - -- - - ----- - 

CO2e 1,184,234 1,184,234 1,184,234 1,184,234 40,998 40,998 - - 300 300 586 86 86 - 

1. TSP emissions are only filterable PM emissions.2. PM10 and PM2.5 emissions are estimated as total particulate emissions (filterable + condensable).
Emission Calculations

Facility Wide Potential HAP Emissions Summary 

CCCT1 CCCT2 CCCT3 CCCT4 B001 B002 CT01 CT02 EG01 EG02 EG03 FP01 FP02

DM01-

DM06

S

Pollutant (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) 

1,3-Butadiene 4.43E-04 4.43E-04 4.43E-04 4.43E-04 - - - - - - - 2.54E-05 2.54E-05 - 

2-Methylnaphthalene - - - - 3.76E-06 3.76E-06 - - ----- - 

3-Methylchloranthrene - - - - 2.82E-07 2.82E-07 - - ----- - 

7,12-Dimethylbenz(a)anthracene - - - - 2.51E-06 2.51E-06 - - ----- - 

Acenaphthene - - - - 2.82E-07 2.82E-07 - - 8.24E-06 8.24E-06 1.65E-05 9.22E-07 9.22E-07 - 

Acenaphthylene - - - - 2.82E-07 2.82E-07 - - 1.62E-05 1.62E-05 3.25E-05 3.29E-06 3.29E-06 - 

Acetaldehyde 3.15E-01 3.15E-01 3.15E-01 3.15E-01 - - - - 4.44E-05 4.44E-05 8.87E-05 4.98E-04 4.98E-04 - 

Acrolein 4.10E-02 4.10E-02 4.10E-02 4.10E-02 - - - - 1.39E-05 1.39E-05 2.77E-05 6.01E-05 6.01E-05 - 

Anthracene - - - - 3.76E-07 3.76E-07 - - 2.16E-06 2.16E-06 4.33E-06 1.21E-06 1.21E-06 - 

Arsenic - - - - 3.14E-05 3.14E-05 - - ----- - 

Beryllium - - - - 1.88E-06 1.88E-06 - - ----- - 

Benzene 9.56E-02 9.56E-02 9.56E-02 9.56E-02 3.29E-04 3.29E-04 - - 1.37E-03 1.37E-03 2.73E-03 6.06E-04 6.06E-04 - 

Benz(a)anthracene - - - - 2.82E-07 2.82E-07 - - 1.09E-06 1.09E-06 2.19E-06 1.09E-06 1.09E-06 - 

Benzo(a)pyrene - - - - 1.88E-07 1.88E-07 - - 4.52E-07 4.52E-07 9.05E-07 1.22E-07 1.22E-07 - 

Benzo(b)fluoranthene - - - - 2.82E-07 2.82E-07 - - 1.95E-06 1.95E-06 3.91E-06 6.43E-08 6.43E-08 - 

Benzo(g,h,i)perylene - - - - 1.88E-07 1.88E-07 - - 9.79E-07 9.79E-07 1.96E-06 3.17E-07 3.17E-07 - 

Benzo(k)fluoranthene - - - - 2.82E-07 2.82E-07 - - 3.84E-07 3.84E-07 7.67E-07 1.01E-07 1.01E-07 - 

Cadmium - - - - 1.73E-04 1.73E-04 - - ----- - 

Chromium - - - - 2.20E-04 2.20E-04 - - ----- - 

Chrysene - - - - 2.82E-07 2.82E-07 - - 2.69E-06 2.69E-06 5.39E-06 2.29E-07 2.29E-07 - 

Cobalt - - - - 1.32E-05 1.32E-05 - - ----- - 

Dibenzo(a,h)anthracene - - - - 1.88E-07 1.88E-07 - - 6.09E-07 6.09E-07 1.22E-06 3.79E-07 3.79E-07 - 

Dichlorobenzene - - - - 1.88E-04 1.88E-04 - - ----- - 

Ethylbenzene 1.67E-01 1.67E-01 1.67E-01 1.67E-01 - - - - ----- - 

Fluoranthene - - - - 4.71E-07 4.71E-07 - - 7.09E-06 7.09E-06 1.42E-05 4.94E-06 4.94E-06 - 

Fluorene - - - - 4.39E-07 4.39E-07 - - 2.25E-05 2.25E-05 4.51E-05 1.90E-05 1.90E-05 - 

Formaldehyde 1.27E+00 1.27E+00 1.27E+00 1.27E+00 1.18E-02 1.18E-02 - - 1.39E-04 1.39E-04 2.78E-04 7.66E-04 7.66E-04 - 

Hexane - - - - 2.82E-01 2.82E-01 - - ----- - 

Indeno(1,2,3-cd)pyrene - - - - 2.82E-07 2.82E-07 - - 7.29E-07 7.29E-07 1.46E-06 2.43E-07 2.43E-07 - 

Lead - - - - 7.84E-05 7.84E-05 - - ----- - 

Manganese - - - - 5.96E-05 5.96E-05 - - ----- - 

Mercury - - - - 4.08E-05 4.08E-05 - - ----- - 

Naphthalene 4.64E-03 4.64E-03 4.64E-03 4.64E-03 9.57E-05 9.57E-05 - - 2.29E-04 2.29E-04 4.58E-04 5.51E-05 5.51E-05 - 

Nickel - - - - 3.29E-04 3.29E-04 - - ----- - 

PAH 3.45E-03 3.45E-03 3.45E-03 3.45E-03 - - - - ----- - 

Phenanthrene - - - - 2.67E-06 2.67E-06 - - 7.18E-05 7.18E-05 1.44E-04 1.91E-05 1.91E-05 - 

Propylene Oxide 2.10E-01 2.10E-01 2.10E-01 2.10E-01 - - - - ----- - 

Pyrene - - - - 7.84E-07 7.84E-07 - - 6.53E-06 6.53E-06 1.31E-05 3.10E-06 3.10E-06 - 

Selenium - - - - 3.76E-06 3.76E-06 - - ----- - 

Toluene 4.98E-01 4.98E-01 4.98E-01 4.98E-01 5.33E-04 5.33E-04 - - 4.95E-04 4.95E-04 9.89E-04 2.66E-04 2.66E-04 - 

Xylenes 4.77E-01 4.77E-01 4.77E-01 4.77E-01 - - - - 3.40E-04 3.40E-04 6.79E-04 1.85E-04 1.85E-04 - 

Total HAP 3.09 3.09 3.09 3.09 0.30 0.30 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.00 Maximum Single HAP1 1.27 1.27 1.27 1.27 0.28 0.28 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 

1. Formaldehyde is the single HAP with the greatest facility emissions.
Emission Calculations

Facility Wide Uncontrolled Potential Emissions Summary 

CCCT1 CCCT2 CCCT3 CCCT4 B001 B002 CT01 CT02 EG01 EG02 EG03 FP01 FP02

DM01-

DM06

S

Pollutant (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) CO 242.65 242.65 242.65 242.65 28.91 28.91 - - 1.45 1.45 0.49 0.43 0.43 - NOX 359.16 359.16 359.16 359.16 10.99 10.99 - - 2.65 2.65 0.64 0.50 0.50 - 

TSP 78.84 78.84 78.84 78.84 2.63 2.63 3.73 3.73 0.08 0.08 0.03 0.03 0.03 0.35 Total PM10 78.84 78.84 78.84 78.84 2.63 2.63 2.37 2.37 0.08 0.08 0.03 0.03 0.03 0.35 

Total PM2.5 78.84 78.84 78.84 78.84 2.63 2.63 0.01 0.01 0.08 0.08 0.03 0.03 0.03 0.35 SO2 24.97 24.97 24.97 24.97 0.77 0.77 - - 0.00 0.00 0.01 0.19 0.19 - VOC 33.29 33.29 33.29 33.29 1.75 1.75 - - 0.05 0.05 0.12 0.03 0.03 0.35 H2SO4 19.69 19.69 19.69 19.69 0.00 0.00 - - ----- - 

Fluorides (Other than HF) 0.00 0.00 0.00 0.00 0.00 0.00 - - ----- - 

NH3 69.42 69.42 69.42 69.42 0.00 0.00 - - ----- - 

CO2 1,183,104 1,183,104 1,183,104 1,183,104 40,958 40,958 - - 299 299 584 86 86 - 

CH4 21.74 21.74 21.74 21.74 0.77 0.77 - - 0.01 0.01 0.02 0.003 0.003 - 

N2O 2.17 2.17 2.17 2.17 0.08 0.08 - - 0.002 0.002 0.005 0.001 0.001 - 

SF6 - - - - -- - - ----- - 

CO2e 1,184,234 1,184,234 1,184,234 1,184,234 40,998 40,998 - - 300 300 586 86 86 - 

1. TSP emissions are only filterable PM emissions.2. PM10 and PM2.5 emissions are estimated as total particulate emissions (filterable + condensable).
Emission Calculations

Facility Wide Potential HAP Emissions Summary 

CCCT1 CCCT2 CCCT3 CCCT4 B001 B002 CT01 CT02 EG01 EG02 EG03 FP01 FP02

DM01-

DM06

S

Pollutant (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) 

1,3-Butadiene 5.91E-04 5.91E-04 5.91E-04 5.91E-04 - - - - - - - 2.54E-05 2.54E-05 - 

2-Methylnaphthalene - - - - 3.76E-06 3.76E-06 - - ----- - 

3-Methylchloranthrene - - - - 2.82E-07 2.82E-07 - - ----- - 

7,12-Dimethylbenz(a)anthracene - - - - 2.51E-06 2.51E-06 - - ----- - 

Acenaphthene - - - - 2.82E-07 2.82E-07 - - 8.24E-06 8.24E-06 1.65E-05 9.22E-07 9.22E-07 - 

Acenaphthylene - - - - 2.82E-07 2.82E-07 - - 1.62E-05 1.62E-05 3.25E-05 3.29E-06 3.29E-06 - 

Acetaldehyde 4.20E-01 4.20E-01 4.20E-01 4.20E-01 - - - - 4.44E-05 4.44E-05 8.87E-05 4.98E-04 4.98E-04 - 

Acrolein 5.46E-02 5.46E-02 5.46E-02 5.46E-02 - - - - 1.39E-05 1.39E-05 2.77E-05 6.01E-05 6.01E-05 - 

Anthracene - - - - 3.76E-07 3.76E-07 - - 2.16E-06 2.16E-06 4.33E-06 1.21E-06 1.21E-06 - 

Arsenic - - - - 3.14E-05 3.14E-05 - - ----- - 

Beryllium - - - - 1.88E-06 1.88E-06 - - ----- - 

Benzene 1.27E-01 1.27E-01 1.27E-01 1.27E-01 3.29E-04 3.29E-04 - - 1.37E-03 1.37E-03 2.73E-03 6.06E-04 6.06E-04 - 

Benz(a)anthracene - - - - 2.82E-07 2.82E-07 - - 1.09E-06 1.09E-06 2.19E-06 1.09E-06 1.09E-06 - 

Benzo(a)pyrene - - - - 1.88E-07 1.88E-07 - - 4.52E-07 4.52E-07 9.05E-07 1.22E-07 1.22E-07 - 

Benzo(b)fluoranthene - - - - 2.82E-07 2.82E-07 - - 1.95E-06 1.95E-06 3.91E-06 6.43E-08 6.43E-08 - 

Benzo(g,h,i)perylene - - - - 1.88E-07 1.88E-07 - - 9.79E-07 9.79E-07 1.96E-06 3.17E-07 3.17E-07 - 

Benzo(k)fluoranthene - - - - 2.82E-07 2.82E-07 - - 3.84E-07 3.84E-07 7.67E-07 1.01E-07 1.01E-07 - 

Cadmium - - - - 1.73E-04 1.73E-04 - - ----- - 

Chromium - - - - 2.20E-04 2.20E-04 - - ----- - 

Chrysene - - - - 2.82E-07 2.82E-07 - - 2.69E-06 2.69E-06 5.39E-06 2.29E-07 2.29E-07 - 

Cobalt - - - - 1.32E-05 1.32E-05 - - ----- - 

Dibenzo(a,h)anthracene - - - - 1.88E-07 1.88E-07 - - 6.09E-07 6.09E-07 1.22E-06 3.79E-07 3.79E-07 - 

Dichlorobenzene - - - - 1.88E-04 1.88E-04 - - ----- - 

Ethylbenzene 2.23E-01 2.23E-01 2.23E-01 2.23E-01 - - - - ----- - 

Fluoranthene - - - - 4.71E-07 4.71E-07 - - 7.09E-06 7.09E-06 1.42E-05 4.94E-06 4.94E-06 - 

Fluorene - - - - 4.39E-07 4.39E-07 - - 2.25E-05 2.25E-05 4.51E-05 1.90E-05 1.90E-05 - 

Formaldehyde 1.70E+00 1.70E+00 1.70E+00 1.70E+00 1.18E-02 1.18E-02 - - 1.39E-04 1.39E-04 2.78E-04 7.66E-04 7.66E-04 - 

Hexane - - - - 2.82E-01 2.82E-01 - - ----- - 

Indeno(1,2,3-cd)pyrene - - - - 2.82E-07 2.82E-07 - - 7.29E-07 7.29E-07 1.46E-06 2.43E-07 2.43E-07 - 

Lead - - - - 7.84E-05 7.84E-05 - - ----- - 

Manganese - - - - 5.96E-05 5.96E-05 - - ----- - 

Mercury - - - - 4.08E-05 4.08E-05 - - ----- - 

Naphthalene 6.18E-03 6.18E-03 6.18E-03 6.18E-03 9.57E-05 9.57E-05 - - 2.29E-04 2.29E-04 4.58E-04 5.51E-05 5.51E-05 - 

Nickel - - - - 3.29E-04 3.29E-04 - - ----- - 

PAH 4.60E-03 4.60E-03 4.60E-03 4.60E-03 - - - - ----- - 

Phenanthrene - - - - 2.67E-06 2.67E-06 - - 7.18E-05 7.18E-05 1.44E-04 1.91E-05 1.91E-05 - 

Propylene Oxide 2.79E-01 2.79E-01 2.79E-01 2.79E-01 - - - - ----- - 

Pyrene - - - - 7.84E-07 7.84E-07 - - 6.53E-06 6.53E-06 1.31E-05 3.10E-06 3.10E-06 - 

Selenium - - - - 3.76E-06 3.76E-06 - - ----- - 

Toluene 6.64E-01 6.64E-01 6.64E-01 6.64E-01 5.33E-04 5.33E-04 - - 4.95E-04 4.95E-04 9.89E-04 2.66E-04 2.66E-04 - 

Xylenes 6.35E-01 6.35E-01 6.35E-01 6.35E-01 - - - - 3.40E-04 3.40E-04 6.79E-04 1.85E-04 1.85E-04 - 

Total HAP 4.11 4.11 4.11 4.11 0.30 0.30 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.00 Maximum Single HAP1 1.70 1.70 1.70 1.70 0.28 0.28 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 

1. Formaldehyde is the single HAP with the greatest facility emissions.
Emission Calculations

CCCT Normal Operating Scenario Parameters Page 7 of 22 TSD App A

Operating Data for each CCCT Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 7 Case 8 

Load (%) 100 100 100 75 75 75 47 46 Inlet Air Cooling (on/off) On Off Off On Off Off On Off Ambient Temperature (F) 92 50 -10 92 50 -10 92 52 Duct Burner Firing (yes/no) Yes No No No No No No No CT Heat Consumption (MMBtu/hr) (HHV) 2,000 2,080 2,230 1,540 1,660 1,820 1,220 1,280 DB Heat Consumption (MMBtu/hr) (HHV) 251 0 0 0 0 0 0 0 Total Heat Consumption (MMBtu/hr) (HHV) 2,251 2,080 2,230 1,540 1,660 1,820 1,220 1,280 Startup/Shutdown Emissions (Worst-case) - Per CT

Pollutant 

Cold Start 

Emissions 

(lb/event)

Warm Start 

Emissions 

(lb/event)

Hot Start 

Emissions 

(lb/event)

Shutdown 

Emissions 

(lb/event)

CO 2,125 705 454 445NOX 443 162 75 22

TSP 37 15 7 4Total PM10 37 15 7 4

Total PM2.5 37 15 7 4SO2 4211

VOC 153 39 22 12Lead - - - -

H2SO4 - - - -

Fluorides (other than HF) - - - -

NH3 - - - -

CO2 226,148.83 105,873.46 60,202.56 36,718.37

CH4 4.27 2.00 1.14 0.69

N2O 0.43 0.20 0.11 0.07

Emissions (lb/event) are for conventional startup/shutdown of lead combustion turbine.For GHG, emissions (lb/event) calculated based on fuel consumed per event, and default pollutant emission factor for natural gas per 40 CFR 98, Subpart C. Emissions (lb/event) assume no control devices.Conservatively assumed that PM2.5 emissions equal PM10 emissions.

Conservatively assumed that TSP emissions equal PM10 emissions.

Total Startup and Shutdown HoursCold Start Hours, per event 3.08Warm Start Hours, per event 1.25Hot Start Hours, per event 0.58Shutdown Hours, per event 0.30Minimum Duration Between Operation:Cold Starts (> 72 hrs downtime): 72.0Warm Starts (8-48 hrs downtime): 8.0Hot Starts (0-8 hrs downtime): 0.0Events per Year:Cold Startups events per year per CT 16Warm Startups events per year per CT 198Hot Startups events per year per CT 4Shutdown events per year 218 Same as total startupsStartup and Shutdown Operation (hr/yr) 3100.6 Sum of duration + downtime multiplied by number of events, for each event type
Emission Calculations

CCCT Criteria and GHG Emission Factors1,2,3 - Continuous Operation Page 8 of 22 TSD App A

Emissions Data for each CCCT Case 1 Case 2 Case 3 Case 4 Case 5 Case 6 Case 7 Case 8 Case 9

Load 100 100 100 75 75 75 47 46 56

Duct Burner Firing Yes No No No No No No No No

Stack Temperature (F) 188 192 196 177 178 185 175 175 176Total Exhaust Gas Flow (acfm) 1,143,330 1,165,380 1,258,320 764,990 910,067 1,005,403 599,834 694,208 830,243CO (lb/hr) 10.0 9.2 9.9 6.8 7.3 8.0 5.4 5.7 6.7NOX as NO2 (lb/hr) 16.4 15.1 16.2 11.2 12.0 13.1 8.9 9.3 11.0

TSP (lb/hr)4 18.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0

Total PM10(lb/hr) 18.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0

Total PM2.5 (lb/hr)4 18.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0

SO2 (lb/hr) 5.7 5.3 5.7 3.9 4.2 4.6 3.1 3.3 3.8

VOC (lb/hr) 5.7 2.7 2.8 2.0 2.1 2.3 1.6 1.6 1.9Lead (lb/hr) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0H2SO4 (lb/hr)7 4.5 4.1 4.5 3.1 3.3 3.6 2.4 2.6 3.0

Fluorides (other than HF) (lb/hr) 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Ammonia Slip (lb/hr) 15.9 14.7 15.7 10.8 11.7 12.8 8.6 9.0 10.7CO2 (lb/hr) 270,115 249,785 267,828 185,248 199,683 218,930 146,755 153,972 182,842

CH4 (lb/MMBtu)5 2.2E-03 2.2E-03 2.2E-03 2.2E-03 2.2E-03 2.2E-03 2.2E-03 2.2E-03 2.2E-03

CH4 (lb/hr)6 5.0 4.6 4.9 3.4 3.7 4.0 2.7 2.8 3.4

N2O (lb/MMBtu)5 2.2E-04 2.2E-04 2.2E-04 2.2E-04 2.2E-04 2.2E-04 2.2E-04 2.2E-04 2.2E-04

N2O (lb/hr)6 0.5 0.5 0.5 0.3 0.4 0.4 0.3 0.3 0.3

1. Emission factors obtained from client, unless otherwise noted. 2. Emission factors were given per 2x1 block. Numbers in table are presented per combustion turbine.3. Emission factors in lb/hr based on GT Pro software, with the following modifications & assumptions

NOX emission factors rounded up to next whole number to account for software understimating ppmvd. Duct burner emissions based on 0.06 lb NOX/MMBtu.

CO emission factors rounded up (or, for whole numbers, increased by 1) to account for decrease in function of oxidation catalyst over time. Duct burner emissions based on 0.04 lb CO/MMBtu. 80% control assumed.VOC emission factors based on GE guaranteed levels, plus a duct burner emission factor of 0.006 lb VOC as CH4/MMBTU (HHV) and conservative assumption of 25% reduction of VOC across the oxidation catalyst.

PM10 values based on GE-published values for engine exhaust of 9 lb/hr filterable and 9 lb/hr condensable. For duct burner case, PM10 emission factor of 0.0045 lb/Mmbtu (HHV) was used as advised by Vogt (HRSG supplier).

SO2 emission factor based on 0.75 gr/100 scf sulfur in fuel.

4. TSP and PM2.5 emission factors conservatively assumed equal to PM10.

5. Emission factors obtained from 40 CFR 98, Subpart C. Note that these are uncontrolled emission factors.6. Emission factors in lb/hr calculated based on 40 CFR 98, Subpart C emission factors total heat consumption (MMBtu/hr) for each case.7. H2SO4 emission factors calculated based on 34% molar conversion of SO2 to SO3 across the oxidation catalyst, and 100% conversion of SO3 to H2SO4.

SO3 formed across SCR (mol/hr) = [SO2 Emissions Post-SCR (mol/hr) / 0.66] - [SO2 Emissions Post-SCR (mol/hr)]

H2SO4 Emissions (lb/hr) = SO3 formed across SCR (mol/hr) * (1 mol H2SO4/ 1 mol SO3) * (98 g H2SO4 /mol) * (kg/1000g) * (lb/0.45 kg)

CCCT Criteria and GHG Emission Factors - Startup/Shutdown

Pollutant 

Cold Start 

Emissions 

(lb/hr)

Warm Start 

Emissions 

(lb/hr)

Hot Start 

Emissions 

(lb/hr)

Shutdown Emissions 

(lb/hr)

CO 689.2 564.0 454.0 445.0

NOX 143.7 75.0 129.6 22.0

TSP 12.0 12.0 7.0 4.0Total PM10 12.0 7.0 12.0 4.0

Total PM2.5 12.0 7.0 12.0 4.0SO2 1.2 1.0 1.4 0.8

VOC 49.6 31.2 22.0 12.0Lead - - - -

H2SO4 - - - -

Fluorides (other than HF) - - - -

NH3 - - - -

CO2 73,345.6 60,202.6 84,698.8 36,718.4

CH4 1.4 1.1 1.6 0.7

N2O 0.1 0.1 0.2 0.1

Methodology:For events lasting longer than 1 hr: Emissions (lb/hr) = (lb/event) / (hr/event)For events lasting less than 1 hr: Emissions (lb/hr) = lb/eventEmissions (lb/event) are for conventional startup/shutdown of lead combustion turbine.  "Stack exit conditions for startup JW R2 9-13.doc." GHG lb/event calculated based on fuel consumption per event and default pollutant emission factors in 40 CFR 98 Subpart C.Emissions (lb/event) assume no control devices.Conservatively assumed that PM2.5 emissions equal PM10 emissions.

Conservatively assumed that TSP emissions equal PM10 emissions.
Emission Calculations

Summary of CCCT Criteria and GHG Potential Emissions PNumber of CCCTs 4Potential Operation 8,760 hr/yr

Total Event Hours Minimum Downtime Between Events Total Event & Down

Number of Cold Starts (each CCCT) 16 events/yr 3.08 hr/event 49.3 hr/yr 72 hr 1,201 h

Number of Warm Starts (each CCCT) 198 events/yr 1.25 hr/event 247.5 hr/yr 8 hr 1,832 h

Number of Hot Starts (each CCCT) 4 events/yr 0.58 hr/event 2.3 hr/yr - hr 2 h

Number of Shutdowns (each CCCT) 218 events/yr 0.30 hr/event 65.4 hr/yr - hr 65 h

Continuous Operation with Maximum

Normal Cold Warm Hot Normal Operation1 Startups and Shutdowns2

Operation Startup Startup Startup Shutdown Each CCCT All CCCT Each CCCT All CCCT

Pollutant (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (tpy) (tpy) (tpy) (tpy) (lb/hr)3 

CO 10.0 689.2 564.0 454.0 445.0 43.6 174.3 130.0 520.1 689.2 

NOX 143.7 16.4 129.6 75.0 22.0 71.8 287.3 66.8 267.2 143.7 

TSP 18.0 12.0 12.0 7.0 4.0 78.8 315.4 52.9 211.4 18.0 

Total PM10 12.0 18.0 12.0 7.0 4.0 78.8 315.4 52.9 211.4 18.0 

Total PM2.5 12.0 18.0 12.0 7.0 4.0 78.8 315.4 52.9 211.4 18.0 SO2 1.2 5.7 1.4 1.0 0.8 25.0 99.9 16.4 65.5 5.7 

VOC 5.7 49.6 31.2 22.0 12.0 25.0 99.9 21.6 86.5 49.6 

Lead - - - - - - - - - - 

H2SO4 - 4.5 - - - 19.7 78.8 12.7 50.9 4.5 

Fluorides (Other than HF) - - - - - - - - - - 

NH3 - 15.9 - - - 69.4 277.7 44.9 179.4 15.9 

CO2 73,345.6 270,115.0 84,698.8 60,202.6 36,718.4 1,183,104 4,732,415 777,911 3,111,642 270,115 

CH4 1.4 5.0 1.6 1.1 0.7 22 87 14.3 57 5 

N2O 0.1 0.5 0.2 0.1 0.1 2.2 8.7 1.4 5.7 0.5 

1. Based on 8,760 hr/yr at normal operations.3. Based on the worst-case of normal, startup (cold, warm or hot), or shutdown operations.4. Based on the worst-case continuous normal operation or operation with maximum startups and shutdowns.

Maximum # Events Event Duration 

2. Based on maximum number of hours of each startup or shutdown per year multiplied by the average lb/hr rate for each event type plus normal operation for the remainder of the year (8,760 hr/yr - total event & downtime hours).

Worst-Case 

Emissions, E

CONTROLLED (per turbine) UNCONTROLLED (per turbine) - Weighted Averages
Emission Calculations

Summary of CCCT Criteria and GHG Potential Emissions PNumber of CCCTs 4Potential Operation 8,760 hr/yr

Total Event Hours Minimum Downtime Between Events Total Event & Down

Number of Cold Starts (each CCCT) 16 events/yr 3.08 hr/event 49.3 hr/yr 72 hr 1,201 h

Number of Warm Starts (each CCCT) 198 events/yr 1.25 hr/event 247.5 hr/yr 8 hr 1,832 h

Number of Hot Starts (each CCCT) 4 events/yr 0.58 hr/event 2.3 hr/yr - hr 2 h

Number of Shutdowns (each CCCT) 218 events/yr 0.30 hr/event 65.4 hr/yr - hr 65 h

Continuous Operation with Maximum

Normal Cold Warm Hot Normal Operation4 Startups and Shutdowns5

Operation1,2,3 Startup Startup Startup Shutdown Each CCCT All CCCT Each CCCT All CCCT

Pollutant (lb/hr) (lb/hr) (lb/hr) (lb/hr) (lb/hr) (tpy) (tpy) (tpy) (tpy) (lb/hr)6 

CO 49.8 689.2 564.0 454.0 445.0 217.9 871.6 242.7 970.6 689.2 

NOX 143.7 82.0 129.6 75.0 22.0 359.2 1,436.6 252.4 1,009.7 143.7 

TSP 18.0 12.0 12.0 7.0 4.0 78.8 315.4 52.9 211.4 18.0 

Total PM10 12.0 18.0 12.0 7.0 4.0 78.8 315.4 52.9 211.4 18.0 

Total PM2.5 12.0 18.0 12.0 7.0 4.0 78.8 315.4 52.9 211.4 18.0 SO2 1.2 5.7 1.4 1.0 0.8 25.0 99.9 16.4 65.5 5.7 

VOC 7.6 49.6 31.2 22.0 12.0 33.3 133.2 27.0 108.0 49.6 

Lead - - - - - - - - - - 

H2SO4 - 4.5 - - - 19.7 78.8 12.7 50.9 4.5 

Fluorides (Other than HF) - - - - - - - - - - 

NH3 - 15.9 - - - 69.4 277.7 44.9 179.4 15.9 

CO2 73,345.6 270,115.0 84,698.8 60,202.6 36,718.4 1,183,104 4,732,415 777,911 3,111,642 270,115 

CH4 1.4 5.0 1.6 1.1 0.7 22 87 14.3 57 5 

N2O 0.1 0.5 0.2 0.1 0.1 2.2 8.7 1.4 5.7 0.5 

1. Assumes 80% control of CO from oxidation catalyst to estimate uncontrolled emission factor. Actual control efficiency will vary based on ambient air and load conditions.2. Assumes 80% control of NOX from selective catalytic reduction system to estimate uncontrolled emission factor. Actual control efficiency will vary based on ambient air and load conditions.

3. Assumes 25% control of VOC from oxidation catalyst to estimate uncontrolled emission factor. Actual control efficiency will vary based on ambient air and load conditions.4. Based on 8,760 hr/yr at normal operations.6. Based on the worst-case of normal, startup (cold, warm or hot), or shutdown operations.7. Based on the worst-case continuous normal operation or operation with maximum startups and shutdowns.

Emissions, E

5. Based on maximum number of hours of each startup or shutdown per year multiplied by the average lb/hr rate for each event type plus normal operation for the remainder of the year (8,760 hr/yr - total event & downtime hours).

Maximum # Events Event Duration 

UNCONTROLLED (per turbine) UNCONTROLLED (per turbine) - Weighted Averages

Worst-Case 
Emission Calculations

CCCT Maximum Potential HAP Emissions - CT Page 11 of 2CCCTsShort-term Heat Input (each) 2,230 MMBtu/hr (HHV), worst-case scenarioPotential Operation 8,760 hr/yrOrganic Pollutant Control 25% (from Oxidation Catalyst)Number of CCCT 4

Uncontrolled

Emission Factor1

Pollutant HAP Reason/CAS Organic? (lb/MMBtu) (lb/hr) (tpy) 

1,3-Butadiene 106990 Yes 6.05E-08 1.01E-04 4.43E-04 Acetaldehyde 75070 Yes 4.31E-05 7.20E-02 3.15E-01 Acrolein 107028 Yes 5.60E-06 9.36E-03 4.10E-02 Benzene 71432 Yes 1.30E-05 2.18E-02 9.56E-02 Ethylbenzene 100414 Yes 2.28E-05 3.82E-02 1.67E-01 Formaldehyde3 50000 Yes 1.74E-04 2.91E-01 1.27E+00 

Naphthalene 91203 Yes 6.33E-07 1.06E-03 4.64E-03 PAH POM Yes 4.71E-07 7.87E-04 3.45E-03 Propylene Oxide 75569 Yes 2.86E-05 4.78E-02 2.10E-01 Toluene 108883 Yes 6.80E-05 1.14E-01 4.98E-01 Xylenes 108383, 106423 Yes 6.51E-05 1.09E-01 4.77E-01 Total HAP 7.05E-01 3.09E+00 Maximum Single HAP 2.91E-01 1.27E+00 

2. Includes application of the control efficiency from the oxidation catalyst for organic pollutants.3. Formaldehyde custom emission factor excludes a single high outlier and a single low outlier.

Potential Emissions

Each CCCT2

1. Unless otherwise noted, emission factors are based on average of large (>40 MW) natural gas-fired turbine test data from AP-42 Section 3.1.
Emission Calculations

CCCT Maximum Potential HAP Emissions Page 12 of 2CCCTsShort-term Heat Input (each) 2,230 MMBtu/hr (HHV), worst-case scenarioPotential Operation 8,760 hr/yrNumber of CCCT 4

Uncontrolled

Emission Factor1

Pollutant HAP Reason/CAS Organic? (lb/MMBtu) (lb/hr) (tpy) 

1,3-Butadiene 106990 Yes 6.05E-08 1.35E-04 5.91E-04 Acetaldehyde 75070 Yes 4.31E-05 9.60E-02 4.20E-01 Acrolein 107028 Yes 5.60E-06 1.25E-02 5.46E-02 Benzene 71432 Yes 1.30E-05 2.91E-02 1.27E-01 Ethylbenzene 100414 Yes 2.28E-05 5.09E-02 2.23E-01 Formaldehyde2 50000 Yes 1.74E-04 3.88E-01 1.70E+00 

Naphthalene 91203 Yes 6.33E-07 1.41E-03 6.18E-03 PAH POM Yes 4.71E-07 1.05E-03 4.60E-03 Propylene Oxide 75569 Yes 2.86E-05 6.38E-02 2.79E-01 Toluene 108883 Yes 6.80E-05 1.52E-01 6.64E-01 Xylenes 108383, 106423 Yes 6.51E-05 1.45E-01 6.35E-01 Total HAP 9.39E-01 4.11E+00 Maximum Single HAP 3.88E-01 1.70E+00 

2. Formaldehyde custom emission factor excludes a single high outlier and a single low outlier.

Potential Emissions 

Each CCCT 

1. Unless otherwise noted, emission factors are based on average of large (>40 MW) natural gas-fired turbine test data from AP-42 Section 3.1.
Emission Calculations

Auxiliary Boiler Potential NSR-Regulated and GHG Pollutant Emissions Page 13 of 22 TSD App AAuxiliary Boiler DataMaximum Heat Input 80.00 MMBtu/hr (HHV)Fuel Heat Content 1,020 MMBtu/MMscf (HHV)Potential Operation 8,760 hr/yrNumber of Auxiliary Boilers 2Criteria and GHG Pollutant Emissions

Pollutant (lb/hr) (lb/MMBtu)1 (lb/hr) (tpy) (lb/hr) (tpy)

CO 6.6 - 6.60 28.91 13.20 57.82NOX 2.5 - 2.51 10.99 5.02 21.99

TSP 0.6 - 0.60 2.63 1.20 5.26Total PM10 0.6 - 0.60 2.63 1.20 5.26Total PM2.5 0.6 - 0.60 2.63 1.20 5.26SO23 - 0.00221 0.18 0.77 0.35 1.55

VOC 0.4 - 0.40 1.75 0.80 3.50Lead - 0.0 0.00 0.00 0.00 0.00H2SO4 0.0 0.0 0.00 0.00 0.00 0.00

Fluorides (other than HF) 0.0 0.0 0.00 0.00 0.00 0.00NH3 0.0 0.0 0.00 0.00 0.00 0.00CO2 - 116.9 9351.13 40957.94 18702.25 81915.88

CH4 - 0.0 0.18 0.77 0.35 1.54N2O - 0.0 0.02 0.08 0.04 0.15

3. Assumed a sulfur content of 7,500 grains per MMscf.

Toxic/Hazardous Air Pollutant Emissions

Pollutant (lb/MMscf) (lb/MMBtu) (lb/hr) (tpy) (lb/hr) (tpy)

2-Methylnaphthalene 2.4E-05 2.4E-08 1.88E-06 8.24E-06 3.76E-06 1.65E-053-Methylchloranthrene 1.8E-06 1.8E-09 1.41E-07 6.18E-07 2.82E-07 1.24E-067,12-Dimethylbenz(a)anthracene 1.6E-05 1.6E-08 1.25E-06 5.50E-06 2.51E-06 1.10E-05Acenaphthene 1.8E-06 1.8E-09 1.41E-07 6.18E-07 2.82E-07 1.24E-06Acenaphthylene 1.8E-06 1.8E-09 1.41E-07 6.18E-07 2.82E-07 1.24E-06Anthracene 2.4E-06 2.4E-09 1.88E-07 8.24E-07 3.76E-07 1.65E-06Arsenic 2.0E-04 2.0E-07 1.57E-05 6.87E-05 3.14E-05 1.37E-04Beryllium 1.2E-05 1.2E-08 9.41E-07 4.12E-06 1.88E-06 8.24E-06Benzene 2.1E-03 2.1E-06 1.65E-04 7.21E-04 3.29E-04 1.44E-03Benz(a)anthracene 1.8E-06 1.8E-09 1.41E-07 6.18E-07 2.82E-07 1.24E-06Benzo(a)pyrene 1.2E-06 1.2E-09 9.41E-08 4.12E-07 1.88E-07 8.24E-07Benzo(b)fluoranthene 1.8E-06 1.8E-09 1.41E-07 6.18E-07 2.82E-07 1.24E-06Benzo(g,h,i)perylene 1.2E-06 1.2E-09 9.41E-08 4.12E-07 1.88E-07 8.24E-07Benzo(k)fluoranthene 1.8E-06 1.8E-09 1.41E-07 6.18E-07 2.82E-07 1.24E-06Cadmium 1.1E-03 1.1E-06 8.63E-05 3.78E-04 1.73E-04 7.56E-04Chromium 1.4E-03 1.4E-06 1.10E-04 4.81E-04 2.20E-04 9.62E-04Chrysene 1.8E-06 1.8E-09 1.41E-07 6.18E-07 2.82E-07 1.24E-06Cobalt 8.4E-05 8.2E-08 6.59E-06 2.89E-05 1.32E-05 5.77E-05Dibenzo(a,h)anthracene 1.2E-06 1.2E-09 9.41E-08 4.12E-07 1.88E-07 8.24E-07Dichlorobenzene 1.2E-03 1.2E-06 9.41E-05 4.12E-04 1.88E-04 8.24E-04Fluoranthene 3.0E-06 2.9E-09 2.35E-07 1.03E-06 4.71E-07 2.06E-06Fluorene 2.8E-06 2.7E-09 2.20E-07 9.62E-07 4.39E-07 1.92E-06Formaldehyde 7.5E-02 7.4E-05 5.88E-03 2.58E-02 1.18E-02 5.15E-02Hexane 1.8E+00 1.8E-03 1.41E-01 6.18E-01 2.82E-01 1.24E+00Indeno(1,2,3-cd)pyrene 1.8E-06 1.8E-09 1.41E-07 6.18E-07 2.82E-07 1.24E-06Lead 5.0E-04 4.9E-07 3.92E-05 1.72E-04 7.84E-05 3.44E-04Manganese 3.8E-04 3.7E-07 2.98E-05 1.31E-04 5.96E-05 2.61E-04Mercury 2.6E-04 2.5E-07 2.04E-05 8.93E-05 4.08E-05 1.79E-04Naphthalene 6.1E-04 6.0E-07 4.78E-05 2.10E-04 9.57E-05 4.19E-04Nickel 2.1E-03 2.1E-06 1.65E-04 7.21E-04 3.29E-04 1.44E-03Phenanthrene 1.7E-05 1.7E-08 1.33E-06 5.84E-06 2.67E-06 1.17E-05Pyrene 5.0E-06 4.9E-09 3.92E-07 1.72E-06 7.84E-07 3.44E-06Selenium 2.4E-05 2.4E-08 1.88E-06 8.24E-06 3.76E-06 1.65E-05Toluene 3.4E-03 3.3E-06 2.67E-04 1.17E-03 5.33E-04 2.34E-03Total HAP 1.48E-01 6.49E-01 2.96E-01 1.30E+00Highest Single HAP 1.41E-01 6.18E-01 2.82E-01 1.24E+00

1. Per AP-42, Section 1.4, July 1998.

Emission Factor Potential Emissions (each boiler) 1

Emission Factor Potential Emissions (both boilers) Potential Emissions (each boiler)

Potential Emissions (both boilers)

1. Factor based on conversion of AP-42 Section 1.4 emission factor in lb/MMscf to lb/MMBtu, based on natural gas HHV of 1,020 Btu/scf, per Table 1.4-1 footnote a. For GHGs, factor based on default pollutant emission factors for natural gas in 40 CFR 98, Subpart C, converted to lb/MMBtu based on natural gas HHV of 1,020 Btu/scf.2. Per AP-42 Section 1.4, all PM (total, condensible, and filterable) is assumed to be less than 1.0 micrometer in diameter. Therefore, the PM emission factors presented in AP-42 Section 1.4 may be used to estimate PM 10 or PM2.5 emissions. TSP/PM10/PM2.5 include filterable and condensable PM.
Emission Calculations

Cooling Tower Potential NSR-Regulated Pollutant Emissions Number of cooling towers: 2Cooling Towers

Cooling Tower 

Capacity (each)

Total 

Dissolved 

Solids

Drift 

Loss Drift Mass Flow Rate1

(gpm) (ppm) (%) (lb/hr) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/hr) (tpy) (lb/h

170,000 2,000 0.0005% 425.6 0.851 3.728 0.541 2.367 0.002 0.008 1.702 7.456 1.08

1. Drift mass flow rate (lb/hr) = Cooling tower capacity (gpm) x Density of water (8.34 lb/gal) x 60 (min/hour) x Drift loss (%) .5. Annual TSP/PM10/PM2.5 emission rate (ton/yr) = Hourly emission rate (lb/hr) x 8,760 (hours/yr)/(2000 lb/ton).ReferenceJ. Reisman and G. Frisbie, Calculating Realistic PM10 Emissions from Cooling Towers, Presented at Air & Waste Management Association Annual Conference. (June 2001)3. PM10 emissions (lb/hr) = Drift mass flow rate (lb/hr) x TDS (ppm)/(106) x Percent PM smaller than PM104. PM2.5 emissions (lb/hr) = Drift mass flow rate (lb/hr) x TDS (ppm)/(106) x Percent PM smaller than PM2.52. TSP emissions (lb/hr) = Drift mass flow rate (lb/hr) x TDS (ppm)/(106)

Total TSP

Emission Rate 

(each tower)2,5

Total PM10 

Emission Rate 

(each tower)3,5,6

Total TSP 

Emission Rate 

(both towers)

T

Em

(b

Total PM2.5 

Emission Rate 

(each tower)4,5,6
Emission Calculations

Page 15 of 22 TSD App A

EPRI Droplet 

Diameter1 Droplet Volume Droplet Mass Particle Mass (Solids) Solid Particle Volume

S

(μm) (μm3) (μg) (μg) (μm3) 

10 0 5.24E+02 5.24E-04 1.05E-06 4.76E-01 20 0.196 4.19E+03 4.19E-03 8.38E-06 3.81E+00 

25.81 0.213 9.00E+03 9.00E-03 1.80E-05 8.18E+00 

30 0.226 1.41E+04 1.41E-02 2.83E-05 1.29E+01 40 0.514 3.35E+04 3.35E-02 6.70E-05 3.05E+01 50 1.816 6.54E+04 6.54E-02 1.31E-04 5.95E+01 60 5.702 1.13E+05 1.13E-01 2.26E-04 1.03E+02 70 21.348 1.80E+05 1.80E-01 3.59E-04 1.63E+02 90 49.812 3.82E+05 3.82E-01 7.63E-04 3.47E+02 

103.23 63.501 5.76E+05 5.76E-01 1.15E-03 5.24E+02 

110 70.509 6.97E+05 6.97E-01 1.39E-03 6.34E+02 130 82.023 1.15E+06 1.15E+00 2.30E-03 1.05E+03 150 88.012 1.77E+06 1.77E+00 3.53E-03 1.61E+03 180 91.032 3.05E+06 3.05E+00 6.11E-03 2.78E+03 210 92.468 4.85E+06 4.85E+00 9.70E-03 4.41E+03 240 94.091 7.24E+06 7.24E+00 1.45E-02 6.58E+03 270 94.689 1.03E+07 1.03E+01 2.06E-02 9.37E+03 300 96.288 1.41E+07 1.41E+01 2.83E-02 1.29E+04 350 97.011 2.24E+07 2.24E+01 4.49E-02 2.04E+04 400 98.34 3.35E+07 3.35E+01 6.70E-02 3.05E+04 450 99.071 4.77E+07 4.77E+01 9.54E-02 4.34E+04 500 99.071 6.54E+07 6.54E+01 1.31E-01 5.95E+04 600 100 1.13E+08 1.13E+02 2.26E-01 1.03E+05 

ReferenceJ. Reisman and G. Frisbie, Calculating Realistic PM10 Emissions from Cooling Towers, Presented at Air & Waste Management Association Annual Conference. (June 2001)

1. Test data provided by Brentwood Industries for cooling tower with 0.0003% drift rate. The use of this data is conservative as it can be reasonably expected that a co0.0003% drift rate will produce smaller droplets than one with a 0.0005% drift rate.

Cooling Tower Particle Size Distribution

EPRI % Mass 

Smaller1

2. Highlights indicate interpolated values to determine PM10/PM2.5 speciation.
Emission Calculations

CCCT Lube Oil Demister Vent Potential Fugitive Emissions Page 16 oCT/ST Lube Oil Demister Vent DataNumber of CT/ST 6Oil Mist Loading 7 mg/m3Oil Mist Loading 4.41E-07 lb/acfOil Mist Fan Vent Flow Rate 500 cfmFugitive VOC Emissions

Pollutant (lb/hr) (tpy) (lb/hr) (tpy)

TSP/PM10/PM2.5 (total) 0.0 0.1 0.1 0.3

VOC 0.0 0.1 0.1 0.3

1. Emission factor per turbine (lb/hr) = Oil mist loading (lb/acf) * Oil Mist Fan Vent Flow Rate (cfm) * (60 min/hr)2. Emission factor, all turbines (lb/hr) = Oil mist loading (lb/acf) * Oil Mist Fan Vent Flow Rate (cfm) * (60 min/hr) * Total Number of Combustion and Steam Turbines3. Emissions per turbine (ton/yr) = Emission factor (lb/hr) * Hours of Operation (8,760 hr/yr) * (ton/2000 lb)4. Emissions, all turbines (ton/yr) = Emission factor (lb/hr) * Hours of Operation (8,760 hr/yr) * (ton/2000 lb) * Total Number of Combustion and Steam Turbines

Conversion Factors

0.45359237 kg/lb

0.3048 m/ft

Each CT/ST1,3

Potential Emissions Potential Emissions

All CCCT/ST2,4
Emission Calculations

Emergency Fire Water Pump Engine Potential NSR-Regulated and HAP Emissions Page 17 of 22 TSD App AFire Water Pumps: FP01, FP02Engine Power 371 bhpHours of Operation 500 hr/yrHeating Value of Diesel 19,300 Btu/lb Per AP-42, Section 3.3, Table 3.3-1 footnote.Power Conversion 7,000 Btu/hp-hr Per AP-42, Section 3.3, Table 3.3-1 footnote.Heat Input 2.60 MMBtu/hr, inputNumber of FWP Engines 2Criteria and GHG Pollutant Emissions

Emission

Factor1 Units (lb/hr) (tpy)4 (lb/hr) (tpy)4

CO 1.70 lb/hr 1.70 0.43 3.40 0.85NOX 1.98 lb/hr 1.98 0.50 3.96 0.99

TSP 0.10 lb/hr 0.10 0.03 0.20 0.05PM10 0.10 lb/hr 0.10 0.03 0.20 0.05PM2.5 0.10 lb/hr 0.10 0.03 0.20 0.05SO22 0.00 lb/hp-hr 0.76 0.19 1.52 0.38VOC 0.13 lb/hr 0.13 0.03 0.25 0.06CO23 342.41 lb/hr 342.41 85.60 684.83 171.21

CH43 0.01 lb/hr 0.01 0.00 0.03 0.01

N2O3 0.00 lb/hr 0.00 0.00 0.01 0.001. CO, NOX, and TSP/PM10/PM2.5 emissions standards for Tier 3 stand-by emergency use engines. VOC emissions taken from a Cummin

2. Per AP-42 Section 3.3, Table 3.3-1 for diesel fuel.4. Emissions in tons per year calculated assuming 500 hours of operation annually.Toxic/Hazardous Air Pollutant Emissions

Emission Factor

(lb/MMBtu) (lb/hr)2 (tpy)3 (lb/hr)2 (tpy)3

1,3-Butadiene 3.9E-05 1.0E-04 2.5E-05 2.0E-04 5.1E-05Acenaphthene 1.4E-06 3.7E-06 9.2E-07 7.4E-06 1.8E-06Acenaphthylene 5.1E-06 1.3E-05 3.3E-06 2.6E-05 6.6E-06Acetaldehyde 7.7E-04 2.0E-03 5.0E-04 4.0E-03 1.0E-03Acrolein 9.3E-05 2.4E-04 6.0E-05 4.8E-04 1.2E-04Anthracene 1.9E-06 4.9E-06 1.2E-06 9.7E-06 2.4E-06Benzene 9.3E-04 2.4E-03 6.1E-04 4.8E-03 1.2E-03Benz(a)anthracene 1.7E-06 4.4E-06 1.1E-06 8.7E-06 2.2E-06Benzo(a)pyrene 1.9E-07 4.9E-07 1.2E-07 9.8E-07 2.4E-07Benzo(b)fluoranthene 9.9E-08 2.6E-07 6.4E-08 5.1E-07 1.3E-07Benzo(g,h,i)perylene 4.9E-07 1.3E-06 3.2E-07 2.5E-06 6.3E-07Benzo(k)fluoranthene 1.6E-07 4.0E-07 1.0E-07 8.1E-07 2.0E-07Chrysene 3.5E-07 9.2E-07 2.3E-07 1.8E-06 4.6E-07Dibenzo(a,h)anthracene 5.8E-07 1.5E-06 3.8E-07 3.0E-06 7.6E-07Fluoranthene 7.6E-06 2.0E-05 4.9E-06 4.0E-05 9.9E-06Fluorene 2.9E-05 7.6E-05 1.9E-05 1.5E-04 3.8E-05Formaldehyde 1.2E-03 3.1E-03 7.7E-04 6.1E-03 1.5E-03Indeno(1,2,3-cd)pyrene 3.8E-07 9.7E-07 2.4E-07 1.9E-06 4.9E-07Naphthalene 8.5E-05 2.2E-04 5.5E-05 4.4E-04 1.1E-04Phenanthrene 2.9E-05 7.6E-05 1.9E-05 1.5E-04 3.8E-05Pyrene 4.8E-06 1.2E-05 3.1E-06 2.5E-05 6.2E-06Toluene 4.1E-04 1.1E-03 2.7E-04 2.1E-03 5.3E-04Xylenes 2.9E-04 7.4E-04 1.9E-04 1.5E-03 3.7E-04

Total HAP 1.0E-02 2.5E-03 2.0E-02 5.0E-03

Highest Single HAP 3.1E-03 7.7E-04 6.1E-03 1.5E-03

1. Per AP-42 Section 3.3, October 1996.2. Emissions (lb/hr) calculated assuming heat input capacity of 2.1 MMBtu/hr.3. Emissions in tons per year calculated assuming 500 hours of operation annually

Potential Emissions (both FWP)

Potential Emissions (each FWP)Potential Emissions (both FWP)

PollutantPollutant

Potential Emissions (each FWP)

3. Calculated using 40 CFR 98, Subpart C, Tables C-1 and C-2 default pollutant emission factors for No. 2 fuel oil, fire pump fuel consumption, and the following values for diesel fuel per AP-42 Section 3.4: 19,300 Btu/lb, and 7.1 lb/gal.
Emission Calculations

Emergency Diesel Generator Emissions Page 18 of 22 TSD App AEmergency Generators: EG01 & EG02Engine Power 1,006 hp, outputHours of Operation 500 hr/yrHeating Value of Diesel 19,300 Btu/lb Per AP-42, Section 3.3, Table 3.3-1 footnote.Power Conversion 7,000 Btu/hp-hr Per AP-42, Section 3.3, Table 3.3-1 footnote.Heat Input 7.04 MMBtu/hr, inputNumber of Emergency Generators 2Criteria and GHG Pollutant Emissions

Units (lb/hr) (tpy)4 (lb/hr) (tpy)4

CO 5.80 lb/hr 5.8 1.5 11.6 2.9NOX 10.60 lb/hr 10.6 2.7 21.2 5.3

TSP 0.33 lb/hr 0.3 0.1 0.7 0.2PM10 0.33 lb/hr 0.3 0.1 0.7 0.2

PM2.5 0.33 lb/hr 0.3 0.1 0.7 0.2SO22 0.00001 lb/hp-hr 0.0122 0.0 0.0 0.0

VOC 0.20 lb/hr 0.2 0.1 0.4 0.1CO23 1197.60 lb/hr 1197.6 299.4 2395.2 598.8CH43 0.05 lb/hr 0.0 0.0 0.1 0.0

N2O3 0.01 lb/hr 0.0 0.0 0.0 0.0

1. CO, NOX, and TSP/PM10/PM2.5 emissions standards for Tier 3 stand-by emergency use engines. VOC emissions taken from a Cummins guarantee for a similarly size engine.

2. Emission factor calculated per AP-42 Section 3.4, Table 3.4-1 footnote d, assuming use of ULSD (<0.0015% sulfur).4. Emissions in tons per year calculated assuming 500 hours of operation annually.

Toxic/Hazardous Air Pollutant Emissions

Emission 

Factor1

(lb/MMBtu) (lb/hr)2 (tpy)3 (lb/hr)2 (tpy)3

Acenaphthene 4.7E-06 3.3E-05 8.2E-06 6.6E-05 1.6E-05Acenaphthylene 9.2E-06 6.5E-05 1.6E-05 1.3E-04 3.2E-05Acetaldehyde 2.5E-05 1.8E-04 4.4E-05 3.5E-04 8.9E-05Acrolein 7.9E-06 5.5E-05 1.4E-05 1.1E-04 2.8E-05Anthracene 1.2E-06 8.7E-06 2.2E-06 1.7E-05 4.3E-06Benzene 7.8E-04 5.5E-03 1.4E-03 1.1E-02 2.7E-03Benz(a)anthracene 6.2E-07 4.4E-06 1.1E-06 8.8E-06 2.2E-06Benzo(a)pyrene 2.6E-07 1.8E-06 4.5E-07 3.6E-06 9.0E-07Benzo(b)fluoranthene 1.1E-06 7.8E-06 2.0E-06 1.6E-05 3.9E-06Benzo(g,h,i)perylene 5.6E-07 3.9E-06 9.8E-07 7.8E-06 2.0E-06Benzo(k)fluoranthene 2.2E-07 1.5E-06 3.8E-07 3.1E-06 7.7E-07Chrysene 1.5E-06 1.1E-05 2.7E-06 2.2E-05 5.4E-06Dibenzo(a,h)anthracene 3.5E-07 2.4E-06 6.1E-07 4.9E-06 1.2E-06Fluoranthene 4.0E-06 2.8E-05 7.1E-06 5.7E-05 1.4E-05Fluorene 1.3E-05 9.0E-05 2.3E-05 1.8E-04 4.5E-05Formaldehyde 7.9E-05 5.6E-04 1.4E-04 1.1E-03 2.8E-04Indeno(1,2,3-cd)pyrene 4.1E-07 2.9E-06 7.3E-07 5.8E-06 1.5E-06Naphthalene 1.3E-04 9.2E-04 2.3E-04 1.8E-03 4.6E-04Phenanthrene 4.1E-05 2.9E-04 7.2E-05 5.7E-04 1.4E-04Pyrene 3.7E-06 2.6E-05 6.5E-06 5.2E-05 1.3E-05Toluene 2.8E-04 2.0E-03 4.9E-04 4.0E-03 9.9E-04Xylenes 1.9E-04 1.4E-03 3.4E-04 2.7E-03 6.8E-04Total HAP 1.1E-02 2.8E-03 2.2E-02 5.5E-03Highest Single HAP 5.5E-03 1.4E-03 1.1E-02 2.7E-03

1. Per AP-42 Section 3.4 (Table 3.4-3 and 3.4-4), October 1996.2. Emissions (lb/hr) calculated assuming heat input capacity of 7.04 MMBtu/hr.3. Emissions in tons per year calculated assuming 500 hours of operation annually.

PollutantPollutant

Emission 

Factor1

Potential Emissions (each generator) Potential Emissions (both generators)

Potential Emissions (each generator) Potential Emissions (both generators)

3. Emission factor calculated using 40 CFR 98, Subpart C, Tables C-1 and C-2 default pollutant emission factors for No. 2 fuel oil, emergency generator fuel consumption, and the following values for diesel fuel per AP-42 Section 3.4: 19,300 Btu/lb, and 7.1 lb/gal.
Emission Calculations

Storage Tank Potential Fugitive VOC Emissions Page 19 of 

Quantity Volume1 Contains Throughput2,3,4 

Tank ID Tank Description (gal) VOC/HAP? (gal/yr) Turnovers 

TK09-TK10 Fire Pump ULSD Tank 2 70 Yes 7,663 109.5 TK07-TK08 Emergency Generator ULSD Tank 2 550 Yes 26,800 48.7 

TK11 Vehicle Gasoline Tank 1 650 Yes 33,800 52.0 TK12 Vehicle Diesel Tank 1 650 Yes 33,800 52.0 

TK01-TK06 Turbine Lube Oil Tanks 6 6,800 Yes 81,600 12.0 

TK50

Water Pretreatment Plant Emergency Generator ULSD Tank 1 300 No 52,300 174.3 

Total 

1. Design specifications.2. ULSD tanks' throughput based on engine hourly fuel usage and 500 operating hours per year.3. Vehicle diesel and gasoline tanks' throughput based on conservative assumption of 52 turnovers per year.4. Lube oil tanks' throughput based on conservative assumption of 12 turnovers per year.
Emission Calculations

Page 20 of 22 TSD App A

Emergency Diesel Generator Emissions - Water Treatment Plant Emergency GeneratorEmergency Generator: EG03Engine Power 2,012 hp, outputHours of Operation 500 hr/yrHeating Value of Diesel 19,300 Btu/lb Per AP-42, Section 3.3, Table 3.3-1 footnote.Power Conversion 7,000 Btu/hp-hr Per AP-42, Section 3.3, Table 3.3-1 footnote.Heat Input 14.08 MMBtu/hr, inputNumber of Emergency Generators 1Criteria and GHG Pollutant Emissions

Units (lb/hr) (tpy)4

CO 1.95 lb/hr 1.95 0.49NOX 2.57 lb/hr 2.57 0.64

TSP 0.13 lb/hr 0.13 0.03PM10 0.13 lb/hr 0.13 0.03PM2.5 0.13 lb/hr 0.13 0.03SO22 0.00001 lb/hp-hr 0.02 0.01

VOC 0.49 lb/hr 0.49 0.12CO23 2337.11 lb/hr 2337.11 584.28CH43 0.09 lb/hr 0.09 0.02

N2O3 0.02 lb/hr 0.02 0.005

2. Emission factor calculated per AP-42 Section 3.4, Table 3.4-1 footnote d, assuming use of ULSD (<0.0015% sulfur).4. Emissions in tons per year calculated assuming 500 hours of operation annually.

Toxic/Hazardous Air Pollutant Emissions

Emission 

Factor1

(lb/MMBtu) (lb/hr)2 (tpy)3

Acenaphthene 4.7E-06 6.6E-05 1.6E-05Acenaphthylene 9.2E-06 1.3E-04 3.2E-05Acetaldehyde 2.5E-05 3.5E-04 8.9E-05Acrolein 7.9E-06 1.1E-04 2.8E-05Anthracene 1.2E-06 1.7E-05 4.3E-06Benzene 7.8E-04 1.1E-02 2.7E-03Benz(a)anthracene 6.2E-07 8.8E-06 2.2E-06Benzo(a)pyrene 2.6E-07 3.6E-06 9.0E-07Benzo(b)fluoranthene 1.1E-06 1.6E-05 3.9E-06Benzo(g,h,i)perylene 5.6E-07 7.8E-06 2.0E-06Benzo(k)fluoranthene 2.2E-07 3.1E-06 7.7E-07Chrysene 1.5E-06 2.2E-05 5.4E-06Dibenzo(a,h)anthracene 3.5E-07 4.9E-06 1.2E-06Fluoranthene 4.0E-06 5.7E-05 1.4E-05Fluorene 1.3E-05 1.8E-04 4.5E-05Formaldehyde 7.9E-05 1.1E-03 2.8E-04Indeno(1,2,3-cd)pyrene 4.1E-07 5.8E-06 1.5E-06Naphthalene 1.3E-04 1.8E-03 4.6E-04Phenanthrene 4.1E-05 5.7E-04 1.4E-04Pyrene 3.7E-06 5.2E-05 1.3E-05Toluene 2.8E-04 4.0E-03 9.9E-04Xylenes 1.9E-04 2.7E-03 6.8E-04Total HAP 2.2E-02 5.5E-03Highest Single HAP 1.1E-02 2.7E-03

1. Per AP-42 Section 3.4 (Table 3.4-3 and 3.4-4), October 1996.2. Emissions (lb/hr) calculated assuming heat input capacity of 14.08 MMBtu/hr.3. Emissions in tons per year calculated assuming 500 hours of operation annually.

Pollutant

Potential Emissions

Pollutant

Emission 

Factor1

Potential Emissions

3. Emission factor calculated using 40 CFR 98, Subpart C, Tables C-1 and C-2 default pollutant emission factors for No. 2 fuel oil, emergency generator fuel consumption, and the following values for diesel fuel per AP-42 Section 3.4: 19,300 Btu/lb, and 7.1 lb/gal.1. Unless otherwise noted, emission factors provided manufacturer specifications. 
Emission Calculations

Lime Silo Bin Vent Emission Calculations 

Lime Silo Bin Vent Data

0.005 Outlet Grain loading (gr/dscf)

600 Flow Rate (dscfm)

20 Maximum Material Throughput (ton/hr)

7,000 grains/lb

Controlled TSP/PM10/PM2.5 potential to emit1 (lb/hr) = 0.03

Controlled TSP/PM10/PM2.5 potential to emit2 (tpy) = 0.11Uncontrolled TSP potential to emit3 (lb/hr) = 0.15

Uncontrolled PM10 potential to emit3 (lb/hr) = 0.07

Uncontrolled PM2.5 potential to emit3 (lb/hr) = 0.01

Uncontrolled TSP potential to emit4 (lb/ton) = 7.55E-03

Uncontrolled PM10 potential to emit4 (lb/ton) = 3.57E-03

Uncontrolled PM2.5 potential to emit4 (lb/ton) = 5.41E-041. Controlled PTE (lb/hr) = Flow Rate (scfm) x Outlet Grain Loading (gr/dscf) x 1 lb/7,000 grains x 60 min/hr2. Controlled PTE (ton/yr) = Controlled potential to emit (lb/hr) x 8760 hr/yr x 1 ton/2,000 lb3. Uncontrolled PTE (lb/hr) calculated based on lb/ton emission factor and maximum material throughput (ton/hr).4. Uncontrolled PTE (lb/ton) calculated based on AP-42, Section 13.2.4, equation 1. Assumed minimum moisture content and minim
Emission Calculations

Fugitive Circuit Breaker SF6 Emissions Page 22 of 22 TSD App A

Amount of SF6 

Per Breaker1

SF6 Leak

Rate2

SF6 Emission

Rate CO2e

(lb) (%/yr) (tpy) (tpy)

GHG Fugitive Equipment Leaks 6 60 0.5 9.0E-04 21.5

1. Design specification.2. Proposed BACT limitMethodologySF6 Emission Rate (tpy) = Number of Breakers * Amount of SF6 Per Breaker (lb) * SF6 Leak Rate (%/yr) * 1ton/2000lb

CO2e = SF6 Emission Rate (tpy) * Global Warming Potential for SF6 (23,900)

GWP - SF6 (per http://www.epa.gov/highgwp/magnesium-sf6/basic.html or Table A-1 of 40 CFR 98)

23,900

Description

Number of 

Breakers1
Indiana Department of Environmental Management

Office of Air Quality

Appendix B – BACT Analyses

Technical Support Document (TSD)

Prevention of Significant Deterioration (PSD)

Source Background and Description

Source Name: St. Joseph Energy Center, LLC

Source Location: Corner of Walnut and Edison Roads, 

New Carlisle, Indiana 46552

County: St. Joseph

SIC Code: 4911

Operation Permit No.: T 141-31003-00579

Operation Permit Issuance Date: Yet to be issued

Permit Reviewer: Josiah Balogun

Proposed Construction

St. Joseph Energy Center, LLC (SJEC) is proposing to install a new source in St. Joseph County.

The source is proposing the construction and operation of a nominal 1,350 megawatt (MW) combined 

cycle combustion turbine (CCCT) electric generating facility (CCCT Facility). The proposed CCCT Facility 

will consist of a nominal net 1,350 MW natural gas-fired CCCT operation that includes two natural gasfired 2 x1 CCCT blocks and ancillary equipment. A water treatment facility will be constructed on-site to 

supply SJEC operations. This facility will be operated by the town of New Carlisle, but is considered as 

part of the CCCT Facility.

St. Joseph Energy Center, LLC is required to undergo a review of control technology for 

pollutants above PSD threshold and significant levels under Federal and State Prevention of Significant 

Deterioration (PSD) Regulations.

St. Joseph Energy Center, LLC is located at the Corner of Walnut and Edison Roads, New 

Carlisle, Indiana, in St. Joseph County. SJEC submitted a PSD and Title V operating permit application 

to IDEM, OAQ on October 3, 2011, 

Requirement for Best Available Control Technology (BACT)

326 IAC 2-2 requires a best available control technology (BACT) review to be performed on the proposed 

New Source Review because the new construction has the potential to emit CO emissions greater than 

100 tons per year, which exceeds the PSD threshold and significant levels for this pollutant. The BACT 

review also addressed the following pollutants: PM, PM10, PM2.5, SO2, VOC, NOx, H2SO4 and Green 

House Gases that exceeded the PSD significant levels. 

See Appendix A – Emission Calculations – of this TSD for detailed Potential to Emit (PTE) calculations.
St. Joseph Energy Center, LLC Page 2 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Proposed New Emission Units

326 IAC 2-2 requires a best available control technology (BACT) review to be performed on the proposed 

emission units:

(a) Four (4) natural gas-fired combined cycle combustion turbines, identified as units 

CCCT1, CCCT2, CCCT3, and CCCT4, permitted in 2012, each with a combustion turbine 

equipped with dry low NOx burners, natural gas fired duct burners, and a heat recovery 

steam generator identified as HRSG1, HRSG2, HRSG3, and HRSG4, NOx emissions 

controlled by four (4) selective catalytic reduction (SCR) systems (SCR01, SCR02, 

SCR03 and SCR04), CO and VOC emissions controlled by oxidation catalyst systems

(CAT01, CAT02, CAT03 and CAT04) and exhausting to stacks CCCT01, CCCT02, 

CCCT03, and CCCT04, respectively. Each stack has continuous emissions monitors 

(CEMS) for NOx and CO. The nominal heat input for each CCCT is 2,300 MMBtu/hr 

(higher heating value (HHV)). The combined nominal power output is 1,350 megawatts 

(MW). 

*Note: The heat recovery steam generators are not a source of emissions. They have 

been included for clarity as they are a part of the entire source and operate in 

conjunction with the duct burners which are a source of emissions.

(b) Two (2) natural gas fired auxiliary boilers, identified as B001 and B002, permitted in 

2012, each, with a maximum heat input capacity of 80 MMBtu/hr (HHV), equipped with 

low NOx burners (LNB) with flue gas recirculation (FGR) to reduce NOx emissions, and 

exhausting to stacks B001 and B002. Under 40 CFR Part 60, Subpart Dc, the auxiliary 

boiler is considered a steam generating unit.

(c) One (1) emergency diesel generator, nominally rated at 2012 horsepower, identified as 

EG03, permitted in 2012, exhausting through one (1) vent, identified as EG03. [Under 40 

CFR 60, Subpart IIII, the emergency diesel fired generator is considered a new affected 

source.][Under 40 CFR 63, Subpart ZZZZ, the emergency diesel fired generator is 

considered a new affected source.]

(d) Two (2) firewater pump engines, each nominally rated at 371 brake horsepower (bph)

and identified as FP01 and FP02, permitted in 2012, exhausting through two (2) vents, 

identified as FP01 and FP02, respectively. [Under 40 CFR 60, Subpart IIII, the firewater 

pump engines are considered new affected sources.][Under 40 CFR 63, Subpart ZZZZ, 

the firewater pump engines are considered new affected sources.]

(e) Two (2) emergency diesel generators, each nominally rated at 1,006 horsepower, 

identified as EG01 and EG02, permitted in 2012, exhausting through two (2) vents, 

identified as EG01 and EG02, respectively. [Under 40 CFR 60, Subpart IIII, the 

emergency diesel fired generators are considered new affected sources.][Under 40 CFR 

63, Subpart ZZZZ, the emergency diesel fired generators are considered new affected 

source.]

(f) Two (2) cooling towers, each nominally rated with a circulation rate of 170,000 gpm , 

identified as CT01 and CT02, permitted in 2012, with high efficiency drift/mist eliminators, 

and exhausting through ten vents each, identified as CT01A – CT01J and CT02A –

CT02J.
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New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(g) Six (6) Turbine Lube Demister Vents, identified as DM01 - DM06, permitted in 2012, 

exhausting through vents DM01 – DM06.

(h) Six (6) Turbine Lube Oil storage tanks, identified as TK01 - TK06, permitted in 2012, 

each with a nominal capacity of 6,800 gallons.

(i) Two (2) Emergency Generator ULSD Tanks, identified as TK07 and TK08, permitted in 

2012, each with a nominal capacity of 550 gallons.

(j) Two (2) Fire Pump Engine ULSD Tanks, identified as TK09 and TK10, permitted in 2012, 

each with a nominal capacity of 70 gallons.

(k) One (1) Vehicle Gasoline dispensing Tank, identified as TK11, permitted in 2012, with a 

nominal capacity of 650 gallons, equipped with submerged fill and stage 1 vapor balance.

(l) One (1) Vehicle Diesel Tank, identified as TK12, permitted in 2012, with a nominal 

capacity of 650 gallons.

(m) One (1) Emergency Generator ULSD Tank, identified as TK50, permitted in 2012, with a 

nominal capacity of 300 gallons;

(n) Six (6) Electrical Circuit Breakers containing sulfur hexafluoride (SF6) identified as 

emissions unit SF6, permitted in 2012, with fugitive GHG emissions;

Summary of the Best Available Control Technology (BACT) Process

BACT is a mass emission limitation based on the maximum degree of pollution reduction of 

emissions, which is achievable on a case-by-case basis. BACT analysis takes into account the 

energy, environmental, and economic impacts on the source. These reductions may be determined 

through the application of available control techniques, process design, work practices, and 

operational limitations. There will still be air pollution from this project; however, St. Joseph Energy 

Center, LLC (SJEC) will be required to demonstrate that the emissions will be reduced to maximum 

extent.

Federal EPA generally requires an evaluation that follows a “top down” process. In this approach, the 

applicant identifies the best controlled similar source on the basis of controls required by regulation or 

permit, or controls achieved in practice. The highest level of control is then evaluated for technical 

feasibility. IDEM evaluates BACT based on a "top down" approach. 

The five (5) basic steps of a top-down BACT analysis used by the Office of Air Quality (OAQ) to make 

BACT determinations are listed below:

Step 1: Identify Potential Control Technologies

The first step is to identify potentially “available” control options for each emission unit and for 

each pollutant under review. Available options should consist of a comprehensive list of those 

technologies with a potentially practical application to the emissions unit in question. The list 

should include lowest achievable emission rate (LAER) technologies and controls applied to 

similar source categories. 

Step 2: Eliminate Technically Infeasible Options

The second step is to eliminate technically infeasible options from further consideration. To be 

considered feasible, a technology must be both available and applicable. It is important in this 

step that any presentation of a technical argument for eliminating a technology from further 

consideration be clearly documented based on physical, chemical, engineering, and source 

specific factors related to safe and successful use of the controls. Innovative control means a 

control that has not been demonstrated in a commercial application on similar units. Innovative 
St. Joseph Energy Center, LLC Page 4 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

controls are normally given a waiver from the BACT requirements due to the uncertainty of 

actual control efficiency. IDEM evaluates any innovative controls if proposed by the source. 

Only available and proven control technologies are evaluated. A control technology is 

considered available when there are sufficient data indicating that the technology results in a 

reduction in emissions of regulated pollutants.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The third step is to rank the technologies not eliminated in Step 2 in order of descending 

control effectiveness for each pollutant of concern. The ranked alternatives are reviewed in 

terms of control effectiveness (percent pollutant removed). If the highest ranked technology 

is proposed as BACT, it is not necessary to perform any further technical or economic 

evaluation, except, for the environmental analyses.

Step 4: Evaluate the Most Effective Controls and Document the Results

The fourth step begins with an evaluation of the remaining technologies under 

consideration for each pollutant of concern in regards to energy, environmental, and 

economic impacts for determining a final control technology. The highest ranked alternative 

is evaluated for environmental, energy and economic impacts specific to the proposed 

modification. If the analysis determines that the highest ranked control is not appropriate 

as BACT, due to any of the energy, environmental, and economic impacts, then the next 

most effective control is evaluated. The evaluation continues until a technology under 

consideration cannot be eliminated based on adverse energy, environmental, or economic 

impacts. If the highest ranked technology is proposed as BACT, it is not necessary to 

perform any further technical, economic or environmental analysis for a greenhouse gas 

BACT. An Air Quality Impact Analysis would be required for a non-greenhouse gas BACT.

Step 5: Select BACT

The most effective option not eliminated in step 4 is BACT.

Particulate Matter (PM/PM10/PM2.5) BACT – Combined Cycle Combustion Turbines CCCT1 - CCCT4

Step 1: Identify Potential Control Technologies

Emissions of PM, PM10 and PM2.5 are generally controlled with add-on control equipment 

designed to capture the emissions prior to the time they are exhausted to the atmosphere. In 

cases where the material being emitted is organic, particulate matter may be controlled through a 

combustion process. Generally, PM, PM10 and PM2.5 emissions are controlled through one of the 

following mechanisms:

(1) Fabric Filter Dust Collectors (Baghouses).

(2) Electrostatic Precipitators (ESP); and

(3) Wet Scrubbers;

(4) Cyclones or Multiclones;

(5) Fuel Specification; and

(6) Good Combustion Practices.

The choice of which technology is most appropriate for a specific application depends upon 

several factors, including particle size to be collected, particle loading, stack gas flow rate, stack 

gas physical characteristics (e.g., temperature, moisture content, presence of reactive materials), 

and desired collection efficiency.
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New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Step 2: Eliminate Technically Infeasible Options

Fabric Filtration:

A fabric filter unit consists of one or more isolated compartments containing rows of fabric bags in 

the form of round, flat, or shaped tubes, or pleated cartridges. Particle laden gas passes up 

(usually) along the surface of the bags then radially through the fabric. Particles are retained on 

the upstream face of the bags, and the cleaned gas stream is vented to the atmosphere. The 

filter is operated cyclically, alternating between relatively long periods of filtering and short periods 

of cleaning. During cleaning, dust that has accumulated on the bags is removed from the fabric 

surface and deposited in a hopper for subsequent disposal.

Fabric filters collect particles with sizes ranging from submicron to several hundred microns in 

diameter at efficiencies generally in excess of 99 or 99.9%. The layer of dust, or dust cake, 

collected on the fabric is primarily responsible for such high efficiency. The cake is a barrier with 

tortuous pores that trap particles as they travel through the cake. 

Gas temperatures up to about 500°F, with surges to about 550°F, can be accommodated 

routinely in some configurations. Most of the energy used to operate the system appears as 

pressure drop across the bags and associated hardware and ducting. Typical values of system 

pressure drop range from about 5 to 20 inches of water.

Fabric filters are used where high efficiency particle collection is required. Limitations are 

imposed by gas characteristics (temperature and corrosivity) and particle characteristics 

(primarily stickiness) that affect the fabric or its operation and that cannot be economically 

accommodated. Important process variables include particle characteristics, gas characteristics, 

and fabric properties. The most important design parameter is the air- or gas-to-cloth ratio (the 

amount of gas in ft3

/min that penetrates one ft2 of fabric) and the usual operating parameter of 

interest is pressure drop across the filter system. The major operating feature of fabric filters that 

distinguishes them from other gas filters is the ability to renew the filtering surface periodically by 

cleaning. Common furnace filters, high efficiency particulate air (HEPA) filters, high efficiency air 

filters (HEAFs), and automotive induction air filters are examples of filters that must be discarded 

after a significant layer of dust accumulates on the surface. These filters are typically made of 

matted fibers, mounted in supporting frames, and used where dust concentrations are relatively 

low. Fabric filters are usually made of woven or (more commonly) needle-punched felts sewn to 

the desired shape, mounted in a plenum with special hardware, and used across a wide range of 

dust concentrations.

The fabric filters are susceptible to corrosion and binding by moisture. Appropriate fabrics must 

be selected for specific process conditions. Accumulations of dust may present fire or explosion 

hazard. The typical waste stream inlet flow is 100-100,000 scfm (Standard) or 100,000-1,000,00 

scfm (Custom). The natural gas fired CCCTs generate low particulate matter emissions and have 

large exhaust flow rates, resulting in very low concentration of particulates.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Baghouse is not a technically feasible option for the combined cycle combustion 

turbines (CCCT1-CCCT4) at this source.

Electrostatic Precipitators:

An electrostatic precipitator (ESP) is a particle control device that uses electrical forces to move 

the particles out of the flowing gas stream and onto collector plates. The particles are given an 

electrical charge by forcing them to pass through a corona, a region in which gaseous ions flow. 

The electrical field that forces the charged particles to the walls comes from electrodes 

maintained at high voltage in the center of the flow lane.
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New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Once the particles are collected on the plates, they must be removed from the plates without 

re-entraining them into the gas stream. This is usually accomplished by knocking them loose 

from the plates, allowing the collected layer of particles to slide down into a hopper from which 

they are evacuated. Some precipitators remove the particles by intermittent or continuous 

washing with water. ESP control efficiencies can range from 95% to 99.9%.

Gas temperatures may be up to about 1,300 °F (dry) and Lower than 170 - 190 °F (wet). The 

typical waste stream inlet flow is 1,000 - 100,000 scfm (Wire-Pipe) and 100,000 - 1,000,000 scfm 

(Wire-Plate). Dry ESP efficiency varies significantly with dust resistivity. Air leakage and acid 

condensation may cause corrosion. ESPs are not generally suitable for highly variable 

processes. Equipment footprint is often substantial. Natural-gas fired CCCTs generate low 

Particulate emissions and have large exhaust flowrates, resulting in very low concentrations of 

Particulates. Add-on control devices would not provide any measurable emission reduction.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of an electrostatic precipitator is not a technically feasible option for the combined cycle 

combustion turbines (CCCT1-CCCT4) at this source.

Wet scrubbers:

A wet scrubber is an air pollution control device that removes PM from waste gas streams 

primarily through the impaction, diffusion, interception and/or absorption of the pollutant onto 

droplets of liquid. The liquid containing the pollutant is then collected for disposal. There are 

numerous types of wet scrubbers that remove PM. Collection efficiencies for wet scrubbers vary 

with the particle size distribution of the waste gas stream. In general, collection efficiency 

decreases as the PM size decreases. Collection efficiencies also vary with scrubber type. 

Collection efficiencies range from greater than 99% for venturi scrubbers to 40-60% (or lower) for 

simple spray towers. Wet scrubbers are smaller and more compact than baghouses or ESPs. 

They have lower capital costs and comparable operation and maintenance (O&M) costs. Wet 

scrubbers are particularly useful in the removal of PM with the following characteristics:

(1) Sticky and/or hygroscopic materials (materials that readily absorb water);

(2) Combustible, corrosive and explosive materials;

(3) Particles which are difficult to remove in their dry form;

(4) PM in the presence of soluble gases; and

(5) PM in waste gas streams with high moisture content.

The primary disadvantage of wet scrubbers is that increased collection efficiency comes at the 

cost of increased pressure drop across the control system. Another disadvantage is that they are 

limited to lower waste gas flow rates and temperatures than ESPs or baghouses. Current wet 

scrubber designs accommodate air flow rates over 100,000 actual cubic feet per minute and 

temperatures of up to 750°F. Another disadvantage is that they generate waste in the form of a 

sludge which requires treatment and/or disposal. Lastly, downstream corrosion or plume visibility 

problems can result unless the added moisture is removed from the gas stream.

Gas temperatures are between 40 to 750 °F. The typical waste stream inlet flow is 500 - 100,000 

scfm (units in parallel can operate at greater flow rates). Effluent wastewater stream may require 

treatment. Sludge disposal may be costly. Wet scrubbers are particularly susceptible to 

corrosion. Natural-gas fired CCCTs generate low Particulate emissions and have large exhaust 

flowrates, resulting in very low concentrations of Particulates. Add-on control devices would not 

provide any measurable emission reduction.
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Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a wet scrubber is not a technically feasible option for the combined cycle combustion 

turbines (CCCT1-CCCT4) at this source.

Cyclones:

Cyclones are simple mechanical devices commonly used to remove relatively large particles from 

gas streams. In industrial applications, cyclones are often used as precleaners for the more 

sophisticated air pollution control equipment such as ESPs or baghouses. Cyclones are less 

efficient than wet scrubbers, baghouses, or ESPs. 

Cyclones used as pre-cleaners are often designed to remove more than 80% of the particles that 

are greater than 20 microns in diameter. Smaller particles that escape the cyclone can then be 

collected by more efficient control equipment. This control technology may be more commonly 

used in industrial sites that generate a considerable amount of particulate matter, such as lumber 

companies, feed mills, cement plants, and smelters.

The gas temperature is about 1,000°F. The typical waste stream inlet flow is between 1.1 -

63,500 scfm (single) and Up to 106,000 scfm (in parallel). Cyclones typically exhibit lower 

efficiencies when collecting smaller particles. High-efficiency units may require substantial 

pressure drop. Natural-gas fired CCCTs generate low Particulate emissions and have large 

exhaust flow rates, resulting in very low concentrations of Particulates. Add-on control devices 

would not provide any measurable emission reduction.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a cyclone is not a technically feasible option for the combined cycle combustion 

turbines (CCCT1-CCCT4) at this source.

Fuel Specifications 

Combusting only clean natural gas, which has an inherently low sulfur content, rather than higher 

sulfur content fuels alone or in combination with natural gas has a very low potential for 

generating PM, PM10 and PM2.5 emissions. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Fuel Specifications is a technically feasible option for the combined cycle combustion 

turbines (CCCT1-CCCT4) at this source.

Good Combustion Practices 

Good combustion practices as well as operation and maintenance of the combined cycle 

combustion turbines to keep them in good working order per the manufacturer's specifications will 

minimize PM, PM10 and PM2.5 emissions. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Good Combustion Practices is a technically feasible option for the combined cycle 

combustion turbines (CCCT1-CCCT4) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of PM, PM10 and PM2.5 resulting from the 

operation of the combined cycle combustion turbines (CCCT1-CCCT4). 

(1) Fuel Specifications 

(2) Good Combustion Practices 
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Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for similar plants. All data in the table is 

based on the information obtained from the permit application submitted by St. Joseph Energy 

Center, LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of 

permits available at the websites of other permitting agencies. All limitations in parenthesis were 

not obtained from the RBLC but were calculated to provide a consistent basis for comparing 

emissions rates to the proposed project.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 141-

31003-00579

Proposed

Limit

St. Joseph 

Energy Center

- proposed

Proposed Combined Cycle 

Combustion 

Turbines (CCCT1 -

CCCT4)

2,300 

MMBtu/hr

PM/PM10/PM2.5: 

18 pounds per 

hour and 0.0078 

lbs/MMBtu, with 

duct firing based 

on 3-hr average

Good 

Combustion 

Practice and 

Fuel 

Specification

15 pounds per 

hour and 0.0092

lbs/MMBtu 

without duct 

firing based on 

3-hr average

NC-9001 Richmond 

County 

Combustion 

Turbine Facility

04/02/2009 Combustion 

Turbines

2,225 CT

390 DB

0.0059 lb/MMBtu 

with duct firing, 

based on 3,1-hr 

average

0.0071 lb/MMBtu 

without duct firing, 

based on 3,1-hr 

average

Fuel 

Specification

NY-0095 Caithness 

Bellport Energy 

Center

5/10/2006 2,221 CT

494 DB

0.0055 

lb/MMBtu 

without DB

Fuel 

Specification

0.0066 

lb/MMBtu with 

DB

NJ-0043 Liberty 

Generating 

Station (State 

requirement, 

not PSD)

03/28/2002 *Combustion 

Turbines

2,964 CT PM: 0.005 

lb/MMBtu

Unknown

TX-0546 Pattillo Branch 

Power Company, 

LLC - Electric 

Generating 

Station

06/17/2009 Combustion 

Turbines

350 MW 

per CCCT

444 DB

PM/PM10: 0.012 

lb/MMBtu based 

on 3-hr average

Fuel 

Specification

GA-0105 Mcintosh 

Combined 

Cycle Facility

04/17/2003 Combustion 

Turbines

140 MW 

542 DB

PM: 0.03 

lb/MMBtu

Fuel 

Specification

CA-9002 PG&E - Colusa 

Generating 

Station

09/29/2008 Combustion 

Turbines

172 MW 

per turbine

PM: 20 lb/hour

(0.008 lb/MMBtu)

Fuel 

Specification

LA-0224 SWEPCO -

Arsenal Hill 

Power Plant

3/20/2008 Combustion 

Turbines

180 MW,

each

PM/PM10: 24.23 

lb/hr

(0.010 lb/MMBtu)

Good 

design/proper 

operation
St. Joseph Energy Center, LLC Page 9 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

TX-0590 Pondera 

Capital 

Management 

GP Inc., King 

Power Station

8/5/2010 *Combustion 

Turbines (SGT6-

5000F)

1350 MW *PM: 11.10 lb/hr Low Sulfur 

fuel

*Combustion 

Turbines (GE7FA

1350 MW *PM: 19.80 lb/hr

TX-0600 Lower 

Colorado River 

Authority 

Thomas C. 

Ferguson 

Power Plant

9/1/2011 *Combustion 

Turbines

195 MW, 

each

PM/PM10/PM2.5: 

33.43 lb/hr based 

on 1-hr average

Low Sulfur 

fuel

VA-0308 Virginia Electric 

and Power -

Warren County 

Facility

12/21/2010 Combustion 

Turbines

300 MW PM10/PM2.5: 

0.004 lb/MMBtu 

with duct burners

based on 3-hr 

average

0.0027 without 

duct burner, 

based on 3-hr 

average

Good 

Combustion 

Practices

AZ-9001 Bowie Power 

Station, LLC

Unknown Combustion 

Turbines

172 MW 

per turbine

PM10: 22 lb/hr

(0.010 lb/MMBtu)

Good 

Combustion 

Practices and 

Fuel 

Specifications

WA-0315 Sumas Energy 

2 Generation 

Facility

05/27/2003 *Combustion 

Turbines

334 MW 

per turbine

PM10: 573 

lb/day/HRSG 

stack, based on 

24-hr average

Good 

Combustion 

Practices and 

Fuel 

Specifications

CA-1097 Southern 

California 

Public Power 

Authority -

Magnolia 

Power Plant

5/27/2003 Combustion 

Turbines

181 MW PM10: 18 lb/day 

with DB

(0.0079 lb/MMBtu)

Unknown

PM10: 12 lb/day 

without DB

(0.0071 lb/MMBtu)

OK-0129 Associated 

Electric 

Cooperative, 

Inc. –

Chouteau 

Power Plant

1/20/2009 Combustion

Turbines

178 MW 

per turbine

PM10: 0.0035 

lb/MMBtu, based 

on 24-hr average

Good 

Combustion 

Practices

CA-9001 Calpine –

Russell City 

Energy Center

2/3/2010 *Combustion 

Turbines

2038.6 CT

200 DB

PM10: 0.0036 

lb/MMBtu

Good 

Combustion 

Practices and 

Fuel 

Specification

Note: * Not yet constructed
St. Joseph Energy Center, LLC Page 10 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

The Calpine – Russell City Energy Center, Pondera Capital Management GP Inc. – King Power 

Station, and Lower Colorado River Authority – Thomas C. Ferguson Power Plant, have not yet 

been constructed. Therefore, these BACT limits have not been demonstrated.

The Sumas Energy 2 Generation Facility and Liberty Generating Station were never constructed 

and are not evaluated against the proposed project.

The limits for the Richmond County Combustion Turbine Facility do not have an associated 

testing requirement in the issued PSD permit. Therefore, these BACT limits have not been 

demonstrated.

The Southern California Public Power Authority – Magnolia Power Plant was permitted in a 

nonattainment area for PM10 and was issued state BACT limits established to meet LAER. 

Therefore, these limits are not evaluated against the proposed project.

The combustion turbines at the Caithness Bellport Energy Center are permitted to operate only at 

steady state loads of 75% or greater. To ensure optimal flexibility in responding to market 

demand for power, St. Joseph Energy has developed emission limits and conducted air 

dispersion modeling based on steady state operating loads as low as 47%. In addition, the 

Caithness Bellport Energy Center SO2 limits indicate access to natural gas with a sulfur content 

of 0.35 gr/100 scf, while St. Joseph Energy cannot assure access to natural gas with a sulfur 

content less than 0.75 gr/100 scf. Therefore, the limits for the Caithness Bellport Energy Center 

are not evaluated against this project. 

The permit issued for the PG&E – Colusa Generating Station includes annual, daily, and hourly 

limits on PM10 emissions, but does not limit PM10 emissions on a lb/MMBtu basis. Based on 

emissions data presented in the permit application for the PG&E – Colusa Generating Station, 

PM10 emissions range from 0.008 lb/MMBtu at maximum load, to 0.011 lb/MMBtu at 50% load 

levels. 

The Associated Electric Cooperative, Inc. – Chouteau Power Plant value is an outlier and is 

specific to the design of this facility. All other demonstrated limits for F-class turbines are not less 

than 0.0055 lb/MMBtu.

The limits in the Virginia Electric and Power - Warren County Facility are for G-class turbines, not 

F-class turbines like those for the proposed project. 

The project site is based upon the development and construction, in stages, of two power blocks 

each rated at 600MW nominal output and capable of responding quickly to frequent changes in 

power demand for the local grid. The 600MW nominal power blocks were selected because they 

fit both the physical parameters of the available interconnection with the local grids and the 

assessment of the near term market demand.

The configuration of a 600MW nominal gas turbine combined cycle power block is a natural fit 

with “F” class combustion turbines. The desired capacity of 600MW’s can be provided at 

Summer ambient condition by combining two(2) “F” class combustion turbines (rated at just over 

200MW at high ambient temperatures) combined with a single 200+ MW steam turbine and heat 

recovery steam generator with a modest amount of supplementary duct burner firing. This type of 

configuration represents the overwhelmingly most popular type planned and constructed in the 

North American market.

The “G” class combustion turbines differ from “F” in two important ways: a) the combustors fire at 

substantially higher temperatures, which fundamentally is the reason “G” machines have a 

somewhat higher thermal efficiency and b) the commercially available equipment is rated at 

250MW nominal each unit. The larger 250MW unit rating does not fit the 600MW power block 

capacity. A “2on1” configuration would be too large at 750MW and a “1on1” too small at 400MW. 
St. Joseph Energy Center, LLC Page 11 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Also, the higher thermal efficiency “G” machines are primarily designed to operate more 

frequently at a steady base loaded condition and not be cycled up and down in MW load or on 

and off frequently. The “F” class machines are more thermally flexible and the power blocks more 

responsive to varying market demand and unit load cycling operation. 

Based on the available interconnection with the local grid, the maximum load requirements 

established by near term market demand, and the need to respond quickly to frequent changes in 

power demand, use of "G" class combustion turbines are not suitable for this project and SJEC 

will utilize commercially proven F-class turbines.

St. Joseph Energy is proposing PM/PM10/PM2.5 emissions limits at 15 lb/hr and 0.0092 lb/MMBtu 

without duct burning and 18 lb/hr and 0.0078 MMBtu with duct burning based on vendor data. 

For a typical combustion turbine, the PM/PM10/PM2.5 emission rate in lb/MMBtu increases as 

turbine load decreases. Therefore, the proposed lb/hr emission rates are based on maximum 

load while the proposed lb/MMBtu emission rates are based on the minimum design load for that 

operating scenario. PM/PM10/PM2.5 emissions for CCCT include contributions from the 

combustion turbine, duct burner, and oxidation of sulfur in the fuel to sulfate particulate matter. 

Therefore, PM/PM10/PM2.5 potential to emit for the similar sized turbine can vary based on duct 

burner size, sulfur content guarantees for the available fuel, and the assumed sulfur to sulfate 

conversion rate. Therefore, the proposed emission rates are consistent with the recent BACT 

determinations in EPA’s RACT/BACT/LAER clearinghouse such as the PG&E – Colusa 

Generating Station, given variations between duct burner sizes, natural gas sulfur content, and 

assumed fuel sulfur to sulfate conversion rates between these projects.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for PM, PM10 and PM2.5 emissions from the proposed 

combined cycle combustion turbines, identified as CCCT1 -CCCT4:

1. The PM, PM10 and PM2.5 emissions from the combined cycle combustion turbines

identified as CCCT1 -CCCT4 shall not exceed 18 lb/hour and 0.0078 lb/MMBtu with duct 

firing based on 3-hr average through the use of good combustion practices and fuel 

specification. 

2. The PM, PM10 and PM2.5 emissions from the combined cycle combustion turbines

identified as CCCT1 -CCCT4 shall not exceed 15 pounds per hour and 0.0092 lb/MMBtu

without duct firing based on 3-hr average through the use of good combustion practices and 

fuel specification. 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for the combined cycle combustion turbines

(CCCT1-CCCT4).

1. The PM, PM10 and PM2.5 emissions from the combined cycle combustion turbines

identified as CCCT1 -CCCT4 shall not exceed 18 lb/hour and 0.0078 lbs per MMBtu with 

duct firing based on 3-hr average through the use of good combustion practices and fuel 

specification. 

2. The PM, PM10 and PM2.5 emissions from the combined cycle combustion turbines

identified as CCCT1 -CCCT4 shall not exceed 15 pounds per hour and 0.0092 lbs per 

MMBtu without duct firing based on 3-hr average through the use of good combustion 

practices and fuel specification. 
St. Joseph Energy Center, LLC Page 12 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Sulfuric Acid (H2SO4) BACT – Combined Cycle Combustion Turbines CCCT1 - CCCT4

Step 1: Identify Potential Control Technologies

Emissions of Sulfuric Acid (H2SO4) emissions depend upon the sulfur content of the fuel and 

oxidation of SO2 to SO3, followed by immediate conversion of SO3 to H2SO4 when water vapor is 

present. Sulfuric Acid (H2SO4) emissions are generally controlled with add-on control equipment 

designed to capture the emissions prior to the time they are exhausted to the atmosphere. 

(1) Flue Gas Desulfurization (FGD) System);

(2) Dry Sorbent Injection; and

(3) Fuel Specification.

The choice of which technology is most appropriate for a specific application depends upon 

several factors, including particle size to be collected, particle loading, stack gas flow rate, stack 

gas physical characteristics (e.g., temperature, moisture content, presence of reactive materials), 

and desired collection efficiency. H2SO4 emissions are not dependent upon combustion turbine 

properties such as size or burner design.

Step 2: Eliminate Technically Infeasible Options

Flue Gas Desulfurization (FGD) System 

A flue gas desulfurization system (FGD) is comprised of a spray dryer that uses lime as a reagent 

followed by particulate control or wet scrubber that uses limestone as a reagent. FGD is an 

established technology. FGD typically operates at a temperature of approximately 300°F to 

700°F (wet) and 300°F to 1830°F (dry). The FGD has a waste stream inlet pollutant concentration 

of 2,000ppmv. Absorption of SO2 is accomplished by the contact between the exhaust and an 

alkaline reagent, which results in the formation of neutral salts. Wet systems employ reagents 

using packed or spray towers and generate wastewater streams, while dry systems inject slurry 

reagent into the exhaust stream to react, dry and be removed downstream by particulate control 

equipment. By removing SO2 from the exhaust stream, conversion of SO2 to SO3 and H2SO4 is 

reduced. Chlorine emissions can result in salt deposition within the absorber and in downstream 

equipment. Wet systems may require flue gas re-heating downstream of the absorber to prevent 

corrosive condensation. Inlet streams for dry systems must be cooled as appropriate, and dry 

systems require use of particulate controls to collect the solid netural salts.

FGD systems are not listed in the RBLC as BACT for the control of H2SO4 emissions for large 

combined cycle combustion turbines. Technology has not been applied to natural gas combined 

cycle combustion turbines due to very low SO2 and H2SO4 emissions. Controls would not 

provide any measurable emission reduction.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of flue gas desulfurization system (FGD) is not a technically feasible option for the 

combined cycle combustion turbines (CCCT1-CCCT4) at this source.

Dry Sorbent Injection

A post-combustion technology in which a calcium or sodium-based sorbent reacts with SO2 and 

SO3 and is removed downstream by particulate control equipment. The reduced availability of 

SO2 and SO3 in the exhaust stream reduces H2SO4 formation, thereby reducing H2SO4

emissions. The system requires use of particulate controls to collect the reaction solids.

Dry sorbent injection is not listed in the RBLC as BACT for the control of H2SO4 emissions for 

large combined cycle combustion turbines. Technology has not been applied to natural gas 
St. Joseph Energy Center, LLC Page 13 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

combined cycle combustion turbines due to very low SO2 and H2SO4 emissions. Controls would 

not provide any measurable emission reduction.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of dry sorbent injection is not a technically feasible option for the combined cycle 

combustion turbines (CCCT1-CCCT4) at this source.

Fuel Specifications 

Combusting only clean natural gas, which has an inherently low sulfur content, rather than higher 

sulfur content fuels alone or in combination with natural gas has a very low potential for 

generating H2SO4 emissions. Fuel Specifications is included in RBLC for the control of H2SO4

from combined cycle combustion turbines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Fuel Specifications is a technically feasible option for the combined cycle combustion 

turbines (CCCT1-CCCT4) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of H2SO4 resulting from the operation of 

the combined cycle combustion turbines (CCCT1-CCCT4). 

(1) Fuel Specifications 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed H2SO4 BACT determination along with the existing H2SO4

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued 

Date

Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 141-

31003-00579

Proposed

Limit

St. Joseph 

Energy Center -

proposed

Proposed Combined 

Cycle 

Combustion 

Turbines

(CCCT1 -

CCCT4)

2,300 

MMBtu/hr

H2SO4: 0.75 

gr S/100 scf 

fuel sulfur

Fuel 

Specification

FL-0304 FMPA - Cane 

Island Power 

Park

9/8/2008 Combustion 

Turbines 

1,860 CT 

600 DB

2 gr S/100 scf 

gas

Fuel 

Specification

FL-0263 FP&L - Turkey 

Point Fossil Plant

2/8/2005 Combustion 

Turbines 

1,608 CT 

495 DB

2 gr S/100 scf 

gas

Fuel 

Specification

TX-0546 Pattillo Branch 

Power Company, 

LLC - Electric 

Generating Plant

6/17/2009 Combustion 

Turbines 

444 DB 2 gr S/100 scf 

gas

Fuel 

Specification

FL-9002 FP&L Company -

Cape Canaveral 

Energy Center

7/23/2009 Combustion 

Turbines 

2,586 CT 

460 DB

2 gf S/100 scf 

gas

Fuel 

Specification
St. Joseph Energy Center, LLC Page 14 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

The proposed natural gas sulfur content limit of 0.75 gr S/100 scf is the most stringent limit for 

H2SO4 emissions. Note that H2SO4 emissions depend on the sulfur content of the natural gas 

available to the facility. The proposed facility will have access to natural gas from a single 

supplier for the region, and will not have the option to receive natural gas from any other source 

or require the supplier to provide lower sulfur content fuel. Since natural gas sulfur content is 

dependent on the supply available to that region, comparison of fuel sulfur content for natural gas 

from different regions, which the proposed site will not have access to, is not appropriate.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for H2SO4 emissions from the proposed combined 

cycle combustion turbines, identified as CCCT1 -CCCT4:

The H2SO4 emissions from the combined cycle combustion turbines identified as CCCT1 -

CCCT4 shall not exceed 0.75 gr S/100 scf fuel sulfur through the use of fuel specification. 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for H2SO4 for the combined cycle combustion turbines (CCCT1-CCCT4).

The H2SO4 emissions from the combined cycle combustion turbines identified as CCCT1 -

CCCT4 shall be limited by a fuel sulfur limit of 0.75 gr S/100 scf fuel. 

Carbon Monoxide (CO) BACT – Combined Cycle Combustion Turbines CCCT1 - CCCT4

Step 1: Identify Potential Control Technologies

Emissions of carbon monoxide (CO) are generally controlled by oxidation. Oxidation technologies 

include regenerative thermal oxidation, catalytic oxidation, and flares.

(a) Regenerative thermal oxidation; 

(b) Recuperative thermal oxidizer

(c) SCONOx Catalytic Absorption System; 

(d) Catalytic oxidation; 

(e) Good Combustion Controls; and

(f) Flares.

If add-on control technology is not feasible, an alternate method of control may be implemented. 

Step 2: Eliminate Technically Infeasible Options

Regenerative Thermal Oxidizers

The thermal oxidizer has a high temperature combustion chamber that is maintained by a 

combination of auxiliary fuel, waste gas compounds, and supplemental air added when 

necessary. This technology is typically applied for destruction of organic vapors, nevertheless it is 

also considered as a technology for controlling CO emissions. Upon passing through the flame, 

the waste gas containing CO is heated. The mixture continues to react as it flows through the 

combustion chamber.
St. Joseph Energy Center, LLC Page 15 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

The required level of CO destruction of the waste gas that must be achieved within the time that it 

spends in the thermal combustion chamber dictates the reactor temperature. The shorter the 

residence time, the higher the reactor temperature must be. Most thermal units are designed to 

provide no more than 1 second of residence time to the waste gas with typical temperatures of 

1,200 to 2,000o

F. Once the unit is designed and built, the residence time is not easily changed, 

so that the required reaction temperature becomes a function of the particular gaseous species 

and the desired level of control. 

A Regenerative Thermal Oxidizer incorporates heat recovery and greater thermal efficiency 

through the use of direct contact heat exchangers constructed of a ceramic material that can 

tolerate the high temperatures needed to achieve ignition of the waste stream.

The inlet gas first passes through a hot ceramic bed thereby heating the stream (and cooling the 

bed) to its ignition temperature. The hot gases then react (releasing energy) in the combustion 

chamber and while passing through another ceramic bed, thereby heating it. The process flows 

are then switched, feeding the inlet stream to the hot bed. This cyclic process affords very high 

energy recovery (up to 95%). The higher capital costs associated with these high-performance 

heat exchangers and combustion chambers may be offset by the increased auxiliary fuel savings 

to make such a system economical. 

Thermal oxidizers do not reduce emissions of CO from properly operated natural gas combustion 

units without the use of a catalyst.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a regenerative thermal oxidizer is not a technically feasible option for the combined 

cycle combustion turbines at this source.

Recuperative Thermal Oxidizers

This control technology oxidizes combustible materials by raising the temperature of the material 

above the auto-ignition point in the presence of oxygen and maintaining the high temperature for 

sufficient time to complete combustion. The operating temperature ranges from 1,100 - 1,200o

F

and the waste stream inlet pollutants concentration is as low as 500-50,000 scfm. 

Additional fuel is required to reach the ignition temperature of the waste gas stream. Oxidizers 

are not recommended for controlling gases with sulfur containing compounds because of the 

formation of highly corrosive acid gases. Thermal oxidizers do not reduce emissions of CO from 

properly operated natural gas combustion units without the use of a catalyst.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a recuperative thermal oxidizer is not a technically feasible option for the combined 

cycle combustion turbines at this source.

SCONOx Catalytic Absorption System

This control technology utilizes a single catalyst to remove NOX, CO, and VOC through oxidation. 

Now operating as EmeraChem, the current version of the technology is now marketed as EMX. 

The operating temperature ranges from 300 - 700o

F. The SCONOX Catalyst is sensitive to 

contamination by sulfur, so it must be used in conjunction with the SCOSOX catalyst, which 

favors sulfur compound absorption. Not included in RBLC for control of CO emissions from large 

combined cycle combustion turbines. Technology has only been demonstrated on units ranging 

from 5 to 45 MW.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a SCONOx Catalytic Absorption System is not a technically feasible option for 

combined cycle combustion turbines at this source.
St. Joseph Energy Center, LLC Page 16 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Catalytic Oxidizers

Catalytic oxidation is also a widely used control technology to control pollutants where the waste 

gas is passed through a flame area and then through a catalyst bed for complete combustion of 

the waste in the gas. This technology is typically applied for destruction of organic vapors, 

nevertheless it is considered as a technology for controlling CO emissions. A catalyst is an 

element or compound that speeds up a reaction at lower temperatures compared to thermal 

oxidation without undergoing change itself. Catalytic oxidizers operate at 600°F to 800°F and 

approximately require 1.5 to 2.0 ft3 of catalyst per 1000 standard ft3 per gas flow rate. 

Similar to thermal incineration; waste stream is heated by a flame and then passes through a 

catalyst bed that increases the oxidation rate more quickly and at lower temperatures. Typical 

waste stream inlet flow rate ranges from 700 - 50,000 scfm and waste stream inlet pollutant 

concentration is as low as 1ppmv.

Oxidation efficiency depends on exhaust flow rate and composition. Residence time required for 

oxidation to take place at the active sites of the catalyst may not be achieved if exhaust flow rates 

exceed design specifications. Also, sulfur and other compounds may foul the catalyst, leading to

decreased efficiency. This control is widely accepted as BACT for control of CO emissions from 

combined cycle combustion turbines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a catalytic oxidizer is a technically feasible option for combined cycle combustion 

turbines at this source.

Flare

Although the CO concentration is very low, the stream flow rate is very high. The low heating 

value of the stream is too low for flaring. As there are insufficient organics in this vent stream to 

support combustion, use of a flare would require a significant addition of supplementary fuel. 

Therefore, a secondary impact of the use of flare for this stream would be the creation of 

additional emissions from burning supplemental fuel, including NOx. Flares have not been 

utilized or demonstrated as a control device for CO from this type of high-volume process stream. 

In addition, the flare would have no additional control versus the thermal oxidizers. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flare is not a technically feasible option for the combined cycle combustion turbines

at this source

Good Combustion Controls

Good combustion controls is a continued operation of the CCCT at the appropriate oxygen range 

and temperature to promote complete combustion and minimize CO formation. Because CO is 

essentially a by-product of incomplete or inefficient combustion, combustion control constitutes 

the primary mode of reduction of CO emissions. This type of control is appropriate for any type of 

fuel combustion source. Combustion process controls involve combustion chamber designs and 

operating practices that improve the oxidation process and minimize incomplete combustion. CO 

emissions result from the incomplete combustion of carbon and organic compounds. Factors 

affecting CO emissions include firing temperatures, residence time in the combustion zone and 

combustion chamber mixing characteristics.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Good Combustion Controls is a technically feasible option for the combined cycle 

combustion turbines at this source
St. Joseph Energy Center, LLC Page 17 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Oxidation Catalyst - 70-90% destruction efficiency

(2) Combustion Control

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed CO BACT determination along with the existing CO BACT 

determinations for similar plants. All data in the table is based on the information obtained from 

the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy 

Center -

proposed

Proposed Combined Cycle 

Combustion 

Turbines (CCCT1 -

CCCT4)

2,300 

MMBtu/hr

CO: 2.0 ppmvd 

@15% O2, with 

duct burners 

based on 3-hr 

average

Oxidation 

Catalyst

VA-0308 Virginia 

Electric and 

Power -

Warren 

County Facility

12/21/2010 Combustion 

Turbines

2996 CT 

500 DB

1.5 ppmvd 

@15% O2, 

without duct 

burner, based 

on 1-hr average

Oxidation 

Catalyst

2.4 ppmvd 

@15% O2, with 

duct burner, 

based on 1-hr 

average

CT-0151 Kleen Energy 

Systems, LLC

2/25/2008 Combustion 

Turbines

2136 CT 

445 DB

0.9 ppmvd 

@15% O2, 

without duct 

burner, based 

on 1-hr average

Oxidation 

Catalyst

1.7 ppmvd 

@15% O2, with 

duct burner, 

based on 1-hr 

average

GA-0127 Georgia 

Power -

McDonough

1/7/2008 Combustion 

Turbines

Unknown 1.8 ppmvd 

@15% O2, 

based on 3-hr 

average

Oxidation 

Catalyst

GA-9001 Live Oaks 

Power Plant

4/8/2010 Combustion 

Turbines

1990 CT

359 DB

2.0 ppmvd 

@15% O2, 

without duct 

burners based 

on 3-hr average

3.2 ppmvd @15% 

O2, with duct 

burners based on 

a 3-hr average

Oxidation 

Catalyst

CA-9001 Calpine - 2/3/2010 Combustion 2038.6 CT 2.0 ppmvd Oxidation 
St. Joseph Energy Center, LLC Page 18 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

Russell City 

Energy Center

Turbines 200DB @15% O2, 

based on 1-hr 

average

Catalyst

TX-0600 Lower 

Colorado 

River Authority 

Thomas C. 

Ferguson 

Power Plant

9/1/2011 Combustion 

Turbines

Unknown 4.0 ppmvd 

@15% O2, 

based on 3-hr 

rolling at load > 

60%,

6.0 ppmvd @15% 

O2, based on 3-hr 

rolling at load < 

60%

Oxidation 

Catalyst

VA-0308 Virginia 

Electric and 

Power -

Warren 

County Facility

1/14/2008 Combustion 

Turbines

1717 CT 

500 DB

2.5 ppmvd 

@15% O2, with 

power 

augmentation

and DB firing, 

based on 3-hr 

average

Oxidation 

Catalyst

AZ-0047 Dome Valley 

Energy 

Partners -

Wellton 

Mohawk 

Generating 

Facility

12/1/2004 Combustion 

Turbines

Unknown 3.0 ppmvd 

@15% O2, 

based on 3-hr 

average

Oxidation 

Catalyst

CA-9002 PG&E -

Colusa 

Generating 

Station

9/29/2008 Combustion 

Turbines

1917.2 CT

688 DB

3.0 ppmvd 

@15% O2, 

based on 3-hr 

average

Oxidation 

Catalyst

FL-0304 FMPA - Cane 

Island Power 

Park

9/8/2008 Combustion 

Turbines

1860 CT 

600 DB

6.0 ppmvd 

@15% O2 based 

on annual average

8.0 ppmvd @15% 

O2 based on 24-

hr average

Combustion 

Practices

As shown in the above table, the CO BACT emission limits range from a minimum of 0.9 ppmvd 

at 15% O2 to greater than 6.0 ppmvd at 15% O2, and the averaging periods range from a 1-hour 

average to a 30-day rolling average. The majority of the facilities with the most stringent CO 

BACT emission limits have installed oxidation catalysts for CO control; however, a recent permit 

identified in the table list good combustion practices as BACT for CO.

Based on a review of the emission limits achievable and recent BACT determinations for similar 

facilities, IDEM has determined that CO BACT for normal operation is a limit of 2.0 ppmvd at 15% 

O2 on a 3-hour rolling average basis. The only facilities in the RBLC with more stringent 

emission limits are the Virginia Electric and Power Company – Warren County Facility, Kleen 

Energy Systems, and the Georgia Power McDonough Combined Cycle Generating Units. The 

permit for the Warren County facility provides a range of BACT limits that cover three different 

potential turbine manufacturers with two or three operating modes per manufacturer. Since 

receiving the original air permit, the Virginia Electric and Power Company has submitted a new 

application for the Warren County requesting revisions to the CO BACT limits in the current 

permit. Some of the modes are higher for CO than proposed for the SJEC CCCT facility, while 

others are lower. In aggregate, the limits are likely slightly lower than the SJEC CCCT facility, but 
St. Joseph Energy Center, LLC Page 19 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

one limit is as high as 2.5 ppmvd. This substantial range of limits makes an accurate comparison 

with Warren County difficult. The permit for the McDonough Combined Cycle Generating Facility 

provides a BACT limit of 1.8 ppmvd at 15% O2 on a 3-hour average basis during periods of 

operation with duct burners. This facility is under construction. This limit is slightly lower, but 

nearly equivalent to that identified as BACT for the SJEC CCCT facility. McDonough uses larger 

G-class turbines that are designed to operate at higher capacity factors than the SJEC units and 

thus are not directly comparable to the F-class units for the SJEC CCCT facility. 

The “G” class combustion turbines differ from “F” in two important ways: a) the combustors fire at 

substantially higher temperatures; which fundamentally is the reason “G” machines have a 

somewhat higher thermal efficiency and b) the commercially available equipment is rated at 

250MW nominal each unit. The larger 250MW unit rating does not fit the 600MW power block 

capacity. A “2on1” configuration would be too large at 750MW and a “1on1” too small at 400MW.

Also, the higher thermal efficiency “G” machines are primarily designed to operate more 

frequently at a steady base loaded condition and not be cycled up and down in MW load or on 

and off frequently. The “F” class machines are more thermally flexible and the power blocks 

more responsive to varying market demand and unit load cycling operation. 

Based on the available interconnection with the local grid, the maximum load requirements 

established by near term market demand, and the need to respond quickly to frequent changes in 

power demand, use of "G" class combustion turbines are not suitable for this project and SJEC 

will utilize commercially proven F-class turbines.

The permit for the Kleen Energy Systems facility in Middletown, Connecticut provides a BACT 

limit of 1.7 ppmvd at 15% O2 on a 1-hour average basis during periods of operation with duct 

burners. The Kleen Energy Systems, LLC value is an outlier and is specific to the design of this 

facility. This limit is only slightly lower than that identified as BACT for the SJEC CCCT facility, 

and is reflective of the site-specific capabilities of this particular facility. Within the RBLC, all other 

demonstrated CO limits for F-class turbines are not less than 2.0 ppmv. Therefore the proposed 

limit of 2.0 ppmvd @15% O2, with duct burners based on 3-hr average is consistent with the most 

stringent limit for this type of operation.

The proposed SJEC CCCT facility BACT limit of 2.0 ppmvd at 15% O2 is consistent with other 

demonstrated permits limits reviewed in the RBLC database. Therefore, the proposed limit of 

2.0 ppmvd at 15% O2 on a 3-hour rolling average basis is appropriate for the proposed CCCTs.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for CO emissions from the proposed combined cycle 

combustion turbines, identified as CCCT1 -CCCT4:

(1) The CO emissions from the CCCT shall be controlled by catalytic oxidation

(2) The CO emissions shall not exceed 2.0ppmv @15% O2 based on a 3-hr average.

(3) The CO emissions from each of the turbines and the associated burners, excluding 

startup and shutdown periods, shall not exceed 407.5 tons per twelve (12) consecutive 

month period with compliance determined at the end of each month.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for CO for the combined cycle combustion turbines:

(1) The CO emissions from the CCCT shall be controlled by catalytic oxidation

(2) The CO emissions shall not exceed 2.0 ppmvd @15% O2 based on a 3-hour

average.
St. Joseph Energy Center, LLC Page 20 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Sulfur Dioxide (SO2) BACT - Combined Cycle Combustion Turbines CCCT1 - CCCT4 

Step 1: Identify Potential Control Technologies

Sulfur Dioxide (SO2) emissions result from the oxidation of fuel-bound sulfur, with emissions 

dependent upon the sulfur content of the fuel. Sulfur Dioxide (SO2) emissions are generally 

controlled with add-on control equipment designed to capture the emissions prior to the time they 

are exhausted to the atmosphere. 

(1) Flue Gas Desulfurization (FGD) System);

(2) Dry Sorbent Injection; and

(3) Fuel Specification.

The choice of which technology is most appropriate for a specific application depends upon 

several factors, including particle size to be collected, particle loading, stack gas flow rate, stack 

gas physical characteristics (e.g., temperature, moisture content, presence of reactive materials), 

and desired collection efficiency. Sulfur Dioxide (SO2) emissions are not dependent upon 

combustion turbine properties such as size or burner design.

Step 2: Eliminate Technically Infeasible Options

Flue Gas Desulfurization (FGD) System 

A flue gas desulfurization system (FGD) is comprised of a spray dryer that uses lime as a reagent 

followed by particulate control or wet scrubber that uses limestone as a reagent. FGD is an 

established technology. FGD typically operates at a temperature of approximately 300°F to 

700°F (wet) and 300°F to 1830°F (dry). The FGD has a waste stream inlet pollutant concentration 

of 2,000ppmv. Absorption of SO2 is accomplished by the contact between the exhaust and an 

alkaline reagent, which results in the formation of neutral salts. Wet systems employ reagents 

using packed or spray towers and generate wastewater streams, while dry systems inject slurry 

reagent into the exhaust stream to react, dry and be removed downstream by particulate control 

equipment. Chlorine emissions can result in salt deposition within the absorber and in 

downstream equipment. Wet systems may require flue gas re-heating downstream of the 

absorber to prevent corrosive condensation. Inlet streams for dry systems must be cooled as 

appropriate, and dry systems require use of particulate controls to collect the solid netural salts.

FGD systems are not listed in the RBLC as BACT for the control of H2SO4 emissions for large 

combined cycle combustion turbines. Technology has not been applied to natural gas combined 

cycle combustion turbines due to very low SO2 and H2SO4 emissions. Controls would not 

provide any measurable emission reduction.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of flue gas desulfurization system (FGD) is not a technically feasible option for the 

combined cycle combustion turbines (CCCT1-CCCT4) at this source.

Dry Sorbent Injection

A post-combustion technology in which a calcium or sodium-based sorbent reacts with SO2 and 

SO3 and is removed downstream by particulate control equipment. The system requires use of 

particulate controls to collect the reaction solids. Dry sorbent injection is not listed in the RBLC as 

BACT for the control of SO2 emissions for large combustion turbines. Technology has not been 

applied to natural gas combustion turbines due to very low SO2 emissions. Controls would not 

provide any measurable emission reduction.
St. Joseph Energy Center, LLC Page 21 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of dry sorbent injection is not a technically feasible option for the combined cycle 

combustion turbines (CCCT1-CCCT4) at this source.

Fuel Specifications 

Combusting only clean natural gas, which has an inherently low sulfur content, rather than higher 

sulfur content fuels alone or in combination with natural gas has a very low potential for 

generating SO2 emissions. Fuel Specifications is included in RBLC for the control of SO2

emissions from combustion turbines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Fuel Specifications is a technically feasible option for the combined cycle combustion 

turbines (CCCT1-CCCT4) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of SO2 resulting from the operation of the 

combined cycle combustion turbines (CCCT1-CCCT4). 

(1) Fuel Specifications 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed SO2 BACT determination along with the existing SO2 BACT 

determinations for similar plants. All data in the table is based on the information obtained from 

the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy 

Center -

proposed

Proposed Combined Cycle 

Combustion 

Turbines (CCCT1 -

CCCT4) 

2,300 

MMBtu/hr

SO2: 0.75 gr

S/100 scf fuel 

sulfur

Fuel 

Specification

CA-9002 PG&E -

Colusa 

Generating 

Station

9/29/2008 Combustion 

Turbines 

1917.2CT 

688 DB

0.3 gr S/100 cf 

gas

Fuel 

Specification

CA-9003 Sempra 

Energy 

Resources -

Palomar 

Energy Project

Unknown Combustion 

Turbines 

Unknown 0.75 gr S/100 

cf gas

Fuel 

Specification

FL-0304 FMPA - Cane 

Island Power 

Park

9/8/2008 Combustion 

Turbines 

1860 CT 

600 DB

2 gr S/100 cf 

gas

Fuel 

Specification

TX-0546 Pattillo Branch 

Power 

Company, 

LLC - Electric 

6/17/2009 Combustion 

Turbines 

444 DB 2 gf S/100 scf 

gas

Fuel 

Specification
St. Joseph Energy Center, LLC Page 22 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control Method

Generating 

Plant

FL-9002 FP&L 

Company -

Cape 

Canaveral 

Energy Center

7/23/2009 Combustion 

Turbines 

2586 CT 

460 DB

2 gf S/100 scf 

gas

Fuel 

Specification

The proposed CCCTs will be subject to NSPS KKKK. NSPS KKKK provides that either SO2

emissions from any turbine must not exceed 0.90 lb/MWh of gross output, or fuels burned in the 

turbine must have sulfur content that is below the amount which would result in potential sulfur 

emissions in excess of 0.060 lb SO2/MMBtu heat input. NSPS KKKK sets the floor of allowable 

SO2 BACT limits. Based on review of the emission limits achievable, IDEM has determined that 

SO2 BACT for normal operation is the use of fuels with a sulfur content no greater than 0.75 

grains per 100 standard cubic feet. The lowest BACT limit in all of the permits reviewed is 0.3 

grains per 100 standard cubic feet. The SO2 emissions are based primarily on the sulfur content 

of the natural gas available in the pipeline. The natural gas used at the SJEC CCCT facility will 

have a sulfur content of 0.75 grains per 100 standard cubic feet. The proposed natural gas sulfur 

content limit of 0.75 gr S/100 scf is dependent on the sulfur content of the natural gas available to 

the facility. 

The proposed facility will have access to natural gas from a single supplier for the region, and will 

not have the option to receive natural gas from any other source or require the supplier to provide 

lower sulfur content fuel. Therefore, the proposed BACT limit of the use of fuels with a sulfur 

content no greater than 0.75 grains per 100 standard cubic feet is appropriate.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for SO2 emissions from the proposed combined cycle 

combustion turbines, identified as CCCT1 -CCCT4:

The SO2 emissions from the combined cycle combustion turbines identified as CCCT1 -CCCT4

shall not exceed 0.75 gr S/100 scf fuel sulfur through the use of fuel specification. 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for SO2 for the combined cycle combustion turbines (CCCT1-CCCT4).

The SO2 emissions from the combined cycle combustion turbines identified as CCCT1 -CCCT4

shall be limited by a fuel sulfur limit of 0.75 gr S/100 scf fuel. 

Volatile Organic Compounds (VOCs) BACT – Combined Cycle Combustion Turbines CCCT1 -

CCCT4

Emissions of volatile organic compounds (VOCs) are generally controlled by oxidation. Oxidation

technologies include regenerative thermal oxidation, catalytic oxidation, and flares.

(a) Regenerative thermal oxidation; 

(b) Recuperative thermal oxidizer
St. Joseph Energy Center, LLC Page 23 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(c) SCONOx Catalytic Absorption System; 

(d) Catalytic oxidation; 

(e) Good Combustion Controls; and

(f) Flares.

If add-on control technology is not feasible, an alternate method of control may be implemented. 

Step 2: Eliminate Technically Infeasible Options

Regenerative Thermal Oxidizers

The thermal oxidizer has a high temperature combustion chamber that is maintained by a 

combination of auxiliary fuel, waste gas compounds, and supplemental air added when 

necessary. This technology is typically applied for destruction of organic vapors, nevertheless it is 

also considered as a technology for controlling VOC emissions. Upon passing through the flame, 

the waste gas containing VOC is heated. The mixture continues to react as it flows through the 

combustion chamber.

The required level of VOC destruction of the waste gas that must be achieved within the time that 

it spends in the thermal combustion chamber dictates the reactor temperature. The shorter the 

residence time, the higher the reactor temperature must be. Most thermal units are designed to 

provide no more than 1 second of residence time to the waste gas with typical temperatures of 

1,200 to 2,000o

F. Once the unit is designed and built, the residence time is not easily changed, 

so that the required reaction temperature becomes a function of the particular gaseous species 

and the desired level of control. 

A Regenerative Thermal Oxidizer incorporates heat recovery and greater thermal efficiency 

through the use of direct contact heat exchangers constructed of a ceramic material that can 

tolerate the high temperatures needed to achieve ignition of the waste stream.

The inlet gas first passes through a hot ceramic bed thereby heating the stream (and cooling the 

bed) to its ignition temperature. The hot gases then react (releasing energy) in the combustion 

chamber and while passing through another ceramic bed, thereby heating it. The process flows 

are then switched, feeding the inlet stream to the hot bed. This cyclic process affords very high 

energy recovery (up to 95%). The higher capital costs associated with these high-performance 

heat exchangers and combustion chambers may be offset by the increased auxiliary fuel savings 

to make such a system economical. 

Thermal oxidizers do not reduce emissions of VOC from properly operated natural gas 

combustion units without the use of a catalyst.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a regenerative thermal oxidizer is not a technically feasible option for the combined 

cycle combustion turbines at this source.

Recuperative Thermal Oxidizers

This control technology oxidizes combustible materials by raising the temperature of the material 

above the auto-ignition point in the presence of oxygen and maintaining the high temperature for 

sufficient time to complete combustion. The operating temperature ranges from 1,100 - 1.200o

F

and the waste stream inlet pollutants concentration is as low as 500-50,000 scfm. 
St. Joseph Energy Center, LLC Page 24 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Additional fuel is required to reach the ignition temperature of the waste gas stream. Oxidizers 

are not recommended for controlling gases with sulfur containing compounds because of the 

formation of highly corrosive acid gases. Thermal oxidizers do not reduce emissions of VOC from 

properly operated natural gas combustion units without the use of a catalyst.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a recuperative thermal oxidizer is not a technically feasible option for the combined 

cycle combustion turbines at this source.

SCONOx Catalytic Absorption System

This control technology utilizes a single catalyst to remove NOX, CO, and VOC through oxidation. 

Now operating as EmeraChem, the current version of the technology is now marketed as EMX. 

The operating temperature ranges from 300 - 700o

F. The SCONOX Catalyst is sensitive to 

contamination by sulfur, so it must be used in conjunction with the SCOSOX catalyst, which 

favors sulfur compound absorption. Not included in RBLC for control of CO emissions from large 

combustion turbines. Technology has only been demonstrated on units ranging from 5 to 45 MW.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a SCONOx Catalytic Absorption System is not a technically feasible option for 

combined cycle combustion turbines at this source.

Catalytic Oxidizers

Catalytic oxidation is also a widely used control technology to control pollutants where the waste 

gas is passed through a flame area and then through a catalyst bed for complete combustion of 

the waste in the gas. This technology is typically applied for destruction of organic vapors, 

nevertheless it is considered as a technology for controlling VOC emissions. A catalyst is an 

element or compound that speeds up a reaction at lower temperatures compared to thermal 

oxidation without undergoing change itself. Catalytic oxidizers operate at 600°F to 800°F and 

approximately require 1.5 to 2.0 ft3 of catalyst per 1000 standard ft3 per gas flow rate. 

Similar to thermal incineration; waste stream is heated by a flame and then passes through a 

catalyst bed that increases the oxidation rate more quickly and at lower temperatures. Typical 

waste stream inlet flow rate ranges from 700 - 50,000 scfm and waste stream inlet pollutant 

concentration is as low as 1ppmv.

Oxidation efficiency depends on exhaust flow rate and composition. Residence time required for 

oxidation to take place at the active sites of the catalyst may not be achieved if exhaust flow rates 

exceed design specifications. Also, sulfur and other compounds may foul the catalyst, leading to 

decreased efficiency. This control is widely accepted as BACT for control of VOC emissions from 

combustion turbines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a catalytic oxidizer is a technically feasible option for combined cycle combustion 

turbines at this source.

Flare

Although the VOC concentration is very low, the stream flow rate is very high. The low heating 

value of the stream is too low for flaring. As there are insufficient organics in this vent stream to 

support combustion, use of a flare would require a significant addition of supplementary fuel. 

Therefore, a secondary impact of the use of flare for this stream would be the creation of 

additional emissions from burning supplemental fuel, including NOx. Flares have not been 

utilized or demonstrated as a control device for VOC from this type of high-volume process 

stream. In addition, the flare would have no additional control versus the thermal oxidizers. 
St. Joseph Energy Center, LLC Page 25 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flare is not a technically feasible option for the combined cycle combustion turbines

at this source

Good Combustion Controls

Good combustion controls is a continued operation of the CCCT at the appropriate oxygen range 

and temperature to promote complete combustion and minimize VOC formation. Because VOC is 

essentially a by-product of incomplete or inefficient combustion, combustion control constitutes 

the primary mode of reduction of VOC emissions. This type of control is appropriate for any type 

of fuel combustion source. Combustion process controls involve combustion chamber designs 

and operating practices that improve the oxidation process and minimize incomplete combustion. 

VOC emissions result from the incomplete combustion of carbon and organic compounds. 

Factors affecting VOC emissions include firing temperatures, residence time in the combustion 

zone and combustion chamber mixing characteristics.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Good Combustion Controls is a technically feasible option for the combined cycle 

combustion turbines at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Oxidation Catalyst - 20-40% destruction efficiency

(2) Combustion Control

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed VOC BACT determination along with the existing VOC

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy 

Center -

proposed

Proposed Combined Cycle 

Combustion 

Turbines (CCCT1 -

CCCT4) 

2,300 

MMBtu/hr

1.0 ppmvd 

@15% O2, 

without duct 

burners based 

on 3-hr average

Oxidation 

Catalyst

2.0 ppmvd 

@15% O2, with 

duct burners 

based on 3-hr 

average

OK-0129 Associated 

Electric 

Cooperative, 

Inc. -

Chouteau 

Power Plant

1/20/2009 Combustion 

Turbines

1882 CT 

100 DB

0.3 ppmvd 

@15% O2

Good 

Combustion 

Practices

VA-0308 Virginia 

Electric and 

Power -

Warren 

County Facility

12/21/2010 Combustion 

Turbines

2996 CT 

500 DB

0.7 ppmvd 

@15% O2, 

without duct 

burners, based 

on 3-hr average, 

Oxidation 

Catalyst
St. Joseph Energy Center, LLC Page 26 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

1.6 ppmvd 

@15% O2 with 

duct burners, 

based on 3-hr 

average

CA-1144 Caithness 

Blythe II, LLC 

- Blythe 

Energy Project

4/25/2007 Combustion 

Turbines

Unknown 1 ppmvd @15% 

O2, based on 1-

hr average

Good 

Combustion 

Practices

ID-0018 Idaho Power 

Company 

Langley Gulch 

Power Plant

6/25/2010 Combustion 

Turbines

2134 CT

241.28 DB

2 ppmvd @15% 

O2, based on 3-

hr rolling, 11.5 

ppmvd @15% O2

based on 3-hr 

rolling average 

during low load 

events

Catalytic 

Oxidation

TX-0600 Lower 

Colorado 

River Authority 

Thomas C. 

Ferguson 

Power Plant

9/1/2011 Combustion 

Turbines

Unknown 2 ppmvd @15% 

O2, based on 3-

hr rolling

Catalytic 

Oxidation

FL-0303 FP&L - West 

County 

Energy Center

7/30/2008 Combustion 

Turbines

2333 CT 

428 DB

1.2 ppmvd 

@15% O2, based 

on 3-hr initial

Catalytic 

Oxidation

FL-0244 FP&L - Martin 

Plant

4/16/2003 Combustion 

Turbines

1600 CT 

495 DB

1.3 ppmvd 

@15% O2 without 

duct burners, 4 

ppmvd at 15% O2

with duct burners

Good 

Combustion 

Practices

AZ-0038 Gila Bend 

Power 

Generating 

Station

5/15/2002 Combustion 

Turbines

Unknown 2.8 ppmvd 

@15% O2, based 

on 3-hr average

Good 

Combustion 

Practices

MN-0053 Minnesota 

Municipal 

Power Agency 

- Fairbault 

Energy Park

6/5/2007 Combustion 

Turbines

1758 CT 

249 DB 

1.5 ppmvd 

@15% O2, 

without duct 

burners based on 

3-hr average, 3

ppmvd at 15% O2

with duct burners 

based on 3-hr 

average

Unknown

AZ-0043 Duke Energy 

Arlington 

Valley 

(AVEFII)

11/23/2003 Combustion 

Turbines

2333 CT 

(LHV)

428 DB 

(LHB)

1 ppmvd @15% 

O2 without duct 

burners, based 

on 3-hr average

4 ppmvd @15% 

O2 with duct 

burners, based 

on 3-hr average

Catalytic 

Oxidation
St. Joseph Energy Center, LLC Page 27 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

NJ-0043 Liberty 

Generating 

Station (State 

Requirement, 

not PSD)

3/28/2002 *Combustion 

Turbines

2964 CT 1 ppmvd @15% 

O2

Catalytic 

Oxidation

FL-0285 Progress 

Energy Florida 

– Bartow 

Power Plant

1/26/2007 Combustion 

Turbines

2006 CT 

500 DB

1.2 ppmvd 

@15% O2 without 

duct burners, 1.5 

ppmvd @15% O2

with duct 

burners,

None 

required by 

permit

PA-0189 Connectiv 

Bethlehem 

(not PSD 

BACT)

1/16/2002 Combustion 

Turbines

Unknown 1.2 ppmvd 

@15% O2

Unknown

FL-0263 FP&L –

Turkey Point 

Fossil Plant

2/8/2005 Combustion 

Turbines

1608 CT 

(LHF)

495 DB 

(LHV)

1.3 ppmvd 

@15% O2 without 

duct burners, 

based on 3-run 

average

1.9 ppmvd 

@15% O2 with 

duct burners, 

based on 3-run 

average

Good 

Combustion 

Practices

FL-0245 FP&L –

Manatee Plant 

Unit 3

4/15/2003 Combustion 

Turbines

1600 CT 

(LHV)

495 DB 

(LHV)

1.3 ppmvd 

@15% O2 without 

duct burners

4 ppmvd @15% 

O2 with duct 

burners

Good 

Combustion 

Practices

AR-0070 Genova 

Arkansas I, 

LLC

8/23/2002 Combustion 

Turbines

Unknown 1.4 ppmvd 

@15% O2

Good 

Combustion 

Practices

LA-01157 Perryville 

Energy 

Partners, LLC 

– Perryville 

Energy Center

3/8/2002 Combustion 

Turbines

Unknown 1.4 ppmvd 

@15% O2

Good 

Combustion 

Practices

NC-9001 Richmond 

County 

Combustion 

Turbine 

Facility

4/2/2009 Combustion 

Turbines

2225 CT

390 DB

1 ppmvd @15% 

O2 without duct 

burners at 70-

100% load

5 ppmvd @15% 

O2 without duct 

burners at 60-

70% load

3 ppmvd @15% 

O2 with duct 

burners at 60-

100% load

Good 

Combustion 

Practices
St. Joseph Energy Center, LLC Page 28 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

* Not yet constructed

The Caithness Blythe II, LLC project is in a state nonattainment area for ozone, requiring the 

source to obtain emission offsets for VOC. Therefore, this limit is not evaluated against the 

proposed project.

The limits for Connectiv Bethlehem were established to meet applicable requirements other than 

PSD-BACT requirements. Therefore, this limit is not evaluated against the proposed project.

The Liberty Generating Station was never constructed and is not evaluated against the proposed 

project.

The limits in the Virginia Electric and Power - Warren County Facility are for G-class turbines, not 

F-class turbines like those for the proposed project. Commercial operation is scheduled for late 

2014 or early 2015. Therefore, BACT limits have not been demonstrated.

The limits for FP&L – West County Energy Center are for G-class turbines, not F-class turbines 

like those for the proposed project.

The “G” class combustion turbines differ from “F” in two important ways: a) the combustors fire at 

substantially higher temperatures; which fundamentally is the reason “G” machines have a 

somewhat higher thermal efficiency and b) the commercially available equipment is rated at 

250MW nominal each unit. The larger 250MW unit rating does not fit the 600MW power block 

capacity. A “2on1” configuration would be too large at 750MW and a “1on1” too small at 400MW. 

Also, the higher thermal efficiency “G” machines are primarily designed to operate more 

frequently at a steady base loaded condition and not be cycled up and down in MW load or on 

and off frequently. The “F” class machines are more thermally flexible and the power blocks 

more responsive to varying market demand and unit load cycling operation. 

Based on the available interconnection with the local grid, the maximum load requirements 

established by near term market demand, and the need to respond quickly to frequent changes in 

power demand, use of "G" class combustion turbines are not suitable for this project and SJEC 

will utilize commercially proven F-class turbines.

The Associated Electric Cooperative, Inc. – Chouteau Power Plant value is an outlier and is 

specific to the design of this facility. All other demonstrated limits for F-class turbines are not less 

than 1.0 ppmvd without duct burner firing. Therefore the proposed limit of 1.0 ppmvd @15% O2, 

without duct burners and of 2.0 ppmvd @15% O2, with duct burners based on 3-hr average is 

consistent with all other limits in the RBLC for this type of operation.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for VOC emissions from the proposed combined cycle 

combustion turbines, identified as CCCT1 -CCCT4:

(1) The VOC emissions from the CCCT shall be controlled by a catalytic oxidation.

(2) The VOC emissions shall not exceed 2.0 ppmvd @15% O2, with duct burners based on 

3-hr average.

(3) The VOC emissions shall not exceed 1.0 ppmvd @15% O2, without duct burners based 

on 3-hr average.

(4) The VOCs emissions from each of the turbines and the associated burners, excluding 

startup and shutdown periods, shall not exceed 22.0 tons per twelve (12) consecutive 

month period with compliance determined at the end of each month.

Step 5: Select BACT
St. Joseph Energy Center, LLC Page 29 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for VOC for the combined cycle combustion turbines:

(1) The VOC emissions from the CCCTs shall be controlled by a catalytic oxidation

(2) The VOC emissions shall not exceed 2.0 ppmvd @15% O2, with duct burners based on 

3-hr average.

(3) The VOC emissions shall not exceed 1.0 ppmvd @15% O2, without duct burners based 

on 3-hr average.

Nitrogen Oxide (NOx) BACT – Combined Cycle Combustion Turbines CCCT01 - CCCT04

Step 1: Identify Potential Control Technologies

The nitrogen oxide (NOx) emissions can be controlled by the following methods: 

(a) Selective Catalytic Reduction (SCR);

(b) Selective Non-Catalytic Reduction (SNCR);

(c) SCONOx Catalytic Absorption System;

(d) Xonon Cool Combustion;

(e) Water/Steam Injection; and

(f) Low NOx Burners (LNB).

Add-on control technologies and combustion control approaches are discussed below.

Step 2: Eliminate Technically Infeasible Options

Selective Catalytic Reduction (SCR)

Selective Catalytic Reduction (SCR) process involves the mixing of anhydrous or aqueous 

ammonia vapor with flue gas and passing the mixture through a catalytic reactor to reduce NOX

to water and N2. Under optimal conditions, SCR has a removal efficiency up to 90% when used 

on steady state processes. The efficiency of removal will be reduced for processes that are not 

stable or require frequent changes in the mode of operation.

The most important factor affecting SCR efficiency is temperature. SCR can operate in a flue gas 

window ranging from 480°F to 800°F, although the optimum temperature range depends on the 

type of catalyst and the flue gas composition. In this particular service, the minimum target 

temperature is approximately 750o

F. Temperatures below the optimum decrease catalyst activity 

and allow NH3 to slip through; above the optimum range, ammonia will oxidize to form additional 

NOx. SCR efficiency is also largely dependent on the stoichiometric molar ratio of NH3:NOx; 

variation of the ideal 1:1 ratio to 0.5:1 ratio can reduce the removal efficiency to 50%.

Unreacted reagent may form ammonium sulfates which may plug or corrode downstream 

equipment. Particulate-laden streams may blind the catalyst and may necessitate the application 

of a sootblower. Selective Catalytic Reduction (SCR) is included in RBLC for the control of NOX

emissions from large combustion turbines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

selective catalytic reduction (SCR) is a technically feasible option for the combined cycle 

combustion turbines at this source.
St. Joseph Energy Center, LLC Page 30 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Selective Non-Catalytic Reduction (SNCR)

With selective non-catalytic reduction (SNCR), NOX is selectively removed by the injection of 

ammonia or urea into the flue gas at an appropriate temperature window of 1600°F to 2100°F 

and without employing a catalyst. Similar to SCR without a catalyst bed, the injected chemicals 

selectively reduce the NOX to molecular nitrogen and water. This approach avoids the problem 

related to catalyst fouling but the temperature window and reagent mixing residence time is 

critical for conducting the necessary chemical reaction. At the proper temperature, urea 

decomposes to produce ammonia which is responsible for NOX reduction. At a higher 

temperature, the rate of a competing reaction for the direct oxidation of ammonia that actually 

forms NOx becomes significant. At a lower temperature, the rates of NOX reduction reactions 

become too slow resulting in urea slip (i.e. emissions of unreacted urea).

Optimal implementation of SNCR requires the employment of an injection system that can 

accomplish thorough reagent/gas mixing within the temperature window while accommodating 

spatial and production rate temperature variability in the gas stream. The attainment of maximum 

NOx control performance therefore requires that the source exhibit a favorable opportunity for the 

application of this technology relative to the location of the reaction temperature range.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

selective non-catalytic reduction (SNCR) is a technically feasible option for the combined cycle 

combustion turbines at this source.

SCONOx Catalytic Absorption System

SCONOx Catalytic Absorption System utilizes a single catalyst to remove NOX, CO, and VOC 

through oxidation. Now operating as EmeraChem, the current version of the technology is now 

marketed as EMX. The Operating Temperature ranges from 300 - 700 °F. The SCONOX Catalyst 

is sensitive to contamination by sulfur, so it must be used in conjunction with the SCOSOX

catalyst, which favors sulfur compound absorption. This control technology is not listed in RBLC 

for the control of NOX emissions from large combustion turbines. Technology has only been 

demonstrated on units ranging from 5 to 45 MW.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

selective SCONOx Catalytic Absorption System is not a technically feasible option for the 

combined cycle combustion turbines at this source.

Xonon Cool Combustion

Xonon Cool Combustion is a catalyst integrated into gas turbine combustors that limits the 

production of NOX through temperature control also resulting in reduced emissions of CO and 

VOC. This control device is not included in RBLC for the control of NOX emissions from large 

combustion turbines. This technology is not commercially available on large units; all commercial 

installations to date have been on small turbines in the range of 1-2 MW.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

Xonon Cool Combustion is not a technically feasible option for the combined cycle combustion 

turbines at this source.

Water/Steam Injection

Water/steam Injection acts as a heat sink, lowing combustion zone peak temperatures, resulting 

in a decrease in thermal NOx emissions. This result in a small efficiency penalty but an increase 

in power output and this control technology may increase CO and VOC emissions. The control 

technology is included in RBLC for the control of NOX emissions from large combustion turbines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

Water/steam Injection is a technically feasible option for the combined cycle combustion turbines

at this source.
St. Joseph Energy Center, LLC Page 31 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Low NOx Burner (LNB)

Using LNB can reduce formation of NOx through careful control of the fuel-air mixture during 

combustion. Control techniques used in LNBs includes staged air, and fuel, as well as other 

methods that effectively lower the flame temperature. In the drive to reduce NOx emissions, NOx 

reduction techniques were implemented to lower peak flame temperature.

The LNBs are specially designed pieces of combustion equipment that reduce NOx formation 

through careful control of the fuel-air mixture during combustion. In a staged air combustion LNB, 

either air or fuel is added downstream of the primary combustion zone. Depending on which of 

these NOx reduction techniques is used, LNBs with staged combustion are subdivided into 

staged air burners and staged fuel burners. 

Experience suggests that significant reductions in NOx emissions can be realized using LNBs. 

The U.S. EPA reports that LNBs have achieved reduction up to 80%, but actual reduction 

depends on the type of fuel and varies considerably from one burner installation to another. 

Typical reductions range from 40% - 50% but under certain conditions, higher reductions are 

possible especially when another NOx reduction technique is used in conjunction with LNBs.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a low NOx burner is a technically feasible option for the combined cycle combustion 

turbines at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Selective Catalytic Reduction — (70-90% NOx Reduction)

(2) Selective Noncatalytic Reduction — (40-60% NOx Reduction)

(3) Low NOx Burner (LNB) — (40%-50% NOx Reduction)

(4) Water/Steam Injection — (30-50% NOx Reduction)

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed NOx BACT determination along with the existing NOx 

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy 

Center -

proposed

Proposed Combined Cycle 

Combustion 

Turbines (CCCT1 -

CCCT4) 

2,300 

MMBtu/hr

NOx: 2.0 ppmvd 

@15% O2, with 

duct burners 

based on 3-hr 

average

SCR and 

DLN 

Burners

VA-0308 Virginia 

Electric and 

Power -

Warren 

County Facility

12/21/2010 Combustion 

Turbines

2996 CT 

500 DB

2.0 ppmvd 

@15% O2, based 

on 1-hr average

DLN and 

SCR

FL-0303 FP&L - West 

County 

7/30/2008 Combustion 

Turbines

2333 CT 

428 DB

2.0 ppmvd 

@15% O2, based 

DLN and 

SCR
St. Joseph Energy Center, LLC Page 32 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

Energy Center on 24-hr average

AZ-0047 Dome Valley 

Energy 

Partners -

Wellton 

Mohawk 

Generating 

Facility

12/1/2004 Combustion 

Turbines

Unknown 2.0 ppmvd 

@15% O2, based 

on 3-hr for 18 

months and 1-hr 

average

DLN and 

SCR

WA-0315 Sumas Energy 

2 Generation 

Facility

3/11/2004 *Combustion 

Turbines

334 MW 

per turbine

2.0 ppmvd 

@15% O2, based 

on 3-hr average

DLN and 

SCR

ID-0012 Garnet 

Energy, 

Middleton 

Facility

10/19/2001 Combustion 

Turbines

1707 CT 

390 DB

2.5 ppmvd 

@15% O2, based 

on 12 month 

average

DLN and 

SCR

WA-0315 Wallula Power 

Plant

1/3/2003 Combustion 

Turbines

1300 MW 2.5 ppmvd 

@15% O2, based 

on 3-hr average

SCR

GA-0102 Wansley 

Combined 

Cycle Energy 

Facility

1/15/2002 Combustion 

Turbines

167 MW 3 ppmvd @15% 

O2

DLN and 

SCR

CA-1096 Vernon City 

Light and 

Power -

5/27/2003 Combustion 

Turbines

43 MW per 

turbine

2.0 ppmvd 

@15% O2, based 

on 1-hr average

SCR

* Never constructed 

The Sumas Energy 2 Generation Facility and Wallula Power Plant were never constructed and is

not evaluated against the proposed project.

The proposed CCCTs will be subject to NSPS KKKK. NSPS KKKK provides a NOX limit of 15 

ppmvd at 15 percent O2 for the CCCTs when burning natural gas. NSPS KKKK sets the floor of 

allowable NOX BACT limits. The lowest BACT emission rate in all of the permits reviewed is 2 

ppmvd at 15% O2. No facilities identified in the permit search had a lower BACT emission rate. 

The entries vary in the determination of the most appropriate averaging period, ranging from a 1-

hour average to a 30-day rolling average. 

All of the facilities identified with the most stringent NOX emission limits utilize SCR for control of 

NOX emissions. Based on a review of the emission limits achievable and recent BACT 

determinations for similar facilities, the NOX BACT for normal operation is a limit of 2 ppmvd at 

15% O2 on a 3-hour rolling average basis utilizing SCR. As shown in the above table, the 

proposed limit is consistent with the most stringent limit for NOX at 2.0 ppmvd at 15% O2.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for VOC emissions from the proposed combined cycle 

combustion turbines, identified as CCCT1 -CCCT4:

(1) The NOx emissions from the CCCT shall be controlled by a Selective Catalytic Reduction 

and DLN Burners.

(2) The NOx emissions shall not exceed 2.0ppmv @15% O2 with duct burners based on a 3-

hr average.
St. Joseph Energy Center, LLC Page 33 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(3) The NOx emissions from each of the turbines and the associated burners, excluding 

startup and shutdown periods, shall not exceed 81.6 tons per twelve (12) consecutive 

month period with compliance determined at the end of each month.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for NOx for the combined cycle combustion turbines:

(1) The NOx emissions from the CCCTs shall be controlled by a Selective Catalytic 

Reduction and DLN Burners.

(2) The NOx emissions shall not exceed 2.0ppmv @15% O2 with duct burners based 

on a 3-hr average.

Particulate Matter (PM/PM10/PM2.5) BACT – Auxiliary Boilers B001- B002

Emissions of PM, PM10 and PM2.5 are generally controlled with add-on control equipment 

designed to capture the emissions prior to the time they are exhausted to the atmosphere. In 

cases where the material being emitted is organic, particulate matter may be controlled through a 

combustion process. Generally, PM, PM10 and PM2.5 emissions are controlled through one of the 

following mechanisms:

(1) Fabric Filter Dust Collectors (Baghouses).

(2) Electrostatic Precipitators (ESP); and

(3) Wet Scrubbers;

(4) Cyclones or Multiclones;

(5) Fuel Specification; and

(6) Good Combustion Practices.

The choice of which technology is most appropriate for a specific application depends upon

several factors, including particle size to be collected, particle loading, stack gas flow rate, stack 

gas physical characteristics (e.g., temperature, moisture content, presence of reactive materials), 

and desired collection efficiency.

Step 2: Eliminate Technically Infeasible Options

Fabric Filtration:

A fabric filter unit consists of one or more isolated compartments containing rows of fabric bags in 

the form of round, flat, or shaped tubes, or pleated cartridges. Particle laden gas passes up 

(usually) along the surface of the bags then radially through the fabric. Particles are retained on 

the upstream face of the bags, and the cleaned gas stream is vented to the atmosphere. The 

filter is operated cyclically, alternating between relatively long periods of filtering and short periods 

of cleaning. During cleaning, dust that has accumulated on the bags is removed from the fabric 

surface and deposited in a hopper for subsequent disposal.

Fabric filters collect particles with sizes ranging from submicron to several hundred microns in 

diameter at efficiencies generally in excess of 99 or 99.9%. The layer of dust, or dust cake, 

collected on the fabric is primarily responsible for such high efficiency. The cake is a barrier with 

tortuous pores that trap particles as they travel through the cake. 
St. Joseph Energy Center, LLC Page 34 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Gas temperatures up to about 500°F, with surges to about 550°F, can be accommodated 

routinely in some configurations. Most of the energy used to operate the system appears as 

pressure drop across the bags and associated hardware and ducting. Typical values of system 

pressure drop range from about 5 to 20 inches of water.

Fabric filters are used where high efficiency particle collection is required. Limitations are 

imposed by gas characteristics (temperature and corrosivity) and particle characteristics 

(primarily stickiness) that affect the fabric or its operation and that cannot be economically 

accommodated. Important process variables include particle characteristics, gas characteristics, 

and fabric properties. The most important design parameter is the air- or gas-to-cloth ratio (the 

amount of gas in ft3

/min that penetrates one ft2 of fabric) and the usual operating parameter of 

interest is pressure drop across the filter system. The major operating feature of fabric filters that 

distinguishes them from other gas filters is the ability to renew the filtering surface periodically by 

cleaning. Common furnace filters, high efficiency particulate air (HEPA) filters, high efficiency air 

filters (HEAFs), and automotive induction air filters are examples of filters that must be discarded 

after a significant layer of dust accumulates on the surface. These filters are typically made of 

matted fibers, mounted in supporting frames, and used where dust concentrations are relatively 

low. Fabric filters are usually made of woven or (more commonly) needle-punched felts sewn to 

the desired shape, mounted in a plenum with special hardware, and used across a wide range of 

dust concentrations.

The fabric filters are susceptible to corrosion and binding by moisture. Appropriate fabrics must 

be selected for specific process conditions. Accumulations of dust may present fire or explosion 

hazard. The typical waste stream inlet flow is 100-100,000 scfm (Standard) or 100,000-1,000,00 

scfm (Custom). The natural gas fired boilers generate low particulate matter emissions and have 

large exhaust flow rates, resulting in very low concentration of particulates.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Baghouse is not a technically feasible option for the Auxiliary Boilers (B001-B002) at 

this source.

Electrostatic Precipitators:

An electrostatic precipitator (ESP) is a particle control device that uses electrical forces to move 

the particles out of the flowing gas stream and onto collector plates. The particles are given an 

electrical charge by forcing them to pass through a corona, a region in which gaseous ions flow. 

The electrical field that forces the charged particles to the walls comes from electrodes 

maintained at high voltage in the center of the flow lane.

Once the particles are collected on the plates, they must be removed from the plates without 

re-entraining them into the gas stream. This is usually accomplished by knocking them loose 

from the plates, allowing the collected layer of particles to slide down into a hopper from which 

they are evacuated. Some precipitators remove the particles by intermittent or continuous 

washing with water. ESP control efficiencies can range from 95% to 99.9%.

Gas temperatures may be up to about 1,300 °F (dry) and Lower than 170 - 190 °F (wet). The 

typical waste stream inlet flow is 1,000 - 100,000 scfm (Wire-Pipe) and 100,000 - 1,000,000 scfm 

(Wire-Plate). Dry ESP efficiency varies significantly with dust resistivity. Air leakage and acid 

condensation may cause corrosion. ESPs are not generally suitable for highly variable 

processes. Equipment footprint is often substantial. Natural-gas fired auxiliary boilers generate 

low Particulate emissions and have large exhaust flowrates, resulting in very low concentrations 

of Particulates. Add-on control devices would not provide any measurable emission reduction.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a electrostatic precipitator is not a technically feasible option for the Auxiliary Boilers 

(B001-B002) at this source.
St. Joseph Energy Center, LLC Page 35 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Wet scrubbers:

A wet scrubber is an air pollution control device that removes PM from waste gas streams 

primarily through the impaction, diffusion, interception and/or absorption of the pollutant onto 

droplets of liquid. The liquid containing the pollutant is then collected for disposal. There are 

numerous types of wet scrubbers that remove PM. Collection efficiencies for wet scrubbers vary 

with the particle size distribution of the waste gas stream. In general, collection efficiency 

decreases as the PM size decreases. Collection efficiencies also vary with scrubber type. 

Collection efficiencies range from greater than 99% for venturi scrubbers to 40-60% (or lower) for 

simple spray towers. Wet scrubbers are smaller and more compact than baghouses or ESPs. 

They have lower capital costs and comparable operation and maintenance (O&M) costs. Wet 

scrubbers are particularly useful in the removal of PM with the following characteristics:

(1) Sticky and/or hygroscopic materials (materials that readily absorb water);

(2) Combustible, corrosive and explosive materials;

(3) Particles which are difficult to remove in their dry form;

(4) PM in the presence of soluble gases; and

(5) PM in waste gas streams with high moisture content.

The primary disadvantage of wet scrubbers is that increased collection efficiency comes at the 

cost of increased pressure drop across the control system. Another disadvantage is that they are 

limited to lower waste gas flow rates and temperatures than ESPs or baghouses. Current wet 

scrubber designs accommodate air flow rates over 100,000 actual cubic feet per minute and 

temperatures of up to 750°F. Another disadvantage is that they generate waste in the form of a 

sludge which requires treatment and/or disposal. Lastly, downstream corrosion or plume visibility 

problems can result unless the added moisture is removed from the gas stream.

Gas temperatures are between 40 to 750 °F. The typical waste stream inlet flow is 500 - 100,000 

scfm (units in parallel can operate at greater flow rates). Effluent wastewater stream may require 

treatment. Sludge disposal may be costly. Wet scrubbers are particularly susceptible to 

corrosion. Natural-gas fired auxiliary boilers generate low Particulate emissions and have large 

exhaust flowrates, resulting in very low concentrations of Particulates. Add-on control devices 

would not provide any measurable emission reduction.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a wet scrubber is not a technically feasible option for the Auxiliary Boilers (B001-B002)

at this source.

Cyclones:

Cyclones are simple mechanical devices commonly used to remove relatively large particles from 

gas streams. In industrial applications, cyclones are often used as precleaners for the more 

sophisticated air pollution control equipment such as ESPs or baghouses. Cyclones are less 

efficient than wet scrubbers, baghouses, or ESPs. 

Cyclones used as pre-cleaners are often designed to remove more than 80% of the particles that 

are greater than 20 microns in diameter. Smaller particles that escape the cyclone can then be 

collected by more efficient control equipment. This control technology may be more commonly 

used in industrial sites that generate a considerable amount of particulate matter, such as lumber 

companies, feed mills, cement plants, and smelters.
St. Joseph Energy Center, LLC Page 36 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

The gas temperature is about 1,000°F. The typical waste stream inlet flow is between 1.1 -

63,500 scfm (single) and Up to 106,000 scfm (in parallel). Cyclones typically exhibit lower 

efficiencies when collecting smaller particles. High-efficiency units may require substantial 

pressure drop. Natural-gas fired auxiliary boilers generate low Particulate emissions and have 

large exhaust flowrates, resulting in very low concentrations of Particulates. Add-on control 

devices would not provide any measurable emission reduction.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a cyclone is not a technically feasible option for the Auxiliary Boilers (B001-B002) at 

this source.

Fuel Specifications 

Combusting only clean natural gas, which has an inherently low sulfur content, rather than higher 

sulfur content fuels alone or in combination with natural gas has a very low potential for 

generating PM, PM10 and PM2.5 emissions. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Fuel Specifications is a technically feasible option for the Auxiliary Boilers (B001-B002)

at this source.

Good Combustion Practices 

Good combustion practices as well as operation and maintenance of the Auxiliary Boilers to keep 

them in good working order per the manufacturer's specifications will minimize PM, PM10 and 

PM2.5 emissions. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Good Combustion Practices is a technically feasible option for the Auxiliary Boilers 

(B001-B002) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of PM, PM10 and PM2.5 resulting from the 

operation of the Auxiliary Boilers (B001-B002).

(1) Fuel Specifications 

(2) Good Combustion Practices 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for similar plants. All data in the table is 

based on the information obtained from the permit application submitted by St. Joseph Energy 

Center, LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of 

permits available at the websites of other permitting agencies.

BACT ID 

or Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control Method

Draft 

Permit No. 

141-31003-

00579

Proposed

Limit

St. Joseph 

Energy Center -

proposed

Proposed Auxiliary Boilers 

(B001 and B002)

80 

MMBtu/hr

PM/PM10/PM2.5: 

0.0075 lb/MMBtu 

and 0.6 lb/hr, 

each, based on 

3-hr average

Good 

Combustion 

Practices and 

Fuel 

Specifications

VA-0270 VCU EAST 

PLANT

3/31/2003 BOILER 

NATURAL GAS

150 

MMBtu/hr

0.008 lb/MMBtu 

and 1.2 lb/hr

Good 

Combustion 
St. Joseph Energy Center, LLC Page 37 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID 

or Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control Method

Practices

OH-0310 AMERICAN 

MUNICIPAL 

POWER 

GENERATING 

STATION

10/8/2009

AUXILIARY 

BOILER

150 

MMBtu/hr

0.008 lb/MMBtu 

and 1.14 lb/hr

Unknown

NC-0101 FORSYTH 

ENERGY PLANT

9/29/2005 AUXILIARY 

BOILER

110.2 

MMBtu/hr

0.074 lb/MMBtu 

and 0.82 lb/hr, 

based on 3-hr avg

GOOD 

COMBUSTION 

CONTROL 

AND 

NATURAL 

GAS ONLY

VA-0278 VCU EAST 

PLANT

3/31/2003 BOILER 

NATURAL GAS

150 

MMBtu/hr

0.008 lb/MMBtu 

and 1.2 lb/hr

Unknown

OR-0046 TURNER 

ENERGY 

CENTER, LLC

1/6/2005 AUXILIARY 

BOILER

417,904 

MMBtu/yr

none Natural gas 

only

OR-0040 KLAMATH 

GENERATION, 

LLC

3/12/2003 *BOILER, 

AUXILIARY, 

NATURAL GAS

50,000 

lb/hr

0.004 lb/MMBtu Unknown

TN-0153 WILLIAMS 

REFINING & 

MARKETING, 

L.L.C.

4/3/2002 Heaters (5) 50 

MMBtu/hr

0.005 lb/MMBtu Unknown

TN-0153 WILLIAMS 

REFINING & 

MARKETING, 

L.L.C.

4/3/2002 Boiler No. 9 95 

MMBtu/hr

0.0075 lb/MMBtu Unknown

TN-0153 WILLIAMS 

REFINING & 

MARKETING, 

L.L.C.

4/3/2002 Boiler No. 10 180 

MMBtu/hr

0.0075 lb/MMBtu Unknown

LA-0246

VALERO ST. 

CHARLES 

REFINERY 7/6/2011

EQT0323 - Boiler 

401F

99 

MMBtu/hr

0.74 lb/hr and 

0.0075 lb/MMBtu

Proper design 

and operation, 

good 

combustion 

practices and 

gaseous fuels

OR-0048 PGE Carty Plant 12/24/2009

**NATURAL 

GAS-FIRED 

BOILER

91 

MMBtu/hr

0.002 lb/MMBtu Clean Fuel

Note: * Under construction 

** Not yet constructed

The limits for the Williams Refining and Marketing, L.L.C. heaters are not applicable to this 

project, which includes installation of auxiliary boilers, not process heaters. The units for the 

Klamath Generation, LLC, and PGE Carty Plant have not yet been constructed, so these limits 

have not been demonstrated. Therefore, the proposed limit of 0.0075 lb/MMBtu is consistent with 

the most stringent limits for this type of operation.
St. Joseph Energy Center, LLC Page 38 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for PM, PM10 and PM2.5 emissions from the proposed 

Auxiliary Boilers (B001-B002):

The PM, PM10 and PM2.5 emissions from the Auxiliary Boilers, identified as B001-B002 shall be 

limited to less than 0.0075 lb/MMBtu and 0.6 lbs/hr, each, based on a 3-hr average period through 

the use of good combustion practices and fuel specification. 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for the Auxiliary Boilers (B001-B002).

The PM, PM10 and PM2.5 emissions from the Auxiliary Boilers, identified as B001-B002 shall not 

exceed 0.0075 lb/MMBtu and 0.6 lbs/hour, each, based on a 3-hr average period through the use of 

good combustion practices and fuel specification. 

Carbon Monoxide (CO) BACT – Auxiliary Boilers B001 - B002

Step 1: Identify Potential Control Technologies

Emissions of carbon monoxide (CO) are generally controlled by oxidation. Oxidation technologies 

include regenerative thermal oxidation, catalytic oxidation, and flares.

(a) Regenerative thermal oxidation; 

(b) Recuperative thermal oxidizer

(c) Catalytic oxidation; 

(d) Good Combustion Controls; and

(e) Flares.

If add-on control technology is not feasible, an alternate method of control may be implemented. 

Step 2: Eliminate Technically Infeasible Options

Regenerative Thermal Oxidizers

The thermal oxidizer has a high temperature combustion chamber that is maintained by a 

combination of auxiliary fuel, waste gas compounds, and supplemental air added when 

necessary. This technology is typically applied for destruction of organic vapors, nevertheless it is 

also considered as a technology for controlling VOC emissions. Upon passing through the flame, 

the waste gas containing VOC is heated. The mixture continues to react as it flows through the 

combustion chamber.

The required level of VOC destruction of the waste gas that must be achieved within the time that 

it spends in the thermal combustion chamber dictates the reactor temperature. The shorter the 

residence time, the higher the reactor temperature must be. Most thermal units are designed to 

provide no more than 1 second of residence time to the waste gas with typical temperatures of 

1,200 to 2,000o

F. Once the unit is designed and built, the residence time is not easily changed, 

so that the required reaction temperature becomes a function of the particular gaseous species 

and the desired level of control. 
St. Joseph Energy Center, LLC Page 39 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

A Regenerative Thermal Oxidizer incorporates heat recovery and greater thermal efficiency 

through the use of direct contact heat exchangers constructed of a ceramic material that can 

tolerate the high temperatures needed to achieve ignition of the waste stream.

The inlet gas first passes through a hot ceramic bed thereby heating the stream (and cooling the 

bed) to its ignition temperature. The hot gases then react (releasing energy) in the combustion 

chamber and while passing through another ceramic bed, thereby heating it. The process flows 

are then switched, feeding the inlet stream to the hot bed. This cyclic process affords very high 

energy recovery (up to 95%). The higher capital costs associated with these high-performance 

heat exchangers and combustion chambers may be offset by the increased auxiliary fuel savings 

to make such a system economical. 

Thermal oxidizers do not reduce emissions of VOC from properly operated natural gas 

combustion units without the use of a catalyst.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a regenerative thermal oxidizer is not a technically feasible option for the Auxiliary 

Boilers at this source.

Recuperative Thermal Oxidizers

This control technology oxidizes combustible materials by raising the temperature of the material 

above the auto-ignition point in the presence of oxygen and maintaining the high temperature for 

sufficient time to complete combustion. The operating temperature ranges from 1,100 - 1.200o

F

and the waste stream inlet pollutants concentration is as low as 500-50,000 scfm. 

Additional fuel is required to reach the ignition temperature of the waste gas stream. Oxidizers 

are not recommended for controlling gases with sulfur containing compounds because of the 

formation of highly corrosive acid gases. Thermal oxidizers do not reduce emissions of VOC from 

properly operated natural gas combustion units without the use of a catalyst.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a recuperative thermal oxidizer is not a technically feasible option for the Auxiliary 

Boilers at this source.

Catalytic Oxidizers

Catalytic oxidation is also a widely used control technology to control pollutants where the waste 

gas is passed through a flame area and then through a catalyst bed for complete combustion of 

the waste in the gas. This technology is typically applied for destruction of organic vapors, 

nevertheless it is considered as a technology for controlling CO emissions. A catalyst is an 

element or compound that speeds up a reaction at lower temperatures compared to thermal 

oxidation without undergoing change itself. Catalytic oxidizers operate at 600°F to 800°F and 

approximately require 1.5 to 2.0 ft3 of catalyst per 1000 standard ft3 per gas flow rate. 

Similar to thermal incineration; waste stream is heated by a flame and then passes through a 

catalyst bed that increases the oxidation rate more quickly and at lower temperatures. Typical 

waste stream inlet flow rate ranges from 700 - 50,000 scfm and waste stream inlet pollutant 

concentration is as low as 1ppmv.

Oxidation efficiency depends on exhaust flow rate and composition. Residence time required for

oxidation to take place at the active sites of the catalyst may not be achieved if exhaust flow rates 

exceed design specifications. Also, sulfur and other compounds may foul the catalyst, leading to 

decreased efficiency. .

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a catalytic oxidizer is a technically feasible option for Auxiliary Boilers at this source.
St. Joseph Energy Center, LLC Page 40 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Flare

Although the CO concentration is very low, the stream flow rate is very high. The low heating 

value of the stream is too low for flaring. As there are insufficient organics in this vent stream to 

support combustion, use of a flare would require a significant addition of supplementary fuel. 

Therefore, a secondary impact of the use of flare for this stream would be the creation of 

additional emissions from burning supplemental fuel, including NOx. Flares have not been 

utilized or demonstrated as a control device for CO from this type of high-volume process stream. 

In addition, the flare would have no additional control versus the thermal oxidizers. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flare is not a technically feasible option for the Auxiliary Boilers at this source

Good Combustion Controls

Good combustion controls is a continued operation of the CCCT at the appropriate oxygen range 

and temperature to promote complete combustion and minimize CO formation. Because CO is 

essentially a by-product of incomplete or inefficient combustion, combustion control constitutes 

the primary mode of reduction of CO emissions. This type of control is appropriate for any type of 

fuel combustion source. Combustion process controls involve combustion chamber designs and 

operating practices that improve the oxidation process and minimize incomplete combustion. CO 

emissions result from the incomplete combustion of carbon and organic compounds. Factors 

affecting CO emissions include firing temperatures, residence time in the combustion zone and 

combustion chamber mixing characteristics.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Good Combustion Controls is a technically feasible option for the Auxiliary Boilers at 

this source

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Oxidation Catalyst - (50-90% destruction efficiency)

(2) Combustion Control

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed CO BACT determination along with the existing CO BACT 

determinations for similar plants. All data in the table is based on the information obtained from 

the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy 

Center -

proposed

Proposed Auxiliary Boilers 

(B001 and B002)

80 

MMBtu/hr

CO: 0.083

lb/MMBtu and 

6.64 lb/hr,

each, based 

on 3-hr 

average

Good 

Combustion 

Practices 

OH-0310 AMERICAN 

MUNICIPAL 

POWER 

GENERATING 

STATION

10/8/2009 AUXILIARY 

BOILER

150 

MMBtu/h

12.6 lb/hr and 

0.084 

lb/MMBtu

None

NC-0101 FORSYTH 

ENERGY 

9/29/2005 AUXILIARY 

BOILER

110.2 

MMBtu/h

9.08 lb/hr and 

0.082 

LOW NOX

BURNERS & 
St. Joseph Energy Center, LLC Page 41 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control Method

PLANT lb/MMBtu, 

based on 3-hr 

avg

GOOD 

COMBUSTION 

CONTROL 

WI-0204 UWGP - FUEL 

GRADE 

ETHANOL 

PLANT

8/14/2003 BOILER 

/OXIDIZER 

( DRYER / 

DISTILLATION), 

P10

140 

MMBtu/h

18.4 lb/hr and 

0.131 

lb/MMBtu

None

LA-0184 TITANIUM 

DIOXIDE 

FACILITY

5/13/2003 UTILITY BOILERS 

D841-1X & D841-

2X (135 MM BTU/H 

EA.)

135

MMBtu/h

12.229 lb/hr 

and 0.091 

lb/MMBtu

GOOD 

EQUIPMENT 

DESIGN AND 

PROPER 

COMBUSTION 

TECHNIQUES

VA-0270 VCU EAST 

PLANT

3/31/2003 BOILER NATURAL 

GAS

150 

MMBtu/hr

0.099 

lb/MMBtu and 

14.9 lb/hr

GOOD 

COMBUSTION 

PRACTICE

VA-0278 VCU EAST 

PLANT

3/31/2003 BOILER NATURAL 

GAS (3)

150.6

MMBtu/hr

0.099 

lb/MMBtu and 

14.9 lb/hr

GOOD 

COMBUSTION 

PRACTICE

OR-0040 KLAMATH 

GENERATION, 

LLC

3/12/2003 *BOILER, 

AUXILIARY, 

NATURAL GAS

50,000 lb/hr 0.035

lb/MMBtu, 

based on 3-hr 

avg

Unknown

CO-0052 ROCKY 

MOUNTAIN 

ENERGY 

CENTER, LLC.

8/11/2002 NATURAL GAS 

FIRED BOILER 

(AUXILIARY 

BOILER)

129 

MMBtu/hr

0.039 

lb/MMBtu

GOOD 

COMBUSTION 

PRACTICES

TN-0153 WILLIAMS 

REFINING & 

MARKETING, 

L.L.C.

4/3/2002 Boiler No. 9 95 

MMBtu/hr

0.09 lb/MMBtu Unknown

LA-0246 VALERO ST. 

CHARLES 

REFINDERY

7/6/2011 EQT0323 - Boiler 

401F

99 

MMBtu/Hr

0.092 

lb/MMBtu and 

9.15 lb/hr

Proper design 

and 

operation, 

good 

combustion 

practices and 

gaseous fuels

Note: *under construction.

The unit for Klamath Generation, LLC, has not yet been constructed, so this limit has not been 

demonstrated. The Rocky Mountain Energy Center, LLC value is an outlier and is specific to the 

design and operation of this facility. All other demonstrated limits for CO are not less than 0.082 

lb/MMBtu. Therefore the proposed limit of 0.083 lb/MMBtu is consistent with all other limits in the 

RBLC for this type of operation.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for CO emissions from the proposed Auxiliary Boilers, 

identified as B001-B002:
St. Joseph Energy Center, LLC Page 42 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

The CO emissions from the Auxiliary Boilers (B001-B002) operation shall not exceed 0.083 

lb/MMBtu and 6.64 lbs/hr, each, based on a 3 - hour average through Good Combustion 

Practices.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for CO for Auxiliary Boilers (B001-B002).

The CO emissions from the Auxiliary Boilers (B001-B002) operation shall not exceed 0.083 

lb/MMBtu and 6.64 lbs/hr, each, based on a 3 - hour average through Good Combustion 

Practices.

Sulfur Dioxide (SO2) BACT - Auxiliary Boilers B001 - B002

Step 1: Identify Potential Control Technologies

Sulfur Dioxide (SO2) emissions result from the oxidation of fuel-bound sulfur, with emissions 

dependent upon the sulfur content of the fuel. Sulfur Dioxide (SO2) emissions are generally 

controlled with add-on control equipment designed to capture the emissions prior to the time they 

are exhausted to the atmosphere. 

(1) Flue Gas Desulfurization (FGD) System);

(2) Dry Sorbent Injection; and

(3) Fuel Specification.

The choice of which technology is most appropriate for a specific application depends upon 

several factors, including particle size to be collected, particle loading, stack gas flow rate, stack 

gas physical characteristics (e.g., temperature, moisture content, presence of reactive materials), 

and desired collection efficiency. 

Step 2: Eliminate Technically Infeasible Options

Flue Gas Desulfurization (FGD) System 

A flue gas desulfurization system (FGD) is comprised of a spray dryer that uses lime as a reagent 

followed by particulate control or wet scrubber that uses limestone as a reagent. FGD is an 

established technology. FGD typically operates at a temperature of approximately 300°F to 

700°F (wet) and 300°F to 1830°F (dry). The FGD has a waste stream inlet pollutant concentration 

of 2,000ppmv. Absorption of SO2 is accomplished by the contact between the exhaust and an 

alkaline reagent, which results in the formation of neutral salts. Wet systems employ reagents 

using packed or spray towers and generate wastewater streams, while dry systems inject slurry 

reagent into the exhaust stream to react, dry and be removed downstream by particulate control 

equipment. Chlorine emissions can result in salt deposition within the absorber and in 

downstream equipment. Wet systems may require flue gas re-heating downstream of the 

absorber to prevent corrosive condensation. Inlet streams for dry systems must be cooled as 

appropriate, and dry systems require use of particulate controls to collect the solid netural salts.
St. Joseph Energy Center, LLC Page 43 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

FGD systems are not listed in the RBLC as BACT for the control of SO2 emissions for auxiliary 

boilers. Technology has not been applied to natural gas auxiliary boiler due to very low SO2

emissions. Controls would not provide any measurable emission reduction.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of flue gas desulfurization system (FGD) is not a technically feasible option for the 

Auxiliary Boilers at this source.

Dry Sorbent Injection

A post-combustion technology in which a calcium or sodium-based sorbent reacts with SO2 and 

SO3 and is removed downstream by particulate control equipment. The system requires use of 

particulate controls to collect the reaction solids. Dry sorbent injection is not listed in the RBLC as 

BACT for the control of SO2 emissions for auxiliary boilers. Technology has not been applied to 

natural gas combustion turbines due to very low SO2 emissions. Controls would not provide any 

measurable emission reduction.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of dry sorbent injection is not a technically feasible option for the Auxiliary Boilers at this 

source.

Fuel Specifications 

Combusting only clean natural gas, which has an inherently low sulfur content, rather than higher 

sulfur content fuels alone or in combination with natural gas has a very low potential for 

generating SO2 emissions. Fuel Specifications is included in RBLC for the control of SO2

emissions from Auxiliary Boilers.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Fuel Specifications is a technically feasible option for the Auxiliary Boilers at this 

source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of SO2 resulting from the operation of the 

Auxiliary Boilers. 

(1) Fuel Specifications 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed SO2 BACT determination along with the existing SO2

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy 

Center -

proposed

Proposed Auxiliary Boilers 

(B001 and B002)

80 

MMBtu/hr

SO2: 0.0022

lb/MMBtu and

0.176 lb/hr,

each, based 

on 3-hr 

average

Fuel 

Specifications

VA-0270 VCU EAST 

PLANT

3/31/2003 BOILER NATURAL 

GAS

150 

MMBtu/hr

0.299 lb/MMBtu GOOD 

COMBUSTION 

PRACTICES. 
St. Joseph Energy Center, LLC Page 44 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control Method

LOW SULFUR 

FUELS.

AL-0230 THYSSENKRU

PP STEEL AND 

STAINLESS 

USA, LLC

8/17/2007 3 natural Gas-Fired 

Boilers

64.9 

MMBtu/Hr, 

each

0.006 lb/MMBtu None

AL-0230 THYSSENKRU

PP STEEL AND 

STAINLESS 

USA, LLC

8/17/2007 Boilers with ULNB 64.9 

MMBtu/Hr, 

each

0.006 lb/MMBtu None

IA-0062 EMERY 

GENERATING 

STATION

12/20/2002 Auxiliary Boilers 68 

MMBtu/Hr, 

each

0.006 lb/MMBtu Low Sulfur Fuel, 

Natural gas

OH-0251 CENTRAL 

SOYA 

COMPANY 

INC.

11/12/2007 Natural Gas Boiler 91.2 

MMBtu/Hr, 

each

0.006 lb/MMBtu None

AL-0231 NUCOR 

DECATUR LLC

6/12/2007 Vacuum Gegasser 

Boiler

95 

MMBtu/Hr, 

each

0.006 lb/MMBtu None

MN-0054 MANKATO 

ENERGY 

CENTER

12/4/2003 Auxiliary Boilers 70 

MMBtu/Hr

0.001 lb/MMBtu Low Sulfur Fuel

VA-0255 VA POWER -

POSSUM 

POINT

11/18/2002 Auxiliary Boilers 99 

MMBtu/Hr

0.001 lb/MMBtu Low Sulfur Fuel 

and Good 

Combustion 

Practices

NV-0047 NELLIS AIR 

FORCE BASE

2/26/2008 Boiler/Heater Unknown 0.0015 lb/MMBtu Use of PipelineQuality natural 

gas

AZ-0049 LA PAZ 

GENERATING 

FACILITY

9/4/2003 Auxiliary Boilers 55.34 

MMBtu/Hr

0.0025 lb/MMBtu None

LA-0174 PORT 

HUDSON 

OPERATIONS

1/25/2002 Power Boilers No.2 65.5 

MMBtu/Hr

0.004 lb/MMBtu Firing Natural 

Gas

IN-0085 PSEG 

LAWRENCEBU

RG ENERGY 

FACILITY

6/7/2001 Auxiliary Boilers 124.6 

MMBtu/Hr

0.006 lb/MMBtu Low Sulfur 

Natural gas 9less 

than 0.8% by 

weight)

OH-0257 JACKSON 

COUNTY 

POWER, LLC

12/27/2001 Auxiliary Boilers 76 

MMBtu/Hr

0.006 lb/MMBtu LOW SULFUR 

FUEL, 

NATURAL 

GAS SULFUR 

LIMIT - 2 

GR/100 SCF
St. Joseph Energy Center, LLC Page 45 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

The Mankato Energy Center - according to page 9 of 12 in the TSD to the Title V permit for this 

facility, the Permittee reported a manufacturer's SO2 emissions rate of 0.0012 lb/MMBtu for 

natural gas but this doesn't coincide with the 0.8 gr S/100scf, so the 0.0022409 lb/MMBtu value 

was used in place of 0.012 lb/MMBtu. (http://www.pca.state.mn.us/index.php/viewdocument.html?gid=1402). The Nellis Air Force Base SO2 limit is for 125 regulated and 142 

exempt units, including boilers and other heaters, at this facility. Therefore, this limit it is not 

comparable to the auxiliary boiler proposed for SJEC. The VA Power - Possum Point, according 

to the Title V permit for this facility, has an approved fuel for the auxiliary boiler is guaranteed at

0.3 gr S/100 dscf. The natural gas supplier for SJEC cannot provide a sulfur content guarantee 

at this level. IDEM is aware that some vendors have guaranteed emission factors to control 

similar processes for other proposed auxiliary boilers. However, BACT limitations do not 

necessarily need to reflect the highest possible emission factors achievable by the technology on

which the emission limitation is based. The permitting authority has discretion to base the 

emission limitation on an emission factor that is somewhat lower than the optimal level, which can 

be achieved by the emission unit consistently.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for SO2 emissions from the proposed Auxiliary 

Boilers, identified as B001-B002:

The SO2 emissions from the Auxiliary Boilers, identified as B001-B002 shall not exceed 0.0022 

lb/MMBtu and 0.176 lbs/hr, each, based on a 3-hr average through the use of fuel specification. 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for SO2 for the Auxiliary Boilers, identified as B001-B002.

The SO2 emissions from the Auxiliary Boilers, identified as B001-B002 shall not exceed 0.0022 

lb/MMBtu and 0.176 lbs/hr, each, based on a 3-hr average through the use of fuel specification. 

Volatile Organic Compounds (VOCs) BACT - Auxiliary Boilers B001 - B002

Step 1: Identify Potential Control Technologies

Emissions of Volatile Organic Compounds (VOCs) are generally controlled by oxidation. 

Oxidation technologies include regenerative thermal oxidation, catalytic oxidation, and flares.

(a) Regenerative thermal oxidation; 

(b) Recuperative thermal oxidizer

(c) Catalytic oxidation; 

(d) Good Combustion Controls; and

(e) Flares.

If add-on control technology is not feasible, an alternate method of control may be implemented. 

Step 2: Eliminate Technically Infeasible Options

Regenerative Thermal Oxidizers

The thermal oxidizer has a high temperature combustion chamber that is maintained by a 

combination of auxiliary fuel, waste gas compounds, and supplemental air added when 
St. Joseph Energy Center, LLC Page 46 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

necessary. This technology is typically applied for destruction of organic vapors, nevertheless it is 

also considered as a technology for controlling VOCs emissions. Upon passing through the 

flame, the waste gas containing VOCs is heated. The mixture continues to react as it flows 

through the combustion chamber.

The required level of VOCs destruction of the waste gas that must be achieved within the time 

that it spends in the thermal combustion chamber dictates the reactor temperature. The shorter 

the residence time, the higher the reactor temperature must be. Most thermal units are designed 

to provide no more than 1 second of residence time to the waste gas with typical temperatures of 

1,200 to 2,000o

F. Once the unit is designed and built, the residence time is not easily changed, 

so that the required reaction temperature becomes a function of the particular gaseous species 

and the desired level of control. 

A Regenerative Thermal Oxidizer incorporates heat recovery and greater thermal efficiency

through the use of direct contact heat exchangers constructed of a ceramic material that can 

tolerate the high temperatures needed to achieve ignition of the waste stream.

The inlet gas first passes through a hot ceramic bed thereby heating the stream (and cooling the 

bed) to its ignition temperature. The hot gases then react (releasing energy) in the combustion 

chamber and while passing through another ceramic bed, thereby heating it. The process flows 

are then switched, feeding the inlet stream to the hot bed. This cyclic process affords very high 

energy recovery (up to 95%). The higher capital costs associated with these high-performance 

heat exchangers and combustion chambers may be offset by the increased auxiliary fuel savings 

to make such a system economical. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a regenerative thermal oxidizer is a technically feasible option for the Auxiliary Boilers

at this source.

Recuperative Thermal Oxidizers

This control technology oxidizes combustible materials by raising the temperature of the material 

above the auto-ignition point in the presence of oxygen and maintaining the high temperature for 

sufficient time to complete combustion. The operating temperature ranges from 1,100 - 1.200o

F

and the waste stream inlet pollutants concentration is as low as 500-50,000 scfm. 

Additional fuel is required to reach the ignition temperature of the waste gas stream. Oxidizers 

are not recommended for controlling gases with sulfur containing compounds because of the 

formation of highly corrosive acid gases. Thermal oxidizers do not reduce emissions of VOC from 

properly operated natural gas combustion units without the use of a catalyst.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a recuperative thermal oxidizer is not a technically feasible option for the Auxiliary 

Boilers at this source.

Catalytic Oxidizers

Catalytic oxidation is also a widely used control technology to control pollutants where the waste 

gas is passed through a flame area and then through a catalyst bed for complete combustion of 

the waste in the gas. This technology is typically applied for destruction of organic vapors, 

nevertheless it is considered as a technology for controlling VOCs emissions. A catalyst is an 

element or compound that speeds up a reaction at lower temperatures compared to thermal 

oxidation without undergoing change itself. Catalytic oxidizers operate at 600°F to 800°F and 

approximately require 1.5 to 2.0 ft3 of catalyst per 1000 standard ft3 per gas flow rate. 

Similar to thermal incineration; waste stream is heated by a flame and then passes through a 

catalyst bed that increases the oxidation rate more quickly and at lower temperatures. Typical 
St. Joseph Energy Center, LLC Page 47 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

waste stream inlet flow rate ranges from 700 - 50,000 scfm and waste stream inlet pollutant 

concentration is as low as 1ppmv.

Oxidation efficiency depends on exhaust flow rate and composition. Residence time required for 

oxidation to take place at the active sites of the catalyst may not be achieved if exhaust flow rates 

exceed design specifications. Also, sulfur and other compounds may foul the catalyst, leading to 

decreased efficiency.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a catalytic oxidizer is a technically feasible option for Auxiliary Boilers at this source.

Flare

Although the VOC concentration is very low, the stream flow rate is very high. The low heating 

value of the stream is too low for flaring. As there are insufficient organics in this vent stream to 

support combustion, use of a flare would require a significant addition of supplementary fuel. 

Therefore, a secondary impact of the use of flare for this stream would be the creation of 

additional emissions from burning supplemental fuel, including NOx. Flares have not been 

utilized or demonstrated as a control device for VOCs from this type of high-volume process 

stream. In addition, the flare would have no additional control versus the thermal oxidizers. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flare is not a technically feasible option for the Auxiliary Boilers at this source

Good Combustion Controls

Good combustion controls is a continued operation of the Boilers at the appropriate oxygen range 

and temperature to promote complete combustion and minimize VOC formation. Because VOC is 

essentially a by-product of incomplete or inefficient combustion, combustion control constitutes 

the primary mode of reduction of VOC emissions. This type of control is appropriate for any type 

of fuel combustion source. Combustion process controls involve combustion chamber designs 

and operating practices that improve the oxidation process and minimize incomplete combustion. 

VOC emissions result from the incomplete combustion of carbon and organic compounds. 

Factors affecting VOC emissions include firing temperatures, residence time in the combustion

zone and combustion chamber mixing characteristics.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Good Combustion Controls is a technically feasible option for the Auxiliary Boilers at 

this source

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Oxidation Catalyst - (20-40% destruction efficiency)

(2) Good Combustion Controls

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed VOCs BACT determination along with the existing VOCs

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method
St. Joseph Energy Center, LLC Page 48 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy 

Center -

proposed

Proposed Auxiliary Boilers 

(B001 and B002)

80 

MMBtu/hr

VOCs: 0.005 

lb/MMBtu and

0.4 lb/hr, each, 

based on 3-hr 

average

Good 

Combustion 

Practices 

NC-0101 FORSYTH 

ENERGY 

PLANT

9/29/2005 AUXILIARY 

BOILER

110.2 

MMBtu/hr

0.59 lb/hr and 

0.005 MMBtu/hr, 

based on 3-hr avg

LOW NOX

BURNERS, 

GOOD 

COMBUSTION 

CONTROL 

AND 

NATURAL 

GAS ONLY

OR-0046 TURNER 

ENERGY 

CENTER, LLC

1/6/2005 Auxiliary Boilers 417,904

MMBtu/yr

0.0044 lb/MMBtu 

based on 3-hr block

Oxidation 

Catalyst

VA-0270 VCU EAST 

PLANT

3/31/2003 BOILER NATURAL 

GAS

150 

MMBtu/hr

2.1 lb/hr and 0.014 

MMBtu/hr

GOOD 

COMBUSTION 

PRACTICES.

VA-0270 VCU EAST 

PLANT

3/31/2003 BOILER NATURAL 

GAS

150.6 

MMBtu/hr

2.1 lb/hr and 0.014 

MMBtu/hr

GOOD 

COMBUSTION

PRACTICES.

LA-0246 VALERO ST. 

CHARLES 

REFINDERY

7/6/2011 EQT0323 - Boiler 

401F

99 

MMBtu/hr

0.53 lb/hr and 

0.005 MMBtu/hr

Proper design 

and operation, 

good 

combustion 

practices and 

gaseous fuels

IN-0085 PSEG 

LAWRENCEB

URG 

ENERGY 

FACILITY

6/7/2001 Auxiliary Boilers 124.6

MMBtu/hr

0.0054 lb/MMBtu Good 

Combustion 

Practices and 

Natural Gas 

only

The use of oxidation catalyst is economically infeasible as referenced in the cost analysis. The 

emission limits in Turner Energy Center, LLC which is 0.0044 lb/MMBtu has never been tested 

because the facility was never constructed and this was confirmed by the Oregon DEQ. 

Therefore, the proposed limit of 0.005 lb/MMBtu is consistent with the most stringent limits for this 

type of operation.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for PM, PM10 and PM2.5 emissions from the proposed 

Auxiliary Boilers (B001-B002):

The VOC emissions from the Auxiliary Boilers, identified as B001-B002 shall not exceed 0.005 

lb/MMBtu and 0.4 lbs/hr, each, based on a 3-hr average period through the use of good combustion 

practices. 
St. Joseph Energy Center, LLC Page 49 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for VOC for the Auxiliary Boilers (B001-B002).

The VOC emissions from the Auxiliary Boilers, identified as B001-B002 shall not exceed 0.005 

lb/MMBtu and 0.4 lbs/hr, each, based on a 3-hr average period through the use of good combustion 

practices. 

Nitrogen Oxide (NOx) BACT - Auxiliary Boilers B001 - B002

Step 1: Identify Potential Control Technologies

The nitrogen oxide (NOx) emissions can be controlled by the following methods: 

(a) Selective Catalytic Reduction (SCR)

(b) Selective Non-Catalytic Reduction (SNCR)

(c) SCONOx Catalytic Absorption System

(d) Ultra-Low NOx Burners (LNB)

Add-on control technologies and combustion control approaches are discussed below.

Step 2: Eliminate Technically Infeasible Options

Selective Catalytic Reduction (SCR)

Selective Catalytic Reduction (SCR) process involves the mixing of anhydrous or aqueous 

ammonia vapor with flue gas and passing the mixture through a catalytic reactor to reduce NOX

to water and N2. Under optimal conditions, SCR has a removal efficiency up to 90% when used 

on steady state processes. The efficiency of removal will be reduced for processes that are not 

stable or require frequent changes in the mode of operation.

The most important factor affecting SCR efficiency is temperature. SCR can operate in a flue gas 

window ranging from 480°F to 800°F, although the optimum temperature range depends on the 

type of catalyst and the flue gas composition. In this particular service, the minimum target 

temperature is approximately 750 F. Temperature below the optimum, decrease catalyst activity 

and allow NH3 to slip through; above the optimum range, ammonia will oxidize to form additional 

NOx. SCR efficiency is also largely dependent on the stoichiometric molar ratio of NH3:NOx; 

variation of the ideal 1:1 ratio to 0.5:1 ratio can reduce the removal efficiency to 50%.

Unreacted reagent may form ammonium sulfates which may plug or corrode downstream 

equipment. Particulate-laden streams may blind the catalyst and may necessitate the application 

of a sootblower.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

selective catalytic reduction (SCR) is a technically feasible option for the Auxiliary Boilers at this 

source.

Selective Non-Catalytic Reduction (SNCR)

With selective non-catalytic reduction (SNCR), NOX is selectively removed by the injection of 

ammonia or urea into the flue gas at an appropriate temperature window of 1600°F to 2100°F 

and without employing a catalyst. Similar to SCR without a catalyst bed, the injected chemicals 

selectively reduce the NOX to molecular nitrogen and water. 
St. Joseph Energy Center, LLC Page 50 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

This approach avoids the problem related to catalyst fouling but the temperature window and 

reagent mixing residence time is critical for conducting the necessary chemical reaction. At the 

proper temperature, urea decomposes to produce ammonia which is responsible for NOX

reduction. At a higher temperature, the rate of a competing reaction for the direct oxidation of 

ammonia that actually forms NOx becomes significant. At a lower temperature, the rates of NOX

reduction reactions become too slow resulting in urea slip (i.e. emissions of unreacted urea).

Optimal implementation of SNCR requires the employment of an injection system that can 

accomplish thorough reagent/gas mixing within the temperature window while accommodating 

spatial and production rate temperature variability in the gas stream. The attainment of maximum 

NOx control performance therefore requires that the source exhibit a favorable opportunity for the 

application of this technology relative to the location of the reaction temperature range.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

selective non-catalytic reduction (SNCR) is a technically feasible option for the Auxiliary Boilers at 

this source.

Low NOx Burner (LNB)

Using LNB can reduce formation of NOx through careful control of the fuel-air mixture during 

combustion. Control techniques used in LNBs includes staged air, and fuel, as well as other 

methods that effectively lower the flame temperature. In the drive to reduce NOx emissions, NOx 

reduction techniques were implemented to lower peak flame temperature.

The ULNBs are specially designed pieces of combustion equipment that reduce NOx formation 

through careful control of the fuel-air mixture during combustion. In a staged air combustion LNB, 

either air or fuel is added downstream of the primary combustion zone. Depending on which of 

these NOx reduction techniques is used, LNBs with staged combustion are subdivided into 

staged air burners and staged fuel burners. 

Experience suggests that significant reduction in NOx emissions can be realized using LNBs. The 

U.S. EPA reports that LNBs have achieved reduction up to 80%, but actual reduction depends on 

the type of fuel and varies considerably from one burner installation to another. Typical reductions 

range from 40% - 50% but under certain conditions, higher reductions are possible especially 

when another NOx reduction technique is used in conjunction with LNBs.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of low NOx burners is a technically feasible option for the Auxiliary Boilers at this source.

SCONOx Catalytic Absorption System

SCONOx Catalytic Absorption System utilizes a single catalyst to remove NOX, CO, and VOC 

through oxidation. Now operating as EmeraChem, the current version of the technology is now 

marketed as EMX. The Operating Temperature ranges from 300 - 700 °F. The SCONOX Catalyst 

is sensitive to contamination by sulfur, so it must be used in conjunction with the SCOSOX

catalyst, which favors sulfur compound absorption. This control technology is not listed in RBLC 

for the control of NOX emissions from auxiliary boilers. Technology has only been demonstrated 

on units ranging from 5 to 45 MW.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

selective SCONOx Catalytic Absorption System is not a technically feasible option for the 

Auxiliary Boilers at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Selective Catalytic Reduction — (50-90% NOx Reduction)

(2) Selective Non-catalytic Reduction — (40-60% NOx Reduction)
St. Joseph Energy Center, LLC Page 51 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(3) Low NOx Burner (LNB) — (40%-50% NOx Reduction)

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed NOx BACT determination along with the existing NOx

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy 

Center -

proposed

Proposed Auxiliary Boilers 

(B001 and B002)

80 

MMBtu/hr

NOx: 0.032

lb/MMBtu and 

2.56 pounds 

per hour, 

each, based 

on 3-hr 

average

Low NOx 

Burner with 

Flue Gas 

Recirculation

VA-0270 VCU EAST 

PLANT

3/31/2003 BOILER NATURAL 

GAS

150 

MMBtu/hr

0.1 lb/MMBtu GOOD 

COMBUSTION 

PRACTICES. 

LOW NOX

COMBUSTION 

AND FGR. 

CEM SYSTEM.

OH-0310 AMERICAN 

MUNICIPAL

POWER 

GENERATING 

STATION

10/8/2009 AUXILIARY 

BOILER

150 

MMBtu/hr

0.14 lb/MMBtu 

and 21 lb/hr

UNKNOWN

OK-0126 SUNOCO INC 

TULSA 

REFINERY

5/27/2008 Process Heater 53.7 

MMBtu/hr

0.03 

lb/MMBtu

Ultra Low NOx 

Burner 

CA-1148 CELITE 6/11/2007 HEATER-OTHER

PROCESS

50 

MMBtu/hr

0.089 

lb/MMBtu

Ultra Low NOx 

Burner 

NC-0101 FORSYTH 

ENERGY 

PLANT

9/29/2005 AUXILIARY 

BOILER

110.2 

MMBtu/hr

0.137 

lb/MMBtu and 

15.13 lb/hr, 

based on 3-hr 

avg

LOW NOX

BURNERS, 

GOOD 

COMBUSTION 

CONTROL

OR-0046 TURNER 

ENERGY 

CENTER, LLC

1/6/2005 AUXILIARY 

BOILER

417,904 

MMBtu/yr

0.011 

lb/MMBtu, 

based on 3-hr 

block

SELECTIVE 

CATALYTIC 

REDUCTION

ID-0015 J R SIMPLOT 

COMPANY -

DON SIDING 

PLANT

4/5/2004 BOILER, 64 

MMBTU/H

110.2 

MMBtu/hr

0.045 

lb/MMBtu and 

2.88 lb/hr

Low NOx 

Burner

LA-0183 TITANIUM 

DIOXIDE 

FACILITY

11/14/2003 BOILERS, UTILITY, 

D841-1X & D841-2X

135 

MMBtu/hr

0.074 

lb/MMBtu and 

10 lb/hr

Low NOx 

Burner

WI-0204 UWGP - FUEL 

GRADE 

ETHANOL 

8/14/2003 BOILER /OXIDIZER 

( DRYER / 

DISTILLATION), P10

140 

MMBtu/hr

0.095 

lb/MMBtu and 

BOILER / 

BURNER 

DESIGN
St. Joseph Energy Center, LLC Page 52 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control Method

PLANT 10 lb/hr

VA-0270 VCU EAST 

PLANT

3/31/2003 BOILER NATURAL 

GAS (3)

150.6 

MMBtu/hr

15.6 lb/hr and 

0.104 MMBtu/hr

LOW NOX

BURNERS, 

FGR, AND 

GOOD 

OPERATING 

PROCEDURES

CO-0052 ROCKY 

MOUNTAIN 

ENERGY 

CENTER, LLC.

8/11/2002 NATURAL GAS 

FIRED BOILER 

(AUXILIARY 

BOILER)

129 

MMBtu/hr

0.038 

MMBtu/hr

OPERATION 

IS LIMITED TO 

1,900 H/YR. 

LOW NOX

COMBUSTION 

SYSTEM.

TN-0153 WILLIAMS 

REFINING & 

MARKETING, 

L.L.C.

4/3/2002 Heaters (5) 50 

MMBtu/hr

0.03 

lb/MMBtu

None

TN-0153 WILLIAMS 

REFINING & 

MARKETING, 

L.L.C.

4/3/2002 Boiler No.9 95 

MMBtu/hr

0.084 

lb/MMBtu

None

TN-0153 WILLIAMS 

REFINING & 

MARKETING, 

L.L.C.

4/3/2002 CCR 

STABILIZATION 

REBOILER

54 

MMBtu/hr

0.06 

lb/MMBtu

None

LA-0246 VALERO ST. 

CHARLES 

REFINDERY

7/6/2011 EQT0323 - Boiler 

401F

99 

MMBtu/hr

0.084 

lb/MMBtu

Ultra LNB 

and/or CSR

OR-0048 PGE Carty 

Plant

12/24/2009 NATURAL GASFIRED BOILER

91 

MMBtu/hr

0.04 

lb/MMBtu

LOW NOX

BURNERS

IN-0085 PSEG 

LAWRENCEBU

RG ENERGY 

FACILITY

6/7/2001 *Auxiliary Boiler 124.6 

MMBtu/hr

4.5 lb/hr and 

0.049 

lb/MMBtu

Low NOx 

Burners, Natural 

Gas Only

Note: * Not yet constructed.

The use of oxidation catalyst is economically infeasible as referenced in the cost analysis. The 

emission units at Turner Energy Center, LLC which are limited to 0.011 lb/MMBtu have never 

been tested because the facility was never constructed and this was confirmed by the Oregon 

DEQ. The limits for the Williams Refining and Marketing, L.L.C. and Sunoco Inc Tulsa Refinery 

process heaters are not applicable to this project, which includes installation of auxiliary boilers, 

not process heaters. Therefore, the proposed limit of 0.032 lb/MMBtu is consistent with the most 

stringent limits for this type of operation.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for VOC emissions from the proposed Auxiliary 

Boilers, identified as B001-B002:

(1) The NOx emissions from the Auxiliary Boilers, identified as B001-B002 shall be controlled 

by a Low NOx Burner with Flue Gas Recirculation.
St. Joseph Energy Center, LLC Page 53 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(2) The NOx emissions shall be limited to less than 0.032 lb/MMBtu based on a 3-hr 

average period.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for NOx for the Auxiliary Boilers, identified as B001-B002:

(1) The NOx emissions from the Auxiliary Boilers, identified as B001-B002 shall be controlled 

by Low NOx Burners with Flue Gas Recirculation.

(2) The NOx emissions shall not exceed 0.032 lb/MMBtu and 2.56 pounds per hour, each, 

based on a 3-hr average period.

Particulate Matter (PM/PM10/PM2.5) BACT – Firewater Pumps 

Step 1: Identify Potential Control Technologies

Emissions of PM, PM10 and PM2.5 are generally controlled with add-on control equipment 

designed to capture the emissions prior to the time they are exhausted to the atmosphere. In 

cases where the material being emitted is organic, particulate matter may be controlled through a 

combustion process. Generally, PM, PM10 and PM2.5 emissions are controlled through one of the 

following mechanisms:

(1) Catalyzed Diesel Particulate Filter (CDPF);

(2) Good Combustion Practices; and

(3) Usage Limitation.

The choice of which technology is most appropriate for a specific application depends upon 

several factors, including particle size to be collected, particle loading, stack gas flow rate, stack 

gas physical characteristics (e.g., temperature, moisture content, presence of reactive materials), 

and desired collection efficiency.

Step 2: Eliminate Technically Infeasible Options

Catalyzed Diesel Particulate Filter (CDPF)

The particulate matter emissions in exhaust gas is trapped by a ceramic filter and oxidized using 

a metallic catalyst or a base. The operating temperature ranges between 480 - 570°F. The 

exhaust gas temperature must be high enough over an extended period of time to allow for filter 

regeneration. The type of control is not included in RBLC for the control of PM emissions from fire 

pump and emergency engines. EPA determined in the development of NSPS IIII that add-on 

controls are economically infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Catalyzed Diesel Particulate Filter is not an economically feasible option for the 

Firewater Pump Engine at this source.

Good Combustion Practices 

The organic particulate matter emissions are caused through incomplete combustion. When fuel 

and air are not well mixed in the combustion zone, low oxygen regions form in the fuel injection 

plume that cause unburned fuel to pyrolize at the high engine temperature and form soot. Soot 

formation can be minimized by improving the fuel air mixing through enhanced fuel injection 

systems, air management systems, combustion system designs, and pre-mixed diesel 
St. Joseph Energy Center, LLC Page 54 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

combustion. This type of emission control is included in RBLC for the control of particulate

emissions from fire pump and emergency engines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Good Combustion Practices is a technically feasible option for the Firewater Pump 

Engine at this source.

Usage Limitation

Usage limitation involves accepting a limit on the maximum hours of operation on the units, which 

results in lower emissions. This is included in RBLC for the control of particulate emissions from 

fire pump and emergency engines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Usage Limitation is a technically feasible option for the Firewater Pump Engine at this 

source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

1. Good Combustion Practices.

2. Usage Limitation.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of combustion design control and usage limitation shall be used to reduce the particulate 

emissions from the fire pump engines at this source.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for emergency engines. All data in the table 

is based on the information obtained from the permit application submitted by St. Joseph Energy 

Center, LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of 

permits available at the websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating (TPH) Limitation Control 

Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy 

Center -

proposed

Proposed Firewater Pump 

Engines

371 brake 

horsepower

PM, PM10 and 

PM2.5: 0.15 

g/bhp-hr

Combustion 

Design 

Controls 

and Usage 

Limits

MI-0389 KARN 

WEADOCK 

GENERATING 

COMPLEX

12/29/2009 Fire Pump 525 HP 0.15 g/hp-hr Engine Design 

and Operation. 

15 ppm Sulfur 

Fuel

MI-0390 KARN 

WEADOCK 

GENERATING 

COMPLEX

12/29/2009 Emergency 

Generator

2000 KW 0.2 g/hp-hr Engine Design 

and Operation. 

15 ppm Sulfur 

Fuel

MI-0393 KARN 

WEADOCK 

GENERATING 

COMPLEX

12/29/2009 Fire Booster 

Pump

40 KW 0.4 G/KW-H Engine Design 

and Operation. 

15 ppm Sulfur 

Fuel

MI-0395 KARN 

WEADOCK 

GENERATING 

COMPLEX

12/29/2009 Fire Pump 305 KW 0.2 g/hp-hr Engine Design 

and Operation. 

15 ppm Sulfur 

Fuel
St. Joseph Energy Center, LLC Page 55 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating (TPH) Limitation Control 

Method

ID-0018 LANGLEY 

GULCH 

POWER PLANT

6/25/2010 Emergency 

Generator Engine

750 KW 0.2 G/KW-H Tier 2 EngineBased on 

Good 

Combustion 

Practices

ID-0018 LANGLEY 

GULCH 

POWER PLANT

6/25/2010 Fire Pump Engine 235 KW 0.2 G/KW-H Tier 2 EngineBased on 

Good 

Combustion 

Practices

FL-0322 SWEET 

SORGHUM-TOETHANOL 

ADVANCED 

BIOREFINERY

12/23/2010 Emergency 

Generators

2682 HP 0.2 G/KW-H None

FL-0322 SWEET 

SORGHUM-TOETHANOL 

ADVANCED 

BIOREFINERY

12/23/2010 Emergency 

Generators

600 HP 0.15 g/hp-hr None

FL-0324 PALM BEACH 

RENEWABLE 

ENERGY PARK

12/23/2010 Emergency 

Generators

250 KW 0.2 G/KW-H Use inherently 

clean ultra low 

sulfur distillate 

(ULSD) fuel oil 

and GCP & 

demonstrate 

Compliance in 

accordance 

with the 

procedure 

given in 40 

CFR 60, 

Subpart IIII

FL-0324 PALM BEACH 

RENEWABLE 

ENERGY PARK

12/23/2010 Emergency diesel 

Firewater Pump 

engines

250 HP 0.15 g/hp-hr Demonstrate 

Compliance in 

accordance 

with the 

procedure 

given in 40 

CFR 60, 

Subpart IIII

As shown in the above table, a proposed limit of 0.15 g/bhp-hr, which is equivalent to 0.20 g/kWhr, is consistent with the most stringent limits contained in the RBLC.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Fire Pump 

Engines:

(1) The PM, PM10 and PM2.5 emissions from the Firewater Pump Engines shall not exceed

0.15 g/hp-hr through the use of combustion design control and usage limitation. 

(2) The Fire Pumps shall not exceed 500 hours per year of, each.
St. Joseph Energy Center, LLC Page 56 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for the Fire Pump Engines.

(1) The PM, PM10 and PM2.5 emissions from the Firewater Pump Engines shall not exceed 

0.15 g/hp-hr through the use of combustion design control and usage limitation. 

(2) The Fire Pump shall not exceed 500 hours per year, each.

Carbon Monoxide (CO) BACT – Firewater Pumps 

Step 1: Identify Potential Control Technologies

Emissions of carbon monoxide (CO) are generally controlled by oxidation. Oxidation technologies 

include:

(a) Regenerative thermal oxidation; 

(b) Recuperative thermal oxidation; 

(c) Catalytic oxidation; 

(d) Combustion Design Controls; and

(e) Flares

(f) Usage Limitations

Step 2: Eliminate Technically Infeasible Options

Regenerative Thermal Oxidizers

The thermal oxidizer has a high temperature combustion chamber that is maintained by a 

combination of auxiliary fuel, waste gas compounds, and supplemental air added when 

necessary. This technology is typically applied for destruction of organic vapors, nevertheless it is 

also considered as a technology for controlling CO emissions. Upon passing through the flame, 

the waste gas containing CO is heated. The mixture continues to react as it flows through the 

combustion chamber.

The required level of CO destruction of the waste gas that must be achieved within the time that it 

spends in the thermal combustion chamber dictates the reactor temperature. The shorter the 

residence time, the higher the reactor temperature must be. Most thermal units are designed to 

provide no more than 1 second of residence time to the waste gas with typical temperatures of 

1,200 to 2,000o

F. Once the unit is designed and built, the residence time is not easily changed, 

so that the required reaction temperature becomes a function of the particular gaseous species 

and the desired level of control. 

A Regenerative Thermal Oxidizer incorporates heat recovery and greater thermal efficiency 

through the use of direct contact heat exchangers constructed of a ceramic material that can 

tolerate the high temperatures needed to achieve ignition of the waste stream.

The inlet gas first passes through a hot ceramic bed thereby heating the stream (and cooling the 

bed) to its ignition temperature. The hot gases then react (releasing energy) in the combustion 

chamber and while passing through another ceramic bed, thereby heating it. The process flows 
St. Joseph Energy Center, LLC Page 57 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

are then switched, feeding the inlet stream to the hot bed. This cyclic process affords very high 

energy recovery (up to 95%). The higher capital costs associated with these high-performance 

heat exchangers and combustion chambers may be offset by the increased auxiliary fuel savings 

to make such a system economical. 

This control is not included in RBLC for the control of CO emissions from fire pump & emergency 

engines. EPA determined in the development of NSPS IIII that add-on controls are economically 

infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a regenerative thermal oxidizer is not a technically feasible option for the Firewater

Pump Engines at this source.

Recuperative Thermal Oxidizers

This control technology oxidizes combustible materials by raising the temperature of the material 

above the auto-ignition point in the presence of oxygen and maintaining the high temperature for 

sufficient time to complete combustion. The operating temperature ranges from 1,100 - 1.200o

F

and the waste stream inlet pollutants concentration is as low as 500-50,000 scfm.

Additional fuel is required to reach the ignition temperature of the waste gas stream. Oxidizers 

are not recommended for controlling gases with sulfur containing compounds because of the 

formation of highly corrosive acid gases. Thermal oxidizers do not reduce emissions of CO from 

properly operated natural gas combustion units without the use of a catalyst.

This control is not included in RBLC for the control of CO emissions from fire pump & emergency 

engines. EPA determined in the development of NSPS IIII that add-on controls are economically 

infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a recuperative thermal oxidizer is not a technically feasible option for the Firewater

Pump Engines at this source.

Catalytic Oxidizers

Catalytic oxidation is also a widely used control technology to control pollutants where the waste 

gas is passed through a flame area and then through a catalyst bed for complete combustion of 

the waste in the gas. This technology is typically applied for destruction of organic vapors, 

nevertheless it is considered as a technology for controlling CO emissions. A catalyst is an 

element or compound that speeds up a reaction at lower temperatures compared to thermal 

oxidation without undergoing change itself. Catalytic oxidizers operate at 600°F to 800°F and 

approximately require 1.5 to 2.0 ft3 of catalyst per 1000 standard ft3 per gas flow rate. 

Similar to thermal incineration; waste stream is heated by a flame and then passes through a 

catalyst bed that increases the oxidation rate more quickly and at lower temperatures. Typical 

waste stream inlet flow rate ranges from 700 - 50,000 scfm and waste stream inlet pollutant 

concentration is as low as 1ppmv.

Oxidation efficiency depends on exhaust flow rate and composition. Residence time required for 

oxidation to take place at the active sites of the catalyst may not be achieved if exhaust flow rates 

exceed design specifications. Also, sulfur and other compounds may foul the catalyst, leading to 

decreased efficiency. This control is not included in RBLC for the control of CO emissions from 

fire pump & emergency engines. EPA determined in the development of NSPS IIII that add-on 

controls are economically infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a catalytic oxidizer is not a technically feasible option for Firewater Pump Engines at 

this source.
St. Joseph Energy Center, LLC Page 58 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Flare

Although the CO concentration is very low, the stream flow rate is very high. The low heating 

value of the stream is too low for flaring. As there are insufficient organics in this vent stream to 

support combustion, use of a flare would require a significant addition of supplementary fuel. 

Therefore, a secondary impact of the use of flare for this stream would be the creation of 

additional emissions from burning supplemental fuel, including NOx. Flares have not been 

utilized or demonstrated as a control device for CO from this type of high-volume process stream. 

In addition, the flare would have no additional control versus the thermal oxidizers. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flare is not a technically feasible option for the Firewater Pump Engines at this 

source.

Combustion Design Controls

CO emissions are caused through incomplete combustion. When fuel and air are not well mixed 

in the combustion zone, low oxygen regions form where fuel will partially combust, resulting in CO 

and unburned hydrocarbons that exit with the exhaust. CO formation can be minimized by 

improving the fuel air mixing through enhanced fuel injection systems, air management systems, 

combustion system designs, and pre-mixed diesel combustion. This type of control is included in 

RBLC for the control of CO emissions from fire pump & emergency engines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Good Combustion Controls is a technically feasible option for the Firewater Pump

Engines at this source.

Usage Limitation 

Usage limitation involves accepting a limit on the maximum hours of operation on the units, which 

results in lower emissions. This is included in RBLC for the control of CO emissions from fire 

pump and emergency engines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Usage Limitation is a technically feasible option for the Firewater Pump Engine at this 

source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of combustion design control and usage limitation shall be used to reduce the CO 

emissions from the firewater pump engines at this source.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed CO BACT determination along with the existing CO BACT 

determinations for emergency engines. All data in the table is based on the information obtained 

from the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating (TPH) Limitation Control Method

Draft Permit 

No. 141-

31003-

00579

St. Joseph 

Energy 

Center -

proposed

Proposed Firewater Pump 

Engines

371 brake 

horsepower

CO: 2.6 

g/bhp-hr

Combustion 

Design 

Controls and 

Usage Limits
St. Joseph Energy Center, LLC Page 59 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating (TPH) Limitation Control Method

Proposed

Limit

MI-0389 KARN 

WEADOCK 

GENERATING 

COMPLEX

12/29/2009 Fire Pump 525 HP 2.6 g/hp-hr Engine design 

and Operation. 

15 ppm Sulfur 

fuel

MI-0390 KARN 

WEADOCK 

GENERATING 

COMPLEX

12/29/2009 Emergency 

Generators

2000 KW 3.5 G/KW-H Engine design 

and Operation. 

15 ppm Sulfur 

fuel

MI-0391 KARN 

WEADOCK 

GENERATING 

COMPLEX

12/29/2009 Fire Booster 

Pump

40 KW 5 G/KW-H Engine design 

and Operation. 

15 ppm Sulfur 

fuel

MI-0392 KARN 

WEADOCK 

GENERATING 

COMPLEX

12/29/2009 Flue gas 

Desulfurization 

Quench Pump

305 KW 3.5 G/KW-H Engine design 

and Operation. 

15 ppm Sulfur 

fuel

NV-0049 HARRAH'S 

OPERATING 

COMPANY, 

INC.

8/20/2009 Large Internal 

Combustion 

Engines

1,232 HP 0.006 lb/HP-H The unit is 

equipped with a 

Turborcharger

NV-0050 HARRAH'S 

OPERATING 

COMPANY, 

INC.

8/20/2009 Small Internal 

Combustion 

Engines

536 HP 0.007 lb/HP-H The unit is 

equipped with a 

Turborcharger

NV-0052 MGM MIRAGE 11/30/2009 Small Internal 

Combustion 

Engines

350 HP 0.007 lb/HP-H Turborcharger 

and Good 

Combustion 

Practices

LA-0229 SHINTECH 

PLAQUEMINE 

PLANT 2

7/10/2008 Emergency IC 

Engines

< 600 HP 0.007 lb/HP-H Follow 

Manufacture's 

Specifications

As shown in the above table, a proposed limit of 2.6 g/bhp-hr, which is equivalent to 3.5 g/kW-hr 

and 0.006 lb/bhp-hr, is consistent with the most stringent limits contained in the RBLC.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for CO emissions from the proposed Fire Pump 

Engines:

(1) The CO emissions from the Firewater Pump Engines shall not exceed 2.6 g/hp-hr 

through the use of combustion design controls and usage limitation. 

(2) The Fire Pumps shall not exceed 500 hours per year, each.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for CO emissions for the Fire Pump Engines.

(1) The CO emissions from the Firewater Pump Engines shall not exceed 2.6 g/hp-hr 

through the use of combustion design control and usage limitation. 

(2) The Fire Pumps shall not exceed 500 hours per year of, each.
St. Joseph Energy Center, LLC Page 60 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Sulfur Dioxide (SO2) BACT - Firewater Pumps 

Step 1: Identify Potential Control Technologies

Sulfur Dioxide (SO2) emissions result from the oxidation of fuel-bound sulfur, with emissions 

dependent upon the sulfur content of the fuel. Sulfur Dioxide (SO2) emissions are generally 

controlled with add-on control equipment designed to capture the emissions prior to the time they 

are exhausted to the atmosphere. 

(a) Fuel Specification; and

(b) Good Combustion Practices.

(c) Usage Limitation.

Add-on control measures are generally based upon exposure of sulfur dioxide molecules to 

reagents that react with sulfur dioxide to form a sulfate molecule that can then be captured as a 

particulate. Sulfur dioxide control systems vary in reagent utilized to react with sulfur dioxide, the 

manner in which the reagent is exposed to sulfur dioxide, and the manner in which sulfate 

molecules are captured.

Step 2: Eliminate Technically Infeasible Options

Fuel Specifications 

Combusting only clean natural gas, which has an inherently low sulfur content, rather than higher 

sulfur content fuels alone or in combination with natural gas has a very low potential for 

generating SO2 emissions. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Fuel Specifications is a technically feasible option for the Firewater pumps at this 

source.

Good Combustion Practices 

Good combustion practices as well as operation and maintenance of the fire pumps to keep them 

in good working order per the manufacturer's specifications will minimize SO2 emissions. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Good Combustion Practices is a technically feasible option for the Firewater Pumps at 

this source.

Usage Limitation 

Usage limitation involves accepting a limit on the maximum hours of operation on the units, which 

results in lower emissions. This is included in RBLC for the control of SO2 emissions from fire 

pump and emergency engines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Usage Limitation is a technically feasible option for the Firewater Pump Engine at this 

source.
St. Joseph Energy Center, LLC Page 61 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of ultra low sulfur distillate (ULSD) (Fuel Specification and Good combustion practices) 

and usage limitation shall be used to reduce the SO2 emissions from the firewater pump engines 

at this source.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed SO2 BACT determination along with the existing SO2

BACT determinations for emergency pumps. All data in the table is based on the information 

obtained from the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating (TPH) Limitation Control 

Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy Center -

proposed

Proposed Firewater

Pump Engines

371 brake 

horsepower

SO2: 0.0015% 

sulfur diesel 

fuel and 

0.043 lbs/hr

ULSD and 

Usage 

Limits

OH-0252 DUKE ENERGY 

HANGING ROCK 

ENERGY 

FACILITY

12/28/2004 Fire Water 

Pump 

265 HP 0.1 lb/hr Low Sulfur 

Fuel

OK-0129 CHOUTEAU 

POWER PLANT

1/23/2009 Emergency 

Fire Pump

267 HP 0.11 lb/hr Low Sulfur 

Fuel

OH-0281 RUMPKE 

SANITARY 

LANDFILL, INC

6/10/2004 Portable Engines 0.58 MMBtu/hr 0.17 lb/hr None

LA-0122 MANSFIELD MILL 8/14/2001 Diesel Generator 130 HP 0.26 lb/hr Preventive 

Maintenance

OH-0252 DUKE ENERGY 

HANGING ROCK 

ENERGY 

FACILITY

12/28/2004 Backup 

Generators 

500 KW 0.27 lb/hr Low Sulfur 

Fuel

OK-0090 DUKE ENERGY 

STEPHENS, LLC 

STEPHENS 

ENERGY

3/21/2003 Backup 

Generators, 

Diesel

749 BHP 0.3 lb/hr

(<0.05% S by 

wt)

Use of low 

sulfur diesel 

fuel 

LA-0122 MANSFIELD MILL 8/14/2001 Diesel Engines 152 HP 0.31 lb/hr Preventive 

Maintenance

WI-0227 PORT 

WASHINGTON 

GENERATING 

STATION

10/13/2004 Diesel Engines 

Generator

0.58 MMBtu/hr 0.38 lb/hr

(0.05% wt S)

Low sulfur 

diesel fuel 

OH-0254 DUKE ENERGY 

WASHINGTON 

COUNTY LLC

8/14/2003 Emergency 

diesel-fired 

generator 

600 KW 0.4 lb/hr Low sulfur 

fuel 

combustion 

control

OK-0090 DUKE ENERGY 

STEPHENS, LLC 

STEPHENS 

ENERGY

3/21/2003 Fire Water 

Pump

265 BHP 0.5 lb/hr

(<0.05% S by 

wt)

Use of very 

low sulfur 

diesel fuel 
St. Joseph Energy Center, LLC Page 62 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating (TPH) Limitation Control 

Method

WI-0228 WPS - WESTON 

PLANT

10/19/2004 Diesel Booster 

Pump

265 BHP 0.54 lb/hr

(0.003 WT %)

Fuel Sulfur 

Content Limit 

Good 

Combustion 

practices

SO2 emissions depend entirely on the sulfur content of the fuel. Use of ultra-low sulfur diesel fuel 

(< 0.0015% S) is the most stringent limit for fuel sulfur content in the RBLC.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for SO2 emissions from the proposed Firewater Pump 

Engines:

(1) The SO2 emissions from the Firewater Pump Engines shall not exceed 0.0015 % S and 

0.043 lb/hr through the use of ultra low sulfur distillate (ULSD) and usage limitation. 

(2) The Fire Pumps shall not exceed 500 hours per year, each.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for SO2 emissions for the Fire Pump Engines.

(1) The SO2 emissions from the Firewater Pump Engines shall not exceed 0.0015 % S and 

0.043 lb/hr, each through the use of ultra low sulfur distillate (ULSD) and usage limitation. 

(2) The Fire Pumps shall not exceed 500 hours per year, each.

Volatile Organic Compounds (VOCs) BACT - Firewater Pumps 

Step 1: Identify Potential Control Technologies

Emissions of volatile organic compounds (VOC) are generally controlled by oxidation. Oxidation

technologies include:

(a) Regenerative thermal oxidation; 

(b) Recuperative thermal oxidation; 

(c) Catalytic oxidation; 

(d) Combustion Design Controls; and

(e) Flares.

(f) Usage Limitation

Step 2: Eliminate Technically Infeasible Options

Regenerative Thermal Oxidizers

The thermal oxidizer has a high temperature combustion chamber that is maintained by a 

combination of auxiliary fuel, waste gas compounds, and supplemental air added when 

necessary. This technology is typically applied for destruction of organic vapors, nevertheless it is 
St. Joseph Energy Center, LLC Page 63 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

also considered as a technology for controlling VOC emissions. Upon passing through the flame, 

the waste gas containing VOC is heated. The mixture continues to react as it flows through the 

combustion chamber.

The required level of VOC destruction of the waste gas that must be achieved within the time that 

it spends in the thermal combustion chamber dictates the reactor temperature. The shorter the 

residence time, the higher the reactor temperature must be. Most thermal units are designed to 

provide no more than 1 second of residence time to the waste gas with typical temperatures of 

1,200 to 2,000o

F. Once the unit is designed and built, the residence time is not easily changed, 

so that the required reaction temperature becomes a function of the particular gaseous species 

and the desired level of control. 

A Regenerative Thermal Oxidizer incorporates heat recovery and greater thermal efficiency 

through the use of direct contact heat exchangers constructed of a ceramic material that can 

tolerate the high temperatures needed to achieve ignition of the waste stream.

The inlet gas first passes through a hot ceramic bed thereby heating the stream (and cooling the 

bed) to its ignition temperature. The hot gases then react (releasing energy) in the combustion 

chamber and while passing through another ceramic bed, thereby heating it. The process flows 

are then switched, feeding the inlet stream to the hot bed. This cyclic process affords very high 

energy recovery (up to 95%). The higher capital costs associated with these high-performance 

heat exchangers and combustion chambers may be offset by the increased auxiliary fuel savings 

to make such a system economical. 

This control is not included in RBLC for the control of VOC emissions from fire pump & 

emergency engines. EPA determined in the development of NSPS IIII that add-on controls are 

economically infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a regenerative thermal oxidizer is not a technically feasible option for the Firewater

Pump Engines at this source.

Recuperative Thermal Oxidizers

This control technology oxidizes combustible materials by raising the temperature of the material 

above the auto-ignition point in the presence of oxygen and maintaining the high temperature for 

sufficient time to complete combustion. The operating temperature ranges from 1,100 - 1.200o

F

and the waste stream inlet pollutants concentration is as low as 500-50,000 scfm.

Additional fuel is required to reach the ignition temperature of the waste gas stream. Oxidizers 

are not recommended for controlling gases with sulfur containing compounds because of the 

formation of highly corrosive acid gases. Thermal oxidizers do not reduce emissions of VOC from 

properly operated natural gas combustion units without the use of a catalyst.

This control is not included in RBLC for the control of VOC emissions from fire pump & 

emergency engines. EPA determined in the development of NSPS IIII that add-on controls are 

economically infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a recuperative thermal oxidizer is not a technically feasible option for the Firewater

Pump Engines at this source.

Catalytic Oxidizers

Catalytic oxidation is also a widely used control technology to control pollutants where the waste 

gas is passed through a flame area and then through a catalyst bed for complete combustion of 

the waste in the gas. This technology is typically applied for destruction of organic vapors, 

nevertheless it is considered as a technology for controlling VOC emissions. A catalyst is an 
St. Joseph Energy Center, LLC Page 64 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

element or compound that speeds up a reaction at lower temperatures compared to thermal 

oxidation without undergoing change itself. Catalytic oxidizers operate at 600°F to 800°F and 

approximately require 1.5 to 2.0 ft3 of catalyst per 1000 standard ft3 per gas flow rate. 

Similar to thermal incineration; waste stream is heated by a flame and then passes through a 

catalyst bed that increases the oxidation rate more quickly and at lower temperatures. Typical 

waste stream inlet flow rate ranges from 700 - 50,000 scfm and waste stream inlet pollutant 

concentration is as low as 1ppmv.

Oxidation efficiency depends on exhaust flow rate and composition. Residence time required for 

oxidation to take place at the active sites of the catalyst may not be achieved if exhaust flow rates 

exceed design specifications. Also, sulfur and other compounds may foul the catalyst, leading to 

decreased efficiency. This control is not included in RBLC for the control of VOC emissions from 

fire pump & emergency engines. EPA determined in the development of NSPS IIII that add-on 

controls are economically infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a catalytic oxidizer is not a technically feasible option for Firewater Pump Engines at 

this source.

Flare

Although the VOC concentration is very low, the stream flow rate is very high. The low heating 

value of the stream is too low for flaring. As there are insufficient organics in this vent stream to 

support combustion, use of a flare would require a significant addition of supplementary fuel. 

Therefore, a secondary impact of the use of flare for this stream would be the creation of 

additional emissions from burning supplemental fuel, including NOx. Flares have not been 

utilized or demonstrated as a control device for VOC from this type of high-volume process 

stream. In addition, the flare would have no additional control versus the thermal oxidizers. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that

the use of a flare is not a technically feasible option for the Firewater Pump Engines at this 

source.

Combustion Design Controls

VOC emissions are caused through incomplete combustion. When fuel and air are not well 

mixed in the combustion zone, low oxygen regions form where fuel will partially combust, 

resulting in VOC and unburned hydrocarbons that exit with the exhaust. VOC formation can be 

minimized by improving the fuel air mixing through enhanced fuel injection systems, air 

management systems, combustion system designs, and pre-mixed diesel combustion. This type 

of control is included in RBLC for the control of VOC emissions from fire pump & emergency 

engines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Good Combustion Controls is a technically feasible option for the Firewater Pump

Engines at this source.

Usage Limitation 

Usage limitation involves accepting a limit on the maximum hours of operation on the units, which 

results in lower emissions. This is included in RBLC for the control of VOC emissions from fire 

pump and emergency engines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Usage Limitation is a technically feasible option for the Firewater Pump Engine at this 

source.
St. Joseph Energy Center, LLC Page 65 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of combustion design control and usage limitation shall be used to reduce the VOC 

emissions from the firewater pump engines at this source.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed VOC BACT determination along with the existing VOC 

BACT determinations for emergency engines. All data in the table is based on the information 

obtained from the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating (TPH) Limitation Control 

Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy 

Center -

proposed

Proposed Firewater Pump 

Engines

371 brake 

horsepower

VOC: 0.16

lbs/hr

Combustion 

Design 

Controls and 

Usage Limits

LA-0194 SABINE PASS 

LNG 

TERMINAL

11/24/2004 Fire Water Pump 

Diesel Engines

660 HP 0.07 lb/hr Good 

Combustion 

Practices

LA-0195 SABINE PASS 

LNG 

TERMINAL

11/24/2004 Standby 

Generator Diesel 

Engines

2,220 HP Unknown Complying with 

40 CFR 60 

Subpart IIII

LA-0196 SABINE PASS 

LNG 

TERMINAL

11/24/2004 Fire Water 

Booster Pump 

Diesel Engines

300 HP 0.1 lb/hr Good Engine 

Design & 

Proper 

operating

Practices

NC-0101 FORSYTH 

ENERGY 

PLANT

9/29/2005 IC Engine, 

Emergency 

Generators

11.4 

MMBtu/hr

1.04 lb/hr None

NJ-0043 LIBERTY 

GENERATING 

STATION

3/28/2002 Emergency 

Generators

14.1 

MMBtu/hr

1.4 lb/hr None

NJ-0044 LIBERTY 

GENERATING 

STATION

3/29/2002 Diesel Fire Pump 3.5 MMBtu/hr 1.2 lb/hr None

WI-0228 WPS -

WESTON 

PLANT

10/19/2004 Diesel Booster 

Pump

265 HP 0.7 lb/hr Combustion 

practices, ultra 

low Sulfur 

(0.003 WT %) 

Diesel Fuel Oil 

WI-0229 WPS -

WESTON 

PLANT

10/19/2004 Main Fire Pump

(Diesel Engine)

460 HP 1.14 lb/hr Combustion 

Practices, ultra 

low Sulfur 

(0.003 WT %) 

Diesel Fuel Oil 

WV-0023 MAIDSVILLE 3/2/2004 Emergency 

Generators

1,801 HP 1.12 lb/hr Good 

Combustion 

Practices

WV-0023 MAIDSVILLE 3/2/2004 IC Engines, Fire 

Water Pump

85 HP 0.64 lb/hr Good 

Combustion 

Practices
St. Joseph Energy Center, LLC Page 66 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

The Sabine Pass LNG Terminal Firewater Pump Diesel Engines have NOx emissions equivalent 

to 8.4 g/hp-hr, which are higher than the Tier 3 emissions standards of 3.0 g/hp-hr and therefore 

cannot be used at the proposed facility. As shown in the above table, a proposed limit of 0.16

lb/hr is consistent with the other limits contained in the RBLC.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for VOC emissions from the proposed Firewater

Pump Engines:

(1) The VOC emissions from the Firewater Pump Engines shall not exceed 0.16 lb/hr

through the use of Combustion Design Controls and usage limitation. 

(2) The Fire Pumps shall not exceed 500 hours per year, each.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for VOC emissions for the Fire Pump Engines.

(1) The VOC emissions from the Firewater Pump Engines shall not exceed 0.16 pounds per 

hour, each through the use of Combustion Design Controls and usage limitation. 

(2) The Fire Pumps shall not exceed 500 hours per year, each.

Nitrogen Oxide (NOx) BACT - Firewater Pumps

Step 1: Identify Potential Control Technologies

The nitrogen oxide (NOx) emissions can be controlled by the following methods: 

(a) Selective Catalytic Reduction (SCR)

(b) Selective Non-Catalytic Reduction (SNCR)

(c) Combustion Design Controls

(d) Usage Limitations

Add-on control technologies and combustion control approaches are discussed below.

Step 2: Eliminate Technically Infeasible Options

Selective Catalytic Reduction (SCR)

Selective Catalytic Reduction (SCR) process involves the mixing of anhydrous or aqueous 

ammonia vapor with flue gas and passing the mixture through a catalytic reactor to reduce NOX

to water and N2. Under optimal conditions, SCR has removal efficiency up to 90% when used on 

steady state processes. The efficiency of removal will be reduced for processes that are not 

stable or require frequent changes in the mode of operation.
St. Joseph Energy Center, LLC Page 67 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

The most important factor affecting SCR efficiency is temperature. SCR can operate in a flue gas 

window ranging from 480°F to 800°F, although the optimum temperature range depends on the 

type of catalyst and the flue gas composition. In this particular service, the minimum target 

temperature is approximately 750 F. Temperature below the optimum, decrease catalyst activity 

and allow NH3 to slip through; above the optimum range, ammonia will oxidize to form additional 

NOx. SCR efficiency is also largely dependent on the stoichiometric molar ratio of NH3:NOx; 

variation of the ideal 1:1 ratio to 0.5:1 ratio can reduce the removal efficiency to 50%.

Unreacted reagent may form ammonium sulfates which may plug or corrode downstream 

equipment. Particulate-laden streams may blind the catalyst and may necessitate the application 

of a sootblower.

This control is not included in RBLC for the control of NOx emissions from fire pump & 

emergency engines. EPA determined in the development of NSPS IIII that add-on controls are 

economically infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

selective catalytic reduction (SCR) is not a technically feasible option for the Firewater Pump

Engines at this source.

Selective Non-Catalytic Reduction (SNCR)

With selective non-catalytic reduction (SNCR), NOX is selectively removed by the injection of 

ammonia or urea into the flue gas at an appropriate temperature window of 1600°F to 2100°F 

and without employing a catalyst. Similar to SCR without a catalyst bed, the injected chemicals 

selectively reduce the NOX to molecular nitrogen and water. This approach avoids the problem 

related to catalyst fouling but the temperature window and reagent mixing residence time is 

critical for conducting the necessary chemical reaction. 

At the proper temperature, urea decomposes to produce ammonia which is responsible for NOX

reduction. At a higher temperature, the rate of a competing reaction for the direct oxidation of 

ammonia that actually forms NOx becomes significant. At a lower temperature, the rates of NOX

reduction reactions become too slow resulting in urea slip (i.e. emissions of unreacted urea).

Optimal implementation of SNCR requires the employment of an injection system that can 

accomplish thorough reagent/gas mixing within the temperature window while accommodating 

spatial and production rate temperature variability in the gas stream. The attainment of maximum 

NOx control performance therefore requires that the source exhibit a favorable opportunity for the 

application of this technology relative to the location of the reaction temperature range.

This control is not included in RBLC for the control of NOx emissions from fire pump & 

emergency engines. EPA determined in the development of NSPS IIII that add-on controls are 

economically infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

selective non-catalytic reduction (SNCR) is not a technically feasible option for the Firewater

Pump Engines at this source.

Combustion Design Controls

NOX emissions are caused by oxidation of nitrogen gas in the combustion air during fuel 

combustion. This occurs due to high combustion temperatures and insufficiently mixed air and 

fuel in the cylinder where pockets of excess oxygen occur. These effects can be minimized 

through air-to-fuel ratio control, ignition timing reduction, and exhaust gas recirculation. This type 

of control is included in RBLC for the control of NOX emissions from fire pump & emergency 

engines.
St. Joseph Energy Center, LLC Page 68 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Good Combustion Controls is a technically feasible option for the Firewater Pump

Engines at this source.

Usage Limitation 

Usage limitation involves accepting a limit on the maximum hours of operation on the units, which 

results in lower emissions. This is included in RBLC for the control of NOx emissions from fire 

pump and emergency engines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Usage Limitation is a technically feasible option for the Firewater Pump Engine at this 

source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

1. Good Combustion Controls.

2. Usage Limitation.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of combustion design control and usage limitation shall be used to reduce the NOx 

emissions from the firewater pump engines at this source.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed NOx BACT determination along with the existing NOx 

BACT determinations for emergency pumps. All data in the table is based on the information 

obtained from the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating (TPH) Limitation Control Method

Draft Permit 

No. 141-

31003-00579

Proposed

Limit

St. Joseph 

Energy Center -

proposed

Proposed Firewater

Pump 

Engines

371 brake 

horsepower

NOx + NMNC:

3.0 g/bhp-hr 

Combustion 

Design 

Controls and 

Usage Limits

FL-0322 SWEET 

SORGHUM-TOETHANOL 

ADVANCED 

BIOREFINERY

12/23/2010 Emergency 

Diesel Fire 

Pump

600 HP 3 g/hp-hr None

LA-0194 SABINE PASS 

LNG TERMINAL

11/24/2004 Firewater 

Pump Diesel

660 HP 12.2 lb/hr

(8.4 g/hp-hr)

Good Engine 

Design and 

Proper operating 

Practices

LA-0195 SABINE PASS 

LNG TERMINAL

11/24/2004 Standby 

Generator 

Diesel 

Engines

2,220 HP None Complying with 

40 CFR 60 

Subpart IIII

LA-0196 SABINE PASS 

LNG TERMINAL

11/24/2004 Firewater 

Booster Pump 

Diesel 

Engines

300 HP 3.44 lb/hr

(5.2 g/hp-hr)

Good Engine 

Design and 

Proper operating 

Practices

NV-0049 HARRAH'S 

OPERATING 

8/20/2009 Large Internal 

combustion 

1,232 HP 0.024 lb/hp-hr The unit is 

equipped with a 
St. Joseph Energy Center, LLC Page 69 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating (TPH) Limitation Control Method

COMPANY, INC. Engines Turborcharger

NV-0050 MGM MIRAGE 11/30/2009 Emergency 

Generators

2,206 HP 0.0131 lb/hb-hr Turborcharger 

After Cooling and 

lean Burn 

Technology

ID-0017 POWER COUNTY 

ADVANCED 

ENERGY 

CENTER

2/10/2009 Emergency

Generators

2000 KW None Good 

Combustion 

Practices. EPA 

Certification Per 

NSPS IIII

ID-0018 POWER COUNTY 

ADVANCED 

ENERGY 

CENTER

2/10/2009 Emergency 

Generators

500 KW None Good 

Combustion 

Practices. EPA 

Certification Per 

NSPS IIII

NJ-0043 LIBERTY 

GENERATING 

STATION

3/28/2002 Emergency 

Generators

14.4 MMBtu/hr 26.2 lb/hr

(5.9 g/hp-hr)

None

NJ-0044 LIBERTY 

GENERATING 

STATION

3/29/2002 Diesel Fire 

Pump

3.5 MMBtu/hr 15.5 lb/hr

(14 g/hp-hr)

None

As shown in the above table, a proposed limit of 3.0 g/bhp-hr, which is equivalent to 0.0066 lb/hphr, is consistent with the most stringent limits contained in the RBLC.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for NOx emissions from the proposed Fire Pump 

Engines:

(1) The NOx emissions from the Firewater Pump Engines shall not exceed 3.0 g/bhp-hr for 

NOx + NMHC through the use of Combustion Design Controls and usage limitation. 

(2) The Fire Pumps shall not exceed 500 hours per year of non-emergency operation, each.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for NOx emissions for the Fire Pump Engines.

(1) The NOx emissions from the Firewater Pump Engines shall not exceed 3.0 g/bhp-hr for 

NOx + NMHC through the use of Combustion Design Controls and usage limitation. 

(2) The Fire Pumps shall not exceed 500 hours per year, each.

Particulate Matter (PM/PM10/PM2.5) BACT –Emergency Diesel Generators

Step 1: Identify Potential Control Technologies

Emissions of PM, PM10 and PM2.5 are generally controlled with add-on control equipment 

designed to capture the emissions prior to the time they are exhausted to the atmosphere. In 

cases where the material being emitted is organic, particulate matter may be controlled through a 

combustion process. Generally, PM, PM10 and PM2.5 emissions are controlled through one of the 

following mechanisms:
St. Joseph Energy Center, LLC Page 70 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(1) Catalyzed Diesel Particulate Filter (CDPF);

(2) Good Combustion Practices; and

(3) Usage Limitation.

The choice of which technology is most appropriate for a specific application depends upon 

several factors, including particle size to be collected, particle loading, stack gas flow rate, stack 

gas physical characteristics (e.g., temperature, moisture content, presence of reactive materials), 

and desired collection efficiency.

Step 2: Eliminate Technically Infeasible Options

Catalyzed Diesel Particulate Filter (CDPF)

The particulate matter emissions in exhaust gas is trapped by a ceramic filter and oxidized using 

a metallic catalyst or a base. The operating temperature ranges between 480 - 570°F. The 

exhaust gas temperature must be high enough over an extended period of time to allow for filter 

regeneration. The type of control is not included in RBLC for the control of PM emissions from fire 

pump and emergency engines. EPA determined in the development of NSPS IIII that add-on 

controls are economically infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Catalyzed Diesel Particulate Filter is not an economically feasible option for the 

Emergency Diesel Generators at this source.

Good Combustion Practices 

The organic particulate matter emissions are caused through incomplete combustion. When fuel 

and air are not well mixed in the combustion zone, low oxygen regions form in the fuel injection 

plume that cause unburned fuel to pyrolize at the high engine temperature and form soot. Soot 

formation can be minimized by improving the fuel air mixing through enhanced fuel injection 

systems, air management systems, combustion system designs, and pre-mixed diesel 

combustion. This type of emission control is included in RBLC for the control of particulate

emissions from fire pump and emergency engines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Good Combustion Practices is a technically feasible option for the Emergency Diesel 

Generators at this source.

Usage Limitation 

Usage limitation involves accepting a limit on the maximum hours of operation on the units, which 

results in lower emissions. This is included in RBLC for the control of particulate emissions from 

firewater pump and emergency diesel engines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Usage Limitation is a technically feasible option for the Emergency Diesel Generators 

at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of combustion design control and usage limitation shall be used to reduce the particulate 

emissions from the Emergency Diesel Generators at this source.
St. Joseph Energy Center, LLC Page 71 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for emergency engines. All data in the table 

is based on the information obtained from the permit application submitted by St. Joseph Energy 

Center, LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of 

permits available at the websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating (TPH) Limitation Control 

Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy Center

- proposed

Proposed Emergency 

Diesel 

Generators

EG01 & EG02

1,006

horsepower, 

each

PM, PM10 and 

PM2.5: 0.15 

g/bhp-hr

Combustion 

Design 

Controls 

and Usage 

Emergency Limits

Generator

EG03

2,012

horsepower

MI-0389 KARN 

WEADOCK 

GENERATING 

COMPLEX

12/29/2009 Emergency 

Generator

2000 KW 0.2 G/KW-H Engine Design 

and Operation. 

15 ppm Sulfur 

Fuel

ID-0018 LANGLEY 

GULCH POWER 

PLANT

6/25/2010 Emergency 

Generator 

Engine

750 KW 0.2 G/KW-H Tier 2 EngineBased on 

Good 

Combustion 

Practices

FL-0310 SHADY HILLS 

GENERATING 

STATION

1/12/2009 Emergency 

generators

2.5 MW 0.4 g/hp-hr Firing ULSO 

with max. 

Sulfur content 

of 0.0015% by 

WT and Max. 

Hours of 

operation of 

500 hour/yr

MN-0054 MANKATO 

ENERGY 

CENTER

12/4/2003 Large IC 1850 HP 0.07 g/b-hp-hr Good 

Combustion

MN-0054 MANKATO 

ENERGY 

CENTER

12/4/2003 Small IC 290 HP 0.07 g/b-hp-hr Good 

Combustion

MN-0071 FAIRBAULT 

ENERGY PARK

6/5/2007 Emergency 

Generator

1750 KW 0.0004 lb/hp-hr None

MN-0071 FAIRBAULT 

ENERGY PARK

6/5/2007 Emergency 

Generator

1750 KW 0.0007 lb/hp-hr None

OH-0254 DUKE ENERGY 

WASHINGTON 

COUNTY LLC

8/14/2003 Emergency 

diesel fired 

engines 

Generator

600 KW 0.72 lb/hr

(0.41 g/hp-hr)

Low sulfur fuel, 

combustion 

control

OH-0266 UNIVERSITY OF 

CINCINNATI

8/15/2002 Diesel fired 

engines

19.17 MMBtu/hr 0.23 lb/hr

(0.036 g/hp-hr)

None

OK-0129 CHOUTEAU 

POWER PLANT

1/23/2009 Emergency 

Diesel 

Generator

2200 HP 0.72 lb/hr

(0.15 g/hp-hr)

None

WV-0023 MAIDSVILLE 3/2/2004 Emergency 

Generator

1801 HP 1.13 lb/hr

(0.28 g/hp-hr)

Good 

Combustion 

Practices
St. Joseph Energy Center, LLC Page 72 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

The Mankato Energy Center Smal IC Engine limit does not apply as the proposed emission units 

are significantly larger. Also, the Mankato Energy Center Large IC Engine, and the University of 

Cincinnati emission units have NOx emissions of 12.7 g/hp-hr and 7.1 g/hp-hr, respectively, 

which are higher than the Tier 2 emissions standards and therefore cannot be used at the 

proposed facility. As shown in the above table, a proposed limit of 0.15 g/bhp-hr, which is 

equivalent to 0.00033 lb/hp-hr and 0.20 g/kW-hr, is consistent with the other limits contained in 

the RBLC.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Fire Pump 

Engines:

(1) The PM, PM10 and PM2.5 emissions from the Emergency Generators, Identified as EG01, 

EG02 and EG03 shall not exceed 0.15 g/hp-hr, each through the use of combustion 

design control and usage limitation. 

(2) The Emergency Diesel Generators shall not exceed 500 hours per year, each.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for the Emergency Generators.

(1) The PM, PM10 and PM2.5 emissions from the Emergency Diesel Generators, Identified as 

EG01, EG02 and EG03 shall not exceed 0.15 g/hp-hr, each through the use of 

combustion design control and usage limitation. 

(2) The Emergency Diesel Generators shall not exceed 500 hours per year, each.

Carbon Monoxide (CO) BACT –Emergency Diesel Generators

Step 1: Identify Potential Control Technologies

Emissions of carbon monoxide (CO) are generally controlled by oxidation. Oxidation technologies 

include:

(a) Regenerative thermal oxidation; 

(b) Recuperative thermal oxidizer

(c) Catalytic oxidation; 

(d) Combustion Design Controls; and

(e) Flares.

(f) Usage Limitations

Step 2: Eliminate Technically Infeasible Options

Regenerative Thermal Oxidizers

The thermal oxidizer has a high temperature combustion chamber that is maintained by a 

combination of auxiliary fuel, waste gas compounds, and supplemental air added when 

necessary. This technology is typically applied for destruction of organic vapors, nevertheless it is 

also considered as a technology for controlling CO emissions. Upon passing through the flame, 
St. Joseph Energy Center, LLC Page 73 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

the waste gas containing CO is heated. The mixture continues to react as it flows through the 

combustion chamber.

The required level of CO destruction of the waste gas that must be achieved within the time that it 

spends in the thermal combustion chamber dictates the reactor temperature. The shorter the 

residence time, the higher the reactor temperature must be. Most thermal units are designed to 

provide no more than 1 second of residence time to the waste gas with typical temperatures of 

1,200 to 2,000o

F. Once the unit is designed and built, the residence time is not easily changed, 

so that the required reaction temperature becomes a function of the particular gaseous species 

and the desired level of control. 

A Regenerative Thermal Oxidizer incorporates heat recovery and greater thermal efficiency 

through the use of direct contact heat exchangers constructed of a ceramic material that can 

tolerate the high temperatures needed to achieve ignition of the waste stream.

The inlet gas first passes through a hot ceramic bed thereby heating the stream (and cooling the 

bed) to its ignition temperature. The hot gases then react (releasing energy) in the combustion 

chamber and while passing through another ceramic bed, thereby heating it. The process flows 

are then switched, feeding the inlet stream to the hot bed. This cyclic process affords very high 

energy recovery (up to 95%). The higher capital costs associated with these high-performance 

heat exchangers and combustion chambers may be offset by the increased auxiliary fuel savings 

to make such a system economical. 

This control is not included in RBLC for the control of CO emissions from fire pump & emergency 

engines. EPA determined in the development of NSPS IIII that add-on controls are economically 

infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a regenerative thermal oxidizer is not a technically feasible option for the Emergency 

Diesel Generators at this source.

Recuperative Thermal Oxidizers

This control technology oxidizes combustible materials by raising the temperature of the material 

above the auto-ignition point in the presence of oxygen and maintaining the high temperature for 

sufficient time to complete combustion. The operating temperature ranges from 1,100 - 1.200o

F

and the waste stream inlet pollutants concentration is as low as 500-50,000 scfm.

Additional fuel is required to reach the ignition temperature of the waste gas stream. Oxidizers 

are not recommended for controlling gases with sulfur containing compounds because of the 

formation of highly corrosive acid gases. Thermal oxidizers do not reduce emissions of CO from 

properly operated natural gas combustion units without the use of a catalyst.

This control is not included in RBLC for the control of CO emissions from fire pump & emergency 

engines. EPA determined in the development of NSPS IIII that add-on controls are economically 

infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a recuperative thermal oxidizer is not a technically feasible option for the Emergency 

Diesel Generators at this source.

Catalytic Oxidizers

Catalytic oxidation is also a widely used control technology to control pollutants where the waste 

gas is passed through a flame area and then through a catalyst bed for complete combustion of 

the waste in the gas. This technology is typically applied for destruction of organic vapors, 

nevertheless it is considered as a technology for controlling CO emissions. A catalyst is an 

element or compound that speeds up a reaction at lower temperatures compared to thermal 
St. Joseph Energy Center, LLC Page 74 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

oxidation without undergoing change itself. Catalytic oxidizers operate at 600°F to 800°F and 

approximately require 1.5 to 2.0 ft3 of catalyst per 1000 standard ft3 per gas flow rate. 

Similar to thermal incineration; waste stream is heated by a flame and then passes through a 

catalyst bed that increases the oxidation rate more quickly and at lower temperatures. Typical 

waste stream inlet flow rate ranges from 700 - 50,000 scfm and waste stream inlet pollutant 

concentration is as low as 1ppmv.

Oxidation efficiency depends on exhaust flow rate and composition. Residence time required for 

oxidation to take place at the active sites of the catalyst may not be achieved if exhaust flow rates 

exceed design specifications. Also, sulfur and other compounds may foul the catalyst, leading to 

decreased efficiency. This control is not included in RBLC for the control of CO emissions from 

fire pump & emergency engines. EPA determined in the development of NSPS IIII that add-on 

controls are economically infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a catalytic oxidizer is not a technically feasible option for Emergency Diesel Generators

at this source.

Combustion Design Controls

CO emissions are caused through incomplete combustion. When fuel and air are not well mixed 

in the combustion zone, low oxygen regions form where fuel will partially combust, resulting in CO 

and unburned hydrocarbons that exit with the exhaust. CO formation can be minimized by 

improving the fuel air mixing through enhanced fuel injection systems, air management systems, 

combustion system designs, and pre-mixed diesel combustion. This type of control is included in 

RBLC for the control of CO emissions from fire pump & emergency engines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Good Combustion Controls is a technically feasible option for the Emergency Diesel 

Generators at this source

Flare

Although the CO concentration is very low, the stream flow rate is very high. The low heating 

value of the stream is too low for flaring. As there are insufficient organics in this vent stream to 

support combustion, use of a flare would require a significant addition of supplementary fuel. 

Therefore, a secondary impact of the use of flare for this stream would be the creation of 

additional emissions from burning supplemental fuel, including NOx. Flares have not been 

utilized or demonstrated as a control device for CO from this type of high-volume process stream. 

In addition, the flare would have no additional control versus the thermal oxidizers. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flare is not a technically feasible option for the Emergency Diesel Generators at this 

source.

Usage Limitation 

Usage limitation involves accepting a limit on the maximum hours of operation on the units, which 

results in lower emissions. This is included in RBLC for the control of CO emissions from fire 

pump and emergency engines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Usage Limitation is a technically feasible option for the Emergency Diesel Generators

at this source.
St. Joseph Energy Center, LLC Page 75 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of combustion design control and usage limitation shall be used to reduce the CO 

emissions from the Emergency Diesel Generators at this source.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed CO BACT determination along with the existing CO BACT 

determinations for emergency engines. All data in the table is based on the information obtained 

from the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating (TPH) Limitation Control Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy 

Center -

proposed

Proposed Emergency 

Diesel 

Generators

EG01 & EG02

1,006

horsepower, 

each

CO: 2.6 

g/bhp-hr

Combustion 

Design 

Controls and 

Usage Limits

Emergency 

Generator EG03

2,012

horsepower

MI-0389 KARN 

WEADOCK 

GENERATING 

COMPLEX

12/29/2009 Emergency 

Generators

2000 KW 3.5 G/KW-H Engine design 

and Operation. 

15 ppm Sulfur 

fuel

AK-0060 SNAKE RIVER 

POWER PLANT

11/5/2004 Diesel Electric 

Generator

5211 KW 10.5 lb/hr

(0.68 g/hp-hr)

Good 

Combustion 

Practices

MN-0071 FAIRBAULT 

ENERGY PARK

6/5/2007 Emergency 

Generators

1750 KW 0.0055 lb/hp-hr None

FL-0310 SHADY HILLS 

GENERATING 

STATION

1/12/2009 Emergency 

Generators

2.5 MW 8.5 g/hp-hr EPA Certification

ID-0018 LANGLEY 

GULCH 

POWER PLANT

6/25/2010 Emergency 

Generators Engine

750 KW 3.5 g/KW-hr Tier 2 Engine 

Based, Good 

Combustion 

Practices (GCP)

MN-0054 MANKATO 

ENERGY 

CENTER

12/4/2003 IC Engine, Large 1850 HP 1 g/b-hp-hr Good 

Combustion

MN-0054 MANKATO 

ENERGY 

CENTER

12/4/2003 IC Engine, Small 290 HP 0.25 g/b-hp-hr Good 

Combustion

AR-0051 DUKE 

ENERGYJACKSON 

FACILITY

4/1/2002 Generator Diesel 

Fired

671 HP 8.5 g/hp-hr Good Operating 

Practice

WV-0023 MAIDSVILLE 3/2/2004 Emergency 

Generator

1801 HP 8.85 lb/hr

(2.3 g/hp-hr)

Good 

Combustion 

Practices
St. Joseph Energy Center, LLC Page 76 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

The Mankato Energy Center Small IC Engine limit does not apply as the proposed units are 

significantly larger. Also, the Mankato Energy Center Large IC Engine, and the Snake River 

Power Plant units have NOx emissions of 12.7 g/hp-hr and 8.7 g/hp-hr, respectively, which are 

higher than the Tier 2 emissions standards and therefore cannot be used at the proposed facility. 

As shown in the above table, a proposed limit of 2.6 g/bhp-hr, which is equivalent to 3.5 g/kW-hr 

and 0.006 lb/bhp-hr, is consistent with all other limits contained in the RBLC.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for CO emissions from the proposed Emergency 

Diesel Generators, Identified as EG01, EG02 and EG03:

(1) The CO emissions from the Emergency Diesel Generators, Identified as EG01, EG02 

and EG03 shall not exceed 2.6 g/hp-hr, each through the use of combustion design 

controls and usage limitation. 

(2) The Emergency Diesel Generators shall not exceed 500 hours per year, each.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for CO emissions for the Emergency Generators.

(1) The CO emissions from the Emergency Diesel Generators, Identified as EG01, EG02 

and EG03 shall not exceed 2.6 g/hp-hr, each through the use of combustion design 

controls and usage limitation. 

(2) The Emergency Diesel Generators shall not exceed 500 hours per year, each.

Sulfur Dioxide (SO2) BACT - Emergency Diesel Generators

Step 1: Identify Potential Control Technologies

Sulfur Dioxide (SO2) emissions result from the oxidation of fuel-bound sulfur, with emissions 

dependent upon the sulfur content of the fuel. Sulfur Dioxide (SO2) emissions are generally 

controlled with add-on control equipment designed to capture the emissions prior to the time they 

are exhausted to the atmosphere. 

(a) Fuel Specification; and

(b) Good Combustion Practices.

(c) Usage Limitation.

Add-on control measures are generally based upon exposure of sulfur dioxide molecules to 

reagents that react with sulfur dioxide to form a sulfate molecule that can then be captured as a 

particulate. Sulfur dioxide control systems vary in reagent utilized to react with sulfur dioxide, the 

manner in which the reagent is exposed to sulfur dioxide, and the manner in which sulfate 

molecules are captured.
St. Joseph Energy Center, LLC Page 77 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Step 2: Eliminate Technically Infeasible Options

Fuel Specifications 

Combusting only clean natural gas, which has an inherently low sulfur content, rather than higher 

sulfur content fuels alone or in combination with natural gas has a very low potential for 

generating SO2 emissions. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Fuel Specifications is a technically feasible option for the Emergency Diesel 

Generators at this source.

Good Combustion Practices 

Good combustion practices as well as operation and maintenance of the Emergency Generators 

to keep them in good working order per the manufacturer's specifications will minimize SO2 

emissions. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Good Combustion Practices is a technically feasible option for the Emergency Diesel 

Generators at this source.

Usage Limitation 

Usage limitation involves accepting a limit on the maximum hours of operation on the units, which 

results in lower emissions. This is included in RBLC for the control of SO2 emissions from fire 

pump and emergency engines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Usage Limitation is a technically feasible option for the Emergency Diesel Generators

at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of ultra low sulfur distillate (ULSD) (Fuel Specification and Good combustion practices) 

and usage limitation shall be used to reduce the SO2 emissions from the Emergency Diesel 

Generators at this source.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed SO2 BACT determination along with the existing SO2 BACT 

determinations for emergency pumps. All data in the table is based on the information obtained 

from the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating (TPH) Limitation Control Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy Center -

proposed

Proposed Emergency 

Diesel 

Generators

EG01 & EG02

1,006

horsepower, 

each

SO2: 

0.012

lb/hr

ULSD and 

Usage Limits

Emergency 

Generator

EG03

2,012

horsepower

SO2:

0.024

lb/hr
St. Joseph Energy Center, LLC Page 78 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating (TPH) Limitation Control Method

CO-0055 LAMAR LIGHT & 

POWER POWER 

PLANT

2/3/2006 Fire Water 

Pump 

1500 HP 0.06 lb/hr Low Sulfur Fuel. 

Less than 0.05 by 

weight

NJ-0036 AES RED OAK 

LLC

10/24/2001 Emergency 

Generator

49 MMBtu/hr 2.45 lb/hr Low Sulfur Fuel

OH-0254 DUKE ENERGY 

WASHINGTON 

COUNTY LLC

8/14/2003 Emergency 

Generator

600 KW 0.4 lb/hr Low Sulfur Fuel, 

Combustion 

Control

OH-0275 PSI ENERGYMADISON 

STATION

8/24/2004 Emergency 

Generator

172.1 MMBtu/hr 8.61 lb/hr Sulfur limited to 

0.05% by Weight. 

Operation Limited 

to 499 Hours/yr

OK-0090 DUKE ENERGY 

STEPHENS, LLC 

STEPHENS 

ENERGY

3/21/2009 IC Engine, 

Backup 

Generator Diesel

749 BHP 0.3 lb/hr Use of Low Sulfur 

Fuel (<0.05% by 

Wt)

OK-0129 CHOUTEAU 

POWER PLANT

1/23/2009 Emergency 

Generator

2200 HP 0.89 lb/hr Low Sulfur Diesel 

0.05 % S

As shown in the above table, a proposed limit of 0.012 lb/hour for Emergency Generators, 

identified as EG01 & EG02 and 0.02 lbs/hr for Emergency Generator, identified as EG03, are

consistent with the most stringent limits contained in the RBLC.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for SO2 emissions from the proposed Emergency 

Generators, Identified as EG01, EG02 and EG03:

(1) The SO2 emissions from the Emergency Diesel Generators, Identified as EG01 and 

EG02 shall be limited to less than 0.012 lb/hr through the use of ultra low sulfur distillate 

(ULSD) and usage limitation. 

(2) The SO2 emissions from the Emergency Diesel Generator, Identified as EG03 shall be 

limited to less than 0.024 lb/hr through the use of ultra low sulfur distillate (ULSD) and

usage limitation. 

(3) The Emergency Diesel Generators shall not exceed 500 hours per year, each.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for SO2 emissions for the Emergency Generators.

(1) The SO2 emissions from the Emergency Diesel Generators, Identified as EG01 and 

EG02 shall not exceed 0.012 lb/hr through the use of ultra low sulfur distillate (ULSD) and

usage limitation. 

(2) The SO2 emissions from the Emergency Diesel Generator, Identified as EG03 shall not 

exceed 0.024 lb/hr through the use of ultra low sulfur distillate (ULSD) and usage 

limitation. 

(3) The Emergency Diesel Generators shall not exceed 500 hours per year, each.
St. Joseph Energy Center, LLC Page 79 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Volatile Organic Compounds (VOCs) BACT - Emergency Diesel Generators

Step 1: Identify Potential Control Technologies

Emissions of volatile organic compounds (VOC) are generally controlled by oxidation. Oxidation

technologies include:

(a) Regenerative thermal oxidation; 

(b) Recuperative thermal oxidation; 

(c) Catalytic oxidation; 

(d) Combustion Design Controls; and

(e) Flares

(f) Usage Limitation.

Step 2: Eliminate Technically Infeasible Options

Regenerative Thermal Oxidizers

The thermal oxidizer has a high temperature combustion chamber that is maintained by a 

combination of auxiliary fuel, waste gas compounds, and supplemental air added when 

necessary. This technology is typically applied for destruction of organic vapors, nevertheless it is 

also considered as a technology for controlling VOC emissions. Upon passing through the flame, 

the waste gas containing VOC is heated. The mixture continues to react as it flows through the 

combustion chamber.

The required level of VOC destruction of the waste gas that must be achieved within the time that 

it spends in the thermal combustion chamber dictates the reactor temperature. The shorter the 

residence time, the higher the reactor temperature must be. Most thermal units are designed to 

provide no more than 1 second of residence time to the waste gas with typical temperatures of 

1,200 to 2,000o

F. Once the unit is designed and built, the residence time is not easily changed, 

so that the required reaction temperature becomes a function of the particular gaseous species 

and the desired level of control. 

A Regenerative Thermal Oxidizer incorporates heat recovery and greater thermal efficiency 

through the use of direct contact heat exchangers constructed of a ceramic material that can 

tolerate the high temperatures needed to achieve ignition of the waste stream.

The inlet gas first passes through a hot ceramic bed thereby heating the stream (and cooling the 

bed) to its ignition temperature. The hot gases then react (releasing energy) in the combustion 

chamber and while passing through another ceramic bed, thereby heating it. The process flows 

are then switched, feeding the inlet stream to the hot bed. This cyclic process affords very high 

energy recovery (up to 95%). The higher capital costs associated with these high-performance 

heat exchangers and combustion chambers may be offset by the increased auxiliary fuel savings 

to make such a system economical. 

This control is not included in RBLC for the control of VOC emissions from fire pump & 

emergency engines. EPA determined in the development of NSPS IIII that add-on controls are 

economically infeasible for emergency ICE.
St. Joseph Energy Center, LLC Page 80 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a regenerative thermal oxidizer is not a technically feasible option for the Emergency 

Diesel Generators at this source.

Recuperative Thermal Oxidizers

This control technology oxidizes combustible materials by raising the temperature of the material 

above the auto-ignition point in the presence of oxygen and maintaining the high temperature for

sufficient time to complete combustion. The operating temperature ranges from 1,100 - 1.200o

F

and the waste stream inlet pollutants concentration is as low as 500-50,000 scfm.

Additional fuel is required to reach the ignition temperature of the waste gas stream. Oxidizers 

are not recommended for controlling gases with sulfur containing compounds because of the 

formation of highly corrosive acid gases. Thermal oxidizers do not reduce emissions of VOC from 

properly operated natural gas combustion units without the use of a catalyst.

This control is not included in RBLC for the control of VOC emissions from fire pump & 

emergency engines. EPA determined in the development of NSPS IIII that add-on controls are 

economically infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a recuperative thermal oxidizer is not a technically feasible option for the Emergency 

Diesel Generators at this source.

Catalytic Oxidizers

Catalytic oxidation is also a widely used control technology to control pollutants where the waste 

gas is passed through a flame area and then through a catalyst bed for complete combustion of 

the waste in the gas. This technology is typically applied for destruction of organic vapors, 

nevertheless it is considered as a technology for controlling VOC emissions. A catalyst is an 

element or compound that speeds up a reaction at lower temperatures compared to thermal 

oxidation without undergoing change itself. Catalytic oxidizers operate at 600°F to 800°F and 

approximately require 1.5 to 2.0 ft3 of catalyst per 1000 standard ft3 per gas flow rate. 

Similar to thermal incineration; waste stream is heated by a flame and then passes through a 

catalyst bed that increases the oxidation rate more quickly and at lower temperatures. Typical 

waste stream inlet flow rate ranges from 700 - 50,000 scfm and waste stream inlet pollutant 

concentration is as low as 1ppmv.

Oxidation efficiency depends on exhaust flow rate and composition. Residence time required for 

oxidation to take place at the active sites of the catalyst may not be achieved if exhaust flow rates 

exceed design specifications. Also, sulfur and other compounds may foul the catalyst, leading to 

decreased efficiency. This control is not included in RBLC for the control of VOC emissions from 

fire pump & emergency engines. EPA determined in the development of NSPS IIII that add-on 

controls are economically infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a catalytic oxidizer is not a technically feasible option for Emergency Diesel Generators

at this source.

Combustion Design Controls

VOC emissions are caused through incomplete combustion. When fuel and air are not well 

mixed in the combustion zone, low oxygen regions form where fuel will partially combust, 

resulting in VOC and unburned hydrocarbons that exit with the exhaust. VOC formation can be 

minimized by improving the fuel air mixing through enhanced fuel injection systems, air 

management systems, combustion system designs, and pre-mixed diesel combustion. This type 

of control is included in RBLC for the control of VOC emissions from fire pump & emergency 

engines.
St. Joseph Energy Center, LLC Page 81 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Good Combustion Controls is a technically feasible option for the Emergency Diesel 

Generators at this source.

Flare

Although the VOC concentration is very low, the stream flow rate is very high. The low heating 

value of the stream is too low for flaring. As there are insufficient organics in this vent stream to 

support combustion, use of a flare would require a significant addition of supplementary fuel. 

Therefore, a secondary impact of the use of flare for this stream would be the creation of 

additional emissions from burning supplemental fuel, including NOx. Flares have not been 

utilized or demonstrated as a control device for VOC from this type of high-volume process

stream. In addition, the flare would have no additional control versus the thermal oxidizers. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flare is not a technically feasible option for the Emergency Diesel Generators at this 

source.

Usage Limitation 

Usage limitation involves accepting a limit on the maximum hours of operation on the units, which 

results in lower emissions. This is included in RBLC for the control of VOC emissions from fire 

pump and emergency engines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Usage Limitation is a technically feasible option for the Emergency Diesel Generators

at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of combustion design control and usage limitation shall be used to reduce the VOC 

emissions from the Emergency Generators at this source.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed VOC BACT determination along with the existing VOC 

BACT determinations for emergency engines. All data in the table is based on the information 

obtained from the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating (TPH) Limitation Control 

Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy 

Center -

proposed

Proposed Emergency

Diesel

Generators

EG01 & EG02

1,006

horsepower

, each

VOC: 1.04 

lbs/hr, each

Combustion 

Design 

Controls and 

Usage Limits

Emergency 

Generator EG03

2,012

horsepower

VOC: 1.04 

lbs/hr

OK-0090 DUKE 

ENERGY 

STEPHENS, 

LLC 

STEPHENS 

3/21/2009 IC Engine, Backup 

Generator Diesel

749 BHP 1.7 lb/hr Good Engine 

Design
St. Joseph Energy Center, LLC Page 82 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating (TPH) Limitation Control 

Method

ENERGY

OK-0129 CHOUTEAU 

POWER 

PLANT

1/23/2009 Emergency 

Generator

2200 HP 1.55 lb/hr Good 

Combustion 

Practice

WV-0023 MAIDSVILLE 3/2/2004 Emergency 

Generator

1801 HP 1.21 lb/hr Good 

Combustion 

Practice

SC-0064 SCE&G -

JASPER 

COUNTY 

GENERATIN

G FACILITY

5/23/2002 Emergency 

Generator

2000 KW 1.7 lb/hr None

OH-0254 DUKE 

ENERGY 

WASHINGT

ON 

COUNTY 

LLC

8/14/2003 Emergency 

Generator

600 KW 1.76 lb/hr Low Sulfur Fuel, 

Combustion 

Control

OH-0266 UNIVERSIT

Y OF 

CINCINNATI

8/15/2002 Diesel fired engines 19.17 

MMBtu/hr

1.04 lb/hr None

OH-0275 PSI 

ENERGYMADISON 

STATION

8/24/2004 Emergency 

Generator

17.21 

MMBtu/hr

1.55 lb/hr None

As shown in the above table, a proposed limit of 1.04 lb/hr is consistent with the most stringent 

limits contained in the RBLC.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for VOC emissions from the proposed Emergency 

Generators, Identified as EG01, EG02 and EG03:

(1) The VOC emissions from the Emergency Diesel Generators, Identified as EG01 and 

EG02 shall be limited to less than 1.04 lb/hr, each, through the use of Combustion 

Design Controls and usage limitation. 

(2) The VOC emissions from the Emergency Diesel Generator, Identified as EG03 shall be 

limited to less than 1.04 lb/hr, each, through the use of Combustion Design Controls and

usage limitation. 

(3) The Emergency Diesel Generators shall not exceed 500 hours per year, each.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for VOC emissions for the Emergency Diesel Generators.
St. Joseph Energy Center, LLC Page 83 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(1) The VOC emissions from the Emergency Diesel Generators, Identified as EG01 and 

EG02 shall not exceed 1.04 lbs/hr, each, through the use of Combustion Design Controls

and usage limitation. 

(2) The VOC emissions from the Emergency Diesel Generator, Identified as EG03 shall not 

exceed 1.04 lbs/hr, each, through the use of Combustion Design Controls and usage 

limitation. 

(3) The Emergency Diesel Generators shall not exceed 500 hours per year, each.

Nitrogen Oxide (NOx) BACT - Emergency Diesel Generators

Step 1: Identify Potential Control Technologies

The nitrogen oxide (NOx) emissions can be controlled by the following methods: 

(a) Selective Catalytic Reduction (SCR)

(b) Selective Non-Catalytic Reduction (SNCR)

(c) Combustion Design Controls

(d) Usage Limitations

Add-on control technologies and combustion control approaches are discussed below.

Step 2: Eliminate Technically Infeasible Options

Selective Catalytic Reduction (SCR)

Selective Catalytic Reduction (SCR) process involves the mixing of anhydrous or aqueous 

ammonia vapor with flue gas and passing the mixture through a catalytic reactor to reduce NOX

to water and N2. Under optimal conditions, SCR has a removal efficiency up to 90% when used 

on steady state processes. The efficiency of removal will be reduced for processes that are not 

stable or require frequent changes in the mode of operation.

The most important factor affecting SCR efficiency is temperature. SCR can operate in a flue gas 

window ranging from 480°F to 800°F, although the optimum temperature range depends on the 

type of catalyst and the flue gas composition. In this particular service, the minimum target 

temperature is approximately 750 F. Temperature below the optimum, decrease catalyst activity 

and allow NH3 to slip through; above the optimum range, ammonia will oxidize to form additional 

NOx. SCR efficiency is also largely dependent on the stoichiometric molar ratio of NH3:NOx; 

variation of the ideal 1:1 ratio to 0.5:1 ratio can reduce the removal efficiency to 50%.

Unreacted reagent may form ammonium sulfates which may plug or corrode downstream 

equipment. Particulate-laden streams may blind the catalyst and may necessitate the application 

of a sootblower.

This control is not included in RBLC for the control of NOx emissions from fire pump & 

emergency engines. EPA determined in the development of NSPS IIII that add-on controls are 

economically infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

selective catalytic reduction (SCR) is not a technically feasible option for the Emergency Diesel 

Generators at this source.
St. Joseph Energy Center, LLC Page 84 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Selective Non-Catalytic Reduction (SNCR)

With selective non-catalytic reduction (SNCR), NOX is selectively removed by the injection of 

ammonia or urea into the flue gas at an appropriate temperature window of 1600°F to 2100°F 

and without employing a catalyst. Similar to SCR without a catalyst bed, the injected chemicals 

selectively reduce the NOX to molecular nitrogen and water. 

This approach avoids the problem related to catalyst fouling but the temperature window and 

reagent mixing residence time is critical for conducting the necessary chemical reaction. At the 

proper temperature, urea decomposes to produce ammonia which is responsible for NOX

reduction. At a higher temperature, the rate of a competing reaction for the direct oxidation of 

ammonia that actually forms NOx becomes significant. At a lower temperature, the rates of NOX

reduction reactions become too slow resulting in urea slip (i.e. emissions of unreacted urea).

Optimal implementation of SNCR requires the employment of an injection system that can 

accomplish thorough reagent/gas mixing within the temperature window while accommodating 

spatial and production rate temperature variability in the gas stream. The attainment of maximum 

NOx control performance therefore requires that the source exhibit a favorable opportunity for the 

application of this technology relative to the location of the reaction temperature range.

This control is not included in RBLC for the control of NOx emissions from fire pump & 

emergency engines. EPA determined in the development of NSPS IIII that add-on controls are 

economically infeasible for emergency ICE.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

selective non-catalytic reduction (SNCR) is not a technically feasible option for the Emergency 

Diesel Generators at this source.

Combustion Design Controls

NOX emissions are caused by oxidation of nitrogen gas in the combustion air during fuel 

combustion. This occurs due to high combustion temperatures and insufficiently mixed air and 

fuel in the cylinder where pockets of excess oxygen occur. These effects can be minimized 

through air-to-fuel ratio control, ignition timing reduction, and exhaust gas recirculation. This type 

of control is included in RBLC for the control of NOX emissions from fire pump & emergency 

engines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Good Combustion Controls is a technically feasible option for the Emergency Diesel 

Generators at this source.

Usage Limitation 

Usage limitation involves accepting a limit on the maximum hours of operation on the units, which 

results in lower emissions. This is included in RBLC for the control of NOx emissions from fire 

pump and emergency engines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Usage Limitation is a technically feasible option for the Emergency Diesel Generators

at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of combustion design control and usage limitation shall be used to reduce the NOx 

emissions from the Emergency Generators at this source.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed NOx BACT determination along with the existing NOx 
St. Joseph Energy Center, LLC Page 85 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT determinations for emergency pumps. All data in the table is based on the information 

obtained from the permit application submitted by St. Joseph Energy Center, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating (TPH) Limitation Control 

Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy 

Center -

proposed

Proposed Emergency

Diesel

Generators

EG01 & EG02

1,006

horsepower

, each

NOx + NMNC:

4.8 g/bhp-hr 

Combustion 

Design 

Controls and 

Usage Limits

Emergency 

Generator EG03

2,012

horsepower

AR-0051 DUKE 

ENERGYJACKSON 

FACILITY

4/1/2002 Generator Diesel 

Fired

671 HP 14 g/b-hp-hr Good 

Combustion 

Practice

FL-0310 SHADY HILLS 

GENERATING 

STATION

1/12/2009 Emergency 

Generator

2.5 MW 6.9 g/hp-hr Purchased 

model is at least 

as stringent as 

the BACT 

values under 

EPA 

Certification

MN-0054 MANKATO 

ENERGY 

CENTER

12/4/2003 IC Engines Large 

Fuel Oil

1850 HP 12.7 g/b-hp-hr Good 

Combustion 

Practice

MN-0054 MANKATO 

ENERGY 

CENTER

12/4/2003 IC Engines Small 

Fuel Oil

290 HP 5.7 g/b-hp-hr Good 

Combustion 

Practice

MN-0071 FAIRBAULT 

ENERGY PARK

6/5/2007 Emergency 

Generator

1750 KW 0.024 lb/hp-hr None

OK-0072 REDBUD 

POWER PLT

5/6/2002 Emergency 

Generator

1818 HP 0.024 lb/b-hp-hr None

OK-0129 CHOUTEAU 

POWER PLANT

1/23/2009 Emergency 

Generator

2200 HP 23.15 lb/hr

(4.8 g/hp-hr)

None

WV-0023 MAIDSVILLE 3/2/2004 Emergency 

Generator

1801 HP 20.9 lb/hr

(5.3 g/hp-hr)

Good 

Combustion 

Practice

SC-0064 SCE&G -

JASPER 

COUNTY 

GENERATING 

FACILITY

5/23/2002 Emergency 

Generator, Diesel 

Fuel

2000 KW 59.5 lb/hr

(10.1 g/hp-hr)

None

OH-0254 DUKE ENERGY 

WASHINGTON 

COUNTY LLC

8/14/2003 Emergency 

Generator

600 KW 12.4 lb/hr

(7.0 g/hp-hr)

Low Sulfur Fuel, 

Combustion 

Control

OH-0266 UNIVERSITY 

OF 

CINCINNATI

8/15/2002 Diesel fired engines 19.17 

MMBtu/hr

40.92 lb/hr

(6.4 g/hp-hr)

None

OH-0275 PSI ENERGYMADISON 

STATION

8/24/2004 Emergency 

Generator

172.1 

MMBtu/hr

55.07 lb/hr

(10.2 g/hp-hr)

None

As shown in the above table, a proposed limit of 4.8 g/bhp-hr NOx + NMHC, which is equivalent 

to 0.011 lb/bhp-hr, is consistent with the most stringent limits contained in the RBLC.
St. Joseph Energy Center, LLC Page 86 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for NOx emissions from the proposed Emergency 

Generators, Identified as EG01, EG02 and EG03:

(1) The NOx emissions from the Emergency Diesel Generators shall be limited to less than 

4.8 g/bhp-hr for NOx + NMHC through the use of Combustion Design Controls and usage 

limitation. 

(2) The Emergency Generators shall not exceed 500 hours per year, each.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for NOx emissions for the Emergency Generators.

(1) The NOx emissions from the Emergency Diesel Generators shall not exceed 4.8 g/bhp-hr 

for NOx + NMHC through the use of Combustion Design Controls and usage limitation. 

(2) The Emergency Diesel Generators shall not exceed 500 hours per year, each.

Particulate Matter (PM/PM10/PM2.5) BACT – Cooling Tower CT01 - CT02

Step 1: Identify Potential Control Technologies

Emissions of Particulate matter (PM, PM10 and PM2.5) from cooling towers are generally 

controlled by:

(1) Drift (Mist) eliminator system. 

(2) Minimizing TSD

Step 2: Eliminate Technically Infeasible Options

The test for technical feasibility of any control option is whether it is both available and applicable 

to reducing the PM/PM10/PM2.5 emissions from the Cooling Towers.

Drift Eliminator System

Cooling towers are a source of particulate matter (PM/PM10/PM2.5) emissions from the small 

amount of water mist that is entrained with the cooling air as “drift”. The cooling water contains 

small amounts of dissolved solids which become particulate (PM/PM10/PM2.5) emissions once the 

water mist evaporates. To reduce the drift from cooling towers, drift eliminators are typically 

incorporated into the tower design to remove as many droplets as practical from the air stream 

before exiting the tower. 

Particulate matter emissions occur from cooling towers when suspended solids contained in 

water used in the cooling tower becomes airborne as the water is circulated and cooled. Drift 

eliminators contain packing which is used to limit the amount of this particulate matter which

becomes airborne during the cooling process. As mist passes through the packing, the particles 

in the air contact and adhere to the surface of the packing. As condensed water flows down this 

packing, these particles are removed. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a drift eliminator system is technically feasible option for the Cooling Towers at this 

source.
St. Joseph Energy Center, LLC Page 87 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Minimizing TSD

Minimizing dissolved solids in cooling water to reduce PM emissions. This system is included in 

RBLC for the control of PM emissions from cooling towers.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Minimizing TSD is a technically feasible option for the Cooling Towers at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Drift (Mist) eliminator system. 

(2) Minimizing TSD

The most effective method for control of particulate emissions resulting from operation of the 

cooling towers at this source is the use of high efficiency drift eliminators designed to 0.0005% 

maximum drift to maintain a drift loss as well as the maintenance of the equipment in good 

working order and operation per manufacturer’s specifications. The source has chosen the drift 

eliminator to control particulate matter from their Cooling Towers.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for cooling towers. All data in the table is 

based on the information obtained from the permit application submitted by St. Joseph Energy 

Center, LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of 

permits available at the websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy 

Center -

proposed

Proposed Cooling Towers 

(CT01 and CT02)

170,000 

gpm

0.0005% Drift 

Eliminator

AR-0070 GENOVA 

ARKANSAS I, 

LLC

8/23/2002 Cooling Towers 11 mmg/hr 0.001% Drift 

Eliminator

TN-0153 WILLIAMS 

REFINING & 

MARKETING, 

L.L.C.

4/3/2002 Cooling Towers 56 mmg/hr 0.005% None

ID-0017 POWER 

COUNTY 

ADVANCED 

ENERGY 

CENTER

2/10/2009 Cooling Towers 121,000 

gal/m

0.0005% Drift/Mist 

Eliminator

ID-0017 POWER 

COUNTY 

ADVANCED 

ENERGY 

CENTER

2/10/2009 Cooling Towers 985 gal/m 0.001% Drift/Mist 

Eliminator

GA-0141 WARREN 

COUNTY 

BIOMASS 

ENERGY 

FACILITY

12/1/2010 Cooling Towers None 0.0005% Drift 

Eliminator
St. Joseph Energy Center, LLC Page 88 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

GA-0142 OSCEOLA 

STEEL CO.

12/29/2010 Cooling Towers None 0.0005% Drift 

Eliminator

LA-0248 DIRECT 

REDUCTION 

IRON PLANT

1/27/2011 Cooling Towers 26,857 gpm 0.0005% less than 

1000mg/l 

TSD 

concentration 

in cooling 

water and 

drift eliminator

LA-0248 DIRECT 

REDUCTION 

IRON PLANT

1/27/2011 Cooling Towers 17,611 gpm 0.0005% less than 

1000mg/l 

TSD 

concentration 

in cooling 

water and 

drift eliminator

LA-0254 NINEMILE 

POINT 

ELECTRIC 

GENERATING 

PLANT

8/16/2011 Cooling Towers 12,000 

gal/min

0.001% High 

efficiency 

Mist 

Eliminator

LA-0254 NINEMILE 

POINT 

ELECTRIC 

GENERATING 

PLANT

8/16/2011 Cooling Towers 115,847 

gal/min

0.0005% High 

efficiency 

Mist 

Eliminator

USEPA’s RACT/BACT/LAER Clearinghouse shows BACT determinations specifying the use of 

drift/mist eliminators for controlling PM, PM10 and PM2.5 emissions, with drift rates ranging from 

0.003% – 0.0005%. A design drift rate of 0.0005% appears in the most recent permit 

determinations and it represents the best performing of all cooling towers in the RBLC and the 

highest efficiency mist eliminators available in the cooling tower design. 

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for PM, PM10 and PM2.5 emissions from the proposed 

Cooling Tower (CT01-CT02):

Therefore, a 0.0005% drift (mist) eliminator system is proposed as BACT for PM, PM10 and PM2.5

emissions from the Cooling Towers, identified as CT01 and CT02. 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM, OAQ has 

approved the proposed PM, PM10 and PM2.5 BACT for the Cooling Towers, identified as CT01 

and CT02. 

The PM, PM10 and PM2.5 emissions from the Cooling Towers, identified as CT01 and CT02 shall 

be controlled by High efficiency drift eliminators designed with a drift loss rate of less than 

0.0005%.
St. Joseph Energy Center, LLC Page 89 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Volatile Organic Compounds (VOCs) BACT – Turbine Lube Oil Demister Vent DM01 – DM06

Step 1: Identify Potential Control Technologies

Emissions of Volatile Organic Compounds (VOCs) are generally controlled by oxidation. 

Oxidation technologies include regenerative thermal oxidation, catalytic oxidation, and flares.

(a) Catalytic oxidation; 

(b) Regenerative thermal oxidation; 

(c) Flares.

If add-on control technology is not feasible, an alternate method of control may be implemented. 

Step 2: Eliminate Technically Infeasible Options

Catalytic Oxidizers

Catalytic oxidation is also a widely used control technology to control pollutants where the waste 

gas is passed through a flame area and then through a catalyst bed for complete combustion of 

the waste in the gas. This technology is typically applied for destruction of organic vapors, 

nevertheless it is considered as a technology for controlling VOCs emissions. A catalyst is an 

element or compound that speeds up a reaction at lower temperatures compared to thermal 

oxidation without undergoing change itself. Catalytic oxidizers operate at 600°F to 800°F and 

approximately require 1.5 to 2.0 ft3 of catalyst per 1000 standard ft3 per gas flow rate. 

Similar to thermal incineration; waste stream is heated by a flame and then passes through a 

catalyst bed that increases the oxidation rate more quickly and at lower temperatures. Typical 

waste stream inlet flow rate ranges from 700 - 50,000 scfm and waste stream inlet pollutant 

concentration is as low as 1ppmv.

Catalyst can be deactivated by certain catalyst poisons or other fouling contaminants such as 

silicone, sulfur, heavy hydrocarbons, and particulates. The air flow from the lubrication oil vents 

and oil mist loading are sufficiently low to prohibit the use of any add-on controls to control VOC 

emissions from the lube oil vents. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a catalytic oxidizer is not a technically feasible option for Turbine Lube Oil Demister 

Vents at this source.

Regenerative Thermal Oxidizers

The thermal oxidizer has a high temperature combustion chamber that is maintained by a 

combination of auxiliary fuel, waste gas compounds, and supplemental air added when 

necessary. This technology is typically applied for destruction of organic vapors, nevertheless it is 

also considered as a technology for controlling VOCs emissions. Upon passing through the 

flame, the waste gas containing VOCs is heated. The mixture continues to react as it flows 

through the combustion chamber.

The required level of VOCs destruction of the waste gas that must be achieved within the time 

that it spends in the thermal combustion chamber dictates the reactor temperature. The shorter 

the residence time, the higher the reactor temperature must be. Most thermal units are designed 

to provide no more than 1 second of residence time to the waste gas with typical temperatures of 

about 1,600o

F with a waste stream inlet flow rate of 10,000-100,000 scfm range. And a waste 

stream inlet pollutant concentration as low as 100 ppmv or less. Once the unit is designed and 
St. Joseph Energy Center, LLC Page 90 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

built, the residence time is not easily changed, so that the required reaction temperature becomes 

a function of the particular gaseous species and the desired level of control. 

A Regenerative Thermal Oxidizer incorporates heat recovery and greater thermal efficiency

through the use of direct contact heat exchangers constructed of a ceramic material that can 

tolerate the high temperatures needed to achieve ignition of the waste stream.

Additional fuel is required to reach the ignition temperature of the waste gas stream. Oxidizers 

are not recommended for controlling gases with sulfur containing compounds because of the 

formation of highly corrosive acid gases. The air flow from the lubrication oil vents and oil mist 

loading are sufficiently low to prohibit the use of any add-on controls to control VOC emissions 

from the lube oil vents. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a regenerative thermal oxidizer is not a technically feasible option for the Turbine Lube 

Oil Demister Vents at this source.

Flare

A flare is not technically feasible because the exhaust stream concentration must be high enough 

to sustain combustion, requiring a VOC inlet concentration of greater than 13,000 ppm, which is 

not feasible with this operation. They require a high heating value waste gas (in excess of 300 

BTU/scf) or supplemental fuel. Flares will not be considered as BACT for this operation, and no 

additional analysis will be conducted.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flare is not a technically feasible option for the Turbine Lube Oil Demister Vents at 

this source

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

there is no viable technology for controlling the VOC emissions resulting from the Turbine Lube 

Oil Demister Vents.

Step 4: Evaluate the Most Effective Controls and Document the Results

No BACT determinations for VOC emissions from Lubrication Oil Demister Vents were located in 

the RBLC data base. Based on the information reviewed for this BACT determination, IDEM, 

OAQ has determined that there is no viable technology for controlling the VOC emissions

resulting from Turbine Lube Oil Demister Vents.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for VOC emissions from the proposed Turbine Lube 

Oil Demister Vents:

The VOC emissions from the Turbine Lube Oil Demister Vents identified as DM01 – DM06 shall 

be the use of good design and operating practices. 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for VOC emissions for the Turbine Lube Oil Demister Vents.

The VOC emissions from the Turbine Lube Oil Demister Vents identified as DM01 – DM06 shall 

be the use of good design and operating practices. 
St. Joseph Energy Center, LLC Page 91 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

PM10 and PM2.5 BACT – Turbine Lube Oil Demister Vent DM01 – DM06

Step 1: Identify Potential Control Technologies

The organic PM (PM10 and PM2.5) are generally controlled with add-on control equipment 

designed to capture the emissions prior to the time they are exhausted to the atmosphere. 

Generally, organic PM (PM10 and PM2.5) emissions are controlled through one of the following 

mechanisms:

(1) Mechanical Collectors (such as Cyclones or Multiclones);

(2) Wet Scrubbers;

(3) Electrostatic Precipitators (ESP); and

(4) Fabric Filter Dust Collectors (Baghouses).

The choice of which technology is most appropriate for a specific application depends upon 

several factors, including particle size to be collected, particle loading, stack gas flow rate, stack 

gas physical characteristics (e.g., temperature, moisture content, presence of reactive materials), 

and desired collection efficiency.

Step 2: Eliminate Technically Infeasible Options

Add - on - Controls

The organic PM (PM10 and PM2.5) emissions from this source result only from the small amount

of turbine lube oil used. This emissions level is so low that it would not be feasible for any add-on 

controls such as cyclones, baghouses, ESPs or wet scrubbers to effectively further reduce 

emissions. For this reason, the above-listed add-on particulate controls are not considered 

feasible in this BACT analysis. There is no evidence that any of these add-on controls have ever 

been used to control organic PM emissions from lube oil demister vents.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of add-on controls is not a technically feasible option for the Turbine Lube Oil Demister 

Vents at this source.

 Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

there is no viable technology for controlling the organic PM emissions resulting from the Turbine 

Lube Oil Demister Vents.

Step 4: Evaluate the Most Effective Controls and Document the Results

No BACT determinations for organic PM (PM10 and PM2.5) emissions from Lubrication Oil 

Demister Vents were located in the RBLC data base. Based on the information reviewed for this 

BACT determination, IDEM, OAQ has determined that there is no viable technology for controlling 

the organic PM (PM10 and PM2.5) emissions resulting from Turbine Lube Oil Demister Vents.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for organic PM emissions from the proposed Turbine 

Lube Oil Demister Vents:

The organic PM, PM10 and PM2.5 emissions from the Turbine Lube Oil Demister Vents identified 

as DM01 – DM06 shall be the use of good design and operating practices. 
St. Joseph Energy Center, LLC Page 92 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for organic PM (PM10 and PM2.5) emissions for the Turbine Lube Oil 

Demister Vents.

The organic PM, PM10 and PM2.5 emissions from the Turbine Lube Oil Demister Vents identified 

as DM01 – DM06 shall be the use of good design and operating practices. 

Volatile Organic Compounds (VOCs) BACT - Storage Tanks

(a) Six (6) Turbine Lube Oil storage tanks, identified as TK01 - TK06, permitted in 2012, with 

a nominal capacity of 6,800 gallons each.

(b) Two (2) Emergency Generator ULSD Tanks, identified as TK07 and TK08, permitted in 

2012, with a nominal capacity of 550 gallons, each.

(c) Two (2) Fire Pump Engine ULSD Tanks, identified as TK09 and TK10, permitted in 2012, 

with a nominal capacity of 70 gallons, each.

(d) One (1) Vehicle Diesel Tank, identified as TK12, permitted in 2012, with a nominal 

capacity of 650 gallons.

(e) One (1) Emergency Generator ULSD Tank, identified as TK50, permitted in 2012, with a 

nominal capacity of 300 gallons.

The VOC emissions from the above diesel storage Tanks are less than 0.01 tons per year, each.

Step 1: Identify Potential Control Technologies

Emissions of Volatile Organic Compounds (VOCs) are generally controlled by oxidation. 

Oxidation technologies include regenerative thermal oxidation, catalytic oxidation, and flares.

(a) Catalytic oxidation; 

(b) Regenerative thermal oxidation; 

If add-on control technology is not feasible, an alternate method of control may be implemented. 

Step 2: Eliminate Technically Infeasible Options

Catalytic Oxidizers

Catalytic oxidation is also a widely used control technology to control pollutants where the waste 

gas is passed through a flame area and then through a catalyst bed for complete combustion of 

the waste in the gas. This technology is typically applied for destruction of organic vapors, 

nevertheless it is considered as a technology for controlling VOCs emissions. A catalyst is an 

element or compound that speeds up a reaction at lower temperatures compared to thermal 

oxidation without undergoing change itself. Catalytic oxidizers operate at 600°F to 800°F and 

approximately require 1.5 to 2.0 ft3 of catalyst per 1000 standard ft3 per gas flow rate. 

Similar to thermal incineration; waste stream is heated by a flame and then passes through a 

catalyst bed that increases the oxidation rate more quickly and at lower temperatures. Typical 

waste stream inlet flow rate ranges from 700 - 50,000 scfm and waste stream inlet pollutant 

concentration is as low as 1ppmv.
St. Joseph Energy Center, LLC Page 93 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Catalyst can be deactivated by certain catalyst poisons or other fouling contaminants such as 

silicone, sulfur, heavy hydrocarbons, and particulates. The air flow from the storage tanks is

sufficiently low to prohibit the use of any add-on controls to control VOC emissions. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a catalytic oxidizer is not a technically feasible option for Storage Tanks at this source.

Regenerative Thermal Oxidizers

The thermal oxidizer has a high temperature combustion chamber that is maintained by a 

combination of auxiliary fuel, waste gas compounds, and supplemental air added when 

necessary. This technology is typically applied for destruction of organic vapors, nevertheless it is 

also considered as a technology for controlling VOCs emissions. Upon passing through the 

flame, the waste gas containing VOCs is heated. The mixture continues to react as it flows 

through the combustion chamber.

The required level of VOCs destruction of the waste gas that must be achieved within the time 

that it spends in the thermal combustion chamber dictates the reactor temperature. The shorter 

the residence time, the higher the reactor temperature must be. Most thermal units are designed 

to provide no more than 1 second of residence time to the waste gas with typical temperatures of 

about 1,600o

F with a waste stream inlet flow rate of 10,000-100,000 scfm range. And a waste 

stream inlet pollutant concentration as low as 100 ppmv or less. Once the unit is designed and 

built, the residence time is not easily changed, so that the required reaction temperature becomes 

a function of the particular gaseous species and the desired level of control. 

A Regenerative Thermal Oxidizer incorporates heat recovery and greater thermal efficiency 

through the use of direct contact heat exchangers constructed of a ceramic material that can 

tolerate the high temperatures needed to achieve ignition of the waste stream.

Additional fuel is required to reach the ignition temperature of the waste gas stream. Oxidizers 

are not recommended for controlling gases with sulfur containing compounds because of the 

formation of highly corrosive acid gases. The air flow from the storage tanks is sufficiently low to 

prohibit the use of any add-on controls to control VOC emissions. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a regenerative thermal oxidizer is not a technically feasible option for the Storage 

Tanks at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

there is no viable technology for controlling the VOC emissions resulting from the Storage Tanks.

Step 4: Evaluate the Most Effective Controls and Document the Results

No BACT determinations for VOC emissions from Storage Tanks were located in the RBLC data 

base. Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that there is no viable technology for controlling the VOC emissions resulting from 

Storage Tanks.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for VOC emissions from the proposed Storage Tanks:

The VOC emissions from the Storage Tanks, identified as TK01, TK02, TK03, TK04, TK05, TK06, 

TK07, TK08, TK09, TK10, TK12 and TK50 shall be the use of good design and operating 

practices. 
St. Joseph Energy Center, LLC Page 94 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for VOC emissions for the Storage Tanks.

The VOC emissions from the Turbine Lube Oil storage tanks, identified as TK01 - TK06, and 

Diesel Storage Tanks, identified as TK07, TK08, TK09, TK10, TK12 and TK50 shall be the use of 

good design and operating practices. 

Volatile Organic Compounds (VOCs) BACT - Gasoline Storage Tank

(a) One (1) Vehicle Gasoline dispensing Tank, identified as TK11, permitted in 2012, with a 

nominal capacity of 650 gallons, equipped with submerged fill and stage 1 vapor balance.

Step 1: Identify Potential Control Technologies

Emissions of Volatile Organic Compounds (VOCs) are generally controlled by oxidation. 

Oxidation technologies include regenerative thermal oxidation, catalytic oxidation, and flares.

(a) Catalytic oxidation; 

(b) Regenerative thermal oxidation; 

(c) Flares.

If add-on control technology is not feasible, an alternate method of control may be implemented. 

Step 2: Eliminate Technically Infeasible Options

Add - on - Controls

The VOC emissions from this source are so low that it would not be feasible for any add-on 

controls such as Catalytic oxidation, Regenerative thermal oxidation and Flares to effectively 

further reduce emissions. For this reason, the above-listed add-on VOCs controls are not 

considered feasible in this BACT analysis. There is no evidence that any of these add-on controls 

have ever been used to control VOC emissions from the gasoline dispensing tanks.

The only add on control technologies used in practice for reducing VOC emission from the 

gasoline dispensing are the use of a submerged fill pipes when filling storage tanks, Stage I vapor 

control, Stage II vapor control and equipping vehicles with on-board vapor recovery system 

(ORVR).

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of submerged fill pipes and Stage I vapor control shall be used to reduce the VOC 

emissions from the Vehicle Gasoline Dispensing Tank at this source..

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed VOC BACT determination along with the existing VOC 

BACT determinations for gasoline dispensing operation. All data in the table is based on the 

information obtained from the permit application submitted by St. Joseph Energy Center, LLC, the 

U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available 

at the websites of other permitting agencies.
St. Joseph Energy Center, LLC Page 95 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process Description Limitation

(Tons/year)

Control Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy 

Center -

proposed

Proposed Gasoline 

Dispensing 

Operation (TK11)

0.11 Submerged fill pipes 

and Stage I vapor 

control

SPM 031-

26051-

00026

Honda 

Manufacturing 

of Indiana, 

LLC –

Greensburg, 

IN

5/12/2008 Gasoline 

Dispensing 

Operation

0.81 Submerged fill

Stage I vapor control for 

filling the storage tanks.

Use of on-board vapor 

recovery (ORVR) on a 

minimum of 95% of 

vehicles manufactured

T031-23360-

00026

Honda 

Manufacturing 

of Indiana, 

LLC –

Greensburg, 

IN

10/19/2006 Gasoline 

Dispensing 

Operation

No limit Submerged fill

Stage I vapor control

Use of on-board vapor 

recovery or Stage II 

vapor control on vehicles 

manufactured

AL-0191 Hyundai Motor 

Manufacturing 

-

Montgomery 

Co, AL

3/23/04 Gasoline 

Dispensing 

Operation

No limit identified Submerged fill pipes, 

Stage 1 vapor control on 

large gasoline tanks

AL-0192 Honda Mfg. of 

Alabama LLC 

-

Talladega Co., 

AL

10/18/02 Storage tanks No emission rate 

limits. BACT is 

control.

Submerged fill

Stage 1 vapor control

Based on the RBLC entries in the above table, the most stringent PSD BACT for gasoline dispensing is 

still the same using Submerged fill and Stage I vapor control for filling the storage tanks.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for VOC emissions from the proposed Storage Tanks:

The VOC emissions from the Vehicle Gasoline Dispensing Operation, identified as TK11 shall be 

controlled by submerged fill pipes and Stage I vapor control 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for VOC emissions for the Gasoline Dispensing Operation.

The VOC emissions from the Vehicle Gasoline Dispensing Operation, identified as TK11 shall be 

the use of submerged fill pipes and Stage I vapor control.

GHGs BACT – Combined Cycle Combustion Turbines CCCT1 - CCCT4

Step 1: Identify Potential Control Technologies

The CO2 is by far the dominant GHG from this source. CH4 and N2O are present only in very 

small amounts, are incidental to combustion, and trend with the CO2 emissions. There are no 
St. Joseph Energy Center, LLC Page 96 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

known supplemental controls for N2O or methane emissions from gas-fired units. Therefore, this 

BACT analysis focused on CO2 as a surrogate for all GHG emissions (CO2e). 

(1) Carbon Capture and Storage (CCS); and

(2) High Thermal Efficiency Design.

Step 2: Eliminate Technically Infeasible Options

Carbon Capture and Storage (CCS)

Carbon Capture and Storage (CCS) involves separation and capture of CO2 from the combustion 

exhaust gases using physical or chemical adsorption, pressurization of the captured CO2, 

transportation of the captured CO2 via pipeline, and injection and long-term geologic storage of 

the captured CO2. Carbon Capture and Storage (CCS) technology, specifically post-combustion 

CO2 capture technology, is not commercially available as it has not yet been successfully 

implemented on a large-scale basis such as a natural gas combined cycle power plant. 

According to the Carbon Capture and Storage (CCS) task force report, CO2 capture technology is 

being operated at a small scale at several coal-fired power plants and there are plans to 

implement this technology on a larger scale at several coal-fired power plants in the coming 

years. However, Carbon Capture and Storage (CCS) technology, specifically post-combustion 

CO2 capture technology, is not commercially available and has not yet been successfully 

implemented on a large-scale basis for a natural gas combined cycle power plant. The 

combustion of natural gas and large turbine airflows results in exhaust streams with dilute 

concentrations of CO2, 3-4%, versus 13-15% for coal-fired systems. As outlined in EPA's GHG 

permitting guidance, a control technology would not be applicable if there are significant 

differences that preclude successful operations of the control device, such as differences in 

temperature, pressure, pollutant concentration, or volume of the exhaust stream. Given this 

significant difference in exhaust CO2 concentration, it is uncertain that the CO2 capture 

technologies currently being investigated for coal-fired power plants can also be applied to natural 

gas combined cycle power plants.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Carbon Capture and Storage (CCS) is not a technically feasible option for the 

combined cycle combustion turbines at this source. 

High Thermal Efficiency Design

By utilizing a high efficiency natural gas fired CCCT system that meets the basic design purpose 

of the proposed project, less fossil fuels are required to generate the same desired output of 

electricity, thereby reducing GHG emissions.

The selected F-class engine has a net design base heat rate of 6.779 Btu/kW-hr (HHV, without 

duct firing, corrected to ISO conditions). This equates to a heat rate of 7,646 Btu/kW-hr (HHVnet) after accounting for a "reasonable margin of compliance" for the CCCT Facility. SJEC is 

proposing to install a high efficiency F-class gas turbine to be operated in combined cycle mode.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of High thermal efficiency design is a technically feasible option for the combined cycle 

combustion turbines at this source. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The only feasible, applicable and available control technologies identified is:
St. Joseph Energy Center, LLC Page 97 of 112

New Carlisle, Indiana PSD and TV Permit No.: 141-31003-00579

Permit Reviewer: Josiah Balogun

(1) High Thermal Efficiency Design 

Step 4: Evaluate the Most Effective Controls and Document the Results

The mass emissions limit is based on the maximum rated heat input capacity of the combustion 

turbines and HRSG duct burners needed to produce the power generation demand that the 

CCCT Facility is designed to serve. The source propose to comply with the mass based 

emission limit via continuous fuel usage monitoring and records of the calculated heat input and 

mass GHG emissions.

The heat rate BACT limit of 7,646 Btu/kW-hr (HHV) is determined by applying a “reasonable 

margin of compliance” of 12.8 percent to the design net base heat rate of the CCCT blocks. A 

margin of compliance of 12.8 percent over the design base heat rate is consistent with the GHG 

BACT analyses performed for the Russell City Energy Center project, a proposed 600 MW 

natural gas fired combined-cycle power plant proposed to be located in Hayward, California, and 

the Cricket Valley Energy Center project, a nominal 1,000 MW natural gas fire combined cycle 

power plant to be located in Dover, New York. The margin of compliance accounts for the 

following degradation factors: 

(1) Design margin to reflect that the current baseline performance values are preliminary 

estimates absent equipment supplier commercial guarantees and the equipment as 

constructed and installed may not fully achieve the assumptions that went into the design 

calculations, 

(2) A reasonable performance degradation margin to reflect normal wear and tear over the 

life of the combustions turbines, heat recovery steam generator, and steam turbine 

generator, and

(3) A reasonable degradation margin based on normal wear and tear over the life of the 

auxiliary plant equipment (e.g., cooling towers).

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for GHG emissions from the proposed combined 

cycle combustion turbines:

(1) The CO2 emissions shall be limited to less than 7,646 Btu/kW-hr (HHV-net) for each 

CCCT block (ISO conditions, without duct firing or inlet evaporative cooling, and not 

accounting for transformer losses).

(2) The total CO2 emissions from all four CCCT blocks shall be limited to less than

4,885,000 tons of CO2e per twelve (12) consecutive month period with compliance 

determined at the end of the month.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for the GHG for the combined cycle combustion turbines:

(1) The net heat rate shall not exceed 7,646 Btu/kW-hr (HHV-net) for each CCCT block (ISO 

conditions, baseload operation without duct firing or inlet evaporative cooling, and not 

accounting for transformer losses).

(2) The total CO2e emissions from all four CCCT blocks shall not exceed 4,736,936 tons of 

CO2e per twelve (12) consecutive month period with compliance determined at the end 

of the month.
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GHGs BACT – Auxiliary Boilers B001 - B002

Step 1: Identify Potential Control Technologies

The CO2 is by far the dominant GHG from this source. CH4 and N2O are present only in very 

small amounts, are incidental to combustion, and trend with the CO2 emissions. There are no 

known supplemental controls for N2O or methane emissions from gas-fired units. Therefore, this 

BACT analysis focused on CO2 as a surrogate for all GHG emissions. 

(1) Operating and Maintenance (O&M) Practices;

(2) Efficient Burner Design;

(3) Improved Combustion Measures: Combustion Tuning;

(4) Improved Combustion Measures: Optimization & Digital Control System;

(5) Air Preheat & Economizers;

(6) Turbulators for Firetube Boilers;

(7) Boiler Insulation;

(8) Minimization of Air Infiltration;

(9) Boiler Blowdown Heat Exchange;

(10) Condensation Return System;

(11) Minimization of Gas-side heat Transfer Surface Deposits;

(12) Steam Line Maintenance;

(13) Alternative Fuels-Biomass/Co-firing; and

(14) Fuel Switching.

Step 2: Eliminate Technically Infeasible Options

Operating and Maintenance (O&M) Practices

Boiler efficiency decreases over time; however, the rate of deterioration can be curbed by proper 

Operating and Maintenance (O&M) practices. A well operated and maintained plant will 

experience less deterioration of boiler efficiency.

Deterioration results in higher heat rate, CO2 emissions, and operating costs; in lower reliability; 

and in some cases, reduced output. After a few years of neglect, it may reach the point where 

significant investment is required to rehabilitate the plant and bring it as close as possible to the 

design performance.
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Rehabilitation may focus on life extension and reliability improvement of the plant or may include 

additional measures that improve plant efficiency, occasionally above the original design 

efficiency. The efficiency can be improved by retrofitting combustion control technologies such as 

heat recovery systems, control technology, and upgraded burners.

Additional GHG reductions can be achieved through energy improvements in the steam/hot water 

distribution system, the boiler auxiliaries, or in process efficiency improvements.

Operation and maintenance according to the manufacturer's emission-related instructions or per 

a facility-developed maintenance plan (in a manner consistent with safety and good air pollution 

control practices for minimizing emissions) will prevent generation of additional GHG emissions 

due to efficiency losses over the lifetime of each piece of combustion equipment.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Operating and Maintenance (O&M) practices is a technically feasible option for the 

Auxiliary Boilers at this source. 

Efficient Burner Design

New efficient burner designs for all types of boilers and fuels are commercially available to help 

minimize fuel combustion and GHG emissions. Burners with single and multiple fuel capability, 

low- and ultra low-NOX models, and sizes ranging from very small to very large are widely 

deployed in industry. Further, the burner size and turndown capability (i.e., ability to operate 

and/or efficiency of operation at less than full load) are also key aspects of burner design as they 

will impact the losses associated with inefficient low load and on/off cycling duty. A higher 

turndown ratio reduces burner startups, provides better load control, saves wear-and-tear on the 

burner, and reduces purge-air requirements, all resulting in better overall efficiency. Therefore, 

site-specific conditions and objectives may favor one model over the other. The emission 

reduction is up to a 6% reduction of CO2 emissions.

Efficient burner designs will be employed, taking into account the size, fuel flexibility, operating 

loads, and other site specific conditions and objectives for each piece of combustion equipment.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of efficient burner designs is a technically feasible option for the Auxiliary Boilers at this 

source. 

Improved Combustion Measures: Combustion Tuning

Tuning of the combustion system requires a visual check by an experienced boiler engineer to 

ensure that everything is in good working condition and set according to the manufacturer’s 

recommendations or the optimum settings developed for the particular boiler. Simple parametric 

testing may be required, which may involve changes in the key control variables of the 

combustion system and observation of key parameters such as CO emissions, steam outlet 

conditions, flue gas outlet (stack) temperature, and NOX emissions.

Up to a 3% reduction in CO2 emissions

As part of the O&M practices, combustion tuning of boilers will be conducted on an as-needed 

basis to address any decreases in boiler efficiency over time.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Improved Combustion Measures: Combustion Tuning is a technically feasible option 

for the Auxiliary Boilers at this source. 

Improved Combustion Measures: Optimization & Digital Control System

Optimization can be accomplished through parametric testing, analysis of the results, parameter 

estimation, periodic testing, and/or manual tuning. Software-based optimization systems may be 
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cost effective for large boilers.

Digital control systems are generally necessary to achieve the greatest improvement in 

performance through tuning and optimization. Temperature sensors, oxygen monitors, oxygen 

trim controls, and other instrumentation may be required to maximize boiler efficiency.

The addition of optimization systems, modern control systems, and instrumentation has resulted 

in efficiency improvements of 0.5 to 5%.

The selected package boilers will be equipped with oxygen trim controls and oxygen analyzers.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Operating and Maintenance (O&M) practices is a technically feasible option for the 

Auxiliary Boilers at this source. 

Air Preheat & Economizers

Energy efficiency can be increased by using waste heat gas recovery systems to capture and 

utilize heat in the flue gas. The most commonly used waste heat recovery methods are 

preheating combustion air and water heating via economizer. Economizers and air preheaters 

often occupy a substantial physical footprint.

There are two general types of air preheaters: recuperators and regenerators. Recuperators are 

gas-to-gas heat exchangers usually placed on the boiler stack. Internal tubes or plates transfer 

heat from the outgoing exhaust to the incoming combustion air. Regenerators include two or 

more separate heat storage sections. The hot flue gas heats the heating plates which in turn 

heat the incoming combustion air. General benefits include improved efficiency and faster 

startup. Efficiency typically increases by 1% for each 40 °F reduction in flue gas temperature.

In an economizer, tubular heat transfer surfaces preheat the boiler feedwater before it enters the 

steam drum or furnace surfaces. Economizers also reduce the potential of thermal shock and 

strong water temperature fluctuations as the feedwater enters the drum or waterwalls. 

Economizers are typically installed on larger units. Air preheaters typically increase efficiency by 

1% for each 40 °F reduction in flue gas temperature. Economizers typically operate at a thermal 

efficiency of 5%.

Air preheaters are not widely used for industrial, commercial, or institutional boilers as the 

resulting increases in combustion temperature contribute to elevated emissions of NOX. The 

auxiliary boilers will be equipped with an economizer.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Improved Combustion Measures: Optimization & Digital Control System is a technically 

feasible option for the Auxiliary Boilers at this source. 

Turbulators for Firetube Boilers

Turbulators create turbulence within the firetubes to improve heat transfer characteristics. An 

array of baffles, blades, or coiled wires disturbs the laminar boundary layer within the firetubes, 

resulting in increased convective heat transfer. Turbulators are often considered a more 

economic alternative to economizers or air preheaters. Turbulators are typically installed on older 

firetube boilers operating with fewer tube passes than newer boilers given that multi-pass boilers 

utilize a greater heat transfer area and are inherently more efficient. Efficiency typically increases 

by 1% for each 40 °F reduction in flue gas temperature. Turbulators are substitutes for more 

costly economizers or air preheaters. As the selected boilers will already come equipped with an 

economizer, the turbulator was not considered to be necessary.
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Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of turbulators for fireture boiler is a technically feasible option for the Auxiliary Boilers at 

this source. 

Boiler Insulation

Significant heat losses can occur through the boiler shell. Proper insulation is used to minimize 

such losses. The refractory material lining inside the boiler is the primary insulating material, but 

properly applied insulation on the outer boiler surface can also reduce heat losses.

Insulation is categorized as either mass or reflective type depending on whether it is intended to 

reduce conductive or radiative heat transmission, respectively. Radiation losses tend to increase 

with decreasing load and can be as high as 7% for small units or for larger units operating at 

reduced loads. The Thermal Insulation Manufacturers' Association provides guidance for 

determining the optimum insulation thickness for various applications. Up to 7%, varying by boiler 

load. Energy efficient refractory will be installed.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of boiler insulation is a technically feasible option for the Auxiliary Boilers at this source. 

Minimization of Air Infiltration

Air infiltration occurs as a result of the large temperature difference between the hot combustion 

gases and the ambient air; the resulting pressure differential draws ambient air into the system 

through leaks such as warped doors or cracked casings/ductwork. Indications of excessive air 

leakage include elevated oxygen levels at the boiler outlet, elevated fuel consumption, and 

elevated gas temperatures.

The severity and source of the leaks determines whether the issue may be addressed as part of 

routine maintenance (e.g., door seal adjustments) or as part of planned outages (e.g., cracked 

casing repairs). Maintenance of boiler systems to minimize air leakage is a universally applicable 

approach.

The opportunity for improvement is a function of the leakage reduction and associated reduction 

in excess air. For example, a 3% change in oxygen levels in a gas-fired boiler represents 

efficiency improvements of approximately 4%. The expected efficiency improvements from 

reducing air leakage problems in industrial, commercial, and institutional boilers range from 1 to 

4%. As part of the O&M practices, the air handling systems for each boiler will be periodically 

inspected for leaks.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of minimization of air infiltration is a technically feasible option for the Auxiliary Boilers at 

this source. 

Boiler Blowdown Heat Exchange

Waste heat from the boiler blowdown stream can be recovered with a heat exchanger, a flash 

tank, or flash tank in combination with a heat exchanger. The resulting low-pressure steam is 

most typically used in deaerators. Cooling the blowdown has the additional advantage of 

reducing the temperature of the liquids released into the sewer system.

Blowdown can be either intermittent bottom blowdown or continuous blowdown. Intermittent 

bottom blowdown may be sufficient if the feedwater is exceptionally pure. Intermittent blowdown 

is performed manually and therefore may result in wide fluctuations in blowdown patterns. Use of 

continuous rather than intermittent blowdown saves treated boiler water and can result in 

significant energy savings.

High blowdown rates and boiler pressures are ideal conditions for blowdown recovery. Any boiler 
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with continuous blowdown exceeding 5% of the steam rate exhibits significant potential for 

blowdown waste heat recovery. Manufacturers specified that a 1% thermal efficiency can be 

achieved by this method. In certain cases, significant energy savings can be accomplished by 

recovering heat from boiler blowdown. 

Site-specific conditions and economic considerations must be addressed to determine whether 

this measure involving heat recovery is technically and economically viable; it is necessary to 

consider its viability on a case-by-case basis.

Expected efficiency improvements vary based on boiler blowdown rate and boiler pressure.

The proposed natural gas boilers are stand-by, auxiliary units that are not intended to operate a 

significant number of hours. As such, a blowdown heat exchanger is not economically feasible.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of boiler blowdown heat exchange is a technically feasible option for the Auxiliary Boilers 

at this source. 

Condensation Return System

Hot condensate that is not returned to the boiler represents a corresponding loss of energy. 

Other benefits associated with an efficient condensate return system include reduced make-up 

water usage, water related treatment costs, boiler blowdown, and disposal costs. Energy savings 

originate from the fact that most condensate is returned at relatively high temperatures (typically 

130 to 225 °F) compared to the cold makeup water (50 to 60 °F) that must be heated, but must 

also account for the “steam flash loss” - the amount of saturated condensate that flashes off to 

steam when reduced to a lower pressure. Operation of the return condensate system depends 

on the specific boiler and water/condensate quality. Site-specific conditions and economic 

considerations must be addressed to determine whether it would be applicable, and, therefore, it 

is necessary to consider its viability on a case-by-case basis.

A further improvement on recovering the available energy of the condensate may be to use a 

heat exchanger (vent condenser) where the flashing steam is typically vented. Site-specific 

evaluation is necessary before determining the viability of this approach.

Expected efficiency improvements vary based on condensate temperature and % recovery.

The selected package boilers will be equipped with a condensate return system.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of condensation return system is a technically feasible option for the Auxiliary Boilers at 

this source. 

Minimization of Gas-side heat Transfer Surface Deposits

To minimize deposition on boiler heat transfer surfaces, the boiler must be operated within its 

design parameters. In practice, this may include the application of restrictions for fuel quality and 

firing rates. Boilers firing ash-laden fuels may be equipped with soot blowers to periodically 

remove the unavoidable deposition on the boiler walls and tubes and may utilize fuel treatment to 

mitigate the deposition propensity of the ash and combustion products.

Advanced soot blowing systems can be calibrated to activate automatically in response to 

feedback signals (e.g., exit gas temperature, heat transfer sensors) to optimize operations and 

effectiveness.

The relationship between deposits and heat transfer deterioration varies with the type of fuel and 

ash characteristics. For example, ash deposits of similar thickness will have different impacts on 

heat transfer based on the refractory characteristics of the individual ashes. The extent to which 

dirty heat transfer surfaces affect efficiency can be estimated from an increase in stack 
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temperature relative to a “clean operation” or baseline condition. Efficiency is reduced by 

approximately 1% for every 40 °F increase in stack temperature. Changes in exit gas 

temperatures of over 120 °F due to boiler slagging and fouling would correspond to about a 3% 

decrease in efficiency. Excessive slagging may also affect the outlet steam conditions of the 

boiler (i.e., reducing steam temperatures or necessitating the installation of attemperation 

sprays).

Efficiency gains of 1 - 3% may be gained within industrial, commercial, and institutional boilers by 

minimizing boiler surface deposition. 

Natural gas-fired boilers do not typically employ soot blowing systems given the reduced ash 

content of gaseous fuels.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of minimization of gas-side heat transfer surface deposits is a technically feasible option 

for the Auxiliary Boilers at this source. 

Steam Line Maintenance

Heat losses through uninsulated lines and fittings can be significant. For example, 250 ft of 

uninsulated, 4-inch line with 300 psig steam would yield 2,800 MMBtu/yr, the equivalent of about 

0.3 to 1.2% heat loss for boiler sizes between 25 and 100 MMBtu/hr. Similarly, the penalties for 

leaky valves/traps can represent measurable losses. General experience suggests that steam 

systems that do not include steam trap maintenance over a period of 3 to 5 years can result in 15 

- 30% steam trap failures. Leaking traps should account for less than 5% of the trap population at 

plants with regular inspection and maintenance programs for steam traps.

Energy audits and maintenance procedures should highlight common maintenance items such as 

uninsulated steam distribution and condensate return lines and other fittings. Ensuring that all 

steam/condensate lines are properly insulated will yield measurable efficiency gains. Common 

practice suggests that surfaces over 120 °F (steam and condensate return piping, fittings) should 

be insulated. Insulating jackets are available for valves, traps, flanges and other fittings. Leaky 

steam traps should be fixed as they represent another potentially significant source of wasted 

energy. Energy efficiency gains and cost depend on length and type of insulation required.

Steam and hot water lines will be insulated. As part of the O&M practices, the steam system 

components and insulation will be periodically inspected for leaks. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of stream line maintenance is a technically feasible option for the Auxiliary Boilers at this 

source. 

Alternative Fuels-Biomass/Co-firing

The potential on-site reduction in CO2 emissions that may be realized by switching from a 

traditional fossil fuel to a biomass fuel is based on the specific emission factor for the fuel as 

related to its caloric value. Pure biomass fuels include animal meal, waste wood products and 

sawdust, and sewage sludge. It may also be possible to use biomass materials that are 

specifically cultivated for fuel use, such as wood, grasses, green algae, and other quick growing 

species.

Gas co-firing involves modification of the combustion system to accommodate the introduction of 

natural gas or biomass-derived gas. The co-fired fuel is injected directly into the combustion 

zone. Co-firing of natural gas or biofuels does not present any technical issues which cannot be 

addressed through appropriate design. In most cases, the issues associated with these fuels 

relate to economic attractiveness, availability of biofuels, and availability of natural gas at the 

plant site.
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Technically infeasible for solid and liquid biomass fuels - boiler design will not be capable of cofiring solid or liquid. Feasible for gaseous biomass fuels. Co-firing of gaseous biomass fuels will 

result in only a minor decrease in GHG emissions.

Availability of gaseous biomass based fuels is limited such that a consistent supply of fuel cannot 

be assured over the life of the boilers. In addition, the combustion of biomass based fuels can 

affect compliance with BACT limits for other pollutants, such as NOX and CO. Therefore, the 

boilers will be initially constructed and operated to utilize only natural gas. Should a consistent, 

reliable source of gaseous biomass based fuels become available, use of these fuels will be 

evaluated on an individual basis.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of alternative fuels-biomass/co-firing is not a technically feasible option for the Auxiliary 

Boilers at this source. 

Fuel Switching

Fuel switching refers to a change in the plant hardware to accommodate complete replacement of 

one fuel with another fuel. Coal could be switched to oil, natural gas, or coal-derived gas; and oil 

could be switched to natural gas or coal-derived gas to achieve emissions reductions. Technically 

infeasible - does not apply to the natural gas combustion units.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of fuel switching is not a technically feasible option for the Auxiliary Boilers at this source. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the technical feasibility analysis in Step 2, the remaining control technologies may be 

ranked as follows for controlling GHG emissions from the Auxiliary Boilers.

(1) Boiler Insulation; (7% CO2 Reduction)

(2) Efficient Burner Design (6% CO2 Reduction)

(3) Air Preheat & Economizers; (5% CO2 Reduction)

(4) Improved Combustion Measures: Optimization & Digital Control System; (0.5-5% CO2

Reduction)

(5) Minimization of Air Infiltration; (4% CO2 Reduction)

(6) Improved Combustion Measures: Combustion Tuning; (3% CO2 Reduction)

(7) Minimization of Gas-side heat Transfer Surface Deposits; (1-3% CO2 Reduction)

(8) Turbulators for Firetube Boilers; (1% CO2 Reduction)

(9) Steam Line Maintenance;

(10) Operating and Maintenance (O&M) Practices;

(11) Condensation Return System;
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Step 4: Evaluate the Most Effective Controls and Document the Results

Operation and maintenance according to the manufacturer's emission-related instructions or per 

a facility-developed maintenance plan (in a manner consistent with safety and good air pollution 

control practices for minimizing emissions) will prevent generation of additional GHG emissions 

due to efficiency losses over the lifetime of each piece of combustion equipment. Efficient burner 

designs will be employed, taking into account the size, fuel flexibility, operating loads, and other 

site specific conditions and objectives for each piece of combustion equipment. As part of the 

O&M practices, the air handling systems for each boiler will be periodically inspected for leaks

and combustion tuning of boilers will be conducted on an as-needed basis to address any 

decreases in boiler efficiency over time.

The proposed natural gas boilers are stand-by, auxiliary units that are not intended to operate a 

significant number of hours. As such, a blowdown heat exchanger is not economically feasible.

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for GHG emissions from the proposed auxiliary 

boilers:

(1) Operating and Maintenance (O&M) Practices;

(2) Combustion Turning; 

(3) The boiler will be equipped with oxygen trim controls and oxygen analyzers;

(4) The boiler will be equipped with an economizer;

(5) Energy efficient refractory will be installed;

(6) The boiler will be equipped with a condensate return system (recovery);

(7) Steam and hot lines will be insulated;

(8) Boiler designed for 80% thermal efficiency (HHV); and

(9) The total CO2e emissions from the two auxiliary boilers shall not exceed 81,996 tons of 

CO2e per twelve (12) consecutive month period with compliance determined at the end 

of the month.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for the GHG for the Auxiliary Boilers:

(1) Operating and Maintenance (O&M) Practices;

(2) Combustion Turning; 

(3) The boiler will be equipped with oxygen trim controls and oxygen analyzers;

(4) The boiler will be equipped with an economizer;

(5) Energy efficient refractory will be installed;

(6) The boiler will be equipped with a condensate return system (recovery);

(7) Steam and hot lines will be insulated;

(8) Boiler designed for 80% thermal efficiency (HHV); and
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(9) The total CO2e emissions from the two auxiliary boilers shall not exceed 81,996 tons of 

CO2e per twelve (12) consecutive month period with compliance determined at the end 

of the month.

GHGs BACT – Emergency Generators

Step 1: Identify Potential Control Technologies

The CO2 is by far the dominant GHG from this source. CH4 and N2O are present only in very 

small amounts, are incidental to combustion, and trend with the CO2 emissions. There are no 

known supplemental controls for N2O or methane emissions from diesel engines. To the extent 

measures are identified that reduce CO2, the other GHGs may be also reduced accordingly. 

Therefore, this BACT analysis focused on CO2 as a surrogate for all GHG emissions.

Diesel fuel is used because it is an independent source of fuel not related to the operation of the 

facility. As such, it is the most reliable fuel source and its use in this application is fundamental to 

meeting power and water requirements in an emergency situation. For this reason, it is the most 

common fuel used for these types of emergency backup applications. 

GHG control possibilities identified and addressed in this BACT analysis for these small engines

are:

(1) Good engineering design and Fuel efficient design; and 

 

(2) Post combustion carbon capture

Step 2: Eliminate Technically Infeasible Options

Good Engineering Design and Fuel Efficient Design

The source will install engines meeting the latest efficiency and pollutant performance standards 

specified in NSPS Part 60 Subpart IIII and NESHAP Part 63 Subpart ZZZZ. These Diesel engines 

are built with automatic control of the air to fuel ratio that ensures that they operate when needed

and meet the applicable standards. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Good engineering design and Fuel efficient design is a technically feasible option for 

the Emergency generators at this source. 

Carbon Capture

Post-combustion CO2 capture is a relatively new concept. In EPA’s recent GHG BACT guidance, 

EPA takes the position that, “for the purpose of a BACT analysis for GHGs, EPA classifies CCS 

as an add-on pollution control technology that is “available” for large CO2-emitting facilities 

including fossil fuel-fired power plants and industrial facilities with high-purity CO2 streams”. The 

source combustion sources such as the emergency engines do not fit into either of the above 

categories called out by EPA’s guidance document as appropriate for consideration of CCS. The 

EPA guidance document provides little specific guidance on whether or how to consider CCS in 

situations outside of the above examples. However, relevant guidance can be discerned from the 

Appendix F to the above referenced US EPA guidance document, which presents an example 

GHG BACT analysis for a 250 MMBtu/hr natural gas fired boiler. In this US EPA boiler example, 

carbon capture isn’t listed or considered in the BACT analysis as a potentially available option.

The absence of a discussion of carbon capture in this 250 MMBtu/hr boiler example is consistent 

with the fact that carbon capture is extremely expensive, has numerous technical challenges, and 

is currently only being contemplated on very large or very concentrated CO2 sources. In stark 
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contrast, the source's Project miscellaneous combustion sources are an order of magnitude 

smaller than EPA’s example, and significantly smaller still than the categories that US EPA’s 

guidance document suggests should consider CCS. 

A CO2 capture system for the emergency diesel engines is not a reasonable BACT option 

because the capture of the CO2 from combustion exhaust of small sources is significantly more 

difficult than from the types of industrial gas streams that EPA references as having potential for 

CCS. The increased difficulty is due to four factors: low CO2 concentration, low pressure, low 

quantity of CO2 available for capture, and the variability of load for these units. 

The low concentration and low pressure of the exhausts from these processes complicate the 

absorption and desorption of the CO2, which increases the energy required. Also, a low pressure 

absorption system creates a low pressure CO2 stream which requires a very high energy demand 

for compression prior to transport. All these factors make the application of CO2 capture on any 

small combustion exhaust extremely difficult and expensive. Additionally, the cost of capturing 

CO2 for smaller sources is more expensive due to the lack of economy-of-scale. Further, the 

emergency engines are intermittent sources, which would further increase the cost and difficulty 

of implementing any control.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of post-combustion capture of CO2 is not a technically feasible option for the Emergency 

generators at this source. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The only feasible, applicable and available control technology identified to reduce greenhouse 

gases from the emergency diesel generators engines is to utilize good engineering design and 

fuel efficient design. 

Step 4: Evaluate the Most Effective Controls and Document the Results

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for GHG emissions from the proposed Emergency 

generators engines: the selection and use of good engineering design and fuel efficient design.

This project includes two (2) diesel-fired 750 KW and one (1) diesel-fired 1,500 KW standby 

emergency generators. These engines are required for safety reasons. Each engine is expected 

to operate less than 500 hours per year each. That use is associated with assuring their 

readiness in an emergency. These emergency diesel engines will have the potential to emit 

greenhouse gases (CO2, CH4, and N2O) because they will combust a hydrocarbon fuel. 

However, because their normal use is limited to routine maintenance, inspection and testing, their 

total emissions are very small (less than 600 tons CO2e/yr, each). 

The following has been proposed as BACT for GHG emissions from the proposed Emergency 

Diesel Generators:

(1) The use of a good engineering design and fuel efficient design; and 

(2) The total CO2e emissions from all the three (3) emergency diesel generators shall be 

limited to less than 1,200 tons of CO2e per twelve (12) consecutive month period with 

compliance determined at the end of the month.
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Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for the GHG for the Emergency Diesel Generators:

(1) The use of a good engineering design and fuel efficient design; and 

(2) The total CO2e emissions from all the three (3) emergency diesel generators shall not 

exceed 1,186 tons of CO2e per twelve (12) consecutive month period with compliance 

determined at the end of the month.

GHGs BACT – Firewater Pumps 

Step 1: Identify Potential Control Technologies

The CO2 is by far the dominant GHG from this source. CH4 and N2O are present only in very 

small amounts, are incidental to combustion, and trend with the CO2 emissions. There are no 

known supplemental controls for N2O or methane emissions from diesel engines. To the extent 

measures are identified that reduce CO2, the other GHGs may be also reduced accordingly. 

Therefore, this BACT analysis focused on CO2 as a surrogate for all GHG emissions.

Diesel fuel is used because it is an independent source of fuel not related to the operation of the 

facility. As such, it is the most reliable fuel source and its use in this application is fundamental to 

meeting power and water requirements in an emergency situation. For this reason, it is the most 

common fuel used for these types of emergency backup applications. 

GHG control possibilities identified and addressed in this BACT analysis for these small engines

are:

(1) Good engineering design and Fuel efficient design; and 

 

(2) Post combustion carbon capture

Step 2: Eliminate Technically Infeasible Options

Good Engineering Design and Fuel Efficient Design

The source will install engines meeting the latest efficiency and pollutant performance standards 

specified in NSPS Part 60 Subpart IIII and NESHAP Part 63 Subpart ZZZZ. These Diesel engines 

are built with automatic control of the air to fuel ratio that ensures that they operate when needed

and meet the applicable standards. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Good engineering design and Fuel efficient design is a technically feasible option for 

the Firewater pumps at this source. 

Carbon Capture

Post-combustion CO2 capture is a relatively new concept. In EPA’s recent GHG BACT guidance, 

EPA takes the position that, “for the purpose of a BACT analysis for GHGs, EPA classifies CCS 

as an add-on pollution control technology that is “available” for large CO2-emitting facilities 

including fossil fuel-fired power plants and industrial facilities with high-purity CO2 streams”. The 

source combustion sources such as the emergency engines do not fit into either of the above 

categories called out by EPA’s guidance document as appropriate for consideration of CCS. The 

EPA guidance document provides little specific guidance on whether or how to consider CCS in 
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situations outside of the above examples. However, relevant guidance can be discerned from the 

Appendix F to the above referenced US EPA guidance document, which presents an example 

GHG BACT analysis for a 250 MMBtu/hr natural gas fired boiler. In this US EPA boiler example, 

carbon capture isn’t listed or considered in the BACT analysis as a potentially available option.

The absence of a discussion of carbon capture in this 250 MMBtu/hr boiler example is consistent 

with the fact that carbon capture is extremely expensive, has numerous technical challenges, and 

is currently only being contemplated on very large or very concentrated CO2 sources. In stark 

contrast, the source's Project miscellaneous combustion sources are an order of magnitude 

smaller than EPA’s example, and significantly smaller still than the categories that US EPA’s 

guidance document suggests should consider CCS. 

A CO2 capture system for the emergency diesel engines is not a reasonable BACT option 

because the capture of the CO2 from combustion exhaust of small sources is significantly more 

difficult than from the types of industrial gas streams that EPA references as having potential for 

CCS. The increased difficulty is due to four factors: low CO2 concentration, low pressure, low 

quantity of CO2 available for capture, and the variability of load for these units. 

The low concentration and low pressure of the exhausts from these processes complicate the 

absorption and desorption of the CO2, which increases the energy required. Also, a low pressure 

absorption system creates a low pressure CO2 stream which requires a very high energy demand 

for compression prior to transport. All these factors make the application of CO2 capture on any 

small combustion exhaust extremely difficult and expensive. Additionally, the cost of capturing 

CO2 for smaller sources is more expensive due to the lack of economy-of-scale. Further, the 

emergency engines are intermittent sources, which would further increase the cost and difficulty 

of implementing any control.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of post-combustion capture of CO2 is not a technically feasible option for the Firewater 

pumps at this source. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The only feasible, applicable and available control technology identified to reduce greenhouse 

gases from the firewater pump diesel engines is to utilize good engineering design and fuel 

efficient design. 

Step 4: Evaluate the Most Effective Controls and Document the Results

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for GHG emissions from the proposed Firewater 

pump diesel engines: the selection and use of good engineering design and fuel efficient design.

This project includes two (2) diesel-fired 371 hp standby fire water pumps. These engines are 

required for safety reasons. Each engine is expected to operate less than 500 hours per year 

each. That use is associated with assuring their readiness in an emergency. These emergency 

diesel engines will have the potential to emit greenhouse gases (CO2, CH4, and N2O) because 

they will combust a hydrocarbon fuel. However, because their normal use is limited to routine 
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maintenance, inspection and testing, their total emissions are very small (less than 100 tons 

CO2e/yr, each). 

The following has been proposed as BACT for GHG emissions from the proposed Firewater 

Pump Engines:

(1) The use of a good engineering design and fuel efficient design; and 

(2) The total CO2e emissions from all the two (2) firewater pump engines shall be limited to 

less than 180 tons of CO2e per twelve (12) consecutive month period with compliance 

determined at the end of the month.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for the GHG for the Firewater Pump Engines:

(1) The use of a good engineering design and fuel efficient design; and 

(2) The total CO2e emissions from all the two (2) firewater pump engines shall not exceed

172 tons of CO2e per twelve (12) consecutive month period with compliance determined 

at the end of the month.

GHGs BACT – Circuit Breakers SF6

Step 1: Identify Potential Control Technologies

GHG control possibilities identified and addressed in this BACT analysis for these small potential 

sources are:

(1) Alternative Technology.

(2) Alternative Dielectric Material.

Step 2: Eliminate Technically Infeasible Options

Alternative Technology

The use of fully enclosed circuit breakers with leak detection (low pressure alarm) is state-of-theart for circuit breakers and is proposed by SJEC. A low pressure alarm is installed on each 

breaker to alert operators of a loss of SF6 gas. Operators will investigate the cause of any alarm 

and take corrective measures to stop the leak if one exists. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of alternative technology is a technically feasible option for the Circuit Breaker at this 

source.

Alternative Dielectric Material

There is no practical alternative to the use of SF6 as the insulator and arc quenching substance in 

SJEC’s circuit breakers. The unique performance qualities of SF6 breakers is further supported 

by the most recent report released by the EPA SF6 Partnership, which states: “no clear 

alternative exists for this gas that is used extensively in circuit breakers, gas-insulated 

substations, and switch gear, due to its inertness and dielectric properties.” Research and 

development efforts have focused on finding substitutes for SF6 that have comparable insulating 
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and arc quenching properties in high-voltage applications. While some progress has reportedly 

been made in medium- or low-voltage applications, most studies have concluded, “that there is 

no replacement gas immediately available to use as an SF6 substitute” for high-voltage 

applications. Therefore, the use of a breaker that doesn’t contain SF6 is judged as not feasible 

for this application.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Alternative Dielectric Material is not a technically feasible option for the Circuit Breaker

at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) The use of totally enclosed and pressurized circuit breakers with a density alarm for leak 

detection.

Step 4: Evaluate the Most Effective Controls and Document the Results

Proposal: St. Joseph Energy Center, LLC – New Carlisle, Indiana

The following has been proposed as BACT for GHGs from the proposed Electric Circuit Breaker:

(1) The use of totally enclosed and pressurized circuit breakers with a design leak rate of 

0.5% and a density alarm for leak detection.

(2) The total SF6 emissions from all the circuit breakers shall be limited to less than 0.0009

tons of SF6 per twelve (12) consecutive month period with compliance determined at the 

end of the month.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for GHGs for Electrical Circuit Breaker.

(1) The use of totally enclosed pressure system with a design leak rate of 0.5% and a 

density alarm for leak detection.

(2) The total SF6 emissions from all the circuit breakers shall not exceed 0.0009 tons of SF6

per twelve (12) consecutive month period with compliance determined at the end of the 

month.
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Best Available Control Technology during Startup and Shutdown for the 

Combustion Turbines, identified as CCCT1-CCCT4.

(a) A startup is defined as the operation in the period beginning when continuous fuel flow to 

the combustion turbine is initiated and ending when the CCCT achieves consecutive 

CEMS data points in compliance with the primary BACT limits.

(b) Steady-state operating condition shall be defined as the period of time that the 

combustion turbine is operating in dry low NOx (premix) mode and in compliance with the 

primary BACT limit.

(c) A shutdown is defined as operation beginning when the combustion turbine exits dry lowNOx (premix) mode and ending with termination of continuous fuel flow to each turbine.

(d) A startup/shutdown cycle is a pair of subsequent shutdown and startup events (i.e., one 

startup followed by one shutdown represents one startup/shutdown cycle).

(e) Unit Offline is represented by the Unit on-line Time being 0. 

(f) The following records shall be kept by the source:

(1) Number of minutes in each hour that the unit is in startup mode. 

 

(2) Number of minutes in each hour that the unit is in shutdown mode. 

(3) Records shall be maintained at any time the unit is off-line. 

(g) An event is defined as: 

(1) exactly one (1) startup or exactly one (1) shutdown

For CO and NOX, the source determined the worst-case operating scenario that results in 

the highest modeled impacts to be a cold start of the CCCTs. The modeled cold start 

emission rates are based on startup emission totals provided by the turbine vendor. 

Therefore, the source proposes to use the cold start emission totals, per CCCT as a 

short-term limit during startup/shutdown events, as follows:

CO - 2,125 lb/event

NOx - 443 lb/event

(h) The NOX emissions from the combined cycle combustion turbines stacks shall not 

exceed 81.6 tons per twelve (12) consecutive month period, for the duration of the 

combined startup and shutdown events, with compliance determined at the end of each 

month. 

(i) The CO emissions from the combined cycle combustion turbines stacks shall not exceed 

407.5 tons per twelve (12) consecutive month period, for the duration of the combined 

startup and shutdown events, with compliance determined at the end of each month. 

(j) The VOC emissions from the combined cycle combustion turbines stacks shall not 

exceed 22.0 tons per twelve (12) consecutive month period, for the duration of the 

combined startup and shutdown events, with compliance determined at the end of each 

month. 
Air Quality Analysis

St Joseph Energy Center, LLC

New Carlisle, Indiana (St. Joseph County)

Tracking and Plant ID: 141-31003-00579

Proposed Project

St Joseph Energy Center, LLC (SJE) first submitted their PSD modeling in October 2011. SJE

proposes to construct and operate a 1,200 megawatt (MW) combined cycle combustion turbine (CCCT) 

electric generating facility in St Joseph County, in New Carlisle, Indiana.

Trinity Consultants (Trinity) was the consultant who prepared the modeling portion of the permit 

application for SJE. This technical support document provides the air quality analysis review of the 

submitted modeling by Trinity for SJE but revised by the Indiana Department of Environmental 

Management (IDEM).

Analysis Summary

Based on the potential emissions after controls, a PSD air quality analysis was triggered for

SO2, PM10, PM2.5, CO, NO2, and sulfuric acid mist. The significant impact analysis for CO, SO2, PM10, 

and annual NO2 determined that modeling concentrations did not exceed the significant impact levels. A 

refined analysis was required for the 1-hour NO2 and PM2.5 standards. No NAAQS violations were 

modeled for NO2. NAAQS violations did occur for the 24-hour PM2.5 but SJE was below significance 

whenever the violations occurred. SJE was below the 24-hour PM10 as well as both annual and 24-hour

PM2.5 PSD increment. Pre-construction monitoring requirements are not necessary since existing 

monitoring is available. Hazardous Air Pollutants were below the 25 ton per year total and 10 ton per 

year individual pollutant thresholds. An additional impact analysis was conducted and showed no 

significant impact.

Air Quality Impact Objectives

The purpose of the air quality impact analysis in the permit application is to accomplish the 

following objectives. Each objective is individually addressed in this document in each section outlined 

below.

A. Establish which pollutants require an air quality analysis based on PSD significant emission 

rates.

B. Provide analyses of actual stack heights with respect to Good Engineering Practice (GEP), 

the meteorological data used, a description of the model used in the analysis, and the 

receptor grid utilized for the analyses. 

C. Determine the significant impact level, the area impacted by the source's emissions, and 

background air quality levels.

D. Demonstrate that the source will not cause or contribute to a violation of the National 

Ambient Air Quality Standard (NAAQS) or PSD increment if the applicant exceeds 

significant impact levels.
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E. Perform a qualitative analysis of the source's impact on general growth, soils, vegetation,

and visibility in the impact area with emphasis on any Class I areas. The nearest Class I 

area is Kentucky's Mammoth Cave National Park.

F. Analysis of Secondary Ozone formation

G. Analysis of Secondary PM2.5 formation

H. Summarize the Air Quality Analysis

Section A - Pollutants Analyzed for Air Quality Impact

Applicability

The PSD requirements, 326 IAC 2-2, apply in attainment and unclassifiable areas and require an 

air quality impact analysis of each regulated pollutant emitted in significant amounts by a major stationary 

source or modification. Significant emission levels for each pollutant are defined in 326 IAC 2-2-1 and in 

the Code of Federal Regulations (CFR) 52.21(b) (23) (i). 

Proposed Project Emissions

PM10, PM2.5, NO2, SO2, Sulfuric Acid Mist and CO are the pollutants that will be emitted from SJE 

and are summarized below in Table 1. PM10, PM2.5, NO2, SO2, and CO potential emissions after controls

exceed the PSD Significant Emission Rates and therefore require an air quality analysis. Sulfuric acid 

mist also exceeds the PSD Significant Emission Rate but does not require an air quality impact analysis 

under current PSD regulations.

TABLE 1

Significant Emission Rates for PSD

POLLUTANT SOURCE EMISSION RATE

(Facility totals in tons/year)

SIGNIFICANT EMISSION 

RATE

(tons/year)

PRELIMINARY AQ ANALYSIS 

REQUIRED

PM10 343.4 15 Yes

PM2.5 339.3 10 Yes

NO2 291.7 40 Yes

SO2 93.0 40 Yes

CO 554.5 100 Yes

Sulfuric Acid Mist1 71.8 7 No1

1 Sulfuric Acid Mist has no monitoring threshold or National Ambient Air Quality Standard. No AQ analysis is required 

for Sulfuric Acid Mist under the PSD regulations.
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Section B – Good Engineering Practice (GEP), Met Data, Model Used, Receptor 

Grid and Terrain

Stack Height Compliance with Good Engineering Practice (GEP) 

Stacks should comply with GEP requirements established in 326 IAC 1-7-4. If stacks are lower 

than GEP, excessive ambient concentrations due to aerodynamic downwash may occur. Dispersion 

modeling credit for stacks taller than 65 meters (213 feet) is limited to GEP for the purpose of establishing 

emission limitations. The GEP stack height takes into account the distance and dimensions of nearby 

structures, which affects the downwind wake of the stack. The downwind wake is considered to extend 

five times the lesser of the structure's height or width. A GEP stack height is determined for each nearby 

structure by the following formula:

Hg = H + 1.5L

Where: Hg is the GEP stack height

H is the structure height

L is the structure's lesser dimension (height or width)

New Stacks

Since all of the new stack heights for SJE are below GEP stack height, the effect of aerodynamic 

downwash is accounted for in the air quality analysis for the project.

Meteorological Data

The National Weather Service (NWS) 1-minute Automated Surface Observation Station (ASOS) 

meteorological data used in the air quality analysis consisted of 2006 through 2010 surface data from 

South Bend, Indiana and upper air measurements taken at Lincoln, Illinois. The meteorological data was 

preprocessed using the latest versions of AERMINUTE, AERSURFACE, and AERMET.

Model Description

The Office of Air Quality (OAQ) used AERMOD version 12060 in their air quality analysis review 

to determine maximum off-property concentrations or impacts for each pollutant. All regulatory default 

options were utilized in the U.S. EPA approved model, as listed in the 40 Code of Federal Register Part 

51, Appendix W “Guideline on Air Quality Models”.

Receptor Grid

OAQ modeling used the same receptor grids generated by Trinity. The receptor grid is outlined 

below:

• 100 meter spacing along the facility’s property boundary,

• 100 meter spacing from the property boundary to 3000 meters,

• 500 meters spacing from 3000 meters to 10000 meters.

• 1000 meters spacing from 10000 meters to 20000 meters

• 2500 meters spacing from 20000 meters to 50000 meters

Treatment of Terrain 

Receptor terrain elevation inputs were interpolated from NED (National Elevation Dataset) data 

obtained from the USGS. NED terrain data was preprocessed using AERMAP. 
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Section C - Significant Impact Level/Area (SIA) and Background Air Quality Levels

A significant impact analysis was conducted to determine if the source would exceed the PSD 

significant impact levels (concentrations). Depending on pollutant and averaging times, either 16 or 25 

different operating scenarios were modeled and the highest impacts were considered. A complete 

discussion of the different operating scenarios can be found in their application. If the source's

concentrations exceed these significant impact levels, further air quality analysis is required. Refined 

modeling for CO, SO2 , PM10,and annual NO2 was not required because the results did not exceed 

significant impact levels. The PM2.5 and 1-hour NO2 exceeded their significant impact levels and required

refined modeling. Significant impact levels are defined by the following time periods in Table 2 below,

with all maximum-modeled concentrations from the worst case operating scenarios. A Tier II 80% 

conversion of NO to NO2 was assumed based on the March 01, 2011, Tyler Fox memorandum. 

TABLE 2

Significant Impact Analysis3

POLLUTANT TIME AVERAGING 

PERIOD

MAXIMUM MODELED 

IMPACTS (ug/m3

)

SIGNIFICANT IMPACT 

LEVEL (ug/m3

)

REFINED AQ ANALYSIS 

REQUIRED

NO2 Annual1 0.97 1 No

NO2 1-hour2 105.9 7.55 Yes

PM10 Annual1 0.49 1 No

PM10 24-hour1 4.8 5 No

PM2.5 Annual2 0.47 0.3 Yes

PM2.5 24-hour2 4.7 1.2 Yes

SO2 3-hour1 2.9 25 No

SO2 24-hour1 1.2 5 No

SO2 Annual1 0.11 1 No

SO2 1-hour2 5.0 7.80 No

CO 1-hour1 627 2000 No

CO 8-hour1 129 500 No

1

First highest values per EPA NSR manual October 1990. 2 In accordance with recent U.S. EPA guidance, the highest modeled concentration may be averaged over the five years modeled 

for comparison with the 1-hour NO2, 1-hour SO2, 24-hour PM2.5, and the annual PM2.5 SIL. See the March 01, 2011 and the March 

23, 2010 memorandums 3

Impacts are from SJE only.

Pre-construction Monitoring Analysis

Applicability

The PSD rule, 326 IAC 2-2-4, requires an air quality analysis of the new source or the major 

modification to determine if the pre-construction monitoring threshold is triggered. In most cases, 

monitoring data taken from a similar geographic location can satisfy this requirement if the preconstruction monitoring threshold has been exceeded. Also, post construction monitoring could be 

required if the air quality in that area could be adversely impacted by applicant’s emissions.
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Modeling Results

The modeling results were compared to the PSD preconstruction monitoring thresholds. The 

results are shown in the table below.

TABLE 3

Preconstruction Monitoring Analysis

POLLUTANT TIME AVERAGING 

PERIOD

MAXIMUM MODELED

IMPACTS (ug/m3

)

DEMINIMIS LEVEL 

(ug/m3

)

ABOVE DE MINIMIS 

LEVEL

NO2 Annual1 0.97 14 No

PM10 24-hour1 4.8 10 No

PM2.5 24-hour2 4.7 4 Yes

SO2 24-hour1 1.2 13 No

CO 8-hour 129 575 No

1

First highest values per EPA NSR manual October 1990. Maximum modeled impacts are from SJE only. 2 In accordance with recent U.S. EPA guidance, the highest modeled concentration may be averaged over the five years. See the 

March 01, 2011 and the March 23, 2010 memorandums from EPA.

NO2, CO, PM10, and SO2 did not trigger the preconstruction monitoring threshold level. SJE can 

satisfy the preconstruction monitoring requirement for PM2.5 since there is existing air quality monitoring 

data representative of the area within St. Joseph County.

Background Concentrations

Applicability

EPA’s “Ambient Monitoring Guidelines for Prevention of Significant Deterioration” (EPA-450/4-87-

007) Section 2.4.1 is cited for approval of the monitoring sites chosen for this area. 

Background Monitors

Background data was taken from representative monitoring stations for SJE. The background design 

value was used for PM2.5. It was agreed between SJE and OAQ that this approach be taken in place of 

the preconstruction monitoring requirement.
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TABLE 4

Existing Monitoring Data Used For Background Concentrations *

Pollutant Location Monitoring 

Site

Averaging 

Period

Concentration 

(ug/m3

)

PM2.5

Shields Drive, 

South Bend, IN 18-141-0015 24-hour 28.0

PM2.5

Shields Drive, 

South Bend, IN 18-141-0015 Annual 11.0

NO2

Shields Drive, 

South Bend, IN 18-141-0015 1-hour 69.6

* PM2.5 and NO2 used the design value. 

Section D - NAAQS and PSD Increment

NAAQS Compliance Analysis and Results

OAQ supplied emission inventories of all point sources in Indiana within a 50-kilometer radius of 

SJE. The NAAQS inventories are generated from EMITS (Emission Inventory Tracking System) in 

accordance with 326 IAC 2-6. The PSD increment inventories include sources that affect the increment 

and are compiled from permits issued by OAQ. The Michigan Department of Environmental Quality

supplied emission inventories for Michigan.

OAQ modeling results are shown in Table 5. All maximum-modeled concentrations were 

compared to the respective NAAQS limit. All maximum-modeled concentrations during the five years 

were below the NAAQS limit except for the 24-hour PM2.5 and a culpability analysis was required and is 

shown in Table 6. Results were based on the worst operating scenario determined in SIA modeling.

TABLE 51

NAAQS Analysis

Pollutant Year

TimeAveraging 

Period

Maximum

Concentration 

(ug/m3

)

Background

Concentration (ug/m3

)

Total 

(ug/m3)

NAAQS Limit 

(ug/m3)

NAAQS 

Violation

NO2 2006-2010 1-hour 110.02 69.6 179.6 189 No

PM2.5 2006-2010 24-hour 30.42 28.0 58.4 35 Yes

PM2.5 2006-2010 Annual 0.86 11.0 11.9 15 No

1 Any differences between the maximum concentration numbers in Tables 5 and 6 are due to different sources used for the NAAQS 

and the increment inventories. 2

In accordance with recent U.S. EPA guidance, the highest modeled concentration may be averaged over the five years. See the 

March 23, 2010, memorandum from EPA.
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Table 6

Culpability Analysis

Highest Predicted 24-hour PM2.5 Concentration from Cumulative Analysis for SJE (μg/m3)

Maximum 

Modeled 

Concentration 

SJE + 

Inventory 

Sources

Background 

Design Value 

South Bend, 

IN

Concentration 

(modeled + 

background)

Contribution 

from 

Modeled 

Nearby 

Sources

Contribution 

from SJE at 

peak

Is the Total 

Concentration 

≥ NAAQS of 

35 μg/m3

?

Is the SJE

contribution 

≥ SIL of 1.2

μg/m3

?

29.0 28.0 57.0 29.0 0.0 yes no

Every 24-hour modeled exceedence was examined to determine SJE's impact on that day at that 

receptor. A table of these values can be found in the Appendix. Even though the modeled impact plus 

background was over the NAAQS, SJE was never above the significant impact level, and often had 0.0 

ug/m3 impact. Therefore, SJE does not cause or contribute to a violation of the NAAQS. 

Analysis and Results of Source Impact on the PSD Increment

Applicability

Maximum allowable increases (PSD increments) are established by 326 IAC 2-2 for PM2.5. This 

rule also limits a source to no more than 80 percent of available PSD increment to allow for future growth. 

Source Impact

Since the impacts for 24-hr PM10 and 24-hour and annual PM2.5 modeled above significant 

impact levels, a PSD increment analysis for SJE and surrounding sources was required.

Results of the increment modeling are summarized in Table 7 below.

TABLE 71

Increment Analysis

Pollutant Year Time-Averaging 

Period

Maximum 

Concentration 

(ug/m3

)

PSD Increment

(ug/m3

)

Percent Impact on 

the PSD Increment

Increment

Violation

PM2.5 2006-2010 24-hour2 3.16 9 35% NO

PM2.5 2006-2010 Annual 0.47 4 12% NO

PM10 2006-2010 24-hour2 3.25 30 11% NO

1 Any differences between the maximum concentration numbers in Tables 5 and 6 are due to different sources used for the NAAQS 

and the increment inventories. 

2

in accordance with the Federal Register dated October 20, 2010; the high 2nd high is used.

The results of the increment analysis show all pollutants for all averaging periods were below 80% of the 

available increment. No further analysis is required.
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Part E – Qualitative Analysis

Additional Impact Analysis

All PSD permit applicants must prepare an additional impact analysis for each pollutant subject to 

regulation under the Act. This analysis assesses the impacts on growth, soils and vegetation, 

endangered species, and visibility caused by any increase in emissions of any regulated pollutant from 

the source. The SJE modeling submittal provided an additional impact analysis performed by Trinity.

Economic Growth

The purpose of the growth analysis is to quantify project associated growth and estimate the air 

quality impacts from this growth either quantitatively or qualitatively.

Many of the permanent SJE employees will be drawn from the local area. Since the area is 

predominately rural, it is not expected the growth impacts will cause a violation of the NAAQs or the PSD 

increment.

Soils and Vegetation Analysis

Soil types included a variety of loamy soils. Due to the agricultural nature of the land, crops in the 

St. Joseph County area consist mainly of corn and soybeans. (2007 Agricultural Census for St. Joseph

County). The maximum modeled concentrations for SJE are well below the threshold limits necessary to 

have adverse impacts on the surrounding vegetation. Livestock in St. Joseph County consist mainly of 

hogs, cattle and dairy (2007 Agricultural Census for St. Joseph County) and will not be adversely 

impacted from the facility. Trees in the area are mainly hardwoods. These are hardy trees and no 

significant adverse impacts are expected due to modeled concentrations.

Federal and State Endangered Species Analysis

Federal and state endangered species are listed by the U.S. Fish and Wildlife Service; Division of 

Endangered Species for Indiana, and includes 5 amphibians, 27 birds, 10 fishes, 7 mammals, 15 

mollusks, and 15 reptiles. Of the federal and state endangered species on the list, 5 reptiles, 3 mollusks, 

1 fish, 1 insect, 18 birds, 3 amphibians and 7 mammals have habitat within St. Joseph County. The 

mollusks, fish, amphibians, and certain species of birds and mammals are found along rivers and lakes 

while the other species of birds and mammals are found in forested areas. The facility is not expected to 

have any additional adverse effects on the habitats of the species than what has already occurred from 

the industrial, farming, and residential activities in the area.

Federal and state endangered plants are listed by the U.S. Fish and Wildlife Service, Division of 

Endangered Species for Indiana. At this time 27 state endangered plant species (including the Goosefoot Corn-salad and Running Serviceberry) are found in St. Joseph County. The endangered plants do 

not thrive in industrialized and residential areas. The facility is not expected to adversely affect any plant 

on the endangered species list.

Visibility Analysis

Visibility analysis was performed for impacts on local visibility. The VISCREEN model is designed 

as a screening model to determine the visual impact using parameters from a single source's plume. It is 

used basically to determine whether or not a plume is visible as an object itself. The visibility impairment 

analysis considers the impacts that occur within the impact area of the source as defined by the user 

distances. The user distances are determined by the nearest interstate or airport. EPA has defined 
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these locations in guidance to the state.

The PM10 and NOx emissions limits were used to run a local visibility Level 1 and a Level 2 

analysis. VISCREEN Version 1.01 was used to determine if the color difference parameter (Delta-E) or 

the plume (green) contrast limits were exceeded. The Delta-E was developed to specify the perceived 

magnitude of color and brightness changes and is used as the primary basis for determining the 

perceptibility of plume visual impacts. The plume constant can be defined at any wavelength as the 

relative difference in the intensity (called spectral radiance) between the viewed object and its 

background. This is used to determine how the human eye responds differently to different wavelengths 

of light. The Delta-E of 2.0 and the plume contrast of 0.05 were not exceeded at the nearest interstate or 

airport location.

A Level 1 analysis was performed and showed that there might be a potential adverse visual 

impact. A Level 2 analysis was performed using the year with the highest percentage of hours that might 

affect the nearest point of interest, in this case the nearby interstate. 

TABLE 8

Level 2 Visibility Analysis

Background Theta

(degrees)

Azimuth

(degrees)

Distance

(km)

Alpha

(degrees)

Delta E

Critical

Delta E

Plume

Contrast

Critical

Contrast

Plume

Sky 10 84 5.1 84 5.07 0.859 0.08 0.014

Sky 140 84 5.1 84 2.00 0.366 0.08 -0.010

Terrain 10 84 5.1 84 3.33 5.025* 0.08 0.035

Terrain 140 84 5.1 84 2.00 0.805 0.08 0.018

 * This Class II location is above suggested critical value for Class I areas 

A forward-scatter analysis is performed on the closest point of the I-90 highway. The range of 

sun angles over the critical sun elevation (10 degrees) that can occur was calculated using the winter and 

summer solstices. The 10 degree sun elevation is bounded by the sun angles 67.4 degrees (ENE) at 

summer solstice and 134.3 degrees (SE) at winter solstice for sunrise conditions. Thus, any observer at 

any angle between 247.4 degrees (67 + 180), and 314.3 degrees (134.3 + 180) could observe the plume 

at the critical sun elevation. At the closest location to the facility, I-90 is located at an angle of 344 

degrees from the facility. Since I-90 does not fall between the sun angle boundaries, this condition will 

never occur.

For sunset conditions, the 10 degree sun elevation is bounded by the sun angles 225.7 (Winter

Solstice) and 247.4 degrees. (Summer Solstice) Thus any observer at any angle between 45.7 (225.7 -

180) and 67.4 degrees (247.4 - 180) could observe the plume at the critical sun elevation. 344 degrees 

does not lie within that range, so this condition will not occur. 

In a backward scatter analysis, the range of sun angle over which the critical sun elevation (140 

degrees) can occur was calculated using the summer solstice since the sun does not reach 140 during 

the winter solstice. The 140 degree elevation is bounded by the sun angles 93 and 267 degrees. Thus, 

any observer at any angle between 93 and 267 degrees could observe the source with a sun elevation at 

140 degrees. Since I-90 sits at 344 degrees, there will be no adverse impacts on visibility at this location.

Thus, it is concluded that there will be no visibility impacts at the closest location on I-90 from the 

facility.

The Federal Class I areas include national parks and national wilderness areas and are 

considered environments for which minimal air quality degradation is allowed. The nearest Class 1 area 

to SJE is Mammoth Cave National Park which is 490 km from the plant. Pursuant to a new federal 
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guidance document (Federal Land Managers’ Air Quality Related Values Work Group (FLAG) Phase 1 

Report – Revised November 2010), the SJE facility would not be required to conduct a Class 1 area 

analysis since the combined emissions of visibility impairing pollutants are less the screening threshold. 

The visual impact is equal to Q / D, the total emissions divided by distance for sources more than 50 km 

from a Class 1 area. If the number is less than 10, then a visibility analysis is not required. 

The primary visibility impairment pollutants are PM10, SO2, H2SO4, and NOx. The proposed 

potential emissions of these pollutants from SJE are Q = 291.7 + 93.0 + 343.5 + 71.9 TPY = 800 TPY. 

The distance to the nearest Class 1 area is D = 490 km. The source impact is Q / D = 800 / 490 = 1.6. 

1.6 is less than 10, so this project will not affect visibility in the nearest Class 1 area. 

Additional Analysis Conclusions

Finally, the results of the additional impact analysis conclude the operation of the facility will have 

no significant impact on economic growth, soils, vegetation, or visibility in the immediate vicinity or on any 

Class I area.

Part F - Secondary Ozone Formation Analysis

Because of the well established relationship between nitrogen oxides (NOx), volatile organic compounds 

(VOCs), and the regional transport formation of ozone, U.S. EPA recently finalized the Cross State Air 

Pollution Rule (CSAPR) to assist states to meet the ozone NAAQS. This rule included extensive 

modeling to support the emissions reductions necessary in each state to achieve the ozone NAAQS in 

the eastern U.S. The source category responsible for these reductions is Electric Generating Units 

(EGUs). 

U.S. EPA used a regional model, Comprehensive Air Quality Model with extensions (CAMx), and the Air 

Quality Assessment Tool (AQAT) to determine levels of reduction from EGUs necessary to achieve the 

NAAQS at every site. The documentation includes extensive tables showing impacts at all ozone 

monitors in the eastern U.S. and emission reduction levels necessary to achieve those results. To 

examine the possible impact of SJE, results from the modeling U.S. EPA conducted to establish the final 

2014 budgets in CSAPR were used for this analysis. The CSAPR website is located at 

http://www.epa.gov/crossstaterule/techinfo.html.

Information regarding the NOx emission reductions necessary to achieve the future year modeled design 

values can be found in the “EmissionsSummaries.xlsx” spreadsheet under the Emissions Inventory Final 

Rule TSD section at EPA’s CSAPR website for technical information 

http://www.epa.gov/crossstaterule/techinfo.html. The spreadsheet shows the base case annual NOx

emissions for Indiana by 2014 at 431,342 tons and remedy control scenario annual NOx emissions by 

2014 at 424,250 tons. Indiana’s total NOx emission reduction between these scenarios is 7,092 tons. All 

surrounding states make similar significant reductions. SJE emissions will be 292 tons per year of NOx.

8-Hour Ozone Modeling Results

The nearest ozone monitors to SJE are the Granger, Potato Creek State Park and South Bend ozone 

monitors in St. Joseph County. Both Granger and South Bend’s current design values for 2009-2011 are 

64 parts per billion (ppb), and Potato Creek's design value is 61 ppb all well below the 8-hour NAAQS of 

75 ppb. The maximum 8-hour ozone modeled concentrations for St. Joseph County are 71.9 ppb for the 

2014 base case and 71.6 ppb for the 2014 control scenario. This is a reduction of 0.3 ppb as a result of 

NOx emission reductions from CSAPR. In order for this modeled 8-hour concentration reduction from 

CSAPR to occur, Indiana’s 2014 NOx emissions were reduced by 7,092 tons of NOx. The St. Joseph 

County monitoring sites are not necessarily impacted by every EGU in Indiana, but in the surrounding 
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states, thousands of tons of annual NOx emission reductions have also occurred by 2014, many of which 

would impact these sites. Therefore, to estimate the impact of SJE on modeled concentrations, the ratio 

of SJE NOx emissions to Indiana’s NOx emission reductions from CSAPR was calculated. This ratio was 

then compared to the modeled ozone impact from the difference between the CSAPR base case and 

remedy control modeling results. 

1) 292 tons St. Joseph Energy NOx emissions / 7,092 tons of Indiana’s NOx emissions reduced 

through CSAPR rulemaking = 0.0412 or 4.12%

2) 0.3 ppb maximum 8-hour modeled CSAPR results for St. Joseph County * 4.12% = 0.01235 ppb 

of St. Joseph Energy ozone impact 

3) 0.01235 ppb of St. Joseph Energy / 71.6 ppb at St. Joseph County ozone monitor from 2014 

CSAPR Remedy Maximum modeled results = 0.01725% of the 2014 modeled Remedy results.

Tables are located in CSAPR_AQModeling.pdf, Appendix B, pages B-10 and B-12, for 8-hour ozone 

design values that show the projected base case 2014 ozone concentrations at surrounding monitoring 

sites versus control strategy ozone concentrations. 2014 Base represents modeled results taken from

the anticipated 2014 emissions and 2014 Remedy represents the 2014 Base emissions with emission 

reductions from CSAPR factored into the modeling. Table 9 below shows the CSAPR modeling results 

for nearby ozone monitors and the impact that St. Joseph Energy would have on ozone concentrations in 

the area.

Table 9

EPA’s Cross-State Air Pollution Rule - 8-Hour Ozone Modeling Results

Monitor ID County

2014

Base

(ppb)

2014

Remedy

(ppb)

2014

Base-Remedy

(ppb)

Anticipated 

Source Impact

(ppb)

Source Impact 

on 2014 BaseRemedy Results

(%)

181411007 St. Joseph 71.9 71.6 0.3 0.0124 0.0173%

181410010 St. Joseph 68.5 68.3 0.2 0.0082 0.0121%

181410015 St. Joseph 69.2 69.0 0.2 0.0082 0.0119%

Summary of Ozone Results

St. Joseph Energy’s NOx emissions were compared with U.S. EPA CSAPR modeling for 8-hour ozone to 

determine what impacts on ozone may occur as a result of ozone formation. When the St. Joseph 

Energy emissions were compared with the amount of NOx emission reductions realized from CSAPR and 

compared with CSAPR modeling results for 8-hour ozone, the impacts from St. Joseph Energy on the 

three ozone monitors in St. Joseph County are anticipated to be minimal and not have a significant 

impact on the attainment status of those counties.

Part G - Secondary PM2.5 formation Analysis

In addition to direct emissions of PM2.5, other pollutants, chiefly NOx and SO2, can lead to formation of 

PM2.5 further downwind. The photochemical reactions that transform these pollutants into particulate

nitrates and sulfates, which become the major species of PM2.5, take place over hours or days. 

Potentials to emit after controls for St. Joseph Energy are 292 TPY NOx and 93 TPY SO2.

The modeling for SO2 and annual NO2 shows that receptor concentrations are below Significant Impact 
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Levels (SIL) for their respective NAAQS and further diminish within the modeling domain of 50 km

Since the NOx and SO2 standards are extremely restrictive, being below the SILs would likely prevent the 

pollutants from impacting secondary formation significantly enough to result in a violation of the PM2.5 

standards. 

However, it is possible that some transformation into nitrates and sulfates from this source may occur and 

be transported downwind. No peer-reviewed regulatory model presently exists to examine the 

photochemical impacts of an individual source of SO2 or NOx. All photochemical models are regional 

scale and a source of this size would not show any measurable impact. Therefore, other available 

information from emissions inventories, meteorological analyses, and other modeling projects can be 

used to estimate the impact from this source.

The wind rose shows the general directions that emissions from this source would impact. 

 South Bend 2008 South Bend 2009 South Bend 2010
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Design values from 2008 – 2010 at all PM2.5 monitors in Indiana meet the annual and 24-hour NAAQS. 

Secondary PM2.5 Weight of Evidence Analysis based on EPA’s CSAPR Modeling

Because of the well established relationship between NOx, SO2, and the regional transport and formation 

of PM2.5, and to assist states to meet the PM2.5 NAAQS, U.S. EPA recently finalized the Cross State Air 

Pollution Rule (CSAPR). This rule included extensive modeling to support the emissions reductions 

necessary in each state to achieve the PM2.5 NAAQS in the eastern U.S. The source category 

responsible for these reductions is Electric Generating Units (EGUs). 

U.S. EPA used a regional model, Comprehensive Air Quality Model with extensions (CAMx), and the Air 

Quality Assessment Tool (AQAT) to determine levels of reduction from EGUs necessary to achieve the 

NAAQS at every site. The documentation includes extensive tables showing impacts at all PM2.5 

monitoring sites in the eastern U.S. and emission reduction levels necessary to achieve those results. To 

examine the possible impact of SJE, results from the modeling U.S. EPA conducted to establish the final 

2014 budgets in CSAPR and were used for this analysis. The CSAPR website is located at 

http://www.epa.gov/crossstaterule/techinfo.html.

Information regarding SO2 and NOx emission reductions necessary to achieve the future year modeled 

design values can be found in the “EmissionsSummaries.xlsx” spreadsheet under the Emissions 

Inventory Final Rule TSD section at EPA’s CSPAR website for technical information : 

http://www.epa.gov/crossstaterule/techinfo.html. The spreadsheet shows the base case annual SO2 and 

NOx emissions for Indiana by 2014 and remedy control scenario annual SO2 and NOx emissions by 2014. 

Indiana’s total SO2 and NOx emission reductions between these scenarios are 539,832 tons. All 

surrounding states make similar significant reductions.

Table 10

EPA’s Cross-State Air Pollution Rule Emission Summary for Indiana

Pollutant

2014 

Base 

(tons)

2014 

Remedy 

(tons)

EGU 

Reduction 

(tons)

Indiana SO2 863,923 331,183 532,740

Indiana NOx 431,342 424,250 7,092

TOTAL 539,832
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Annual PM2.5 Modeling Results

The maximum annual PM2.5 modeled concentrations for St. Joseph County are 12.23 μg/m3 for the 2014 

base case and 11.37 μg/m3 for the 2014 remedy (emission control scenario) results. This is a reduction 

of 0.86 μg/m3

. In order for this modeled annual concentration reduction from CSAPR to occur, Indiana’s 

2014 SO2 emissions from EGUs were reduced by 532,740 tons and 2014 NOx emissions were reduced 

by 7,092 for a total of 539,832 tons of SO2 and NOx. This particular monitoring site is not necessarily 

impacted by every EGU in Indiana, but in the surrounding states, hundreds of thousands of tons of annual 

SO2 emission reductions have also occurred by 2014, many of which would impact this site. Therefore, to 

estimate the impact of St. Joseph Energy on modeled concentrations, the ratio of St. Joseph Energy SO2 

and NOx emissions to Indiana’s SO2 and NOx emission reductions from CSAPR was calculated. This 

ratio was then compared to the modeled annual PM2.5 impact from the difference between the CSAPR 

base case and remedy control annual PM2.5 modeling results.

1) 385 tons St. Joseph Energy SO2 and NOx emissions / 539,832 tons of SO2 and NOx emissions 

reduced through CSAPR rulemaking.= 0.000713 or 0.0713%

2) 0.86 μg/m3 modeled annual PM2.5 CSAPR results * 0.0713% St. Joseph SO2/NOx emission ratio 

= 0.00061 μg/m3 of St. Joseph Energy annual PM2.5 impact 

3) 0.00061 μg/m3 of St. Joseph Energy/11.37 μg/m3 of 2014 CSAPR Remedy Maximum modeled 

results = 0.005% of the 2014 modeled Remedy results.

Tables showing projected base case 2014 PM2.5 concentrations at existing monitoring sites versus control

strategy PM2.5 concentrations are located in CSAPR_AQModeling.pdf, Appendix B, pages B-41 and B-42

for annual design values and pages B-70 to B-72 for 24-hour design values. 2014 Base represents 

anticipated 2014 emissions, 2014 Remedy represents the 2014 Base emissions with emission reductions 

from CSAPR factored into the modeling. Table 11 below shows the CSAPR annual PM2.5 modeled 

concentrations at the three St. Joseph County ozone monitors and SJE anticipated source impacts at 

each monitor.

Table 11

EPA’s Cross-State Air Pollution Rule - Annual PM2.5 Modeling Results

Monitor ID County

2014

Base

2014

Remedy

2014

Base-Remedy

(μg/m3)

Anticipated 

Source Impact

(μg/m3)

Source Impact of 

2014 Remedy

(%)

181410014 St. Joseph 12.21 11.29 0.92 0.00066 0.006%

181410008 St. Joseph 12.23 11.37 0.86 0.00061 0.005%

181410004 St. Joseph 11.81 10.90 0.91 0.00065 0.006%

24-Hour PM2.5 Modeling Results

The same emissions and impact analysis methodology used for the annual PM2.5 impacts was used to 

determine the 24-hour PM2.5 impacts from St. Joseph Energy. The maximum 24-hour modeled 

concentrations for St. Joseph County are 30.4 μg/m3 for the 2014 base case and 28.3 μg/m3 for the 2014 

control scenario. This is a reduction of modeled concentration of 2.1 μg/m3

. To estimate the 24-hour 

impact of St. Joseph Energy on modeled concentrations, the ratio of St. Joseph Energy SO2 and NOx

emissions and the CSAPR SO2 and NOx emission reductions was calculated. This ratio was then 

compared to the modeled 24-hour PM2.5 impact from the difference between the CSAPR base case and 
St. Joseph Energy Center, LLC Page 15 of 28

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remedy control 24-hour PM2.5 modeling results.

1) 385 tons St. Joseph Energy SO2 and NOx emissions / 539,832 tons of SO2 and NOx emissions 

reduced through CSAPR rulemaking.= 0.000713 or 0.0713%

2) 2.1 μg/m3 modeled 24-hour PM2.5 CSAPR results * 0.0713% St. Joseph SO2/NOx emission ratio 

= 0.0015 μg/m3 of St. Joseph Energy 24-hour PM2.5 impact 

3) 0.0015 μg/m3 of St. Joseph Energy / 28.3 μg/m3 of the 2014 CSAPR Remedy Maximum modeled 

24-hour results = 0.005% of the 2014 modeled Remedy results.

Modeling results below in Table 12 show 2014 Base and Remedy modeled 24-hour concentrations and 

the anticipated St. Joseph Energy impacts, based on the emissions comparison and estimated impacts.

Table 12

EPA’s Cross-State Air Pollution Rule - 24-Hour PM2.5 Modeling Results

Monitor ID County

2014

Base

2014

Remedy

2014

Base-Remedy

(μg/m3)

Anticipated 

Source Impact

(μg/m3)

Source Impact 

of 2014 Remedy

(%)

181410014 St. Joseph 30.4 28.3 2.1 0.00150 0.005%

181410008 St. Joseph 28.8 28.3 0.5 0.00036 0.001%

181410004 St. Joseph 27.8 27.9 -0.1 -0.00007 0.000%

Summary Annual and 24-Hour PM2.5

St. Joseph Energy SO2 and NOx emissions were compared with U.S. EPA CSAPR modeling for annual 

and 24-hour PM2.5 to determine what impacts of PM2.5 may occur as a result of secondary PM2.5 

formation. When the St. Joseph Energy emissions were compared with the amount of SO2 and NOx

emission reductions realized from CSAPR and compared with CSAPR modeling results for annual and 

24-hour, the impacts from St. Joseph Energy on nearby PM2.5 monitors are anticipated to be minimal and 

not have an effect on the attainment status of any PM2.5 monitors in the area.

Part H - Summary of Air Quality Analysis

Trinity Consultants prepared the modeling portion of the PSD application. St. Joseph County is 

designated as attainment for all criteria pollutants except the new 1-hour SO2 standard which is 

unclassified. PM10, NO2, SO2, CO, PM2.5, and sulfuric acid mist emission rates associated with the 

proposed facility exceeded the respective significant emission rates. Modeling results taken from 

AERMOD model showed that CO, SO2, PM10, and annual NO2 impacts were less than significance 

levels. Refined modeling showed that the NO2 and PM2.5 increments were maintained. NAAQS 

modeling showed that the 1-hour NO2, 24-hour and annual PM2.5 standards were not exceeded. PM2.5

modeling showed some exceedences of the PM2.5 24-hour standard, but SJE contributed 0.0 ug/m3 to 

most of them, and did not contribute significantly to any of them. SJE did not trigger the preconstruction 

monitoring threshold level but can satisfy the preconstruction monitoring requirement since there is 

existing air quality monitoring data representative of the area. SJE was below the PM10 and PM2.5

increment modeling. The nearest Class I area is Mammoth Cave National Park in Kentucky 490

kilometers away from the source. An additional impact analysis was required but the operation of the 

proposed facility will have no significant impact. 

Appendix
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Table 13

Culpability Analysis For SJE

X Y

AVERAGE 

CONC AVE RANK

SJE 

Impact

Total 

Impact SJE Cause ?

545550 4616150 29.0 24-HR 1ST 0.0 29.0 No

545650 4616150 28.5 24-HR 1ST 0.0 28.5 No

545550 4616150 27.7 24-HR 2ND 0.0 27.7 No

545450 4616150 27.6 24-HR 1ST 0.0 27.6 No

545650 4616150 26.1 24-HR 2ND 0.0 26.1 No

545550 4616150 26.0 24-HR 3RD 0.0 26.0 No

545550 4616050 24.7 24-HR 1ST 0.0 24.7 No

545650 4616150 24.1 24-HR 3RD 0.0 24.1 No

545350 4616150 22.6 24-HR 1ST 0.0 22.6 No

545650 4616150 22.6 24-HR 4TH 0.0 22.6 No

545450 4616150 22.4 24-HR 2ND 0.0 22.4 No

545650 4616250 22.2 24-HR 1ST 0.0 22.2 No

545550 4616150 21.9 24-HR 4TH 0.0 21.9 No

545550 4616050 21.4 24-HR 2ND 0.0 21.4 No

545350 4616250 21.0 24-HR 1ST 0.0 21.0 No

545450 4616150 20.9 24-HR 3RD 0.0 20.9 No

545550 4616150 20.5 24-HR 5TH 0.0 20.5 No

545550 4616250 20.3 24-HR 1ST 0.0 20.3 No

545650 4616150 20.0 24-HR 5TH 0.0 20.0 No

545250 4616250 19.9 24-HR 1ST 0.0 19.9 No

545450 4616250 19.5 24-HR 1ST 0.0 19.5 No

545650 4616250 19.3 24-HR 2ND 0.0 19.3 No

545550 4616050 19.2 24-HR 3RD 0.0 19.2 No

545650 4616150 18.9 24-HR 6TH 0.0 18.9 No

545450 4616050 18.6 24-HR 1ST 0.0 18.6 No

545550 4616150 18.3 24-HR 6TH 0.0 18.3 No

545450 4616250 18.2 24-HR 2ND 0.0 18.2 No

545550 4616050 18.1 24-HR 4TH 0.0 18.1 No

545450 4616150 17.9 24-HR 4TH 0.0 17.9 No

545650 4616250 17.9 24-HR 3RD 0.0 17.9 No

545250 4616150 17.8 24-HR 1ST 0.0 17.8 No

545350 4616150 17.8 24-HR 2ND 0.0 17.8 No

545350 4616250 17.7 24-HR 2ND 0.0 17.7 No

545650 4616150 17.6 24-HR 7TH 0.0 17.6 No

545150 4616250 17.5 24-HR 1ST 0.0 17.5 No

545550 4616250 17.4 24-HR 2ND 0.0 17.4 No

545550 4616150 17.2 24-HR 7TH 0.0 17.2 No

545550 4616350 17.0 24-HR 1ST 0.0 17.0 No
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New Carlisle, Indiana PSD/TV Permit No. T141-31003-00579

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545650 4616150 16.8 24-HR 8TH 0.0 16.8 No

545450 4616250 16.7 24-HR 3RD 0.0 16.7 No

545450 4616150 16.4 24-HR 5TH 0.0 16.4 No

545550 4616150 16.4 24-HR 8TH 0.0 16.4 No

545250 4616250 16.3 24-HR 2ND 0.0 16.3 No

545550 4616050 16.3 24-HR 5TH 0.0 16.3 No

545450 4616050 16.2 24-HR 2ND 0.0 16.2 No

545550 4616250 16.1 24-HR 3RD 0.0 16.1 No

545150 4616350 16.1 24-HR 1ST 0.0 16.1 No

545650 4616150 16.1 24-HR 9TH 0.0 16.1 No

545350 4616250 16.0 24-HR 3RD 0.0 16.0 No

545550 4616150 16.0 24-HR 9TH 0.0 16.0 No

545350 4616150 15.9 24-HR 3RD 0.0 15.9 No

545650 4616150 15.7 24-HR 10TH 0.0 15.7 No

545450 4616150 15.6 24-HR 6TH 0.0 15.6 No

545250 4616350 15.5 24-HR 1ST 0.0 15.5 No

545550 4616250 15.3 24-HR 4TH 0.0 15.3 No

545450 4616250 15.3 24-HR 4TH 0.0 15.3 No

545650 4616150 15.2 24-HR 11TH 0.0 15.2 No

545550 4616050 15.2 24-HR 6TH 0.0 15.2 No

545050 4616350 15.0 24-HR 1ST 0.0 15.0 No

545350 4616050 15.0 24-HR 1ST 0.0 15.0 No

545250 4616250 14.9 24-HR 3RD 0.0 14.9 No

545350 4616250 14.9 24-HR 4TH 0.0 14.9 No

545450 4616350 14.9 24-HR 1ST 0.0 14.9 No

545550 4616150 14.8 24-HR 10TH 0.0 14.8 No

545650 4616250 14.8 24-HR 4TH 0.1 14.8 No

545450 4616050 14.7 24-HR 3RD 0.0 14.7 No

545650 4616150 14.6 24-HR 12TH 0.0 14.6 No

545050 4616250 14.6 24-HR 1ST 0.0 14.6 No

545550 4616250 14.5 24-HR 5TH 0.0 14.5 No

545450 4616150 14.4 24-HR 7TH 0.0 14.4 No

545150 4616250 14.4 24-HR 2ND 0.0 14.4 No

545450 4616250 14.4 24-HR 5TH 0.0 14.4 No

545550 4616350 14.3 24-HR 2ND 0.0 14.3 No

545350 4616350 14.3 24-HR 1ST 0.0 14.3 No

544950 4616350 14.2 24-HR 1ST 0.0 14.2 No

545150 4616150 14.0 24-HR 1ST 0.0 14.0 No

545650 4616250 14.0 24-HR 5TH 0.0 14.0 No

545550 4616250 14.0 24-HR 6TH 0.0 14.0 No

545550 4616150 13.9 24-HR 11TH 0.0 13.9 No

545450 4616150 13.7 24-HR 8TH 0.0 13.7 No

545350 4616150 13.7 24-HR 4TH 0.0 13.7 No
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545350 4616050 13.6 24-HR 2ND 0.0 13.6 No

545450 4616350 13.6 24-HR 2ND 0.0 13.6 No

545650 4616150 13.5 24-HR 13TH 0.0 13.5 No

545550 4616050 13.5 24-HR 7TH 0.0 13.5 No

545250 4616250 13.5 24-HR 4TH 0.0 13.5 No

545550 4616150 13.4 24-HR 12TH 0.0 13.4 No

545350 4616250 13.4 24-HR 5TH 0.0 13.4 No

545250 4616150 13.3 24-HR 2ND 0.0 13.3 No

545650 4616150 13.2 24-HR 14TH 0.0 13.2 No

545650 4616250 13.2 24-HR 6TH 0.0 13.2 No

545550 4616250 13.2 24-HR 7TH 0.0 13.2 No

545450 4616150 13.0 24-HR 9TH 0.0 13.0 No

545650 4616150 13.0 24-HR 15TH 0.0 13.0 No

545350 4616150 12.9 24-HR 5TH 0.0 12.9 No

545650 4616250 12.9 24-HR 7TH 0.0 12.9 No

545550 4616350 12.9 24-HR 3RD 0.0 12.9 No

545450 4616350 12.9 24-HR 3RD 0.0 12.9 No

544950 4616450 12.8 24-HR 1ST 0.0 12.8 No

545450 4616250 12.8 24-HR 6TH 0.0 12.8 No

545350 4616350 12.8 24-HR 2ND 0.0 12.8 No

545550 4616150 12.7 24-HR 13TH 0.0 12.7 No

545250 4616350 12.7 24-HR 2ND 0.0 12.7 No

545050 4616450 12.7 24-HR 1ST 0.0 12.7 No

545450 4616150 12.7 24-HR 10TH 0.0 12.7 No

545250 4616050 12.6 24-HR 1ST 0.0 12.6 No

544850 4616350 12.5 24-HR 1ST 0.0 12.5 No

545550 4616050 12.5 24-HR 8TH 0.0 12.5 No

545150 4616250 12.5 24-HR 3RD 0.0 12.5 No

544950 4616250 12.5 24-HR 1ST 0.0 12.5 No

545550 4616250 12.5 24-HR 8TH 0.0 12.5 No

545650 4616250 12.4 24-HR 8TH 0.0 12.4 No

545650 4616150 12.4 24-HR 16TH 0.0 12.4 No

545450 4616050 12.4 24-HR 4TH 0.0 12.4 No

544850 4616450 12.3 24-HR 1ST 0.0 12.3 No

545250 4616150 12.3 24-HR 3RD 0.0 12.3 No

545550 4616150 12.3 24-HR 14TH 0.0 12.3 No

545050 4616250 12.2 24-HR 2ND 0.0 12.2 No

545150 4616350 12.2 24-HR 2ND 0.0 12.2 No

545450 4616150 12.2 24-HR 11TH 0.0 12.2 No

545650 4616150 12.2 24-HR 17TH 0.0 12.2 No

545250 4616250 12.1 24-HR 5TH 0.0 12.1 No

545350 4616250 12.1 24-HR 6TH 0.0 12.1 No

545250 4616350 12.0 24-HR 3RD 0.0 12.0 No
St. Joseph Energy Center, LLC Page 19 of 28

New Carlisle, Indiana PSD/TV Permit No. T141-31003-00579

Permit Writer: Steve Sherman

545350 4616050 12.0 24-HR 3RD 0.0 12.0 No

545450 4616250 11.9 24-HR 7TH 0.0 11.9 No

545150 4616250 11.9 24-HR 4TH 0.0 11.9 No

545450 4616050 11.9 24-HR 5TH 0.0 11.9 No

545350 4616150 11.8 24-HR 6TH 0.0 11.8 No

545350 4616350 11.8 24-HR 3RD 0.0 11.8 No

545450 4616350 11.7 24-HR 4TH 0.0 11.7 No

545650 4616150 11.7 24-HR 18TH 0.0 11.7 No

545550 4616350 11.6 24-HR 4TH 0.0 11.6 No

544750 4616450 11.6 24-HR 1ST 0.0 11.6 No

545150 4616450 11.6 24-HR 1ST 0.0 11.6 No

545650 4616250 11.6 24-HR 9TH 0.0 11.6 No

545350 4616450 11.5 24-HR 1ST 0.0 11.5 No

545450 4616150 11.5 24-HR 12TH 0.0 11.5 No

545550 4616150 11.5 24-HR 15TH 0.0 11.5 No

545450 4616250 11.4 24-HR 8TH 0.0 11.4 No

545550 4616050 11.4 24-HR 9TH 0.0 11.4 No

545350 4616150 11.4 24-HR 7TH 0.0 11.4 No

545450 4616050 11.3 24-HR 6TH 0.0 11.3 No

545350 4616250 11.3 24-HR 7TH 0.0 11.3 No

545550 4616250 11.3 24-HR 9TH 0.0 11.3 No

545550 4616150 11.3 24-HR 16TH 0.0 11.3 No

545050 4616350 11.2 24-HR 2ND 0.0 11.2 No

545250 4616450 11.2 24-HR 1ST 0.0 11.2 No

545150 4616350 11.2 24-HR 3RD 0.0 11.2 No

545350 4616350 11.2 24-HR 4TH 0.0 11.2 No

545250 4616050 11.2 24-HR 2ND 0.0 11.2 No

545050 4616150 11.1 24-HR 1ST 0.0 11.1 No

545650 4616250 11.0 24-HR 10TH 0.0 11.0 No

545550 4616150 11.0 24-HR 17TH 0.0 11.0 No

545050 4616250 11.0 24-HR 3RD 0.0 11.0 No

545350 4616250 10.9 24-HR 8TH 0.0 10.9 No

545550 4616250 10.9 24-HR 10TH 0.0 10.9 No

545450 4616250 10.9 24-HR 9TH 0.0 10.9 No

545250 4616150 10.9 24-HR 4TH 0.0 10.9 No

545450 4616050 10.9 24-HR 7TH 0.0 10.9 No

545550 4616350 10.9 24-HR 5TH 0.0 10.9 No

545250 4616250 10.9 24-HR 6TH 0.0 10.9 No

544650 4616450 10.9 24-HR 1ST 0.0 10.9 No

544950 4615850 10.9 24-HR 1ST 0.0 10.9 No

545350 4616150 10.9 24-HR 8TH 0.0 10.9 No

545450 4616350 10.8 24-HR 5TH 0.0 10.8 No

545650 4616150 10.8 24-HR 19TH 0.0 10.8 No
St. Joseph Energy Center, LLC Page 20 of 28

New Carlisle, Indiana PSD/TV Permit No. T141-31003-00579

Permit Writer: Steve Sherman

545350 4616450 10.8 24-HR 2ND 0.0 10.8 No

545550 4616150 10.8 24-HR 18TH 0.0 10.8 No

545550 4616050 10.7 24-HR 10TH 0.0 10.7 No

545150 4616150 10.7 24-HR 2ND 0.0 10.7 No

544850 4616550 10.7 24-HR 1ST 0.0 10.7 No

544750 4616550 10.7 24-HR 1ST 0.0 10.7 No

544750 4616350 10.7 24-HR 1ST 0.0 10.7 No

545050 4616350 10.7 24-HR 3RD 0.0 10.7 No

544950 4616350 10.7 24-HR 2ND 0.0 10.7 No

545350 4616350 10.6 24-HR 5TH 0.0 10.6 No

545650 4616250 10.6 24-HR 11TH 0.0 10.6 No

544850 4616250 10.6 24-HR 1ST 0.0 10.6 No

545450 4616150 10.6 24-HR 13TH 0.0 10.6 No

545350 4616150 10.6 24-HR 9TH 0.0 10.6 No

545150 4616050 10.6 24-HR 1ST 0.0 10.6 No

545150 4616250 10.5 24-HR 5TH 0.0 10.5 No

545650 4616150 10.5 24-HR 20TH 0.0 10.5 No

545550 4616250 10.5 24-HR 11TH 0.0 10.5 No

544950 4616550 10.5 24-HR 1ST 0.0 10.5 No

545150 4616350 10.5 24-HR 4TH 0.0 10.5 No

545550 4616150 10.5 24-HR 19TH 0.0 10.5 No

544950 4615750 10.4 24-HR 1ST 0.0 10.4 No

545250 4616250 10.4 24-HR 7TH 0.0 10.4 No

545350 4616250 10.4 24-HR 9TH 0.0 10.4 No

545650 4616250 10.3 24-HR 12TH 0.0 10.3 No

545350 4616050 10.3 24-HR 4TH 0.0 10.3 No

544650 4616550 10.3 24-HR 1ST 0.0 10.3 No

545550 4616050 10.3 24-HR 11TH 0.0 10.3 No

545250 4616350 10.3 24-HR 4TH 0.0 10.3 No

545450 4616150 10.3 24-HR 14TH 0.0 10.3 No

544950 4615950 10.3 24-HR 1ST 0.0 10.3 No

545450 4616250 10.3 24-HR 10TH 0.0 10.3 No

545350 4616150 10.3 24-HR 10TH 0.0 10.3 No

545650 4616150 10.3 24-HR 21ST 0.0 10.3 No

545450 4616350 10.1 24-HR 6TH 0.0 10.1 No

544950 4616350 10.1 24-HR 3RD 0.0 10.1 No

545550 4616350 10.1 24-HR 6TH 0.0 10.1 No

545650 4616250 10.0 24-HR 13TH 0.1 10.0 No

545550 4616050 10.0 24-HR 12TH 0.0 10.0 No

545250 4616150 10.0 24-HR 5TH 0.0 10.0 No

545650 4616150 10.0 24-HR 22ND 0.0 10.0 No

545350 4616450 10.0 24-HR 3RD 0.0 10.0 No

544950 4616250 10.0 24-HR 2ND 0.0 10.0 No
St. Joseph Energy Center, LLC Page 21 of 28

New Carlisle, Indiana PSD/TV Permit No. T141-31003-00579

Permit Writer: Steve Sherman

545450 4616250 9.9 24-HR 11TH 0.0 9.9 No

545350 4616250 9.9 24-HR 10TH 0.0 9.9 No

545350 4616150 9.8 24-HR 11TH 0.0 9.8 No

545550 4616050 9.8 24-HR 13TH 0.0 9.8 No

545350 4616350 9.8 24-HR 6TH 0.0 9.8 No

544850 4615750 9.8 24-HR 1ST 0.0 9.8 No

544550 4616550 9.8 24-HR 1ST 0.0 9.8 No

545650 4616250 9.8 24-HR 14TH 0.0 9.8 No

545250 4616350 9.8 24-HR 5TH 0.0 9.8 No

545450 4616250 9.8 24-HR 12TH 0.0 9.8 No

544550 4616450 9.8 24-HR 1ST 0.0 9.8 No

545250 4616250 9.7 24-HR 8TH 0.0 9.7 No

545650 4616150 9.7 24-HR 23RD 0.0 9.7 No

545050 4616350 9.7 24-HR 4TH 0.0 9.7 No

545450 4616150 9.7 24-HR 15TH 0.0 9.7 No

545250 4616050 9.7 24-HR 3RD 0.0 9.7 No

545550 4616250 9.7 24-HR 12TH 0.0 9.7 No

545550 4616150 9.7 24-HR 20TH 0.0 9.7 No

545250 4616450 9.7 24-HR 2ND 0.0 9.7 No

544850 4615850 9.6 24-HR 1ST 0.0 9.6 No

544850 4616350 9.6 24-HR 2ND 0.0 9.6 No

545150 4616450 9.6 24-HR 2ND 0.0 9.6 No

545150 4616350 9.5 24-HR 5TH 0.0 9.5 No

545450 4616350 9.5 24-HR 7TH 0.0 9.5 No

545550 4616350 9.5 24-HR 7TH 0.0 9.5 No

545350 4616250 9.5 24-HR 11TH 0.0 9.5 No

545150 4616150 9.5 24-HR 3RD 0.0 9.5 No

545550 4616250 9.5 24-HR 13TH 0.0 9.5 No

545450 4616250 9.5 24-HR 13TH 0.0 9.5 No

544950 4616450 9.5 24-HR 2ND 0.0 9.5 No

545150 4616250 9.4 24-HR 6TH 0.0 9.4 No

545350 4616050 9.4 24-HR 5TH 0.0 9.4 No

545650 4616150 9.4 24-HR 24TH 0.0 9.4 No

544650 4616350 9.4 24-HR 1ST 0.0 9.4 No

545050 4616450 9.4 24-HR 2ND 0.0 9.4 No

545150 4616050 9.4 24-HR 2ND 0.0 9.4 No

545450 4616150 9.4 24-HR 16TH 0.0 9.4 No

544850 4615950 9.3 24-HR 1ST 0.0 9.3 No

544450 4616550 9.3 24-HR 1ST 0.0 9.3 No

545350 4616450 9.3 24-HR 4TH 0.0 9.3 No

545350 4616150 9.3 24-HR 12TH 0.0 9.3 No

544550 4616650 9.3 24-HR 1ST 0.0 9.3 No

545050 4616250 9.3 24-HR 4TH 0.0 9.3 No
St. Joseph Energy Center, LLC Page 22 of 28

New Carlisle, Indiana PSD/TV Permit No. T141-31003-00579

Permit Writer: Steve Sherman

545250 4616150 9.3 24-HR 6TH 0.0 9.3 No

545250 4616250 9.2 24-HR 9TH 0.0 9.2 No

545050 4616050 9.2 24-HR 1ST 0.0 9.2 No

545250 4616450 9.2 24-HR 3RD 0.0 9.2 No

544950 4616350 9.2 24-HR 4TH 0.0 9.2 No

545050 4616550 9.2 24-HR 1ST 0.0 9.2 No

545450 4616250 9.2 24-HR 14TH 0.0 9.2 No

545350 4616250 9.2 24-HR 12TH 0.0 9.2 No

545650 4616150 9.2 24-HR 25TH 0.0 9.2 No

544750 4615750 9.2 24-HR 1ST 0.0 9.2 No

545250 4616150 9.1 24-HR 7TH 0.0 9.1 No

545550 4616050 9.1 24-HR 14TH 0.0 9.1 No

545550 4616150 9.1 24-HR 21ST 0.0 9.1 No

545350 4616150 9.1 24-HR 13TH 0.0 9.1 No

545350 4616350 9.0 24-HR 7TH 0.0 9.0 No

544950 4616250 9.0 24-HR 3RD 0.0 9.0 No

545550 4616250 9.0 24-HR 14TH 0.0 9.0 No

545550 4616350 9.0 24-HR 8TH 0.0 9.0 No

545450 4616150 9.0 24-HR 17TH 0.0 9.0 No

544450 4616650 8.9 24-HR 1ST 0.0 8.9 No

545050 4616150 8.9 24-HR 2ND 0.0 8.9 No

545050 4616250 8.9 24-HR 5TH 0.0 8.9 No

544750 4616250 8.9 24-HR 1ST 0.0 8.9 No

545050 4616450 8.9 24-HR 3RD 0.0 8.9 No

544950 4616150 8.9 24-HR 1ST 0.0 8.9 No

545650 4616250 8.9 24-HR 15TH 0.0 8.9 No

545250 4616450 8.9 24-HR 4TH 0.0 8.9 No

544850 4616350 8.9 24-HR 3RD 0.0 8.9 No

545150 4616150 8.9 24-HR 4TH 0.0 8.9 No

544850 4616450 8.8 24-HR 2ND 0.0 8.8 No

545450 4616050 8.8 24-HR 8TH 0.0 8.8 No

544750 4616450 8.8 24-HR 2ND 0.0 8.8 No

544850 4615650 8.8 24-HR 1ST 0.0 8.8 No

544750 4615850 8.8 24-HR 1ST 0.0 8.8 No

545050 4616350 8.8 24-HR 5TH 0.0 8.8 No

545350 4616250 8.8 24-HR 13TH 0.0 8.8 No

545450 4616350 8.8 24-HR 8TH 0.0 8.8 No

545450 4616250 8.8 24-HR 15TH 0.0 8.8 No

545350 4616050 8.8 24-HR 6TH 0.0 8.8 No

545550 4616250 8.7 24-HR 15TH 0.0 8.7 No

544750 4616350 8.7 24-HR 2ND 0.0 8.7 No

545150 4616450 8.7 24-HR 3RD 0.0 8.7 No

545350 4616450 8.7 24-HR 5TH 0.0 8.7 No
St. Joseph Energy Center, LLC Page 23 of 28

New Carlisle, Indiana PSD/TV Permit No. T141-31003-00579

Permit Writer: Steve Sherman

545650 4616150 8.7 24-HR 26TH 0.0 8.7 No

544350 4616550 8.7 24-HR 1ST 0.0 8.7 No

545650 4616250 8.7 24-HR 16TH 0.0 8.7 No

545150 4616350 8.7 24-HR 6TH 0.0 8.7 No

545150 4616250 8.7 24-HR 7TH 0.0 8.7 No

545350 4616150 8.7 24-HR 14TH 0.0 8.7 No

545550 4616350 8.6 24-HR 9TH 0.0 8.6 No

544450 4616450 8.6 24-HR 1ST 0.0 8.6 No

544350 4616650 8.6 24-HR 1ST 0.0 8.6 No

544750 4615650 8.6 24-HR 1ST 0.0 8.6 No

545450 4616150 8.6 24-HR 18TH 0.0 8.6 No

545250 4616350 8.5 24-HR 6TH 0.0 8.5 No

545250 4616050 8.5 24-HR 4TH 0.0 8.5 No

545350 4616350 8.5 24-HR 8TH 0.0 8.5 No

545650 4616150 8.5 24-HR 27TH 0.0 8.5 No

544550 4616350 8.5 24-HR 1ST 0.0 8.5 No

544850 4616350 8.5 24-HR 4TH 0.0 8.5 No

545550 4616150 8.5 24-HR 22ND 0.0 8.5 No

544750 4615950 8.5 24-HR 1ST 0.0 8.5 No

542050 4616550 8.5 24-HR 1ST 0.6 8.5 No

545550 4616250 8.5 24-HR 16TH 0.0 8.5 No

544950 4615750 8.5 24-HR 2ND 0.1 8.5 No

545250 4616250 8.5 24-HR 10TH 0.0 8.5 No

544850 4616450 8.5 24-HR 3RD 0.0 8.5 No

545550 4616050 8.5 24-HR 15TH 0.0 8.5 No

544650 4615750 8.5 24-HR 1ST 0.0 8.5 No

544950 4616350 8.4 24-HR 5TH 0.0 8.4 No

545150 4616250 8.4 24-HR 8TH 0.0 8.4 No

545350 4616050 8.4 24-HR 7TH 0.0 8.4 No

541950 4616650 8.4 24-HR 1ST 0.7 8.4 No

544950 4616450 8.4 24-HR 3RD 0.0 8.4 No

545250 4616150 8.4 24-HR 8TH 0.0 8.4 No

545250 4616450 8.4 24-HR 5TH 0.0 8.4 No

545450 4616050 8.4 24-HR 9TH 0.0 8.4 No

544950 4615850 8.4 24-HR 2ND 0.0 8.4 No

545150 4616450 8.4 24-HR 4TH 0.0 8.4 No

545550 4616350 8.3 24-HR 10TH 0.0 8.3 No

545450 4616150 8.3 24-HR 19TH 0.0 8.3 No

545550 4616050 8.3 24-HR 16TH 0.0 8.3 No

545450 4616350 8.3 24-HR 9TH 0.0 8.3 No

545350 4616250 8.3 24-HR 14TH 0.0 8.3 No

544850 4616250 8.3 24-HR 2ND 0.0 8.3 No

545150 4616350 8.3 24-HR 7TH 0.0 8.3 No
St. Joseph Energy Center, LLC Page 24 of 28

New Carlisle, Indiana PSD/TV Permit No. T141-31003-00579

Permit Writer: Steve Sherman

545250 4616350 8.2 24-HR 7TH 0.0 8.2 No

544950 4616050 8.2 24-HR 1ST 0.0 8.2 No

545550 4616150 8.2 24-HR 23RD 0.0 8.2 No

542050 4616650 8.2 24-HR 1ST 0.6 8.2 No

541950 4616550 8.2 24-HR 1ST 0.7 8.2 No

544950 4615950 8.2 24-HR 2ND 0.0 8.2 No

545550 4616050 8.2 24-HR 17TH 0.0 8.2 No

545450 4616250 8.2 24-HR 16TH 0.0 8.2 No

545650 4616250 8.2 24-HR 17TH 0.0 8.2 No

544350 4616750 8.1 24-HR 1ST 0.0 8.1 No

545150 4616350 8.1 24-HR 8TH 0.0 8.1 No

545650 4616150 8.1 24-HR 28TH 0.0 8.1 No

545050 4616050 8.1 24-HR 2ND 0.0 8.1 No

544650 4616450 8.1 24-HR 2ND 0.0 8.1 No

545450 4616350 8.1 24-HR 10TH 0.0 8.1 No

545150 4616150 8.1 24-HR 5TH 0.0 8.1 No

544650 4615850 8.1 24-HR 1ST 0.0 8.1 No

545550 4616250 8.1 24-HR 17TH 0.0 8.1 No

545350 4616450 8.1 24-HR 6TH 0.0 8.1 No

545550 4616150 8.1 24-HR 24TH 0.0 8.1 No

544250 4616650 8.1 24-HR 1ST 0.0 8.1 No

545550 4616350 8.1 24-HR 11TH 0.0 8.1 No

541850 4616650 8.1 24-HR 1ST 0.6 8.1 No

545350 4616250 8.1 24-HR 15TH 0.0 8.1 No

544850 4615750 8.1 24-HR 2ND 0.1 8.1 No

545250 4616150 8.0 24-HR 9TH 0.0 8.0 No

545650 4616250 8.0 24-HR 18TH 0.0 8.0 No

542050 4616750 8.0 24-HR 1ST 0.5 8.0 No

545150 4616050 8.0 24-HR 3RD 0.0 8.0 No

544750 4616350 8.0 24-HR 3RD 0.0 8.0 No

545050 4616350 8.0 24-HR 6TH 0.0 8.0 No

545450 4616250 8.0 24-HR 17TH 0.0 8.0 No

544650 4615650 8.0 24-HR 1ST 0.0 8.0 No

545350 4616150 8.0 24-HR 15TH 0.0 8.0 No

545250 4616350 8.0 24-HR 8TH 0.0 8.0 No

544350 4616850 8.0 24-HR 1ST 0.0 8.0 No

545350 4616350 8.0 24-HR 9TH 0.0 8.0 No

545450 4616150 8.0 24-HR 20TH 0.0 8.0 No

545250 4616250 8.0 24-HR 11TH 0.0 8.0 No

545650 4616150 8.0 24-HR 29TH 0.0 8.0 No

545050 4616150 7.9 24-HR 3RD 0.0 7.9 No

545450 4616250 7.9 24-HR 18TH 0.0 7.9 No

545550 4616250 7.9 24-HR 18TH 0.0 7.9 No
St. Joseph Energy Center, LLC Page 25 of 28

New Carlisle, Indiana PSD/TV Permit No. T141-31003-00579

Permit Writer: Steve Sherman

544750 4616450 7.9 24-HR 3RD 0.0 7.9 No

545450 4616050 7.9 24-HR 10TH 0.0 7.9 No

544650 4616250 7.9 24-HR 1ST 0.0 7.9 No

544250 4616550 7.9 24-HR 1ST 0.0 7.9 No

545450 4616150 7.9 24-HR 21ST 0.0 7.9 No

544650 4615350 7.9 24-HR 1ST 0.0 7.9 No

545350 4616250 7.9 24-HR 16TH 0.0 7.9 No

545150 4616450 7.9 24-HR 5TH 0.0 7.9 No

544250 4616750 7.8 24-HR 1ST 0.0 7.8 No

544850 4616350 7.8 24-HR 5TH 0.0 7.8 No

545450 4616350 7.8 24-HR 11TH 0.0 7.8 No

542150 4616550 7.8 24-HR 1ST 0.7 7.8 No

545250 4616250 7.8 24-HR 12TH 0.0 7.8 No

541850 4616550 7.8 24-HR 1ST 0.8 7.8 No

545250 4616150 7.8 24-HR 10TH 0.0 7.8 No

544450 4616350 7.8 24-HR 1ST 0.1 7.8 No

545250 4616050 7.8 24-HR 5TH 0.0 7.8 No

544350 4616450 7.8 24-HR 1ST 0.0 7.8 No

544550 4615750 7.8 24-HR 1ST 0.0 7.8 No

545550 4616150 7.8 24-HR 25TH 0.0 7.8 No

545150 4616350 7.8 24-HR 9TH 0.0 7.8 No

544950 4616250 7.8 24-HR 4TH 0.0 7.8 No

545550 4616050 7.8 24-HR 18TH 0.0 7.8 No

544750 4615350 7.8 24-HR 1ST 0.1 7.8 No

544650 4615950 7.8 24-HR 1ST 0.0 7.8 No

544850 4616450 7.7 24-HR 4TH 0.0 7.7 No

545450 4616250 7.7 24-HR 19TH 0.0 7.7 No

545050 4616250 7.7 24-HR 6TH 0.0 7.7 No

544550 4615850 7.7 24-HR 1ST 0.0 7.7 No

544650 4616350 7.7 24-HR 2ND 0.0 7.7 No

544450 4616850 7.7 24-HR 1ST 0.0 7.7 No

545050 4616350 7.7 24-HR 7TH 0.0 7.7 No

544850 4615850 7.7 24-HR 2ND 0.0 7.7 No

545650 4616250 7.7 24-HR 19TH 0.0 7.7 No

544950 4616150 7.7 24-HR 2ND 0.0 7.7 No

541750 4616650 7.7 24-HR 1ST 0.6 7.7 No

544250 4616850 7.7 24-HR 1ST 0.0 7.7 No

544450 4615250 7.7 24-HR 1ST 0.1 7.7 No

545550 4616250 7.7 24-HR 19TH 0.0 7.7 No

545250 4616250 7.7 24-HR 13TH 0.0 7.7 No

545650 4616150 7.6 24-HR 30TH 0.0 7.6 No

545250 4616350 7.6 24-HR 9TH 0.0 7.6 No

545050 4616450 7.6 24-HR 4TH 0.0 7.6 No
St. Joseph Energy Center, LLC Page 26 of 28

New Carlisle, Indiana PSD/TV Permit No. T141-31003-00579

Permit Writer: Steve Sherman

544750 4616350 7.6 24-HR 4TH 0.1 7.6 No

545250 4616150 7.6 24-HR 11TH 0.0 7.6 No

544150 4616650 7.6 24-HR 1ST 0.0 7.6 No

544150 4616750 7.6 24-HR 1ST 0.0 7.6 No

544950 4616350 7.6 24-HR 6TH 0.0 7.6 No

545250 4616450 7.6 24-HR 6TH 0.0 7.6 No

544850 4615650 7.6 24-HR 2ND 0.1 7.6 No

544950 4616450 7.6 24-HR 4TH 0.0 7.6 No

544850 4616550 7.6 24-HR 2ND 0.0 7.6 No

545350 4616150 7.6 24-HR 16TH 0.0 7.6 No

545550 4616350 7.6 24-HR 12TH 0.0 7.6 No

545150 4616250 7.6 24-HR 9TH 0.0 7.6 No

545050 4616550 7.6 24-HR 2ND 0.0 7.6 No

544550 4615250 7.6 24-HR 1ST 0.1 7.6 No

542150 4616450 7.6 24-HR 1ST 0.6 7.6 No

544750 4615750 7.6 24-HR 2ND 0.1 7.6 No

544750 4615450 7.6 24-HR 1ST 0.0 7.6 No

545550 4616050 7.6 24-HR 19TH 0.0 7.6 No

545550 4616150 7.6 24-HR 26TH 0.0 7.6 No

545450 4616250 7.6 24-HR 20TH 0.0 7.6 No

545350 4616450 7.5 24-HR 7TH 0.0 7.5 No

545450 4616050 7.5 24-HR 11TH 0.0 7.5 No

545450 4616150 7.5 24-HR 22ND 0.0 7.5 No

545050 4616250 7.5 24-HR 7TH 0.0 7.5 No

544950 4616550 7.5 24-HR 2ND 0.0 7.5 No

545350 4616250 7.5 24-HR 17TH 0.0 7.5 No

541750 4616550 7.5 24-HR 1ST 0.7 7.5 No

542150 4616650 7.5 24-HR 1ST 0.7 7.5 No

544850 4616150 7.5 24-HR 1ST 0.0 7.5 No

545650 4616150 7.5 24-HR 31ST 0.0 7.5 No

545550 4616250 7.5 24-HR 20TH 0.0 7.5 No

545250 4616350 7.5 24-HR 10TH 0.0 7.5 No

545150 4616250 7.5 24-HR 10TH 0.0 7.5 No

545450 4616350 7.5 24-HR 12TH 0.0 7.5 No

545350 4616350 7.5 24-HR 10TH 0.0 7.5 No

544850 4615950 7.5 24-HR 2ND 0.0 7.5 No

545350 4616050 7.4 24-HR 8TH 0.0 7.4 No

544850 4616050 7.4 24-HR 1ST 0.0 7.4 No

545450 4616150 7.4 24-HR 23RD 0.0 7.4 No

544750 4615650 7.4 24-HR 2ND 0.2 7.4 No

544550 4615350 7.4 24-HR 1ST 0.0 7.4 No

545650 4616250 7.4 24-HR 20TH 0.0 7.4 No

545550 4616350 7.4 24-HR 13TH 0.0 7.4 No
St. Joseph Energy Center, LLC Page 27 of 28

New Carlisle, Indiana PSD/TV Permit No. T141-31003-00579

Permit Writer: Steve Sherman

545550 4616050 7.4 24-HR 20TH 0.0 7.4 No

544250 4615150 7.4 24-HR 1ST 0.0 7.4 No

544550 4616450 7.4 24-HR 2ND 0.0 7.4 No

545150 4616150 7.4 24-HR 6TH 0.0 7.4 No

544850 4616250 7.4 24-HR 3RD 0.0 7.4 No

544550 4615650 7.4 24-HR 1ST 0.0 7.4 No

544750 4616550 7.4 24-HR 2ND 0.0 7.4 No

544450 4615850 7.4 24-HR 1ST 0.0 7.4 No

544350 4615150 7.4 24-HR 1ST 0.1 7.4 No

544850 4615550 7.3 24-HR 1ST 0.0 7.3 No

544350 4616350 7.3 24-HR 1ST 0.1 7.3 No

545050 4616350 7.3 24-HR 8TH 0.0 7.3 No

544750 4616250 7.3 24-HR 2ND 0.0 7.3 No

544650 4616550 7.3 24-HR 2ND 0.0 7.3 No

544050 4615050 7.3 24-HR 1ST 0.0 7.3 No

545450 4616250 7.3 24-HR 21ST 0.0 7.3 No

544150 4616950 7.3 24-HR 1ST 0.0 7.3 No

545250 4616250 7.3 24-HR 14TH 0.0 7.3 No

545250 4616350 7.3 24-HR 11TH 0.0 7.3 No

545550 4616150 7.3 24-HR 27TH 0.0 7.3 No

545250 4616150 7.3 24-HR 12TH 0.0 7.3 No

541950 4616850 7.3 24-HR 1ST 0.4 7.3 No

545550 4616250 7.3 24-HR 21ST 0.0 7.3 No

541950 4616450 7.3 24-HR 1ST 0.5 7.3 No

544550 4616550 7.3 24-HR 2ND 0.0 7.3 No

541650 4616650 7.3 24-HR 1ST 0.6 7.3 No

544850 4616450 7.3 24-HR 5TH 0.0 7.3 No

545350 4616150 7.3 24-HR 17TH 0.0 7.3 No

544350 4615250 7.3 24-HR 1ST 0.0 7.3 No

544150 4616850 7.3 24-HR 1ST 0.0 7.3 No

545650 4616150 7.3 24-HR 32ND 0.0 7.3 No

544650 4616450 7.3 24-HR 3RD 0.0 7.3 No

544250 4616950 7.2 24-HR 1ST 0.0 7.2 No

544150 4615050 7.2 24-HR 1ST 0.0 7.2 No

545550 4616350 7.2 24-HR 14TH 0.0 7.2 No

545350 4616250 7.2 24-HR 18TH 0.0 7.2 No

544750 4616450 7.2 24-HR 4TH 0.0 7.2 No

544350 4615650 7.2 24-HR 1ST 0.1 7.2 No

544950 4615950 7.2 24-HR 3RD 0.0 7.2 No

543850 4614950 7.2 24-HR 1ST 0.0 7.2 No

545050 4616550 7.2 24-HR 3RD 0.0 7.2 No

544950 4615750 7.2 24-HR 3RD 0.0 7.2 No

545650 4616250 7.2 24-HR 21ST 0.0 7.2 No
St. Joseph Energy Center, LLC Page 28 of 28

New Carlisle, Indiana PSD/TV Permit No. T141-31003-00579

Permit Writer: Steve Sherman

545150 4616250 7.2 24-HR 11TH 0.0 7.2 No

541850 4616750 7.2 24-HR 1ST 0.5 7.2 No

543950 4614950 7.2 24-HR 1ST 0.0 7.2 No

545150 4616350 7.2 24-HR 10TH 0.1 7.2 No

544950 4616050 7.2 24-HR 2ND 0.0 7.2 No

544150 4616550 7.2 24-HR 1ST 0.0 7.2 No

545150 4616050 7.2 24-HR 4TH 0.0 7.2 No

544150 4615150 7.2 24-HR 1ST 0.0 7.2 No

544550 4616250 7.1 24-HR 1ST 0.0 7.1 No

545550 4616250 7.1 24-HR 22ND 0.0 7.1 No

545350 4616250 7.1 24-HR 19TH 0.0 7.1 No

541650 4616550 7.1 24-HR 1ST 0.7 7.1 No

544250 4615650 7.1 24-HR 1ST 0.1 7.1 No

545150 4616450 7.1 24-HR 6TH 0.0 7.1 No

545550 4616150 7.1 24-HR 28TH 0.0 7.1 No

544450 4615750 7.1 24-HR 1ST 0.0 7.1 No

545250 4616250 7.1 24-HR 15TH 0.0 7.1 No

544250 4616450 7.1 24-HR 1ST 0.1 7.1 No

541850 4616450 7.1 24-HR 1ST 0.4 7.1 No

544050 4616750 7.1 24-HR 1ST 0.0 7.1 No

544550 4615950 7.1 24-HR 1ST 0.0 7.1 No

544450 4615650 7.1 24-HR 1ST 0.1 7.1 No

544650 4615750 7.1 24-HR 2ND 0.1 7.1 No

544050 4616650 7.1 24-HR 1ST 0.0 7.1 No

544950 4616250 7.1 24-HR 5TH 0.0 7.1 No

543650 4614850 7.1 24-HR 1ST 0.0 7.1 No

545150 4616150 7.1 24-HR 7TH 0.0 7.1 No

545450 4616350 7.1 24-HR 13TH 0.0 7.1 No

545350 4616350 7.0 24-HR 11TH 0.0 7.0 No

545350 4616250 7.0 24-HR 20TH 0.0 7.0 No

545050 4616450 7.0 24-HR 5TH 0.0 7.0 No

541950 4616750 7.0 24-HR 1ST 0.6 7.0 No

544650 4616350 7.0 24-HR 3RD 0.0 7.0 No

545550 4616050 7.0 24-HR 21ST 0.0 7.0 No

543750 4614850 7.0 24-HR 1ST 0.0 7.0 No

544050 4616850 7.0 24-HR 1ST 0.0 7.0 No

545250 4616250 7.0 24-HR 16TH 0.0 7.0 No

545050 4616150 7.0 24-HR 4TH 0.0 7.0 No

541550 4616550 7.0 24-HR 1ST 0.6 7.0 No

543950 4615050 7.0 24-HR 1ST 0.0 7.0 No

545250 4616050 7.0 24-HR 6TH 0.0 7.0 No
 Supporting Information for Auxiliary Boiler BACT Analysis

Page 1 of 7

Capital Cost Summary Capital Cost

DIRECT COSTS

Purchased Equipment and Direct Installation Costs

Equipmenta $173,528

Instrumentationb $0

Sales Tax (7% in Indiana) $12,147

Freight (included in base equipment cost) $0

PURCHASED EQUIPMENT COST (PEC) PEC = $185,675

TOTAL DIRECT CAPITAL COST (DCC)b DCC = $185,675

INDIRECT COSTSc

Engineering (10% of PEC) $18,567

General Facilities (5% of PEC) $9,284

Process Contingency (5% of PEC) $9,284

TOTAL INDIRECT CAPITAL COST (ICC) ICC = $37,135

PROJECT CONTINGENCY (15% of ICC + DCC) (PC)c PC = $33,421

OTHER PREPRODUCTION COSTS

Preproduction Cost (2% of (DCC+ ICC + PC )) $5,125

TOTAL CAPITAL INVESTMENT (TCI = DC + IC + PC) TCI = $261,356

 Capital Costs for SCR to Control NOX - 80 MMBtu/hr Auxiliary Boiler

a Quote obtained from Taylorville Energy Center, PSD construction permit application (05040027), submitted in November 2009. Quote by Indeck 

Power Equipment Company in November 2009 was SCR cost of $500,000. Cost adjusted to 2011 dollars based on Consumer Price Index, and 

scaled using the sixth tenths power law to adjust for difference in airflow.

b Freight, instrumentation, initial catalyst charge, and direct installation costs are assumed to be included in the purchase cost quoted by Indeck in 

Tayloville Energy Center PSD construction permit application (05040027).

c U.S. EPA and OAQPS CCM, Section 4.2, Chapter 2, "Selective Catalytic Reduction (SCR)," Sixth Edition, October 2000.
Page 2 of 7

Annual Cost Summary Annual Cost

DIRECT ANNUAL COSTS

OPERATION AND MAINTENANCE c

Maintenance (1.5% of TCI) $3,920

REAGENT d

Requirement 1.1 lb/hr at $412.74 per ton $1,924

CATALYST

Catalyst Replacement e $37,135

Catalyst Life (years) c 3.00

Annual Interest Rate (%) c 7.00% 

Future Worth Factor c 0.381

Total Annual Catalyst Replacement Cost $14,150

UTILITIES f

Electricity Cost 18.07 kW at $0.0712 per kW-hr $11,269

TOTAL DIRECT ANNUAL COSTS (DAC) DAC = $31,264

INDIRECT OPERATING COSTS c

Overhead (0% for SCR) $0

Administrative Charges (2% of TCI) $5,227

Property Taxes (1% of TCI) $2,614

Insurance (1% of TCI) $2,614

Capital Recovery (CRF x TCI)

20 years @ 7.00% interest CRF= 0.0944 $24,670

TOTAL INDIRECT ANNUAL COSTS (IAC) IAC = $35,124

TOTAL ANNUALIZED COST (TAC = DAC + IAC) TAC= $66,389

Cost Effectiveness Summary

Annual Control Cost ($) $66,389

Pollutant to be Removed [NOX] (tpy) g 8.06

CONTROL COST EFFECTIVENESS ($/ton) $8,237

e

 Catalyst replacement cost assumed to be 20% of the purchased equipment cost based on EPA CCM, Section 4.2, Chapter 2, "Selective Catalytic 

Reduction (SCR)," Sixth Edition, January 2002, pg. 2-8.

f

 Based on power consumption and electricity cost equations in EPA CCM, Section 4.2, Chapter 2. Assumes a duct pressure drop of 2 inches of 

water, catalyst pressure drop of 0.75 inches of water, and three catalyst layers. Electricity price is 2009 average retail electricity cost from the 

Northern Indiana Public Service Co., for the Industrial Sector in 2009 (www.eia.doe.gov), adjusted to 2011 dollars.

g NOX emissions reductions were calculated assuming an exit concentration of 7 ppmv.

SCR Cost Analysis to Control NOX - 80 MMBtu/hr Auxiliary Boiler

d

 As shown in Appendix A.2.3 of U.S. EPA's Petroleum Refinery Tier 2 BACT Analysis Report dated January 16, 2001 (available at 

http://www.epa.gov/ttn/caaa/t1/memoranda/bactrpt.pdf), the ammonia injection rate was calculated based on the uncontrolled NOX emissions from a 

ULNB assuming 1:1 ratio of NOX to ammonia. The $300/ton reagent costs from this document was also used but was corrected for inflation.
 Supporting Information for Auxiliary Boiler BACT Analysis

Page 3 of 7

Cost Summary Cost

TOTAL CAPITAL INVESTMENT (TCI = DCC + ICC + PC) a TCI = $96,918

DIRECT ANNUAL COST b $32,306

Capital Recovery (CRF x TCI)

20 years @ 7.00% interest CRFd

 = 0.0944 $9,148

TOTAL ANNUALIZED COST TAC= $41,454

Cost Effectiveness Summary

Annual Control Cost ($) $41,454

Pollutant to be Removed [NOX] (tpy)c 5.50

CONTROL COST EFFECTIVENESS ($/ton) $7,544

 Capital and Annualized Costs for SNCR to Control NOX - 80 MMBtu/hr Auxiliary Boiler

a Based on $1,211/MMBtu/hr capital cost in 2011 dollars, calculated from the lower limit of the $900-$2,500/MMBtu/hr range provided in the 

EPA Air Pollution Control Technology Fact Sheet for SNCR in 1999 dollars.

b

 Based on $404/MMBtu/hr total annualized cost in 2011 dollars, calculated from the lower limit of the $300-$1,000/MMBtu/hr range provided in 

the EPA Air Pollution Control Technology Fact Sheet for SNCR in 1999 dollars.

c

 Emissions are conservatively based on 50 % control according to EPA Air Pollution Control Technology Fact Sheet for SNCR.

d

 Interest rate conservatively set at 7.00%, based on EPA's seven percent social interest rate from the OAQPS CCM Sixth Edition.
 Supporting Information for Auxiliary Boiler BACT Analysis

Page 4 of 7

Capital Cost Summary Capital Cost

DIRECT COSTS

Purchased Equipment Cost

Base Equipment Costa $76,115

Instrumentation (10% of equipment)b $7,611

Sales Tax (7% in Indiana) $5,328

Freight (5% of Equipment) a $3,806

Purchased Equipment Cost (PEC) PEC = $92,860

Direct Installation Costs b

Foundation and supports (8% of PEC) $7,429

Handling and erection (14% of PEC) $13,000

Electrical (4% of PEC) $3,714

Piping (2% of PEC) $1,857

Insulation for ductwork (1% of PEC) $929

Painting (1% of PEC) $929

Direct Installation Cost (DIC) DIC = $27,858

TOTAL DIRECT COSTS (DC) DC = $120,718

INDIRECT COSTSb

Engineering (10% of PEC) $9,286

Construction and field expenses (5% of PEC) $4,643

Contractor fees (10% of PEC) $9,286

Start-up (2% of PEC) $1,857

Performance test (1% of PEC) $929

Contingencies (3% of PEC) $2,786

TOTAL INDIRECT COSTS (IC) IC = $28,787

TOTAL CAPITAL INVESTMENT (TCI = DCC+ ICC) TCI = $149,504

 Capital Costs for Oxidation Catalyst to Control CO - 80 MMBtu/hr Auxiliary Boiler

a Estimated purchased equipment cost obtained in 2009 dollars from PSD construction permit application (05040027) for Taylorville 

Energy Center in Taylorville, IL submitted in November 2010. Cost adjusted to 2011 dollars using Consumer Price Index, and scaled using 

the sixth tenths power law to adjust for difference in airflow.

b

 EPA's Control Cost Manual (CCM) Section 3.2. Chapter 2 Table 2.8 Capital Cost Factors for Thermal and Catalytic Incinerators and 

Table 2.10 Annual Costs for Thermal and Catalytic Incinerators Example Problem.
Page 5 of 7

Annual Cost Summary Annual Cost

DIRECT ANNUAL COSTS

Operating Labor c

Operator (0.5 hour/shift, 3 shifts per day, 183 days/year for 50% utilization @ $29.7/man-hr) $8,153

Supervision (15% of Operator) $1,223

Maintenance c

Labor (0.5 hour/shift, 3 shifts per day, 183 days/year for 50% utilization @ $18.87/man-hr) $5,180

Material (100% of maintenance labor) $5,180

Catalyst Cost d

$22,145

TOTAL DIRECT ANNUAL COSTS (DAC) DAC = $41,880

INDIRECT ANNUAL COSTS b

Overhead (60% of Operating Labor and Maintenance) $11,841

Administrative Charges (2% of TCI) $2,990

Property Taxes (1% of TCI) $1,495

Insurance (1% of TCI) $1,495

Capital Recovery (CRF x TCI)

10 years @ 7.00% interest CRF = 0.1424 $21,286

TOTAL INDIRECT ANNUAL COSTS (IAC) IAC = $39,107

TOTAL ANNUALIZED COST (TAC = DAC + IAC) TAC= $80,988

Cost Effectiveness Summary

Annual Control Cost ($) $80,988

 26.0

CONTROL COST EFFECTIVENESS ($/ton) $3,113

Catalyst Cost: $50,061

Catalyst Disposal Cost: $4,551

Sales Tax (7%) $3,504

Capital Recovery Factor 3 years @ 7% 0.381

Pollutant to be Removed [CO] (tpy)e

c

 Labor rates based on data from the U.S Bureau of Labor Statistics May 2010 State Occupational Employment and Wage Estimates for Indiana 

(http://www.bls.gov/oes/current/oes_in.htm#51-0000), for the following Occupation Codes:

51-8013 Power Plant Operators

49-0000 Installation, Maintenance, and Repair Occupations

d Catalyst costs based upon the following data:

Obtained from PSD construction permit application (05040027) for Taylorville Energy Center in 

Taylorville, IL, submited in November 2010, for replacement cost of catalyst on CCCT, scaled using 

sixth tenth power law. Not adjusted for CPI.

e

 Based on a 90% control efficiency.

Annual Costs for Oxidation Catalyst to Control CO - 80 MMBtu/hr Auxiliary Boiler
 Supporting Information for Auxiliary Boiler BACT Analysis

Page 6 of 7

Capital Cost Summary Capital Cost

DIRECT COSTS

Purchased Equipment Cost

Base Equipment Costa $76,115

Instrumentation (10% of equipment)b $7,611

Sales Tax (7% in Indiana) $5,328

Freight (5% of Equipment) a $3,806

Purchased Equipment Cost (PEC) PEC = $92,860

Direct Installation Costs b

Foundation and supports (8% of PEC) $7,429

Handling and erection (14% of PEC) $13,000

Electrical (4% of PEC) $3,714

Piping (2% of PEC) $1,857

Insulation for ductwork (1% of PEC) $929

Painting (1% of PEC) $929

Direct Installation Cost (DIC) DIC = $27,858

TOTAL DIRECT COSTS (DC) DC = $120,718

INDIRECT COSTSb

Engineering (10% of PEC) $9,286

Construction and field expenses (5% of PEC) $4,643

Contractor fees (10% of PEC) $9,286

Start-up (2% of PEC) $1,857

Performance test (1% of PEC) $929

Contingencies (3% of PEC) $2,786

TOTAL INDIRECT COSTS (IC) IC = $28,787

TOTAL CAPITAL INVESTMENT (TCI = DCC+ ICC) TCI = $149,504

 Capital Costs for Oxidation Catalyst to Control VOC - 80 MMBtu/hr Auxiliary Boiler

a Estimated purchased equipment cost obtained in 2009 dollars from PSD construction permit application (05040027) for Taylorville 

Energy Center in Taylorville, IL submited in November 2010. Cost adjusted to 2011 dollars using Consumer Price Index, and scaled using 

the sixth tenths power law to adjust for difference in airflow.

b

 EPA's Control Cost Manual (CCM) Section 3.2. Chapter 2 Table 2.8 Capital Cost Factors for Thermal and Catalytic Incinerators and 

Table 2.10 Annual Costs for Thermal and Catalytic Incinerators Example Problem.
Page 7 of 7

Annual Cost Summary Annual Cost

DIRECT ANNUAL COSTS

Operating Labor c

Operator (0.5 hour/shift, 3 shifts per day, 183 days/year for 50% utilization @ $29.7/man-hr) $8,153

Supervision (15% of Operator) $1,223

Maintenance c

Labor (0.5 hour/shift, 3 shifts per day, 183 days/year for 50% utilization @ $18.87/man-hr) $5,180

Material (100% of maintenance labor) $5,180

Catalyst Cost d

$22,145

TOTAL DIRECT ANNUAL COSTS (DAC) DAC = $41,880

INDIRECT ANNUAL COSTS b

Overhead (60% of Operating Labor and Maintenance) $11,841

Administrative Charges (2% of TCI) $2,990

Property Taxes (1% of TCI) $1,495

Insurance (1% of TCI) $1,495

Capital Recovery (CRF x TCI)

10 years @ 7.00% interest CRF = 0.1424 $21,286

TOTAL INDIRECT ANNUAL COSTS (IAC) IAC = $39,107

TOTAL ANNUALIZED COST (TAC = DAC + IAC) TAC= $80,988

Cost Effectiveness Summary

Annual Control Cost ($) $80,988

 0.9

CONTROL COST EFFECTIVENESS ($/ton) $92,557

Catalyst Cost: $50,061

Catalyst Disposal Cost: $4,551

Sales Tax (7%) $3,504

Capital Recovery Factor 3 years @ 7% 0.381

Pollutant to be Removed [VOM] (tpy)e

c

 Labor rates based on data from the U.S Bureau of Labor Statistics May 2010 State Occupational Employment and Wage Estimates for Indiana 

(http://www.bls.gov/oes/current/oes_in.htm#51-0000), for the following Occupation Codes:

51-8013 Power Plant Operators

49-0000 Installation, Maintenance, and Repair Occupations

d Catalyst costs based upon the following data:

Obtained from PSD construction permit application (05040027) for Taylorville Energy Center in 

Taylorville, IL, submited in November 2010, for replacement cost of catalyst on CCCT, scaled using 

sixth tenth power law. Not adjusted for CPI.

e

 Based on a 50% control efficiency.

 Annual Costs for Oxidation Catalyst to Control VOC - 80 MMBtu/hr Auxiliary Boiler
What if you are not satisfied with 

this decision and you want to file an appeal?

Who may file an appeal? 

The decision described in the accompanying Notice of Decision may be administratively 

appealed. Filing an appeal is formally known as filing a “Petition for Administrative Review” to 

request an “administrative hearing.” 

If you object to this decision issued by the Indiana Department of Environmental Management 

(IDEM) and are: 1) the person to whom the decision was directed, 2) a party specified by law as 

being eligible to appeal, or 3) aggrieved or adversely affected by the decision, you are entitled to 

file an appeal. (An aggrieved or adversely affected person is one who would be considered by 

the court to be negatively impacted by the decision. If you file an appeal because you feel that 

you are aggrieved, it will be up to you to demonstrate in your appeal how you are directly 

impacted in a negative way by the decision). 

The Indiana Office of Environmental Adjudication (OEA) was established by state law – see 

Indiana Code (IC) 4-21.5-7 – and is a separate state agency independent of IDEM. The 

jurisdiction of the OEA is limited to the review of environmental pollution concerns or any 

alleged technical or legal deficiencies associated with the IDEM decision making process. Once 

your request has been received by OEA, your appeal may be considered by an Environmental 

Law Judge. 

What is required of persons filing an appeal?

Filing an appeal is a legal proceeding, so it is suggested that you consult with an attorney. Your 

request for an appeal must include your name and address and identify your interest in the 

decision (Or, if you are representing someone else, his or her name and address and their interest 

in the decision). In addition, please include a photocopy of the accompanying Notice of Decision 

or list the permit number and name of the applicant, or responsible party, in your letter. 

Before a hearing is granted, you must identify the reason for the appeal request and the issues 

proposed for consideration at the hearing. You also must identify the permit terms and 

conditions that, in your judgment, would appropriately satisfy the requirements of law with 

respect to the IDEM decision being appealed. That is, you must suggest an alternative to the 

language in the permit (or other order, or decision) being appealed, and your suggested changes 

must be consistent with all applicable laws (See Indiana Code 13-15-6-2) and rules (See Title 

315 of the Indiana Administrative Code, or 315 IAC). 

The effective date of this agency action is stated on the accompanying Notice of Decision (or 

other IDEM decision notice). If you file a “Petition for Administrative Review” (appeal), you 

may wish to specifically request that the action be “stayed” (temporarily halted) because most 

appeals do not allow for an automatic “stay.” If, after an evidentiary hearing, a “stay” is granted, 

the IDEM-approved action may be halted altogether, or only allowed to continue in part, until a 

final decision has been made regarding the appeal. However, if the action is not “stayed” the 

IDEM-approved activity will be allowed to continue during the appeal process. 

 (See reverse side) 
Where can you file an appeal? 

If you wish to file an appeal, you must do so in writing. There are no standard forms to fill out 

and submit, so you must state your case in a letter (called a petition for administrative review) to 

the Indiana Office of Environmental Adjudication (OEA). Do not send the original copy of your 

appeal request to IDEM. Instead, send or deliver your letter to: 

 

The Indiana Office of Environmental Adjudication 

100 North Senate Ave. 

Indiana Government Center North 

Room N501E 

Indianapolis, IN 46204 

If you file an appeal, also please send a copy of your appeal letter to the IDEM contact person 

identified in the Notice of Decision, and to the applicant (person receiving an IDEM permit, or 

other approval). 

 

Your appeal (petition for administrative review) must be received by the Office of 

Environmental Adjudication in a timely manner. Different types of permit approvals have 

different deadlines for filing an appeal. The accompanying Notice of Decision (NOD) explains 

how to determine the due date for filing an appeal for this particular permit decision. To ensure 

that you meet this filing requirement, your appeal request must be: 

1) Delivered in person to the OEA by the close-of-business on the due date. (If the due date falls 

on a day when the Office of Environmental Adjudication (OEA) is closed for the weekend or 

for a state holiday, then your petition will be accepted on the next business day on which 

OEA is open.); or 

2) Given to a private carrier who will deliver it to the OEA on your behalf, (and from whom 

you must obtain a receipt dated on or before the due date); or 

3) For those appeal requests sent by U.S. Mail, your letter must be postmarked by no later than 

midnight of the due date; or 

4) Faxed to the OEA at 317/233-9372 before the close-of-business of the due date, provided 

that the original signed “Petition for Administrative Review” is also sent, or delivered, to the 

OEA in a timely manner. 

What are the costs associated with filing an appeal? 

The OEA does not charge a fee for filing documents for an administrative review or for the use 

of its hearing facilities. However, OEA does charge a fifteen cent ($.15) per page fee for copies 

of any documents you may request. Another cost that could be associated with your appeal 

would be for attorney’s fees. Although you have the option to act as your own attorney, the 

administrative review and associated hearing are complex legal proceedings; therefore, you 

should consider whether your interests would be better represented by an experienced attorney. 

What can you expect from the Office of Environmental Adjudication (OEA) after you file 

for an appeal? 

The OEA will provide you with notice of any prehearing conferences, preliminary hearings, 

hearings, “stays,” or orders disposing of the review of this decision. In addition, you may 

contact the OEA by phone at 317/232-8591 with any scheduling questions. However, technical 

questions should be directed to IDEM at the number indicated on the Notice of Decision. 

Do not expect to discuss details of your case with the OEA other than in a formal setting such as 

a prehearing conference, a formal hearing, or a settlement conference. The OEA is not allowed 

to discuss a case without all sides being present. All parties to the proceeding are expected to 

appear at the initial prehearing conference. 
INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

We Protect Hoosiers and Our Environment.

Mitchell E. Daniels Jr. 100 North Senate Avenue

Governor Indianapolis, Indiana 46204

(317) 232-8603

Thomas W. Easterly Toll Free (800) 451-6027

Commissioner www.idem.IN.gov

 Recycled Paper An Equal Opportunity Employer Please Recycle 

SENT VIA U.S. MAIL: CONFIRMED DELIVERY AND SIGNATURE REQUESTED

TO: Willard Ladd

St. Joseph Energy Center, LLC

c/o Development Partners Group

11 Martine Ave, Flr. 9

White Plains, NY 10606

DATE: December 3, 2012

FROM: Matt Stuckey, Branch Chief

Permits Branch

Office of Air Quality

SUBJECT: Final Decision

Title V

141-31003-00579

Enclosed is the final decision and supporting materials for the air permit application referenced above. 

Please note that this packet contains the original, signed, permit documents. 

The final decision is being sent to you because our records indicate that you are the contact person for this 

application. However, if you are not the appropriate person within your company to receive this document, 

please forward it to the correct person. 

A copy of the final decision and supporting materials has also been sent via standard mail to: 

OAQ Permits Branch Interested Parties List

If you have technical questions regarding the enclosed documents, please contact the Office of Air Quality, 

Permits Branch at (317) 233-0178, or toll-free at 1-800-451-6027 (ext. 3-0178), and ask to speak to the 

permit reviewer who prepared the permit. If you think you have received this document in error, please 

contact Joanne Smiddie-Brush of my staff at 1-800-451-6027 (ext 3-0185), or via e-mail at 

jbrush@idem.IN.gov. 

Final Applicant Cover letter.dot 11/30/07
INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

We Protect Hoosiers and Our Environment.

Mitchell E. Daniels Jr. 100 North Senate Avenue

Governor Indianapolis, Indiana 46204

(317) 232-8603

Thomas W. Easterly Toll Free (800) 451-6027

Commissioner www.idem.IN.gov

 Recycled Paper An Equal Opportunity Employer Please Recycle 

December 3, 2012

TO: New Carlisle Olive Township Library

From: Matthew Stuckey, Branch Chief

Permits Branch 

 Office of Air Quality

Subject: Important Information for Display Regarding a Final Determination

Applicant Name: St. Joseph Energy Center, LLC

Permit Number: 141-31003-00579

You previously received information to make available to the public during the public comment 

period of a draft permit. Enclosed is a copy of the final decision and supporting materials for the 

same project. Please place the enclosed information along with the information you previously 

received. To ensure that your patrons have ample opportunity to review the enclosed permit, we

ask that you retain this document for at least 60 days.

The applicant is responsible for placing a copy of the application in your library. If the permit 

application is not on file, or if you have any questions concerning this public review process, 

please contact Joanne Smiddie-Brush, OAQ Permits Administration Section at 1-800-451-6027, 

extension 3-0185. 

Enclosures

Final Library.dot 11/30/07
INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

We Protect Hoosiers and Our Environment.

Mitchell E. Daniels Jr. 100 North Senate Avenue

Governor Indianapolis, Indiana 46204

(317) 232-8603

Thomas W. Easterly Toll Free (800) 451-6027

Commissioner www.idem.IN.gov

 Recycled Paper An Equal Opportunity Employer Please Recycle 

TO: Interested Parties / Applicant

DATE: December 3, 2012

RE: St. Joseph Energy Center, LLC / 141-31003-00579

FROM: Matthew Stuckey, Branch Chief

Permits Branch

Office of Air Quality

In order to conserve paper and reduce postage costs, IDEM’s Office of Air Quality is 

now sending many permit decisions on CDs in Adobe PDF format. The enclosed CD 

contains information regarding the company named above.

This permit is also available on the IDEM website at:

http://www.in.gov/ai/appfiles/idem-caats/

If you would like to request a paper copy of the permit document, please contact IDEM’s 

central file room at:

Indiana Government Center North, Room 1201

100 North Senate Avenue, MC 50-07

Indianapolis, IN 46204

Phone: 1-800-451-6027 (ext. 4-0965)

Fax (317) 232-8659

Please Note: If you feel you have received this information in error, or would like to be 

removed from the Air Permits mailing list, please contact Patricia Pear with the Air 

Permits Administration Section at 1-800-451-6027, ext. 3-6875 or via e-mail at 

PPEAR@IDEM.IN.GOV. 

Enclosures

CD Memo.dot 11/14/08
FACSIMILIE OF PS Form 3877

Mail Code 61-53

IDEM Staff MIDENNEY 12/3/2012

St. Joseph Energy Center LLC 141-31003-00579 (final) AFFIX STAMP

HERE IF

USED AS

CERTIFICATE

OF MAILING

Name and 

address of 

Sender ► Indiana Department of Environmental 

Management

Office of Air Quality – Permits Branch

100 N. Senate

Indianapolis, IN 46204

Type of Mail:

CERTIFICATE OF 

MAILING ONLY

Line Article 

Number

Name, Address, Street and Post Office Address Postage Handing 

Charges

Act. Value

(If Registered)

Insured 

Value

Due Send if 

COD

R.R. 

Fee

S.D. Fee S.H. 

Fee

Rest. 

Del. Fee

Remarks

1 Willard Ladd St. Joseph Energy Center LLC c/o Devlpmnt Partners Grp, 11 Martine Ave Fl 9 White Plains NY 10606 (Source CAATS) via confirm delivery

2 Ken Herceg 211 W. Washington St, Ste 2100 South Bend IN 46601 (Affected Party)

3 Keith Varga 54983 Tulip Rd New Carlisle IN 46552 (Affected Party)

4 Mr. Wayne Falda South Bend Tribune 255 W Colfax Ave South Bend IN 46626 (Affected Party)

5 New Carlisle Town Council 113 South Arch Street, P.O. Box 6 New Carlisle IN 46552 (Local Official)

6 South Bend City Council / Mayors Office 227 W. Jefferson Blvd. South Bend IN 46601 (Local Official)

7 St. Joseph County Board of Commissioners 227 West Jefferson Blvd, South Bend IN 46601 (Local Official)

8 St. Joseph County Health Department 227 W Jefferson Blvd, Room 825 South Bend IN 46601-1870 (Health Department)

9 New Carlisle Olive Township Library 408 S. Bray Street New Carlisle IN 46552 (Library)

10 Jeffrey L. Rea 401 E. Colfax South Bend IN 46617 (Affected Party)

11 Jack Daly P.O. Box 696 New Carlisle IN 46552 (Affected Party)

12 Inland Steel Company 3210 Watling St East Chicago IN 46312 (Affected Party)

13 NICTD 33 East US Hwy 12 Chesterton IN 46304 (Affected Party)

14 Debruce Grain Inc 4100 N Mulberry Dr, Ste 300 Kansas City MO 64116 (Affected Party)

15 Mr. Kenneth E. Sebasty 31527 US 20 New Carlisle IN 46552 (Affected Party)

Total number of pieces

Listed by Sender

14

Total number of Pieces 

Received at Post Office

Postmaster, Per (Name of 

Receiving employee)

The full declaration of value is required on all domestic and international registered mail. The 

maximum indemnity payable for the reconstruction of nonnegotiable documents under Express 

Mail document reconstructing insurance is $50,000 per piece subject to a limit of $50, 000 per 

occurrence. The maximum indemnity payable on Express mil merchandise insurance is $500. 

The maximum indemnity payable is $25,000 for registered mail, sent with optional postal 

insurance. See Domestic Mail Manual R900, S913, and S921 for limitations of coverage on 

inured and COD mail. See International Mail Manual for limitations o coverage on international 

mail. Special handling charges apply only to Standard Mail (A) and Standard Mail (B) parcels.
FACSIMILIE OF PS Form 3877

Mail Code 61-53

IDEM Staff MIDENNEY 12/3/2012

St. Joseph Energy Center LLC 141-31003-00579 (final) AFFIX STAMP

HERE IF

USED AS

CERTIFICATE

OF MAILING

Name and 

address of 

Sender ► Indiana Department of Environmental 

Management

Office of Air Quality – Permits Branch

100 N. Senate

Indianapolis, IN 46204

Type of Mail:

CERTIFICATE OF 

MAILING ONLY

Line Article 

Number

Name, Address, Street and Post Office Address Postage Handing 

Charges

Act. Value

(If Registered)

Insured 

Value

Due Send if 

COD

R.R. 

Fee

S.D. Fee S.H. 

Fee

Rest. 

Del. Fee

Remarks

1 Thomas H. & Nancy Lake Lake Farm Service Inc 54300 Walnut Rd New Carlisle IN 46552 (Affected Party)

2 Kenneth P & Kimberley K Huston 29167 US Hwy 20 New Carlisle IN 46552 (Affected Party)

3 Indiana/ Michigan Electric Company ATT: Tax Dept PO Box 16428 Columbus OH 43216 (Affected Party)

4 Golden Realty LLC 65 Pheasant Dr East Greenwich RI 02818 (Affected Party)

5 Lakes Farm Services LLC 4100 N Mulberry Dr, Ste 300 Kansas City MO 64116 (Affected Party)

6 Susan Jones 2867 N 925 E Millcreek IN 46365 (Affected Party)

7 Mike Compton 1345 Northside Blvd South Bend IN 46615 (Affected Party)

8 Rafael Morton St. Joseph County Council County City Building 4th Floor South Bend IN 46601 (Local Official)

9 Donald Fozo 3512 Sugar Maple Ct South Bend IN 46628 (Affected Party)

10 James Scheetz 22405 New Rd South Bend IN 46614 (Affected Party)

11 Charles Dadlow 29430 State Rd 2 Canton MI 46592 (Affected Party)

12 Larry Truex 7955 N. LaPorte New Carlisle IN 46552 (Affected Party)

13 Kenneth Carter 201 W. Ada New Carlisle IN 46552 (Affected Party)

14 Murray Miller 23698 Western Ave South Bend IN 46619 (Affected Party)

15 Elizabeth Miller 51677 Sycamore Rd New Carlisle IN 46552 (Affected Party)

Total number of pieces

Listed by Sender

15

Total number of Pieces 

Received at Post Office

Postmaster, Per (Name of 

Receiving employee)

The full declaration of value is required on all domestic and international registered mail. The 

maximum indemnity payable for the reconstruction of nonnegotiable documents under Express 

Mail document reconstructing insurance is $50,000 per piece subject to a limit of $50, 000 per 

occurrence. The maximum indemnity payable on Express mil merchandise insurance is $500. 

The maximum indemnity payable is $25,000 for registered mail, sent with optional postal 

insurance. See Domestic Mail Manual R900, S913, and S921 for limitations of coverage on 

inured and COD mail. See International Mail Manual for limitations o coverage on international 

mail. Special handling charges apply only to Standard Mail (A) and Standard Mail (B) parcels.
FACSIMILIE OF PS Form 3877

Mail Code 61-53

IDEM Staff MIDENNEY 12/3/2012

St. Joseph Energy Center LLC 141-31003-00579 (final) AFFIX STAMP

HERE IF

USED AS

CERTIFICATE

OF MAILING

Name and 

address of 

Sender ► Indiana Department of Environmental 

Management

Office of Air Quality – Permits Branch

100 N. Senate

Indianapolis, IN 46204

Type of Mail:

CERTIFICATE OF 

MAILING ONLY

Line Article 

Number

Name, Address, Street and Post Office Address Postage Handing 

Charges

Act. Value

(If Registered)

Insured 

Value

Due Send if 

COD

R.R. 

Fee

S.D. Fee S.H. 

Fee

Rest. 

Del. Fee

Remarks

1 Thomas & Susan Baker 29779 Edison Rd New Carlisle IN 46552 (Affected Party)

2 News WSBT-TV 1301 E. Douglas Rd Mishawaka IN 46545 (Affected Party)

3 Thomas Swaney 32100 Edison Rd New Carlisle IN 46552 (Affected Party)

4

5

6

7

8

9

10

11

12

13

14

15

Total number of pieces

Listed by Sender

3

Total number of Pieces 

Received at Post Office

Postmaster, Per (Name of 

Receiving employee)

The full declaration of value is required on all domestic and international registered mail. The 

maximum indemnity payable for the reconstruction of nonnegotiable documents under Express 

Mail document reconstructing insurance is $50,000 per piece subject to a limit of $50, 000 per 

occurrence. The maximum indemnity payable on Express mil merchandise insurance is $500. 

The maximum indemnity payable is $25,000 for registered mail, sent with optional postal 

insurance. See Domestic Mail Manual R900, S913, and S921 for limitations of coverage on 

inured and COD mail. See International Mail Manual for limitations o coverage on international 

mail. Special handling charges apply only to Standard Mail (A) and Standard Mail (B) parcels.