INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

We Protect Hoosiers and Our Environment. 

100 N. Senate Avenue • Indianapolis, IN 46204

(800) 451-6027 • (317) 232-8603 • www.idem.IN.gov

 Michael R. Pence Thomas W. Easterly 

 Governor Commissioner

An Equal Opportunity Employer Recycled Paper

TO: Interested Parties / Applicant 

DATE: October 11, 2013

RE: IPL - Eagle Valley/109-32471-00004 

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 according to IC 13-15-6-3, 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 and IC 13-15-6-1 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, within eighteen (18) calendar days of the mailing of this notice. 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. 

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 

 FNPER.dot 6/13/13 

IPL Eagle Valley Generating Station Page 2 of 3

Martinsville, IN PSD/Source Modification No. 109-32471-00004

new affected sources.]

(c) One (1) evaporative cooling tower, identified as emission unit U-7, with a rated circulation 

rate of 192,000 gpm to provide non-contact cooling water to the steam turbine condenser, 

permitted in 2013, and equipped with high efficiency drift eliminators. 

(d) Electrical Circuit Breakers containing sulfur hexafluoride (SF6) identified as emissions unit 

F-1, permitted in 2013, with fugitive emissions controlled by full enclosure.

(e) Fugitive equipment leaks from the natural gas supply lines, identified as F-2 controlled by 

a Leak Detection and Repair (LDAR) program.

(f) Three (3) Turbine Lube Demister Vents, permitted in 2013.

The following construction conditions are applicable to the proposed project:

General Construction Conditions

1. The data and information supplied with the application shall be considered part of this 

source modification approval. Prior to any proposed change in construction which may 

affect the potential to emit (PTE) of the proposed project, the change must be approved 

by the Office of Air Quality (OAQ).

2. This approval 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.

3. Effective Date of the Permit

Pursuant to IC 13-15-5-3, this approval becomes effective upon its issuance.

4. Pursuant to 326 IAC 2-1.1-9 and 326 IAC 2-7-10.5(i), the Commissioner may revoke this 

approval 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.

5. All requirements and conditions of this construction approval shall remain in effect unless 

modified in a manner consistent with procedures established pursuant to 326 IAC 2.

6. Pursuant to 326 IAC 2-7-10.5(l) the emission units constructed under this approval shall 

not be placed into operation prior to revision of the source’s Part 70 Operating Permit to 

incorporate the required operation conditions.

This significant source modification authorizes construction of the new emission units. Operating 

conditions shall be incorporated into the Part 70 operating permit as a significant permit modification in 

accordance with 326 IAC 2-7-10.5(l)(2) and 326 IAC 2-7-12. Operation is not approved until the significant 

permit modification has been issued.

All other conditions of the permit shall remain unchanged and in effect. For your convenience, the 

entire Part 70 Operating Permit as modified will be provided at issuance.

This decision is subject to the Indiana Administrative Orders and Procedures Act – IC 4-21.5-3-5. 

If you have any questions on this matter, please contact Josiah Balogun, OAQ, 100 North Senate Avenue, 

MC 61-53, Room 1003, Indianapolis, Indiana, 46204-2251, or call at (800) 451-6027, and ask for Josiah 

Balogun or extension (4-5257), or dial (317) 234-5257.


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Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

TABLE OF CONTENTS

A SOURCE SUMMARY

A.1 General Information [326 IAC 2-7-4(c)] [326 IAC 2-7-5(15)] [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(15)]

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

[326 IAC 2-7-5(15)]

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

B GENERAL CONDITIONS

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

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

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

B.3 Term of Conditions [326 IAC 2-1.1-9.5]

B.4 Enforceability [326 IAC 2-7-7]

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

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

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

B.8 Certification [326 IAC 2-7-4(f)] [326 IAC 2-7-5(3)(C)] [326 IAC 2-7-6(1)]

B.9 Annual Compliance Certification [326 IAC 2-7-6(5)]

B.10 Preventive Maintenance Plan [326 IAC 1-6-3] [326 IAC 2-7-5(1),(3) and (13)] 

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

B.11 Emergency Provisions [326 IAC 2-7-16]

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

B.13 Prior Permits Superseded [326 IAC 2-1.1-9.5] [326 IAC 2-7-10.5]

B.14 Termination of Right to Operate [326 IAC 2-7-4(a)] [326 IAC 2-7-10]

B.15 Deviations from Permit Requirements and Conditions [326 IAC 2-7-5(3)(C)(ii)]

B.16 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.17 Permit Renewal [326 IAC 2-7-3] [326 IAC 2-7-4] [326 IAC 2-7-8(e)]

B.18 Permit Amendment or Modification [326 IAC 2-7-11] [326 IAC 2-7-12] [40 CFR 72]

B.19 Permit Revision Under Economic Incentives and Other Programs [326 IAC 2-7-5(8)] 

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

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

B.21 Source Modification Requirement [326 IAC 2-7-10.5]

B.22 Inspection and Entry [326 IAC 2-7-6] [IC 13-14-2-2] [IC 13-17-3-2] [IC 13-30-3-1]

B.23 Transfer of Ownership or Operational Control [326 IAC 2-7-11]

B.24 Annual Fee Payment [326 IAC 2-1.1-7] [326 IAC 2-7-5(7)] [326 IAC 2-7-19]

B.25 Credible Evidence [326 IAC 1-1-6] [326 IAC 2-7-5(3)] [326 IAC 2-7-6] [62 FR 8314]

C SOURCE OPERATION CONDITIONS

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

C.1 Particulate Emission Limitations for Processes with Process Weight Rates Less Than 

One Hundred (100) Pounds per Hour [326 IAC 6-3-2]

C.2 Opacity [326 IAC 5-1]

C.3 Open Burning [326 IAC 4-1] [IC 13-17-9]

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

C.5 Fugitive Dust Emissions [326 IAC 6-4]

C.6 Motor Vehicle Fugitive Dust Sources [326 IAC 6-4-4]

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

C.8 Asbestos Abatement Projects [326 IAC 14-10] [326 IAC 18] [40 CFR Part 61, Subpart M]
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Testing Requirements [326 IAC 2-7-6(1)]

C.9 Performance Testing [326 IAC 3-6]

Compliance Requirements [326 IAC 2-1.1-11]

C.10 Compliance Requirements [326 IAC 2-1.1-11]

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

C.11 Compliance Monitoring [326 IAC 2-7-5(3)] [326 IAC 2-7-6(1)]

C.12 Maintenance of Continuous Opacity Monitoring Equipment [326 IAC 2-7-5(3)(A)(iii)]

C.13 Maintenance of Continuous Emissions Monitoring Equipment [326 IAC 2-7-5(3)(A)]

C.14 Monitoring Methods [326 IAC 3] [40 CFR 60] [40 CFR 63]

C.15 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.16 Emergency Reduction Plans [326 IAC 1-5-2] [326 IAC 1-5-3]

C.17 Risk Management Plan [326 IAC 2-7-5(12)] [40 CFR 68]

C.18 Response to Excursions or Exceedances [326 IAC 2-7-5] [326 IAC 2-7-6]

C.19 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.20 Emission Statement [326 IAC 2-6] [326 IAC 2-7-5(3)(C)(iii)] [326 IAC 2-7-5(7)] 

[326 IAC 2-7-19(c)]

C.21 General Record Keeping Requirements [326 IAC 2-2] [326 IAC 2-3] [326 IAC 2-7-5(3)] 

[326 IAC 2-7-6]

C.22 General Reporting Requirements [326 IAC 2-1.1-11] [326 IAC 2-2] [326 IAC 2-3] 

[326 IAC 2-7-5(3)(C)]

Stratospheric Ozone Protection

C.23 Compliance with 40 CFR 82 and 326 IAC 22-1 

D.1 FACILITY OPERATION CONDITIONS - Oil-Fired Boilers

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

D.1.0 Air Quality Analysis Requirements [326 IAC 2-2-4] 

D.1.1 Particulate Emission Limitations for Sources of Indirect Heating [326 IAC 6-2-2]

D.1.2 Temporary Alternative Opacity Limitations [326 IAC 5-1-3]

D.1.3 Sulfur Dioxide (SO2) [326 IAC 7-4-11]

Compliance Determination Requirements

D.1.4 Testing Requirements [326 IAC 2-7-6(1),(6)] [326 IAC 2-1.1-11]

D.1.5 Sulfur Dioxide Emissions and Sulfur Content [326 IAC 3-7-4] [326 IAC 7-4-11]

D.1.6 RESERVED

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

D.1.7 Visible Emissions Notations [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)]

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

D.1.8 Record Keeping Requirements

D.1.9 Reporting Requirements

D.2 FACILITY OPERATION CONDITIONS - Coal-Fired Boilers

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

D.2.0 Air Quality Analysis Requirements [326 IAC 2-2-4] 

D.2.1 Particulate Emission Limitations for Sources of Indirect Heating [326 IAC 6-2-2]
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D.2.2 Temporary Alternative Opacity Limitations [326 IAC 5-1-3]

D.2.3 Sulfur Dioxide (SO2) [326 IAC 7-4-11]

Compliance Determination Requirements

D.2.4 Testing Requirements [326 IAC 2-7-6(1),(6)] [326 IAC 2-1.1-11]

D.2.5 Operation of Electrostatic Precipitator [326 IAC 2-7-6(6)]

D.2.6 Continuous Emissions Monitoring [326 IAC 3-5]

D.2.7 Sulfur Dioxide Emissions and Sulfur Content [326 IAC 7-2] [326 IAC 7-4-11]

D.2.8 RESERVED

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

D.2.9 Transformer-Rectifier (T-R) Sets [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)] [40 CFR 64]

D.2.10 Opacity Readings [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)]

D.2.11 SO2 Monitor Downtime [326 IAC 2-7-6(1)] [326 IAC 2-7-5(3)]

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

D.2.12 Record Keeping Requirements

D.2.13 Reporting Requirements

D.3 FACILITY OPERATION CONDITIONS - Oil-Fired Generator

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

D.3.0 Air Quality Analysis Requirements [326 IAC 2-2-4] 

D.3.1 Sulfur Dioxide (SO2) [326 IAC 7-1.1-2]

Compliance Determination Requirements

D.3.2 Sulfur Dioxide Emissions and Sulfur Content [326 IAC 3-7-4] [326 IAC 7-1.1-2]

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

D.3.3 Record Keeping Requirements

D.3.4 Reporting Requirements

D.4 FACILITY OPERATION CONDITIONS - Coal Handling

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

D.4.0 Air Quality Analysis Requirements [326 IAC 2-2-4] 

D.4.1 Particulate [326 IAC 6-3-2]

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

D.4.2 Visible Emissions Notations [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)] 

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

D.4.3 Record Keeping Requirements

D.5 FACILITY OPERATION CONDITIONS - Fly Ash Storage and Handling

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

D.5.0 Air Quality Analysis Requirements [326 IAC 2-2-4] 

D.5.1 PSD Minor Limits and Nonattainment NSR [326 IAC 2-2] [326 IAC 2-1.1-5] 

D.5.2 Particulate Emission Limitations for Manufacturing Processes [326 IAC 6-3-2]

Compliance Determination Requirements

D.5.3 Particulate Matter (PM)

D.5.4 Testing Requirements [326 IAC 2-7-6(1),(6)] [326 IAC 2-1.1-11]
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Compliance Monitoring Requirements [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)]

D.5.5 Visible Emissions Notations [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)]

D.5.6 Parametric Monitoring

D.5.7 Broken or Failed Bag Detection

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

D.5.8 Record Keeping Requirements

D.6 FACILITY OPERATION CONDITIONS - Ash Handling

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

D.6.0 Air Quality Analysis Requirements [326 IAC 2-2-4] 

D.6.1 Fugitive Dust Emission Limitations [326 IAC 6-4-2]

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

D.6.2 Visible Emissions Notations [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)]

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

D.6.3 Record Keeping Requirements

D.7. EMISSIONS UNIT OPERATION CONDITIONS

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

D.7.1 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3] 

D.7.2 H2SO4 PSD BACT [326 IAC 2-2-3] 

D.7.3 CO PSD BACT [326 IAC 2-2-3] 

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

D.7.5 NOx PSD BACT [326 IAC 2-2-3] 

D.7.6 GHGs PSD BACT [326 IAC 2-2-3] 

D.7.7 Hazardous Air Pollutants (HAPs) Minor Limits 

D.7.8 Startup, Shutdown and Other Opacity Limits [326 IAC 5-1-3] 

Compliance Determination Requirements

D.7.9 Oxidation Catalyst Control

D.7.10 Nitrogen Oxide Control 

D.7.11 H2SO4 Compliance Determination Requirements [326 IAC 2-2] 

D.7.12 Greenhouse Gases (GHGs) Calculations 

D.7.13 HAPs Minor Limits Calculations 

D.7.14 Maintenance of Continuous Emission Monitoring Equipment [326 IAC 3-5][326 IAC 2-2-3]

D.7.15 Testing Requirements [326 IAC 2-1.1-11]

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

D.7.16 Oxidation Catalyst Parametric Monitoring 

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

D.7.17 Record Keeping Requirement

D.7.18 Reporting Requirements 

D.8. EMISSIONS UNIT OPERATION CONDITIONS

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

D.8.1 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3] 
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D.8.2 H2SO4 PSD BACT [326 IAC 2-2-3] 

D.8.3 CO PSD BACT [326 IAC 2-2-3] 

D.8.4 VOC PSD BACT [326 IAC 2-2-3] 

D.8.5 NOx PSD BACT [326 IAC 2-2-3] 

D.8.6 GHGs PSD BACT [326 IAC 2-2-3] 

D.8.7 Startup, Shutdown and Other Opacity Limits [326 IAC 5-1-3] 

Compliance Determination Requirements

D.8.8 Nitrogen Oxide Control 

D.8.9 H2SO4 Compliance Determination Requirements [326 IAC 2-2] 

D.8.10 Testing Requirements [326 IAC 2-1.1-11]

D.8.11 Greenhouse Gases (GHGs) Calculations 

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

D.8.12 Record Keeping Requirement

D.8.13 Reporting Requirements 

D.9. EMISSIONS UNIT OPERATION CONDITIONS

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

D.9.1 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3] 

D.9.2 H2SO4 PSD BACT [326 IAC 2-2-3] 

D.9.3 CO PSD BACT [326 IAC 2-2-3] 

D.9.4 VOC PSD BACT [326 IAC 2-2-3] 

D.9.5 NOx PSD BACT [326 IAC 2-2-3] 

D.9.6 GHGs PSD BACT [326 IAC 2-2-3] 

Compliance Determination Requirements

D.9.7 Nitrogen Oxide Control 

D.9.8 H2SO4 Compliance Determination Requirements [326 IAC 2-2] 

D.9.9 Greenhouse Gases (GHGs) Calculations 

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

D.9.10 Record Keeping Requirement

D.9.11 Reporting Requirements 

D.10. EMISSIONS UNIT OPERATION CONDITIONS

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

D.10.1 PM, PM10, PM2.5, H2SO4, VOC, CO, NOx and GHGs PSD BACT [326 IAC 2-2-3] 

D.10.2 PM, PM10, PM2.5, H2SO4, VOC, CO, NOx and GHGs PSD BACT [326 IAC 2-2-3] 

Compliance Determination Requirements

D.10.3 Greenhouse Gases (GHGs) Calculations

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

D.10.4 Record Keeping Requirement

D.10.5 Reporting Requirements 
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D.11. EMISSIONS UNIT OPERATION CONDITIONS

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

D.11.1 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3] 

Compliance Determination Requirements

D.11.2 PM, PM10 and PM2.5 Control [326 IAC 2-1.1-11]

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

D.11.3 Record Keeping Requirement

D.12. EMISSIONS UNIT OPERATION CONDITIONS

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

D.12.1 GHGs PSD BACT [326 IAC 2-2-3] 

D.13. EMISSIONS UNIT OPERATION CONDITIONS

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

D.13.1 GHGs PSD BACT [326 IAC 2-2-3] 

D.14. EMISSIONS UNIT OPERATION CONDITIONS

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

D.14.1 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

E.1 ACID RAIN PROGRAM CONDITIONS

Acid Rain Program

E.1.1 Acid Rain Permit [326 IAC 2-7-5(1)(C)] [326 IAC 21] [40 CFR 72 through 40 CFR 78]

E.1.2 Title IV Emissions Allowances [326 IAC 2-7-5(4)] [326 IAC 21]

E.2. EMISSIONS UNIT OPERATION CONDITIONS

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

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 Stationary Combustion Turbines Requirements [40 

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

E.3. EMISSIONS UNIT OPERATION CONDITIONS

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

E.3.1 General Provisions Relating to New Source Performance Standard [326 IAC 12-1][40 CFR 

Part 60, Subpart A]

E.3.2 New Source Performance Standard for Small-Commercial-Institutional Steam Generating 

Units Requirements [40 CFR Part 60, Subpart Dc] [326 IAC 12]
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E.4. EMISSIONS UNIT OPERATION CONDITIONS

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

E.4.1 General Provisions Relating to NSPS IIII [326 IAC 12][40 CFR Part 60, Subpart A]

E.4.2 Standard of Performance for Stationary Compression Inginition Internal Combustion 

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

E.5. EMISSIONS UNIT OPERATION CONDITIONS

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

E.5.1 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.5.2 National Emissions Standard for Hazardous Air Pollutants for Stationary 

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

 20-82-1] 

F Reserved

G Clean Air Interstate Rule (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)

G.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)]

G.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)]

G.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)]

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

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

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

[40 CFR 97.306(c)]

G.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)]

G.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)]

G.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)]

G.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)]

G.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)]
IPL Eagle Valley Generating Station Page 9 of 104

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Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

Certification

Emergency Occurrence Report

Quarterly Reports 

Quarterly Deviation and Compliance Monitoring Report

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 
IPL Eagle Valley Generating Station Page 10 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

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.

A.1 General Information [326 IAC 2-7-4(c)] [326 IAC 2-7-5(15)] [326 IAC 2-7-1(22)]

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

Source Address: 4040 Blue Bluff Road, Martinsville, Indiana, 46151

Mailing Address: 4040 Blue Bluff Road, Martinsville, Indiana, 46151

Source Telephone: 765-349-3413

SIC Code: 4911

County Location: Morgan

County Status: Attainment for all criteria pollutants

Source Status: Part 70 Operating Permit Program

Major Source, under PSD Rules;

Major 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(15)]

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

(a) Two (2) no. 2 fuel oil fired boilers, identified as Unit 1 and Unit 2, constructed in 1949 and 

1950, respectively, each with a design heat input capacity of 524 million Btu per hour 

(MMBtu/hr), both exhausting to stack 1-1.

(b) One (1) tangentially-fired wet-bottom coal boiler, identified as Unit 3, constructed in 1951, 

with a design heat input capacity of 524 million Btu per hour (MMBtu/hr), with an 

electrostatic precipitator (ESP) and flue gas conditioning system for control of particulate 

matter, exhausting to stack 2-1. Unit 3 will combust no. 2 fuel oil during startup, 

shutdown, and stabilization periods. Used oil generated onsite and used oil contaminated

materials generated onsite may be combusted in Unit 3 as supplemental fuel for energy 

recovery. Stack 2-1 has continuous emission monitoring systems (CEMS) for NOX and 

SO2 and a continuous opacity monitor (COM).

(c) One (1) tangentially-fired dry-bottom coal fired boiler, identified as Unit 4, constructed in 

1953, with a design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an 

electrostatic precipitator (ESP) and flue gas conditioning system for control of particulate 

matter, exhausting to stack 2-1. Unit 4 is equipped with separated overfire air (SOFA) 

and low NOX burners (LNB) for control of NOX emissions, which were voluntarily installed 

and are not required to operate. Unit 4 will combust no. 2 fuel oil during startup, 

shutdown, and stabilization periods. Stack 2-1 has continuous emission monitoring 

systems (CEMS) for NOX and SO2 and a continuous opacity monitor (COM).

(d) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 5, constructed in 1953, 

with a design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an 

electrostatic precipitator (ESP) and flue gas conditioning system for control of particulate 

matter, exhausting to stack 3-1. Unit 5 is equipped with SOFA and LNB for control of 

NOX emissions, which were voluntarily installed and are not required to operate. Unit 5 

will combust no. 2 fuel oil during startup, shutdown, and stabilization periods. Stack 3-1 

has continuous emission monitoring systems (CEMS) for NOX and SO2 and a continuous 

opacity monitor (COM).
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(e) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 6, constructed in 1956, 

with a design heat input capacity of 1017 million Btu per hour (MMBtu/hr), with an 

electrostatic precipitator (ESP) for control of particulate matter, exhausting to stack 3-1. 

Unit 6 is equipped with Closed-coupled Overfire Air (COFA) for control of NOX emissions, 

which was voluntarily installed and is not required to operate. Unit 6 will combust no. 2 

fuel oil during startup, shutdown, and stabilization periods. Used oil generated onsite 

may be combusted in Unit 6 as supplemental fuel for energy recovery. Unit 6 has had 

low-NOX burners installed. Stack 3-1 has continuous emission monitoring systems 

(CEMS) for NOX and SO2 and a continuous opacity monitor (COM).

(f) One (1) distillate oil fired generator, identified as Unit PR-10, constructed in 1967, with a 

design heat input capacity of 28.4 million Btu per hour (MMBtu/hr), exhausting to stack 

PR10-1.

(g) Coal transfer facilities, with a maximum throughput of 800 tons per hour, with a dust 

suppression system. 

(h) Rail car unloading, coal pile unloading, and coal storage, with a maximum capacity of 800 

tons per hour.

(i) Coal crushers, identified as 1A and 1B, with a maximum combined capacity of 800 tons 

per hour, each using an enclosure for dust control.

(j) One (1) pneumatic fly ash storage silo and handling system, to be constructed in 2009, 

with a maximum storage capacity of 300 tons and a maximum throughput capacity of 

10.0 tons of fly ash per hour. The particulate emissions from the silo loadout to trucks are 

uncontrolled and exhaust to the atmosphere. The particulate emissions from the silo 

storage will be controlled by a baghouse, identified as Silo Baghouse, and exhausting to a 

stack, identified as Silo Stack. The particulate emissions from fly ash conveyance are 

controlled by a dust collector, identified as Fly Ash Collector, and exhausting to a stack, 

identified as Vacuum Blower Stack.

Note: The pneumatic fly ash storage silo and handling system was never constructed.

The New Combined Cycle Combustion Turbine Generation Facility Emission Units:

(k) Two (2) natural gas fired combustion turbine units each with a natural gas fired duct 

burner identified as EU-1 and EU-2, permitted in 2013, each with a total rated heat input 

capacity of 2,542 MMBtu/hr; with NOx emissions controlled by low combustion burner 

design and Selective Catalytic Reduction (SCR), and each with an oxidation catalyst 

system to reduce emissions of CO and VOCs including formaldehyde, and exhausting to 

stacks S-1 and S-2. Each stack has continuous emissions monitors (CEMS) for NOx.

 

*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 and combustion turbines which are a source of emissions.

(l) One (1) natural gas fired Auxiliary Boiler, identified as emission unit EU-3, permitted in 

2013, with a rated heat input capacity of 79.3 MMBtu/hr, equipped with low NOx burners 

(LNB) with flue gas recirculation (FGR) to reduce NOx emissions exhausting to stack S-3. 

(m) One (1) natural gas fired Dew Point Heater, identified as emission unit EU-4, permitted in 

2013, with a rated heat input capacity of 20.8 MMBtu/hr exhausting to stack S-4.
IPL Eagle Valley Generating Station Page 12 of 104

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Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

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

[326 IAC 2-7-5(15)]

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

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

(a) Coal bunker and coal scale exhausts. [326 IAC 6-3] [326 IAC 5]

Before the startup of the Combined Cycle Combustion Turbine Generation Facility, the 

Coal bunker and coal scale exhausts shall be permanently shut down and 

decommissioned.

(b) Other activities or categories not previously identified with potential, uncontrolled 

emissions equal to or less than thresholds require listing only: Pb 0.6 ton per year or 3.29 

pounds per day, SO2 5 pounds per hour or 25 pounds per day, NOX 5 pounds per hour or 

25 pounds per day, CO 25 pounds per day, PM10 5 pounds per hour or 25 pounds per 

day, VOC 3 pounds per hour or 15 pounds per day:

(1) Wet process ash handling, with hydroveyors conveying ash to storage ponds. 

[326 IAC 6-4]

 Before the startup of the Combined Cycle Combustion Turbine Generation 

 Facility, the Wet process ash handling shall be permanently shut 

 down and decommissioned.

(2) Ponded ash handling/removal operations. [326 IAC 6-4]

(3) Truck traffic on paved road. [326 IAC 6-4]

The New Combined Cycle Combustion Turbine Generation Facility Insignificant Emission 

Units: 

(c) One (1) distillate oil fired Emergency Generator, identified as emission unit EU-5, 

permitted in 2013, with a rated capacity of 1,826 HP and exhausting through stack S-5.

[Under 40 CFR 60, Subpart IIII, the Emergency Generator is considered new affected 

sources.][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Generator is considered 

new affected sources.]

(d) One (1) distillate oil fired Emergency Fire Pump, identified as emission unit EU-6, 

permitted in 2013, with a rated capacity of 500 HP and exhausting through stack S-6.

[Under 40 CFR 60, Subpart IIII, the Emergency Fire Pump is considered new affected 

sources.][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Fire Pump is considered 

new affected sources.]

(e) One (1) evaporative cooling tower, identified as emission unit U-7, rated with a circulation 

rate of 192,000 gpm to provide non-contact cooling water to the steam turbine condenser, 

permitted in 2013, and equipped with high efficiency drift eliminators. 

(f) Electrical Circuit Breakers containing sulfur hexafluoride (SF6) identified as emissions unit 

F-1, permitted in 2013, with fugitive emissions controlled by full enclosure.

(g) Fugitive equipment leaks from the natural gas supply lines, identified as F-2 controlled by 

a Leak Detection and Repair (LDAR) program.

(h) Three (3) Turbine Lube Demister Vents, permitted in 2013. 
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Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

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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Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

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

(a) This permit, T 109-26292-00004, 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.3 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

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

B.4 Enforceability [326 IAC 2-7-7]

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.5 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.6 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.7 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. The submittal by the Permittee does require the certification by the “responsible 

official” as defined by 326 IAC 2-7-1(34). 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.
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B.8 Certification [326 IAC 2-7-4(f)] [326 IAC 2-7-6(1)] [326 IAC 2-7-5(3)(C)]

(a) Where specifically designated by this permit or required by an applicable requirement, any 

application form, report, or compliance certification submitted shall contain certification by 

a responsible official of truth, accuracy, and completeness. This certification shall state 

that, based on information and belief formed after reasonable inquiry, the statements and 

information in the document are true, accurate, and complete.

(b) One (1) certification shall be included, using the attached Certification Form, with each 

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

submittal.

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

B.9 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. All certifications shall cover 

the time period from January 1 to December 31 of the previous year, and shall be 

submitted no later than July 1 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; and

(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).

(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 the certification by the “responsible official” 

as defined by 326 IAC 2-7-1(34).
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B.10 Preventive Maintenance Plan [326 IAC 2-7-5(1),(3) and (13)] [326 IAC 2-7-6(1) and (6)] 

[326 IAC 1-6-3]

(a) The Permittee shall prepare and maintain Preventive Maintenance Plans (PMPs) for the 

source as described in 326 IAC 1-6-3. At a minimum, the PMP shall include:

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

repairing emission control devices;

(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.

(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 or 

potential to emit. The PMP do not require the certification by the “responsible official” as 

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

(c) To the extent the Permittee is required by 40 CFR Part 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.11 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;

(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, 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 Section), or

Telephone Number: 317-233-0178 (ask for Compliance Section) 

Facsimile Number: 317-233-6865.
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Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

(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 the 

certification by the “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.

(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)(9) 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.

(h) The Permittee shall include all emergencies in the Quarterly Deviation and Compliance 

Monitoring Report.
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B.12 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.

(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)]
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B.13 Prior Permits Superseded [326 IAC 2-1.1-9.5]

(a) All terms and conditions of permits established prior to T 109-26292-00004 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 permit, all previous 

registrations and permits are superseded by this 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.14 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).

B.15 Deviations from Permit Requirements and Conditions [326 IAC 2-7-5(3)(C)(ii)]

(a) Deviations from any permit requirements (for emergencies see Section B - Emergency 

Provisions), the probable cause of such deviations, and any response steps or preventive 

measures taken shall be reported 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

using the attached Quarterly Deviation and Compliance Monitoring Report, or its 

equivalent. A deviation required to be reported pursuant to an applicable requirement that 

exists independent of this permit, shall be reported according to the schedule stated in the 

applicable requirement and does not need to be included in this report.

The Quarterly Deviation and Compliance Monitoring Report does require the certification 

by the “responsible official” as defined by 326 IAC 2-7-1(34).

(b) A deviation is an exceedance of a permit limitation or a failure to comply with a 

requirement of the permit.

B.16 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 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 the certification by the “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.
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(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.17 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 the 

certification by the “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:

(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 a 

reasonable deadline specified in writing by IDEM, OAQ, any additional information 

identified as being needed to process the application. 

B.18 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. 
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(b) Pursuant to 326 IAC 2-7-11(b) and 326 IAC 2-7-12(a), administrative Part 70 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 shall be certified by the “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)]

B.19 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 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.20 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), (c), or (e), 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 emissions allowable 

under 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
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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 which document, on a rolling five (5) 

year basis, all such changes and emissions trading that are subject to 

326 IAC 2-7-20(b), (c), or (e) and makes 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), (c)(1), and (e)(2).

(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 the 

certification by the “responsible official” as defined by 326 IAC 2-7-1(34).

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

The Permittee may trade increases and decreases in emissions in 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.21 Source Modification Requirement [326 IAC 2-7-10.5]

(a) A modification, construction, or reconstruction is governed by the requirements of 

326 IAC 2.
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(b) Any modification at an existing major source is governed by the requirements of 

326 IAC 2-2.

B.22 Inspection and Entry [326 IAC 2-7-6] [IC 13-14-2-2] [IC 13-17-3-2] [IC 13-30-3-1]

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 

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.23 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

The application which shall be submitted by the Permittee does require the certification by 

the "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)]
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B.24 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.

(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.25 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 Particulate Emission Limitations for Processes with Process Weight Rates Less Than One 

Hundred (100) Pounds per Hour [326 IAC 6-3-2]

Pursuant to 326 IAC 6-3-2(e)(2), particulate emissions from any manufacturing process not 

exempt under 326 IAC 6-3-1(b) or (c) which has a maximum process weight rate less than 100 

pounds per hour and the methods in 326 IAC 6-3-2(b) through (d) do not apply shall not exceed 

0.551 pounds per hour.

C.2 Opacity [326 IAC 5-1]

Pursuant to 326 IAC 5-1-2 (Opacity Limitations), except as provided in 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 forty percent (40%) 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 non-overlapping integrated averages for a 

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

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

The Permittee shall not operate an incinerator or incinerate any waste or refuse except as 

provided in 326 IAC 4-2 and 326 IAC 9-1-2.

C.5 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.6 Motor Vehicle Fugitive Dust Sources [326 IAC 6-4-4]

Pursuant to 326 IAC 6-4-4, no vehicle shall be driven or moved on any public street, road, alley, 

highway, or other thoroughfare, unless such vehicle is so constructed as to prevent its contents 

from dripping, sifting, leaking, or otherwise escaping therefrom so as to create conditions which 

result in fugitive dust. This section applies only to the cargo any vehicle may be conveying and 

mud tracked by the vehicle.

C.7 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.
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C.8 Asbestos Abatement Projects [326 IAC 14-10] [326 IAC 18] [40 CFR 61, Subpart M]

The Permittee shall comply with the applicable requirements of 326 IAC 14-10, 326 IAC 18, and 

40 CFR 61.140.

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

C.9 Performance Testing [326 IAC 3-6]

(a) All testing shall be performed according to the provisions of 326 IAC 3-6 (Source 

Sampling Procedures), except as provided elsewhere in this permit, utilizing any 

applicable procedures and analysis methods specified in 40 CFR 51, 40 CFR 60, 

40 CFR 61, 40 CFR 63, 40 CFR 75, or other procedures approved by IDEM, OAQ.

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 certification by the "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 

certification by the "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.10 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. 

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

C.11 Compliance Monitoring [326 IAC 2-7-5(3)] [326 IAC 2-7-6(1)]

(a) For new units:

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

monitoring for new emission units shall be implemented on and after the data of start-up.

(b) For existing units:

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 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 the Permittee may 

extend the compliance schedule related to the equipment for an additional ninety (90) 
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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(35).

(c) For monitoring required by CAM, at all times, the Permittee shall maintain the monitoring, 

including but not limited to, maintaining necessary parts for routine repairs of the 

monitoring equipment.

(d) For monitoring required by CAM, except for, as applicable, monitoring malfunctions, 

associated repairs, and required quality assurance or control activities (including, as 

applicable, calibration checks and required zero and span adjustments), the Permittee 

shall conduct all monitoring in continuous operation (or shall collect data at all required 

intervals) at all times that the pollutant-specific emissions unit is operating. Data recorded 

during monitoring malfunctions, associated repairs, and required quality assurance or 

control activities shall not be used for purposes of this part, including data averages and 

calculations, or fulfilling a minimum data availability requirement, if applicable. The owner 

or operator shall use all the data collected during all other periods in assessing the 

operation of the control device and associated control system. 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.12 Maintenance of Continuous Opacity Monitoring Equipment [326 IAC 2-7-5(3)(A)(iii)]

(a) The Permittee shall calibrate, maintain, and operate all necessary continuous opacity 

monitoring systems (COMS) and related equipment. For a boiler, the COM shall be in 

operation at all times that the induced draft fan is in operation.

(b) All continuous opacity monitoring systems shall meet the performance specifications of 

40 CFR 60, Appendix B, Performance Specification No. 1, and are subject to monitor 

system certification requirements pursuant to 326 IAC 3-5.

(c) In the event that a breakdown of a continuous opacity monitoring system occurs, a record 

shall be made of the time and reason of the breakdown and efforts made to correct the 

problem. 

(d) Whenever a COM is malfunctioning or down for repairs or adjustments for twenty-four 

(24) hours or more and a backup COM cannot be brought on-line, the Permittee shall 

provide a certified opacity reader, who may be an employee of the Permittee or an 

independent contractor, to self-monitor the opacity from the emission unit stack.
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(1) Visible emission readings shall be performed in accordance with 40 CFR 60, 

Appendix A, Method 9, for a minimum of five (5) consecutive six (6) minute 

averaging periods beginning not later than twenty-four hours after the start of the 

malfunction or down time; provided, however, that if such 24-hour period ends 

during the period beginning two (2) hours before sunset and ending two (2) hours 

after sunrise, then such visible emissions readings shall begin within four (4) 

hours of sunrise on the day following the expiration of such 24-hour period.

(2) Method 9 opacity readings shall be repeated for a minimum of five (5) 

consecutive six (6) minute averaging periods at least twice per day during daylight 

operations, with at least four (4) hours between each set of readings, until a 

COMS is online.

(3) Method 9 readings may be discontinued once a COM is online.

(4) Any opacity exceedances determined by Method 9 readings shall be reported 

with the Quarterly Opacity Exceedances Reports.

(e) Nothing in this permit shall excuse the Permittee from complying with the requirements to

operate a continuous opacity monitoring system pursuant to 326 IAC 3-5.

C.13 Maintenance of Continuous Emission Monitoring Equipment [326 IAC 2-7-5(3)(A)]

(a) The Permittee shall calibrate, maintain, and operate all necessary continuous emission 

monitoring systems (CEMS) and related equipment.

(b) All continuous emission monitoring systems shall meet all applicable performance 

specifications of 40 CFR 60 and 40 CFR 75 or any other performance specification, 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.

(d) Whenever a continuous emission monitor other than an opacity monitor is malfunctioning 

or will be down for maintenance or repairs, the following shall be used as an alternative to 

continuous data collection

(1) If the CEM is required for monitoring NOX or SO2 emissions pursuant to 

40 CFR 75 (Title IV Acid Rain program) or 326 IAC 10-4 (NOX Budget Trading 

Program), the Permittee shall comply with the relevant requirements of 

40 CFR 75 Subpart D - Missing Data Substitution Procedures.

(2) IF the CEM is not used to monitor NOX or SO2 emissions pursuant to 40 CFR 75 

or 326 IAC 10-4, then supplemental or intermittent monitoring of the parameter 

shall be implemented as specified in Section D of this permit until such time as 

the emission monitor system is back in operation.

(e) Nothing in this permit shall excuse the Permittee from complying with the requirements to 

operate a continuous emission monitoring system pursuant to 326 IAC 3-5, 326 IAC 10-4, 

40 CFR 60 or 40 CFR 75.

C.14 Monitoring Methods [326 IAC 3] [40 CFR 60] [40 CFR 63]

Any monitoring or testing required by Section D of this permit shall be performed according to the 

provisions of 326 IAC 3, 40 CFR 60 Appendix A, 40 CFR 60 Appendix B, 40 CFR 63, or other 

approved methods as specified in this permit.
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C.15 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.16 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 maintain the most recently submitted written emergency reduction 

plans (ERPs) consistent with safe operating procedures.

(b) 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.17 Risk Management Plan [326 IAC 2-7-5(12)] [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.18 Response to Excursions or Exceedances [326 IAC 2-7-5] [326 IAC 2-7-6]

(a) Upon detecting an excursion or exceedance, the Permittee shall 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 emissions.

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

and taking any necessary corrective actions to restore normal operation and prevent the 

likely recurrence of the cause of an excursion or exceedance (other than those caused by 

excused startup or shutdown conditions). Corrective actions may include, but are not 

limited to, the following:

(1) initial inspection and evaluation;

(2) recording that operations returned 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 within the indicator range, 

designated condition, or below the applicable emission limitation or standard, as 

applicable. 

(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
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(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 maintain the following records:

(1) monitoring data; 

(2) monitor performance data, if applicable; and 

(3) corrective actions taken.

C.19 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 take appropriate response actions. The Permittee shall submit a 

description of these response actions to IDEM, OAQ, within thirty (30) days of receipt of 

the test results. The Permittee shall take appropriate action to minimize excess 

emissions from the affected facility while the response actions are being implemented.

(b) A retest to demonstrate compliance shall be performed within one hundred twenty (120) 

days of receipt of the original test results. Should the Permittee demonstrate to IDEM, 

OAQ that retesting in one-hundred and twenty (120) 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 the certification by 

the “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.20 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]

(a) 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 purposes of fee assessment.

The statement must be submitted to:

Indiana Department of Environmental Management

Technical Support and Modeling Section, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

The emission statement does require the certification by the “responsible official” as 

defined by 326 IAC 2-7-1(34).
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(b) The emission statement 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.21 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. 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, all record keeping requirements not already 

legally required shall be implemented within ninety (90) days of permit issuance.

(c) If there is a reasonable possibility (as defined in 40 CFR 51.165(a)(6)(vi)(A), 

40 CFR 51.165(a)(6)(vi)(B), 40 CFR 51.166(r)(6)(vi)(a), and/or 40 CFR 51.166(r)(6)(vi)(b))

that a “project” (as defined in 326 IAC 2-2-1(qq) and/or 326 IAC 2-3-1(ll)) 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(ee) and/or 

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

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

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

(1) Before beginning actual construction of the “project” (as defined in

326 IAC 2-2-1(qq) and/or 326 IAC 2-3-1(ll)) 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(rr)(2)(A)(iii) and/or 326 IAC 2-3-1 (mm)(2)(A)(iii); 

and

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

netting calculations, if applicable.
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(d) If there is a reasonable possibility (as defined in 40 CFR 51.165(a)(6)(vi)(A) and/or 

40 CFR 51.166(r)(6)(vi)(a)) that a “project” (as defined in 326 IAC 2-2-1(qq) and/or 

326 IAC 2-3-1(ll)) 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(ee) and/or 326 IAC 2-3-1(z)) may result in significant emissions 

increase and the Permittee elects to utilize the “projected actual emissions” (as defined in 

326 IAC 2-2-1(rr) and/or 326 IAC 2-3-1(mm)), 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.22 General Reporting Requirements [326 IAC 2-7-5(3)(C)] [326 IAC 2-1.1-11] [326 IAC 2-2] 

[326 IAC 2-3]

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

Report or its equivalent. Any deviation from permit requirements, the date(s) of each 

deviation, the cause of the deviation, and the response steps taken must be reported. 

This report shall be submitted within thirty (30) days of the end of the reporting period. 

The Quarterly Deviation and Compliance Monitoring Report shall include the certification 

by the “responsible official” as defined by 326 IAC 2-7-1(34).

(b) The report required in (a) of this condition and reports required by conditions in Section D 

of 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

(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) Unless otherwise specified in this permit, all reports required in Section D of this permit 

shall be submitted within thirty (30) days of the end of the reporting period. All reports do 

require the certification by the “responsible official” as defined by 326 IAC 2-7-1(34).

(e) 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.

(f) 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 

(qq) and/or 326 IAC 2-3-1 (ll)) at an existing emissions unit, and the project meets the 

following criteria, then the Permittee shall submit a report to IDEM, OAQ:
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(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 (xx) and/or 326 IAC 2-3-1 (qq), 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). 

(g) The report for project at an existing emissions unit shall be submitted within 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.

(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 deems fit to include in this report.

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

(h) 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.23 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 the standards for 

recycling and emissions reduction:

(a) Persons opening appliances for maintenance, service, repair, or disposal must comply 

with the required practices pursuant to 40 CFR 82.156.

(b) Equipment used during the maintenance, service, repair, or disposal of appliances must 

comply with the standards for recycling and recovery equipment pursuant to 

40 CFR 82.158.

(c) Persons performing maintenance, service, repair, or disposal of appliances must be 

certified by an approved technician certification program pursuant to 40 CFR 82.161.
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SECTION D.1 FACILITY OPERATION CONDITIONS

Facility Description [326 IAC 2-7-5(15)]

(a) Two (2) no. 2 fuel oil-fired boilers, identified as Unit 1 and Unit 2, constructed in 1949 and 1950, 

respectively, each with a design heat input capacity of 524 million Btu per hour (MMBtu/hr), both 

exhausting to stack 1-1.

(The information describing the process contained in this facility description box is descriptive information 

and does not constitute enforceable conditions.)

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

D.1.0 Air Quality Analysis Requirements [326 IAC 2-2-4]

Pursuant to the air quality impact assessment requirements of 326 IAC 2-2-4, the Permittee shall 

permanently discontinue the operation of the emission units in Section D.1 before commercial 

operation of the Combined Cycle Combustion Turbine Generation Facility. The requirements of 

this section will no longer be applicable after the units are permanently shutdown. 

D.1.1 Particulate Emission Limitations for Sources of Indirect Heating [326 IAC 6-2-2]

(a) Pursuant to 326 IAC 6-2-2(a) (Particulate Emissions Limitations for Sources of Indirect 

Heating: Emission limitations for facilities specified in 326 IAC 6-2-1(b)), the PM 

emissions from Units 1, 2, 3, 4, 5, and 6 shall not exceed 0.23 pound per million Btu heat 

input (lb/MMBtu). This limitation was calculated using the following equation:

Pt = 0.87 Where Q = total source capacity (MMBtu/hr) on June 8, 1972

 Q0.16 = 4,071 MMBtu/hr

(b) Pursuant to 326 IAC 6-2-2(b), the PM emissions from Units 1 and 2 shall not exceed 0.10 

pound per million Btu heat input (lb/MMBtu), which is less than 0.23 lb/MMBtu, as 

requested by the source in a letter dated August 26, 2008.

D.1.2 Temporary Alternative Opacity Limitations [326 IAC 5-1-3]

(a) Pursuant to 326 IAC 5-1-3 (Temporary Alternative Opacity Limitations), the following 

applies to Eagle Valley Units 1 and 2:

(1) When starting a fire in a boiler, or shutting down a boiler, opacity may exceed the 

forty percent (40%) 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 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. [326 IAC 5-1-3(a)]

(2) When removing ashes from the fuel bed or furnace in a boiler or blowing tubes, 

opacity may exceed the forty percent (40%) 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 and opacity in excess of the applicable limit 

shall not continue for more than one (1) six (6)-minute averaging period in any 

sixty (60) minute period. The averaging periods in excess of the limit set in 

326 IAC 5-1-2 shall not be permitted for more than three (3) six (6)-minute 

averaging periods in a twelve (12) hour period. [326 IAC 5-1-3(b)]
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(b) If this facility cannot meet the opacity limitations in (a)(1) and (a)(2) of this condition, 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.1.3 Sulfur Dioxide (SO2) [326 IAC 7-4-11]

Pursuant to 326 IAC 7-4-11 (Morgan County Sulfur Dioxide Emission Limitations), the SO2

emissions from Unit 1 and Unit 2 shall not exceed 0.37 pounds per million Btu (lbs/MMBtu) each. 

Pursuant to 326 IAC 7-2-1, compliance shall be demonstrated using a calendar month average.

Compliance Determination Requirements

D.1.4 Testing Requirements [326 IAC 2-7-6(1),(6)] [326 IAC 2-1.1-11] [326 IAC 3-6]

Compliance with the particulate limitations in Condition D.1.1(b) and with the Opacity limits in 

Section C - Opacity and Temporary Alternative Opacity Limitations for startup shall be determined 

as follows:

(a) Compliance with the particulate limitations shall be determined by a performance stack 

test conducted utilizing methods as approved by the Commissioner. PM testing with both 

units operating and exhausting to the common stack is permitted. [326 IAC 3-6]

(b) Opacity testing shall be performed in conjunction with the particulate emissions testing in 

accordance with 40 CFR 60, Appendix A, Method 9. The Method 9 opacity testing (VE 

readings) shall be recorded for the full duration of the sampling time for each sampling 

repetition that occurs during daylight hours. [326 IAC 3-5-1(c)(2)(A)(ii)] 

[326 IAC 5-1-4(a)(1)]

(c) To demonstrate compliance with the Temporary Alternative Opacity Limitation for boiler 

startups, opacity testing shall be performed in accordance with 40 CFR 60, Appendix A, 

Method 9, during daylight hours of the startup from light-off to completion of start-up. 

[326 IAC 3-5-1(c)(2)(A)(ii)] [326 IAC 5-1-4(a)(1)]

(d) The PM stack testing and Method 9 opacity testing shall be repeated as follows:

(1) By December 31 of every second calendar year following this valid compliance 

demonstration; or

(2) If a unit is not operated at least 1,000 hours in the 2 years since the previous

stack test, then testing shall be repeated at least once every 1,000 hours of 

operation for that unit, or five (5) calendar years from the date of the last valid 

compliance demonstration, whichever occurs first.

For the purpose of this permit, “calendar year” means the twelve (12) month period from 

January 1 to December 31 inclusive.

(e) Testing shall be conducted in accordance with Section C - Performance Testing.

D.1.5 Sulfur Dioxide Emissions and Sulfur Content [326 IAC 7-2] [326 IAC 7-4-11]

Compliance shall be determined utilizing one of the following options:

(a) Pursuant to 326 IAC 3-7-4, 326 IAC 7-2, and 326 IAC 7-4-11, the Permittee shall 

demonstrate that the fuel oil sulfur content does not exceed the equivalent of 0.37 pounds 

per MMBtu each, using a calendar month average, by:

(1) Providing vendor analysis of fuel delivered, accompanied by a vendor 

certification; or
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(2) Providing analysis of fuel oil samples collected and analyzed in accordance with 

326 IAC 3-7-4(a).

(A) Oil samples shall be collected from the tanker truck load during or prior to 

transferring fuel to the storage tank; or

(B) Oil samples shall be collected from the storage tank immediately after 

each addition of fuel to the tank.

(b) Upon written notification to IDEM by a facility owner or operator, continuous emission 

monitoring data collected and reported pursuant to 326 IAC 3-5 may be used as the 

means for determining compliance with the emission limitations in 326 IAC 7. Upon such 

notification, the other requirements of 326 IAC 7-2 shall not apply. [326 IAC 7-2-1(g)]

D.1.6 RESERVED 

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

D.1.7 Visible Emissions Notations [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)]

(a) Visible emission notations of the fuel oil-fired boiler exhaust shall be performed once per 

day during normal daylight operations when one or both of Units 1 and 2 are in operation

and burning fuel oil. A trained employee shall record whether emissions are normal or 

abnormal.

(b) For processes operated continuously, “normal” means those conditions prevailing, or 

expected to prevail, eighty percent (80%) of the time the process is in operation, not 

counting startup or shut down time.

(c) In the case of batch or discontinuous operations, readings shall be taken during that part 

of the operation that would normally be expected to cause the greatest emissions. 

(d) A trained employee is an employee who has worked at the plant at least one (1) month 

and has been trained in the appearance and characteristics of normal visible emissions 

for that specific process.

(e) If abnormal emissions are observed at any boiler exhaust, the Permittee shall take 

reasonable response steps in accordance with Section C - Response to Excursions or 

Exceedances. Observation of abnormal emissions that do not violate an applicable 

opacity limit is not a deviation from this permit. Failure to take response steps in 

accordance with Section C - Response to Excursions or Exceedances, 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.1.8 Record Keeping Requirements [326 IAC 2-7-5(3)]

(a) To document compliance with the applicable opacity limits and Conditions D.1.1 and 

D.1.2, the Permittee shall maintain records in accordance with (1) and (2) below. 

Records shall be complete and sufficient to establish compliance with the opacity and 

particulate limits established in Section C - Opacity and Conditions D.1.1 and D.1.2.

(1) Data and results from the most recent stack test and accompanying Method 9 

visible emissions evaluation results for Units 1 and 2.

(2) Results of the visible emission notations of the stack 1-1 exhaust.
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(b) To document compliance with Conditions D.1.3 and D.1.5, the Permittee shall maintain 

records in accordance with (1) through (5) below. Records maintained shall be complete 

and sufficient to establish compliance with the SO2 limit as required in Conditions D.1.3 

and D.1.5. 

(1) Calendar dates covered in the compliance determination period.

(2) Monthly weighted average sulfur content.

(3) Fuel heat content.

(4) Fuel consumption.

(5) Monthly weighted average sulfur dioxide emission rate in pounds per million Btus 

(lb/MMBtu).

(c) To document compliance with Condition D.1.7, the Permittee shall maintain daily records 

of the visible emission notations of the Boiler stack exhaust. The Permittee shall include 

in its daily record when a visible emission notation is not taken and the reason for the lack 

of a visible emission notation, (e.g. the process did not operate that day).

(d) All records shall be maintained in accordance with Section C - General Record Keeping 

Requirements, of this permit.

D.1.9 Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 7-2(c)]

A quarterly report of opacity exceedances and a quarterly summary of the information to 

document compliance with Condition D.1.3 shall be submitted to the address listed in Section C - 

General Reporting Requirements of this permit, using the reporting forms located at the end of 

this permit, or their equivalent, within thirty (30) days after the end of the quarter being reported. 

The report submitted by the Permittee does require the certification by the “responsible official” as 

defined by 326 IAC 2-7-1(34).
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SECTION D.2 FACILITY OPERATION CONDITIONS

Facility Description [326 IAC 2-7-5(15)]

(b) One (1) tangentially-fired wet-bottom coal boiler, identified as Unit 3, constructed in 1951, with a 

design heat input capacity of 524 million Btu per hour (MMBtu/hr), with an electrostatic precipitator 

(ESP) and flue gas conditioning system for control of particulate matter, exhausting to stack 2-1. 

Unit 3 will combust no. 2 fuel oil during startup, shutdown, and stabilization periods. Used oil 

generated onsite and used oil contaminated materials generated onsite may be combusted in Unit 

3 as supplemental fuel for energy recovery. Stack 2-1 has continuous emission monitoring 

systems (CEMS) for NOX and SO2 and a continuous opacity monitor (COM).

(c) One (1) tangentially-fired dry-bottom coal fired boiler, identified as Unit 4, constructed in 1953, with 

a design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) and flue gas conditioning system for control of particulate matter, exhausting to 

stack 2-1. Unit 4 is equipped with separated overfire air (SOFA) and low NOX burners (LNB) for 

control of NOX emissions, which were voluntarily installed and are not required to operate. Unit 4 

will combust no. 2 fuel oil during startup, shutdown, and stabilization periods. Stack 2-1 has 

continuous emission monitoring systems (CEMS) for NOX and SO2 and a continuous opacity 

monitor (COM).

(d) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 5, constructed in 1953, with a 

design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an electrostatic precipitator 

(ESP) and flue gas conditioning system for control of particulate matter, exhausting to stack 3-1. 

Unit 5 is equipped with SOFA and LNB to control NOX emissions. Unit 5 will combust no. 2 fuel oil 

during startup, shutdown, and stabilization periods. Stack 3-1 has continuous emission monitoring 

systems (CEMS) for NOX and SO2 and a continuous opacity monitor (COM).

(e) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 6, constructed in 1956, with a 

design heat input capacity of 1017 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) for control of particulate matter, exhausting to stack 3-1. Unit 6 is equipped with 

Closed-coupled Overfire Air (COFA) to control NOX emissions. Unit 6 will combust no. 2 fuel oil 

during startup, shutdown, and stabilization periods. Used oil generated onsite may be combusted 

in Unit 6 as supplemental fuel for energy recovery. Unit 6 has had low-NOX burners installed. 

Stack 3-1 has continuous emission monitoring systems (CEMS) for NOX and SO2 and a 

continuous opacity monitor (COM).

(The information describing the process contained in this facility description box is descriptive information 

and does not constitute enforceable conditions.)

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

D.2.0 Air Quality Analysis Requirements [326 IAC 2-2-4]

Pursuant to the air quality impact assessment requirements of 326 IAC 2-2-4, the Permittee shall 

permanently discontinue the operation of the emission units in Section D.2 before commercial 

operation of the Combined Cycle Combustion Turbine Generation Facility. The requirements of 

this section will no longer be applicable after the units are permanently shutdown.

D.2.1 Particulate Emission Limitations for Sources of Indirect Heating [326 IAC 6-2-2]

(a) Pursuant to 326 IAC 6-2-2 (Particulate Emissions for Sources of Indirect Heating: 

Emission limitations for facilities specified in 326 IAC 6-2-1(b)), the PM emissions from 

Units 1, 2, 3, 4, 5, and 6 shall not exceed 0.23 pound per million Btu heat input 

(lb/MMBtu). This limitation was calculated using the following equation:
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Pt = 0.87 Where Q = total source capacity (MMBtu/hr) on June 8, 1972

 Q0.16 = 4,071 MMBtu/hr

(b) Pursuant to 326 IAC 6-2-2(b), the PM emissions from Units 3, 4, 5 and 6 shall not exceed 

0.27 pound per million Btu heat input (lb/MMBtu), as requested by Indianapolis Power and 

Light Company in a letter dated April 12, 1988.

D.2.2 Temporary Alternative Opacity Limitations [326 IAC 5-1-3]

(a) Pursuant to 326 IAC 5-1-3 (Temporary Alternative Opacity Limitations), the following 

applies:

(1) When building a new fire in a boiler, opacity may exceed the 40% opacity 

limitation established in 326 IAC 5-1-2 for a period not to exceed two and one-half 

(2.5) hours (twenty-five (25) six (6)-minute averaging periods) or until the flue gas 

temperature reaches two hundred fifty (250) degrees Fahrenheit, whichever 

occurs first. [326 IAC 5-1-3(e)]

(2) When shutting down a boiler, opacity may exceed the 40% opacity limitation 

established in 326 IAC 5-1-2 for a period not to exceed one (1) hour (ten (10)

six (6)-minute averaging periods). [326 IAC 5-1-3(e)]

(3) Operation of the electrostatic precipitator is not required during these times.

(4) During the above startup and shutdown periods all reasonable efforts shall be 

made to minimize the number and magnitude of the exceedances.

(b) When removing ashes from the fuel bed or furnace in a boiler or blowing tubes, opacity 

may exceed the applicable limit established in 326 IAC 5-1-2. However, opacity levels 

shall not exceed sixty percent (60%) for any six (6)-minute averaging period and opacity 

in excess of the applicable limit shall not continue for more than one (1) six (6)-minute 

averaging period in any sixty (60) minute period. The averaging periods in excess of the 

limit set in 326 IAC 5-1-2 shall not be permitted for more than three (3) six (6)-minute 

averaging periods in a twelve (12) hour period. [326 IAC 5-1-3(b)]

D.2.3 Sulfur Dioxide (SO2) [326 IAC 7-4-11]

Pursuant to 326 IAC 7-4-11 (Sulfur Dioxide Emission Limitations for Morgan County):

(a) SO2 emissions from Unit 3 shall not exceed 0.37 pounds per million Btu (lbs/MMBtu), 

compliance with which shall be determined as specified in 326 IAC 7-2-1(c), using a thirty 

(30) day rolling weighted average. [326 IAC 7-4-11(2)]

(b) SO2 emissions from Units 4, 5, and 6 shall not exceed 3.04 pounds per million Btu 

(lbs/MMBtu) each, compliance with which shall be determined as specified in 

326 IAC 7-2-1(c), using a thirty (30) day rolling weighted average. [326 IAC 7-4-11(2)]

(c) As an exception to the emission limitations specified in (a) and (b), pursuant to 

326 IAC 7-4-11(7), at any time in which IPL burns coal on Unit 3, the thirty (30) day rolling 

weighted average for sulfur dioxide emissions from Units 3, 4, 5, and 6 shall be limited to 

two and fifty-seven hundredths (2.57) pounds per million Btu each. [326 IAC 7-4-11(3)] 
IPL Eagle Valley Generating Station Page 40 of 104

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Compliance Determination Requirements

D.2.4 Testing Requirements [326 IAC 2-7-6(1),(6)] [326 IAC 2-1.1-11]

In order to determine compliance with the PM limitation in Condition D.2.1(b) for each units (Units 

3, 4, 5 and 6), the Permittee shall conduct before December 31, a performance stack test utilizing 

methods as approved by the Commissioner. This testing shall be repeated by December 31 of 

every second calendar year following this valid compliance demonstration. For the purpose of this 

permit, “calendar year” means the twelve (12) month period from January 1 to December 31 

inclusive. Testing shall be conducted in accordance with Section C - Performance Testing.

D.2.5 Operation of Electrostatic Precipitator [326 IAC 2-7-6(6)]

Except as otherwise provided by statute or rule or in this permit, the electrostatic precipitators 

(ESPs) shall be operated at all times that the boilers vented to the ESPs are in operation. Each 

flue gas conditioning (FGC) system on Unit 3, Unit 4 and Unit 5 shall be used with the 

corresponding ESP as necessary to maintain compliance with this permit.

D.2.6 Continuous Emissions Monitoring [326 IAC 3-5]

(a) Pursuant to 326 IAC 3-5 (Continuous Monitoring of Emissions), continuous emission 

monitoring systems for Units 3, 4, 5 and 6 shall be calibrated, maintained, and operated 

for measuring opacity, SO2, and either CO2 or O2, which meet the performance 

specifications of 326 IAC 3-5-2.

(b) All continuous emission monitoring systems are subject to monitor system certification 

requirements pursuant to 326 IAC 3-5-3.

(c) Pursuant to 326 IAC 3-5-4, if revisions are made to the continuous monitoring standard 

operating procedures (SOP), the Permittee shall submit updates to the department 

biennially.

(d) Nothing in this permit shall excuse the Permittee from complying with the requirements to 

operate a continuous emission monitoring system pursuant to 326 IAC 3-5, 326 IAC 10-4, 

or 40 CFR 75.

(e) Pursuant to 326 IAC 3-7-5(a), the Permittee shall develop a standard operating procedure 

(SOP) to be followed for sampling, handling, analysis, quality control, quality assurance, 

and data reporting of the information collected pursuant to 326 IAC 3-7-2 through 

326 IAC 3-7-4. In addition, any revision to the SOP shall be submitted to IDEM, OAQ.

D.2.7 Sulfur Dioxide Emissions and Sulfur Content [326 IAC 7-2] [326 IAC 7-4-11]

(a) Pursuant to 326 IAC 7-2-1(e) and 326 IAC 3-7, coal sampling and analysis data obtained 

in accordance with procedures specified under 326 IAC 3-7 may be used to demonstrate 

compliance as follows:

(1) Pursuant to 326 IAC 7-4-11(6), on a day for which Unit 3 does not burn any coal, 

compliance with the sulfur dioxide emission limitations in 326 IAC 7-4-11(2) shall 

be determined as specified in 326 IAC 7-2-1(c), using a thirty (30) day rolling 

weighted average.

(2) Pursuant to 326 IAC 7-4-11(7), on a day for which Unit 3 burns any coal, if the 

thirty (30) day rolling weighted average for any unit is above two and fifty-seven 

hundredths (2.57) pounds per million Btu, then 326 IAC 7-2-1(c)(1) does not 

apply, and the daily average emission rate for that unit for that day shall not 

exceed two and fifty-seven hundredths (2.57) pounds per million Btu.

In the alternative, SO2 emissions may be determined by use of CEM in lieu of any other 

method prescribed herein.
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(b) Pursuant to 326 IAC 7-4-11(8), for the purposes of determining compliance under 

326 IAC 7-2-1(b), stack tests performed on Units 3, 4, 5, and 6 shall demonstrate 

compliance with the most stringent set of limits in effect at any time during the day prior to 

or during the test based on the Unit 3 operating status and fuel type as indicated by the 

log maintained pursuant to 326 IAC 7-4-11(9).

D.2.8 RESERVED 

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

D.2.9 Transformer-Rectifier (T-R) Sets [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)] [40 CFR 64]

(a) The ability of the ESP to control particulate emissions shall be monitored once per day, 

when the unit is in operation, by measuring and recording the number of T-R sets in 

service and the primary and secondary voltages and the currents of the 

transformer-rectifier (T-R) sets.

(b) Reasonable response steps shall be taken in accordance with Section C – Response to 

Exceedances or Excursions whenever the percentage of T-R sets in service falls below 

90 percent (90%). T-R set failure resulting in less than 90 percent (90%) availability is not 

a deviation from this permit. Failure to take response steps in accordance with Section C

- Response to Exceedances or Excursions shall be considered a deviation from this 

permit.

D.2.10 Opacity Readings [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)]

(a) In the event of emissions exceeding thirty percent (30)%) average opacity for three (3) 

consecutive six (6) minute averaging periods, appropriate response steps shall be taken 

in accordance with Section C - Response to Exceedances or Excursions such that the 

cause(s) of the excursion are identified and corrected and opacity levels are brought back 

below thirty percent (30%). Examples of expected response steps include, but are not 

limited to, boiler loads being reduced, adjustment of flue gas conditioning rate, and ESP 

T-R sets being returned to service.

(b) Opacity readings in excess of thirty percent (30%) but not exceeding the opacity limit for 

the unit are not a deviation from this permit. Failure to take response steps in accordance 

with Section C - Response to Exceedances or Excursions, shall be considered a deviation 

from this permit.

D.2.11 SO2 Monitor Downtime [326 IAC 2-7-6] [326 IAC 2-7-5(3)]

(a) Whenever the SO2 continuous emission monitoring (CEM) system is malfunctioning or 

down for repairs or adjustments and a backup CEM is not brought on-line, the following 

shall be used to provide information related to SO2 emissions:

(1) If the CEM system is down for less than twenty-four (24) hours and a backup 

CEM is not brought on-line, the Permittee shall substitute an average of the 

quality-assured data from the hour immediately before and the hour immediately 

after the missing data period for each hour of missing data.

(2) If the CEM system is down for twenty-four (24) hours or more and a backup CEM 

is not brought on-line, the Permittee shall either:
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(A) Conduct fuel sampling as specified in 326 IAC 3-7-2(b). Fuel sample

preparation and analysis shall be conducted as specified in

326 IAC 3-7-2(c), 326 IAC 3-7-2(d), and 326 IAC 3-7-2(e). Pursuant to

326 IAC 3-7-3, manual or other non-ASTM automatic sampling and

analysis procedures may be used upon a demonstration, submitted to the

department for approval, that such procedures provide sulfur dioxide

emission estimates representative either of estimates based on coal

sampling and analysis procedures specified in 326 IAC 3-7-2 or of

continuous emissions monitoring: or

(B) Comply with the relevant requirements of 40 CFR Part 75. Subpart D - 

Missing Data Substitution Procedures

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

D.2.12 Record Keeping Requirements

(a) To document compliance with the applicable opacity and particulate limits and Conditions 

D.2.1 and D.2.2, the Permittee shall maintain records in accordance with (1) through (4) 

below. Records shall be complete and sufficient to establish compliance with the opacity 

and particulate limits in Section C - Opacity and in Conditions D.2.1 and D.2.2.

(1) Data and results from the most recent stack test.

(2) All continuous opacity monitoring data, pursuant to 326 IAC 3-5.

(3) The results of all visible emission (VE) notations and Method 9 visible emission 

readings taken during any periods of COM downtime.

(4) All ESP parametric monitoring readings.

(b) To document compliance with SO2 Condition D.2.3, the Permittee shall maintain records 

in accordance with (1) through (3) below. Records shall be complete and sufficient to 

establish compliance with the SO2 limits as required in Condition D.2.3. The Permittee 

shall maintain records in accordance with (2) and (3) or (4) below during SO2 CEM 

system downtime.

(1) All SO2 continuous emissions monitoring data, pursuant to 326 IAC 3-5-6 and 

326 IAC 7-2-1(g).

(2) All fuel sampling and analysis data collected for SO2 CEM downtime, in 

accordance with Condition D.2.11. 

(3) Calculated actual fuel usage during each SO2 CEM downtime for the Unit(s)

affected by CEM downtime lasting 24 or more hours.

(4) The substitute data used for the missing data periods if data substitution pursuant

to 40 CFR Part 75 Subpart D is used to provide data for the SO2 CEM downtime, 

in accordance with Condition D.2.11. 
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(c) Pursuant to 326 IAC 7-4-11(9), the Permittee shall maintain and make available to the 

department upon request a log of the operating status and fuel type used for Unit 3. In 

addition, in the quarterly report required by 326 IAC 7-2-1(a), the Permittee shall submit to 

the department a daily summary indicating fuel type for Unit 3, and, for days on which Unit 

3 burned any coal and any thirty (30) day rolling weighted average was greater than two 

and fifty-seven hundredths (2.57) pounds per million Btu, the Permittee shall submit to the 

department the daily average sulfur content, heat content, and sulfur dioxide emission 

rate for Units 3, 4, 5, and 6. For the purposes of this Condition, "department" refers to the 

Indiana Department of Environmental Management (IDEM).

(d) All records shall be maintained in accordance with Section C - General Record Keeping 

Requirements, of this permit.

D.2.13 Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 3-5-7] [326 IAC 7-2(c)]

(a) A quarterly report of opacity exceedances and a quarterly summary of the information to 

document compliance with Condition D.2.3 shall be submitted to the address listed in 

Section C - General Reporting Requirements of this permit, using the reporting forms 

located at the end of this permit, or their equivalent, within thirty (30) days after the end of 

the quarter being reported. The report submitted by the Permittee does require the 

certification by the “responsible official” as defined by 326 IAC 2-7-1(34).

(b) Pursuant to 326 IAC 3-5-7(5), reporting of continuous monitoring system instrument 

downtime, except for zero (0) and span checks, which shall be reported separately, shall 

include the following:

(1) Date of downtime.

(2) Time of commencement.

(3) Duration of each downtime.

(4) Reasons for each downtime.

(5) Nature of system repairs and adjustments.

The report submitted by the Permittee does require the certification by the “responsible 

official” as defined by 326 IAC 2-7-1(34).
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SECTION D.3 FACILITY OPERATION CONDITIONS

Facility Description [326 IAC 2-7-5(15)]

(f) One (1) distillate oil fired generator, identified as Unit PR-10, constructed in 1967, with a design 

heat input capacity of 28.4 million Btu per hour (MMBtu/hr), exhausting to stack

PR10-1.

(The information describing the process contained in this facility description box is descriptive information 

and does not constitute enforceable conditions.)

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

D.3.0 Air Quality Analysis Requirements [326 IAC 2-2-4]

Pursuant to the air quality impact assessment requirements of 326 IAC 2-2-4, the Permittee shall 

permanently discontinue the operation of the emission units in Section D.3 before commercial 

operation of the Combined Cycle Combustion Turbine Generation Facility. The requirements of 

this section will no longer be applicable after the units are permanently shutdown. 

D.3.1 Sulfur Dioxide (SO2) [326 IAC 7-1.1-2]

Pursuant to 326 IAC 7-1.1-2 (Sulfur Dioxide Emission Limitations), the SO2 emissions from Unit 

PR-10 shall not exceed 0.5 pound per million Btu (lb/MMBtu).

Compliance Determination Requirements

D.3.2 Sulfur Dioxide Emissions and Sulfur Content] [326 IAC 7-1.1-2] [326 IAC 7-2]

Pursuant to 326 IAC 3-7-4, 326 IAC 7-1.1-2, and 326 IAC 7-2, the Permittee shall demonstrate 

that the fuel oil sulfur content does not exceed the equivalent of 0.5 lb/MMBtu, using a calendar 

month average, by:

(a) Providing vendor analysis of fuel delivered, accompanied by a vendor certification; or

(b) Providing analysis of fuel oil samples collected and analyzed in accordance with 

326 IAC 3-7-4(a).

(1) Oil samples shall be collected from the tanker truck load during or prior to 

transferring fuel to the storage tank; or

(2) Oil samples shall be collected from the storage tank immediately after each 

addition of fuel to the tank.

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

D.3.3 Record Keeping Requirements

(a) To document compliance with Condition D.3.1 and D.3.2, the Permittee shall maintain 

records in accordance with (1) through (5) below. Records maintained shall be complete 

and sufficient to establish compliance with the SO2 limit as required in Condition D.3.1 

and D.3.2.

(1) Calendar dates covered in the compliance determination period.

(2) Monthly weighted average sulfur content.

(3) Fuel heat content.
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(4) Fuel consumption.

(5) Monthly weighted average sulfur dioxide emission rate in pounds per million Btus 

(lb/MMBtu).

(b) All records shall be maintained in accordance with Section C - General Record Keeping 

Requirements, of this permit.

D.3.4 Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 7-2(c)]

A quarterly summary of the information to document compliance with Condition D.3.1 shall be 

submitted to the address listed in Section C - General Reporting Requirements, of this permit, 

using the reporting forms located at the end of this permit, or their equivalent, within thirty (30) 

days after the end of the quarter being reported. The report submitted by the Permittee does 

require the certification by the “responsible official” as defined by 326 IAC 2-7-1(34).
IPL Eagle Valley Generating Station Page 46 of 104

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Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

SECTION D.4 FACILITY OPERATION CONDITIONS

Facility Description [326 IAC 2-7-5(15)]

(g) Coal transfer facilities, with a maximum throughput of 800 tons per hour, with a dust suppression 

system. 

(h) Rail car unloading, coal pile unloading, and coal storage, with a maximum capacity of 800 tons per 

hour.

(i) Coal crushers, identified as 1A and 1B, with a maximum combined capacity of 800 tons per hour, 

each using an enclosure for dust control.

Insignificant Activities:

Coal bunker and coal scale exhausts.

(The information describing the process contained in this facility description box is descriptive information 

and does not constitute enforceable conditions.)

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

D.4.0 Air Quality Analysis Requirements [326 IAC 2-2-4]

Pursuant to the air quality impact assessment requirements of 326 IAC 2-2-4, the Permittee shall 

permanently discontinue the operation of the emission units in Section D.4 before commercial 

operation of the Combined Cycle Combustion Turbine Generation Facility. The requirements of 

this section will no longer be applicable after the units are permanently shutdown.

D.4.1 Particulate Emission Limitations for Manufacturing Processes [326 IAC 6-3-2]

Pursuant to 326 IAC 6-3-2 (Particulate Emission Limitations for Manufacturing Processes), the 

particulate emission rate from the coal processing drop points and the particulate emission rate 

from the coal crushers shall not exceed amounts determined by the following:

(a) Interpolation of the data for the process weight rate up to sixty thousand (60,000) pounds 

per hour shall be accomplished by use of the equation:

E = 4.10 P 0.67 where E = rate of emission in pounds per hour and 

P = process weight rate in tons per hour.

(b) Interpolation and extrapolation of the data for the process weight rate in excess of sixty 

thousand (60,000) pounds per hour shall be accomplished by use of the equation:

E = 55.0 P0.11 - 40 where E = rate of emission in pounds per hour; and

P = process weight rate in tons per hour.

When the process weight rate exceeds two hundred (200) tons per hour, the allowable emission 

may exceed the pounds per hour limitation calculated using the above equation, provided the 

concentration of particulate in the discharge gases to the atmosphere is less than 0.10 pounds 

per one thousand (1,000) pounds of gases.

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

D.4.2 Visible Emissions Notations [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)]

(a) Visible emission notations of any coal transfer exhaust points shall be performed once per 

week during normal daylight operations when transferring coal. A trained employee shall 

record whether emissions are normal or abnormal.
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(b) Visible emission notations of the rail car unloading shall be performed once per week 

during normal daylight operations when unloading coal. A trained employee shall record 

whether emissions are normal or abnormal.

(c) Visible emission notations of the coal crusher stack exhaust shall be performed once per 

week during normal daylight operations when the crusher is in operation. A trained 

employee shall record whether emissions are normal or abnormal.

(d) For processes operated continuously, "normal" means those conditions prevailing, or 

expected to prevail, eighty percent (80%) of the time the process is in operation.

(e) In the case of batch or discontinuous operations, readings shall be taken during that part 

of the operation that would normally be expected to cause the greatest emissions.

(f) A trained employee is an employee who has worked at the plant at least one (1) month 

and has been trained in the appearance and characteristics of normal visible emissions 

for that specific process.

(g) If abnormal emissions are observed at a transfer point exhaust or crusher exhaust or 

from the coal unloading, the Permittee shall take reasonable response steps in 

accordance with Section C - Response to Excursions or Exceedances. Failure to take 

response steps in accordance with Section C - Response to Excursions or Exceedances, 

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.4.3 Record Keeping Requirements

(a) To document compliance with Condition D.4.2, the Permittee shall maintain weekly

records of the visible emission notations of the rail car unloading, crusher and coal 

transfer exhaust. The Permittee shall include in its weekly record when a visible emission 

notation is not taken and the reason for the lack of a visible emission notation, (e.g. the 

process did not operate that week).

(b) All records shall be maintained in accordance with Section C - General Record Keeping 

Requirements, of this permit.
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SECTION D.5 FACILITY OPERATION CONDITIONS

Facility Description [326 IAC 2-7-5(15)]:

(j) One (1) pneumatic Fly Ash Conveyance and Silo Storage (fly ash storage silo and handling 

system), to be constructed in 2009, with a maximum storage capacity of 300 tons and a 

maximum throughput capacity of 10.0 tons of fly ash per hour. The particulate emissions from 

the silo loadout to trucks are uncontrolled and exhaust to the atmosphere. The particulate 

emissions from the silo storage will be controlled by a baghouse, identified as Silo Baghouse, 

and exhausting to a stack, identified as Silo Stack. The particulate emissions from fly ash 

conveyance are controlled by a dust collector, identified as Fly Ash Collector, and exhausting 

to a stack, identified as Vacuum Blower Stack.

Note: The pneumatic fly ash storage silo and handling system was never constructed. 

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

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

D.5.0 Air Quality Analysis Requirements [326 IAC 2-2-4]

Pursuant to the air quality impact assessment requirements of 326 IAC 2-2-4, the Permittee shall 

permanently discontinue the operation of the emission units in Section D.5 before commercial 

operation of the Combined Cycle Combustion Turbine Generation Facility. The requirements of 

this section will no longer be applicable after the units are permanently shutdown. 

D.5.1 PSD Minor Limits and Nonattainment NSR [326 IAC 2-2] [326 IAC 2-1.1-5]

The Permittee shall comply with the following:

(a) The combined PM emissions from the Fly Ash Conveyance and Silo Storage shall not 

exceed 3.9 pounds per hour. 

(b) The combined PM10 emissions from the Fly Ash Conveyance and Silo Storage shall not 

exceed 2.9 pounds per hour. 

Compliance with these limits in combination with other emission units will limit the PM and PM10 

emissions from the Fly Ash Conveyance and Silo Storage (fly ash storage and handling system) 

to less than 25 and 15 tons per year, respectively and render the requirements of 326 IAC 2-2 

(PSD) and 326 IAC 2-1.1-5 (Nonattainment NSR) not applicable to the Fly Ash Conveyance and 

Silo Storage (fly ash storage and handling system) permitted in 2008. 

D.5.2 Particulate Emission Limitations for Manufacturing Processes [326 IAC 6-3-2]

Pursuant to 326 IAC 6-3-2, the allowable particulate matter (PM) from the Fly Ash Conveyance 

and Silo Storage (fly ash storage and handling system) shall not exceed 19.2 pounds per hour, 

each, when operating at a process weight rate of 10 tons per hour, each. The pound per hour 

limitation was calculated with the following equation:

Interpolation of the data for the process weight rate up to sixty thousand (60,000) pounds per hour 

was determined by use of the equation:

E = 4.10 P 0.67 where E = rate of emission in pounds per hour and

P = process weight rate in tons per hour
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Compliance Determination Requirements

D.5.3 Particulate Matter (PM)

(a) In order to comply with Conditions D.5.1 and D.5.2, the baghouse and fly ash collector 

shall be in operation at all times when the fly ash storage and handling is in operation.

(b) In the event that bag failure is observed in a multi-compartment baghouse, if operations 

will continue for ten (10) days or more after the failure is observed before the failed units 

will be repaired or replaced, the Permittee shall promptly notify the IDEM, OAQ of the 

expected date the failed units will be repaired or replaced. The notification shall also 

include the status of the applicable compliance monitoring parameters with respect to 

normal, and the results of any response actions taken up to the time of notification.

D.5.4 Testing Requirements [326 IAC 2-7-6(1)][326 IAC 2-1.1-11]

Within 180 days after initial startup of the fly ash handling and storage system, in order to 

demonstrate compliance with Conditions D.5.1 and D.5.2, the Permittee shall perform PM/PM10 

testing on baghouse and the dust collector controlling the fly ash storage and handling system 

utilizing methods as approved by the Commissioner. This test shall be repeated at least once 

every five (5) years from the date of the most recent valid compliance demonstration. Testing 

shall be conducted in accordance with Section C - Performance Testing.

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

D.5.5 Visible Emissions Notations

(a) Visible emission notations of the fly ash storage and handling stack exhausts shall be 

performed once per week during normal daylight operations. A trained employee shall 

record whether emissions are normal or abnormal.

(b) For processes operated continuously, "normal" means those conditions prevailing, or 

expected to prevail, eighty percent (80%) of the time the process is in operation, not 

counting startup or shut down time.

(c) In the case of batch or discontinuous operations, readings shall be taken during that part 

of the operation that would normally be expected to cause the greatest emissions.

(d) A trained employee is an employee who has worked at the plant at least one (1) month 

and has been trained in the appearance and characteristics of normal visible emissions 

for that specific process.

(e) If abnormal emissions are observed, the Permittee shall take reasonable response steps 

in accordance with Section C - Response to Excursions or Exceedances. Failure to take 

response steps in accordance with Section C - Response to Excursions or Exceedances 

shall be considered a deviation from this permit.

D.5.6 Parametric Monitoring

The Permittee shall record the pressure drop across the fly ash storage and handling baghouse and 

dust collector used in conjunction with the fly ash storage and handling at least once per day when the 

fly ash storage and handling is in operation. When for any one reading, the pressure drop across the 

baghouse or the fly ash collector is outside the normal range of 1.0 and 10.0 inches of water, or a 

range established during the latest stack test the Permittee shall take reasonable response steps in 

accordance with Section C - Response to Excursions or Exceedances. Failure to take response steps 

in accordance with Section C - Response to Excursions or Exceedances, shall be considered a 

deviation from this permit.
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The instrument used for determining the pressure shall comply with condition C.14 - Instrument 

Specifications, be subject to approval by IDEM, OAQ, and shall be calibrated at least once every six 

(6) months.

D.5.7 Broken or Failed Bag Detection

(a) For a single compartment baghouse controlling emissions from a process operated 

continuously, a failed unit and the associated process shall be shut down immediately 

until the failed unit has been repaired or replaced.

(b) For a single compartment baghouse controlling emissions from a batch process, the feed 

to the process shall be shut down immediately until the failed unit has been repaired or 

replaced. The emissions unit shall be shut down no later than the completion of the 

processing of the material in the emissions unit.

Bag failure can be indicated by a significant drop in the baghouse's pressure reading with abnormal 

visible emissions, by an opacity violation, or by other means such as gas temperature, flow rate, air 

infiltration, leaks, or dust traces.

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

D.5.8 Record Keeping Requirements

(a) To document compliance with Condition D.5.5 - Visible Emission Notation, the Permittee 

shall maintain weekly records of the visible emission notations of the fly ash storage and 

handling stack exhaust. The Permittee shall include in its weekly record when a visible 

emission notation is not taken and the reason for the lack of a visible emission notation, 

(e.g. the process did not operate that day).

(b) To document compliance with Condition D.5.6 - Parametric Monitoring, the Permittee 

shall maintain the daily records of the pressure drop across the baghouse and fly ash 

collector controlling the fly ash storage and handling. The Permittee shall include in its 

daily record when a pressure drop reading is not taken and the reason for the lack of a 

pressure drop reading, (e.g. the process did not operate that day).

(c) All records shall be maintained in accordance with Section C - General Record Keeping 

Requirements of this permit.
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SECTION D.6 FACILITY CONDITIONS

Facility Description [326 IAC 2-7-5(15)] Insignificant Activities:

(1) Wet process ash handling, with hydroveyors conveying ash to storage ponds.

(2) Ponded ash handling/removal operations.

(3) Truck traffic on paved road.

(The information describing the process contained in this facility description box is descriptive information 

and does not constitute enforceable conditions.)

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

D.6.0 Air Quality Analysis Requirements [326 IAC 2-2-4]

Pursuant to the air quality impact assessment requirements of 326 IAC 2-2-4, the Permittee shall 

permanently discontinue the operation of the “wet process ash handling with hydroveyors 

conveying ash to storage ponds” before commercial operation of the Combined Cycle 

Combustion Turbine Generation Facility. The requirements of this section will no longer be 

applicable after the units are permanently shutdown.

D.6.1 Fugitive Dust Emission Limitations [326 IAC 6-4-2]

Pursuant to 326 IAC 6-4-2:

(a) Any ash storage pond area generating fugitive dust shall be in deviation from this rule 

(326 IAC 6-4) if any of the following criteria are violated:

(1) A source or combination of sources which cause to exist fugitive dust 

concentrations greater than sixty-seven percent (67%) in excess of ambient 

upwind concentrations as determined by the following formula:

P = 100 (R) - U)

 U 

Where

P = Percentage increase

R = Number of particles of fugitive dust measured at downward receptor site

U = Number of particles of fugitive dust measured at upwind or background site

(2) The fugitive dust is comprised of fifty percent (50%) or more respirable dust, then 

the percent increase of dust concentration in subdivision (1) of this section shall 

be modified as follows:

PR = (1.5 ± N) P

Where

N = Fraction of fugitive dust that is respirable dust;

PR = allowable percentage increase in dust concentration above background; 

and

P = no value greater than sixty-seven percent (67%).

(3) The ground level ambient air concentrations exceed fifty (50) micrograms per 

cubic meter above background concentrations for a sixty (60) minute period.
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(4) If fugitive dust is visible crossing the boundary or property line of a source. This 

subdivision may be refuted by factual data expressed in subdivisions (1), (2) or 

(3) of this section. 326 IAC 6-4-2(4) is not federally enforceable.

(b) Pursuant to 326 IAC 6-4-6(6) (Exceptions), fugitive dust from a source caused by adverse 

meteorological conditions will be considered an exception to this rule (326 IAC 6-4) and 

therefore not in violation. 

Adverse weather conditions do not relieve a source from taking all reasonable measures 

to mitigate fugitive dust formation and transport. Failure to take reasonable measures 

during this period may be considered to be a deviation from this permit.

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

D.6.2 Visible Emissions Notations [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)]

(a) Visible emission notations of the fly ash storage pond area(s) shall be performed at least 

once per week during normal daylight operations. A trained employee shall record 

whether emissions are normal or abnormal.

(b) For processes operated continuously, "normal" means those conditions prevailing, or 

expected to prevail, eighty percent (80%) of the time the process is in operation.

(c) In the case of batch or discontinuous operations, readings shall be taken during that part 

of the operation that would normally be expected to cause the greatest emissions.

(d) A trained employee is an employee who has worked at the plant at least one (1) month 

and has been trained in the appearance and characteristics of normal visible emissions 

for that specific process.

(e) If abnormal visible emissions are observed crossing the property line or boundaries of the 

property, right-of-way, or easement on which the source is located, the Permittee shall 

take reasonable response steps in accordance with Section C - Response to Excursions 

or Exceedances. Failure to take response steps in accordance with Section C - 

Response to Excursions or Exceedances, 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.6.3 Record Keeping Requirements

(a) To document compliance with Condition D.6.2, the Permittee shall maintain weekly

records of the visible emission notations of the fly ash storage pond area(s). The 

Permittee shall include in its weekly record when a visible emission notation is not taken 

and the reason for the lack of a visible emission notation, (e.g. the process did not 

operate that day).

(b) All records shall be maintained in accordance with Section C - General Record Keeping 

Requirements, of this permit.
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SECTION D.7 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(k) Two (2) natural gas fired combustion turbine units each with a natural gas fired duct burner 

identified as EU-1 and EU-2, permitted in 2013, each with a total rated heat input capacity of 

2,542 MMBtu/hr; with NOx emissions controlled by low combustion burner design and Selective 

Catalytic Reduction (SCR), and each with an oxidation catalyst system to reduce emissions of 

CO and VOCs including formaldehyde, and exhausting to stacks S-1 and S-2. Each stack has 

continuous emissions monitors (CEMS) for NOx.

 

*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 and combustion turbines 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.)

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

D.7.1 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-1 and EU-2 shall be as follows:

(a) The PM, PM10 and PM2.5 emissions from the combined cycle combustion turbines 

identified as EU-1 and EU-2 shall not exceed 16.8 pounds per hour, each and 0.0066 

pounds per MMBtu, each 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 EU-1 and EU-2 shall not exceed 13.9 pounds per hour, each and 0.0055 

pounds per MMBtu, each without duct firing based on 3-hr average through the use of 

good combustion practices and fuel specification. 

(c) Only pipeline natural gas shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

D.7.2 H2SO4 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-1 and EU-2 shall be as follows:

(a) The H2SO4 emissions from the combined cycle combustion turbines identified as EU-1 

and EU-2 shall be limited by restricting the S content of the natural gas to 0.75 gr S/100 

scf on a monthly average basis. 

(b) Only pipeline natural gas shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

D.7.3 CO PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-1 and EU-2 shall be as follows:
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(a) The CO emissions from the CCCTs shall be controlled by a catalytic oxidation; and

(b) The CO emissions shall not exceed 2.0 ppmvd @15% O2 based on a 3-hour 

average.

(c) Only pipeline natural gas shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

D.7.4 VOC PSD BACT [326 IAC 2-2-3][326 IAC 8-1-6]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 (Prevention 

of Significant Deterioration (PSD)) and 326 IAC 8-1-6, the Best Available Control Technologies 

(BACT) for the natural gas-fired combined cycle combustion turbines, identified as EU-1 and EU-2 

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-hour average.

(c) The VOC emissions shall not exceed 1.0 ppmvd @15% O2, without duct burners 

based on 3-hour average.

(d) Only pipeline natural gas shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

D.7.5 NOx PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-1 and EU-2 shall be as follows:

(a) The NOx emissions from the CCCTs shall be controlled by a Selective Catalytic 

Reduction and Dry Low NOx combustors.

(b) The NOx emissions shall not exceed 2.0ppmv @15% O2 with duct burners based on a 3-

hour average.

(c) Only pipeline natural gas shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

D.7.6 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-1 and EU-2 shall be as follows:

(a) The net heat rate shall not exceed 7,750 Btu/kW-hr (HHV-net) for each CCCT block (ISO 

conditions, without duct firing or inlet evaporative cooling, and not accounting for 

transformer losses).

(b) The total CO2e emissions for both combined cycle combustion turbines shall be limited to 

less than 2,649,570 tons of CO2e per twelve (12) consecutive month period with 

compliance determined at the end of each month.
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D.7.7 Hazardous Air Pollutants (HAPs) Minor Limits

The emissions of single HAP, formaldehyde, from the combined cycle combustion turbines 

identified as EU-1 and EU-2, shall be limited to less than nine (9.0) tons per twelve (12) 

consecutive month period, with compliance determined at the end of each month. 

Compliance with the above limits, combined with the potential to emit formaldehyde emissions 

from all other emission units will limit the potential to emit from this source to less than ten (10) 

tons per year of formaldehyde and make the source an area source of HAPs. 

D.7.8 Startup and Shutdown Limitations for Combustion Turbines [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 (Prevention 

of Significant Deterioration (PSD)), the following shall apply to each combustion turbine:

(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) 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 - 3,390 lb/event

NOx - 429 lb/event

(g) The total NOX emissions from the combined cycle combustion turbines stacks shall not 

exceed 68 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. 

(h) The total CO emissions from the combined cycle combustion turbines stacks shall not 

exceed 565 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 total VOC emissions from the combined cycle combustion turbines stacks shall not 

exceed 146 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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Compliance Determination Requirements

D.7.9 Oxidation Catalyst

In order to ensure compliance with Conditions D.7.3, D.7.4 and D.7.7, the oxidation catalyst shall 

be in operation at all times when the natural gas-fired combined cycle combustion turbines are in 

operation except during periods of startup and shutdown.

D.7.10 Nitrogen Oxide Control

In order to ensure compliance with Condition D.7.5 - NOx PSD BACT, the Selective Catalytic 

Reduction and Dry Low NOx combustors 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 except during periods of startup and shutdown.

D.7.11 H2SO4 Compliance Determination Requirements [326 IAC 2-2]

In order to ensure compliance with Condition D.7.2, the Permittee shall maintain a record of the 

monthly average sulfur content of the natural gas based on vendor data.

D.7.12 Greenhouse Gases (GHGs) Calculations

To determine the compliance status with Condition D.7.6 - GHGs PSD BACT, the following 

equation shall be used to determine the CO2e emissions from the natural gas-fired combined 

cycle combustion turbines, identified as EU-1 and EU-2: 

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) = 120 lbs/mmbtu for combustion with duct firing and 122 lbs/mmbtu for 

combustion without duct firing 

CH4 EF (lb/mmbtu) = 0.0022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) 

for natural gas

N2O EF (lb/mmbtu) = 0.00022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart 

C) for natural gas

CO2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N2O GWP = 310 global warming potential from GHG MRR (40 CFR 98, Subpart A)

D.7.13 HAPs Minor Limits Calculations

To determine the compliance status with Condition D.7.7 - Hazardous Air Pollutants (HAPs) minor 

Limits, the following equation shall be used to determine formaldehyde emissions from the natural 

gas-fired combined cycle combustion turbines, identified as EU-1 and EU-2: 

L (tons/month)= (7.1 x 10-4 x Qu + C x Qc)/2000 lbs/ton

Where: 

L = 9 tons of (formaldehyde) per 12 month rolling period.

7.1 x 10-4 is the uncontrolled emission factor for formaldehyde (lbs/MMBtu)

Qu = 12- month rolling total heat input to the CT units (MMBtu) when the oxidation catalyst is 

not fully operational during startup and shutdown conditions
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Qc = 12- month rolling total heat input to the CT units (MMBtu) when the oxidation catalyst is 

fully operational (includes heat input to duct burners). 

C = is the controlled emission factor for formaldehyde (lbs/MMBtu), which would be based on 

stack test results of the CCCTs. Prior to stack testing the factor will be conservatively 

assumed to equal 60% of the uncontrolled emission factor.

D.7.14 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 O2 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.

(d) Whenever a NOx or O2 CEMS is down for more than twenty-four (24) hours, the 

Permittee shall monitor the catalyst inlet temperature used in conjunction with the CCCT 

units with a continuous temperature monitoring system and comply with the following:

The Permittee shall measure the operating temperature of the catalyst inlet bed 

temperature no less often than once per four (4) hours. In the event of a monitoring 

system malfunction, failure to measure the operating temperature of the catalyst bed 

inlet temperature is not a deviation of the permit. Failure to take response steps shall 

be considered a deviation from the permit. If the measured temperature is below the 

minimum temperature as supplied by the manufacturer, reasonable response steps 

shall be taken to return the catalyst bed inlet temperature to the required minimum 

temperature. A reading that is below the minimum temperature is not a deviation from 

this permit. Failure to take response steps in accordance with Section C – Response to 

Excursions or Exceedances shall be considered a deviation from this permit.

 

(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.7.15 Testing Requirements [326 IAC 2-1.1-11]

(a) In order to demonstrate compliance with Conditions D.7.1 - 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 by December 31 of 

every fifth year following 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.7.3 - 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 oxidation catalyst controlling the combined cycle combustion turbines 

utilizing methods as approved by the commissioner. Testing shall be conducted with the 
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duct burners in operation. This test shall be repeated by December 31 of every fifth year 

following 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.7.4 - 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 oxidation catalyst controlling 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 by December 31 of 

every fifth year following 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.7.6(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 by December 31 of every fifth year following 

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.7.7 - Hazardous Air Pollutants 

(HAPs) minor Limits, 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

HAPs (formaldehyde) emissions stack testing of the emissions from oxidation catalyst 

controlling the combined cycle combustion turbines utilizing methods as approved by the 

commissioner. This test shall be repeated by December 31 of every fifth year following 

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.7.16 Oxidation Catalyst Parametric Monitoring [40 CFR 64]

(a) In order to ensure compliance with Conditions D.7.3, D.7.4 and D.7.7, a continuous 

monitoring system shall be calibrated, maintained, and operated on the 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 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, CO and formaldehyde control or as 

established during the most recent compliant stack test.
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(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, 

CO and formaldehyde 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.7.17 Record Keeping Requirement

(a) In order to document the compliance status with Conditions D.7.1, D.7.2, D.7.3, D.7.4, 

D.7.5, D.7.6 and D.7.7, the Permittee shall maintain monthly records of the amount and 

type of fuel combusted in the combined cycle combustion turbines.

(b) To document the compliance status with Condition D.7.2 - H2SO4 PSD BACT, the 

Permittee shall maintain the monthly vendors records of the fuel sulfur content of the 

natural gas combusted in the turbines and the associated duct burners.

(c) To document the compliance status with Condition D.7.6 (b) - GHGs PSD BACT, the 

Permittee shall maintain monthly records of the CO2e emissions.

(d) To document the compliance status with the emission limits in Condition D.7.7 - 

Hazardous Air Pollutants (HAPs) minor Limits, the Permittee shall maintain monthly 

records of the formaldehyde emissions.

(e) To document compliance with Condition D.7.8 - 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) Records shall be maintained at any time the unit is off-line. 

(4) 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.

(f) To document the compliance status with Condition D.7.14 - 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.

(g) In the event that a breakdown of the NOx or O2 continuous emission monitoring system 

(CEMS) occurs in Condition D.7.14 - 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.

(h) To document the compliance status with Conditions D.7.14 - Maintenance of Continuous 

Emission Monitoring Equipment, the Permittee shall maintain the monthly records of the 

NOx emissions from each of the combined cycle combustion turbines EU-1 and EU-2 

based upon the CEM data. 

(i) In order to document the compliance status with Condition D.7.16 - Oxidation Catalyst 

Parametric Monitoring, the Permittee shall maintain continuous temperature records (on a 

three- (3-) hour average basis) for each oxidation catalyst to demonstrate compliance.
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(j) Section C - General Record Keeping Requirements contains the Permittee's obligations 

with regard to the record keeping required by this condition.

D.7.18 Reporting Requirements 

A quarterly summary of the information to document the compliance status with Conditions 

D.7.6(b), D.7.7, D.7.8(h), D.7.8(i) and D.7.8(j) 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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Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

SECTION D.8 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(l) One (1) natural gas fired Auxiliary Boiler, identified as emission unit EU-3, permitted in 2013, 

with a rated heat input capacity of 79.3 MMBtu/hr, equipped with low NOx burners (LNB) with 

flue gas recirculation (FGR) to reduce NOx emissions exhausting to stack S-3. 

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

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

D.8.1 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-3 shall be as follows:

The PM, PM2.5 and PM10 emissions from the Auxiliary Boiler, identified as EU-3 shall not exceed 

0.005 lb/MMBtu and 0.4 lbs/hour, based on a 3-hr average period through the use of good 

combustion practices and fuel specification. 

D.8.2 H2SO4 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-3 shall be as follows:

(a) The H2SO4 emissions from the auxiliary boiler, identified as EU-3 shall be limited by 

limiting the S content of the natural gas to 0.75 gr S/100 scf on a monthly average basis. 

D.8.3 CO PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-3 shall be as follows:

The CO emissions from the Auxiliary Boiler (EU-3) operation shall not exceed 0.083 lb/MMBtu 

and 6.5 lbs/hr, based on a 3 - hour average through the use of advanced ultra -low NOx burner.

D.8.4 VOC PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-3 shall be as follows:

The VOC emissions from the Auxiliary Boiler, identified as EU-3 shall not exceed 0.0053 

lb/MMBtu and 0.42 lbs/hr, based on a 3-hr average period through the use of advanced ultra - low 

NOx burner.

D.8.5 NOx PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-3 shall be as follows:

(a) The NOx emissions from the Auxiliary Boiler, identified as EU-3 shall be controlled by Low 

NOx Burners with Flue Gas Recirculation.
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(b) The NOx emissions shall be limited to less than 0.011 lb/MMBtu and 0.87 pounds per 

hour, based on a 3-hour average period.

D.8.6 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-3 shall be as follows:

The GHGs BACT for the Auxiliary Boiler 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) The boiler will be equipped with a condensate return system (recovery);

(f) Steam and hot lines will be insulated; and 

(g) Boiler designed for 80% thermal efficiency (HHV).

(h) The total CO2e emissions for Auxiliary Boiler shall be limited to less than 40,639 tons of 

CO2e per twelve (12) consecutive month period with compliance determined at the end of 

each month.

D.8.7 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.

Compliance Determination Requirements

D.8.8 Nitrogen Oxide Control

In order to ensure compliance with Condition D.8.5 - NOx PSD BACT, the Low NOx Burners with 

Flue Gas Recirculation shall be installed and utilized at all times that the auxiliary boiler is in 

operation.

D.8.9 H2SO4 Compliance Determination Requirements [326 IAC 2-2]

In order to ensure compliance with Condition D.8.2, the Permittee shall maintain a record of the 

monthly average sulfur content of the natural gas based on vendor data.

D.8.10 Testing Requirements [326 IAC 2-1.1-11]

(a) In order to demonstrate compliance with Condition D.8.1 - 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 auxiliary boiler utilizing methods as 

approved by the commissioner. This test shall be performed once. Testing shall be 
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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.8.3 - 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 auxiliary boiler 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.

(c) In order to demonstrate compliance with Condition D.8.4 - 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 auxiliary boiler 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.

(d) In order to demonstrate compliance with Condition D.8.5 - 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 auxiliary boiler utilizing methods as approved by the commissioner. 

This test shall be repeated by December 31 of every fifth year following 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.8.6(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 boiler, 

identified as EU-3 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.8.11 Greenhouse Gases (GHGs) Calculations

To determine the compliance status with Condition D.8.6(h), the following equation shall be used 

to determine the CO2e emissions from the Auxiliary Boiler: 

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) = 117 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart 

C) for natural gas

CH4 EF (lb/mmbtu) = 0.0022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) 
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for natural gas

N2O EF (lb/mmbtu) = 0.00022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart 

C) for natural gas

CO2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N2O GWP = 310 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.8.12 Record Keeping Requirements

(a) In order to document the compliance status with Conditions D.8.1, D.8.2, D.8.3, D.8.4, 

D.8.5, D.8.6 and D.8.11, the Permittee shall maintain monthly records of the type and 

amount of fuel combusted in the auxiliary boiler.

(b) To document the compliance status with Condition D.8.2 - H2SO4 PSD BACT, the 

Permittee shall maintain the monthly vendor records of the fuel sulfur content of the 

natural gas combusted in the auxiliary boiler.

(c) To document the compliance status with Condition D.8.6(h) - GHGs PSD BACT, the 

Permittee shall maintain the monthly records of the total CO2e emissions from the 

auxiliary boiler. 

(d) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition.

D.8.13 Reporting Requirements

A quarterly summary of the information to document the compliance status with Condition 

D.8.6(h) 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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Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

SECTION D.9 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(m) One (1) natural gas fired Dew Point Heater, identified as emission unit EU-4, permitted in 2013, 

with a rated heat input capacity of 20.8 MMBtu/hr exhausting to stack S-4.

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

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

D.9.1 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 (Prevention 

of Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the dew 

point heater, identified as EU-4 shall be as follows:

The PM, PM10 and PM2.5 emissions from the Dew Point Heater, identified as EU-4 shall be limited 

to less than 0.0072 lb/MMBtu and 0.15 lbs/hr, based on a 3-hr average period through the use of 

good combustion practices and fuel specification. 

D.9.2 H2SO4 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 (Prevention 

of Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the dew 

point heater, identified as EU-4 shall be as follows:

(a) The H2SO4 emissions from the dew point heater, identified as EU-4 shall be limited by 

limiting the S content of the natural gas to 0.75 gr S/100 scf on a monthly average basis. 

D.9.3 CO PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 (Prevention 

of Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the dew 

point heater, identified as EU-4 shall be as follows:

The CO emissions from the Dew Point Heater (EU-4) operation shall not exceed 0.082 lb/MMBtu 

and 1.7 lbs/hr, based on a 3 - hour average through the use of good combustion and low NOx 

burners.

D.9.4 VOC PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 (Prevention 

of Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the dew 

point heater, identified as EU-4 shall be as follows:

The VOC emissions from the Dew Point Heater, identified as EU-3 shall not exceed 0.0053 

lb/MMBtu and 0.11 lbs/hr, based on a 3-hr average period through the use of good combustion 

and low NOx burners.

D.9.5 NOx PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 (Prevention 

of Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the dew 

point heater, identified as EU-4 shall be as follows:
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Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

(a) The NOx emissions from the Dew Point Heater, identified as EU-4 shall be controlled by a 

Low NOx Burner with Flue Gas Recirculation.

(b) The NOx emissions shall be limited to less than 0.032 lb/MMBtu and 0.67 pounds per 

hour, based on a 3-hr average period.

D.9.6 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 (Prevention 

of Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the dew 

point heater, identified as EU-4 shall be as follows:

(a) The good engineering design and Combustion Practices.

(b) The use of only natural gas.

 

(c) The total CO2e emissions for Dew Point Heater shall be limited to less than 10,659 tons of 

CO2e per twelve (12) consecutive month period with compliance determined at the end of 

each month.

Compliance Determination Requirements

D.9.7 Nitrogen Oxide Control

In order to ensure compliance with Condition D.9.5 - NOx PSD BACT, the low NOx burner shall 

be installed and utilized at all times that the dew point heater, identified as EU-4 is in operation.

D.9.8 Compliance Determination Requirements [326 IAC 2-2]

In order to determine compliance status with Conditions D.9.1 - PM, PM10 and PM2.5 PSD BACT 

and D.9.2 - H2SO4 PSD BACT, the Permittee shall only use natural gas in the dew point heater 

EU-4. 

D.9.9 Greenhouse Gases (GHGs) Calculations

To determine the compliance status with Condition D.9.6(c), the following equation shall be used 

to determine the CO2e emissions from the dew point heater, identified as EU-4: 

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 dew point heater 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) = 117 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart 

C) for natural gas

CH4 EF (lb/mmbtu) = 0.0022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) 

for natural gas

N2O EF (lb/mmbtu) = 0.00022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart 

C) for natural gas

CO2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N2O GWP = 310 global warming potential from GHG MRR (40 CFR 98, Subpart A)
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Record Keeping and Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-19]

D.9.10 Record Keeping Requirements

(a) In order to document the compliance status with Conditions D.9.1, D.9.2, D.9.3, D.9.4, 

D.9.5, and D.9.6, 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.9.6(c) - 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.9.11 Reporting Requirements

A quarterly summary of the information to document the compliance status with Condition D.9.6(c) 

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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Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

SECTION D.10 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: Insignificant Activities

(c) One (1) distillate oil fired Emergency Generator, identified as emission unit EU-5, permitted in 

2013, with a rated capacity of 1,826 HP and exhausting through stack S-5. [Under 40 CFR 60, 

Subpart IIII, the Emergency Generator is considered new affected sources.][Under 40 CFR 63, 

Subpart ZZZZ, the fired Emergency Generator is considered new affected sources.]

(d) One (1) distillate oil fired Emergency Fire Pump, identified as emission unit EU-6, permitted in 

2013, with a rated capacity of 500 HP and exhausting through stack S-6. [Under 40 CFR 60, 

Subpart IIII, the Emergency Fire Pump is considered new affected sources.][Under 40 CFR 63, 

Subpart ZZZZ, the fired Emergency Fire Pump is considered new affected sources.]

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

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

D.10.1 PM, PM10, PM2.5, NOx, CO, H2SO4 and GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 (Prevention 

of Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the 

Emergency Generator, identified as emission unit EU-5 shall be as follows:

Emergency Diesel Generator, identified as (EU5):

(a) The PM, PM10 and PM2.5 emissions from the Emergency Generator, Identified as EU-5, 

shall not exceed 0.15 g/hp-hr, through the use of combustion design control. 

(b) The H2SO4 emissions;

 1. The sulfur content of the fuel oil shall not exceed 15ppm. 

(c) The CO emissions from the Emergency Generators, Identified as EU-5 shall not exceed 

2.6 g/hp-hr through the use of combustion design controls and usage limitation. 

(d) The NOx and VOC emissions from the Emergency Generator shall be limited to less than 

4.80 g/bhp-hr for NMHC + NOx through the use of Combustion Design Controls. 

(e) The GHGs BACT for the Emergency Diesel Generator, Identified as EU5 shall be as 

follows:

1. The use of a good engineering design; and

2. The total CO2e emissions for Emergency Diesel Generator shall be limited to less 

than 605 tons of CO2e per twelve (12) consecutive month period with compliance 

determined at the end of each month.

D.10.2 PM, PM10, PM2.5, NOx, CO, H2SO4 and GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 (Prevention 

of Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the 

Emergency Fire Pump, identified as emission unit EU-6 shall be as follows:
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Emergency Fire Pump Engine, identified as EU-6:

(a) The PM, PM10 and PM2.5 emissions from the Emergency Fire Pump Engine shall not 

exceed 0.15 g/hp-hr through the use of combustion design control. 

(b) H2SO4 BACT Limits 

 1. The sulfur content of the fuel oil shall not exceed 15ppm. 

(c) The CO emissions from the Emergency Fire pump Engine shall not exceed 2.6 g/hp-hr 

through the use of combustion design controls and usage limitation. 

(d) The NOx and VOC emissions from the Emergency Fire Pump Engine shall not exceed 

3.0 g/bhp-hr for NMHC + NOx through the use of Combustion Design Controls and usage 

limitation. 

(e) The GHGs BACT for the Emergency Diesel Generator, Identified as EU-6 shall be as 

follows:

1. The use of a good engineering design; and

2. The total CO2e emissions for Firewater Pump Engine shall be limited to less than 

158 tons of CO2e per twelve (12) consecutive month period with compliance 

determined at the end of each month.

Compliance Determination Requirements

D.10.3 Greenhouse Gases (GHGs) Calculations

(a) To determine the compliance status with Condition D.10.1(e)(2), the following equation 

shall be used to determine the CO2e emissions from the Emergency Diesel Generator 

(EU-5):

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 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) = 163 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart 

C) for diesel fuel

CH4 EF (lb/mmbtu) = 0.00661 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart 

C) for diesel fuel

N2O EF (lb/mmbtu) = 0.00132 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart 

C) for diesel fuel

CO2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N2O GWP = 310 global warming potential from GHG MRR (40 CFR 98, Subpart A)

(b) To determine the compliance status with Condition D.10.2(g)(3), the following equation 

shall be used to determine the CO2e emissions from the Emergency Fire Pump Engine 

(EU-6):

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 + 
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 N2O EF (lb/mmbtu) x N2O GWP)] x 1/2000 (ton/lb)

Where:

Fuel Usage (gal/month) = monthly fire pump engine 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) = 163 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart 

C) for diesel fuel

CH4 EF (lb/mmbtu) = 0.00661 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart 

C) for diesel fuel

N2O EF (lb/mmbtu) = 0.00132 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart 

C) for diesel fuel

CO2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N2O GWP = 310 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.10.4 Record Keeping Requirements

(a) In order to document the compliance status with Conditions D.10.1(b) and D10.2(b), the 

Permittee shall maintain monthly records of the percent sulfur content of the fuel used in 

the emergency diesel engine and the fire pump engine. 

(b) To document compliance with Conditions D.10.1(e) and D.10.2(e), the Permittee shall 

maintain monthly records of hours of operation of the emergency diesel engine and the 

fire pump engine. 

(c) To document the compliance status with Conditions D.10.1(e)(2), D.10.2(e)(2) and 

D.10.3, the Permittee shall maintain records of the total amount of fuel used each month 

in the emergency diesel engine and fire pump engine and the total CO2e emissions from 

the emergency diesel engine and fire pump engine. 

(e) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition.

D.10.5 Reporting Requirements

A quarterly summary of the information to document the compliance status with Conditions 

D.10.1(e)(2) and D.10.2(e)(2) 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.
IPL Eagle Valley Generating Station Page 71 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

SECTION D.11 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: Insignificant Activities

(e) One (1) evaporative cooling tower, identified as emission unit U-7, rated with a circulation rate 

of 192,000 gpm to provide non-contact cooling water to the steam turbine condenser, permitted 

in 2013, and equipped with high efficiency drift eliminators. 

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

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

D.11.1 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 (Prevention 

of Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the 

cooling water, identified as EU-7 shall be as follows:

(a) The PM, PM10 and PM2.5 emissions from the Cooling Tower, identified as U-7 shall be 

controlled by High efficiency drift eliminators designed with a drift loss rate of less than 

0.0005% and maximum total dissolved solids (TDS) shall be less than 5000 ppm.

(b) The PM, PM10 and PM2.5 emissions from the Cooling Tower shall be less than 2.4, 1.5 and 

0.005 pounds per hour, respectively.

Compliance Determination

D.11.2 PM, PM10 and PM2.5 Control

(a) In order to ensure compliance with Conditions D.11.1 - PM and 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.

(b) The Permittee shall perform monthly tests of the blow-down water quality using EPAapproved method. This monthly test shall not be required for any 30-day period in which 

the wet cooling tower is not in operation, provided that the Permittee maintains a log of 

wet cooling tower operation.

(c) The Permittee shall calculate the PM, PM10, and PM2.5 emission rates using an equation 

based on the TDS and water circulation rate using the following formula. 

E = (c x T x Q x 8.34 x 60 x DR) / 106

Where: 

 E = mass emission rate in lbs/hr for PM, PM10 and PM2.5;

 c = particle size fraction (c=1 for PM; 0.635 for PM10 and 0.00213 for PM2.5);

 T = Total Dissolved Solids, mg/l;

Q = Cooling tower circulation rate, gallons/min; and

 DR = Drift rate (assumed to be 0.0005% based on design).
IPL Eagle Valley Generating Station Page 72 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

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

D.11.3 Record Keeping Requirements

(a) To document the compliance status with Condition D.11.1, the Permittee shall maintain a 

log that contains the date and result of each blow-down water quality test and resulting 

mass rate. This log shall be maintained onsite for a minimum of five years and shall be 

provided to EPA and IDEM upon request. 

(b) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition.
IPL Eagle Valley Generating Station Page 73 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

SECTION D.12 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: Insignificant Activities

(f) Electrical Circuit Breakers containing sulfur hexafluoride (SF6) identified as emissions unit F-1, 

permitted in 2013, with fugitive emissions controlled by full enclosure.

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

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

D.12.1 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 (Prevention 

of Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the 

Electrical Circuit Breakers, identified as SF6 shall be as follows:

(1) The use of totally enclosed pressure system with a design leak rate of 0.5% by weight and 

a density alarm for leak detection.

(2) The total SF6 emissions from all the circuit breakers shall not exceed 59.8 tons of CO2e per 

twelve (12) consecutive month period with compliance determined at the end of each month.
IPL Eagle Valley Generating Station Page 74 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

SECTION D.13 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: Insignificant Activities

(g) Fugitive equipment leaks from the natural gas supply lines, identified as F-2.

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

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

D.13.1 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 (Prevention 

of Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the 

Fugitive equipment leaks shall be as follows:

The BACT for fugitive GHG emissions shall be use of Auditory, Visual, and Olfactory (AVO) 

Monitoring program for methane leaks.
IPL Eagle Valley Generating Station Page 75 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

SECTION D.14 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: Insignificant Activities

(h) Three (3) Turbine Lube Demister Vents, permitted in 2013. 

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

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

D.14.1 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 (Prevention 

of Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the 

Turbine Lube Oil Demister Vents shall be as follows:

The PM, PM10 and PM2.5 emissions from the Turbine Lube Oil Demister Vents shall be the use of 

good design and operating practices. 
IPL Eagle Valley Generating Station Page 76 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

SECTION E TITLE IV CONDITIONS

Oris Code: 991

Title IV Source Description:

(a) Two (2) no. 2 fuel oil fired boilers, identified as Unit 1 and Unit 2, constructed in 1949 and 1950, 

respectively, each with a design heat input capacity of 524 million Btu per hour (MMBtu/hr), 

both exhausting to stack 1-1.

(b) One (1) tangentially-fired wet-bottom coal boiler, identified as Unit 3, constructed in 1951, with 

a design heat input capacity of 524 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) and flue gas conditioning system for control of particulate matter, exhausting 

to stack 2-1. Unit 3 will combust no. 2 fuel oil during startup, shutdown, and stabilization 

periods. Used oil generated onsite and used oil contaminated materials generated onsite may 

be combusted in Unit 3 as supplemental fuel for energy recovery. Stack 2-1 has continuous 

emission monitoring systems (CEMS) for NOX and SO2 and a continuous opacity monitor 

(COM).

(c) One (1) tangentially-fired dry-bottom coal fired boiler, identified as Unit 4, constructed in 1953, 

with a design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) and flue gas conditioning system for control of particulate matter, exhausting 

to stack 2-1. Unit 4 is equipped with separated overfire air (SOFA) and low NOX burners (LNB) 

for control of NOX emissions, which were voluntarily installed and are not required to operate. 

Unit 4 will combust no. 2 fuel oil during startup, shutdown, and stabilization periods. Stack 2-1 

has continuous emission monitoring systems (CEMS) for NOX and SO2 and a continuous 

opacity monitor (COM).

(d) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 5, constructed in 1953, with a 

design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) and flue gas conditioning system for control of particulate matter, exhausting 

to stack 3-1. Unit 5 is equipped with SOFA and LNB for control of NOX emissions, which were 

voluntarily installed and are not required to operate. Unit 5 will combust no. 2 fuel oil during 

startup, shutdown, and stabilization periods. Stack 3-1 has continuous emission monitoring 

systems (CEMS) for NOX and SO2 and a continuous opacity monitor (COM).

(e) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 6, constructed in 1956, with a 

design heat input capacity of 1017 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) for control of particulate matter, exhausting to stack 3-1. Unit 6 is equipped 

with Closed-coupled Overfire Air (COFA) for control of NOX emissions, which was voluntarily 

installed and is not required to operate. Unit 6 will combust no. 2 fuel oil during startup, 

shutdown, and stabilization periods. Used oil generated onsite may be combusted in Unit 6 as 

supplemental fuel for energy recovery. Unit 6 has had low-NOX burners installed. Stack 3-1 

has continuous emission monitoring systems (CEMS) for NOX and SO2 and a continuous 

opacity monitor (COM).

The New Combined Cycle Combustion Turbine Generation Facility Emission Units:

(k) Two (2) natural gas fired combustion turbine units each with a natural gas fired duct burner 

identified as EU-1 and EU-2, permitted in 2013, each with a total rated heat input capacity of 

2,542 MMBtu/hr; with NOx emissions controlled by low combustion burner design and Selective 

Catalytic Reduction (SCR), and each with an oxidation catalyst system to reduce emissions of 

CO and VOCs including formaldehyde, and exhausting to stacks S-1 and S-2. Each stack has 

continuous emissions monitors (CEMS) for NOx.
IPL Eagle Valley Generating Station Page 77 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

*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 and combustion turbines which are a source of emissions.

(The information contained in this box is descriptive information and does not constitute enforceable 

conditions.)

Acid Rain Program

E.1.1 Acid Rain Permit [326 IAC 2-7-5(1)(C)] [326 IAC 21] [40 CFR 72 through 40 CFR 78]

Pursuant to 326 IAC 21 (Acid Deposition Control), the Permittee shall comply with all provisions of 

the Acid Rain permit issued for this source, and any other applicable requirements contained in 

40 CFR 72 through 40 CFR 78. The Acid Rain permit for this source is attached to this permit as 

Attachment A, and is incorporated by reference.

E.1.2 Title IV Emissions Allowances [326 IAC 2-7-5(4)] [326 IAC 21]

Emissions exceeding any allowances that the Permittee lawfully holds under the Title IV Acid Rain 

Program of the Clean Air Act are prohibited, subject to the following limitations:

(a) No revision of this permit shall be required for increases in emissions that are authorized 

by allowances acquired under the Title IV Acid Rain Program, provided that such

increases do not require a permit revision under any other applicable requirement.

(b) No limit shall be placed on the number of allowances held by the Permittee. The 

Permittee may not use allowances as a defense to noncompliance with any other 

applicable requirement.

(c) Any such allowance shall be accounted for according to the procedures established in 

regulations promulgated under Title IV of the Clean Air Act.
IPL Eagle Valley Generating Station Page 78 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

SECTION E.2 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(k) Two (2) natural gas fired combustion turbine units each with a natural gas fired duct burner 

identified as EU-1 and EU-2, permitted in 2013, each with a total rated heat input capacity of 

2,542 MMBtu/hr; with NOx emissions controlled by low combustion burner design and Selective 

Catalytic Reduction (SCR), and each with an oxidation catalyst system to reduce emissions of 

CO and VOCs including formaldehyde, and exhausting to stacks S-1 and S-2. Each stack has 

continuous emissions monitors (CEMS) for NOx.

 

*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 and combustion turbines 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.2.1 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 two 

(2) natural gas combustion turbines EU-1 and EU-2 and two (2) duct burners associated with the 

heat recovery steam generators, except as otherwise specified in 40 CFR Part 60, Subparts 

KKKK.

E.2.2 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 two (2) natural gas combustion turbines EU-1 

and EU-2 and two (2) duct burners associated with the heat recovery steam generators 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

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
IPL Eagle Valley Generating Station Page 79 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

SECTION E.3 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(l) One (1) natural gas fired Auxiliary Boiler, identified as emission unit EU-3, permitted in 2013, 

with a rated heat input capacity of 79.3 MMBtu/hr, equipped with low NOx burners (LNB) with 

flue gas recirculation (FGR) to reduce NOx emissions exhausting to stack S-3. 

(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.3.1 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 

natural gas fired auxiliary boiler, except as otherwise specified in 40 CFR Part 60, Subpart Dc.

E.3.2 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) 
IPL Eagle Valley Generating Station Page 80 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

SECTION E.4 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(c) One (1) distillate oil fired Emergency Generator, identified as emission unit EU-5, permitted in 

2013, with a rated capacity of 1,826 HP and exhausting through stack S-5. [Under 40 CFR 60, 

Subpart IIII, the Emergency Generator is considered new affected sources.][Under 40 CFR 63, 

Subpart ZZZZ, the fired Emergency Generator is considered new affected sources.]

(d) One (1) distillate oil fired Emergency Fire Pump, identified as emission unit EU-6, permitted in 

2013, with a rated capacity of 500 HP and exhausting through stack S-6. [Under 40 CFR 60, 

Subpart IIII, the Emergency Fire Pump is considered new affected sources.][Under 40 CFR 63, 

Subpart ZZZZ, the fired Emergency Fire Pump is considered new affected sources.]

(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.4.1 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 generator and the emergency fire pump

engine described in this section except when otherwise specified in 40 CFR Part 60, Subpart IIII.

E.4.2 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 an Attachment in this permit. The source is subject to the following portions of Subpart IIII:

The emergency fire pump engine is subject to the following Sections of 40 CFR Part 60, Subpart 

IIII.

1. 40 CFR 60.4200(a)(2)(ii) 

2. 40 CFR 60.4202(d) 

3. 40 CFR 60.4205(c) 

4. 40 CFR 60.4206 

5. 40 CFR 60.4207 

6. 40 CFR 60.4211(a), (c) 

7. 40 CFR 60.4218 

8. 40 CFR 60.4219

The emergency diesel generator is subject to the following Sections of 40 CFR Part 60, Subpart 

IIII.

1. 40 CFR 60.4200(a)(2)(i)

2. 40 CFR 60.4202(a)(2)

3. 40 CFR 60.4205(b)

4. 40 CFR 60.4206 

5. 40 CFR 60.4207

6. 40 CFR 60.4211(a), (c)

7. 40 CFR 60.4218 

8. 40 CFR 60.4219
IPL Eagle Valley Generating Station Page 81 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

SECTION E.5 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(c) One (1) distillate oil fired Emergency Generator, identified as emission unit EU-5, permitted in 

2013, with a rated capacity of 1,826 HP and exhausting through stack S-5. [Under 40 CFR 60, 

Subpart IIII, the Emergency Generator is considered new affected sources.][Under 40 CFR 63, 

Subpart ZZZZ, the fired Emergency Generator is considered new affected sources.]

(d) One (1) distillate oil fired Emergency Fire Pump, identified as emission unit EU-6, permitted in 

2013, with a rated capacity of 500 HP and exhausting through stack S-6. [Under 40 CFR 60, 

Subpart IIII, the Emergency Fire Pump is considered new affected sources.][Under 40 CFR 63, 

Subpart ZZZZ, the fired Emergency Fire Pump is considered new affected sources.]

(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 63.6590

2. 40 CFR 63.6645
IPL Eagle Valley Generating Station Page 82 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

SECTION F RESERVED
IPL Eagle Valley Generating Station Page 83 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

SECTION G Clean Air Interstate Rule (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)

ORIS Code: 991

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)

(a) Two (2) no. 2 fuel oil fired boilers, identified as Unit 1 and Unit 2, constructed in 1949 and 1950, 

respectively, each with a design heat input capacity of 524 million Btu per hour (MMBtu/hr), both 

exhausting to stack 1-1.

(b) One (1) tangentially-fired wet-bottom coal boiler, identified as Unit 3, constructed in 1951, with a 

design heat input capacity of 524 million Btu per hour (MMBtu/hr), with an electrostatic precipitator 

(ESP) and flue gas conditioning system for control of particulate matter, exhausting to stack 2-1. 

Unit 3 will combust no. 2 fuel oil during startup, shutdown, and stabilization periods. Used oil 

generated onsite and used oil contaminated materials generated onsite may be combusted in Unit 

3 as supplemental fuel for energy recovery. Stack 2-1 has continuous emission monitoring 

systems (CEMS) for NOX and SO2 and a continuous opacity monitor (COM).

(c) One (1) tangentially-fired dry-bottom coal fired boiler, identified as Unit 4, constructed in 1953, 

with a design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) and flue gas conditioning system for control of particulate matter, exhausting to 

stack 2-1. Unit 4 is equipped with separated overfire air (SOFA) and low NOX burners (LNB) for 

control of NOX emissions, which were voluntarily installed and are not required to operate. Unit 4 

will combust no. 2 fuel oil during startup, shutdown, and stabilization periods. Stack 2-1 has 

continuous emission monitoring systems (CEMS) for NOX and SO2 and a continuous opacity 

monitor (COM).

(d) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 5, constructed in 1953, with a 

design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an electrostatic precipitator 

(ESP) and flue gas conditioning system for control of particulate matter, exhausting to stack 3-1. 

Unit 5 is equipped with SOFA and LNB for control of NOX emissions, which were voluntarily 

installed and are not required to operate. Unit 5 will combust no. 2 fuel oil during startup, 

shutdown, and stabilization periods. Stack 3-1 has continuous emission monitoring systems 

(CEMS) for NOX and SO2 and a continuous opacity monitor (COM).

(e) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 6, constructed in 1956, with a 

design heat input capacity of 1017 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) for control of particulate matter, exhausting to stack 3-1. Unit 6 is equipped 

with Closed-coupled Overfire Air (COFA) for control of NOX emissions, which was voluntarily 

installed and is not required to operate. Unit 6 will combust no. 2 fuel oil during startup, shutdown, 

and stabilization periods. Used oil generated onsite may be combusted in Unit 6 as supplemental 

fuel for energy recovery. Unit 6 has had low-NOX burners installed. Stack 3-1 has continuous 

emission monitoring systems (CEMS) for NOX and SO2 and a continuous opacity monitor (COM).

The New Combined Cycle Combustion Turbine Generation Facility Emission Units:

(k) Two (2) natural gas fired combustion turbine units each with a natural gas fired duct burner 

identified as EU-1 and EU-2, permitted in 2013, each with a total rated heat input capacity of 

2,542 MMBtu/hr; with NOx emissions controlled by low combustion burner design and Selective 

Catalytic Reduction (SCR), and each with an oxidation catalyst system to reduce emissions of CO 

and VOCs including formaldehyde, and exhausting to stacks S-1 and S-2. Each stack has 

continuous emissions monitors (CEMS) for NOx.
IPL Eagle Valley Generating Station Page 84 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

*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 and combustion turbines which are a source of emissions.

(The information describing the process contained in this facility description box is descriptive information 

and does not constitute enforceable conditions.)

G.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.

G.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 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 shall operate each source and 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 1, 2, 3, 4, 5 and 6. 

G.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 

applicable monitoring, reporting, and record keeping requirements of 326 IAC 24-1-11, 

326 IAC 24-2-10, and 326 IAC 24-3-11.

(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 G.4.1, Nitrogen Oxides Emission 

Requirements, Condition G.4.2, Sulfur Dioxide Emission Requirements, and Condition 

G.4.3, Nitrogen Oxides Ozone Season Emission Requirements.

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

(a) As of the allowance transfer deadline for a control period, 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 326 IAC 24-1-4(c)(1) for the 

control period starting on the applicable date, as determined under 326 IAC 24-1-4(c)(2), 

and for each control period thereafter.

(c) A CAIR NOX allowance shall not be deducted for compliance with the requirements under 

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.
IPL Eagle Valley Generating Station Page 85 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

(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. 

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

(a) As of the allowance transfer deadline for a control period, 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.

(b) A CAIR SO2 unit shall be subject to the requirements under 326 IAC 24-2-4(c)(1) for the 

control period starting on the applicable date, as determined under 326 IAC 24-2-4(c)(2), 

and for each control period thereafter.

(c) A CAIR SO2 allowance shall not be deducted for compliance with the requirements under 

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.
IPL Eagle Valley Generating Station Page 86 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

G.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 for a control period, 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 ozone season unit shall be subject to the requirements under 

326 IAC 24-3-4(c)(1) for the control period starting on the applicable date, as determined 

under 326 IAC 24-3-4(c)(2), and for each control period thereafter.

(c) A CAIR NOX ozone season allowance shall not be deducted for compliance with the 

requirements under 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 ozone season 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 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 ozone season 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.

G.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)]

(a) 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:

(1) Surrender the CAIR NOX allowances required for deduction under 

326 IAC 24-1-9(j)(4).

(2) 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.

(b) 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:

(1) Surrender the CAIR SO2 allowances required for deduction under 

326 IAC 24-2-8(k)(4).
IPL Eagle Valley Generating Station Page 87 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

(2) 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.

(c) 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:

(1) Surrender the CAIR NOX ozone season allowances required for deduction under 

326 IAC 24-3-9(j)(4).

(2) 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.

G.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.
IPL Eagle Valley Generating Station Page 88 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

G.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 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 information 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

(d) Where 326 IAC 24-1, 326 IAC 24-2, and 326 IAC 24-3 requires a submission to U.S. 

EPA, the information shall be submitted to:

U.S. Environmental Protection Agency

Clean Air Markets Division

1200 Pennsylvania Avenue, NW

Mail Code 6204N

Washington, DC 20460

G.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, respectively. 
IPL Eagle Valley Generating Station Page 89 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

(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 NOX

unit, CAIR SO2 unit, and CAIR NOX ozone season unit shall also apply to the owners and 

operators of such unit.

G.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, CAIR SO2

unit, and CAIR NOX ozone season unit from compliance with any other provision of the 

applicable, approved state implementation plan, a federally enforceable permit, or the Clean Air 

Act (CAA).

G.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), 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.

Except as specified in 326 IAC 24-1-6(f)(3), 326 IAC 24-2-6(f)(3), 326 IAC 24-3-6(f)(3), whenever 

the term "CAIR designated representative" is used, the term shall be construed to include the 

CAIR designated representative or any alternate CAIR designated representative.
IPL Eagle Valley Generating Station Page 90 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY

PART 70 OPERATING PERMIT

CERTIFICATION

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Mailing Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

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: 
IPL Eagle Valley Generating Station Page 91 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY

COMPLIANCE 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: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Mailing Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

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) 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

 
IPL Eagle Valley Generating Station Page 92 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: 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 

Describe:

 

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: 

Attach a signed certification to complete this report.
IPL Eagle Valley Generating Station Page 93 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY

COMPLIANCE DATA SECTION

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Mailing Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Units 1, 2, and PR-10

Parameter: SO2 Emissions

Limit: Shall not exceed the pound per million Btu (lb/MMBtu) limit, demonstrated using a 

calendar month average

YEAR: 

Emission Unit Limit 

(lb/MMBtu)

SO2 Emissions (lb/MMBtu)

Month:

 

Month:

 

Month:

 

Unit 1 0.37 

Unit 2 0.37 

Unit PR-10 0.5 

No deviation occurred in this quarter.

Deviations occurred in this quarter.

Deviation has been reported on: 

Submitted By: 

Title/Position: 

Signature: 

Date: 

Phone: 

Attach a signed certification to complete this report.

Note: The Part 70 quarterly reporting form shall no longer apply to the distillate fuel oil fired 

generator, identified as PR-10 and the two No. 2 fuel oil fired boilers identified as Units 1 

and 2 after the emission units have been shut down and decommissioned. 

 
IPL Eagle Valley Generating Station Page 94 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Combined Cycle Combustion Turbines EU-1 - EU-2 

Parameter: NOx Emissions

Limit: shall not exceed 68 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: 
IPL Eagle Valley Generating Station Page 95 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Combined Cycle Combustion Turbines EU-1 - EU-2 

Parameter: CO Emissions

Limit: shall not exceed 565 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: 
IPL Eagle Valley Generating Station Page 96 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Combined Cycle Combustion Turbines EU-1 - EU-2 

Parameter: VOC Emissions

Limit: shall not exceed 146 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: 
IPL Eagle Valley Generating Station Page 97 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Combined Cycle Combustion Turbine EU-1 - EU-2 

Parameter: CO2e 

Limit: shall not exceed 2,649,570 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: 
IPL Eagle Valley Generating Station Page 98 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Auxiliary Boiler EU-3 

Parameter: CO2e

Limit: shall not exceed 40,639 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: 
IPL Eagle Valley Generating Station Page 99 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Dew Point Heater EU-4 

Parameter: CO2e

Limit: shall not exceed 10,569 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: 
IPL Eagle Valley Generating Station Page 100 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Emergency Generator EU-5 

Parameter: CO2e

Limit: shall not exceed 605 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: 
IPL Eagle Valley Generating Station Page 101 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

 INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Fire Pump Engine EU-6 

Parameter: CO2e

Limit: shall not exceed 157.5 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: 
IPL Eagle Valley Generating Station Page 102 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Combined Cycle Combustion Turbines EU-1 - EU-2 

Parameter: Single HAPs Emissions (Formaldehyde)

Limit: less than 9 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: 
IPL Eagle Valley Generating Station Page 103 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY

COMPLIANCE DATA SECTION

PART 70 OPERATING PERMIT

QUARTERLY DEVIATION AND COMPLIANCE MONITORING REPORT

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Mailing Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Months: to Year: 

Page 1 of 2

This report shall be submitted quarterly based on a calendar year. Any deviation from the requirements, 

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: 
IPL Eagle Valley Generating Station Page 104 of 104

Martinsville, Indiana PSD/Significant Source Modification No. 109-32471-00004 T 109-26292-00004

Permit Reviewer: Kimberly Cottrell Modified by: 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: 

Attach a signed certification to complete this report.
Attachment A to a PSD/SSM/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: IPL Eagle Valley Generating Station

Source Location: 4040 Blue Bluff Road, Martinsville, Indiana, 

46151

County: Morgan

SIC Code: 4911

Operation Permit No.: T109-26292-00004

Operation Permit Issuance Date: December 2, 2008

Significant Source Modification No.: 109-32471-00004

Significant Permit Modification No.: 109-32476-00004

Permit Reviewer: Josiah Balogun

Subpart Dc—Standards of Performance for Small Industrial-Commercial-Institutional 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/h)) or less, but greater than or equal to 2.9 MW 

(10 MMBtu/h).

(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) Affected facilities ( i.e. heat recovery steam generators and fuel heaters) that are associated with 

stationary combustion 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, 

fuel heaters, and other affected facilities that are capable of combusting more than or equal to 2.9 MW 

(10 MMBtu/h) heat input of fossil fuel but less than or equal to 29 MW (100 MMBtu/h) heat input of fossil 

fuel. If the heat recovery steam generator, fuel heater, or other affected facility is subject to this subpart, 

only emissions resulting from combustion of fuels in the steam generating unit are subject to this subpart. 

(The stationary combustion turbine emissions are subject to subpart GG or KKKK, as applicable, of this 

part.)
IPL Eagle Valley Gen. Station Page 2 of 23

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

(f) Any affected facility that meets the applicability requirements of and is subject to subpart AAAA or 

subpart CCCC of this part is not subject to this subpart.

(g) Any facility that meets the applicability requirements and is subject to an EPA approved State or 

Federal section 111(d)/129 plan implementing subpart BBBB of this part is not subject to this subpart.

(h) Affected facilities that also meet the applicability requirements under subpart J or subpart Ja of this 

part are subject to the PM and NOX standards under this subpart and the SO2 standards under subpart J 

or subpart Ja of this part, as applicable.

(i) Temporary boilers are not subject to this subpart.

[72 FR 32759, June 13, 2007, as amended at 74 FR 5090, Jan. 28, 2009; 77 FR 9461, Feb. 16, 2012]

§ 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. Coal-derived 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.

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.
IPL Eagle Valley Gen. Station Page 3 of 23

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

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), 

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), kerosine, as defined by the American Society of Testing 

and Materials in ASTM D3699 (incorporated by reference, see § 60.17), biodiesel as defined by the 

American Society of Testing and Materials in ASTM D6751 (incorporated by reference, see § 60.17), or 

biodiesel blends as defined by the American Society of Testing and Materials in ASTM D7467 

(incorporated by reference, see § 60.17).

Dry flue gas desulfurization technology means a SO2 control 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 SO2 control 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).

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 

formationsbeneath the earth's surface, of which the principal constituent is methane; or
IPL Eagle Valley Gen. Station Page 4 of 23

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

(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 SO2 emissions (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.

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.

Temporary boiler means a steam generating unit that combusts natural gas or distillate oil with a potential 

SO2 emissions rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit is designed to, and is capable 

of, being carried or moved from one location to another by means of, for example, wheels, skids, carrying 

handles, dollies, trailers, or platforms. A steam generating unit is not a temporary boiler if any one of the 

following conditions exists:

(1) The equipment is attached to a foundation.

(2) The steam generating unit or a replacement remains at a location for more than 180 consecutive 

days. Any temporary boiler that replaces a temporary boiler at a location and performs the same or similar 

function will be included in calculating the consecutive time period.

(3) The equipment is located at a seasonal facility and operates during the full annual operating period of 

the seasonal facility, remains at the facility for at least 2 years, and operates at that facility for at least 3 

months each year.

(4) The equipment is moved from one location to another in an attempt to circumvent the residence time 

requirements of this definition.
IPL Eagle Valley Gen. Station Page 5 of 23

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

Wet flue gas desulfurization technology means an SO2 control 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; 77 FR 9461, Feb. 16, 2012]

§ 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 SO2 in excess of 87 ng/J (0.20 lb/MMBtu) 

heat input or 10 percent (0.10) of the potential SO2 emission rate (90 percent reduction), nor cause to be 

discharged into the atmosphere from the affected facility any gases that contain SO2 in 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 SO2 in 

excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO2 emission rate (90 

percent reduction), nor cause to be discharged into the atmosphere from the affected facility any gases 

that contain SO2 in 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 SO2 in 

excess of 87 ng/J (0.20 lb/MMBtu) heat input or 20 percent (0.20) of the potential SO2 emission rate (80 

percent reduction); nor

(ii) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2 in 

excess of SO2 in 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 SO2 emissions limit or 

the 90 percent SO2 reduction 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 SO2 emissions shall 

neither:

(i) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2 in 

excess of 50 percent (0.50) of the potential SO2 emission rate (50 percent reduction); nor
IPL Eagle Valley Gen. Station Page 6 of 23

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

(ii) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2 in 

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 SO2 reduction 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 SO2 in 

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/h) 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; or

(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 SO2 in 

excess of 215 ng/J (0.50 lb/MMBtu) heat input from oil; 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 SO2 in excess of the following:

(1) The percent of potential SO2 emission rate or numerical SO2 emission 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/h); 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:
IPL Eagle Valley Gen. Station Page 7 of 23

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Permit Reviewer: Josiah Balogun

Where:

Es = SO2 emission limit, expressed in ng/J or lb/MMBtu heat input;

Ka = 520 ng/J (1.2 lb/MMBtu);

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 SO2 emission 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 SO2 emission rate; 

and

(2) Emissions from the pretreated fuel (without either combustion or post-combustion SO2 control) 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), (3), or (4) 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 affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/h).

(4) Other fuels-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 

MMBtu/h).

(i) The SO2 emission 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.
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[72 FR 32759, June 13, 2007, as amended at 74 FR 5090, Jan. 28, 2009; 77 FR 9462, Feb. 16, 2012]

§ 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/h) 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.

(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/h) 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 combusts coal, 

wood, or oil and has a heat input capacity of 8.7 MW (30 MMBtu/h) 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 (c).

(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/h) 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.
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(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/h) 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) 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 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 SO2

emissions 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; 77 FR 9462, Feb. 16, 2012]

§ 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 SO2 emission 

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 SO2 emission limits under § 60.42c is based on the average 

percent reduction and the average SO2 emission 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 SO2 emission 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 SO2 emission rate (Eho ) and the 
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30-day average SO2 emission 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 Eao when 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 (Eho o) is used in Equation 19-19 of Method 19 of appendix A of this part to compute 

the adjusted Eao (Eao o). The Eho o is computed using the following formula:

Where:

Eho o = Adjusted Eho , ng/J (lb/MMBtu);

Eho = Hourly SO2 emission rate, ng/J (lb/MMBtu);

E w = SO2 concentration 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 E w

for 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 E w if the owner or operator elects to assume E w = 0.

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 Ew or Xk if 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 SO2 emission 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 SO2 emission rate is computed using the following 

formula:

Where:

%Ps = Potential SO2 emission rate, in percent;

%Rg = SO2 removal efficiency of the control device as determined by Method 19 of appendix A of this part, in percent; 

and

%Rf = SO2 removal 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:
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(i) To compute the %Ps , an adjusted %Rg (%Rg o) is computed from Eao o from paragraph (e)(1) of this 

section and an adjusted average SO2 inlet rate (Eai o) using the following formula:

Where:

%Rg o = Adjusted %Rg , in percent;

Eao o = Adjusted Eao , ng/J (lb/MMBtu); and

Eai o = Adjusted average SO2 inlet rate, ng/J (lb/MMBtu).

(ii) To compute Eai o, an adjusted hourly SO2 inlet rate (Ehi o) is used. The Ehi o is computed using the 

following formula:

Where:

Ehi o = Adjusted Ehi , ng/J (lb/MMBtu);

Ehi = Hourly SO2 inlet rate, ng/J (lb/MMBtu);

E w = SO2 concentration 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 E w

for 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 E w if the owner or operator elects to assume E w = 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 SO2 standards 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 SO2

standards 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.
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(j) The owner or operator of an affected facility shall use all valid SO2 emissions data in calculating %Ps

and Eho under 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 %Ps or Eho

pursuant 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:

(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:
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(i) The O2 or CO2 measurements 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.

(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]
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(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) As of January 1, 2012, and within 90 days after the date of completing each performance test, as 

defined in § 60.8, conducted to demonstrate compliance with this subpart, you must submit relative 

accuracy test audit ( i.e., reference method) data and performance test ( i.e., compliance test) data, 

except opacity data, electronically to EPA's Central Data Exchange (CDX) by using the Electronic 

Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert tool.html/ ) or other compatible electronic 

spreadsheet. Only data collected using test methods compatible with ERT are subject to this requirement 

to be submitted electronically into EPA's WebFIRE database.

(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/h).

[72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009; 76 FR 3523, Jan. 20, 2011; 77 FR 9463, 

Feb. 16, 2012]

§ 60.46c Emission monitoring for sulfur dioxide.

(a) Except as provided in paragraphs (d) and (e) of this section, the owner or operator of an affected 

facility subject to the SO2 emission limits under § 60.42c shall install, calibrate, maintain, and operate a 

CEMS for measuring SO2 concentrations and either O2 or CO2 concentrations at the outlet of the SO2

control device (or the outlet of the steam generating unit if no SO2 control device is used), and shall 

record the output of the system. The owner or operator of an affected facility subject to the percent 
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reduction requirements under § 60.42c shall measure SO2 concentrations and either O2 or CO2

concentrations at both the inlet and outlet of the SO2 control device.

(b) The 1-hour average SO2 emission 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 SO2 emission 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 SO2 emission 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 SO2 CEMS at the inlet to the SO2 control device shall be 125 percent of the maximum estimated 

hourly potential SO2 emission rate of the fuel combusted, and the span value of the SO2 CEMS at the 

outlet from the SO2 control device shall be 50 percent of the maximum estimated hourly potential SO2

emission 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 SO2 CEMS at the outlet from the SO2 control device (or outlet of the steam generating unit if 

no SO2 control device is used) shall be 125 percent of the maximum estimated hourly potential SO2

emission rate of the fuel combusted.

(d) As an alternative to operating a CEMS at the inlet to the SO2 control device (or outlet of the steam 

generating unit if no SO2 control device is used) as required under paragraph (a) of this section, an owner 

or operator may elect to determine the average SO2 emission rate by sampling the fuel prior to 

combustion. As an alternative to operating a CEMS at the outlet from the SO2 control device (or outlet of 

the steam generating unit if no SO2 control device is used) as required under paragraph (a) of this 

section, an owner or operator may elect to determine the average SO2 emission 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 SO2

input 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 
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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 SO2 at the inlet or 

outlet of the SO2 control 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 SO2 and CO2 measurement 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 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 SO2 standards 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), and (f) 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 within 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 or within 45 days of the next day that fuel with an opacity standard is combusted, 

whichever is later;
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(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 or within 45 days of 

the next day that fuel with an opacity standard is combusted, whichever is later;

(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 within 45 days of 

the next day that fuel with an opacity standard is combusted, whichever is later; 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.

(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 10 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.
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(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).

(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 
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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) An owner or operator of an affected facility that is subject to an opacity standard in § 60.43c(c) is not 

required to operate a COMS provided that the affected facility meets the conditions in either paragraphs 

(f)(1), (2), or (3) of this section.

(1) The affected facility uses a fabric filter (baghouse) as the primary PM control device and, the owner or 

operator operates a bag leak detection system to monitor the performance of the fabric filter according to 

the requirements in section § 60.48Da of this part.

(2) The affected facility uses an ESP as the primary PM control device, and the owner or operator uses 

an ESP predictive model to monitor the performance of the ESP developed in accordance and operated 

according to the requirements in section § 60.48Da of this part.

(3) The affected facility burns only gaseous fuels and/or fuel oils that contain no greater than 0.5 weight 

percent sulfur, and the owner or operator operates the unit according to a written site-specific monitoring 

plan approved by the permitting authority. 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. For testing performed as part of this site-specific monitoring plan, the permitting 

authority may require as an alternative to the notification and reporting requirements specified in §§ 60.8 

and 60.11 that the owner or operator submit any deviations with the excess emissions report required 

under § 60.48c(c).

[72 FR 32759, June 13, 2007, as amended at 74 FR 5091, Jan. 28, 2009; 76 FR 3523, Jan. 20, 2011; 77 FR 9463, 

Feb. 16, 2012]

§ 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 SO2 emissions. 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.

(b) The owner or operator of each affected facility subject to the SO2 emission 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.
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(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 SO2 emission 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 SO2 emission 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 SO2 emission 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 SO2 emission 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.
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(4) Identification of any steam generating unit operating days for which SO2 or diluent (O2 or 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.

(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.
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(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);

(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 SO2 standard, 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 SO2 standard, 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.
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(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/SSM/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: IPL Eagle Valley Generating Station

Source Location: 4040 Blue Bluff Road, Martinsville, Indiana, 

46151

County: Morgan

SIC Code: 4911

Operation Permit No.: T109-26292-00004

Operation Permit Issuance Date: December 2, 2008

Significant Source Modification No.: 109-32471-00004

Significant Permit Modification No.: 109-32476-00004

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 
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CFR 70.3(a) or 40 CFR 71.3(a) for a 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 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.
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(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.

(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).
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§ 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?

(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. 
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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.

(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 
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backpressure monitor that notifies the owner or operator when the high backpressure limit of the engine is 

approached.

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.
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(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.

(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 
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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.

(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
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(v) A discussion identifying the frequency and methods for recalibrating the instruments you will use for monitoring 

these parameters.

(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:
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STD = The standard specified for that pollutant in §60.4204(a), §60.4205(a), or §60.4205(c).

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.
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5.9 = 20.9 percent O2−15 percent O2, the defined O2correction value, percent.

%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

Browse Previous | Browse Next
Attachment C to a PSD/SSM/Part 70 Operating Permit

Standards of Performance for Performance for Stationary Combustion 

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

Source Name: IPL Eagle Valley Generating Station

Source Location: 4040 Blue Bluff Road, Martinsville, Indiana, 

46151

County: Morgan

SIC Code: 4911

Operation Permit No.: T109-26292-00004

Operation Permit Issuance Date: December 2, 2008

Significant Source Modification No.: 109-32471-00004

Significant Permit Modification No.: 109-32476-00004

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.
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(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.

(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:
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Permit Reviewer: Josiah Balogun

(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

(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).
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§ 60.4340 How do I demonstrate continuous compliance for NOXif I do not 

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.
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(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.

(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 
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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 

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/SSM/Part 70 Operating Permit

40 CFR 63, Subpart ZZZZ—National Emission Standards for 

Hazardous Air Pollutants for Stationary Reciprocating Internal 

Combustion Engines:

Source Name: IPL Eagle Valley Generating Station

Source Location: 4040 Blue Bluff Road, Martinsville, Indiana, 

46151

County: Morgan

SIC Code: 4911

Operation Permit No.: T109-26292-00004

Operation Permit Issuance Date: December 2, 2008

Significant Source Modification No.: 109-32471-00004

Significant Permit Modification No.: 109-32476-00004

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.
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(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 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.

(f) The emergency stationary RICE listed in paragraphs (f)(1) through (3) of this section are not subject to 

this subpart. The stationary RICE must meet the definition of an emergency stationary RICE in § 63.6675, 

which includes operating according to the provisions specified in § 63.6640(f).

(1) Existing residential emergency stationary RICE located at an area source of HAP emissions that do 

not operate or are not contractually obligated to be available for more than 15 hours per calendar year for 

the purposes specified in § 63.6640(f)(2)(ii) and (iii) and that do not operate for the purpose specified in 

§ 63.6640(f)(4)(ii).

(2) Existing commercial emergency stationary RICE located at an area source of HAP emissions that do 

not operate or are not contractually obligated to be available for more than 15 hours per calendar year for 

the purposes specified in § 63.6640(f)(2)(ii) and (iii) and that do not operate for the purpose specified in 

§ 63.6640(f)(4)(ii).

(3) Existing institutional emergency stationary RICE located at an area source of HAP emissions that do 

not operate or are not contractually obligated to be available for more than 15 hours per calendar year for 

the purposes specified in § 63.6640(f)(2)(ii) and (iii) and that do not operate for the purpose specified in 

§ 63.6640(f)(4)(ii).

[69 FR 33506, June 15, 2004, as amended at 73 FR 3603, Jan. 18, 2008; 78 FR 6700, Jan. 30, 2013]

§ 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.
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(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).

(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 that does not operate or is not 

contractually obligated to be available for more than 15 hours per calendar year for the purposes 

specified in § 63.6640(f)(2)(ii) and (iii).

(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;
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(iii) Existing emergency stationary RICE with a site rating of more than 500 brake HP located at a major 

source of HAP emissions that does not operate or is not contractually obligated to be available for more 

than 15 hours per calendar year for the purposes specified in § 63.6640(f)(2)(ii) and (iii).

(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;

(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;

(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; 78 FR 6700, Jan. 30, 2013]

§ 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, operating limitations and other 

requirements 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, operating limitations, and other requirements 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 
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area source of HAP emissions, you must comply with the applicable emission limitations, operating 

limitations, and other requirements 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.

(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; 78 FR 6701, Jan. 30, 2013]
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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]
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§ 63.6602 What emission limitations and other requirements must I 

meet if I 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?

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 and other 

requirements 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.

[78 FR 6701, Jan. 30, 2013]

§ 63.6603 What emission limitations, operating limitations, and other 

requirements 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 2b to 

this subpart that apply to you.

(b) If you own or operate an existing stationary non-emergency CI RICE with a site rating of more than 

300 HP located at an area source of HAP that meets either paragraph (b)(1) or (2) of this section, you do 

not have to meet the numerical CO emission limitations specified in Table 2d of this subpart. Existing 

stationary non-emergency CI RICE with a site rating of more than 300 HP located at an area source of 

HAP that meet either paragraph (b)(1) or (2) of this section must meet the management practices that are 

shown for stationary non-emergency CI RICE with a site rating of less than or equal to 300 HP in Table 

2d of this subpart.

(1) The area source is located in an area of Alaska that is not accessible by the Federal Aid Highway 

System (FAHS).

(2) The stationary RICE is located at an area source that meets paragraphs (b)(2)(i), (ii), and (iii) of this 

section.

(i) The only connection to the FAHS is through the Alaska Marine Highway System (AMHS), or the 

stationary RICE operation is within an isolated grid in Alaska that is not connected to the statewide 

electrical grid referred to as the Alaska Railbelt Grid.

(ii) At least 10 percent of the power generated by the stationary RICE on an annual basis is used for 

residential purposes.

(iii) The generating capacity of the area source is less than 12 megawatts, or the stationary RICE is used 

exclusively for backup power for renewable energy.
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(c) If you own or operate an existing stationary non-emergency CI RICE with a site rating of more than 

300 HP located on an offshore vessel that is an area source of HAP and is a nonroad vehicle that is an 

Outer Continental Shelf (OCS) source as defined in 40 CFR 55.2, you do not have to meet the numerical 

CO emission limitations specified in Table 2d of this subpart. You must meet all of the following 

management practices:

(1) Change oil every 1,000 hours of operation or annually, whichever comes first. 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.

(2) Inspect and clean air filters every 750 hours of operation or annually, whichever comes first, and 

replace as necessary.

(3) Inspect fuel filters and belts, if installed, every 750 hours of operation or annually, whichever comes 

first, and replace as necessary.

(4) Inspect all flexible hoses every 1,000 hours of operation or annually, whichever comes first, and 

replace as necessary.

(d) If you own or operate an existing non-emergency CI RICE with a site rating of more than 300 HP 

located at an area source of HAP emissions that is certified to the Tier 1 or Tier 2 emission standards in 

Table 1 of 40 CFR 89.112 and that is subject to an enforceable state or local standard that requires the 

engine to be replaced no later than June 1, 2018, you may until January 1, 2015, or 12 years after the 

installation date of the engine (whichever is later), but not later than June 1, 2018, choose to comply with 

the management practices that are shown for stationary non-emergency CI RICE with a site rating of less 

than or equal to 300 HP in Table 2d of this subpart instead of the applicable emission limitations in Table 

2d, operating limitations in Table 2b, and crankcase ventilation system requirements in § 63.6625(g). You 

must comply with the emission limitations in Table 2d and operating limitations in Table 2b that apply for 

non-emergency CI RICE with a site rating of more than 300 HP located at an area source of HAP 

emissions by January 1, 2015, or 12 years after the installation date of the engine (whichever is later), but 

not later than June 1, 2018. You must also comply with the crankcase ventilation system requirements in 

§ 63.6625(g) by January 1, 2015, or 12 years after the installation date of the engine (whichever is later), 

but not later than June 1, 2018.

(e) If you own or operate an existing non-emergency CI RICE with a site rating of more than 300 HP 

located at an area source of HAP emissions that is certified to the Tier 3 (Tier 2 for engines above 560 

kilowatt (kW)) emission standards in Table 1 of 40 CFR 89.112, you may comply with the requirements 

under this part by meeting the requirements for Tier 3 engines (Tier 2 for engines above 560 kW) in 40 

CFR part 60 subpart IIII instead of the emission limitations and other requirements that would otherwise 

apply under this part for existing non-emergency CI RICE with a site rating of more than 300 HP located 

at an area source of HAP emissions.

(f) An existing non-emergency SI 4SLB and 4SRB stationary RICE with a site rating of more than 500 HP 

located at area sources of HAP must meet the definition of remote stationary RICE in § 63.6675 on the 

initial compliance date for the engine, October 19, 2013, in order to be considered a remote stationary 

RICE under this subpart. Owners and operators of existing non-emergency SI 4SLB and 4SRB stationary 

RICE with a site rating of more than 500 HP located at area sources of HAP that meet the definition of 

remote stationary RICE in § 63.6675 of this subpart as of October 19, 2013 must evaluate the status of 

their stationary RICE every 12 months. Owners and operators must keep records of the initial and annual 

evaluation of the status of the engine. If the evaluation indicates that the stationary RICE no longer meets 

the definition of remote stationary RICE in § 63.6675 of this subpart, the owner or operator must comply 

with all of the requirements for existing non-emergency SI 4SLB and 4SRB stationary RICE with a site 

rating of more than 500 HP located at area sources of HAP that are not remote stationary RICE within 1 

year of the evaluation.
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Permit Reviewer: Josiah Balogun

[75 FR 9675, Mar. 3, 2010, as amended at 75 FR 51589, Aug. 20, 2010; 76 FR 12866, Mar. 9, 2011; 78 FR 6701, 

Jan. 30, 2013]

§ 63.6604 What fuel requirements must I meet if I own or operate a 

stationary CI RICE?

(a) 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.

(b) Beginning January 1, 2015, if you own or operate an existing emergency CI stationary RICE with a 

site rating of more than 100 brake HP and a displacement of less than 30 liters per cylinder that uses 

diesel fuel and operates or is contractually obligated to be available for more than 15 hours per calendar 

year for the purposes specified in § 63.6640(f)(2)(ii) and (iii) or that operates for the purpose specified in 

§ 63.6640(f)(4)(ii), you must use diesel fuel that meets the requirements in 40 CFR 80.510(b) for nonroad 

diesel fuel, except that any existing diesel fuel purchased (or otherwise obtained) prior to January 1, 

2015, may be used until depleted.

(c) Beginning January 1, 2015, if you own or operate a new emergency CI stationary RICE with a site 

rating of more than 500 brake HP and a displacement of less than 30 liters per cylinder located at a major 

source of HAP that uses diesel fuel and operates or is contractually obligated to be available for more 

than 15 hours per calendar year for the purposes specified in § 63.6640(f)(2)(ii) and (iii), you must use 

diesel fuel that meets the requirements in 40 CFR 80.510(b) for nonroad diesel fuel, except that any 

existing diesel fuel purchased (or otherwise obtained) prior to January 1, 2015, may be used until 

depleted.

(d) Existing CI stationary RICE located in Guam, American Samoa, the Commonwealth of the Northern 

Mariana Islands, at area sources in areas of Alaska that meet either § 63.6603(b)(1) or § 63.6603(b)(2), 

or are on offshore vessels that meet § 63.6603(c) are exempt from the requirements of this section.

[78 FR 6702, Jan. 30, 2013]

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, operating limitations, and other requirements 

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 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, as amended at 78 FR 6702, Jan. 30, 2013]
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Permit Reviewer: Josiah Balogun

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 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 
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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. The test must be conducted at any load condition within plus or minus 10 percent of 100 

percent load for the stationary RICE listed in paragraphs (b)(1) through (4) of this section.

(1) Non-emergency 4SRB stationary RICE with a site rating of greater than 500 brake HP located at a 

major source of HAP emissions.

(2) New non-emergency 4SLB stationary RICE with a site rating of greater than or equal to 250 brake HP 

located at a major source of HAP emissions.

(3) New non-emergency 2SLB stationary RICE with a site rating of greater than 500 brake HP located at 

a major source of HAP emissions.

(4) New non-emergency CI stationary RICE with a site rating of greater than 500 brake HP located at a 

major source of HAP emissions.

(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, unless otherwise specified in this 

subpart.

(e)(1) You must use Equation 1 of this section to determine compliance with the percent reduction 

requirement:

View or download PDF

Where:

Ci = concentration of carbon monoxide (CO), total hydrocarbons (THC), or formaldehyde at the control device inlet,

Co = concentration of CO, THC, or formaldehyde at the control device outlet, and

R = percent reduction of CO, THC, or formaldehyde emissions.

(2) You must normalize the CO, THC, 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 CO2 concentration is measured in 

lieu of oxygen concentration measurement, a CO2 correction factor is needed. Calculate the CO2

correction factor as described in paragraphs (e)(2)(i) through (iii) of this section.

(i) Calculate the fuel-specific Fo value for the fuel burned during the test using values obtained from 

Method 19, Section 5.2, and the following equation:
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View or download PDF

Where:

Fo = Fuel factor based on the ratio of oxygen volume to the ultimate CO2 volume 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 CO2 produced to the gross calorific value of the fuel from Method 19, dsm3 /J (dscf/106

Btu)

(ii) Calculate the CO2 correction factor for correcting measurement data to 15 percent O2 , as follows:

View or download PDF

Where:

XCO2 = CO2 correction factor, percent.

5.9 = 20.9 percent O2 —15 percent O2 , the defined O2 correction value, percent.

(iii) Calculate the CO, THC, and formaldehyde gas concentrations adjusted to 15 percent O2 using CO2

as follows:

View or download PDF

Where:

Cadj = Calculated concentration of CO, THC, or formaldehyde adjusted to 15 percent O2.

Cd = Measured concentration of CO, THC, or formaldehyde, uncorrected.

XCO2 = CO2 correction factor, percent.

%CO2 = Measured CO2 concentration 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.
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(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;

(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.
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[69 FR 33506, June 15, 2004, as amended at 75 FR 9676, Mar. 3, 2010; 78 FR 6702, Jan. 30, 2013]

§ 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 O2 or CO2 according to the requirements in paragraphs (a)(1) 

through (4) of this section. If you are meeting a requirement to reduce CO emissions, the CEMS must be 

installed at both the inlet and outlet of the control device. If you are meeting a requirement to limit the 

concentration of CO, the CEMS must be installed at the outlet of the control device.

(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 CO2

concentration.

(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 (6) 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.

(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)(ii) and 

(c)(3); and

(v) Ongoing reporting and recordkeeping procedures in accordance with provisions in § 63.10(c), (e)(1), 

and (e)(2)(i).
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(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 emissionrelated 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;

(6) An existing non-emergency, non-black start stationary RICE located at an area 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.

(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;
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(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 (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 that meet either § 63.6603(b)(1) or § 63.6603(b)(2) do 

not have to meet the requirements of this paragraph (g). Existing CI engines located on offshore vessels 

that meet § 63.6603(c) do not have to meet the requirements of this paragraph (g).

(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 business 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 business 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 
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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, 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 business 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 business 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; 78 FR 6703, Jan. 30, 2013]

§ 63.6630 How do I demonstrate initial compliance with the emission 

limitations, operating limitations, and other requirements?

(a) You must demonstrate initial compliance with each emission limitation, operating limitation, and other 

requirement 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.

(d) Non-emergency 4SRB stationary RICE complying with the requirement to reduce formaldehyde 

emissions by 76 percent or more can demonstrate initial compliance with the formaldehyde emission limit 

by testing for THC instead of formaldehyde. The testing must be conducted according to the requirements 

in Table 4 of this subpart. The average reduction of emissions of THC determined from the performance 

test must be equal to or greater than 30 percent.

(e) The initial compliance demonstration required for existing non-emergency 4SLB and 4SRB stationary 

RICE with a site rating of more than 500 HP located at an area source of HAP that are not remote 

stationary RICE and that are operated more than 24 hours per calendar year must be conducted 

according to the following requirements:

(1) The compliance demonstration must consist of at least three test runs.

(2) Each test run must be of at least 15 minute duration, except that each test conducted using the 

method in appendix A to this subpart must consist of at least one measurement cycle and include at least 

2 minutes of test data phase measurement.

(3) If you are demonstrating compliance with the CO concentration or CO percent reduction requirement, 

you must measure CO emissions using one of the CO measurement methods specified in Table 4 of this 

subpart, or using appendix A to this subpart.
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(4) If you are demonstrating compliance with the THC percent reduction requirement, you must measure 

THC emissions using Method 25A, reported as propane, of 40 CFR part 60, appendix A.

(5) You must measure O2 using one of the O2 measurement methods specified in Table 4 of this subpart. 

Measurements to determine O2 concentration must be made at the same time as the measurements for 

CO or THC concentration.

(6) If you are demonstrating compliance with the CO or THC percent reduction requirement, you must 

measure CO or THC emissions and O2 emissions simultaneously at the inlet and outlet of the control 

device.

[69 FR 33506, June 15, 2004, as amended at 78 FR 6704, Jan. 30, 2013]

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, operating limitations, and other requirements?

(a) You must demonstrate continuous compliance with each emission limitation, operating limitation, and 

other requirements 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 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) The annual compliance demonstration required for existing non-emergency 4SLB and 4SRB 

stationary RICE with a site rating of more than 500 HP located at an area source of HAP that are not 
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remote stationary RICE and that are operated more than 24 hours per calendar year must be conducted 

according to the following requirements:

(1) The compliance demonstration must consist of at least one test run.

(2) Each test run must be of at least 15 minute duration, except that each test conducted using the 

method in appendix A to this subpart must consist of at least one measurement cycle and include at least 

2 minutes of test data phase measurement.

(3) If you are demonstrating compliance with the CO concentration or CO percent reduction requirement, 

you must measure CO emissions using one of the CO measurement methods specified in Table 4 of this 

subpart, or using appendix A to this subpart.

(4) If you are demonstrating compliance with the THC percent reduction requirement, you must measure 

THC emissions using Method 25A, reported as propane, of 40 CFR part 60, appendix A.

(5) You must measure O2 using one of the O2 measurement methods specified in Table 4 of this subpart. 

Measurements to determine O2 concentration must be made at the same time as the measurements for 

CO or THC concentration.

(6) If you are demonstrating compliance with the CO or THC percent reduction requirement, you must 

measure CO or THC emissions and O2 emissions simultaneously at the inlet and outlet of the control 

device.

(7) If the results of the annual compliance demonstration show that the emissions exceed the levels 

specified in Table 6 of this subpart, the stationary RICE must be shut down as soon as safely possible, 

and appropriate corrective action must be taken (e.g., repairs, catalyst cleaning, catalyst replacement). 

The stationary RICE must be retested within 7 days of being restarted and the emissions must meet the 

levels specified in Table 6 of this subpart. If the retest shows that the emissions continue to exceed the 

specified levels, the stationary RICE must again be shut down as soon as safely possible, and the 

stationary RICE may not operate, except for purposes of startup and testing, until the owner/operator 

demonstrates through testing that the emissions do not exceed the levels specified in Table 6 of this 

subpart.

(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.
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(f) If you own or operate an emergency stationary RICE, you must operate the emergency stationary 

RICE according to the requirements in paragraphs (f)(1) through (4) of this section. In order for the engine 

to be considered an emergency stationary RICE under this subpart, any operation other than emergency 

operation, maintenance and testing, emergency demand response, and operation in non-emergency 

situations for 50 hours per year, as described in paragraphs (f)(1) through (4) of this section, is prohibited. 

If you do not operate the engine according to the requirements in paragraphs (f)(1) through (4) of this 

section, the engine will not be considered an emergency engine under this subpart and must meet all 

requirements for non-emergency engines.

(1) There is no time limit on the use of emergency stationary RICE in emergency situations.

(2) You may operate your emergency stationary RICE for any combination of the purposes specified in 

paragraphs (f)(2)(i) through (iii) of this section for a maximum of 100 hours per calendar year. Any 

operation for non-emergency situations as allowed by paragraphs (f)(3) and (4) of this section counts as 

part of the 100 hours per calendar year allowed by this paragraph (f)(2).

(i) Emergency stationary RICE may be operated for maintenance checks and readiness testing, provided 

that the tests are recommended by federal, state or local government, the manufacturer, the vendor, the 

regional transmission organization or equivalent balancing authority and transmission operator, or the 

insurance company associated with the engine. 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 calendar year.

(ii) Emergency stationary RICE may be operated for emergency demand response for periods in which 

the Reliability Coordinator under the North American Electric Reliability Corporation (NERC) Reliability 

Standard EOP-002-3, Capacity and Energy Emergencies (incorporated by reference, see § 63.14), or 

other authorized entity as determined by the Reliability Coordinator, has declared an Energy Emergency 

Alert Level 2 as defined in the NERC Reliability Standard EOP-002-3.

(iii) Emergency stationary RICE may be operated for periods where there is a deviation of voltage or 

frequency of 5 percent or greater below standard voltage or frequency.

(3) Emergency stationary RICE located at major sources of HAP may be operated for up to 50 hours per 

calendar year in non-emergency situations. The 50 hours of operation in non-emergency situations are 

counted as part of the 100 hours per calendar year for maintenance and testing and emergency demand 

response provided in paragraph (f)(2) of this section. The 50 hours per year for non-emergency situations 

cannot be used for peak shaving or non-emergency demand response, 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.

(4) Emergency stationary RICE located at area sources of HAP may be operated for up to 50 hours per 

calendar year in non-emergency situations. The 50 hours of operation in non-emergency situations are 

counted as part of the 100 hours per calendar year for maintenance and testing and emergency demand 

response provided in paragraph (f)(2) of this section. Except as provided in paragraphs (f)(4)(i) and (ii) of 

this section, the 50 hours per year for non-emergency situations cannot be used for peak shaving or nonemergency demand response, or to generate income for a facility to an electric grid or otherwise supply 

power as part of a financial arrangement with another entity.

(i) Prior to May 3, 2014, the 50 hours per year for non-emergency situations can be used for peak shaving 

or non-emergency demand response to generate income for a facility, or to otherwise supply power as 

part of a financial arrangement with another entity if the engine is operated as part of a peak shaving 

(load management program) with the local distribution system operator and the power is provided only to 

the facility itself or to support the local distribution system.
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(ii) The 50 hours per year for non-emergency situations can be used to supply power as part of a financial 

arrangement with another entity if all of the following conditions are met:

(A) The engine is dispatched by the local balancing authority or local transmission and distribution system 

operator.

(B) The dispatch is intended to mitigate local transmission and/or distribution limitations so as to avert 

potential voltage collapse or line overloads that could lead to the interruption of power supply in a local 

area or region.

(C) The dispatch follows reliability, emergency operation or similar protocols that follow specific NERC, 

regional, state, public utility commission or local standards or guidelines.

(D) The power is provided only to the facility itself or to support the local transmission and distribution 

system.

(E) The owner or operator identifies and records the entity that dispatches the engine and the specific 

NERC, regional, state, public utility commission or local standards or guidelines that are being followed 

for dispatching the engine. The local balancing authority or local transmission and distribution system 

operator may keep these records on behalf of the engine owner or operator.

[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; 78 FR 6704, Jan. 30, 2013]

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.
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(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.

(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).

(i) If you own or operate an existing non-emergency CI RICE with a site rating of more than 300 HP 

located at an area source of HAP emissions that is certified to the Tier 1 or Tier 2 emission standards in 

Table 1 of 40 CFR 89.112 and subject to an enforceable state or local standard requiring engine 

replacement and you intend to meet management practices rather than emission limits, as specified in 

§ 63.6603(d), you must submit a notification by March 3, 2013, stating that you intend to use the provision 

in § 63.6603(d) and identifying the state or local regulation that the engine is subject to.

[73 FR 3606, Jan. 18, 2008, as amended at 75 FR 9677, Mar. 3, 2010; 75 FR 51591, Aug. 20, 2010; 78 FR 6705, 

Jan. 30, 2013]

§ 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.
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(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.

(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 
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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-of-control 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).

(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.
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(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.

(h) If you own or operate an emergency stationary RICE with a site rating of more than 100 brake HP that 

operates or is contractually obligated to be available for more than 15 hours per calendar year for the 

purposes specified in § 63.6640(f)(2)(ii) and (iii) or that operates for the purpose specified in 

§ 63.6640(f)(4)(ii), you must submit an annual report according to the requirements in paragraphs (h)(1) 

through (3) of this section.

(1) The report must contain the following information:

(i) Company name and address where the engine is located.

(ii) Date of the report and beginning and ending dates of the reporting period.

(iii) Engine site rating and model year.

(iv) Latitude and longitude of the engine in decimal degrees reported to the fifth decimal place.

(v) Hours operated for the purposes specified in § 63.6640(f)(2)(ii) and (iii), including the date, start time, 

and end time for engine operation for the purposes specified in § 63.6640(f)(2)(ii) and (iii).

(vi) Number of hours the engine is contractually obligated to be available for the purposes specified in 

§ 63.6640(f)(2)(ii) and (iii).
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(vii) Hours spent for operation for the purpose specified in § 63.6640(f)(4)(ii), including the date, start 

time, and end time for engine operation for the purposes specified in § 63.6640(f)(4)(ii). The report must 

also identify the entity that dispatched the engine and the situation that necessitated the dispatch of the 

engine.

(viii) If there were no deviations from the fuel requirements in § 63.6604 that apply to the engine (if any), a 

statement that there were no deviations from the fuel requirements during the reporting period.

(ix) If there were deviations from the fuel requirements in § 63.6604 that apply to the engine (if any), 

information on the number, duration, and cause of deviations, and the corrective action taken.

(2) The first annual report must cover the calendar year 2015 and must be submitted no later than March 

31, 2016. Subsequent annual reports for each calendar year must be submitted no later than March 31 of 

the following calendar year.

(3) The annual report must be submitted electronically using the subpart specific reporting form in the 

Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA's Central 

Data Exchange (CDX) ( www.epa.gov/cdx ). However, if the reporting form specific to this subpart is not 

available in CEDRI at the time that the report is due, the written report must be submitted to the 

Administrator at the appropriate address listed in § 63.13.

[69 FR 33506, June 15, 2004, as amended at 75 FR 9677, Mar. 3, 2010; 78 FR 6705, Jan. 30, 2013]

§ 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.

(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.
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(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) through (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 engine is used for the purposes specified in § 63.6640(f)(2)(ii) or (iii) or § 63.6640(f)(4)(ii), 

the owner or operator must keep records of the notification of the emergency situation, and the date, start 

time, and end time of engine operation for these purposes.

(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.

[69 FR 33506, June 15, 2004, as amended at 75 FR 9678, Mar. 3, 2010; 75 FR 51592, Aug. 20, 2010; 78 FR 6706, 

Jan. 30, 2013]

§ 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]
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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.

(5) Approval of a performance test which was conducted prior to the effective date of the rule, as 

specified in § 63.6610(b).
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§ 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:

Alaska Railbelt Grid means the service areas of the six regulated public utilities that extend from 

Fairbanks to Anchorage and the Kenai Peninsula. These utilities are Golden Valley Electric Association; 

Chugach Electric Association; Matanuska Electric Association; Homer Electric Association; Anchorage 

Municipal Light & Power; and the City of Seward Electric System.

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.

Backup power for renewable energy means an engine that provides backup power to a facility that 

generates electricity from renewable energy resources, as that term is defined in Alaska Statute 

42.45.045(l)(5) (incorporated by reference, see § 63.14).

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.
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(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 .

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 reciprocating internal combustion engine that meets all 

of the criteria in paragraphs (1) through (3) of this definition. 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.

(1) The stationary RICE is operated to provide electrical power or mechanical work during an emergency 

situation. 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.

(2) The stationary RICE is operated under limited circumstances for situations not included in paragraph 

(1) of this definition, as specified in § 63.6640(f).

(3) The stationary RICE operates as part of a financial arrangement with another entity in situations not 

included in paragraph (1) of this definition only as allowed in § 63.6640(f)(2)(ii) or (iii) and 

§ 63.6640(f)(4)(i) or (ii).

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 
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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.

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.
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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 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 C3

H8 .

Remote stationary RICE means stationary RICE meeting any of the following criteria:
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(1) Stationary RICE located in an offshore area that is beyond the line of ordinary low water along that 

portion of the coast of the United States that is in direct contact with the open seas and beyond the line 

marking the seaward limit of inland waters.

(2) Stationary RICE located on a pipeline segment that meets both of the criteria in paragraphs (2)(i) and 

(ii) of this definition.

(i) A pipeline segment with 10 or fewer buildings intended for human occupancy and no buildings with 

four or more stories within 220 yards (200 meters) on either side of the centerline of any continuous 1-

mile (1.6 kilometers) length of pipeline. Each separate dwelling unit in a multiple dwelling unit building is 

counted as a separate building intended for human occupancy.

(ii) The pipeline segment does not lie within 100 yards (91 meters) of either a building or a small, welldefined outside area (such as a playground, recreation area, outdoor theater, or other place of public 

assembly) that is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-

month period. The days and weeks need not be consecutive. The building or area is considered occupied 

for a full day if it is occupied for any portion of the day.

(iii) For purposes of this paragraph (2), the term pipeline segment means all parts of those physical 

facilities through which gas moves in transportation, including but not limited to pipe, valves, and other 

appurtenance attached to pipe, compressor units, metering stations, regulator stations, delivery stations, 

holders, and fabricated assemblies. Stationary RICE located within 50 yards (46 meters) of the pipeline 

segment providing power for equipment on a pipeline segment are part of the pipeline segment. 

Transportation of gas means the gathering, transmission, or distribution of gas by pipeline, or the storage 

of gas. A building is intended for human occupancy if its primary use is for a purpose involving the 

presence of humans.

(3) Stationary RICE that are not located on gas pipelines and that have 5 or fewer buildings intended for 

human occupancy and no buildings with four or more stories within a 0.25 mile radius around the engine. 

A building is intended for human occupancy if its primary use is for a purpose involving the presence of 

humans.

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. 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.
IPL Eagle Valley Gen. Station Page 35 of 72

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

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.

[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; 78 FR 6706, Jan. 30, 2013]

Table 1 a to 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
IPL Eagle Valley Gen. Station Page 36 of 72

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

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 1 b to Subpart ZZZZ of Part 63—Operating Limitations for 

Existing, New, and Reconstructed SI 4SRB Stationary RICE >500 HP 

Located at a Major 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:

TABLE 1B TO SUBPART ZZZZ OF PART 63—OPERATING LIMITATIONS FOR EXISTING, NEW, AND 

RECONSTRUCTED SI 4SRB STATIONARY RICE >500 HP LOCATED AT A MAJOR SOURCE OF HAP EMISSIONS

For each . . .

You must meet the following operating 

limitation, except during periods of startup . . .

1. existing, new and reconstructed 4SRB stationary 

RICE >500 HP located at a major source of HAP 

emissions complying with the requirement to reduce 

formaldehyde emissions by 76 percent or more (or by 

75 percent or more, if applicable) and using NSCR; or

existing, new and reconstructed 4SRB stationary 

RICE >500 HP located at a major source of HAP 

emissions complying with the requirement to limit the 

concentration of formaldehyde in the stationary RICE 

exhaust to 350 ppbvd or less at 15 percent O2and 

using NSCR;

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 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.1

2. existing, new and reconstructed 4SRB stationary 

RICE >500 HP located at a major source of HAP 

emissions 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

Comply with any operating limitations approved by 

the Administrator.

existing, new and reconstructed 4SRB stationary 

RICE >500 HP located at a major source of HAP 

emissions complying with the requirement to limit the 

concentration of formaldehyde in the stationary RICE 

exhaust to 350 ppbvd or less at 15 percent O2and not 

using NSCR.

1 Sources can petition the Administrator pursuant to the requirements of 40 CFR 63.8(f) for a different 

temperature range.

[78 FR 6706, Jan. 30, 2013]

Table 2 a to Subpart ZZZZ of Part 63—Emission Limitations for New 

and Reconstructed 2SLB and Compression Ignition Stationary RICE 
IPL Eagle Valley Gen. Station Page 37 of 72

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

>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 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

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

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 2 b to Subpart ZZZZ of Part 63—Operating Limitations for New 

and Reconstructed 2SLB and CI 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 CI Stationary RICE >500 HP

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 CI 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; and existing CI stationary RICE >500 HP:

TABLE 2B TO SUBPART ZZZZ OF PART 63—OPERATING LIMITATIONS FOR NEW AND RECONSTRUCTED 

2SLB AND CI STATIONARY RICE >500 HP LOCATED AT A MAJOR SOURCE OF HAP EMISSIONS, NEW AND 
IPL Eagle Valley Gen. Station Page 38 of 72

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

RECONSTRUCTED 4SLB STATIONARY RICE ≥250 HP LOCATED AT A MAJOR SOURCE OF HAP EMISSIONS,

EXISTING CI STATIONARY RICE >500 HP

For each . . .

You must meet the following operating 

limitation, except during periods of startup 

. . .

1. New and reconstructed 2SLB and CI stationary RICE 

>500 HP located at a major source of HAP emissions and 

new and reconstructed 4SLB stationary RICE ≥250 HP 

located at a major source of HAP emissions complying 

with the requirement to reduce CO emissions and using 

an oxidation catalyst; and

New and reconstructed 2SLB and CI stationary RICE 

>500 HP located at a major source of HAP emissions and 

new and reconstructed 4SLB stationary RICE ≥250 HP 

located at a major source of HAP emissions complying 

with the requirement to limit the concentration of 

formaldehyde in the stationary RICE exhaust and using an 

oxidation catalyst.

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 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. Existing CI stationary RICE >500 HP complying with the 

requirement to limit or reduce the concentration of CO in 

the stationary RICE exhaust and using an oxidation 

catalyst

a. maintain your catalyst so that the pressure 

drop across the catalyst does not change by 

more than 2 inches of water from the pressure 

drop across the catalyst that was 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 450 °F 

and less than or equal to 1350 °F.1

3. New and reconstructed 2SLB and CI stationary RICE 

>500 HP located at a major source of HAP emissions and 

new and reconstructed 4SLB stationary RICE ≥250 HP 

located at a major source of HAP emissions complying 

with the requirement to reduce CO emissions and not 

using an oxidation catalyst; and

Comply with any operating limitations 

approved by the Administrator.

New and reconstructed 2SLB and CI stationary RICE 

>500 HP located at a major source of HAP emissions and 

new and reconstructed 4SLB stationary RICE ≥250 HP 

located at a major source of HAP emissions complying 

with the requirement to limit the concentration of 

formaldehyde in the stationary RICE exhaust and not 

using an oxidation catalyst; and

existing CI stationary RICE >500 HP complying with the 

requirement to limit or reduce the concentration of CO in 

the stationary RICE exhaust and not using an oxidation 

catalyst.

1 Sources can petition the Administrator pursuant to the requirements of 40 CFR 63.8(f) for a different 

temperature range.

[78 FR 6707, Jan. 30, 2013]
IPL Eagle Valley Gen. Station Page 39 of 72

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

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:

TABLE 2C TO 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

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, and replace as 

necessary;

c. Inspect all hoses and 

belts every 500 hours of 

operation or annually, 

whichever comes first, and 

replace as necessary.3

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

2. Non-Emergency, non-black 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, and replace as 

necessary;

c. Inspect all hoses and 

belts every 500 hours of 

operation or annually, 

whichever comes first, and 

replace as necessary.3

3. Non-Emergency, non-black 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, non-black start a. Limit concentration of 
IPL Eagle Valley Gen. Station Page 40 of 72

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

CI stationary RICE 300>HP≤500.” 

is corrected to read “4. NonEmergency, non-black start CI 

stationary RICE 300<HP≤500.

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, non-black 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, and 

replace as necessary;

c. Inspect all hoses and 

belts every 500 hours of 

operation or annually, 

whichever comes first, and 

replace as necessary.3

7. Non-Emergency, non-black 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, and 

replace as necessary;

 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, non-black 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, and 

replace as necessary;

 c. Inspect all hoses and 

belts every 4,320 hours of 

operation or annually, 
IPL Eagle Valley Gen. Station Page 41 of 72

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

whichever comes first, and 

replace as necessary.3

9. Non-emergency, non-black 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, non-black start 

4SRB stationary RICE 

100≤HP≤500

Limit concentration of 

formaldehyde in the 

stationary RICE exhaust to 

10.3 ppmvd or less at 15 

percent O2.

12. Non-emergency, non-black start 

stationary RICE 100≤HP≤500 which 

combusts landfill or digester gas 

equivalent to 10 percent or more of 

the gross heat input on an annual 

basis

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) or (j) 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.

[78 FR 6708, Jan. 30, 2013, as amended at 78 FR 14457, Mar. 6, 2013]

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:

TABLE 2D TO SUBPART ZZZZ OF PART 63—REQUIREMENTS FOR EXISTING STATIONARY RICE LOCATED 

AT AREA SOURCES OF HAP EMISSIONS
IPL Eagle Valley Gen. Station Page 42 of 72

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

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

b. Inspect air cleaner 

every 1,000 hours of 

operation or annually, 

whichever comes first, 

and replace as 

necessary;

c. Inspect all hoses and 

belts every 500 hours of 

operation or annually, 

whichever comes first, 

and replace as 

necessary.

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.

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 replace as 

necessary; and

 c. Inspect all hoses and 

belts every 500 hours of 

operation or annually, 

whichever comes first, 

and replace as 

necessary.
IPL Eagle Valley Gen. Station Page 43 of 72

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

5. Emergency stationary SI RICE; black 

start stationary SI RICE; non-emergency, 

non-black start 4SLB stationary RICE >500 

HP that operate 24 hours or less per 

calendar year; non-emergency, non-black 

start 4SRB stationary RICE >500 HP that 

operate 24 hours or less per calendar 

year.2

a. Change oil and filter 

every 500 hours of 

operation or annually, 

whichever comes first;1

;

b. Inspect spark plugs 

every 1,000 hours of 

operation or annually, 

whichever comes first, 

and replace as 

necessary; 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 replace as 

necessary; 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 replace as 

necessary; 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 4SLB 

remote stationary RICE >500 HP

a. Change oil and filter 

every 2,160 hours of 

operation or annually, 
IPL Eagle Valley Gen. Station Page 44 of 72

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

whichever comes first;1

 b. Inspect spark plugs 

every 2,160 hours of 

operation or annually, 

whichever comes first, 

and replace as 

necessary; and

 c. Inspect all hoses and 

belts every 2,160 hours 

of operation or annually, 

whichever comes first, 

and replace as 

necessary.

9. Non-emergency, non-black start 4SLB 

stationary RICE >500 HP that are not 

remote stationary RICE and that operate 

more than 24 hours per calendar year

Install an oxidation 

catalyst to reduce HAP 

emissions from the 

stationary RICE.

10. 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 replace as 

necessary; and

 c. Inspect all hoses and 

belts every 1,440 hours 

of operation or annually, 

whichever comes first, 

and replace as 

necessary.

11. Non-emergency, non-black start 4SRB 

remote stationary RICE >500 HP

a. Change oil and filter 

every 2,160 hours of 

operation or annually, 

whichever comes first;1

 b. Inspect spark plugs 

every 2,160 hours of 

operation or annually, 

whichever comes first, 

and replace as 

necessary; and

 c. Inspect all hoses and 

belts every 2,160 hours 

of operation or annually, 

whichever comes first, 

and replace as 

necessary.
IPL Eagle Valley Gen. Station Page 45 of 72

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

12. Non-emergency, non-black start 4SRB 

stationary RICE >500 HP that are not 

remote stationary RICE and that operate 

more than 24 hours per calendar year

Install NSCR to reduce 

HAP emissions from the 

stationary RICE.

13. Non-emergency, non-black start 

stationary RICE which combusts landfill or 

digester gas equivalent to 10 percent or 

more of the gross heat input on an annual 

basis

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 replace as 

necessary; and

 c. Inspect all hoses and 

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) or (j) 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.

[78 FR 6709, Jan. 30, 2013]

Subsequent Performance Tests

As stated in §§ 63.6615 and 63.6620, you must comply with the following subsequent performance test 

requirements:

TABLE 3 TO SUBPART ZZZZ OF PART 63—SUBSEQUENT PERFORMANCE TESTS

For each . . .

Complying with the 

requirement to . . . You must . . .

1. New or reconstructed 2SLB stationary RICE >500 

HP located at major sources; new or reconstructed 

4SLB stationary RICE ≥250 HP located at major 

sources; and new or reconstructed CI stationary 

RICE >500 HP located at major sources

Reduce CO emissions 

and not using a CEMS

Conduct subsequent 

performance tests 

semiannually.1
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2. 4SRB stationary RICE ≥5,000 HP located at major 

sources

Reduce formaldehyde 

emissions

Conduct subsequent 

performance tests 

semiannually.1

3. Stationary RICE >500 HP located at major 

sources and new or reconstructed 4SLB stationary 

RICE 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 >500 HP that are not limited use 

stationary RICE

Limit or reduce CO 

emissions and not 

using a CEMS

Conduct subsequent 

performance tests every 

8,760 hours or 3 years, 

whichever comes first.

5. Existing non-emergency, non-black start CI 

stationary RICE >500 HP that are limited use 

stationary RICE

Limit or reduce CO 

emissions and not 

using a CEMS

Conduct subsequent 

performance tests every 

8,760 hours 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.

[78 FR 6711, Jan. 30, 2013]

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:

TABLE 4 TO SUBPART ZZZZ OF PART 63. REQUIREMENTS FOR PERFORMANCE TESTS

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) Method 3 or 3A or 3B of 

40 CFR part 60, appendix 

A, or ASTM Method 

D6522-00 (Reapproved 

2005).a c

(a) 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) ASTM D6522-00 

(Reapproved 2005) a b cor 

Method 10 of 40 CFR part 

60, appendix A

(a) The CO 

concentration must be 

at 15 percent O2, dry 

basis.

2. 4SRB 

stationary 

RICE

a. reduce 

formaldehyde 

emissions

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) sampling sites must 

be located at the inlet 

and outlet of the control 

device.

 ii. Measure O2at the (1) Method 3 or 3A or 3B of (a) measurements to 
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inlet and outlet of the 

control device; and

40 CFR part 60, appendix 

A, or ASTM Method 

D6522-00 (Reapproved 

2005).a

determine 

O2concentration must 

be made at the same 

time as the 

measurements for 

formaldehyde or THC 

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

(a) measurements to 

determine moisture 

content must be made 

at the same time and 

location as the 

measurements for 

formaldehyde or THC 

concentration.

 iv. If demonstrating 

compliance with the 

formaldehyde percent 

reduction requirement, 

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,aprovided 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. If demonstrating 

compliance with the 

THC percent reduction 

requirement, measure 

THC at the inlet and 

the outlet of the control 

device

(1) Method 25A, reported 

as propane, of 40 CFR part 

60, appendix A

(a) THC 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 (Reapproved 

2005).a

(a) measurements to 

determine 

O2concentration must 

be made at the same 

time and location as the 

measurements for 

formaldehyde or CO 

concentration.

 iii. Measure moisture 

content of the 

stationary RICE 

exhaust at the 

sampling port location; 

(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

(a) measurements to 

determine moisture 

content must be made 

at the same time and 

location as the 
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and measurements for 

formaldehyde or CO 

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,aprovided 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),a cMethod 320 of 40 

CFR part 63, appendix A, 

or ASTM D6348-03.a

(a) CO 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.

a Incorporated by reference, see 40 CFR 63.14. You may also obtain copies from University Microfilms 

International, 300 North Zeeb Road, Ann Arbor, MI 48106.

b You may also use Method 320 of 40 CFR part 63, appendix A, or ASTM D6348-03.

c ASTM-D6522-00 (2005) may be used to test both CI and SI stationary RICE.

[78 FR 6711, Jan. 30, 2013]

Table 5 to Subpart ZZZZ of Part 63—Initial Compliance With Emission 

Limitations, Operating Limitations, and Other Requirements

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:

TABLE 5 TO SUBPART ZZZZ OF PART 63—INITIAL COMPLIANCE WITH EMISSION LIMITATIONS, OPERATING 

LIMITATIONS, AND OTHER REQUIREMENTS

For each . . .

Complying with the 

requirement to . . .

You have demonstrated initial 

compliance if . . .

1. New or reconstructed non-emergency 

2SLB stationary RICE >500 HP located at 

a major source of HAP, new or 

reconstructed non-emergency 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, and existing nonemergency stationary CI RICE >500 HP 

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 
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located at an area source of HAP 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, and existing non-emergency

stationary CI RICE >500 HP located at an 

area source of HAP

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 non-emergency 

2SLB stationary RICE >500 HP located at 

a major source of HAP, new or 

reconstructed non-emergency 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, and 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

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, and existing non-emergency 

stationary CI RICE >500 HP located at an 

area source of HAP

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 non-emergency 

2SLB stationary RICE >500 HP located at 

a major source of HAP, new or 

reconstructed non-emergency 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, and existing nonemergency stationary CI RICE >500 HP 

located at an area source of HAP

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
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 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, and existing non-emergency 

stationary CI RICE >500 HP located at an 

area source of HAP

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 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

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, or the average 

reduction of emissions of THC 

determined from the initial performance 

test is equal to or greater than 30 

percent; 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

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 or the average 

reduction of emissions of THC 

determined from the initial performance 

test is equal to or greater than 30 

percent; and
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Permit Reviewer: Josiah Balogun

 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.

9. New or reconstructed non-emergency 

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 nonemergency 4SRB stationary RICE >500 

HP 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. 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.

10. New or reconstructed non-emergency 

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 nonemergency 4SRB stationary RICE >500 

HP 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. 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 

operating parameters (if any) during the 

initial performance test.

11. Existing non-emergency stationary 

RICE 100≤HP≤500 located at a major 

source of HAP, and existing nonemergency stationary CI RICE 

300<HP≤500 located at an area source of 

HAP

a. Reduce CO 

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.

12. Existing non-emergency stationary 

RICE 100≤HP≤500 located at a major 

source of HAP, and existing nonemergency 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.

13. Existing non-emergency 4SLB 

stationary RICE >500 HP located at an 

area source of HAP that are not remote 

stationary RICE and that are operated 

a. Install an oxidation 

catalyst

i. You have conducted an initial 

compliance demonstration as specified 

in § 63.6630(e) to show that the 

average reduction of emissions of CO is 
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more than 24 hours per calendar year 93 percent or more, or the average CO 

concentration is less than or equal to 47 

ppmvd at 15 percent O2;

 ii. You have installed a CPMS to 

continuously monitor catalyst inlet 

temperature according to the 

requirements in § 63.6625(b), or you 

have installed equipment to 

automatically shut down the engine if 

the catalyst inlet temperature exceeds 

1350 °F.

14. Existing non-emergency 4SRB 

stationary RICE >500 HP located at an 

area source of HAP that are not remote 

stationary RICE and that are operated 

more than 24 hours per calendar year

a. Install NSCR i. You have conducted an initial 

compliance demonstration as specified 

in § 63.6630(e) to show that the 

average reduction of emissions of CO is 

75 percent or more, the average CO 

concentration is less than or equal to 

270 ppmvd at 15 percent O2, or the 

average reduction of emissions of THC 

is 30 percent or more;

 ii. You have installed a CPMS to 

continuously monitor catalyst inlet 

temperature according to the 

requirements in § 63.6625(b), or you 

have installed equipment to 

automatically shut down the engine if 

the catalyst inlet temperature exceeds 

1250 °F.

[78 FR 6712, Jan. 30, 2013]

Table 6 to Subpart ZZZZ of Part 63—Continuous Compliance With 

Emission Limitations, and Other Requirements

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:

TABLE 6 TO SUBPART ZZZZ OF PART 63—CONTINUOUS COMPLIANCE WITH EMISSION LIMITATIONS, AND 

OTHER REQUIREMENTS

For each . . .

Complying with the 

requirement to . . .

You must demonstrate continuous 

compliance by . . .

1. New or reconstructed non-emergency 

2SLB stationary RICE >500 HP located at 

a major source of HAP, new or 

reconstructed non-emergency 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 

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 
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major source of HAP 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.

2. New or reconstructed non-emergency 

2SLB stationary RICE >500 HP located at 

a major source of HAP, new or 

reconstructed non-emergency 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 non-emergency 

2SLB stationary RICE >500 HP located at 

a major source of HAP, new or 

reconstructed non-emergency 4SLB 

stationary RICE ≥250 HP located at a 

major source of HAP, new or 

reconstructed non-emergency stationary 

CI RICE >500 HP located at a major 

source of HAP, and existing nonemergency stationary CI RICE >500 HP

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

 iii. Maintaining the 4-hour rolling 
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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, or to demonstrate 

that the average reduction of emissions 

of THC determined from the 

performance test is equal to or greater 

than 30 percent.a

7. New or reconstructed non-emergency 

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 and 

demonstrating that the pressure drop 

across the catalyst is within the 

operating limitation established during 

the performance test.

8. New or reconstructed non-emergency 

stationary RICE >500 HP located at a 

major source of HAP and new or 

a. Limit the 

concentration of 

formaldehyde in the 

i. Conducting semiannual performance 

tests for formaldehyde to demonstrate 

that your emissions remain at or below 
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reconstructed non-emergency 4SLB 

stationary RICE 250≤HP≤500 located at a 

major source of HAP

stationary RICE 

exhaust and not using 

oxidation catalyst or 

NSCR

the formaldehyde concentration limit 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.

9. Existing emergency and black start 

stationary RICE ≤500 HP located at a 

major source of HAP, existing nonemergency 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 nonemergency stationary SI RICE located at 

an area source of HAP which combusts 

landfill or digester gas equivalent to 10 

percent or more of the gross heat input 

on an annual basis, existing nonemergency 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, and existing non-emergency 4SLB 

and 4SRB stationary RICE >500 HP 

located at an area source of HAP that are 

remote stationary RICE

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.

10. Existing stationary CI RICE >500 HP 

that are not limited use stationary RICE

a. Reduce CO 

emissions, or limit the 

concentration of CO in 

the stationary RICE 

exhaust, and using 

oxidation catalyst

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
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 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

a. Reduce CO 

emissions, or limit the 

concentration of CO in 

the stationary RICE 

exhaust, and not using 

oxidation catalyst

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 limitations 

for the operating parameters 

established during the performance 

test.

12. Existing limited use CI stationary 

RICE >500 HP

a. Reduce CO 

emissions or limit the 

concentration of CO in 

the stationary RICE 

exhaust, and using an 

oxidation catalyst

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 
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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

a. Reduce CO 

emissions or limit the 

concentration of CO in 

the stationary RICE 

exhaust, and not using 

an oxidation catalyst

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 rolling 

averages; and

 iv. Maintaining the 4-hour rolling 

averages within the operating limitations 

for the operating parameters 

established during the performance 

test.

14. Existing non-emergency 4SLB 

stationary RICE >500 HP located at an 

area source of HAP that are not remote 

stationary RICE and that are operated 

more than 24 hours per calendar year

a. Install an oxidation 

catalyst

i. Conducting annual compliance 

demonstrations as specified in 

§ 63.6640(c) to show that the average 

reduction of emissions of CO is 93 

percent or more, or the average CO 

concentration is less than or equal to 47 

ppmvd at 15 percent O2; and either

ii. Collecting the catalyst inlet 

temperature data according to 

§ 63.6625(b), reducing these data to 4-

hour rolling averages; and maintaining 

the 4-hour rolling averages within the 

limitation of greater than 450 °F and 

less than or equal to 1350 °F for the 

catalyst inlet temperature; or

iii. Immediately shutting down the 

engine if the catalyst inlet temperature 

exceeds 1350 °F.

15. Existing non-emergency 4SRB 

stationary RICE >500 HP located at an 

area source of HAP that are not remote 

stationary RICE and that are operated 

more than 24 hours per calendar year

a. Install NSCR i. Conducting annual compliance 

demonstrations as specified in 

§ 63.6640(c) to show that the average 

reduction of emissions of CO is 75 

percent or more, the average CO 

concentration is less than or equal to 

270 ppmvd at 15 percent O2,or the 

average reduction of emissions of THC 

is 30 percent or more; and either
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ii. Collecting the catalyst inlet 

temperature data according to 

§ 63.6625(b), reducing these data to 4-

hour rolling averages; and maintaining 

the 4-hour rolling averages within the 

limitation of greater than or equal to 750 

°F and less than or equal to 1250 °F for 

the catalyst inlet temperature; or

iii. Immediately shutting down the 

engine if the catalyst inlet temperature 

exceeds 1250 °F.

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.

[78 FR 6715, Jan. 30, 2013]

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:

TABLE 7 TO SUBPART ZZZZ OF PART 63—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; 

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

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

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.

 b. If you had a deviation from any 

emission limitation or operating 

limitation during the reporting 

period, the information in 

i. Semiannually 

according to the 

requirements in 

§ 63.6650(b).
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§ 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 

§ 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).

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.

3. Existing non-emergency, nonblack start 4SLB and 4SRB 

stationary RICE >500 HP located 

at an area source of HAP that are 

not remote stationary RICE and 

that operate more than 24 hours 

per calendar year

Compliance 

report

a. The results of the annual 

compliance demonstration, if 

conducted during the reporting 

period.

i. Semiannually 

according to the 

requirements in 

§ 63.6650(b)(1)-(5).

4. Emergency stationary RICE 

that operate or are contractually 

obligated to be available for more 

than 15 hours per year for the 

purposes specified in 

§ 63.6640(f)(2)(ii) and (iii) or that 

operate for the purposes specified 

in § 63.6640(f)(4)( ii)

Report a. The information in 

§ 63.6650(h)(1)

i. annually according to 

the requirements in 

§ 63.6650(h)(2)-(3).

[78 FR 6719, Jan. 30, 2013]

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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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.

§ 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 
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§§ 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.

§ 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 No

§ 63.8(c)(1)(ii) SSM not in Startup Shutdown 

Malfunction Plan

Yes.

§ 63.8(c)(1)(iii) Compliance with operation and 

maintenance requirements

No
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§ 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.

§ 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.
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§ 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 

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 Except that the most recent 2 

years of data do not have to be 

retained on site.

§ 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, as amended at 78 FR 6720, Jan. 30, 2013]

Appendix A—Protocol for Using an Electrochemical Analyzer to 

Determine Oxygen and Carbon Monoxide Concentrations From 

Certain Engines

1.0 SCOPE AND APPLICATION. WHAT IS THIS PROTOCOL?

This protocol is a procedure for using portable electrochemical (EC) cells for measuring carbon monoxide 

(CO) and oxygen (O2 ) concentrations in controlled and uncontrolled emissions from existing stationary 4-

stroke lean burn and 4-stroke rich burn reciprocating internal combustion engines as specified in the 

applicable rule.

1.1 Analytes. What does this protocol determine?

This protocol measures the engine exhaust gas concentrations of carbon monoxide (CO) and oxygen (O2

).

Analyte

CAS 

No. Sensitivity

Carbon monoxide 

(CO)

630-08-

0

Minimum detectable limit should be 2 percent of the nominal range or 1 ppm, 

whichever is less restrictive.

Oxygen (O2) 7782-

44-7
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1.2 Applicability. When is this protocol acceptable?

This protocol is applicable to 40 CFR part 63, subpart ZZZZ. Because of inherent cross sensitivities of EC 

cells, you must not apply this protocol to other emissions sources without specific instruction to that effect.

1.3 Data Quality Objectives. How good must my collected data be?

Refer to Section 13 to verify and document acceptable analyzer performance.

1.4 Range. What is the targeted analytical range for this protocol?

The measurement system and EC cell design(s) conforming to this protocol will determine the analytical 

range for each gas component. The nominal ranges are defined by choosing up-scale calibration gas 

concentrations near the maximum anticipated flue gas concentrations for CO and O2 , or no more than 

twice the permitted CO level.

1.5 Sensitivity. What minimum detectable limit will this protocol yield for a 

particular gas component?

The minimum detectable limit depends on the nominal range and resolution of the specific EC cell used, 

and the signal to noise ratio of the measurement system. The minimum detectable limit should be 2 

percent of the nominal range or 1 ppm, whichever is less restrictive.

2.0 SUMMARY OF PROTOCOL

In this protocol, a gas sample is extracted from an engine exhaust system and then conveyed to a 

portable EC analyzer for measurement of CO and O2 gas concentrations. This method provides 

measurement system performance specifications and sampling protocols to ensure reliable data. You 

may use additions to, or modifications of vendor supplied measurement systems (e.g., heated or 

unheated sample lines, thermocouples, flow meters, selective gas scrubbers, etc.) to meet the design 

specifications of this protocol. Do not make changes to the measurement system from the as-verified 

configuration (Section 3.12).

3.0 DEFINITIONS

3.1 Measurement System. The total equipment required for the measurement of CO and O2

concentrations. The measurement system consists of the following major subsystems:

3.1.1 Data Recorder. A strip chart recorder, computer or digital recorder for logging measurement data 

from the analyzer output. You may record measurement data from the digital data display manually or 

electronically.

3.1.2 Electrochemical (EC) Cell. A device, similar to a fuel cell, used to sense the presence of a specific 

analyte and generate an electrical current output proportional to the analyte concentration.

3.1.3 Interference Gas Scrubber. A device used to remove or neutralize chemical compounds that may 

interfere with the selective operation of an EC cell.

3.1.4 Moisture Removal System. Any device used to reduce the concentration of moisture in the sample 

stream so as to protect the EC cells from the damaging effects of condensation and to minimize errors in 

measurements caused by the scrubbing of soluble gases.
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3.1.5 Sample Interface. The portion of the system used for one or more of the following: sample 

acquisition; sample transport; sample conditioning or protection of the EC cell from any degrading effects 

of the engine exhaust effluent; removal of particulate matter and condensed moisture.

3.2 Nominal Range. The range of analyte concentrations over which each EC cell is operated (normally 

25 percent to 150 percent of up-scale calibration gas value). Several nominal ranges can be used for any 

given cell so long as the calibration and repeatability checks for that range remain within specifications.

3.3 Calibration Gas. A vendor certified concentration of a specific analyte in an appropriate balance gas.

3.4 Zero Calibration Error. The analyte concentration output exhibited by the EC cell in response to zerolevel calibration gas.

3.5 Up-Scale Calibration Error. The mean of the difference between the analyte concentration exhibited 

by the EC cell and the certified concentration of the up-scale calibration gas.

3.6 Interference Check. A procedure for quantifying analytical interference from components in the engine 

exhaust gas other than the targeted analytes.

3.7 Repeatability Check. A protocol for demonstrating that an EC cell operated over a given nominal 

analyte concentration range provides a stable and consistent response and is not significantly affected by 

repeated exposure to that gas.

3.8 Sample Flow Rate. The flow rate of the gas sample as it passes through the EC cell. In some 

situations, EC cells can experience drift with changes in flow rate. The flow rate must be monitored and 

documented during all phases of a sampling run.

3.9 Sampling Run. A timed three-phase event whereby an EC cell's response rises and plateaus in a 

sample conditioning phase, remains relatively constant during a measurement data phase, then declines 

during a refresh phase. The sample conditioning phase exposes the EC cell to the gas sample for a 

length of time sufficient to reach a constant response. The measurement data phase is the time interval 

during which gas sample measurements can be made that meet the acceptance criteria of this protocol. 

The refresh phase then purges the EC cells with CO-free air. The refresh phase replenishes requisite O2

and moisture in the electrolyte reserve and provides a mechanism to de-gas or desorb any interference 

gas scrubbers or filters so as to enable a stable CO EC cell response. There are four primary types of 

sampling runs: pre- sampling calibrations; stack gas sampling; post-sampling calibration checks; and 

measurement system repeatability checks. Stack gas sampling runs can be chained together for 

extended evaluations, providing all other procedural specifications are met.

3.10 Sampling Day. A time not to exceed twelve hours from the time of the pre-sampling calibration to the 

post-sampling calibration check. During this time, stack gas sampling runs can be repeated without 

repeated recalibrations, providing all other sampling specifications have been met.

3.11 Pre-Sampling Calibration/Post-Sampling Calibration Check. The protocols executed at the beginning 

and end of each sampling day to bracket measurement readings with controlled performance checks.

3.12 Performance-Established Configuration. The EC cell and sampling system configuration that existed 

at the time that it initially met the performance requirements of this protocol.

4.0 INTERFERENCES.

When present in sufficient concentrations, NO and NO2 are two gas species that have been reported to 

interfere with CO concentration measurements. In the likelihood of this occurrence, it is the protocol 
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user's responsibility to employ and properly maintain an appropriate CO EC cell filter or scrubber for 

removal of these gases, as described in Section 6.2.12.

5.0 SAFETY. [RESERVED]

6.0 EQUIPMENT AND SUPPLIES.

6.1 What equipment do I need for the measurement system?

The system must maintain the gas sample at conditions that will prevent moisture condensation in the 

sample transport lines, both before and as the sample gas contacts the EC cells. The essential 

components of the measurement system are described below.

6.2 Measurement System Components.

6.2.1 Sample Probe. A single extraction-point probe constructed of glass, stainless steel or other nonreactive material, and of length sufficient to reach any designated sampling point. The sample probe must 

be designed to prevent plugging due to condensation or particulate matter.

6.2.2 Sample Line. Non-reactive tubing to transport the effluent from the sample probe to the EC cell.

6.2.3 Calibration Assembly (optional). A three-way valve assembly or equivalent to introduce calibration 

gases at ambient pressure at the exit end of the sample probe during calibration checks. The assembly 

must be designed such that only stack gas or calibration gas flows in the sample line and all gases flow 

through any gas path filters.

6.2.4 Particulate Filter (optional). Filters before the inlet of the EC cell to prevent accumulation of 

particulate material in the measurement system and extend the useful life of the components. All filters 

must be fabricated of materials that are non-reactive to the gas mixtures being sampled.

6.2.5 Sample Pump. A leak-free pump to provide undiluted sample gas to the system at a flow rate 

sufficient to minimize the response time of the measurement system. If located upstream of the EC cells, 

the pump must be constructed of a material that is non-reactive to the gas mixtures being sampled.

6.2.8 Sample Flow Rate Monitoring. An adjustable rotameter or equivalent device used to adjust and 

maintain the sample flow rate through the analyzer as prescribed.

6.2.9 Sample Gas Manifold (optional). A manifold to divert a portion of the sample gas stream to the 

analyzer and the remainder to a by-pass discharge vent. The sample gas manifold may also include 

provisions for introducing calibration gases directly to the analyzer. The manifold must be constructed of a 

material that is non-reactive to the gas mixtures being sampled.

6.2.10 EC cell. A device containing one or more EC cells to determine the CO and O2 concentrations in 

the sample gas stream. The EC cell(s) must meet the applicable performance specifications of Section 13 

of this protocol.

6.2.11 Data Recorder. A strip chart recorder, computer or digital recorder to make a record of analyzer 

output data. The data recorder resolution (i.e., readability) must be no greater than 1 ppm for CO; 0.1 

percent for O2 ; and one degree (either °C or °F) for temperature. Alternatively, you may use a digital or 

analog meter having the same resolution to observe and manually record the analyzer responses.
IPL Eagle Valley Gen. Station Page 68 of 72

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

6.2.12 Interference Gas Filter or Scrubber. A device to remove interfering compounds upstream of the 

CO EC cell. Specific interference gas filters or scrubbers used in the performance-established 

configuration of the analyzer must continue to be used. Such a filter or scrubber must have a means to 

determine when the removal agent is exhausted. Periodically replace or replenish it in accordance with 

the manufacturer's recommendations.

7.0 REAGENTS AND STANDARDS. WHAT CALIBRATION GASES ARE NEEDED?

7.1 Calibration Gases. CO calibration gases for the EC cell must be CO in nitrogen or CO in a mixture of 

nitrogen and O2. Use CO calibration gases with labeled concentration values certified by the manufacturer 

to be within ± 5 percent of the label value. Dry ambient air (20.9 percent O2 ) is acceptable for calibration 

of the O2 cell. If needed, any lower percentage O2 calibration gas must be a mixture of O2 in nitrogen.

7.1.1 Up-Scale CO Calibration Gas Concentration. Choose one or more up-scale gas concentrations 

such that the average of the stack gas measurements for each stack gas sampling run are between 25 

and 150 percent of those concentrations. Alternatively, choose an up-scale gas that does not exceed 

twice the concentration of the applicable outlet standard. If a measured gas value exceeds 150 percent of 

the up-scale CO calibration gas value at any time during the stack gas sampling run, the run must be 

discarded and repeated.

7.1.2 Up-Scale O 2 Calibration Gas Concentration.

Select an O2 gas concentration such that the difference between the gas concentration and the average 

stack gas measurement or reading for each sample run is less than 15 percent O2 . When the average 

exhaust gas O2 readings are above 6 percent, you may use dry ambient air (20.9 percent O2 ) for the upscale O2 calibration gas.

7.1.3 Zero Gas. Use an inert gas that contains less than 0.25 percent of the up-scale CO calibration gas 

concentration. You may use dry air that is free from ambient CO and other combustion gas products (e.g., 

CO2 ).

8.0 SAMPLE COLLECTION AND ANALYSIS

8.1 Selection of Sampling Sites.

8.1.1 Control Device Inlet. Select a sampling site sufficiently downstream of the engine so that the 

combustion gases should be well mixed. Use a single sampling extraction point near the center of the 

duct (e.g., within the 10 percent centroidal area), unless instructed otherwise.

8.1.2 Exhaust Gas Outlet. Select a sampling site located at least two stack diameters downstream of any 

disturbance (e.g., turbocharger exhaust, crossover junction or recirculation take-off) and at least one-half 

stack diameter upstream of the gas discharge to the atmosphere. Use a single sampling extraction point 

near the center of the duct (e.g., within the 10 percent centroidal area), unless instructed otherwise.

8.2 Stack Gas Collection and Analysis. Prior to the first stack gas sampling run, conduct that the presampling calibration in accordance with Section 10.1. Use Figure 1 to record all data. Zero the analyzer 

with zero gas. Confirm and record that the scrubber media color is correct and not exhausted. Then 

position the probe at the sampling point and begin the sampling run at the same flow rate used during the 

up-scale calibration. Record the start time. Record all EC cell output responses and the flow rate during 

the “sample conditioning phase” once per minute until constant readings are obtained. Then begin the 

“measurement data phase” and record readings every 15 seconds for at least two minutes (or eight 

readings), or as otherwise required to achieve two continuous minutes of data that meet the specification 

given in Section 13.1. Finally, perform the “refresh phase” by introducing dry air, free from CO and other 
IPL Eagle Valley Gen. Station Page 69 of 72

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

combustion gases, until several minute-to-minute readings of consistent value have been obtained. For 

each run use the “measurement data phase” readings to calculate the average stack gas CO and O2

concentrations.

8.3 EC Cell Rate. Maintain the EC cell sample flow rate so that it does not vary by more than ± 10 percent 

throughout the pre-sampling calibration, stack gas sampling and post-sampling calibration check. 

Alternatively, the EC cell sample flow rate can be maintained within a tolerance range that does not affect 

the gas concentration readings by more than ± 3 percent, as instructed by the EC cell manufacturer.

9.0 QUALITY CONTROL (RESERVED)

10.0 CALIBRATION AND STANDARDIZATION

10.1 Pre-Sampling Calibration. Conduct the following protocol once for each nominal range to be used on 

each EC cell before performing a stack gas sampling run on each field sampling day. Repeat the 

calibration if you replace an EC cell before completing all of the sampling runs. There is no prescribed 

order for calibration of the EC cells; however, each cell must complete the measurement data phase 

during calibration. Assemble the measurement system by following the manufacturer's recommended 

protocols including for preparing and preconditioning the EC cell. Assure the measurement system has 

no leaks and verify the gas scrubbing agent is not depleted. Use Figure 1 to record all data.

10.1.1 Zero Calibration. For both the O2 and CO cells, introduce zero gas to the measurement system 

(e.g., at the calibration assembly) and record the concentration reading every minute until readings are 

constant for at least two consecutive minutes. Include the time and sample flow rate. Repeat the steps in 

this section at least once to verify the zero calibration for each component gas.

10.1.2 Zero Calibration Tolerance. For each zero gas introduction, the zero level output must be less than 

or equal to ± 3 percent of the up-scale gas value or ± 1 ppm, whichever is less restrictive, for the CO 

channel and less than or equal to ± 0.3 percent O2 for the O2 channel.

10.1.3 Up-Scale Calibration. Individually introduce each calibration gas to the measurement system (e.g., 

at the calibration assembly) and record the start time. Record all EC cell output responses and the flow 

rate during this “sample conditioning phase” once per minute until readings are constant for at least two 

minutes. Then begin the “measurement data phase” and record readings every 15 seconds for a total of 

two minutes, or as otherwise required. Finally, perform the “refresh phase” by introducing dry air, free 

from CO and other combustion gases, until readings are constant for at least two consecutive minutes. 

Then repeat the steps in this section at least once to verify the calibration for each component gas. 

Introduce all gases to flow through the entire sample handling system (i.e., at the exit end of the sampling 

probe or the calibration assembly).

10.1.4 Up-Scale Calibration Error. The mean of the difference of the “measurement data phase” readings 

from the reported standard gas value must be less than or equal to ± 5 percent or ± 1 ppm for CO or ± 0.5 

percent O2 , whichever is less restrictive, respectively. The maximum allowable deviation from the mean 

measured value of any single “measurement data phase” reading must be less than or equal to ± 2 

percent or ± 1 ppm for CO or ± 0.5 percent O2 , whichever is less restrictive, respectively.

10.2 Post-Sampling Calibration Check. Conduct a stack gas post-sampling calibration check after the 

stack gas sampling run or set of runs and within 12 hours of the initial calibration. Conduct up-scale and 

zero calibration checks using the protocol in Section 10.1. Make no changes to the sampling system or 

EC cell calibration until all post-sampling calibration checks have been recorded. If either the zero or upscale calibration error exceeds the respective specification in Sections 10.1.2 and 10.1.4 then all 

measurement data collected since the previous successful calibrations are invalid and re-calibration and 

re-sampling are required. If the sampling system is disassembled or the EC cell calibration is adjusted, 

repeat the calibration check before conducting the next analyzer sampling run.
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Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

11.0 ANALYTICAL PROCEDURE

The analytical procedure is fully discussed in Section 8.

12.0 CALCULATIONS AND DATA ANALYSIS

Determine the CO and O2 concentrations for each stack gas sampling run by calculating the mean gas 

concentrations of the data recorded during the “measurement data phase”.

13.0 PROTOCOL PERFORMANCE

Use the following protocols to verify consistent analyzer performance during each field sampling day.

13.1 Measurement Data Phase Performance Check. Calculate the mean of the readings from the 

“measurement data phase”. The maximum allowable deviation from the mean for each of the individual 

readings is ± 2 percent, or ± 1 ppm, whichever is less restrictive. Record the mean value and maximum 

deviation for each gas monitored. Data must conform to Section 10.1.4. The EC cell flow rate must 

conform to the specification in Section 8.3.

Example: A measurement data phase is invalid if the maximum deviation of any single reading comprising that 

mean is greater than ± 2 percent or ± 1 ppm (the default criteria). For example, if the mean = 30 ppm, single readings 

of below 29 ppm and above 31 ppm are disallowed ). 

13.2 Interference Check. Before the initial use of the EC cell and interference gas scrubber in the field, 

and semi-annually thereafter, challenge the interference gas scrubber with NO and NO2 gas standards 

that are generally recognized as representative of diesel-fueled engine NO and NO2 emission values. 

Record the responses displayed by the CO EC cell and other pertinent data on Figure 1 or a similar form.

13.2.1 Interference Response. The combined NO and NO2 interference response should be less than or 

equal to ± 5 percent of the up-scale CO calibration gas concentration.

13.3 Repeatability Check. Conduct the following check once for each nominal range that is to be used on 

the CO EC cell within 5 days prior to each field sampling program. If a field sampling program lasts longer 

than 5 days, repeat this check every 5 days. Immediately repeat the check if the EC cell is replaced or if 

the EC cell is exposed to gas concentrations greater than 150 percent of the highest up-scale gas 

concentration.

13.3.1 Repeatability Check Procedure. Perform a complete EC cell sampling run (all three phases) by 

introducing the CO calibration gas to the measurement system and record the response. Follow Section 

10.1.3. Use Figure 1 to record all data. Repeat the run three times for a total of four complete runs. 

During the four repeatability check runs, do not adjust the system except where necessary to achieve the

correct calibration gas flow rate at the analyzer.

13.3.2 Repeatability Check Calculations. Determine the highest and lowest average “measurement data 

phase” CO concentrations from the four repeatability check runs and record the results on Figure 1 or a 

similar form. The absolute value of the difference between the maximum and minimum average values 

recorded must not vary more than ± 3 percent or ± 1 ppm of the up-scale gas value, whichever is less 

restrictive.

14.0 POLLUTION PREVENTION (RESERVED)

15.0 WASTE MANAGEMENT (RESERVED)

16.0 ALTERNATIVE PROCEDURES (RESERVED)
IPL Eagle Valley Gen. Station Page 71 of 72

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

17.0 REFERENCES

(1) “Development of an Electrochemical Cell Emission Analyzer Test Protocol”, Topical Report, Phil 

Juneau, Emission Monitoring, Inc., July 1997.

(2) “Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Emissions from Natural Gas-Fired 

Engines, Boilers, and Process Heaters Using Portable Analyzers”, EMC Conditional Test Protocol 30 

(CTM-30), Gas Research Institute Protocol GRI-96/0008, Revision 7, October 13, 1997.

(3) “ICAC Test Protocol for Periodic Monitoring”, EMC Conditional Test Protocol 34 (CTM-034), The 

Institute of Clean Air Companies, September 8, 1999.

(4) “Code of Federal Regulations”, Protection of Environment, 40 CFR, Part 60, Appendix A, Methods 1-

4; 10.

TABLE 1: APPENDIX A—SAMPLING RUN DATA.

 

Facility__________ Engine I.D.__________ Date______

Run Type: (_) (_) (_) (_)

(X) Pre-Sample Calibration Stack Gas Sample Post-Sample Cal. Check Repeatability Check

 .

 

Run # 1 1 2 2 3 3 4 4 Time Scrub. OK Flow- Rate

Gas O2 CO O2 CO O2 CO O2 CO

Sample Cond.

Phase

′′

′′

′′

′′

Measurement

Data Phase

′′

′′

′′
IPL Eagle Valley Gen. Station Page 72 of 72

Martinsville, Indiana TV Permit No.: 109-32471-00004

Permit Reviewer: Josiah Balogun

′′

′′

′′

′′

′′

′′

′′

Mean

Refresh

Phase

′′

′′

′′

′′

[78 FR 6721, Jan. 30, 2013]
Indiana Department of Environmental Management

Office of Air Quality

Addendum to the Technical Support Document (ATSD) for a Part 70

Operating Permit (TITLE V) 

Source Background and Description

Source Name: IPL Eagle Valley Generating Station

Source Location: 4040 Blue Bluff Road, Martinsville, Indiana, 

46151

County: Morgan

SIC Code: 4911

Operation Permit No.: T109-26292-00004

Operation Permit Issuance Date: December 2, 2008

PSD/Significant Source Modification No.: T109-32471-00004

Significant Permit Modification No.: T109-32476-00004

Permit Reviewer: Josiah Balogun

On September 3, 2013, the Office of Air Quality (OAQ) had a notice published in The Martinsville 

Daily Reporter- Times in Martinsville, Indiana, stating that IPL Eagle Valley Generating Station

has applied for a Significant Modification to their Part 70 Operating Title V Permit issued on 

December 2, 2008 relating to the proposed replacement of the current coal and oil fired electric 

generating units at Indianapolis Power and Light’s (IPL’s) Eagle Valley Generating Station 

(EVGS) with a state-of-the-art, highly efficient combined cycle combustion turbine electric 

generation facility. The notice also stated that OAQ proposed to issue a permit for this operation 

and provided information on how the public could review the proposed permit and other 

documentation. Finally, the notice informed interested parties that there was a period of thirty 

(30) days to provide comments on whether or not this permit should be issued as proposed.

Comments Received

On September 30, 2013, IDEM, OAQ received comments from Angelique Oliger of IPL Eagle 

Valley Generating Station. The comments are summarized in the subsequent pages, with IDEM’s 

corresponding responses.

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.

The summary of the comments and IDEM, OAQ responses, including changes to the permit No. 

109-26292-00004 (language deleted is shown in strikeout and language added is shown in bold) are as 

follows:

Comment 1: The proposed sulfur content limit for natural gas used in the combined cycle combustion 

turbines, auxiliary boiler and the dew point heater found in the proposed conditions D.7.2, 

D.8.2 and D.9.2 of the permit. The sulfur content of the natural gas is inherently low and 

expected to be consistently below the proposed limit of 0.75 gr S/100 scf, the actual 

sulfur content of the natural gas is not within our control hence compliance with this limit 
IPL Eagle Valley Gen. Station Page 2 of 2

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

is not within our control. If in the future a spike in the sulfur content were to occur, we 

may have no choice but to cease operation in order to be in compliance which we do not 

believe to be in the best interest of the public. We would also point out that the proposed 

limit is only related to limiting Sulfuric Acid Mist (SAM) emissions for which there are not 

ambient air quality standards, nor is SAM a Hazardous Air Pollutant.

Therefore, we hereby request that these conditions from the permit be modified to require 

the use of pipeline natural gas, without a specific sulfur limitation. We also request that 

the related monitoring and recordkeeping requirements be removed from the permit.

Response 1: The H2SO4 emissions depend on the sulfur content of the natural gas which is 0.75 gr 

S/100 scf. The RBLC does not identify any facilities that have determined BACT to be the 

use of pipeline natural gas, because BACT in most cases is a numerical limit. While the 

use of pipeline natural gas can be used as an additional limit, the sulfur content of the 

natural gas, which is limited to 0.75 gr S/100 scf is the most appropriate limit for the 

H2SO4 emissions since this limit has been accepted and tested in other facilities 

nationwide.

No revisions to the draft permit are required as a result of this comment.
IPL Eagle Valley Gen. Station Page 1 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

 

Indiana Department of Environmental Management

Office of Air Quality

Technical Support Document (TSD) for a PSD/Part 70 Significant

Source and Permit Modification

Source Description and Location

Source Name: IPL Eagle Valley Generating Station

Source Location: 4040 Blue Bluff Road, Martinsville, Indiana, 

46151

County: Morgan

SIC Code: 4911

Operation Permit No.: T109-26292-00004

Operation Permit Issuance Date: December 2, 2008

PSD/Significant Source Modification No.: T109-32471-00004

Significant Permit Modification No.: T109-32476-00004

Permit Reviewer: Josiah Balogun

Existing Approvals

The source was issued Part 70 Operating Permit No. 109-26292-00004 on December 2, 2008. 

The source has since received the following approvals:

(a) Significant Permit Modification No. 109-27356-00004, issued on March 16, 2009; and

(b) Acid Rain Renewal Permit No.109-28085-00004, issued on October 19, 2009. 

County Attainment Status

The source is located in Morgan County.

Pollutant Designation

SO2 Better than national standards.

CO Unclassifiable or attainment effective November 15, 1990.

O3 Attainment effective October 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

Unclassifiable or attainment effective October 18, 2000, for the 1-hour ozone standard which was 

revoked effective June 15, 2005. Unclassifiable or attainment effective federally July 11, 2013, 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. Morgan 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.
IPL Eagle Valley Gen. Station Page 2 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(b) PM2.5

Morgan 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. Morgan County was re-designated attainment County on

July 11, 2013. Therefore, direct PM2.5, NOx 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

Morgan County has been classified as attainment or unclassifiable in Indiana for all 

criteria 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.

Source Status

The table below summarizes the potential to emit of the entire source, prior to the proposed 

modification, after consideration of all enforceable limits established in the effective permits:

Pollutant Emissions (ton/yr)

PM > 100

PM10 > 100

PM2.5 > 100

SO2 > 100

VOC < 100

CO > 100

NOX > 100

GHGs as CO2e ----

HAPs

Single HAP > 10

Total HAPs > 25

(a) This existing source is a major stationary source, under PSD (326 IAC 2-2), because a 

regulated pollutant is emitted at a rate of 100 tons per year or more, and it is one of the 

twenty-eight (28) listed source categories, as specified in 326 IAC 2-2-1(ff)(1).

(b) These emissions are based upon Part 70 operating permit renewal No. 109-26292-

00004, issued on December 2, 2008. 

Description of Proposed Modification 

The Office of Air Quality (OAQ) has reviewed a modification application, submitted by IPL Eagle 

Valley Generating Station on October 31, 2012, relating to the proposed replacement of the 

current coal and oil fired electric generating units at Indianapolis Power and Light’s (IPL’s) Eagle 

Valley Generating Station (EVGS) with a state-of-the-art, highly efficient combined cycle 

combustion turbine electric generation facility. The proposed combined cycle facility would include 
IPL Eagle Valley Gen. Station Page 3 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

two nominal 192.5 Mega Watt (MW) combustion turbines with steam waste heat recovery to drive 

a nominal 271 MW steam turbine generator. The new facility would have a total nominal capacity 

of 656 MW (net) at a fraction of the emissions of the present 340 MW coal and oil units. The 

exclusive fuel for the new combustion turbines will be natural gas. The following is a list of the 

proposed emission unit(s) and pollution control device(s): 

(a) Two (2) natural gas fired combustion turbine units each with a natural gas fired duct 

burner identified as EU-1 and EU-2, permitted in 2013, each with a total rated heat input 

capacity of 2,542 MMBtu/hr; with NOx emissions controlled by low combustion burner 

design and Selective Catalytic Reduction (SCR), and each with an oxidation catalyst 

system to reduce emissions of CO and VOCs including formaldehyde, and exhausting to 

stacks S-1 and S-2. Each stack has continuous emissions monitors (CEMS) for NOx.

*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 and combustion turbines which are a source of emissions.

(b) One (1) natural gas fired Auxiliary Boiler, identified as emission unit EU-3, permitted in 

2013, with a rated heat input capacity of 79.3 MMBtu/hr, equipped with low NOx burners 

(LNB) with flue gas recirculation (FGR) to reduce NOx emissions exhausting to stack S-3. 

(c) One (1) natural gas fired Dew Point Heater, identified as emission unit EU-4, permitted in 

2013, with a rated heat input capacity of 20.8 MMBtu/hr exhausting to stack S-4.

Insignificant and Trivial Activities 

The proposed new emissions units also include the following insignificant activities as defined in 

326 IAC 2-7-1(21): 

(a) One (1) distillate oil fired Emergency Generator, identified as emission unit EU-5, 

permitted in 2013, with a rated capacity of 1,826 HP and exhausting through stack S-5.

[Under 40 CFR 60, Subpart IIII, the Emergency Generator is considered new affected 

sources.][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Generator is considered 

new affected sources.]

(b) One (1) distillate oil fired Emergency Fire Pump, identified as emission unit EU-6, 

permitted in 2013, with a rated capacity of 500 HP and exhausting through stack S-6.

[Under 40 CFR 60, Subpart IIII, the Emergency Fire Pump is considered new affected 

sources.][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Fire Pump is considered 

new affected sources.]

(c) One (1) evaporative cooling tower, identified as emission unit U-7, with a rated circulation 

rate of 192,000 gpm to provide non-contact cooling water to the steam turbine condenser, 

permitted in 2013, and equipped with high efficiency drift eliminators. 

(d) Electrical Circuit Breakers containing sulfur hexafluoride (SF6) identified as emissions unit 

F-1, permitted in 2013, with fugitive emissions controlled by full enclosure.

(e) Fugitive equipment leaks from the natural gas supply lines, identified as F-2 controlled by 

a Leak Detection and Repair (LDAR) program.

(f) Three (3) Turbine Lube Demister Vents, permitted in 2013. 

Enforcement Issues

There are no pending enforcement actions regarding this modification. 
IPL Eagle Valley Gen. Station Page 4 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Emission Calculations

See Appendix A of this Technical Support Document for detailed emission calculations.

Permit Level Determination – Part 70

Pursuant to 326 IAC 2-1.1-1(16), 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.

Increase in PTE Before Controls of the Modification

Pollutant Potential To Emit (ton/yr)

PM 135

PM10 131

PM2.5 125

SO2 31

VOC 170

CO 660

NOX 176

H2SO4 14

Mercury 0.00011

GHGs as CO2e 2,703,157

Single HAPs

(Formaldehyde) 15

Total HAPs 23

This source modification is subject to 326 IAC 2-7-10.5(g) because potential to emit PM, PM10, 

PM2.5, VOC and NOX are greater than 25 tons per year and potential to emit CO is greater than 

100 tons per year. Therefore, this source modification shall be processed as PSD/Significant 

Source Modification pursuant to 326 IAC 2-7-10.5(g)(1), (4) and (7). Additionally, the modification 

will be incorporated into the Part 70 Operating Permit through a significant permit modification 

issued pursuant to 326 IAC 2-7-12(d), because the modification requires a case-by-case 

determination of an emission limitation to the existing Part 70 Operating Permit.
IPL Eagle Valley Gen. Station Page 5 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Permit Level Determination – PSD 

The table below summarizes the potential to emit, reflecting all limits, of the emission units. Any control equipment is considered federally 

enforceable only after issuance of this Part 70 permit modification, and only to the extent that the effect of the control equipment is made practically 

enforceable in the permit.

Table 1

Potential to Emit (Tons per year)

Process PM

(tons)

PM10

(Tons)

PM2.5

(tons)

SO2 VOC NOx CO GHGs as 

CO2e

H2SO4 Hg SF6 Single 

HAP

Total 

HAPs

CT-1w/duct 8.4 8.4 8.4 1.8

84

9.5

310.5

153299 1.0 -- -- 0.9 1.27

CT-1w/o 

duct 

52.6 52.6 52.6 13.4 72.2 1171486 5.7 -- -- 6.79 9.54

CT-2 w/duct 8.4 8.4 8.4 1.8

84

9.5

310.5

153299 1.0 -- -- 0.9 1.27

CT-2 w/o 

duct 

52.6 52.6 52.6 13.4 72.2 1171486 5.7 -- -- 6.79 9.54

Aux. Boiler 1.7 1.7 1.7 0.5 1.8 3.8 28.5 40639 0.04 1.0E-4 -- 0.028 0.72

Dew Point 

heater

0.66 0.66 0.66 0.13 0.48 2.92 7.47 10659 0.01 2.3E-5 -- 0.007 0.17

Fire Pump 0.041 0.041 0.041 0.0015 0.03 0.8 0.72 157.47 -- -- -- 1.0E-3 3.7E-3

Emer. Gen 0.16 0.16 0.16 0.01 0.10 4.7 2.63 605.32 -- -- 1.0E-4 5.8E-3

Cooling 

Tower

10.5 6.7 0.02 -- -- -- -- -- -- -- -- -- --

Paved 

Roads/

Parking

0.216 0.043 0.011 -- -- -- -- -- -- -- -- -- --

Methane 

leaks

-- -- -- -- -- -- -- 1466.9 -- -- -- -- --

Circuit 

Breaker

-- -- -- -- -- -- -- 59.8 -- -- 2.5E-3 -- --

3 Lube Oil 

Vents

0.229 0.229 0.229 -- -- -- -- -- -- -- -- -- --

Total 

Emissions

135.4 131.4 124.7 30.9 170.4 175.5 660.3 2703157 13.5 1.1E-4 2.5E-3 15.4 22.52

PSD 

Significant 

Level

25 15 10 40 40 40 100 75,000 7 0.1 NA NA NA
IPL Eagle Valley Gen. Station Page 6 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Since PM, PM10, PM2.5, NOx, CO, H2SO4 and CO2e are emitted in significant levels from the proposed modification, therefore, netting is triggered 

for these pollutants. Summation of contemporaneous emissions increases and decreases for the last 5 years prior to the modification have been 

considered in the analysis. See detailed netting analysis on Pages 1 through 21 of the emissions calculations spreadsheet.

SO2, lead and Mercury are not emitted at significant level from the proposed modification. Therefore, netting was not triggered for these pollutants.

Table 2: Emission Reduction from shutdown of existing Units 1-6 (Based on 2010 and 2011 actual emissions)

2010 and 2011 Actual Emissions (ton/year)

Process / 

Emission

Unit

PM PM10 PM2.5* SO2 VOC CO NOX GHGs as 

CO2e

H2SO4 Hg Pb Fl

Boiler 1 (oil) 0.14 0.161 0.108 0.3 0.053 0.35 1.1 1598 0.024 2.9E-5 9.2E-5

Boiler 2 (oil) 0.15 0.169 0.113 0.3 0.056 0.37 1.5 1671 0.026 3.1E-5 0.0126

Boiler 3 (Coal) 38.83 160.32 146.7

4153

1.2 14.9

838 426151

9.37 2.5E-3 0.0261 4.5

Boiler 4 (Coal) 80.69 326.75 296.0 3.73 31.1 19.48 0.0052 0.0187 9.3

Boiler 5 (Coal) 84.55 251.63 219.5

6720

2.66 22.2

955 696768

13.93 0.0037 0.0445 6.7

Boiler 6 (Coal) 201.83 600.62 523.93 6.36 53 33.24 0.0088 0.102 15.9

Total 

emissions 

from 

Shutdown

432 1418 1255 11570 15.0 129.3 1782 1192644 76.1 0.021 0.108 38.5
IPL Eagle Valley Gen. Station Page 7 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Table 3: Projected Net Emissions Increase/Decreases based on 2010 and 2011 Actual Emissions

Projected Net Emissions Increase/Decreases based on 2010 and 2011 Actual Emissions

(Tons per year)

Process PM

(tons)

PM10

(Tons)

PM2.5

(tons)

SO2 VOC CO NOx GHGs as 

CO2e

H2SO4 Hg Pb Fl

New Emission 

Units PTE

135.4 131.4 124.7 30.9 170 660.3 175.5 2703157 13.5 1.1E-4 8.8E-5 0.00

Contemporaneous 

Emission Decrease

(Shutdown of six 

boilers)

-432 -1418 -1255 -11570 -15 -129 -1782 -1192644 -80 -0.021 -0.11 -38.

Net Emission 

Increase

-300 -1286 -1130 -11539 155 531 -1606 1510513 -67 -0.021 -0.11 -38

PSD Significant 

Level

25 15 10 40 40 40 100 75,000 0.6 0.0004 0.1 NA
IPL Eagle Valley Gen. Station Page 8 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Federal Rule Applicability Determination

(a) Pursuant to 40 CFR 64.2, Compliance Assurance Monitoring (CAM) is applicable to new 

or modified emission units that involve a pollutant-specific emission unit and meet the 

following criteria:

(1) has a potential to emit before controls equal to or greater than the Part 70 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 new or modified emission unit involved:

CAM Applicability Analysis

Emission Unit Control 

Device

Used

Emission

Limitation

(Y/N)

Uncontrolled

PTE

(ton/yr)

Controlled

PTE

(ton/yr)

Part 70 

Major

Source

Threshold

(ton/yr)

CAM

Applicable

(Y/N)

Large

Unit

(Y/N)

Combustion 

Turbine EU-1 

(NOx)

Y Y > 100 < 100 100 Y N 

Combustion 

Turbine EU-1 

(NOx)

Y Y > 100 < 100 100 Y N 

Combustion 

Turbine EU-1 

(CO)

Y Y 310.5 51 100 Y N 

Combustion 

Turbine EU-2 

(CO)

Y Y 310.5 51 100 Y N 

Combustion 

Turbine EU-1 

(VOC)

Y Y > 100 < 100 100 Y N 

Combustion 

Turbine EU-2 

(VOC)

Y Y > 100 < 100 100 Y N 

Based on this evaluation, the requirements of 40 CFR Part 64, CAM are applicable to the 

combution turbines, idntified as EU-1 and EU-2 for CO and VOC emissions upon issuance of this 

Modification. A CAM plan has been incorporated in to this modification for CO and VOC 

emissions. 

The combustion turbines meet the criteria of a pollutant-specific emission unit for CO, VOC, and 

NOx. IPL will use NOx CEMS, which meets the definition of a continuous compliance 

determination method in 40 CFR 64.1. Therefore, these turbines are exempt from the 

requirements of CAM for NOx emissions, pursuant to 40 CFR 64.2(b)(1)(iv). 

The combustion turbines, auxiliary boiler, emergency generator and the fire pump, each has 

potential to emit regulated pollutants (uncontrolled) less than the major source thresholds. 

Therefore, the requirements of 40 CFR Part 64, CAM are not applicable to these emission units. 
IPL Eagle Valley Gen. Station Page 9 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(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 MMBtu/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 

40 CFR 60 Subpart Da, does not apply to the proposed HRSG units since 40 CFR 

60.40Da(e) exempts heat recovery steam generators used with duct burners capable of 

combusting more than 250 MMBtu/hr heat input if the units meet the applicability 

requirements of and are subject to 40 CFR 60 Subpart KKKK. 

This subpart also does not apply to the proposed auxiliary boiler because it cannot 

combust more than 250 MMBtu/hr. 

(d) The requirements of Standards of Performance for Industrial-Commercial-Institutional 

Steam Generating Units 40 CFR 60 Subpart Db, does not apply to the proposed HRSG 

units. 40 CFR 60.40b(i) exempts HRSGs associated with stationary combustion turbines 

that meet the requirements of subpart KKKK. Since the proposed HRSGs would be 

subject to the requirements of 40 CFR 60 Subpart KKKK, Subpart Db would not apply. 

This subpart also does not apply to the proposed auxiliary boiler because it cannot 

combust more than 100 MMBtu/hr.

(e) The requirements of Standards of Performance for Industrial-Commercial-Institutional 

Steam Generating Units apply to 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 100 MMBtu/hr or less, but greater than or equal to 10 

MMBtu/hr. This subpart does not apply to the proposed HRSG units. 40 CFR 60.40c(e) 

exempts HRSGs associated with stationary combustion turbines that meet the 

requirements of subpart KKKK. 

(f) 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 combustion turbines are subject to the requirements of NSPS KKKK and are, 

therefore, exempt from the requirements of 40 CFR Subpart GG.

(g) The requirements of National Emission Standards For Hazardous Air Pollutants For 

Industrial Process Cooling Towers 40 CFR 63, Subpart Q, applies to all new and existing 

industrial process cooling towers that are operated with chromium-based water treatment 

chemicals and are located at major HAP sources. The proposed cooling towers will not 

use chromium based water treatment chemicals and the proposed combined cycle facility 

would not constitute a major source of HAPs. Therefore this subpart does not apply to 

the cooling towers. 

(h) The requirements of National Emission Standards for Hazardous Air Pollutants for 

Stationary Combustion Turbines 40 CFR 63, Subpart YYYY applies to stationary 

combustion turbines located at Major Sources of HAPs. The proposed combined cycle 

plant will be an Area Source of HAPs following the shutdown of the existing boilers and 

with the proposed combined cycle project annual limitations on formaldehyde emissions. 

Therefore, this subpart would not apply. 
IPL Eagle Valley Gen. Station Page 10 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(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 National Emission Standards for Hazardous Air Pollutants for 

Industrial, Commercial, and Institutional Boilers and Process Heaters, 40 CFR 63, 

Subpart DDDDD are not included in this permit. The requirements of this subpart apply to 

industrial, commercial or institutional boilers located at Major Sources of HAP emissions. 

The combined cycle plant would be an Area Source of HAPs following the shutdown of 

the existing boilers and the proposed annual limitations on formaldehyde emissions. 

Therefore, the requirements of 40 CFR 63, Subpart DDDDD are not included in the 

permit.

(k) 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 this source 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. 

 

(1) Two (2) natural gas fired combustion turbine units each with a natural gas fired 

duct burner identified as EU-1 and EU-2, permitted in 2013, each with a total 

rated heat input capacity of 2,542 MMBtu/hr; with NOx emissions controlled by 

low combustion burner design and Selective Catalytic Reduction (SCR), and each 

with an oxidation catalyst system to reduce emissions of CO and VOCs including 

formaldehyde, and exhausting to stacks S-1 and S-2. Each stack has continuous 

emissions monitors (CEMS) for NOx.

 

*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 and combustion turbines 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)
IPL Eagle Valley Gen. Station Page 11 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

 17. 40 CFR 60.4405

 18. 40 CFR 60.4415

 19. 40 CFR 60.4420

(l) 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)]. The proposed project will 

include auxiliary boilers with a maximum heat input capacity of 79.3 MMBtu/hr. 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.

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.

The following emission unit is subject to the following portions of Subpart Dc: 

(1) One (1) natural gas fired Auxiliary Boiler, identified as emission unit EU-3, 

permitted in 2013, with a rated heat input capacity of 79.3 MMBtu/hr, equipped 

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

emissions exhausting to stack S-3. 

The auxiliary boiler is 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) 

(m) 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. 

(1) One (1) distillate oil fired Emergency Fire Pump, identified as emission unit EU-6, 

permitted in 2013, with a rated capacity of 500 HP and exhausting through stack 

S-6. [Under 40 CFR 60, Subpart IIII, the Emergency Fire Pump is considered new 

affected sources.][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Fire 

Pump is considered new affected sources.]

 The Emergency Fire 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 60.4202(d) 

 3. 40 CFR 60.4205(c)

 4. 40 CFR 60.4206 

 5. 40 CFR 60.4207

 6. 40 CFR 60.4211(a), (c)

 7. 40 CFR 60.4218 

 8. 40 CFR 60.4219

(1) One (1) distillate oil fired Emergency Generator, identified as emission unit EU-5, 

permitted in 2013, with a rated capacity of 1,826 HP and exhausting through 

stack S-5. [Under 40 CFR 60, Subpart IIII, the Emergency Generator is
IPL Eagle Valley Gen. Station Page 12 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

considered new affected sources.][Under 40 CFR 63, Subpart ZZZZ, the fired 

Emergency Generator is considered new affected sources.]

 The emergency diesel generator is subject to the following Sections of 40 CFR Part 60, 

Subpart IIII.

1. 40 CFR 60.4200(a)(2)(i)

2. 40 CFR 60.4202(a)(2)

 3. 40 CFR 60.4205(b)

 4. 40 CFR 60.4206 

 5. 40 CFR 60.4207

 6. 40 CFR 60.4211(a), (c)

 7. 40 CFR 60.4218 

 8. 40 CFR 60.4219

(n) The requirements of National Emission Standards for Hazardous Air Pollutants for 

Stationary Reciprocating Internal Combustion Engine 40 CFR 63, Subpart ZZZZ applies 

to stationary RICE at Area or Major Sources of HAPs and therefore, the emergency 

generator and fire pump would be subject to this subpart. However, pursuant to 40 CFR 

63.6590(c)(1), a new or reconstructed RICE at an area source of HAPs would meet the 

requirements of this subpart by complying with 40 CFR 60 Subpart IIII. There are no 

further requirements under Subpart ZZZZ, including the requirement to submit an initial 

notification.

These emission units are subject to the following portions of Subpart ZZZZ: 

(1) One (1) distillate oil fired Emergency Generator, identified as emission unit EU-5, 

permitted in 2013, with a rated capacity of 1,826 HP and exhausting through 

stack S-5. [Under 40 CFR 60, Subpart IIII, the Emergency Generator is

considered new affected sources.][Under 40 CFR 63, Subpart ZZZZ, the fired 

Emergency Generator is considered new affected sources.]

(2) One (1) distillate oil fired Emergency Fire Pump, identified as emission unit EU-6, 

permitted in 2013, with a rated capacity of 500 HP and exhausting through stack 

S-6. [Under 40 CFR 60, Subpart IIII, the Emergency Fire Pump is considered new

affected sources.][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Fire 

Pump is considered new affected sources.]

 The emergency diesel generator and Emergency Fire Pump engines are subject to the 

following Sections of 40 CFR Part 63, Subpart ZZZZ. 

1. 40 CFR 63.6590

2. 40 CFR 63.6645

The provisions of 40 CFR 63 Subpart A – General Provisions, which are incorporated as 

326 IAC 20-1-1, apply to the facility described in this section except when otherwise 

specified in 40 CFR 63 Subpart ZZZZ. 

(o) 326 IAC 24 and 40 CFR Part 97, Clean Air Interstate Rule (CAIR): 

The natural gas-fired combined cycle combustion turbines and heat recovery steam 

generators are subject to the Clean Air Interstate Rule (CAIR). This includes: the 

Nitrogen Oxides Annual Trading Program (326 IAC 24-1); the Sulfur Dioxide Trading 

Program (326 IAC 24-2; and Nitrogen Oxides Ozone Season Trading Program (326 IAC 

24-3). These emission units are subject to these regulatory requirements because the 

proposed CTs will serve a generator rated at 25 MW or more and will produce electricity 

for sale.
IPL Eagle Valley Gen. Station Page 13 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(p) 326 IAC 21 and 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 because the CCCTs will serve a generator rated at 25 MW or more and will 

produce electricity for sale. The proposed auxiliary boiler does not provide steam that 

subsequently generates electricity from the steam turbines; thus, the boiler 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.

State Rule Applicability Determination

326 IAC 2-2 (Prevention of Significant Deterioration)

This source is a major source for PSD because the potential to emit of one of the regulated 

pollutants are emitted at a rate greater than 100 tons per year and is in 1 of 28 source categories. 

The uncontrolled potential to emit of this modification is greater than 25 tons per year for PM, 

greater than 15 tons per year for PM10, greater than 40 tons per year for VOC, greater than 100 

tons per year for CO and greater than 75,000 for CO2. Therefore, this modification is subject to 

PSD review.

The “contemporaneous” emission decreases associated with the shutdown of the existing boilers 

and the net emissions increase associated with the proposed project, shows there is a “significant 

net emissions increase” for VOCs, CO and CO2e only, and there will be significant reductions in 

the emissions for NOx, PM, PM10, PM2.5, and H2SO4. As such, the requirements of PSD would 

only apply to VOCs, CO and CO2e. However, for this project, the source is electing to not utilize 

any credits for the shutdown of existing equipment and base PSD applicability on whether there is 

a “significant emission increase.” Therefore, this project is subject to PSD BACT for PM, PM10, 

PM2.5, H2SO4, VOCs, NOx, CO and CO2e.

326 IAC 2-2-3 (PSD BACT: Control Technology Review Requirements)

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU1 and EU2: 

1. The PM, PM10 and PM2.5 emissions;

(a) The PM, PM10 and PM2.5 emissions from the combined cycle combustion turbines

identified as EU-1 and EU-2 shall not exceed 16.8 pounds per hour, each and 

0.0066 pounds per MMBtu, each with duct firing based on 3-hr average through 

the use of good combustion practices and fuel specification. 

(b) The PM and PM10 emissions from the combined cycle combustion turbines

identified as EU-1 and EU-2 shall not exceed 13.9 pounds per hour, each and 

0.0055 pounds per MMBtu, each without duct firing based on 3-hr average

through the use of good combustion practices and fuel specification. 

(c) Pipeline natural gas only shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

2. The H2SO4 emissions;

(a) The H2SO4 emissions from the combined cycle combustion turbines identified as 

EU-1 and EU-2 shall be limited by restricting the S content of the natural gas to 

0.75 gr S/100 scf on a monthly average basis. 
IPL Eagle Valley Gen. Station Page 14 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(b) Only pipeline natural gas shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

3. The CO emissions;

(a) The CO emissions from the combined cycle combustion turbines shall be 

controlled by catalytic oxidation

(b) The CO emissions shall not exceed 2.0 ppmvd @15% O2, based on a 3-hour

average. 

(c) Pipeline natural gas only shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

4. 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. 

(c) The VOC emissions shall not exceed 1.0 ppmvd @15% O2, without duct burners 

based on 3-hr average. 

(c) Pipeline natural gas only shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

5. The NOx emissions;

(a) The NOx emissions from the CCCTs shall be controlled by a Selective Catalytic 

 Reduction and Dry Low NOx combustors.

(b) The NOx emissions shall not exceed 2.0ppmv @15% O2 with duct burners based 

on a 3-hr average.

(c) Pipeline natural gas only shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

6. The GHGs BACT for the Combined Cycle Combustion Turbines identified as EU1 -

EU2 shall be as follows;

(a) The net heat rate shall not exceed 7,750 Btu/kW-hr (HHV-net) for each CCCT 

block (ISO conditions, without duct firing or inlet evaporative cooling, and not 

accounting for transformer losses).

(b) The total CO2e emissions for combined cycle combustion turbines shall be limited 

to less than 2,649,570 tons of CO2e per twelve (12) consecutive month period 

with compliance determined at the end of each 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. 
IPL Eagle Valley Gen. Station Page 15 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(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) 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 - 3,390 lb/event

NOx - 429 lb/event

(g) The NOX emissions from the combined cycle combustion turbines stacks shall not exceed 

68 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. 

(h) The CO emissions from the combined cycle combustion turbines stacks shall not exceed 

565 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 VOC emissions from the combined cycle combustion turbines stacks shall not 

exceed 146 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 EU3: 

1. The PM, PM10 and PM2.5 emissions from the Auxiliary Boiler, identified as EU-3 shall not 

exceed 0.005 lb/MMBtu and 0.4 lbs/hour, each, based on a 3-hr average period through 

the use of good combustion practices and fuel specification. 

2. The H2SO4 emissions;

(a) The H2SO4 emissions from the auxiliary boiler, identified as EU-3 shall be limited 

by limiting the S content of the natural gas to 0.75 gr S/100 scf on a monthly 

average basis. 

3. The CO emissions from the Auxiliary Boiler (EU-3) operation shall not exceed 0.083 

lb/MMBtu and 6.65 lbs/hr, each, based on a 3 - hour average through the use of 

advanced ultra -low NOx burner. 

4. The VOC emissions from the Auxiliary Boiler, identified as EU-3 shall not exceed 0.0053 

lb/MMBtu and 0.42 lbs/hr, each, based on a 3-hr average period through the use of 

advanced ultra -low NOx burner.

5. The NOx emissions;

(a) The NOx emissions from the Auxiliary Boilers, identified as EU-3 shall be 

controlled by Low NOx Burners with Flue Gas Recirculation. 
IPL Eagle Valley Gen. Station Page 16 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

 (b) The NOx emissions shall be limited to less than 0.011 lb/MMBtu and 0.87 pounds 

per hour, based on a 3-hr average period.

6. The GHGs BACT for the Auxiliary Boilers, identified as EU3 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) The boiler will be equipped with a condensate return system (recovery);

(f) Steam and hot lines will be insulated; and

(g) Boiler designed for 80% thermal efficiency (HHV).

(h) The total CO2e emissions for Auxiliary Boiler shall be limited to less than 40,639 

tons of CO2e per twelve (12) consecutive month period with compliance 

determined at the end of each month.

Dew Point Heater EU-4 

1. The PM, PM10 and PM2.5 emissions from the Dew Point Heater, identified as EU-4 shall be 

limited to less than 0.0072 lb/MMBtu and 0.15 lbs/hr, based on a 3-hr average period 

through the use of good combustion practices and fuel specification. 

2. The H2SO4 emissions;

(a) The H2SO4 emissions from the dew point heater, identified as EU-4 shall be 

limited by limiting the S content of the natural gas to 0.75 gr S/100 scf on a 

monthly average basis. 

3. The CO emissions from the Dew Point Heater (EU-4) operation shall not exceed 0.082

lb/MMBtu and 1.7 lbs/hr, based on a 3 - hour average through the use of good 

combustion and low NOx burners. 

4. The VOC emissions from the Dew Point Heater, identified as EU-3 shall not exceed 

0.0053 lb/MMBtu and 0.11 lbs/hr, based on a 3-hr average period through the use of good 

combustion and low NOx burners. 

5. The NOx emissions;

(a) The NOx emissions from the Dew Point Heater, identified as EU-4 shall be 

controlled by a Low NOx Burner with Flue Gas Recirculation.

(b) The NOx emissions shall be limited to less than 0.032 lb/MMBtu and 0.67 pounds 

per hour, based on a 3-hr average period.

6. The GHGs BACT for the Dew Point Heater, identified as EU-4 shall be as follows; 

(a) The good engineering design and Combustion Practices.

(b) The use of only natural gas. 

 

(c) The total CO2e emissions for Dew Point Heater shall be limited to less than

10,659 tons of CO2e per twelve (12) consecutive month period with compliance 

determined at the end of each month.
IPL Eagle Valley Gen. Station Page 17 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Emergency Diesel Generator, identified as EU5: 

1. The PM, PM10 and PM2.5 emissions from the Emergency Generator, Identified as EU-5, 

shall not exceed 0.15 g/hp-hr, through the use of combustion design control. 

2. The H2SO4 emissions;

(a) The sulfur content of the fuel oil shall not exceed 15ppm. 

3. The CO emissions from the Emergency Generators, Identified as EU-5 shall not exceed 

2.6 g/hp-hr through the use of combustion design controls. 

4. The NOx and VOC emissions from the Emergency Generator shall be limited to less than 

4.80 g/bhp-hr for NMHC + NOx through the use of Combustion Design Controls. 

5. The GHGs BACT for the Emergency Diesel Generator, Identified as EU5 shall be as follows: 

(a) The use of a good engineering design; 

(b) The total CO2e emissions for Emergency Diesel Generator shall be limited to less 

than 605 tons of CO2e per twelve (12) consecutive month period with compliance 

determined at the end of each month.

Emergency Fire Pump Engine, identified as EU6: 

1. The PM, PM10 and PM2.5 emissions from the Emergency Fire Pump Engine shall not 

exceed 0.15 g/hp-hr through the use of combustion design control. 

2. The H2SO4 emissions;

(a) The sulfur content of the fuel oil shall not exceed 15ppm. 

3. The CO emissions from the Emergency Fire pump Engine shall not exceed 2.6 g/hp-hr 

through the use of combustion design controls. 

4. The NOx and VOC emissions from the Emergency Fire Pump Engine shall not exceed 

3.0 g/bhp-hr for NMHC + NOx through the use of Combustion Design Controls. 

5. The GHGs BACT for the Emergency Diesel Generator, Identified as EU-6 shall be as follows: 

(a) The use of a good engineering design; 

(b) The total CO2e emissions for Firewater Pump Engine shall be limited to less than

157.50 tons of CO2e per twelve (12) consecutive month period with compliance 

determined at the end of each month.

Cooling Tower U-7: 

1. The PM, PM10 and PM2.5 emissions;

(a) The PM, PM10 and PM2.5 emissions from the Cooling Tower, identified as U-7 

shall be controlled by High efficiency drift eliminators designed with a drift loss 

rate of less than 0.0005% and maximum total dissolved solids (TDS) shall be less 

than 5000 mg/L. 

(b) The PM, PM10 and PM2.5 emissions from the Cooling Tower shall be less than 

2.4, 1.5 and 0.005 pounds per hour, respectively.
IPL Eagle Valley Gen. Station Page 18 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Electric Circuit Breaker (F-1):

1. The use of totally enclosed pressure system with a design leak rate of 0.5% by weight and 

a density alarm for leak detection.

2. The total CO2e emissions for circuit breakers shall be limited to less than 59.80 tons of 

CO2e per twelve (12) consecutive month period with compliance determined at the end of 

each month.

The GHGs BACT for Fugitive Equipment Leaks shall be as follows; 

1. The BACT for fugitive GHG emissions shall be use of Auditory, Visual, and Olfactory 

(AVO) Monitoring program for methane leaks.

Three (3) Turbine Lube Oil Demister Vents: 

1. The PM, PM10 and PM2.5 emissions from the Turbine Lube Oil Demister Vents shall be the 

use of good design and operating practices. 

Hazardous Air Pollutants (HAPs) Minor Limits

The source has the uncontrolled potential to emit greater than ten (10) tons per year for a single 

HAP (formaldehyde) and less than twenty-five (25) tons per year for a combination of HAPs, 

therefore: 

 

The emission units shall be limited as follows:

(a) The combined cycle combustion turbines identified as EU-1 and EU-2, formaldehyde

emissions shall be limited to less than nine (9.0) tons per twelve (12) consecutive month 

period, with compliance determined at the end of each month. 

(b) The formaldehyde emissions from the CCCTs shall be calculated by the following 

equation:

L (tons/month)= (7.1 x 10-4 x Qu + C x Qc)/2000 lbs/ton

Where: 

L = 9 tons of (formaldehyde) per 12 month rolling period.

 7.1 x 10-4 is the uncontrolled emission factor for formaldehyde (lbs/MMBtu)

Qu = 12- month rolling total heat input to the CT units (MMBtu) when the oxidation catalyst is 

not fully operational during startup and shutdown conditions

Qc = 12- month rolling total heat input to the CT units (MMBtu) when the oxidation catalyst is 

fully operational (includes heat input to duct burners). 

C = is the controlled emission factor for formaldehyde (lbs/MMBtu), which would be based on 

stack test results of the CCCTs. Prior to stack testing the factor will be conservatively 

assumed to equal 60% of the uncontrolled emission factor.

Compliance with the above limits and requirements and combined with the potential to emit HAP 

emissions from all other emission units will limit the potential to emit from this source to less than 

ten (10) tons per year of formaldehyde and make the source an area source of HAPs. 

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
IPL Eagle Valley Gen. Station Page 19 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

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 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 EU-1 and EU-2, 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) and O2 for each of the stacks, 

S-1 and S-2 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.

326 IAC 6-2-2 (Particulate Emission Limitations for Sources of Indirect Heating)

Pursuant to 326 IAC 6-2-2 (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 boiler, identified as EU-3 and the duct burners shall not exceed 0.22 pounds per million 

Btu heat input (lb/MMBtu), each. This limitation was calculated using the following equation:

 

Pt = 0.87 

 Q0.16

Where:

 

Q = total source heat input capacity (MMBtu/hr). 

For these units, Q = 2542 + 2542 + 79.3 = 5163.3 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 this auxiliary 

boiler.
IPL Eagle Valley Gen. Station Page 20 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

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 generator and emergency fire pump engine 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 

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 EU-1 and EU-2 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) This rule requires that new facilities (as of January 1, 1980), which have potential VOC 

emissions of greater than 25 tons per year, located anywhere in the state, which are not 

otherwise regulated by other provisions of 326 IAC 8, shall reduce VOC emissions using 

Best Available Control Technology (BACT). The two (2) combustion turbines, identified as 

EU-1 and EU-2 are subject to the requirements of 326 IAC 2-2-3 (PSD BACT), therefore, 

PSD BACT requirements will satisfy for the requirements of 326 IAC 8-1-6 at this source.

(b) This rule requires that new facilities (as of January 1, 1980), which have potential VOC 

emissions of 25 tons or more per year, located anywhere in the state, which are not 

otherwise regulated by other provisions of 326 IAC 8, shall reduce VOC emissions using 

Best Available Control Technology (BACT). The auxiliary boiler, dew point heater, 

emergency fire pump and emergency generator each have potential VOC emissions of 

less than 25 tons per year. Therefore, 326 IAC 8-1-6 does not apply to these facilities. 

 

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. IPL 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 of modeling 

were below the NAAQS standards with the exception of the 1-hour NO2 NAAQS. Additional air 

quality modeling was not required for the 24-hour PM10 and PM2.5 and the annual PM2.5 and NO2

standards. The 1-hour NO2 NAAQS modeling results shown in Table 5 of Appendix C had a 

violation of the 1-hour NO2 standard of 100 parts per billion (ppb) or 188.7 ug/m3

. The highest 8thhigh 1-hour NO2 concentration averaged across five years was 419.7 ug/m3 resulting in a total 1-

hour NO2 concentration of 487.6 ug/m3 with a background concentration of 67.9 ug/m3

. The 

highest 8th-high maximum daily 1-hour NO2 modeled concentration of 419.7 in Table 5 of 

Appendix C was adjusted from an actual modeled concentration of 524.6 ug/m3 by using the 

NO2/NOx default ambient ratio of 0.8 (524.6 X 0.8 = 419.7) for a 1-hour concentration. The annual 
IPL Eagle Valley Gen. Station Page 21 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

NO2 modeled concentration shown in Table 5 of Appendix C has been adjusted by the 0.75 

default ambient ratio for NOx to NO2 conversion for an annual concentration.

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)*.

(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

No impact from the economic growth is expected from the IPL Eagle Valley PSD permit major 

source modification and physical changes at the IPL Eagle Valley facility. The existing 

Martinsville, Indiana and Morgan County community will be able to adequately handle potential 

commercial growth associated with this future plant modification. An additional employment of 30 

to 40 people is expected as a result of this facility modification.

Soils and Vegetation Analysis

A soils and vegetation analysis was performed by ERM to assess the impact of the criteria 

pollutant air emissions. Soil types in Morgan County include silt loam, clay loam, and sandy loam 

soils. Crops in Morgan County consist mainly of corn, soybeans, and wheat. Trees in Morgan 

County are mostly hardwoods such as maples and oaks. The results of the soils and vegetation 

analysis show the modeled impacts are well below the thresholds necessary to have an adverse 

impact on the surrounding soils and vegetation. The results of the soils and vegetation analysis 

are listed in the IPL Eagle Valley PSD Permit Application, section 8, page 26.

Federal Endangered Species Analysis

Federal and State endangered or threatened species are listed by the Indiana Department of 

Natural Resources; Division of Nature Preserves for Morgan County, Indiana and includes eight 

species of mussels, six species of birds, three species of reptiles, two species of bats, and one 

specie each of fish and amphibian. The mussels and birds listed are commonly found along 

major rivers and lakes while the bats are found near caves. The Martinsville Eagle Valley facility 

is not expected to have any additional adverse effects on the habitats of the endangered species 

other than that which has already occurred from the industrial and residential activities in the area. 

The endangered species of bats maintains habitats in caves and mines none of which are near 

the Martinsville facility. Federal and State endangered or threatened plants are listed by the 

Indiana Department of Natural Resources, Division of Nature Preserves and include no 

threatened or endangered species of plants in the Morgan County area of central Indiana.

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.
IPL Eagle Valley Gen. Station Page 22 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

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 

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 Requirements applicable to this modification are as follows:
IPL Eagle Valley Gen. Station Page 23 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Testing Requirements

(a) Testing Requirements

Note: Compliance with the NOx emission limits for the combustion turbines are demonstrated by using the NOx CEMs 

data.

Operations of the high efficiency drift eliminators at all times and a weekly test of the blow-down 

water quality will ensure compliance with PM/PM10/PM2.5 limit for the insignificant cooling towers. 

No stack testing are required for the emergency diesel generator and the emergency fire pump 

engine because these units are emergency units and/or insignificant activities and compliance 

with the BACT limits are demonstrated through keeping records of the fuel used and purchase of 

NSPS, Subpart IIII certified engine. 

Stack testing of the insignificant dew point heater for PM/PM10/PM2.5, VOC, CO and NOx 

emission are not justified because of its small size and low emissions rate heater. 

Emission units Control device When to test Pollutants Frequency 

of testing

Limit or 

Requirement

Combined Cycle 

Combustion 

Turbine Units 

EU-1 and EU-2 

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

Combined Cycle 

Combustion 

Turbine Units 

EU-1 and EU-2 

Oxidation 

Catalyst with Duct

Burner 60 days / no 

later than 180 

days

CO 5 year 326 IAC 2-2-3 

Combined Cycle 

Combustion 

Turbine Units 

EU-1 and EU-2 

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

Combined Cycle 

Combustion 

Turbine Units 

EU-1 and EU-2

No control

60 days / no 

later than 180 

days

CO2 

(Heat Rate 

Performance)

5 year

326 IAC 2-2-3 

Combined Cycle 

Combustion 

Turbine Units 

EU-1 and EU-2

Oxidation 

Catalyst

60 days / no 

later than 180 

days

HAPs

(Formaldehyde) 5 years

HAPs Minor 

Limit

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

CO 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

Thermal 

Efficiency

one time 

testing

326 IAC -2-2-3 
IPL Eagle Valley Gen. Station Page 24 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(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 

(c) The compliance monitoring requirements applicable to this source are as follows: 

Control Parameter Frequency Value Excursions and 

Exceedances

Requirement

EU-1 and EU-2 (SCR 

with DLN) NOx CEMS Continuous N/A

Continuous emission 

monitoring system 

measurement data.

326 IAC 2-2-3 

Proposed Changes

The changes listed below have been made to Part 70 Operating Permit No. T109-26292-00004. 

Deleted language appears as strikethroughs and new language appears in bold: 

Change 1: The new Combined Cycle Combustion Turbine Generation Facility has been added to 

Section A.2 - Emission Units and Pollution Control Equipment Summary and Section A.3 - 

Specifically Regulated Insignificant Activities of the permit. 

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

[326 IAC 2-7-5(15)]

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

(a) Two (2) no. 2 fuel oil fired boilers, identified as Unit 1 and Unit 2, constructed in 1949 and 

1950, respectively, each with a design heat input capacity of 524 million Btu per hour 

(MMBtu/hr), both exhausting to stack 1-1.

(b) One (1) tangentially-fired wet-bottom coal boiler, identified as Unit 3, constructed in 1951, 

with a design heat input capacity of 524 million Btu per hour (MMBtu/hr), with an 

electrostatic precipitator (ESP) and flue gas conditioning system for control of particulate 

matter, exhausting to stack 2-1. Unit 3 will combust no. 2 fuel oil during startup, 

shutdown, and stabilization periods. Used oil generated onsite and used oil contaminated 

materials generated onsite may be combusted in Unit 3 as supplemental fuel for energy 

recovery. Stack 2-1 has continuous emission monitoring systems (CEMS) for NOX and 

SO2 and a continuous opacity monitor (COM).

(c) One (1) tangentially-fired dry-bottom coal fired boiler, identified as Unit 4, constructed in 

1953, with a design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an 

electrostatic precipitator (ESP) and flue gas conditioning system for control of particulate 

matter, exhausting to stack 2-1. Unit 4 is equipped with separated overfire air (SOFA) 

and low NOX burners (LNB) for control of NOX emissions, which were voluntarily installed 

and are not required to operate. Unit 4 will combust no. 2 fuel oil during startup, 

shutdown, and stabilization periods. Stack 2-1 has continuous emission monitoring 

systems (CEMS) for NOX and SO2 and a continuous opacity monitor (COM).
IPL Eagle Valley Gen. Station Page 25 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(d) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 5, constructed in 1953, 

with a design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an 

electrostatic precipitator (ESP) and flue gas conditioning system for control of particulate 

matter, exhausting to stack 3-1. Unit 5 is equipped with SOFA and LNB for control of 

NOX emissions, which were voluntarily installed and are not required to operate. Unit 5 

will combust no. 2 fuel oil during startup, shutdown, and stabilization periods. Stack 3-1 

has continuous emission monitoring systems (CEMS) for NOX and SO2 and a continuous 

opacity monitor (COM).

(e) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 6, constructed in 1956, 

with a design heat input capacity of 1017 million Btu per hour (MMBtu/hr), with an 

electrostatic precipitator (ESP) for control of particulate matter, exhausting to stack 3-1. 

Unit 6 is equipped with Closed-coupled Overfire Air (COFA) for control of NOX emissions, 

which was voluntarily installed and is not required to operate. Unit 6 will combust no. 2 

fuel oil during startup, shutdown, and stabilization periods. Used oil generated onsite 

may be combusted in Unit 6 as supplemental fuel for energy recovery. Unit 6 has had 

low-NOX burners installed. Stack 3-1 has continuous emission monitoring systems 

(CEMS) for NOX and SO2 and a continuous opacity monitor (COM).

(f) One (1) distillate oil fired generator, identified as Unit PR-10, constructed in 1967, with a 

design heat input capacity of 28.4 million Btu per hour (MMBtu/hr), exhausting to stack 

PR10-1.

(g) Coal transfer facilities, with a maximum throughput of 800 tons per hour, with a dust 

suppression system. 

(h) Rail car unloading, coal pile unloading, and coal storage, with a maximum capacity of 800 

tons per hour.

(i) Coal crushers, identified as 1A and 1B, with a maximum combined capacity of 800 tons 

per hour, each using an enclosure for dust control.

(j) One (1) pneumatic fly ash storage silo and handling system, to be constructed in 2009, 

with a maximum storage capacity of 300 tons and a maximum throughput capacity of 

10.0 tons of fly ash per hour. The particulate emissions from the silo loadout to trucks are 

uncontrolled and exhaust to the atmosphere. The particulate emissions from the silo 

storage will be controlled by a baghouse, identified as Silo Baghouse, and exhausting to a 

stack, identified as Silo Stack. The particulate emissions from fly ash conveyance are 

controlled by a dust collector, identified as Fly Ash Collector, and exhausting to a stack, 

identified as Vacuum Blower Stack.

Note: The pneumatic fly ash storage silo and handling system was never constructed. 

The New Combined Cycle Combustion Turbine Generation Facility Emission Units:

(k) Two (2) natural gas fired combustion turbine units each with a natural gas fired 

duct burner identified as EU-1 and EU-2, permitted in 2013, each with a total rated 

heat input capacity of 2,542 MMBtu/hr; with NOx emissions controlled by low 

combustion burner design and Selective Catalytic Reduction (SCR), and each with 

an oxidation catalyst system to reduce emissions of CO and VOCs including 

formaldehyde, and exhausting to stacks S-1 and S-2. Each stack has continuous 

emissions monitors (CEMS) for NOx. 

 

*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.
IPL Eagle Valley Gen. Station Page 26 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(l) One (1) natural gas fired Auxiliary Boiler, identified as emission unit EU-3,

permitted in 2013, with a rated heat input capacity of 79.3 MMBtu/hr, equipped with 

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

exhausting to stack S-3. 

(m) One (1) natural gas fired Dew Point Heater, identified as emission unit EU-4, 

permitted in 2013, with a rated heat input capacity of 20.8 MMBtu/hr exhausting to 

stack S-4.

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

[326 IAC 2-7-5(15)]

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

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

(a) Coal bunker and coal scale exhausts. [326 IAC 6-3] [326 IAC 5]

Before the startup of the Combined Cycle Combustion Turbine Generation Facility, the 

Coal bunker and coal scale exhausts shall be permanently shut down and 

decommissioned.

(b) Other activities or categories not previously identified with potential, uncontrolled 

emissions equal to or less than thresholds require listing only: Pb 0.6 ton per year or 3.29 

pounds per day, SO2 5 pounds per hour or 25 pounds per day, NOX 5 pounds per hour or 

25 pounds per day, CO 25 pounds per day, PM10 5 pounds per hour or 25 pounds per 

day, VOC 3 pounds per hour or 15 pounds per day:

(1) Wet process ash handling, with hydroveyors conveying ash to storage ponds. 

[326 IAC 6-4]

 Before the startup of the Combined Cycle Combustion Turbine Generation 

 Facility, the Wet process ash handling shall be permanently shut 

 down and decommissioned.

(2) Ponded ash handling/removal operations. [326 IAC 6-4]

(3) Truck traffic on paved road to and from the Silo. [326 IAC 6-4]

The New Combined Cycle Combustion Turbine Generation Facility Insignificant Emission 

Units: 

(c) One (1) distillate oil fired Emergency Generator, identified as emission unit EU-5, 

permitted in 2013, with a rated capacity of 1,826 HP and exhausting through stack 

S-5. [Under 40 CFR 60, Subpart IIII, the Emergency Generator is considered new 

affected sources.][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Generator

is considered new affected sources.]

(d) One (1) distillate oil fired Emergency Fire Pump, identified as emission unit EU-6, 

permitted in 2013, with a rated capacity of 500 HP and exhausting through stack S6. [Under 40 CFR 60, Subpart IIII, the Emergency Fire Pump is considered new 

affected sources.][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Fire Pump

is considered new affected sources.]

(e) One (1) evaporative cooling tower, identified as emission unit U-7, rated with a 

circulation rate of 192,000 gpm to provide non-contact cooling water to the steam 

turbine condenser, permitted in 2013, and equipped with high efficiency drift 

eliminators. 
IPL Eagle Valley Gen. Station Page 27 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(f) Electrical Circuit Breakers containing sulfur hexafluoride (SF6) identified as 

emissions unit F-1, permitted in 2013, with fugitive emissions controlled by full 

enclosure.

(g) Fugitive equipment leaks from the natural gas supply lines, identified as F-2 

controlled by a Leak Detection and Repair (LDAR) program.

(h) Three (3) Turbine Lube Demister Vents, permitted in 2013. 

Change 2: A Condition has been added in Section D.1 that will discontinue the operation of the 

emission units in Sections D.1, D.2, D.3, D.4, D.5 and the Wet process ash handling in 

Section D.6 before the startup of the Combined Cycle Combustion Turbine Generation 

Facility. 

SECTION D.1 FACILITY OPERATION CONDITIONS

Facility Description [326 IAC 2-7-5(15)]

(a) Two (2) no. 2 fuel oil-fired boilers, identified as Unit 1 and Unit 2, constructed in 1949 and 1950, 

respectively, each with a design heat input capacity of 524 million Btu per hour (MMBtu/hr), both 

exhausting to stack 1-1.

(The information describing the process contained in this facility description box is descriptive information 

and does not constitute enforceable conditions.)

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

D.1.0 Air Quality Analysis Requirements [326 IAC 2-2-4] 

Pursuant to the air quality impact assessment requirements of 326 IAC 2-2-4, the Permittee 

shall permanently discontinue the operation of the emission units in Section D.1 before 

commercial operation of the Combined Cycle Combustion Turbine Generation Facility. The 

requirements of this section will no longer be applicable after the units are permanently 

shutdown. 

D.1.1 Particulate Emission Limitations for Sources of Indirect Heating [326 IAC 6-2-2]

(a) Pursuant to 326 IAC 6-2-2(a) (Particulate Emissions Limitations for Sources of Indirect 

Heating: Emission limitations for facilities specified in 326 IAC 6-2-1(b)), the PM 

emissions from Units 1, 2, 3, 4, 5, and 6 shall not exceed 0.23 pound per million Btu heat 

input (lb/MMBtu). This limitation was calculated using the following equation:

Pt = 0.87 Where Q = total source capacity (MMBtu/hr) on June 8, 1972

 Q0.16 = 4,071 MMBtu/hr

(b) Pursuant to 326 IAC 6-2-2(b), the PM emissions from Units 1 and 2 shall not exceed 0.10 

pound per million Btu heat input (lb/MMBtu), which is less than 0.23 lb/MMBtu, as 

requested by the source in a letter dated August 26, 2008.

D.1.2 Temporary Alternative Opacity Limitations [326 IAC 5-1-3]

(a) Pursuant to 326 IAC 5-1-3 (Temporary Alternative Opacity Limitations), the following 

applies to Eagle Valley Units 1 and 2:
IPL Eagle Valley Gen. Station Page 28 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(1) When starting a fire in a boiler, or shutting down a boiler, opacity may exceed the 

forty percent (40%) 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 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. [326 IAC 5-1-3(a)]

(2) When removing ashes from the fuel bed or furnace in a boiler or blowing tubes, 

opacity may exceed the forty percent (40%) 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 and opacity in excess of the applicable limit 

shall not continue for more than one (1) six (6)-minute averaging period in any 

sixty (60) minute period. The averaging periods in excess of the limit set in 

326 IAC 5-1-2 shall not be permitted for more than three (3) six (6)-minute 

averaging periods in a twelve (12) hour period. [326 IAC 5-1-3(b)]

(b) If this facility cannot meet the opacity limitations in (a)(1) and (a)(2) of this condition, 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.1.3 Sulfur Dioxide (SO2) [326 IAC 7-4-11]

Pursuant to 326 IAC 7-4-11 (Morgan County Sulfur Dioxide Emission Limitations), the SO2

emissions from Unit 1 and Unit 2 shall not exceed 0.37 pounds per million Btu (lbs/MMBtu) each. 

Pursuant to 326 IAC 7-2-1, compliance shall be demonstrated using a calendar month average.

Compliance Determination Requirements

D.1.4 Testing Requirements [326 IAC 2-7-6(1),(6)] [326 IAC 2-1.1-11] [326 IAC 3-6]

Compliance with the particulate limitations in Condition D.1.1(b) and with the Opacity limits in 

Section C - Opacity and Temporary Alternative Opacity Limitations for startup shall be determined 

as follows:

(a) Compliance with the particulate limitations shall be determined by a performance stack 

test conducted utilizing methods as approved by the Commissioner. PM testing with both 

units operating and exhausting to the common stack is permitted. [326 IAC 3-6]

(b) Opacity testing shall be performed in conjunction with the particulate emissions testing in 

accordance with 40 CFR 60, Appendix A, Method 9. The Method 9 opacity testing (VE 

readings) shall be recorded for the full duration of the sampling time for each sampling 

repetition that occurs during daylight hours. [326 IAC 3-5-1(c)(2)(A)(ii)] 

[326 IAC 5-1-4(a)(1)]

(c) To demonstrate compliance with the Temporary Alternative Opacity Limitation for boiler 

startups, opacity testing shall be performed in accordance with 40 CFR 60, Appendix A, 

Method 9, during daylight hours of the startup from light-off to completion of start-up. 

[326 IAC 3-5-1(c)(2)(A)(ii)] [326 IAC 5-1-4(a)(1)]

(d) The PM stack testing and Method 9 opacity testing shall be repeated as follows:

(1) By December 31 of every second calendar year following this valid compliance 

demonstration; or

(2) If a unit is not operated at least 1,000 hours in the 2 years since the previous

stack test, then testing shall be repeated at least once every 1,000 hours of 

operation for that unit, or five (5) calendar years from the date of the last valid 

compliance demonstration, whichever occurs first.
IPL Eagle Valley Gen. Station Page 29 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

For the purpose of this permit, “calendar year” means the twelve (12) month period from 

January 1 to December 31 inclusive.

(e) Testing shall be conducted in accordance with Section C - Performance Testing.

D.1.5 Sulfur Dioxide Emissions and Sulfur Content [326 IAC 7-2] [326 IAC 7-4-11]

Compliance shall be determined utilizing one of the following options:

(a) Pursuant to 326 IAC 3-7-4, 326 IAC 7-2, and 326 IAC 7-4-11, the Permittee shall 

demonstrate that the fuel oil sulfur content does not exceed the equivalent of 0.37 pounds 

per MMBtu each, using a calendar month average, by:

(1) Providing vendor analysis of fuel delivered, accompanied by a vendor 

certification; or

(2) Providing analysis of fuel oil samples collected and analyzed in accordance with 

326 IAC 3-7-4(a).

(A) Oil samples shall be collected from the tanker truck load during or prior to 

transferring fuel to the storage tank; or

(B) Oil samples shall be collected from the storage tank immediately after 

each addition of fuel to the tank.

(b) Upon written notification to IDEM by a facility owner or operator, continuous emission 

monitoring data collected and reported pursuant to 326 IAC 3-5 may be used as the 

means for determining compliance with the emission limitations in 326 IAC 7. Upon such 

notification, the other requirements of 326 IAC 7-2 shall not apply. [326 IAC 7-2-1(g)]

D.1.6 RESERVED Nitrogen Oxides Monitoring Requirement [326 IAC 10-4-4(b)(1)] [326 IAC 10-4-12(b) 

and (c)] [40 CFR 75]

The Permittee has met the monitoring requirements of 326 IAC 10-4-12(b)(1) through (b)(3) that 

are applicable to their monitoring systems for the NOX budget units. The Permittee shall record, 

report, and quality assure the data from the monitoring systems in accordance with 

326 IAC 10-4-12 and 40 CFR 75.

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

D.1.7 Visible Emissions Notations [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)]

(a) Visible emission notations of the fuel oil-fired boiler exhaust shall be performed once per 

day during normal daylight operations when one or both of Units 1 and 2 are in operation

and burning fuel oil. A trained employee shall record whether emissions are normal or 

abnormal.

(b) For processes operated continuously, “normal” means those conditions prevailing, or 

expected to prevail, eighty percent (80%) of the time the process is in operation, not 

counting startup or shut down time.

(c) In the case of batch or discontinuous operations, readings shall be taken during that part 

of the operation that would normally be expected to cause the greatest emissions. 

(d) A trained employee is an employee who has worked at the plant at least one (1) month 

and has been trained in the appearance and characteristics of normal visible emissions 

for that specific process.
IPL Eagle Valley Gen. Station Page 30 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(e) If abnormal emissions are observed at any boiler exhaust, the Permittee shall take 

reasonable response steps in accordance with Section C - Response to Excursions or 

Exceedances. Observation of abnormal emissions that do not violate an applicable 

opacity limit is not a deviation from this permit. Failure to take response steps in 

accordance with Section C - Response to Excursions or Exceedances, 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.1.8 Record Keeping Requirements [326 IAC 2-7-5(3)]

(a) To document compliance with the applicable opacity limits and Conditions D.1.1 and 

D.1.2, the Permittee shall maintain records in accordance with (1) and (2) below. 

Records shall be complete and sufficient to establish compliance with the opacity and 

particulate limits established in Section C - Opacity and Conditions D.1.1 and D.1.2.

(1) Data and results from the most recent stack test and accompanying Method 9 

visible emissions evaluation results for Units 1 and 2.

(2) Results of the visible emission notations of the stack 1-1 exhaust.

(b) To document compliance with Conditions D.1.3 and D.1.5, the Permittee shall maintain 

records in accordance with (1) through (5) below. Records maintained shall be complete 

and sufficient to establish compliance with the SO2 limit as required in Conditions D.1.3 

and D.1.5.

(1) Calendar dates covered in the compliance determination period.

(2) Monthly weighted average sulfur content.

(3) Fuel heat content.

(4) Fuel consumption.

(5) Monthly weighted average sulfur dioxide emission rate in pounds per million Btus 

(lb/MMBtu).

(c) To document compliance with Condition D.1.7, the Permittee shall maintain daily records 

of the visible emission notations of the Boiler stack exhaust. The Permittee shall include 

in its daily record when a visible emission notation is not taken and the reason for the lack 

of a visible emission notation, (e.g. the process did not operate that day).

(d) All records shall be maintained in accordance with Section C - General Record Keeping 

Requirements, of this permit.

D.1.9 Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 7-2(c)]

A quarterly report of opacity exceedances and a quarterly summary of the information to 

document compliance with Condition D.1.3 shall be submitted to the address listed in Section C - 

General Reporting Requirements of this permit, using the reporting forms located at the end of 

this permit, or their equivalent, within thirty (30) days after the end of the quarter being reported. 

The report submitted by the Permittee does require the certification by the “responsible official” as 

defined by 326 IAC 2-7-1(34).
IPL Eagle Valley Gen. Station Page 31 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION D.2 FACILITY OPERATION CONDITIONS

Facility Description [326 IAC 2-7-5(15)]

(b) One (1) tangentially-fired wet-bottom coal boiler, identified as Unit 3, constructed in 1951, with a 

design heat input capacity of 524 million Btu per hour (MMBtu/hr), with an electrostatic precipitator 

(ESP) and flue gas conditioning system for control of particulate matter, exhausting to stack 2-1. 

Unit 3 will combust no. 2 fuel oil during startup, shutdown, and stabilization periods. Used oil 

generated onsite and used oil contaminated materials generated onsite may be combusted in Unit 

3 as supplemental fuel for energy recovery. Stack 2-1 has continuous emission monitoring 

systems (CEMS) for NOX and SO2 and a continuous opacity monitor (COM).

(c) One (1) tangentially-fired dry-bottom coal fired boiler, identified as Unit 4, constructed in 1953, with 

a design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) and flue gas conditioning system for control of particulate matter, exhausting to 

stack 2-1. Unit 4 is equipped with separated overfire air (SOFA) and low NOX burners (LNB) for 

control of NOX emissions, which were voluntarily installed and are not required to operate. Unit 4 

will combust no. 2 fuel oil during startup, shutdown, and stabilization periods. Stack 2-1 has 

continuous emission monitoring systems (CEMS) for NOX and SO2 and a continuous opacity 

monitor (COM).

(d) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 5, constructed in 1953, with a 

design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an electrostatic precipitator 

(ESP) and flue gas conditioning system for control of particulate matter, exhausting to stack 3-1. 

Unit 5 is equipped with SOFA and LNB to control NOX emissions. Unit 5 will combust no. 2 fuel oil 

during startup, shutdown, and stabilization periods. Stack 3-1 has continuous emission monitoring 

systems (CEMS) for NOX and SO2 and a continuous opacity monitor (COM).

(e) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 6, constructed in 1956, with a 

design heat input capacity of 1017 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) for control of particulate matter, exhausting to stack 3-1. Unit 6 is equipped with 

Closed-coupled Overfire Air (COFA) to control NOX emissions. Unit 6 will combust no. 2 fuel oil 

during startup, shutdown, and stabilization periods. Used oil generated onsite may be combusted 

in Unit 6 as supplemental fuel for energy recovery. Unit 6 has had low-NOX burners installed. 

Stack 3-1 has continuous emission monitoring systems (CEMS) for NOX and SO2 and a 

continuous opacity monitor (COM).

(The information describing the process contained in this facility description box is descriptive information 

and does not constitute enforceable conditions.)

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

D.2.0 Air Quality Analysis Requirements [326 IAC 2-2-4] 

Pursuant to the air quality impact assessment requirements of 326 IAC 2-2-4, the Permittee 

shall permanently discontinue the operation of the emission units in Section D.2 before 

commercial operation of the Combined Cycle Combustion Turbine Generation Facility. The 

requirements of this section will no longer be applicable after the units are permanently 

shutdown. 

D.2.1 Particulate Emission Limitations for Sources of Indirect Heating [326 IAC 6-2-2]

(a) Pursuant to 326 IAC 6-2-2 (Particulate Emissions for Sources of Indirect Heating: 

Emission limitations for facilities specified in 326 IAC 6-2-1(b)), the PM emissions from 

Units 1, 2, 3, 4, 5, and 6 shall not exceed 0.23 pound per million Btu heat input 

(lb/MMBtu). This limitation was calculated using the following equation:

Pt = 0.87 Where Q = total source capacity (MMBtu/hr) on June 8, 1972

 Q0.16 = 4,071 MMBtu/hr
IPL Eagle Valley Gen. Station Page 32 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(b) Pursuant to 326 IAC 6-2-2(b), the PM emissions from Units 3, 4, 5 and 6 shall not exceed 

0.27 pound per million Btu heat input (lb/MMBtu), as requested by Indianapolis Power and 

Light Company in a letter dated April 12, 1988.

D.2.2 Temporary Alternative Opacity Limitations [326 IAC 5-1-3]

(a) Pursuant to 326 IAC 5-1-3 (Temporary Alternative Opacity Limitations), the following 

applies:

(1) When building a new fire in a boiler, opacity may exceed the 40% opacity 

limitation established in 326 IAC 5-1-2 for a period not to exceed two and one-half 

(2.5) hours (twenty-five (25) six (6)-minute averaging periods) or until the flue gas 

temperature reaches two hundred fifty (250) degrees Fahrenheit, whichever 

occurs first. [326 IAC 5-1-3(e)]

(2) When shutting down a boiler, opacity may exceed the 40% opacity limitation 

established in 326 IAC 5-1-2 for a period not to exceed one (1) hour (ten (10)

six (6)-minute averaging periods). [326 IAC 5-1-3(e)]

(3) Operation of the electrostatic precipitator is not required during these times.

(4) During the above startup and shutdown periods all reasonable efforts shall be 

made to minimize the number and magnitude of the exceedances.

(b) When removing ashes from the fuel bed or furnace in a boiler or blowing tubes, opacity 

may exceed the applicable limit established in 326 IAC 5-1-2. However, opacity levels 

shall not exceed sixty percent (60%) for any six (6)-minute averaging period and opacity 

in excess of the applicable limit shall not continue for more than one (1) six (6)-minute 

averaging period in any sixty (60) minute period. The averaging periods in excess of the 

limit set in 326 IAC 5-1-2 shall not be permitted for more than three (3) six (6)-minute 

averaging periods in a twelve (12) hour period. [326 IAC 5-1-3(b)]

D.2.3 Sulfur Dioxide (SO2) [326 IAC 7-4-11]

Pursuant to 326 IAC 7-4-11 (Sulfur Dioxide Emission Limitations for Morgan County):

(a) SO2 emissions from Unit 3 shall not exceed 0.37 pounds per million Btu (lbs/MMBtu), 

compliance with which shall be determined as specified in 326 IAC 7-2-1(c), using a thirty 

(30) day rolling weighted average. [326 IAC 7-4-11(2)]

(b) SO2 emissions from Units 4, 5, and 6 shall not exceed 3.04 pounds per million Btu 

(lbs/MMBtu) each, compliance with which shall be determined as specified in 

326 IAC 7-2-1(c), using a thirty (30) day rolling weighted average. [326 IAC 7-4-11(2)]

(c) As an exception to the emission limitations specified in (a) and (b), pursuant to 326 IAC 7-4-11(7), 

at any time in which IPL burns coal on Unit 3, the thirty (30) day rolling weighted average for sulfur 

dioxide emissions from Units 3, 4, 5, and 6 shall be limited to two and fifty-seven hundredths (2.57) 

pounds per million Btu each. [326 IAC 7-4-11(3)] 

Compliance Determination Requirements

D.2.4 Testing Requirements [326 IAC 2-7-6(1),(6)] [326 IAC 2-1.1-11]

In order to determine compliance with the PM limitation in Condition D.2.1(b) for each units (Units 

3, 4, 5 and 6), the Permittee shall conduct before December 31, 2009 a performance stack test 

utilizing methods as approved by the Commissioner. This testing shall be repeated by December 

31 of every second calendar year following this valid compliance demonstration. For the purpose 

of this permit, “calendar year” means the twelve (12) month period from January 1 to December 

31 inclusive. Testing shall be conducted in accordance with Section C - Performance Testing.
IPL Eagle Valley Gen. Station Page 33 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

D.2.5 Operation of Electrostatic Precipitator [326 IAC 2-7-6(6)]

Except as otherwise provided by statute or rule or in this permit, the electrostatic precipitators 

(ESPs) shall be operated at all times that the boilers vented to the ESPs are in operation. Each 

flue gas conditioning (FGC) system on Unit 3, Unit 4 and Unit 5 shall be used with the 

corresponding ESP as necessary to maintain compliance with this permit.

D.2.6 Continuous Emissions Monitoring [326 IAC 3-5]

(a) Pursuant to 326 IAC 3-5 (Continuous Monitoring of Emissions), continuous emission 

monitoring systems for Units 3, 4, 5 and 6 shall be calibrated, maintained, and operated 

for measuring opacity, SO2, and either CO2 or O2, which meet the performance 

specifications of 326 IAC 3-5-2.

(b) All continuous emission monitoring systems are subject to monitor system certification 

requirements pursuant to 326 IAC 3-5-3.

(c) Pursuant to 326 IAC 3-5-4, if revisions are made to the continuous monitoring standard 

operating procedures (SOP), the Permittee shall submit updates to the department 

biennially.

(d) Nothing in this permit shall excuse the Permittee from complying with the requirements to 

operate a continuous emission monitoring system pursuant to 326 IAC 3-5, 326 IAC 10-4, 

or 40 CFR 75.

(e) Pursuant to 326 IAC 3-7-5(a), the Permittee shall develop a standard operating procedure 

(SOP) to be followed for sampling, handling, analysis, quality control, quality assurance, 

and data reporting of the information collected pursuant to 326 IAC 3-7-2 through 

326 IAC 3-7-4. In addition, any revision to the SOP shall be submitted to IDEM, OAQ.

D.2.7 Sulfur Dioxide Emissions and Sulfur Content [326 IAC 7-2] [326 IAC 7-4-11]

(a) Pursuant to 326 IAC 7-2-1(e) and 326 IAC 3-7, coal sampling and analysis data obtained 

in accordance with procedures specified under 326 IAC 3-7 may be used to demonstrate 

compliance as follows:

(1) Pursuant to 326 IAC 7-4-11(6), on a day for which Unit 3 does not burn any coal, 

compliance with the sulfur dioxide emission limitations in 326 IAC 7-4-11(2) shall 

be determined as specified in 326 IAC 7-2-1(c), using a thirty (30) day rolling 

weighted average.

(2) Pursuant to 326 IAC 7-4-11(7), on a day for which Unit 3 burns any coal, if the 

thirty (30) day rolling weighted average for any unit is above two and fifty-seven 

hundredths (2.57) pounds per million Btu, then 326 IAC 7-2-1(c)(1) does not 

apply, and the daily average emission rate for that unit for that day shall not 

exceed two and fifty-seven hundredths (2.57) pounds per million Btu.

In the alternative, SO2 emissions may be determined by use of CEM in lieu of any other method 

prescribed herein.

(b) Pursuant to 326 IAC 7-4-11(8), for the purposes of determining compliance under 

326 IAC 7-2-1(b), stack tests performed on Units 3, 4, 5, and 6 shall demonstrate 

compliance with the most stringent set of limits in effect at any time during the day prior to 

or during the test based on the Unit 3 operating status and fuel type as indicated by the 

log maintained pursuant to 326 IAC 7-4-11(9).
IPL Eagle Valley Gen. Station Page 34 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

D.2.8 RESERVED Nitrogen Oxides Monitoring Requirement [326 IAC 10-4-4(b)(1)] [326 IAC 10-4-12(b) 

and (c)] [40 CFR 75]

The Permittee has met the monitoring requirements of 326 IAC 10-4-12(b)(1) through (b)(3) that 

are applicable to their monitoring systems for the NOX budget units. The Permittee shall record, 

report, and quality assure the data from the monitoring systems in accordance with 

326 IAC 10-4-12 and 40 CFR 75.

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

D.2.9 Transformer-Rectifier (T-R) Sets [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)] [40 CFR 64]

(a) The ability of the ESP to control particulate emissions shall be monitored once per day, 

when the unit is in operation, by measuring and recording the number of T-R sets in 

service and the primary and secondary voltages and the currents of the 

transformer-rectifier (T-R) sets.

(b) Reasonable response steps shall be taken in accordance with Section C – Response to 

Exceedances or Excursions whenever the percentage of T-R sets in service falls below 

90 percent (90%). T-R set failure resulting in less than 90 percent (90%) availability is not 

a deviation from this permit. Failure to take response steps in accordance with Section C 

- Response to Exceedances or Excursions shall be considered a deviation from this 

permit.

D.2.10 Opacity Readings [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)]

(a) In the event of emissions exceeding thirty percent (30)%) average opacity for three (3) 

consecutive six (6) minute averaging periods, appropriate response steps shall be taken 

in accordance with Section C - Response to Exceedances or Excursions such that the 

cause(s) of the excursion are identified and corrected and opacity levels are brought back 

below thirty percent (30%). Examples of expected response steps include, but are not 

limited to, boiler loads being reduced, adjustment of flue gas conditioning rate, and ESP 

T-R sets being returned to service.

(b) Opacity readings in excess of thirty percent (30%) but not exceeding the opacity limit for 

the unit are not a deviation from this permit. Failure to take response steps in accordance 

with Section C - Response to Exceedances or Excursions, shall be considered a deviation 

from this permit.

D.2.11 SO2 Monitor Downtime [326 IAC 2-7-6] [326 IAC 2-7-5(3)]

(a) Whenever the SO2 continuous emission monitoring (CEM) system is malfunctioning or 

down for repairs or adjustments and a backup CEM is not brought on-line, the following 

shall be used to provide information related to SO2 emissions:

(1) If the CEM system is down for less than twenty-four (24) hours and a backup 

CEM is not brought on-line, the Permittee shall substitute an average of the 

quality-assured data from the hour immediately before and the hour immediately 

after the missing data period for each hour of missing data.

(2) If the CEM system is down for twenty-four (24) hours or more and a backup CEM 

is not brought on-line, the Permittee shall either:
IPL Eagle Valley Gen. Station Page 35 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(A) Conduct fuel sampling as specified in 326 IAC 3-7-2(b). Fuel sample

preparation and analysis shall be conducted as specified in

326 IAC 3-7-2(c), 326 IAC 3-7-2(d), and 326 IAC 3-7-2(e). Pursuant to

326 IAC 3-7-3, manual or other non-ASTM automatic sampling and

analysis procedures may be used upon a demonstration, submitted to the

department for approval, that such procedures provide sulfur dioxide

emission estimates representative either of estimates based on coal

sampling and analysis procedures specified in 326 IAC 3-7-2 or of

continuous emissions monitoring: or

(B) Comply with the relevant requirements of 40 CFR Part 75. Subpart D - 

Missing Data Substitution Procedures

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

D.2.12 Record Keeping Requirements

(a) To document compliance with the applicable opacity and particulate limits and Conditions 

D.2.1 and D.2.2, the Permittee shall maintain records in accordance with (1) through (4) 

below. Records shall be complete and sufficient to establish compliance with the opacity 

and particulate limits in Section C - Opacity and in Conditions D.2.1 and D.2.2.

(1) Data and results from the most recent stack test.

(2) All continuous opacity monitoring data, pursuant to 326 IAC 3-5.

(3) The results of all visible emission (VE) notations and Method 9 visible emission 

readings taken during any periods of COM downtime.

(4) All ESP parametric monitoring readings.

(b) To document compliance with SO2 Condition D.2.3, the Permittee shall maintain records 

in accordance with (1) through (3) below. Records shall be complete and sufficient to 

establish compliance with the SO2 limits as required in Condition D.2.3. The Permittee 

shall maintain records in accordance with (2) and (3) or (4) below during SO2 CEM 

system downtime.

(1) All SO2 continuous emissions monitoring data, pursuant to 326 IAC 3-5-6 and 

326 IAC 7-2-1(g).

(2) All fuel sampling and analysis data collected for SO2 CEM downtime, in 

accordance with Condition D.2.11.

(3) Calculated actual fuel usage during each SO2 CEM downtime for the 

Unit(s) affected by CEM downtime lasting 24 or more hours.

(4) The substitute data used for the missing data periods if data substitution

pursuant to 40 CFR Part 75 Subpart D is used to provide data for the SO2 CEM 

downtime, in accordance with Condition D.2.11. 
IPL Eagle Valley Gen. Station Page 36 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(c) Pursuant to 326 IAC 7-4-11(9), the Permittee shall maintain and make available to the 

department upon request a log of the operating status and fuel type used for Unit 3. In 

addition, in the quarterly report required by 326 IAC 7-2-1(a), the Permittee shall submit to 

the department a daily summary indicating fuel type for Unit 3, and, for days on which Unit 

3 burned any coal and any thirty (30) day rolling weighted average was greater than two 

and fifty-seven hundredths (2.57) pounds per million Btu, the Permittee shall submit to the 

department the daily average sulfur content, heat content, and sulfur dioxide emission 

rate for Units 3, 4, 5, and 6. For the purposes of this Condition, "department" refers to the 

Indiana Department of Environmental Management (IDEM).

(d) All records shall be maintained in accordance with Section C - General Record Keeping 

Requirements, of this permit.

D.2.13 Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 3-5-7] [326 IAC 7-2(c)]

(a) A quarterly report of opacity exceedances and a quarterly summary of the information to 

document compliance with Condition D.2.3 shall be submitted to the address listed in 

Section C - General Reporting Requirements of this permit, using the reporting forms 

located at the end of this permit, or their equivalent, within thirty (30) days after the end of 

the quarter being reported. The report submitted by the Permittee does require the 

certification by the “responsible official” as defined by 326 IAC 2-7-1(34).

(b) Pursuant to 326 IAC 3-5-7(5), reporting of continuous monitoring system instrument 

downtime, except for zero (0) and span checks, which shall be reported separately, shall 

include the following:

(1) Date of downtime.

(2) Time of commencement.

(3) Duration of each downtime.

(4) Reasons for each downtime.

(5) Nature of system repairs and adjustments.

The report submitted by the Permittee does require the certification by the “responsible 

official” as defined by 326 IAC 2-7-1(34).
IPL Eagle Valley Gen. Station Page 37 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION D.3 FACILITY OPERATION CONDITIONS

Facility Description [326 IAC 2-7-5(15)]

(f) One (1) distillate oil fired generator, identified as Unit PR-10, constructed in 1967, with a design 

heat input capacity of 28.4 million Btu per hour (MMBtu/hr), exhausting to stack

PR10-1.

(The information describing the process contained in this facility description box is descriptive information 

and does not constitute enforceable conditions.)

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

D.3.0 Air Quality Analysis Requirements [326 IAC 2-2-4] 

Pursuant to the air quality impact assessment requirements of 326 IAC 2-2-4, the Permittee 

shall permanently discontinue the operation of the emission units in Section D.3 before 

commercial operation of the Combined Cycle Combustion Turbine Generation Facility. The 

requirements of this section will no longer be applicable after the units are permanently 

shutdown

D.3.1 Sulfur Dioxide (SO2) [326 IAC 7-1.1-2]

Pursuant to 326 IAC 7-1.1-2 (Sulfur Dioxide Emission Limitations), the SO2 emissions from Unit 

PR-10 shall not exceed 0.5 pound per million Btu (lb/MMBtu).

Compliance Determination Requirements

D.3.2 Sulfur Dioxide Emissions and Sulfur Content] [326 IAC 7-1.1-2] [326 IAC 7-2]

Pursuant to 326 IAC 3-7-4, 326 IAC 7-1.1-2, and 326 IAC 7-2, the Permittee shall demonstrate 

that the fuel oil sulfur content does not exceed the equivalent of 0.5 lb/MMBtu, using a calendar 

month average, by:

(a) Providing vendor analysis of fuel delivered, accompanied by a vendor certification; or

(b) Providing analysis of fuel oil samples collected and analyzed in accordance with 

326 IAC 3-7-4(a).

(1) Oil samples shall be collected from the tanker truck load during or prior to 

transferring fuel to the storage tank; or

(2) Oil samples shall be collected from the storage tank immediately after each 

addition of fuel to the tank.

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

D.3.3 Record Keeping Requirements

(a) To document compliance with Condition D.3.1 and D.3.2, the Permittee shall maintain 

records in accordance with (1) through (5) below. Records maintained shall be complete 

and sufficient to establish compliance with the SO2 limit as required in Condition D.3.1 

and D.3.2.

(1) Calendar dates covered in the compliance determination period.

(2) Monthly weighted average sulfur content.

(3) Fuel heat content.

(4) Fuel consumption.
IPL Eagle Valley Gen. Station Page 38 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(5) Monthly weighted average sulfur dioxide emission rate in pounds per million Btus 

(lb/MMBtu).

(b) All records shall be maintained in accordance with Section C - General Record Keeping 

Requirements, of this permit.

D.3.4 Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 7-2(c)]

A quarterly summary of the information to document compliance with Condition D.3.1 shall be 

submitted to the address listed in Section C - General Reporting Requirements, of this permit, 

using the reporting forms located at the end of this permit, or their equivalent, within thirty (30) 

days after the end of the quarter being reported. The report submitted by the Permittee does 

require the certification by the “responsible official” as defined by 326 IAC 2-7-1(34).
IPL Eagle Valley Gen. Station Page 39 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION D.4 FACILITY OPERATION CONDITIONS

Facility Description [326 IAC 2-7-5(15)]

(g) Coal transfer facilities, with a maximum throughput of 800 tons per hour, with a dust suppression 

system. 

(h) Rail car unloading, coal pile unloading, and coal storage, with a maximum capacity of 800 tons per 

hour.

(i) Coal crushers, identified as 1A and 1B, with a maximum combined capacity of 800 tons per hour, 

each using an enclosure for dust control.

Insignificant Activities:

Coal bunker and coal scale exhausts.

(The information describing the process contained in this facility description box is descriptive information 

and does not constitute enforceable conditions.)

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

D.4.0 Air Quality Analysis Requirements [326 IAC 2-2-4] 

Pursuant to the air quality impact assessment requirements of 326 IAC 2-2-4, the Permittee 

shall permanently discontinue the operation of the emission units in Section D.4 before 

commercial operation of the Combined Cycle Combustion Turbine Generation Facility. The 

requirements of this section will no longer be applicable after the units are permanently 

shutdown. 

D.4.1 Particulate Emission Limitations for Manufacturing Processes [326 IAC 6-3-2] 

Pursuant to 326 IAC 6-3-2 (Particulate Emission Limitations for Manufacturing Processes), the 

particulate emission rate from the coal processing drop points and the particulate emission rate 

from the coal crushers shall not exceed amounts determined by the following:

(a) Interpolation of the data for the process weight rate up to sixty thousand (60,000) pounds 

per hour shall be accomplished by use of the equation:

E = 4.10 P 0.67 where E = rate of emission in pounds per hour and 

P = process weight rate in tons per hour.

(b) Interpolation and extrapolation of the data for the process weight rate in excess of sixty 

thousand (60,000) pounds per hour shall be accomplished by use of the equation:

E = 55.0 P0.11 - 40 where E = rate of emission in pounds per hour; and

P = process weight rate in tons per hour.

When the process weight rate exceeds two hundred (200) tons per hour, the allowable emission 

may exceed the pounds per hour limitation calculated using the above equation, provided the 

concentration of particulate in the discharge gases to the atmosphere is less than 0.10 pounds 

per one thousand (1,000) pounds of gases.

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

D.4.2 Visible Emissions Notations [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)]

(a) Visible emission notations of any coal transfer exhaust points shall be performed once per 

week during normal daylight operations when transferring coal. A trained employee shall 

record whether emissions are normal or abnormal.
IPL Eagle Valley Gen. Station Page 40 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(b) Visible emission notations of the rail car unloading shall be performed once per week 

during normal daylight operations when unloading coal. A trained employee shall record 

whether emissions are normal or abnormal.

(c) Visible emission notations of the coal crusher stack exhaust shall be performed once per 

week during normal daylight operations when the crusher is in operation. A trained 

employee shall record whether emissions are normal or abnormal.

(d) For processes operated continuously, "normal" means those conditions prevailing, or 

expected to prevail, eighty percent (80%) of the time the process is in operation.

(e) In the case of batch or discontinuous operations, readings shall be taken during that part 

of the operation that would normally be expected to cause the greatest emissions.

(f) A trained employee is an employee who has worked at the plant at least one (1) month 

and has been trained in the appearance and characteristics of normal visible emissions 

for that specific process.

(g) If abnormal emissions are observed at a transfer point exhaust or crusher exhaust or 

from the coal unloading, the Permittee shall take reasonable response steps in 

accordance with Section C - Response to Excursions or Exceedances. Failure to take 

response steps in accordance with Section C - Response to Excursions or Exceedances, 

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.4.3 Record Keeping Requirements

(a) To document compliance with Condition D.4.2, the Permittee shall maintain weekly

records of the visible emission notations of the rail car unloading, crusher and coal 

transfer exhaust. The Permittee shall include in its weekly record when a visible emission 

notation is not taken and the reason for the lack of a visible emission notation, (e.g. the 

process did not operate that week).

(b) All records shall be maintained in accordance with Section C - General Record Keeping 

Requirements, of this permit.
IPL Eagle Valley Gen. Station Page 41 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION D.5 FACILITY OPERATION CONDITIONS

Facility Description [326 IAC 2-7-5(15)]:

(j) One (1) pneumatic Fly Ash Conveyance and Silo Storage (fly ash storage silo and handling 

system), to be constructed in 2009, with a maximum storage capacity of 300 tons and a 

maximum throughput capacity of 10.0 tons of fly ash per hour. The particulate emissions from 

the silo loadout to trucks are uncontrolled and exhaust to the atmosphere. The particulate 

emissions from the silo storage will be controlled by a baghouse, identified as Silo Baghouse,

and exhausting to a stack, identified as Silo Stack. The particulate emissions from fly ash 

conveyance are controlled by a dust collector, identified as Fly Ash Collector, and exhausting 

to a stack, identified as Vacuum Blower Stack.

Note: The pneumatic fly ash storage silo and handling system was never constructed. 

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

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

D.5.0 Air Quality Analysis Requirements [326 IAC 2-2-4] 

Pursuant to the air quality impact assessment requirements of 326 IAC 2-2-4, the Permittee 

shall permanently discontinue the operation of the emission units in Section D.5 before 

commercial operation of the Combined Cycle Combustion Turbine Generation Facility. The 

requirements of this section will no longer be applicable after the units are permanently 

shutdown. 

D.5.1 PSD Minor Limits and Nonattainment NSR [326 IAC 2-2] [326 IAC 2-1.1-5]

The Permittee shall comply with the following:

(a) The combined PM emissions from the Fly Ash Conveyance and Silo Storage shall not 

exceed 3.9 pounds per hour. 

(b) The combined PM10 emissions from the Fly Ash Conveyance and Silo Storage shall not 

exceed 2.9 pounds per hour. 

Compliance with these limits in combination with other emission units will limit the PM and PM10 

emissions from the Fly Ash Conveyance and Silo Storage (fly ash storage and handling system) 

to less than 25 and 15 tons per year, respectively and render the requirements of 326 IAC 2-2 

(PSD) and 326 IAC 2-1.1-5 (Nonattainment NSR) not applicable to the Fly Ash Conveyance and 

Silo Storage (fly ash storage and handling system) permitted in 2008. 

D.5.2 Particulate Emission Limitations for Manufacturing Processes [326 IAC 6-3-2]

Pursuant to 326 IAC 6-3-2, the allowable particulate matter (PM) from the Fly Ash Conveyance 

and Silo Storage (fly ash storage and handling system) shall not exceed 19.2 pounds per hour, 

each, when operating at a process weight rate of 10 tons per hour, each. The pound per hour 

limitation was calculated with the following equation:

Interpolation of the data for the process weight rate up to sixty thousand (60,000) pounds per hour 

was determined by use of the equation:

E = 4.10 P 0.67 where E = rate of emission in pounds per hour and

P = process weight rate in tons per hour
IPL Eagle Valley Gen. Station Page 42 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Compliance Determination Requirements

D.5.3 Particulate Matter (PM)

(a) In order to comply with Conditions D.5.1 and D.5.2, the baghouse and fly ash collector 

shall be in operation at all times when the fly ash storage and handling is in operation.

(b) In the event that bag failure is observed in a multi-compartment baghouse, if operations 

will continue for ten (10) days or more after the failure is observed before the failed units 

will be repaired or replaced, the Permittee shall promptly notify the IDEM, OAQ of the 

expected date the failed units will be repaired or replaced. The notification shall also 

include the status of the applicable compliance monitoring parameters with respect to 

normal, and the results of any response actions taken up to the time of notification.

D.5.4 Testing Requirements [326 IAC 2-7-6(1)][326 IAC 2-1.1-11]

Within 180 days after initial startup of the fly ash handling and storage system, in order to 

demonstrate compliance with Conditions D.5.1 and D.5.2, the Permittee shall perform PM/PM10 

testing on baghouse and the dust collector controlling the fly ash storage and handling system 

utilizing methods as approved by the Commissioner. This test shall be repeated at least once 

every five (5) years from the date of the most recent valid compliance demonstration. Testing 

shall be conducted in accordance with Section C - Performance Testing.

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

D.5.5 Visible Emissions Notations

(a) Visible emission notations of the fly ash storage and handling stack exhausts shall be 

performed once per week during normal daylight operations. A trained employee shall 

record whether emissions are normal or abnormal.

(b) For processes operated continuously, "normal" means those conditions prevailing, or 

expected to prevail, eighty percent (80%) of the time the process is in operation, not 

counting startup or shut down time.

(c) In the case of batch or discontinuous operations, readings shall be taken during that part 

of the operation that would normally be expected to cause the greatest emissions.

(d) A trained employee is an employee who has worked at the plant at least one (1) month 

and has been trained in the appearance and characteristics of normal visible emissions 

for that specific process.

(e) If abnormal emissions are observed, the Permittee shall take reasonable response steps 

in accordance with Section C - Response to Excursions or Exceedances. Failure to take 

response steps in accordance with Section C - Response to Excursions or Exceedances 

shall be considered a deviation from this permit.

D.5.6 Parametric Monitoring

The Permittee shall record the pressure drop across the fly ash storage and handling baghouse and 

dust collector used in conjunction with the fly ash storage and handling at least once per day when the 

fly ash storage and handling is in operation. When for any one reading, the pressure drop across the 

baghouse or the fly ash collector is outside the normal range of 1.0 and 10.0 inches of water, or a 

range established during the latest stack test the Permittee shall take reasonable response steps in 

accordance with Section C - Response to Excursions or Exceedances. Failure to take response steps 

in accordance with Section C - Response to Excursions or Exceedances, shall be considered a 

deviation from this permit.

The instrument used for determining the pressure shall comply with condition C.14 - Instrument 

Specifications, be subject to approval by IDEM, OAQ, and shall be calibrated at least once every six 

(6) months.
IPL Eagle Valley Gen. Station Page 43 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

D.5.7 Broken or Failed Bag Detection

(a) For a single compartment baghouse controlling emissions from a process operated 

continuously, a failed unit and the associated process shall be shut down immediately 

until the failed unit has been repaired or replaced.

(b) For a single compartment baghouse controlling emissions from a batch process, the feed 

to the process shall be shut down immediately until the failed unit has been repaired or 

replaced. The emissions unit shall be shut down no later than the completion of the 

processing of the material in the emissions unit.

Bag failure can be indicated by a significant drop in the baghouse's pressure reading with abnormal 

visible emissions, by an opacity violation, or by other means such as gas temperature, flow rate, air 

infiltration, leaks, or dust traces.

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

D.5.8 Record Keeping Requirements

(a) To document compliance with Condition D.5.5 - Visible Emission Notation, the Permittee 

shall maintain weekly records of the visible emission notations of the fly ash storage and 

handling stack exhaust. The Permittee shall include in its weekly record when a visible 

emission notation is not taken and the reason for the lack of a visible emission notation, 

(e.g. the process did not operate that day).

(b) To document compliance with Condition D.5.6 - Parametric Monitoring, the Permittee 

shall maintain the daily records of the pressure drop across the baghouse and fly ash 

collector controlling the fly ash storage and handling. The Permittee shall include in its 

daily record when a pressure drop reading is not taken and the reason for the lack of a 

pressure drop reading, (e.g. the process did not operate that day).

(c) All records shall be maintained in accordance with Section C - General Record Keeping 

Requirements of this permit.
IPL Eagle Valley Gen. Station Page 44 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION D.6 FACILITY CONDITIONS

Facility Description [326 IAC 2-7-5(15)] Insignificant Activities:

(1) Wet process ash handling, with hydroveyors conveying ash to storage ponds.

(2) Ponded ash handling/removal operations.

(3) Truck traffic on paved road to and from the Silo. 

(The information describing the process contained in this facility description box is descriptive information 

and does not constitute enforceable conditions.)

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

D.6.0 Air Quality Analysis Requirements [326 IAC 2-2-4] 

Pursuant to the air quality impact assessment requirements of 326 IAC 2-2-4, the Permittee 

shall permanently discontinue the operation of the “wet process ash handling with 

hydroveyors conveying ash to storage ponds” before commercial operation of the 

Combined Cycle Combustion Turbine Generation Facility. The requirements of this section 

will no longer be applicable after the units are permanently shutdown. 

D.6.1 Fugitive Dust Emission Limitations [326 IAC 6-4-2]

Pursuant to 326 IAC 6-4-2:

(a) Any ash storage pond area generating fugitive dust shall be in deviation from this rule 

(326 IAC 6-4) if any of the following criteria are violated:

(1) A source or combination of sources which cause to exist fugitive dust 

concentrations greater than sixty-seven percent (67%) in excess of ambient 

upwind concentrations as determined by the following formula:

P = 100 (R) - U)

 U 

Where

P = Percentage increase

R = Number of particles of fugitive dust measured at downward receptor site

U = Number of particles of fugitive dust measured at upwind or background site

(2) The fugitive dust is comprised of fifty percent (50%) or more respirable dust, then 

the percent increase of dust concentration in subdivision (1) of this section shall 

be modified as follows:

PR = (1.5 ± N) P

Where

N = Fraction of fugitive dust that is respirable dust;

PR = allowable percentage increase in dust concentration above background; 

and

P = no value greater than sixty-seven percent (67%).

(3) The ground level ambient air concentrations exceed fifty (50) micrograms per 

cubic meter above background concentrations for a sixty (60) minute period.

(4) If fugitive dust is visible crossing the boundary or property line of a source. This 

subdivision may be refuted by factual data expressed in subdivisions (1), (2) or 

(3) of this section. 326 IAC 6-4-2(4) is not federally enforceable.
IPL Eagle Valley Gen. Station Page 45 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(b) Pursuant to 326 IAC 6-4-6(6) (Exceptions), fugitive dust from a source caused by adverse 

meteorological conditions will be considered an exception to this rule (326 IAC 6-4) and 

therefore not in violation. 

Adverse weather conditions do not relieve a source from taking all reasonable measures 

to mitigate fugitive dust formation and transport. Failure to take reasonable measures 

during this period may be considered to be a deviation from this permit.

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

D.6.2 Visible Emissions Notations [326 IAC 2-7-6(1)] [326 IAC 2-7-5(1)]

(a) Visible emission notations of the fly ash storage pond area(s) shall be performed at least 

once per week during normal daylight operations. A trained employee shall record 

whether emissions are normal or abnormal.

(b) For processes operated continuously, "normal" means those conditions prevailing, or 

expected to prevail, eighty percent (80%) of the time the process is in operation.

(c) In the case of batch or discontinuous operations, readings shall be taken during that part 

of the operation that would normally be expected to cause the greatest emissions.

(d) A trained employee is an employee who has worked at the plant at least one (1) month 

and has been trained in the appearance and characteristics of normal visible emissions 

for that specific process.

(e) If abnormal visible emissions are observed crossing the property line or boundaries of the 

property, right-of-way, or easement on which the source is located, the Permittee shall 

take reasonable response steps in accordance with Section C - Response to Excursions 

or Exceedances. Failure to take response steps in accordance with Section C - 

Response to Excursions or Exceedances, 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.6.3 Record Keeping Requirements

(a) To document compliance with Condition D.6.2, the Permittee shall maintain weekly

records of the visible emission notations of the fly ash storage pond area(s). The 

Permittee shall include in its weekly record when a visible emission notation is not taken

and the reason for the lack of a visible emission notation, (e.g. the process did not 

operate that day).

(b) All records shall be maintained in accordance with Section C - General Record Keeping 

Requirements, of this permit.
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Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Change 3: The new emission units and there conditions have been added to Section D.7, D.8, D.9, 

D.10, D.11, D.12, D.13 and D.14 of the permit.

SECTION D.7 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(k) Two (2) natural gas fired combustion turbine units each with a natural gas fired duct 

burner identified as EU-1 and EU-2, permitted in 2013, each with a total rated heat input 

capacity of 2,542 MMBtu/hr; with NOx emissions controlled by low combustion burner 

design and Selective Catalytic Reduction (SCR), and each with an oxidation catalyst 

system to reduce emissions of CO and VOCs including formaldehyde, and exhausting to 

stacks S-1 and S-2. Each stack has continuous emissions monitors (CEMS) for NOx. 

 

*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.)

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

D.7.1 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-1 

and EU-2 shall be as follows:

(a) The PM, PM10 and PM2.5 emissions from the combined cycle combustion turbines 

identified as EU-1 and EU-2 shall not exceed 16.8 pounds per hour, each and 0.0066 

pounds per MMBtu, each 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 EU-1 and EU-2 shall not exceed 13.9 pounds per hour, each and 0.0055 

pounds per MMBtu, each without duct firing based on 3-hr average through the use

of good combustion practices and fuel specification. 

(c) Only pipeline natural gas shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

D.7.2 H2SO4 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-1 

and EU-2 shall be as follows:

(a) The H2SO4 emissions from the combined cycle combustion turbines identified as 

EU-1 and EU-2 shall be limited by restricting the S content of the natural gas to 0.75 

gr S/100 scf on a monthly average basis. 

(b) Only pipeline natural gas shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.
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Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

D.7.3 CO PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-1 

and EU-2 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 ppmvd @15% O2 based on a 3-hour 

average.

(c) Only pipeline natural gas shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

D.7.4 VOC PSD BACT [326 IAC 2-2-3][326 IAC 8-1-6]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 

(Prevention of Significant Deterioration (PSD)) and 326 IAC 8-1-6, the Best Available 

Control Technologies (BACT) for the natural gas-fired combined cycle combustion 

turbines, identified as EU-1 and EU-2 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-hour average.

(c) The VOC emissions shall not exceed 1.0 ppmvd @15% O2, without duct burners 

 based on 3-hour average.

(d) Only pipeline natural gas shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

D.7.5 NOx PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-1 

and EU-2 shall be as follows:

(a) The NOx emissions from the CCCTs shall be controlled by a Selective Catalytic 

Reduction and Dry Low NOx combustors.

(b) The NOx emissions shall not exceed 2.0ppmv @15% O2 with duct burners based on 

a 3-hour average.

(c) Only pipeline natural gas shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

D.7.6 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-1 

and EU-2 shall be as follows:

(a) The net heat rate shall not exceed 7,750 Btu/kW-hr (HHV-net) for each CCCT block 

(ISO conditions, without duct firing or inlet evaporative cooling, and not 

accounting for transformer losses).
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Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(b) The total CO2e emissions for both combined cycle combustion turbines shall be 

limited to less than 2,649,570 tons of CO2e per twelve (12) consecutive month 

period with compliance determined at the end of each month.

D.7.7 Hazardous Air Pollutants (HAPs) Minor Limits

The emissions of single HAP, formaldehyde, from the combined cycle combustion turbines 

identified as EU-1 and EU-2, shall be limited to less than nine (9.0) tons per twelve (12) 

consecutive month period, with compliance determined at the end of each month. 

Compliance with the above limits, combined with the potential to emit formaldehyde 

emissions from all other emission units will limit the potential to emit from this source to 

less than ten (10) tons per year of formaldehyde and make the source an area source of 

HAPs. 

D.7.8 Startup and Shutdown Limitations for Combustion Turbines [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 

(Prevention of Significant Deterioration (PSD)), the following shall apply to each 

combustion turbine:

(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 low-NOx (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) 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 - 3,390 lb/event

NOx - 429 lb/event

(g) The total NOX emissions from the combined cycle combustion turbines stacks 

shall not exceed 68 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. 

(h) The total CO emissions from the combined cycle combustion turbines stacks shall 

not exceed 565 tons per twelve (12) consecutive month period, for the duration of 
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the combined startup and shutdown events, with compliance determined at the 

end of each month. 

(i) The total VOC emissions from the combined cycle combustion turbines stacks 

shall not exceed 146 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. 

Compliance Determination Requirements

D.7.9 Oxidation Catalyst

In order to ensure compliance with Conditions D.7.3, D.7.4 and D.7.7, the oxidation catalyst 

shall be in operation at all times when the natural gas-fired combined cycle combustion 

turbines are in operation except during periods of startup and shutdown. 

D.7.10 Nitrogen Oxide Control

In order to ensure compliance with Condition D.7.5 - NOx PSD BACT, the Selective 

Catalytic Reduction and Dry Low NOx combustors shall be in operation and control 

emissions from the natural gas-fired combustion turbines at all times that the natural gasfired combined cycle combustion turbines are in operation except during periods of 

startup and shutdown. 

D.7.11 H2SO4 Compliance Determination Requirements [326 IAC 2-2]

In order to ensure compliance with Condition D.7.2, the Permittee shall maintain a record 

of the monthly average sulfur content of the natural gas based on vendor data.

D.7.12 Greenhouse Gases (GHGs) Calculations

To determine the compliance status with Condition D.7.6 - GHGs PSD BACT, the following 

equation shall be used to determine the CO2e emissions from the natural gas-fired 

combined cycle combustion turbines, identified as EU-1 and EU-2: 

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) = 120 lbs/mmbtu for combustion with duct firing and 122 lbs/mmbtu for 

combustion without duct firing 

CH4 EF (lb/mmbtu) = 0.0022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, 

Subpart C) for natural gas

N2O EF (lb/mmbtu) = 0.00022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, 

Subpart C) for natural gas

CO2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N2O GWP = 310 global warming potential from GHG MRR (40 CFR 98, Subpart A)

D.7.13 HAPs Minor Limits Calculations

To determine the compliance status with Condition D.7.7 - Hazardous Air Pollutants (HAPs) 

minor Limits, the following equation shall be used to determine formaldehyde emissions 

from the natural gas-fired combined cycle combustion turbines, identified as EU-1 and EU2: 
IPL Eagle Valley Gen. Station Page 50 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

L (tons/month)= (7.1 x 10-4 x Qu + C x Qc)/2000 lbs/ton

Where: 

L = 9 tons of (formaldehyde) per 12 month rolling period.

7.1 x 10-4 is the uncontrolled emission factor for formaldehyde (lbs/MMBtu)

Qu = 12- month rolling total heat input to the CT units (MMBtu) when the oxidation 

catalyst is not fully operational during startup and shutdown conditions

Qc = 12- month rolling total heat input to the CT units (MMBtu) when the oxidation 

catalyst is fully operational (includes heat input to duct burners). 

C = is the controlled emission factor for formaldehyde (lbs/MMBtu), which would be 

based on stack test results of the CCCTs. Prior to stack testing the factor will be 

conservatively assumed to equal 60% of the uncontrolled emission factor.

D.7.14 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 O2 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.

(d) Whenever a NOx or O2 CEMS is down for more than twenty-four (24) hours, the 

Permittee shall monitor the catalyst inlet temperature used in conjunction with the 

CCCT units with a continuous temperature monitoring system and comply with the 

following:

The Permittee shall measure the operating temperature of the catalyst inlet bed 

temperature no less often than once per four (4) hours. In the event of a 

monitoring system malfunction, failure to measure the operating temperature of 

the catalyst bed inlet temperature is not a deviation of the permit. Failure to take 

response steps shall be considered a deviation from the permit. If the measured 

temperature is below the minimum temperature as supplied by the manufacturer, 

reasonable response steps shall be taken to return the catalyst bed inlet 

temperature to the required minimum temperature. A reading that is below the 

minimum temperature is not a deviation from this permit. Failure to take 

response steps in accordance with Section C – Response to Excursions or 

Exceedances shall be considered a deviation from this permit.

 

(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.7.15 Testing Requirements [326 IAC 2-1.1-11]

(a) In order to demonstrate compliance with Conditions D.7.1 - PM, PM10 and PM2.5 PSD 

BACT, within sixty (60) days of reaching maximum capacity but no later than one 
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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 by December 31 of every fifth year following 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.7.3 - 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 oxidation catalyst controlling the combined 

cycle combustion turbines utilizing methods as approved by the commissioner. 

Testing shall be conducted with the duct burners in operation. This test shall be 

repeated by December 31 of every fifth year following 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.7.4 - 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 oxidation catalyst controlling 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 by December 31 of every fifth year following 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.7.6(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 by December 31 of 

every fifth year following 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.7.7 - Hazardous Air Pollutants 

(HAPs) minor Limits, 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 HAPs (formaldehyde) emissions stack testing of the emissions from 

oxidation catalyst controlling the combined cycle combustion turbines utilizing 

methods as approved by the commissioner. This test shall be repeated by 

December 31 of every fifth year following 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.
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Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

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

D.7.16 Oxidation Catalyst Parametric Monitoring [40 CFR 64]

(a) In order to ensure compliance with Conditions D.7.3, D.7.4 and D.7.7, a continuous 

monitoring system shall be calibrated, maintained, and operated on the 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 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, CO and formaldehyde 

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, CO and formaldehyde 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.7.17 Record Keeping Requirement

(a) In order to document the compliance status with Conditions D.7.1, D.7.2, D.7.3, 

D.7.4, D.7.5, D.7.6 and D.7.7, the Permittee shall maintain monthly records of the 

amount and type of fuel combusted in the combined cycle combustion turbines.

(b) To document the compliance status with Condition D.7.2 - H2SO4 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.

(c) To document the compliance status with Condition D.7.6 (b) - GHGs PSD BACT, the 

Permittee shall maintain monthly records of the CO2e emissions.

(d) To document the compliance status with the emission limits in Condition D.7.7 - 

Hazardous Air Pollutants (HAPs) minor Limits, the Permittee shall maintain monthly 

records of the formaldehyde emissions.

(e) To document compliance with Condition D.7.8 - 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) Records shall be maintained at any time the unit is off-line. 

(4) 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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(f) To document the compliance status with Condition D.7.14 - 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.

(g) In the event that a breakdown of the NOx or O2 continuous emission monitoring 

system (CEMS) occurs in Condition D.7.14 - 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.

(h) To document the compliance status with Conditions D.7.14 - Maintenance of 

Continuous Emission Monitoring Equipment, the Permittee shall maintain the 

monthly records of the NOx emissions from each of the combined cycle 

combustion turbines EU-1 and EU-2 based upon the CEM data. 

(i) In order to document the compliance status with Condition D.7.16 - Oxidation 

Catalyst Parametric Monitoring, the Permittee shall maintain continuous 

temperature records (on a three- (3-) hour average basis) for each oxidation 

catalyst to demonstrate compliance.

(j) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition.

D.7.18 Reporting Requirements 

A quarterly summary of the information to document the compliance status with 

Conditions D.7.6(b), D.7.7, D.7.8(h), D.7.8(i) and D.7.8(j) 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.8 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(l) One (1) natural gas fired Auxiliary Boiler, identified as emission unit EU-3, permitted in 

2013, with a rated heat input capacity of 79.3 MMBtu/hr, equipped with low NOx burners 

(LNB) with flue gas recirculation (FGR) to reduce NOx emissions exhausting to stack S3. 

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

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

D.8.1 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3] 

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-3 shall be as follows:

The PM, PM2.5 and PM10 emissions from the Auxiliary Boiler, identified as EU-3 shall not 

exceed 0.005 lb/MMBtu and 0.4 lbs/hour, based on a 3-hr average period through the use of

good combustion practices and fuel specification. 

D.8.2 H2SO4 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-3 shall be as follows:

(a) The H2SO4 emissions from the auxiliary boiler, identified as EU-3 shall be limited by 

limiting the S content of the natural gas to 0.75 gr S/100 scf on a monthly average 

basis. 

D.8.3 CO PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-3 shall be as follows:

The CO emissions from the Auxiliary Boiler (EU-3) operation shall not exceed 0.083 

lb/MMBtu and 6.5 lbs/hr, based on a 3 - hour average through the use of advanced ultra -

low NOx burner.

D.8.4 VOC PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-3 shall be as follows:

The VOC emissions from the Auxiliary Boiler, identified as EU-3 shall not exceed 0.0053 

lb/MMBtu and 0.42 lbs/hr, based on a 3-hr average period through the use of advanced 

ultra - low NOx burner.

D.8.5 NOx PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-3 shall be as follows:
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(a) The NOx emissions from the Auxiliary Boiler, identified as EU-3 shall be controlled 

by Low NOx Burners with Flue Gas Recirculation.

(b) The NOx emissions shall be limited to less than 0.011 lb/MMBtu and 0.87 pounds 

per hour, based on a 3-hour average period.

D.8.6 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 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 EU-3 shall be as follows:

The GHGs BACT for the Auxiliary Boiler 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) The boiler will be equipped with a condensate return system (recovery);

(f) Steam and hot lines will be insulated; and 

(g) Boiler designed for 80% thermal efficiency (HHV).

(h) The total CO2e emissions for Auxiliary Boiler shall be limited to less than 40,639 

tons of CO2e per twelve (12) consecutive month period with compliance 

determined at the end of each month.

D.8.7 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.

Compliance Determination Requirements

D.8.8 Nitrogen Oxide Control

In order to ensure compliance with Condition D.8.5 - NOx PSD BACT, the Low NOx Burners 

with Flue Gas Recirculation shall be installed and utilized at all times that the auxiliary 

boiler is in operation.

D.8.9 H2SO4 Compliance Determination Requirements [326 IAC 2-2]

In order to ensure compliance with Condition D.8.2, the Permittee shall maintain a record 

of the monthly average sulfur content of the natural gas based on vendor data.
IPL Eagle Valley Gen. Station Page 56 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

D.8.10 Testing Requirements [326 IAC 2-1.1-11]

(a) In order to demonstrate compliance with Condition D.8.1 - 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 auxiliary boiler 

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.8.3 - 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 auxiliary boiler 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.

(c) In order to demonstrate compliance with Condition D.8.4 - 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 auxiliary boiler 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.

(d) In order to demonstrate compliance with Condition D.8.5 - 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 auxiliary boiler utilizing methods as 

approved by the commissioner. This test shall be repeated by December 31 of 

every fifth year following 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.8.6(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 boiler, identified as EU-3 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.8.11 Greenhouse Gases (GHGs) Calculations

To determine the compliance status with Condition D.8.6(h), the following equation shall 

be used to determine the CO2e emissions from the Auxiliary Boiler: 

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 
IPL Eagle Valley Gen. Station Page 57 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

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) = 117 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart 

C) for natural gas

CH4 EF (lb/mmbtu) = 0.0022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, 

Subpart C) for natural gas

N2O EF (lb/mmbtu) = 0.00022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, 

Subpart C) for natural gas

CO2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N2O GWP = 310 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.8.12 Record Keeping Requirements

(a) In order to document the compliance status with Conditions D.8.1, D.8.2, D.8.3, 

D.8.4, D.8.5, D.8.6 and D.8.11, the Permittee shall maintain monthly records of the 

type and amount of fuel combusted in the auxiliary boiler.

(b) To document the compliance status with Condition D.8.2 - H2SO4 PSD BACT, the 

Permittee shall maintain the monthly vendor records of the fuel sulfur content of 

the natural gas combusted in the auxiliary boiler.

(c) To document the compliance status with Condition D.8.6(h) - GHGs PSD BACT, the 

Permittee shall maintain the monthly records of the total CO2e emissions from the 

auxiliary boiler. 

(d) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition.

D.8.13 Reporting Requirements

A quarterly summary of the information to document the compliance status with Condition 

D.8.6(h) 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.
IPL Eagle Valley Gen. Station Page 58 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION D.9 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(m) One (1) natural gas fired Dew Point Heater, identified as emission unit EU-4, permitted in 

2013, with a rated heat input capacity of 20.8 MMBtu/hr exhausting to stack S-4.

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

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

D.9.1 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 

(Prevention of Significant Deterioration (PSD)), the Best Available Control Technologies 

(BACT) for the dew point heater, identified as EU-4 shall be as follows:

The PM, PM10 and PM2.5 emissions from the Dew Point Heater, identified as EU-4 shall be 

limited to less than 0.0072 lb/MMBtu and 0.15 lbs/hr, based on a 3-hr average period 

through the use of good combustion practices and fuel specification. 

D.9.2 H2SO4 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 

(Prevention of Significant Deterioration (PSD)), the Best Available Control Technologies 

(BACT) for the dew point heater, identified as EU-4 shall be as follows:

(a) The H2SO4 emissions from the dew point heater, identified as EU-4 shall be limited 

by limiting the S content of the natural gas to 0.75 gr S/100 scf on a monthly

average basis. 

D.9.3 CO PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 

(Prevention of Significant Deterioration (PSD)), the Best Available Control Technologies 

(BACT) for the dew point heater, identified as EU-4 shall be as follows:

The CO emissions from the Dew Point Heater (EU-4) operation shall not exceed 0.082 

lb/MMBtu and 1.7 lbs/hr, based on a 3 - hour average through the use of good combustion 

and low NOx burners.

D.9.4 VOC PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 

(Prevention of Significant Deterioration (PSD)), the Best Available Control Technologies 

(BACT) for the dew point heater, identified as EU-4 shall be as follows:

The VOC emissions from the Dew Point Heater, identified as EU-3 shall not exceed 0.0053 

lb/MMBtu and 0.11 lbs/hr, based on a 3-hr average period through the use of good 

combustion and low NOx burners.

D.9.5 NOx PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 

(Prevention of Significant Deterioration (PSD)), the Best Available Control Technologies 

(BACT) for the dew point heater, identified as EU-4 shall be as follows:

(a) The NOx emissions from the Dew Point Heater, identified as EU-4 shall be 

controlled by a Low NOx Burner with Flue Gas Recirculation.
IPL Eagle Valley Gen. Station Page 59 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(b) The NOx emissions shall be limited to less than 0.032 lb/MMBtu and 0.67 pounds 

per hour, based on a 3-hr average period.

D.9.6 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 

(Prevention of Significant Deterioration (PSD)), the Best Available Control Technologies 

(BACT) for the dew point heater, identified as EU-4 shall be as follows:

(a) The good engineering design and Combustion Practices.

(b) The use of only natural gas.

 

(c) The total CO2e emissions for Dew Point Heater shall be limited to less than 10,659 

tons of CO2e per twelve (12) consecutive month period with compliance 

determined at the end of each month.

Compliance Determination Requirements

D.9.7 Nitrogen Oxide Control

In order to ensure compliance with Condition D.9.5 - NOx PSD BACT, the low NOx burner 

shall be installed and utilized at all times that the dew point heater, identified as EU-4 is in 

operation.

D.9.8 Compliance Determination Requirements [326 IAC 2-2]

In order to determine compliance status with Conditions D.9.1 - PM, PM10 and PM2.5 PSD 

BACT and D.9.2 - H2SO4 PSD BACT, the Permittee shall only use natural gas in the dew 

point heater EU-4. 

D.9.9 Greenhouse Gases (GHGs) Calculations

To determine the compliance status with Condition D.9.6(c), the following equation shall 

be used to determine the CO2e emissions from the dew point heater, identified as EU-4: 

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 dew point heater 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) = 117 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart 

C) for natural gas

CH4 EF (lb/mmbtu) = 0.0022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, 

Subpart C) for natural gas

N2O EF (lb/mmbtu) = 0.00022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, 

Subpart C) for natural gas

CO2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N2O GWP = 310 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.9.10 Record Keeping Requirements

(a) In order to document the compliance status with Conditions D.9.1, D.9.2, D.9.3, 
IPL Eagle Valley Gen. Station Page 60 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

D.9.4, D.9.5, and D.9.6, 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.9.6(c) - 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.9.11 Reporting Requirements

A quarterly summary of the information to document the compliance status with Condition 

D.9.6(c) 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.
IPL Eagle Valley Gen. Station Page 61 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION D.10 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: Insignificant Activities

(c) One (1) distillate oil fired Emergency Generator, identified as emission unit EU-5, 

permitted in 2013, with a rated capacity of 1,826 HP and exhausting through stack S-5.

[Under 40 CFR 60, Subpart IIII, the Emergency Generator is considered new affected 

sources.][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Generator is considered 

new affected sources.]

(d) One (1) distillate oil fired Emergency Fire Pump, identified as emission unit EU-6, 

permitted in 2013, with a rated capacity of 500 HP and exhausting through stack S-6.

[Under 40 CFR 60, Subpart IIII, the Emergency Fire Pump is considered new affected 

sources.][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Fire Pump is considered 

new affected sources.]

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

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

D.10.1 PM, PM10, PM2.5, NOx, CO, H2SO4 and GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 

(Prevention of Significant Deterioration (PSD)), the Best Available Control Technologies 

(BACT) for the Emergency Generator, identified as emission unit EU-5 shall be as follows:

Emergency Diesel Generator, identified as (EU5):

(a) The PM, PM10 and PM2.5 emissions from the Emergency Generator, Identified as EU5, shall not exceed 0.15 g/hp-hr, through the use of combustion design control. 

(b) The H2SO4 emissions;

 1. The sulfur content of the fuel oil shall not exceed 15ppm. 

(c) The CO emissions from the Emergency Generators, Identified as EU-5 shall not 

exceed 2.6 g/hp-hr through the use of combustion design controls and usage 

limitation. 

(d) The NOx and VOC emissions from the Emergency Generator shall be limited to less 

than 4.8 g/bhp-hr for NMHC + NOx through the use of Combustion Design Controls. 

 

(e) The GHGs BACT for the Emergency Diesel Generator, Identified as EU5 shall be as 

follows:

1. The use of a good engineering design; and

2. The total CO2e emissions for Emergency Diesel Generator shall be limited 

to less than 605 tons of CO2e per twelve (12) consecutive month period with

compliance determined at the end of each month.

D.10.2 PM, PM10, PM2.5, NOx, CO, H2SO4 and GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 

(Prevention of Significant Deterioration (PSD)), the Best Available Control Technologies 

(BACT) for the Emergency Fire Pump, identified as emission unit EU-6 shall be as follows:
IPL Eagle Valley Gen. Station Page 62 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Emergency Fire Pump Engine, identified as EU-6:

(a) The PM, PM10 and PM2.5 emissions from the Emergency Fire Pump Engine shall not 

exceed 0.15 g/hp-hr through the use of combustion design control. 

 (b) H2SO4 BACT Limits 

 1. The sulfur content of the fuel oil shall not exceed 15ppm. 

(c) The CO emissions from the Emergency Fire pump Engine shall not exceed 2.6 

g/hp-hr through the use of combustion design controls and usage limitation. 

(d) The NOx and VOC emissions from the Emergency Fire Pump Engine shall not 

exceed 3.0 g/bhp-hr for NMHC + NOx through the use of Combustion Design 

Controls and usage limitation. 

(e) The GHGs BACT for the Emergency Diesel Generator, Identified as EU-6 shall be as 

follows:

1. The use of a good engineering design; and

2. The total CO2e emissions for Firewater Pump Engine shall be limited to less 

than 157.50 tons of CO2e per twelve (12) consecutive month period with 

compliance determined at the end of each month.

Compliance Determination Requirements

D.10.3 Greenhouse Gases (GHGs) Calculations

(a) To determine the compliance status with Condition D.10.1(e)(2), the following 

equation shall be used to determine the CO2e emissions from the Emergency 

Diesel Generator (EU-5):

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 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) = 163 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart 

C) for diesel fuel

CH4 EF (lb/mmbtu) = 0.00661 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, 

Subpart C) for diesel fuel

N2O EF (lb/mmbtu) = 0.00132 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, 

Subpart C) for diesel fuel

CO2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N2O GWP = 310 global warming potential from GHG MRR (40 CFR 98, Subpart A)

(b) To determine the compliance status with Condition D.10.2(g)(3), the following 

equation shall be used to determine the CO2e emissions from the Emergency Fire 

Pump Engine (EU-6):
IPL Eagle Valley Gen. Station Page 63 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

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 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) = 163 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart 

C) for diesel fuel

CH4 EF (lb/mmbtu) = 0.00661 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, 

Subpart C) for diesel fuel

N2O EF (lb/mmbtu) = 0.00132 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, 

Subpart C) for diesel fuel

CO2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N2O GWP = 310 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.10.4 Record Keeping Requirements

(a) In order to document the compliance status with Conditions D.10.1(c) and D10.2(c), 

the Permittee shall maintain monthly records of the percent sulfur content of the 

fuel used in the emergency diesel engine and the fire pump engine. 

(b) To document compliance with Conditions D.10.1(h) and D.10.2(h), the Permittee 

shall maintain monthly records of hours of operation of the emergency diesel 

engine and the fire pump engine. 

(c) To document the compliance status with Conditions D.10.1(g)(3), D.10.2(g)(3) and 

D.10.3, the Permittee shall maintain records of the total amount of fuel used each 

month in the emergency diesel engine and fire pump engine and the total CO2e

emissions from the emergency diesel engine and fire pump engine. 

(e) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition.

D.10.5 Reporting Requirements

A quarterly summary of the information to document the compliance status with 

Conditions D.10.1(e)(2) and D.10.2(e)(2) 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.
IPL Eagle Valley Gen. Station Page 64 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION D.11 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: Insignificant Activities

(e) One (1) evaporative cooling tower, identified as emission unit U-7, rated with a 

circulation rate of 192,000 gpm to provide non-contact cooling water to the steam 

turbine condenser, permitted in 2013, and equipped with high efficiency drift eliminators. 

 

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

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

D.11.1 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 

(Prevention of Significant Deterioration (PSD)), the Best Available Control Technologies 

(BACT) for the cooling water, identified as EU-7 shall be as follows:

(a) The PM, PM10 and PM2.5 emissions from the Cooling Tower, identified as U-7 shall 

be controlled by High efficiency drift eliminators designed with a drift loss rate of 

less than 0.0005% and maximum total dissolved solids (TDS) shall be less than 

5000 ppm.

(b) The PM, PM10 and PM2.5 emissions from the Cooling Tower shall be less than 2.4, 

1.5 and 0.005 pounds per hour, respectively. 

Compliance Determination

D.11.2 PM, PM10 and PM2.5 Control

(a) In order to ensure compliance with Conditions D.11.1 - PM and 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.

(b) The Permittee shall perform monthly tests of the blow-down water quality using 

EPA-approved method. This monthly test shall not be required for any 30-day 

period in which the wet cooling tower is not in operation, provided that the 

Permittee maintains a log of wet cooling tower operation.

(c) The Permittee shall calculate the PM, PM10, and PM2.5 emission rates using an 

equation based on the TDS and water circulation rate using the following formula. 

E = (c x T x Q x 8.34 x 60 x DR) / 106

Where: 

 E = mass emission rate in lbs/hr for PM, PM10 and PM2.5;

 c = particle size fraction (c=1 for PM; 0.635 for PM10 and 0.00213 for PM2.5);

 T = Total Dissolved Solids, mg/l;

Q = Cooling tower circulation rate, gallons/min; and

 DR = Drift rate (assumed to be 0.0005% based on design).
IPL Eagle Valley Gen. Station Page 65 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

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

D.11.3 Record Keeping Requirements

(a) To document the compliance status with Condition D.11.1, the Permittee shall 

maintain a log that contains the date and result of each blow-down water quality 

test and resulting mass rate. This log shall be maintained onsite for a minimum of 

five years and shall be provided to EPA and IDEM upon request. 

(b) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition.
IPL Eagle Valley Gen. Station Page 66 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION D.12 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: Insignificant Activities

(f) Electrical Circuit Breakers containing sulfur hexafluoride (SF6) identified as emissions 

unit F-1, permitted in 2013, with fugitive emissions controlled by full enclosure.

(The information describing the process contained in this emissions unit description box is descriptive 

information and does not constitute enforceable conditions.)

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

D.12.1 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 

(Prevention of Significant Deterioration (PSD)), the Best Available Control Technologies 

(BACT) for the Electrical Circuit Breakers, identified as SF6 shall be as follows:

(1) The use of totally enclosed pressure system with a design leak rate of 0.5% by 

weight and a density alarm for leak detection.

(2) The total SF6 emissions from all the circuit breakers shall not exceed 59.8 tons of 

CO2e per twelve (12) consecutive month period with compliance determined at the 

end of each month.
IPL Eagle Valley Gen. Station Page 67 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION D.13 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: Insignificant Activities

(g) Fugitive equipment leaks from the natural gas supply lines, identified as F-2 controlled 

by a Leak Detection and Repair (LDAR) program.

(The information describing the process contained in this emissions unit description box is 

descriptive information and does not constitute enforceable conditions.)

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

D.13.4 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 

(Prevention of Significant Deterioration (PSD)), the Best Available Control Technologies 

(BACT) for the Fugitive equipment leaks shall be as follows: 

The BACT for fugitive GHG emissions shall be use of Auditory, Visual, and Olfactory (AVO) 

Monitoring program for methane leaks.
IPL Eagle Valley Gen. Station Page 68 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION D.14 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: Insignificant Activities

(h) Three (3) Turbine Lube Demister Vents, permitted in 2013. 

(The information describing the process contained in this emissions unit description box is 

descriptive information and does not constitute enforceable conditions.)

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

D.14.1 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Significant Source Modification 109-32471-00004 and 326 IAC 2-2-3 

(Prevention of Significant Deterioration (PSD)), the Best Available Control Technologies 

(BACT) for the Turbine Lube Oil Demister Vents shall be as follows:

The PM, PM10 and PM2.5 emissions from the Turbine Lube Oil Demister Vents shall be the 

use of good design and operating practices. 
IPL Eagle Valley Gen. Station Page 69 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Change 4: The new emission units and there conditions have been added to Section E.1, E.2, E.3, 

 E.4 and Section G of the permit. 

SECTION E TITLE IV CONDITIONS

Oris Code: 991

Title IV Source Description:

(a) Two (2) no. 2 fuel oil fired boilers, identified as Unit 1 and Unit 2, constructed in 1949 and 1950, 

respectively, each with a design heat input capacity of 524 million Btu per hour (MMBtu/hr), 

both exhausting to stack 1-1.

(b) One (1) tangentially-fired wet-bottom coal boiler, identified as Unit 3, constructed in 1951, with 

a design heat input capacity of 524 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) and flue gas conditioning system for control of particulate matter, exhausting 

to stack 2-1. Unit 3 will combust no. 2 fuel oil during startup, shutdown, and stabilization 

periods. Used oil generated onsite and used oil contaminated materials generated onsite may 

be combusted in Unit 3 as supplemental fuel for energy recovery. Stack 2-1 has continuous 

emission monitoring systems (CEMS) for NOX and SO2 and a continuous opacity monitor 

(COM).

(c) One (1) tangentially-fired dry-bottom coal fired boiler, identified as Unit 4, constructed in 1953, 

with a design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) and flue gas conditioning system for control of particulate matter, exhausting 

to stack 2-1. Unit 4 is equipped with separated overfire air (SOFA) and low NOX burners (LNB) 

for control of NOX emissions, which were voluntarily installed and are not required to operate. 

Unit 4 will combust no. 2 fuel oil during startup, shutdown, and stabilization periods. Stack 2-1 

has continuous emission monitoring systems (CEMS) for NOX and SO2 and a continuous 

opacity monitor (COM).

(d) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 5, constructed in 1953, with a 

design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) and flue gas conditioning system for control of particulate matter, exhausting 

to stack 3-1. Unit 5 is equipped with SOFA and LNB for control of NOX emissions, which were 

voluntarily installed and are not required to operate. Unit 5 will combust no. 2 fuel oil during 

startup, shutdown, and stabilization periods. Stack 3-1 has continuous emission monitoring 

systems (CEMS) for NOX and SO2 and a continuous opacity monitor (COM).

(e) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 6, constructed in 1956, with a 

design heat input capacity of 1017 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) for control of particulate matter, exhausting to stack 3-1. Unit 6 is equipped 

with Closed-coupled Overfire Air (COFA) for control of NOX emissions, which was voluntarily 

installed and is not required to operate. Unit 6 will combust no. 2 fuel oil during startup, 

shutdown, and stabilization periods. Used oil generated onsite may be combusted in Unit 6 as 

supplemental fuel for energy recovery. Unit 6 has had low-NOX burners installed. Stack 3-1 

has continuous emission monitoring systems (CEMS) for NOX and SO2 and a continuous 

opacity monitor (COM).

The New Combined Cycle Combustion Turbine Generation Facility Emission Units:

(k) Two (2) natural gas fired combustion turbine units each with a natural gas fired duct 

burner identified as EU-1 and EU-2, permitted in 2013, each with a total rated heat input 

capacity of 2,542 MMBtu/hr; with NOx emissions controlled by low combustion burner 

design and Selective Catalytic Reduction (SCR), and each with an oxidation catalyst 

system to reduce emissions of CO and VOCs including formaldehyde, and exhausting to 

stacks S-1 and S-2. Each stack has continuous emissions monitors (CEMS) for NOx.
IPL Eagle Valley Gen. Station Page 70 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

*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 and combustion turbines which are a source 

of emissions.

(The information contained in this box is descriptive information and does not constitute enforceable 

conditions.)

Acid Rain Program

E.1.1 Acid Rain Permit [326 IAC 2-7-5(1)(C)] [326 IAC 21] [40 CFR 72 through 40 CFR 78]

Pursuant to 326 IAC 21 (Acid Deposition Control), the Permittee shall comply with all provisions of 

the Acid Rain permit issued for this source, and any other applicable requirements contained in 

40 CFR 72 through 40 CFR 78. The Acid Rain permit for this source is attached to this permit as 

Attachment A, and is incorporated by reference.

E.1.2 Title IV Emissions Allowances [326 IAC 2-7-5(4)] [326 IAC 21]

Emissions exceeding any allowances that the Permittee lawfully holds under the Title IV Acid Rain 

Program of the Clean Air Act are prohibited, subject to the following limitations:

(a) No revision of this permit shall be required for increases in emissions that are authorized 

by allowances acquired under the Title IV Acid Rain Program, provided that such 

increases do not require a permit revision under any other applicable requirement.

(b) No limit shall be placed on the number of allowances held by the Permittee. The 

Permittee may not use allowances as a defense to noncompliance with any other 

applicable requirement.

(c) Any such allowance shall be accounted for according to the procedures established in 

regulations promulgated under Title IV of the Clean Air Act.
IPL Eagle Valley Gen. Station Page 71 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION E.2 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(k) Two (2) natural gas fired combustion turbine units each with a natural gas fired duct 

burner identified as EU-1 and EU-2, permitted in 2013, each with a total rated heat input 

capacity of 2,542 MMBtu/hr; with NOx emissions controlled by low combustion burner 

design and Selective Catalytic Reduction (SCR), and each with an oxidation catalyst 

system to reduce emissions of CO and VOCs including formaldehyde, and exhausting to 

stacks S-1 and S-2. Each stack has continuous emissions monitors (CEMS) for NOx. 

 

*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 and combustion turbines 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.2.1 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 two (2) natural gas combustion turbines EU-1 and EU-2 and two (2) duct burners 

associated with the heat recovery steam generators, except as otherwise specified in 40 

CFR Part 60, Subparts KKKK.

E.2.2 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 two (2) natural gas combustion turbines 

EU-1 and EU-2 and two (2) duct burners associated with the heat recovery steam 

generators 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

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
IPL Eagle Valley Gen. Station Page 72 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION E.3 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(l) One (1) natural gas fired Auxiliary Boiler, identified as emission unit EU-3, permitted in 

2013, with a rated heat input capacity of 79.3 MMBtu/hr, equipped with low NOx burners 

(LNB) with flue gas recirculation (FGR) to reduce NOx emissions exhausting to stack S3. 

(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.3.1 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 natural gas fired auxiliary boiler, except as otherwise specified in 40 CFR Part 60, 

Subpart Dc.

E.3.2 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) 
IPL Eagle Valley Gen. Station Page 73 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION E.4 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(c) One (1) distillate oil fired Emergency Generator, identified as emission unit EU-5, 

permitted in 2013, with a rated capacity of 1,826 HP and exhausting through stack S-5.

[Under 40 CFR 60, Subpart IIII, the Emergency Generator is considered new affected 

sources.][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Generator is considered 

new affected sources.]

(d) One (1) distillate oil fired Emergency Fire Pump, identified as emission unit EU-6, 

permitted in 2013, with a rated capacity of 500 HP and exhausting through stack S-6.

[Under 40 CFR 60, Subpart IIII, the Emergency Fire Pump is considered new affected 

sources.][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Fire Pump is considered 

new affected sources.]

(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.4.1 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 generator and the emergency 

fire pump engine described in this section except when otherwise specified in 40 CFR Part 

60, Subpart IIII.

E.4.2 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 an Attachment in this permit. The source is subject to the 

following portions of Subpart IIII:

The emergency fire pump engine is subject to the following Sections of 40 CFR Part 60, 

Subpart IIII.

1. 40 CFR 60.4200(a)(2)(ii) 

2. 40 CFR 60.4202(d) 

3. 40 CFR 60.4205(c) 

4. 40 CFR 60.4206 

5. 40 CFR 60.4207 

6. 40 CFR 60.4211(a), (c) 

7. 40 CFR 60.4218 

8. 40 CFR 60.4219

The emergency diesel generator is subject to the following Sections of 40 CFR Part 60, 

Subpart IIII.

1. 40 CFR 60.4200(a)(2)(i)

2. 40 CFR 60.4202(a)(2)

3. 40 CFR 60.4205(b)

4. 40 CFR 60.4206 

5. 40 CFR 60.4207

6. 40 CFR 60.4211(a), (c)

7. 40 CFR 60.4218 
IPL Eagle Valley Gen. Station Page 74 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

8. 40 CFR 60.4219
IPL Eagle Valley Gen. Station Page 75 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION E.5 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(c) One (1) distillate oil fired Emergency Generator, identified as emission unit EU-5, 

permitted in 2013, with a rated capacity of 1,826 HP and exhausting through stack S-5.

[Under 40 CFR 60, Subpart IIII, the Emergency Generator is considered new affected 

sources.][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Generator is considered 

new affected sources.]

(d) One (1) distillate oil fired Emergency Fire Pump, identified as emission unit EU-6, 

permitted in 2013, with a rated capacity of 500 HP and exhausting through stack S-6.

[Under 40 CFR 60, Subpart IIII, the Emergency Fire Pump is considered new affected 

sources.][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Fire Pump is considered 

new affected sources.]

(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.5.1 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.5.2 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 63.6590

2. 40 CFR 63.6645
IPL Eagle Valley Gen. Station Page 76 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION F RESERVED Nitrogen Oxides Budget Trading Program - NOX Budget Permit for NOX

Budget Units Under 326 IAC 10-4-1(a)

ORIS Code: 991

NOX Budget Source [326 IAC 2-7-5(15)]

(a) Two (2) no. 2 fuel oil fired boilers, identified as Unit 1 and Unit 2, constructed in 1949 and 1950, 

respectively, each with a design heat input capacity of 524 million Btu per hour (MMBtu/hr), 

both exhausting to stack 1-1.

(b) One (1) tangentially-fired wet-bottom coal boiler, identified as Unit 3, constructed in 1951, with 

a design heat input capacity of 524 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) and flue gas conditioning system for control of particulate matter, exhausting 

to stack 2-1. Unit 3 will combust no. 2 fuel oil during startup, shutdown, and stabilization 

periods. Used oil generated onsite and used oil contaminated materials generated onsite may 

be combusted in Unit 3 as supplemental fuel for energy recovery. Stack 2-1 has continuous 

emission monitoring systems (CEMS) for NOX and SO2 and a continuous opacity monitor 

(COM).

(c) One (1) tangentially-fired dry-bottom coal fired boiler, identified as Unit 4, constructed in 1953, 

with a design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) and flue gas conditioning system for control of particulate matter, exhausting 

to stack 2-1. Unit 4 is equipped with separated overfire air (SOFA) and low NOX burners (LNB) 

for control of NOX emissions, which were voluntarily installed and are not required to operate. 

Unit 4 will combust no. 2 fuel oil during startup, shutdown, and stabilization periods. Stack 2-1 

has continuous emission monitoring systems (CEMS) for NOX and SO2 and a continuous 

opacity monitor (COM).

(d) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 5, constructed in 1953, with a 

design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) and flue gas conditioning system for control of particulate matter, exhausting 

to stack 3-1. Unit 5 is equipped with SOFA and LNB for control of NOX emissions, which were 

voluntarily installed and are not required to operate. Unit 5 will combust no. 2 fuel oil during 

startup, shutdown, and stabilization periods. Stack 3-1 has continuous emission monitoring 

systems (CEMS) for NOX and SO2 and a continuous opacity monitor (COM).

(e) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 6, constructed in 1956, with a 

design heat input capacity of 1017 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) for control of particulate matter, exhausting to stack 3-1. Unit 6 is equipped 

with Closed-coupled Overfire Air (COFA) for control of NOX emissions, which was voluntarily 

installed and is not required to operate. Unit 6 will combust no. 2 fuel oil during startup, 

shutdown, and stabilization periods. Used oil generated onsite may be combusted in Unit 6 as 

supplemental fuel for energy recovery. Unit 6 has had low-NOX burners installed. Stack 3-1 

has continuous emission monitoring systems (CEMS) for NOX and SO2 and a continuous 

opacity monitor (COM).

(The information contained in this box is descriptive information and does not constitute enforceable 

conditions.)

F.1 Automatic Incorporation of Definitions [326 IAC 10-4-7(e)]

This NOX budget permit is deemed to incorporate automatically the definitions of terms under 

326 IAC 10-4-2.

F.2 Standard Permit Requirements [326 IAC 10-4-4(a)]

(a) The owners and operators of the NOX budget source and each budget unit shall operate 

each unit in compliance with this NOX budget permit.
IPL Eagle Valley Gen. Station Page 77 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(b) The NOX budget units subject to this NOX budget permit are Units 1, 2, 3, 4, 5 and 6.

F.3 Monitoring Requirements [326 IAC 10-4-4(b)]

(a) The owners and operators and, to the extent applicable, the NOX authorized account 

representative of the NOX budget source and each NOX budget unit at the source shall 

comply with the monitoring requirements of 40 CFR 75 and 326 IAC 10-4-12.

(b) The emissions measurements recorded and reported in accordance with 40 CFR 75 and 

326 IAC 10-4-12 shall be used to determine compliance by each unit with the NOX budget 

emissions limitation under 326 IAC 10-4-4(c) and Condition F.4, Nitrogen Oxides 

Requirements.

F.4 Nitrogen Oxides Requirements [326 IAC 10-4-4(c)]

(a) The owner and operators of the NOX budget source and each NOX budget unit at the 

source shall hold NOX allowances available for compliance deductions under 

326 IAC 10-4-10(j), as of the NOX allowance transfer deadline, in each boiler’s 

compliance account and the source’s overdraft account in an amount:

(1) Not less than the total NOX emissions for the ozone control period from the unit, 

as determined in accordance with 40 CFR 75 and 326 IAC 10-4-12;

(2) To account for excess emissions for a prior ozone control period under 

326 IAC 10-4-10(k)(5); or

(3) To account for withdrawal from the NOX budget trading program, or a change in 

regulatory status of a NOX budget opt-in unit.

(b) Each ton of NOX emitted in excess of the NOX budget emissions limitation shall constitute 

a separate violation of the Clean Air Act (CAA) and 326 IAC 10-4.

(c) NOX allowances shall be held in, deducted from, or transferred among NOX allowance 

tracking system accounts in accordance with 326 IAC 10-4-9 through 11, 

326 IAC 10-4-13, and 326 IAC 10-4-14.

(d) A NOX allowance shall not be deducted, in order to comply with the requirements under 

(a) above and 326 IAC 10-4-4(c)(1), for an ozone control period in a year prior to the year 

for which the NOX allowance was allocated.

(e) A NOX allowance allocated under the NOX budget trading program is a limited 

authorization to emit one (1) ton of NOX in accordance with the NOX budget trading 

program. No provision of the NOX budget trading program, the NOX budget permit 

application, the NOX budget permit, or an exemption under 326 IAC 10-4-3 and no 

provision of law shall be construed to limit the authority of the U.S. EPA or IDEM, OAQ to 

terminate or limit the authorization.

(f) A NOX allowance allocated under the NOX budget trading program does not constitute a 

property right.

(g) Upon recordation by the U.S. EPA under 326 IAC 10-4-10, 326 IAC 10-4-11, or 

326 IAC 10-4-13, every allocation, transfer, or deduction of a NOX allowance to or from 

each NOX budget unit’s compliance account or the overdraft account or the overdraft 

account of the source where the unit is located is deemed to amend automatically, and 

become a part of, this NOX budget permit of the NOX budget unit by operation of law 

without any further review.

F.5 Excess Emissions Requirements [326 IAC 10-4-4(d)]

The owners and operators of each NOX budget unit that has excess emissions in any ozone 

control period shall do the following:
IPL Eagle Valley Gen. Station Page 78 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(a) Surrender the NOX allowances required for deduction under 326 IAC 10-4-10(k)(5).

(b) Pay any fine, penalty, or assessment or comply with any other remedy imposed under 

326 IAC 10-4-10(k)(7).

F.6 Record Keeping Requirements [326 IAC 10-4-4(e)] [326 IAC 2-7-5(3)]

Unless otherwise provided, the owners and operators of the NOX budget source and each NOX

budget unit at the source shall keep, either on site at the source or at a central location within 

Indiana for unattended sources, each of the following documents for a period of five (5) years: 

(a) The account certificate of representation for the NOX authorized account representative 

for the source and each NOX budget unit at the source and all documents that 

demonstrate the truth of the statements in the account certificate of representation, in 

accordance with 326 IAC 10-4-6(h). The certificate and documents shall be retained 

either on site at the source or at a central location within Indiana for those owners or 

operators with unattended sources beyond the five (5) year period until the documents are

superseded because of the submission of a new account certificate of representation 

changing the NOX authorized account representative.

(b) All emissions monitoring information, in accordance with 40 CFR 75 and 

326 IAC 10-4-12, provided that to the extent that 40 CFR 75 and 326 IAC 10-4-12 provide 

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 NOX budget trading program.

(d) Copies of all documents used to complete a NOX budget permit application and any other 

submission under the NOX budget trading program or to demonstrate compliance with the 

requirements of the NOX budget trading program.

This period may be extended for cause, at any time prior to the end of five (5) years, in writing by 

IDEM, OAQ or the U.S. EPA. Records retained at a central location within Indiana shall be 

available immediately at the location and submitted to IDEM, OAQ or U.S. EPA within three (3) 

business days following receipt of a written request. Nothing in 326 IAC 10-4-4(e) shall alter the 

record retention requirements for a source under 40 CFR 75. 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 10-4-4(e)]

(a) The NOX authorized account representative of the NOX budget source and each NOX

budget unit at the source shall submit the reports and compliance certifications required 

under the NOX budget trading program, including those under 326 IAC 10-4-8, 

326 IAC 10-4-12, or 326 IAC 10-4-13.

(b) Pursuant to 326 IAC 10-4-4(e) and 326 IAC 10-4-6(e)(1), each submission shall include 

the following certification statement by the NOX authorized account representative: “I am 

authorized to make this submission on behalf of the owners and operators of the NOX

budget sources or NOX budget 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 10-4 requires a submission to IDEM, OAQ, the NOX authorized account 

representative shall submit required information to:
IPL Eagle Valley Gen. Station Page 79 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Indiana Department of Environmental Management

Office of Air Quality

100 North Senate Avenue

MC 61-53, IGCN Room 1003

Indianapolis, Indiana 46204-2251

(d) Where 326 IAC 10-4 requires a submission to U.S. EPA, the NOX authorized account 

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 10-4-4(f)]

The owners and operators of each NOX budget source shall be liable as follows:

(a) Any person who knowingly violates any requirement or prohibition of the NOX budget 

trading program, a NOX budget permit, or an exemption under 326 IAC 10-4-3 shall be 

subject to enforcement pursuant to applicable state or federal law.

(b) Any person who knowingly makes a false material statement in any record, submission, 

or report under the NOX budget trading program shall be subject to criminal enforcement 

pursuant to the applicable state or federal law.

(c) No permit revision shall excuse any violation of the requirements of the NOX budget 

trading program that occurs prior to the date that the revision takes effect.

(d) Each NOX budget source and each NOX budget unit shall meet the requirements of the 

NOX budget trading program.

(e) Any provision of the NOX budget trading program that applies to a NOX budget source, 

including a provision applicable to the NOX authorized account representative of a NOX

budget source, shall also apply to the owners and operators of the source and the NOX

budget units at the source.

(f) Any provision of the NOX budget trading program that applies to a NOX budget unit, 

including a provision applicable to the NOX authorized account representative of a NOX

budget unit, shall also apply to the owners and operators of the unit. Except with regard 

to the requirements applicable to units with a common stack under 40 CFR 75 and 

326 IAC 10-4-12, the owners and operators and the NOX authorized account 

representative of one (1) NOX budget unit shall not be liable for any violation by any other 

NOX budget unit of which they are not owners or operators or the NOX authorized account 

representative and that is located at a source of which they are not owners or operators or 

the NOX authorized account representative.

F.9 Effect on Other Authorities [326 IAC 10-4-4(g)]

No provision of the NOX budget trading program, a NOX budget permit application, a NOX budget 

permit, or an exemption under 326 IAC 10-4-3 shall be construed as exempting or excluding the 

owners and operators and, to the extent applicable, the NOX authorized account representative a 

NOX budget source or NOX budget unit from compliance with any other provision of the applicable, 

approved state implementation plan, a federally enforceable permit, or the CAA.
IPL Eagle Valley Gen. Station Page 80 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

SECTION G Clean Air Interstate Rule (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)

ORIS Code: 991

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)

(a) Two (2) no. 2 fuel oil fired boilers, identified as Unit 1 and Unit 2, constructed in 1949 and 1950, 

respectively, each with a design heat input capacity of 524 million Btu per hour (MMBtu/hr), both 

exhausting to stack 1-1.

(b) One (1) tangentially-fired wet-bottom coal boiler, identified as Unit 3, constructed in 1951, with a 

design heat input capacity of 524 million Btu per hour (MMBtu/hr), with an electrostatic precipitator 

(ESP) and flue gas conditioning system for control of particulate matter, exhausting to stack 2-1. 

Unit 3 will combust no. 2 fuel oil during startup, shutdown, and stabilization periods. Used oil 

generated onsite and used oil contaminated materials generated onsite may be combusted in Unit 

3 as supplemental fuel for energy recovery. Stack 2-1 has continuous emission monitoring 

systems (CEMS) for NOX and SO2 and a continuous opacity monitor (COM).

(c) One (1) tangentially-fired dry-bottom coal fired boiler, identified as Unit 4, constructed in 1953, 

with a design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) and flue gas conditioning system for control of particulate matter, exhausting to 

stack 2-1. Unit 4 is equipped with separated overfire air (SOFA) and low NOX burners (LNB) for 

control of NOX emissions, which were voluntarily installed and are not required to operate. Unit 4 

will combust no. 2 fuel oil during startup, shutdown, and stabilization periods. Stack 2-1 has 

continuous emission monitoring systems (CEMS) for NOX and SO2 and a continuous opacity 

monitor (COM).

(d) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 5, constructed in 1953, with a 

design heat input capacity of 741 million Btu per hour (MMBtu/hr), with an electrostatic precipitator 

(ESP) and flue gas conditioning system for control of particulate matter, exhausting to stack 3-1. 

Unit 5 is equipped with SOFA and LNB for control of NOX emissions, which were voluntarily 

installed and are not required to operate. Unit 5 will combust no. 2 fuel oil during startup, 

shutdown, and stabilization periods. Stack 3-1 has continuous emission monitoring systems 

(CEMS) for NOX and SO2 and a continuous opacity monitor (COM).

(e) One (1) tangentially-fired dry-bottom coal boiler, identified as Unit 6, constructed in 1956, with a 

design heat input capacity of 1017 million Btu per hour (MMBtu/hr), with an electrostatic 

precipitator (ESP) for control of particulate matter, exhausting to stack 3-1. Unit 6 is equipped 

with Closed-coupled Overfire Air (COFA) for control of NOX emissions, which was voluntarily 

installed and is not required to operate. Unit 6 will combust no. 2 fuel oil during startup, shutdown, 

and stabilization periods. Used oil generated onsite may be combusted in Unit 6 as supplemental 

fuel for energy recovery. Unit 6 has had low-NOX burners installed. Stack 3-1 has continuous 

emission monitoring systems (CEMS) for NOX and SO2 and a continuous opacity monitor (COM).

The New Combined Cycle Combustion Turbine Generation Facility Emission Units:

(k) Two (2) natural gas fired combustion turbine units each with a natural gas fired duct 

burner identified as EU-1 and EU-2, permitted in 2013, each with a total rated heat input 

capacity of 2,542 MMBtu/hr; with NOx emissions controlled by low combustion burner 

design and Selective Catalytic Reduction (SCR), and each with an oxidation catalyst 

system to reduce emissions of CO and VOCs including formaldehyde, and exhausting to 

stacks S-1 and S-2. Each stack has continuous emissions monitors (CEMS) for NOx. 

 

*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 
IPL Eagle Valley Gen. Station Page 81 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

conjunction with the duct burners and combustion turbines which are a source of 

emissions.

(The information describing the process contained in this facility description box is descriptive information 

and does not constitute enforceable conditions.)

G.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.

G.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 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 shall operate each source and 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 1, 2, 3, 4, 5 and 6. 

G.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 

applicable monitoring, reporting, and record keeping requirements of 326 IAC 24-1-11, 

326 IAC 24-2-10, and 326 IAC 24-3-11.

(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 G.4.1, Nitrogen Oxides Emission 

Requirements, Condition G.4.2, Sulfur Dioxide Emission Requirements, and Condition 

G.4.3, Nitrogen Oxides Ozone Season Emission Requirements.

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

(a) As of the allowance transfer deadline for a control period, 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 326 IAC 24-1-4(c)(1) for the 

control period starting on the applicable date, as determined under 326 IAC 24-1-4(c)(2), 

and for each control period thereafter.

(c) A CAIR NOX allowance shall not be deducted for compliance with the requirements under 

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.
IPL Eagle Valley Gen. Station Page 82 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(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.

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

(a) As of the allowance transfer deadline for a control period, 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.

(b) A CAIR SO2 unit shall be subject to the requirements under 326 IAC 24-2-4(c)(1) for the 

control period starting on the applicable date, as determined under 326 IAC 24-2-4(c)(2), 

and for each control period thereafter.

(c) A CAIR SO2 allowance shall not be deducted for compliance with the requirements under 

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.

G.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 for a control period, 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 ozone season unit shall be subject to the requirements under 

326 IAC 24-3-4(c)(1) for the control period starting on the applicable date, as determined 

under 326 IAC 24-3-4(c)(2), and for each control period thereafter.
IPL Eagle Valley Gen. Station Page 83 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(c) A CAIR NOX ozone season allowance shall not be deducted for compliance with the 

requirements under 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 ozone season 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 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 ozone season 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.

G.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)]

(a) 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:

(1) Surrender the CAIR NOX allowances required for deduction under 

326 IAC 24-1-9(j)(4).

(2) 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.

(b) 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:

(1) Surrender the CAIR SO2 allowances required for deduction under 

326 IAC 24-2-8(k)(4).

(2) 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.

(c) 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:

(1) Surrender the CAIR NOX ozone season allowances required for deduction under 

326 IAC 24-3-9(j)(4).
IPL Eagle Valley Gen. Station Page 84 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(2) 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.

G.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.

G.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.
IPL Eagle Valley Gen. Station Page 85 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

(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 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 information 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

(d) Where 326 IAC 24-1, 326 IAC 24-2, and 326 IAC 24-3 requires a submission to U.S. 

EPA, the information shall be submitted to:

U.S. Environmental Protection Agency

Clean Air Markets Division

1200 Pennsylvania Avenue, NW

Mail Code 6204N

Washington, DC 20460

G.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, respectively. 

(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 NOX

unit, CAIR SO2 unit, and CAIR NOX ozone season unit shall also apply to the owners and 

operators of such unit.
IPL Eagle Valley Gen. Station Page 86 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

G.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, CAIR SO2

unit, and CAIR NOX ozone season unit from compliance with any other provision of the 

applicable, approved state implementation plan, a federally enforceable permit, or the Clean Air 

Act (CAA).

G.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), 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.

Except as specified in 326 IAC 24-1-6(f)(3), 326 IAC 24-2-6(f)(3), 326 IAC 24-3-6(f)(3), whenever 

the term "CAIR designated representative" is used, the term shall be construed to include the 

CAIR designated representative or any alternate CAIR designated representative.
IPL Eagle Valley Gen. Station Page 87 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Change 5: New reporting forms have been added to the permit and some of the reporting forms will 

 be deleted after the removal of the boilers. 

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY

COMPLIANCE DATA SECTION

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Mailing Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Units 1, 2, and PR-10

Parameter: SO2 Emissions

Limit: Shall not exceed the pound per million Btu (lb/MMBtu) limit, demonstrated using a 

calendar month average

YEAR: 

Emission Unit Limit 

(lb/MMBtu)

SO2 Emissions (lb/MMBtu)

Month:

 

Month:

 

Month:

 

Unit 1 0.37 

Unit 2 0.37 

Unit PR-10 0.5 

No deviation occurred in this quarter.

Deviations occurred in this quarter.

Deviation has been reported on: 

Submitted By: 

Title/Position: 

Signature: 

Date: 

Phone: 

Attach a signed certification to complete this report.

Note: The Part 70 quarterly reporting form shall no longer apply to the distillate fuel oil fired 

generator, identified as PR-10 and the two No. 2 fuel oil fired boilers identified as Units 1 

and 2 after the emission units have been shut down and decommissioned. 
IPL Eagle Valley Gen. Station Page 88 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY

COMPLIANCE DATA SECTION

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Mailing Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Units 3, 4, 5, and 6

Parameter: SO2 Emissions

Limit: Shall not exceed the pound per million Btu (lb/MMBtu) limit, demonstrated using a 

30-day rolling average

YEAR: QUARTER:

Date Limit 

(lb/MMBtu)

Daily 

Average

Weight 

Factor

30-day Rolling 

Average Remarks

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

13.

14.

15.

16.

17.

18.

19.

20.

21.

22.

23.

24.

25.

26.

27.

28.

29.

30.

No deviation occurred in this quarter.

Deviations occurred in this quarter.

Deviation has been reported on:

Submitted By:
IPL Eagle Valley Gen. Station Page 89 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Title/Position:

Signature:

Date:

Phone:

Attach a signed certification to complete this report.

 

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Combined Cycle Combustion Turbines EU-1 - EU-2 

Parameter: NOx Emissions

Limit: shall not exceed 68 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: 
IPL Eagle Valley Gen. Station Page 90 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Phone: 

 

 

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Combined Cycle Combustion Turbines EU-1 - EU-2 

Parameter: CO Emissions

Limit: shall not exceed 565 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: 

 

 
IPL Eagle Valley Gen. Station Page 91 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Combined Cycle Combustion Turbines EU-1 - EU-2 

Parameter: VOC Emissions

Limit: shall not exceed 146 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: 

 

 
IPL Eagle Valley Gen. Station Page 92 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Combined Cycle Combustion Turbine EU-1 - EU-2 

Parameter: CO2e 

Limit: shall not exceed 2,649,570 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: 

 

 

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report
IPL Eagle Valley Gen. Station Page 93 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Auxiliary Boiler EU-3 

Parameter: CO2e

Limit: shall not exceed 40,639 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: 

 

 

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Dew Point Heater EU-4 

Parameter: CO2e

Limit: shall not exceed 10,569 tons per twelve (12) consecutive month period with 

 compliance determined at the end of each month.
IPL Eagle Valley Gen. Station Page 94 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

 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: 

 

 

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Emergency Generator EU-5 

Parameter: CO2e

Limit: shall not exceed 605 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
IPL Eagle Valley Gen. Station Page 95 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

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: 

 

 

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Fire Pump Engine EU-6 

Parameter: CO2e

Limit: shall not exceed 157.5 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
IPL Eagle Valley Gen. Station Page 96 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

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: 

 

 

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Source Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109-26292-00004

Facility: Combined Cycle Combustion Turbines EU-1 - EU-2 

Parameter: Single HAPs Emissions (Formaldehyde) 

Limit: less than 9 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.
IPL Eagle Valley Gen. Station Page 97 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

 Deviation has been reported on: 

Submitted by: 

Title / Position: 

Signature: 

Date: 

Phone: 

Other Changes

Upon further review IDEM, OAQ has made the following changes to the Title V permit T109-26292-

00004. (deleted language appears as strikout and the new language bolded):

Change 1: Upon re-designation of Morgan County as attainment Country on July 11, 2013, IDEM has 

revised Section A.2 - General Information with respect to the re-designation.

A.1 General Information [326 IAC 2-7-4(c)] [326 IAC 2-7-5(15)] [326 IAC 2-7-1(22)]

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

Source Address: 4040 Blue Bluff Road, Martinsville, Indiana, 46151

Mailing Address: 4040 Blue Bluff Road, Martinsville, Indiana, 46151

Source Telephone: 765-349-3413

SIC Code: 4911

County Location: Morgan

County Status: Nonattainment for PM2.5

Attainment for all other criteria pollutants

Source Status: Part 70 Operating Permit Program

Major Source, under PSD Rules and Nonattainment NSR; 

Major Source, Section 112 of the Clean Air Act

1 of 28 Source Categories

Change 2: IDEM OAQ has replaced Condition C.11 - Compliance Monitoring with the updated 

version. 

C.11 Compliance Monitoring [326 IAC 2-7-5(3)] [326 IAC 2-7-6(1)]

(a) For new units:

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

compliance monitoring for new emission units shall be implemented on and after 

the data of start-up.

(b) For existing units:

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 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 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 
IPL Eagle Valley Gen. Station Page 98 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004 

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

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(35).

(c) For monitoring required by CAM, at all times, the Permittee shall maintain the 

monitoring, including but not limited to, maintaining necessary parts for routine 

repairs of the monitoring equipment.

(d) For monitoring required by CAM, except for, as applicable, monitoring 

malfunctions, associated repairs, and required quality assurance or control 

activities (including, as applicable, calibration checks and required zero and span 

adjustments), the Permittee shall conduct all monitoring in continuous operation 

(or shall collect data at all required intervals) at all times that the pollutant-specific 

emissions unit is operating. Data recorded during monitoring malfunctions, 

associated repairs, and required quality assurance or control activities shall not be 

used for purposes of this part, including data averages and calculations, or 

fulfilling a minimum data availability requirement, if applicable. The owner or 

operator shall use all the data collected during all other periods in assessing the 

operation of the control device and associated control system. 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.

Unless otherwise specified in this permit, all monitoring and record keeping requirements not 

already legally required shall be implemented within ninety (90) days of permit issuance. If 

required by Section D, the Permittee shall be responsible for installing any necessary equipment 

and initiating any required monitoring related to that equipment. If due to circumstances beyond 

its control, that equipment cannot be installed and operated within ninety (90) days, 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 the certification by the 

“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.

 

Conclusion and Recommendation

The construction and operation of this proposed modification shall be subject to the conditions of 

the attached proposed PSD/Part 70 Significant Source Modification No. 109-32471-00004 and 

Significant Permit Modification No. 109-32476-00004. The staff recommends to the 

Commissioner that this Part 70 Significant Source and Significant Permit Modification be 

approved.
IPL Eagle Valley Gen. Station Page 99 of 99

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

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
Emission Unit MW output MMBtu/hr IPL Eagle Valley Page 1 of 11 TSD Appx A

CT-1 EU-1 2463

CT-1 w/ Duct Burner 2542

CT-2 EU-2 2463

CT-2 w/ Duct Burner 2542

Aux. Boiler EU-3 79.3 Basis for Emisison Factors

Dew Point Heater EU-4 20.8 Proposed permit Limits Based On 

AP-42

HP MMBtu/hr 40 CFR Part 98; Tables A-1, C-1 

Fire Pump Engine EU-5 500 3.85

Emergency generator EU-6 1826 14.8

Units NOx CO VOC SO2 PM PM10 PM2.5 H2SO4 Fluorides Lead Mercury CO2 CH4 N2O

ppmv 2 2 2

lbs/hr 18.9 14.4 8.99 3.55 16.78 16.78 16.78 2.06 306,306 5.60 0.56

lbs/MMBtu 0.0014 0.0066 0.0066 0.0066 0.00081 2.20E-03 2.20E-04

lbs/hr 18.6 11.3 3.25 3.45 13.55 13.55 13.55 1.47 301,647 5.43 0.54

lbs/MMBtu 0.0014 0.0055 0.0055 0.0055 0.00060 2.20E-03 2.20E-04lbs/MMBtu 0.011 0.082 0.0053 0.0014 0.005 0.005 0.005 0.000107 2.55E-07 117 2.20E-03 2.20E-04

lbs/hr 0.87 6.50 0.42 0.11 0.40 0.40 0.40 0.00850 2.02E-05

lbs/MMBtu 0.032 0.082 0.0053 0.0014 0.0072 0.0072 0.0072 0.000107 2.55E-07 117 2.20E-03 2.20E-04

lbs/hr 0.67 1.71 0.11 0.029 0.150 0.150 0.150 0.00223 5.30E-06

lbs/MMBtu 0.831 0.745 0.029 0.0015 0.043 0.043 0.043 0.000115 163 6.61E-03 1.32E-03

lbs/hr 3.20 2.87 0.11 0.0060 0.17 0.17 0.17 0.00044

lbs/MMBtu 1.27 0.709 0.027 0.0015 0.043 0.043 0.043 0.000115 163 6.61E-03 1.32E-03

lbs/hr 18.8 10.50 0.40 0.022 0.64 0.6 0.6 0.00170

Lube Oil Demister Vents lbs/hr/vent 0.0174 0.0174 0.0174

1 21 310 23,900

Emission Unit Hours/ Year NOx CO VOC SO2 PM PM10 PM2.5 H2SO4 Fluorides Lead Mercury CO2 CH4 N2O SF6 CO2e CT-1 w/duct firing 1000 9.5 7.2 4.5 1.8 8.4 8.4 8.4 1.0 153,153 2.80 0.28 153,299 CT-1 w/o duct firing 7760 72.2 43.8 12.6 13.4 52.6 52.6 52.6 5.7 1,170,390 21.07 2.11 1,171,486 CT-2 w/duct firing 1000 9.5 7.2 4.5 1.8 8.4 8.4 8.4 1.0 153,153 2.80 0.28 153,299 CT-2 w/o duct firing 7760 72.2 43.8 12.6 13.4 52.6 52.6 52.6 5.7 1,170,390 21.07 2.11 1,171,486 Auxiliary Boiler 8760 3.8 28.5 1.8 0.5 1.7 1.7 1.7 0.04 0.0001 40,599 0.77 0.08 40,639 Dew Point Heater 8760 2.92 7.47 0.48 0.13 0.66 0.66 0.66 0.010 0.000023 10,649 0.20 0.02 10,659 Fire Pump 500 0.80 0.72 0.03 0.0015 0.041 0.041 0.041 156.94 0.0064 0.0013 157.47 Emergency Generator 500 4.70 2.63 0.10 0.01 0.16 0.15 0.15 603.29 0.0245 0.0049 605.32 Cooling Towers 8760 10.5 6.7 0.020

Paved Roads/Parking 8760 0.216 0.043 0.011

Potential to Emit, Tons/Year

656 MW 

nominal capacity

Global Warming Potentials

Emission Factors

Emergency Generator

per CT NG w/o duct 

firing

per CT NG w duct firing

Fire Pump Engine

Aux Boiler

Dew Point Heater

Paved Roads/Parking 8760 0.216 0.043 0.011Methane leaks 8760 69.85 1466.9Circuit Breakers 8760 0.0025 59.83 Lube Oil vents 8760 0.229 0.229 0.229

175.5 141.4 36.7 30.9 135.4 131.5 124.7 13.5 0.0 0.000 0.00011 2,699,095 118.6 4.9 0.003 2,703,157 

CCCT Subtotal 163.2 102.1 34.2 30.3 121.9 121.9 121.9 13.5 0.0 0.000 0.00 2,647,087 47.7 4.8 0.0 2,649,569 

40 100 40 40 25 15 10 7 3 0.6 0.1 NA NA NA NA 75,000

Totals

SD/NNSR Significance Threshold, tons/yea
Potential to Emit, 8760 Hours: Non-Normal Load Operation (cold, warm, hot starts and shutdown conditions) Page 2 of 11 TSD Appx A

NOx CO VOC NOx CO VOC

CT-1 @100% load w/ duct firing 1000 18.9 12.6 8.99 9.5 6.3 4.5 NOx CO VOCCT-1 @ 100% Load w/o duct firing 3863.0 18.4 11.2 3.25 35.5 21.6 6.3 Cold Start 428.6 3390.0 996.8CT-1 Cold Starts 16 225 72 60.0 114.3 904 265.8 3.4 27.1 8.0 Warm Start 220.2 1885.2 481.0CT-1 Warm Starts 260 119 8 515.7 111 950.5 242.5 28.6 245.1 62.5 Hot Start 34.5 308.8 50.3

CT-1 Hot Starts 10 50 0 8.3 41.4 370.6 60.3 0.2 1.5 0.3 Shut Down 10.7 61.9 17.1

CT-1 Shutdown 286 17 81.0 37.9 218.3 60.4 1.5 8.8 2.4CT-1 Annual Total 78.7 310.5 84.0CT-2 @100% load w/ duct firing 1000 18.9 12.6 8.99 9.5 6.3 4.5CT-2 @ 100% Load w/o duct firing 3863.0 18.4 11.2 3.25 35.5 21.6 6.3CT-2 Cold Starts 16 225 72 60.0 114.3 904 265.8 3.4 27.1 8.0

CT-2 Warm Starts 260 119 8 515.7 111 950.5 242.5 28.6 245.1 62.5

CT-2 Hot Starts 10 50 0 8.3 41.4 370.6 60.3 0.2 1.5 0.3

CT-2 Shutdown 286 17 81.0 37.9 218.3 60.4 1.5 8.8 2.4CT-2 Annual Total 78.7 310.5 84.0CT-1 & CT-2 Total 157.5 621.0 167.9CT-1 & CT-2 Startup Shutdown Total 67.5 565.2 146.4

Potential to Emit, 8760 Hours: Non-Normal Load Operation (cold, warm, hot starts and shutdown conditions) Cas

NOx CO VOC NOx CO VOC

CT-1 @100% load w/ duct firing 1000 18.9 12.6 8.99 9.5 6.3 4.5CT-1 @ 100% Load w/o duct firing 4072.3 18.4 11.2 3.25 37.5 22.8 6.6 CT-1 Cold Starts 5 229 72 19.1 114.3 1295 1686 1.1 12.4 16.1CT-1 Warm Starts 260 123 10 533.0 111 1363 1538 29.6 363.2 409.9

CT-1 Hot Starts 10 71 4 11.8 41.4 527.7 794 0.2 3.1 4.7

CT-1 Shutdown 275 27 123.8 37.9 245.8 671 2.3 15.2 41.5

CT-1 Annual Total 80.2 423.0 483.3CT-2 @100% load w/ duct firing 1000 18.9 12.6 8.99 9.5 6.3 4.5CT-2 @ 100% Load w/o duct firing 4072.3 18.4 11.2 3.25 37.5 22.8 6.6CT-2 Cold Starts 5 229 72 19.1 114.3 1295 1686 1.1 12.4 16.1CT-2 Warm Starts 260 123 10 533.0 111 1363 1538 29.6 363.2 409.9

CT-2 Hot Starts 10 71 4 11.8 41.4 527.7 794 0.2 3.1 4.7

CT-2 Shutdown 275 27 123.8 37.9 245.8 671 2.3 15.2 41.5

CT-2 Annual Total 80.2 423.0 483.3CT-1 & CT-2 Total 160.4 846.1 966.6

CT-1 & CT-2 Startup Shutdown Tota 66.5 787.9 944.4

Emission Reductions From Shutdown of Existing Units 1-6 (based on 2010 and 2011 Actual Emissions) Basis for Emission Factors

CEMs DataAP-4240 CFR Part 98 

644,000 tons coal in 2010 Coal Heating Value 11,200 BTU/lb Stack Test Data538,000 tons coal in 2011 Fuel Oil Heating Value 140,000 Btu/gal Mass balance

Hours 

Down/ event Emissions per event, lbs

Global Warming Pote

PTE, tons/year

PTE, tons/year

Hours Down/ Emission Rate, lbs/hour

event

Emission Rate, lbs/hour Minutes/ 

Event Emission Unit Events/ year Hours/ year

Minutes/ Event Hours/ year Emission Unit Events/ year

1 21 

NOx CO VOC SO2 CPM PM, filt, Controlled PM10, filt, Controlled PM10 Total, Controlled PM2.5, filt, controlled PM2.5, Total Controlled H2SO4 Fluorides Lead Mercury CO2 CH4 

Boiler 1 (Oil) 0.0357 0.00543 0.00929 0.0143 0.0071 0.0164 0.0017 0.0110 0.00249 9.00E-06 3.00E-06 0.00661 

Boiler 2 (Oil) 0.0357 0.00543 0.00929 0.0143 0.0071 0.0164 0.0017 0.0110 0.00249 9.00E-06 3.00E-06 0.00661 

Boiler 3 (Coal) Wet Bottom 0.0223 0.0018 0.196 0.058 0.0435 0.2395 0.0232 0.2192 0.014 0.0067 1.88E-05 3.71E-06 0.02425 

Boiler 4 (Coal) Dry Bottom 0.0223 0.0027 0.196 0.058 0.03886 0.23486 0.01682 0.21282 0.014 0.0067 1.88E-05 3.71E-06 0.02425 Boiler 5 (Coal) Dry Bottom 0.0223 0.0027 0.196 0.085 0.05695 0.25295 0.02465 0.22065 0.014 0.0067 1.88E-05 3.71E-06 0.02425 Boiler 6 (Coal) Dry Bottom 0.0223 0.0027 0.196 0.085 0.05695 0.25295 0.02465 0.22065 0.014 0.0067 1.88E-05 3.71E-06 0.02425 

NOx CO VOC SO2 CPM PM, filt, Controlled PM10, filt, Controlled PM10 Total, Controlled PM2.5, filt, controlled PM2.5, Total Controlled H2SO4 Fluorides Lead Mercury CO2 CH4 

Boiler 1 (Oil) 40,435 2.10 0.72 0.11 0.7 0.19 0.29 0.14 0.33 0.035 0.22 0.050 0.00018 0.00006 3,282 0.13 Boiler 2 (Oil) 40,049 2.80 0.72 0.11 0.7 0.19 0.29 0.14 0.33 0.034 0.22 0.050 0.00018 0.00006 3,248 0.13 

Boiler 3 (Coal) 1,222,378 13.64 1.09 119.8 35.4 26.6 146.4 14.2 134.0 8.6 4.1 0.0115 0.0023 14.82 Boiler 4 (Coal) 3,031,974 33.84 4.06 297.1 87.9 58.9 356.0 25.5 322.6 21.2 10.2 0.0284 0.0056 36.76 Boiler 5 (Coal) 2,833,621 31.63 3.80 277.7 120.4 80.7 358.4 34.9 312.6 19.8 9.5 0.0266 0.0052 34.36 Boiler 6 (Coal) 5,025,518 56.09 6.73 492.5 213.6 143.1 635.6 61.9 554.4 35.2 16.8 0.0471 0.0093 60.94 

Totals 1,767.3 136.6 15.9 12,265.7 1,187.5 458.0 309.6 1,497.1 136.6 1,324.1 84.9 40.6 0.11 0.023 1,249,371 147.1 

806,346 

CEMS Data

Emission Factors, lbs/MMBtu

436,495

2010 Annual Emissions, Tons 

798.40 4,199.3964.00 8,065.0

CEMs 

Data CEMs Data

Emission Unit MMBtu/yearEmission Unit

lbs/MMBtu

Units
NOx CO VOC SO2 CPM PM, filt, Controlled PM10, filt, Controlled PM10 Total, Controlled PM2.5, filt, controlled PM2.5, Total Controlled H2SO4 Fluorides Lead Mercury CO2 CH4 

Boiler 1 (Oil) 19,636 1.1 0.35 0.053 0.300 0.09 0.14 0.070 0.161 0.017 0.108 0.024 0.000088 0.000029 1,593.1 0.065 Boiler 2 (Oil) 20,531 1.5 0.37 0.056 0.300 0.10 0.15 0.073 0.169 0.018 0.113 0.026 0.000092 0.000031 1,665.5 0.068 

Boiler 3 (Coal) 1,338,811 14.94 1.20 131.20 38.83 29.12 160.32 15.53 146.73 9.37 4.5 0.0126 0.0025 16.23 Boiler 4 (Coal) 2,782,533 31.06 3.73 272.69 80.69 54.06 326.75 23.40 296.09 19.48 9.3 0.0261 0.0052 33.74 Boiler 5 (Coal) 1,989,529 22.20 2.66 194.97 84.55 56.65 251.63 24.52 219.49 13.93 6.7 0.0187 0.0037 24.12 Boiler 6 (Coal) 4,748,933 53.00 6.36 465.40 201.83 135.23 600.62 58.53 523.93 33.24 15.9 0.0445 0.0088 57.58 

Totals 1,795.9 121.9 14.1 10,874.7 1,064.4 406.2 275.2 1,339.7 122.0 1,186.5 76.1 36.4 0.102 0.020 1,117,474.6 131.8 

1,782 129.3 15.0 11,570 1,126 432 292 1,418 129 1,255 80.5 38.5 0.108 0.021 1,183,423 139 

NOx CO VOC SO2 CPM PM, filterable PM10, filt, Controlled PM10 Total PM2.5, filt, controlled PM2.5, Total H2SO4 Fluorides Lead Mercury CO2 CH4 

New equipment PTE 175.5 660.3 170.4 30.9 135.4 131.5 124.7 13.5 0.00000 0.000 0.000 2699095.0 118.6 

Shutdown Credits -1,782 -129 -15 -11,570 -432 -1,418 -1,255 -80 -38 -0.11 -0.021 -1,183,423 -139 

Net Emissions Increase/Decrease -1,606 531.0 155 -11,539 -297 -1,287 -1,131 -67 -38 -0.11 -0.021 1,515,672 -21 

40 100 40 40 NA 25 NA 15 NA 10 7 3 0.6 0.1 NA NA 

NOx CO VOC SO2 PM, filterable PM10 Total PM2.5, Total H2SO4 Fluorides Lead Mercury CO2e

New Equipment PTE 175.5 660.3 170.4 30.9 135.4 131.5 124.7 13.5 0.000 0.0000 0.0001 2,703,157

Reduction s from 

Shutdown of existing 

units

-1782 -129.3 -15.0 -11570 -432.1 -1418 -1255.3 -80.5 -38.5 -0.1080 -0.0214 -1,192,644

Net Emissions Change -1606 531.0 155.4 -11539 -296.6 -1287 -1130.5 -67.0 -38.5 -0.1080 -0.0213 1,510,513

PSD/NNSR Significance 

Thresholds 40 100 40 40 25 15 10 7 3 0.6 0.1 75,000

6,720.2 

20111 Annual Emissions, Tons 

838.2 4,153.9 422,848.4

Emission Unit Rated capacity, MMBtu/hr

Tons/year

PSD/NNSR Significance Threshold, tons/year

955.1

2010/2011 Average Emissions, tons

Emissions, tons/year

691,367.6

Project Net Emission 

Increase (Decrease) (Based 

on Basecase)
Page 4 of 11 TSD Appx A

1826 HP Emergency RICE 14.8 MMBtu/hr 500 HP Fire Pump RICE 3.85 MMBtu/hr

Benzene 7.76E-04 2.87E-03 Benzene 9.33E-04 8.98E-04

Toluene 2.81E-04 1.04E-03 Toluene 4.09E-04 3.94E-04

Xylenes 1.93E-04 7.14E-04 Xylenes 2.85E-04 2.74E-04

Formaldehyde 7.89E-05 2.92E-04 1,3-Butadiene 3.91E-05 3.76E-05

Acetaldehyde 2.52E-05 9.32E-05 Formaldehyde 1.18E-03 1.14E-03

Acrolein 7.88E-06 2.92E-05 Acetaldehyde 7.67E-04 7.38E-04

Naphthalene 1.30E-04 4.81E-04 Acrolein 9.25E-05 8.90E-05

Acenaphthylene 9.23E-06 3.42E-05 Naphthalene 8.48E-05 8.16E-05

Acenaphthene 4.68E-06 1.73E-05 Acenaphthylene 5.06E-06 4.87E-06

Fluorene 1.28E-05 4.74E-05 Acenaphthene 1.42E-06 1.37E-06

Phenanthrene 4.08E-05 1.51E-04 Fluorene 2.92E-05 2.81E-05

Anthracene 1.23E-06 4.55E-06 Phenanthrene 2.94E-05 2.83E-05

Fluoranthrene 4.03E-06 1.49E-05 Anthracene 1.87E-06 1.80E-06

Pyrene 3.71E-06 1.37E-05 Fluoranthrene 7.61E-06 7.32E-06

Benz(a)anthracene 6.22E-07 2.30E-06 Pyrene 4.78E-06 4.60E-06

Chrysene 1.53E-06 5.66E-06 Benz(a)anthracene 1.68E-06 1.62E-06

Benzo(b)fluoranthrene 1.11E-06 4.11E-06 Chrysene 3.53E-07 3.40E-07

Benzo(k)fluoranthrene 2.18E-07 8.07E-07 Benzo(b)fluoranthrene 9.91E-08 9.54E-08

Benzo(a)pyrene 2.57E-07 9.51E-07 Benzo(k)fluoranthrene 1.55E-07 1.49E-07

Indeno(1,2,3-cd)pyrene 4.14E-07 1.53E-06 Benzo(a)pyrene 1.88E-07 1.81E-07

Dibenz(a,h)anthracene 3.46E-07 1.28E-06 Indeno(1,2,3-cd)pyrene 3.75E-07 3.61E-07

Benzo(g,h,l)perylene 5.56E-07 2.06E-06 Dibenz(a,h)anthracene 5.83E-07 5.61E-07

Total 1.57E-03 0.0058 Benzo(g,h,l)perylene 4.89E-07 4.71E-07

Total 3.87E-03 0.0037

Diesel IC Engines > 600 HP, 

AP-42 Tables 3.4-2 and 3.4-3 lbs/MMBtu Tons/year Tons/year Diesel IC Engines < 600 HP, AP-42 Table 3.3-2 lbs/MMBtu
Page 5 of 11 TSD Appx A

Auxiliary Boiler 79.3 MMBtu/hr Dew Point Heater 20.8 MMBtu/hr

Benzene 2.10E-03 7.97E-04 Benzene 2.10E-03 1.88E-04

Toluene 3.40E-03 1.29E-03 Toluene 3.40E-03 3.04E-04

Formaldehyde 7.50E-02 2.85E-02 Formaldehyde 7.50E-02 6.70E-03

1,3-Butadiene 3.91E-05 1.48E-05 1,3-Butadiene 3.91E-05 3.49E-06

Naphthalene 6.10E-04 2.31E-04 Naphthalene 6.10E-04 5.45E-05

Acenaphthylene 1.80E-06 6.83E-07 Acenaphthylene 1.80E-06 1.61E-07

Acenaphthene 1.80E-06 6.83E-07 Acenaphthene 1.80E-06 1.61E-07

Fluorene 2.80E-06 1.06E-06 Fluorene 2.80E-06 2.50E-07

Phenanthrene 1.70E-05 6.45E-06 Phenanthrene 1.70E-05 1.52E-06

Anthracene 2.40E-06 9.11E-07 Anthracene 2.40E-06 2.14E-07

Fluoranthrene 3.00E-06 1.14E-06 Fluoranthrene 3.00E-06 2.68E-07

Pyrene 5.00E-06 1.90E-06 Pyrene 5.00E-06 4.47E-07

Benz(a)anthracene 1.80E-06 6.83E-07 Benz(a)anthracene 1.80E-06 1.61E-07

Chrysene 1.80E-06 6.83E-07 Chrysene 1.80E-06 1.61E-07

Benzo(b)fluoranthrene 1.80E-06 6.83E-07 Benzo(b)fluoranthrene 1.80E-06 1.61E-07

Benzo(k)fluoranthrene 1.80E-06 6.83E-07 Benzo(k)fluoranthrene 1.80E-06 1.61E-07

Benzo(a)pyrene 1.20E-06 4.55E-07 Benzo(a)pyrene 1.20E-06 1.07E-07

Indeno(1,2,3-cd)pyrene 1.80E-06 6.83E-07 Indeno(1,2,3-cd)pyrene 1.80E-06 1.61E-07

Dibenz(a,h)anthracene 1.20E-06 4.55E-07 Dibenz(a,h)anthracene 1.20E-06 1.07E-07

Benzo(g,h,l)perylene 1.20E-06 4.55E-07 Benzo(g,h,l)perylene 1.20E-06 1.07E-07

2 Methylnapthalene 2.50E-05 9.48E-06 2 Methylnapthalene 2.50E-05 2.23E-06

3 methylcloranthene 1.60E-06 6.07E-07 3 methylcloranthene 1.60E-06 1.43E-07

7,12-Dimethylbenz(a)anthracene 1.60E-05 6.07E-06 7,12-Dimethylbenz(a)anthracene 1.60E-05 1.43E-06

Dichlorobenzene 1.20E-03 4.55E-04 Dichlorobenzene 1.20E-03 1.07E-04

Hexane 1.80E+00 6.83E-01 Hexane 1.80E+00 1.61E-01

Arsenic 2.00E-04 7.59E-05 Arsenic 2.00E-04 1.79E-05

Barium 4.40E-03 1.67E-03 Barium 4.40E-03 3.93E-04

Beryllium 1.20E-05 4.55E-06 Beryllium 1.20E-05 1.07E-06

Cadmium 1.10E-03 4.17E-04 Cadmium 1.10E-03 9.82E-05

Chromium 1.40E-03 5.31E-04 Chromium 1.40E-03 1.25E-04

Cobalt 8.40E-05 3.19E-05 Cobalt 8.40E-05 7.50E-06

Manganese 3.80E-04 1.44E-04 Manganese 3.80E-04 3.39E-05

Mercury 2.60E-04 9.86E-05 Mercury 2.60E-04 2.32E-05

Nickel 2.10E-03 7.97E-04 Nickel 2.10E-03 1.88E-04

Selenium 2.40E-05 9.11E-06 Selenium 2.40E-05 2.14E-06

Total HAPs 1.89E+00 0.72 Total HAPs 1.89 0.17

Natural Gas Fired Boilers AP-42 

Tables 1.4-3 and 1.4-4 lbs/MMCF Tons/year Natural Gas Fired Boilers AP-42 Tables 1.4-3 and 1.4-4 lbs/MMCF Tons/year
CT-1 w/o Duct Burner 2463 MMBtu/hr 7760 hrs/year

CT-1 w/ Duct Burner 2542 MMBtu/hr 1000 hrs/yr

CT-2 w/o Duct Burner 2463 MMBtu/hr 7760 hrs/year Page 6 of 11 TSD Appx A

CT-2 w/ Duct Burner 2542 MMBtu/hr 1000 hrs/yr

Benzene 1.20E-05 1.15E-01 1.53E-02 1.15E-01 1.53E-02 2.60E-01 5.20E-02

Toluene 1.30E-04 1.24E+00 1.65E-01 1.24E+00 1.65E-01 2.82E+00 5.63E-01

Xylenes 6.40E-05 6.12E-01 8.13E-02 6.12E-01 8.13E-02 1.39E+00 2.77E-01

Formaldehyde 7.10E-04 6.79E+00 9.02E-01 6.79E+00 9.02E-01 1.54E+01 3.07E+00

1,3-Butadiene 4.30E-07 4.11E-03 5.47E-04 4.11E-03 5.47E-04 9.31E-03 1.86E-03

Acetaldehyde 4.00E-05 3.82E-01 5.08E-02 3.82E-01 5.08E-02 8.66E-01 1.73E-01

Acrolein 6.40E-06 6.12E-02 8.13E-03 6.12E-02 8.13E-03 1.39E-01 2.77E-02

Ethylbenzene 3.20E-05 3.06E-01 4.07E-02 3.06E-01 4.07E-02 6.93E-01 1.39E-01

Naphthalene 1.30E-06 1.24E-02 1.65E-03 1.24E-02 1.65E-03 2.82E-02 5.63E-03

PAH 2.20E-06 2.10E-02 2.80E-03 2.10E-02 2.80E-03 4.76E-02 9.53E-03

Total HAPs 9.98E-04 9.54 1.27 9.54 1.27 21.62 4.32

Tons/Year 

PTE @ 80% 

control

CT-1 w/o Duct 

Burner

CT-1 w Duct 

Burner

Natural Gas Fired Turbines AP-42 

Table 3.1-3 lbs/MMBtu

2 CT Units with Duct Burners Tons/Year PTE, Uncontrolled

CT-2 w/o Duct 

Burner Totals CT-2 w Duct Burner
Page 7 of 11 TSD Appx A

Hazardous Air Pollutant 2 CTs with 

Duct Burners

Auxiliary 

Boiler

Dew Point 

Heater

Emergency 

Generator RICE Fire Pump Rice Project Totals

Benzene 2.60E-01 7.97E-04 1.88E-04 2.87E-03 8.98E-04 2.65E-01

Toluene 2.82E+00 1.29E-03 3.04E-04 1.04E-03 3.94E-04 2.82E+00

Formaldehyde 1.54E+01 2.85E-02 6.70E-03 2.92E-04 1.14E-03 1.54E+01

1,3-Butadiene 9.31E-03 1.48E-05 3.49E-06 NA 3.76E-05 9.37E-03

Naphthalene 1.30E-06 2.31E-04 5.45E-05 4.81E-04 8.16E-05 8.50E-04

Acenaphthylene NA 6.83E-07 1.61E-07 3.42E-05 4.87E-06 3.99E-05

Acenaphthene NA 6.83E-07 1.61E-07 1.73E-05 1.37E-06 1.95E-05

Fluorene NA 1.06E-06 2.50E-07 4.74E-05 2.81E-05 7.68E-05

Phenanthrene NA 6.45E-06 1.52E-06 1.51E-04 2.83E-05 1.87E-04

Anthracene NA 9.11E-07 2.14E-07 4.55E-06 1.80E-06 7.48E-06

Fluoranthrene NA 1.14E-06 2.68E-07 1.49E-05 7.32E-06 2.36E-05

Pyrene NA 1.90E-06 4.47E-07 1.37E-05 4.60E-06 2.07E-05

Benz(a)anthracene NA 6.83E-07 1.61E-07 2.30E-06 1.62E-06 4.76E-06

Chrysene NA 6.83E-07 1.61E-07 5.66E-06 3.40E-07 6.84E-06

Benzo(b)fluoranthrene NA 6.83E-07 1.61E-07 4.11E-06 9.54E-08 5.05E-06

Benzo(k)fluoranthrene NA 6.83E-07 1.61E-07 8.07E-07 1.49E-07 1.80E-06

Benzo(a)pyrene NA 4.55E-07 1.07E-07 9.51E-07 1.81E-07 1.69E-06

Indeno(1,2,3-cd)pyrene NA 6.83E-07 1.61E-07 1.53E-06 3.61E-07 2.74E-06

Dibenz(a,h)anthracene NA 4.55E-07 1.07E-07 1.28E-06 5.61E-07 2.40E-06

Benzo(g,h,l)perylene NA 4.55E-07 1.07E-07 2.06E-06 4.71E-07 3.09E-06

2 Methylnapthalene NA 9.48E-06 2.23E-06 NA NA 1.17E-05

3 methylcloranthene NA 6.07E-07 1.43E-07 NA NA 7.50E-07

7,12-Dimethylbenz (a)anthracene NA 6.07E-06 1.43E-06 NA NA 7.50E-06

Dichlorobenzene NA 4.55E-04 1.07E-04 NA NA 5.62E-04

Hexane NA 6.83E-01 1.61E-01 NA NA 8.44E-01

Acetaldehyde 8.66E-01 NA NA 9.32E-05 7.38E-04 8.67E-01

Acrolein 1.39E-01 NA NA 2.92E-05 8.90E-05 1.39E-01

Ethylbenzene 6.93E-01 NA NA 6.93E-01

Xylenes 1.39E+00 NA NA 7.14E-04 2.74E-04 1.39E+00

PAH 4.76E-02 NA NA NA NA 4.76E-02

Arsenic NA 7.59E-05 1.79E-05 NA NA 9.37E-05

Barium NA 1.67E-03 3.93E-04 NA NA 2.06E-03

Beryllium NA 4.55E-06 1.07E-06 NA NA 5.62E-06

Cadmium NA 4.17E-04 9.82E-05 NA NA 5.16E-04

Chromium NA 5.31E-04 1.25E-04 NA NA 6.56E-04

Cobalt NA 3.19E-05 7.50E-06 NA NA 3.94E-05

Manganese NA 1.44E-04 3.39E-05 NA NA 1.78E-04

Mercury NA 9.86E-05 2.32E-05 NA NA 1.22E-04

Nickel NA 7.97E-04 1.88E-04 NA NA 9.84E-04

Selenium NA 9.11E-06 2.14E-06 NA NA 1.12E-05

HAP Totals 21.6 0.7 0.2 0.006 0.004 22.5
AP-42 Cooling Tower Emission Factor (Section 13.4, January 1995) Page 8 of 11 TSD Appx A

0.019 lb PM/1000 gal circulated

0.02% % Liquid Drift

12,000 Total Dissolved Solids (mg/L)

Proposed Cooling Tower

% Liquid Drift EF Unit lb/hr1 tpy

Cooling Tower 192,000 gpm 0 gpm 5,000 0.0005% 1.98E-04 lb/1000 gal 2.280 9.986

Cooling Tower PM/PM10/PM2.5 Emission Factor Calculation

Where,

PM EFAP-42 = AP-42 Emission Factor for PM10 (lb/1000 gal)

TLDdesign = Design total liquid drift (%)

TLDAP-42 = Design total liquid drift (%)

TDSfuture = Estimated future total dissolved solid content (mg/L)

TDSAP-42 = Total dissolved solid content used in AP-42 (mg/L)

Cooling Tower PM/PM10/PM2.5 Emission Calculation

Where,

R = Recirculation rate (400 gal/min)

M = Make-up rate (20 gal/min - Assumed to be 3% of recirculation rate)

Process 

Unit Circulation Rate Make-Up Rate

Total Dissolved 

Solids 

(mg/L)

PM/PM10/PM2.5

42 42

10 2.5 42 / /

 

   

AP

future

AP

design

AP TDS

TDS

TLD

TLD

PM PM PM EF PMEF

PM / PM 10 / PM 2.5  (R  M )  PM EF
P

3.00

21,900

365365

100

Process Pollutant Emission Factor 

Emission 

Factor 

Units

Source of Emission 

Factor

Potential Emissions 

(tons/year)

Actual Emissions 

(Tons/Yr) 

PM 0.020 0.2162 0.2162 

PM-10 0.004 0.0432 0.0432 

PM-2.5 0.001 0.0106 0.0106 

PAVED ROAD SPREADSHEET 

Typical Days of Operation

Determination of Annual Emissions

Average Vehicle Weight (W) (tons): Average weight of vehicles from Assumptions Tab

0.6

Paved Road lb/vmt AP-42

Enter 0.6 for public road, 120 for apshalt batching industrial road, 12 for consand & gravel processing industrial road, 8.2 for quarry industrial road. If 

limit, use that s

EQUATION

VMT 40 vehicles; 1.5 miles/day; 365 days per year Potential Days of Operation

SOURCE OF EMISSION FACTOR: 

Days/Year with at Least 0.01 inches of Precipitation See Map - Figure 1 for value. 100 may be entered as a default value.

EMISSIONS CALCULATIONS

The emission factor is taken from 

Equation 1 in AP-42, 13.2.1, Paved 

Roads (updated January 2011).

Road Surface Silt Loading (g/m2):

k = constant = 0.0022 for PM42 Table 13.2.1-1 (lb/VMT vsL = road surface silt loadinentered aboveW = Average Vehicle Weighp = Number of Days per Ye

EF = [[(k) x [(sL )^0.91] x [(W)^1.02]]((1- (p/1460)) lb/VMT
Page 10 of 11 TSD Appx A

No. of 

Components

SF6/ 

component, 

lbs

% leak 

Assumption SF6, tons/year GWP = 23,900

10 100 0.5% 0.0025 59.75

Number of 

Components

Factor, 

lbs/hr/compo

nent

tons/yr CH4 tons/year 

CO2e

Factor, 

lbs/hr/compon

ent

tons/yr CH4 tons/year CO2e

Valves 500 0.008 17.52 367.92 0.00024 0.53 11.04

Flanges 1300 0.003 17.08 358.72 9E-05 0.51 10.76

Compressor seals 2 0.474 4.15 87.20 0.001422 0.01 0.26

Relief valves 30 0.216 28.38 596.03 0.000648 0.09 1.79

Open ended lines 20 0.031 2.72 57.03 9.3E-05 0.01 0.17

Total 69.85 1466.90 1.14 24.02

Emission factors from TCEQ vHP LDAR Program

SF6

Uncontrolled Controlled
Page 11 of 11 TSD Appx A

Hours/ 

day

Days/ 

week

Weeks/

yr 

Capacity 

Factor 

(%)

Days 

(each)

Hours, 

total gallons/hr

gallons 

Total for 

3-years

PM2.5, 

gr/HP-hr

NMOC/ 

NOx, 

gr/HP-hr

NOx, 

gr/HPhrPM2.5 NOx PM2.5 NOx

Average 

Speed, 

mph

Miles per 

Project

PM2.5 

Emissions, 

Tons/proje

ct

PM2.5 

Emissions, 

Tons/year

Vibratory Compactor 180 2 10 5 20 0.75 100 1500 11.7 17550 0.22 3 3 0.065 0.893 0.022 0.298 5 7500 1.01 0.34

Motor Grader 140 2 10 5 20 0.75 100 1500 9.2 13800 0.22 3 3 0.051 0.694 0.017 0.231 5 7500 1.01 0.34

Dump Truck 400 2 10 5 10 0.75 50 750 26 19500 0.15 3 3 0.050 0.992 0.017 0.331 5 3750 0.51 0.17

Wheel Loader 600 2 10 5 20 0.75 100 1500 42.5 63750 0.15 3 3 0.149 2.976 0.050 0.992 5 7500 1.01 0.34

Dozer 350 2 10 5 8 0.75 40 600 24 14400 0.15 3 3 0.035 0.694 0.012 0.231 5 3000 0.41 0.14

Excavator 350 4 10 5 25 0.75 125 3750 23.4 87750 0.15 3 3 0.217 4.340 0.072 1.447 5 18750 2.53 0.84

Scraper 300 2 10 5 8 0.75 40 600 21.3 12780 0.15 3 3 0.030 0.595 0.010 0.198 5 3000 0.41 0.14

Pavers 140 1 10 5 2 0.75 10 75 9.2 690 0.22 3 3 0.003 0.035 0.001 0.012 5 375 0.05 0.02

Generators/Compressors 40 2 10 5 8 0.75 40 600 2.5 1500 0.44 5.6 5.6 0.012 0.148 0.004 0.049 NA NA NA NA

Welding Machine 40 10 10 5 50 0.50 250 12500 3.2 40000 0.6 5.6 5.6 0.331 3.086 0.110 1.029 NA NA NA NA

Dump Truck 400 2 10 5 20 0.50 100 1000 26 26000 0.15 3 3 0.066 1.323 0.022 0.441 5 5000 0.68 0.23

Wheel Loader 600 2 10 5 50 0.50 250 2500 10.2 25500 0.22 3 3 0.364 4.960 0.121 1.653 5 12500 1.69 0.56

Water Truck 150 2 10 5 120 0.25 600 3000 42.5 127500 0.15 3 3 0.074 1.488 0.025 0.496 5 15000 2.03 0.68

Crawler Crane 300 2 10 5 50 0.50 250 2500 20.3 50750 0.15 3 3 0.124 2.480 0.041 0.827 NA NA NA NA

Concrete Truck 300 2 10 5 8 0.50 40 400 20.7 8280 0.15 3 3 0.020 0.397 0.007 0.132 5 2000 0.27 0.09

Concret Pump 70 2 10 5 8 0.50 40 400 6.1 2440 0.3 3.5 3.5 0.009 0.108 0.003 0.036 NA NA NA NA

Flat Bed Tracktor Trailor 250 2 10 5 10 0.50 50 500 22.7 11350 0.15 3 3 0.021 0.413 0.007 0.138 5 2500 0.34 0.11

Forklift 80 5 10 5 80 0.50 400 10000 5.42 54200 0.3 3.5 3.5 0.265 3.086 0.088 1.029 5 50000 6.75 2.25

Crane 300 2 10 5 35 0.50 175 1750 18.92 33110 0.15 3 3 0.087 1.736 0.029 0.579 NA NA NA NA

Generators/Compressors 40 6 10 5 80 0.50 400 12000 2.51 30120 0.44 5.6 5.6 0.233 2.963 0.078 0.988 NA NA NA NA

2.2 33.4 0.7 11.1 138,375 18.7 6.2

All Engines are assumed to use diesel fuel

PM2.5 emission factor for unpaved roads based on AP-42, Chapter 13-2-2 equation, vehicle weight = 22 tons; silt content = 8.5%; a=0.9; b=0.45 ; k=0.15. Factor = 0.27 lbs/VMT

PM2.5 Nox

0.73 11.1

6.23

6.96 11.1

Totals

Operating Schedule

Total

Tons/Year

Engine Emissions from Construction

Unpaved Roadway Emissions

Horse 

Power

missions, tons/yea Unpaved Road Emissions

Emissions, 

tons/project Number 

of Units

Site preparation Plant Construction

Total Time During 

3-year 

Construction 

P id Fuel Use Emission Factors
Air Quality Analysis

Indianapolis Power & Light Company

Eagle Valley Generating Plant

Martinsville, Indiana (Morgan County)

Tracking and Plant ID: T109-32471-00004

Proposed Project

Indianapolis Power & Light (IPL) Company has submitted a request for a significant major source 

modification of their Eagle Valley Generating Station near Martinsville, Indiana with an increase in carbon 

monoxide (CO), nitrogen dioxide (NO2), particulate matter less than 10 microns (PM10), particulate matter 

less than 2.5 microns (PM2.5), sulfur dioxide (SO2), and volatile organic compounds (VOCs). The increase 

in CO, NO2, PM10, and PM2.5 emissions will be as a result of the installation of two natural gas fired 

combined cycle combustion turbines and an auxiliary boiler at the IPL Eagle Valley Generating Station in 

Martinsville, Indiana. Additional criteria pollutant emissions will be the result of new cooling towers, a dew 

point heater, an emergency generator, and an emergency fire pump.

Environmental Resources Management (ERM) in Rolling Meadows, Illinois prepared the air quality 

analysis portion of the Prevention of Significant Deterioration (PSD) permit application for IPL. The 

Modeling Section in the Office of Air Quality (QAQ) received the air quality analysis portion of the permit 

application on November 7, 2012 and the air quality modeling files on November 26, 2012. A revised 

permit application was received on July 9, 2013 with the revised modeling files received on July 15, 2013. 

This technical support document provides the air quality analysis review of the PSD permit application.

Analysis Summary

Based on the potential emissions after controls, a PSD air quality analysis was triggered for CO, NO2,

PM10, and PM2.5. The significant impact analysis determined modeling concentrations for NO2, PM10, and

PM2.5 exceeded the significant impact levels. A refined analysis, PSD increment analysis and National 

Ambient Air Quality Standards (NAAQS) analysis were required. The pre-construction monitoring 

requirement was triggered for the 24-hour PM10 and 24-hour PM2.5 as a result of this analysis. An 

additional impact analysis was conducted and showed no significant impacts. Based on the modeling 

results, the proposed PSD major source modification will not have a significant impact upon federal air 

quality standards.

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 used for the analyses. 
IPL Eagle Valley Gen. Station Page 2 of 17

Martinsville, Indiana PSD/SSM No. T109-32471-00004

Permit Writer: Mark Neyman

C. Determine the significant impact levels, 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 NAAQS or PSD

increment if the applicant exceeds significant impact levels.

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 located in south central Kentucky about 150 

kilometers south of Louisville.

F. Secondary Ozone Formation Analysis

G. Secondary PM2.5 Formation Analysis

H. Summary of 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). Morgan County is classified as attainment for all 

criteria pollutants. Morgan County was classified as nonattainment for the annual PM2.5 standard, but the 

United States Environmental Protection Agency (U.S. EPA) approved the Indiana Department of 

Environmental Management (IDEM) request to redesignate Morgan County to attainment for the annual

PM2.5 standard effective July 11, 2013, Federal Register Volume 78, No. 133 dated July 11, 2013.

Proposed Project Emissions

CO, NO2, PM10, PM2.5, SO2, VOCs, and H2SO4 are the pollutants which will be emitted from the IPL

Eagle Valley PSD major source modification. An air quality analysis is required for CO, NO2, PM10 and 

PM2.5 pollutants because potential emissions after controls exceed the significant emission rates (SER) as 

shown in Table 1. Sulfuric Acid Mist (SAM) will exceed the significant emission rate for PSD applicability. 

However, no air quality analysis is required for SAM under the PSD regulations and SAM has no 

monitoring concentration threshold listed in 326 IAC 2-2-4. The significant emission rates in Table 1 were 

taken from Table 4-2 of the IPL Eagle Valley PSD permit application technical support document for NO2, 

SO2, SAM, and VOCs and the modeled emission limits in the case of CO, PM2.5, and PM10. The modeled 

emissions limits for CO, PM2.5, and PM10 listed in Table 1 on page 3 are somewhat higher than the 

emissions listed in Table 4-2 of the PSD permit application. Three operating scenarios were modeled by 

ERM to determine the highest modeled impact, or worst case operating scenario, for each criteria pollutant 

with the exception of PM10 and PM2.5 where only two operating scenarios were applicable to particulate 

matter.
IPL Eagle Valley Gen. Station Page 3 of 17

Martinsville, Indiana PSD/SSM No. T109-32471-00004

Permit Writer: Mark Neyman

Table 1

Significant Emission Rates for PSD Applicability

CRITERIA 

POLLUTANT

POTENTIAL EMISSION 

RATE

(Source Totals)

SIGNIFICANT EMISSION RATE PRELIMINARY AIR QUALITY

ANALYSIS REQUIRED

(tons/year) (tons/year)

CO 670 100 Yes

NO2 176.7 40 Yes

PM10 183 15 Yes

PM2.5 149.5 10 Yes

SO2 30.9 40 No

VOC 170 40 Yes

H2SO4 (Sulfuric 

Acid Mist) 13.5 7 No

Section B – Good Engineering Practice (GEP), Met Data, Model Used, Receptor 

Grid

Stack Height Compliance with Good Engineering Practice (GEP)

Applicability

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 or 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 would affect 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)
IPL Eagle Valley Gen. Station Page 4 of 17

Martinsville, Indiana PSD/SSM No. T109-32471-00004

Permit Writer: Mark Neyman

Existing Stack

Since the existing stack heights of the units for which the modification is proposed are below GEP stack 

height, the effect of aerodynamic downwash will be accounted for in the air quality analysis for the 

project.

Meteorological Data

The meteorological data used in the American Meteorological Society Environmental Protection Agency 

Regulatory Model (AERMOD) consisted of 2006 through 2010 surface meteorological data from the 

Indianapolis, Indiana National Weather Service (NWS) station merged with the upper air data from the

Lincoln, Illinois NWS upper air station. Additionally, the Indianapolis 1-minute Automated Surface 

Observing System (ASOS) wind speed and wind direction data were processed with the AERMINUTE 

preprocessor version 11325. The meteorological data were preprocessed into an AERMOD ready format

by the OAQ using U.S.EPA’s AERMET, Version 12345, meteorological preprocessor for AERMOD.

Model Description

ERM and OAQ used the most recent version of AERMOD, Version 12345, at the time the permit 

application was submitted to determine maximum off-property concentrations or impacts for each criteria

pollutant. All regulatory default options were utilized in the U.S. EPA approved model, as listed in the 40 

Code of Federal Regulations Part 51, Appendix W “Revision to the Guideline on Air Quality Models”.

The Auer Land Use Classification Scheme was used to determine the land use in the area. The area is 

considered primarily rural; therefore, a rural classification was used. 

Receptor Grid

The receptor grids extended to a distance approximately 50 kilometers from the plant. Fence line 

receptors were closely spaced at 50 to 100 meters along the plant fence line and spaced every 100 

meters out to a distance of 1000 meters from the plant property lines to identify the influence of 

aerodynamic building downwash. A total of 7237 receptors were used in the significant impact area air 

quality analysis for CO, NO2, PM10, and PM2.5 with a more refined receptor grid of 4621 receptors for the 

NO2 NAAQS and PSD increment analyses and 2461 receptors for the PM10 and the PM2.5 NAAQS 

analyses. A total of 7237 receptors were used for the PM2.5 PSD increment analysis which was 

essentially the SIL analysis for PM2.5 and 4621 receptors for the PM10 PSD increment analysis. Each 

receptor grid was sufficiently large enough to extend to a distance beyond the significant impact area for 

the respective pollutant.

Section C - Significant Impact Level/Area (SIA) and Background Air Quality Levels

A significant impact analysis was conducted to determine if the source exceeded the PSD significant 

impact levels (SILs) or concentrations. If the source's concentrations exceed the SILs, further air quality 

analyses are required. Refined modeling for the 1-hour and 8-hour CO and the PM10 annual time 

averaging periods were not required because the results did not exceed the SILs. SILs are defined by the 

following time periods shown in Table 2 on page 5 with all the maximum-modeled concentrations from the 

worst case operating scenarios. Case 2 operating scenario had the highest modeled impact on the air 

quality for the 1-hour and annual NO2 and the 24-hour and annual PM10 and PM2.5. Case 3 operating 

scenario resulted in the highest modeled concentrations for the 1-hour and 8-hour CO. The 1-hour NO2
IPL Eagle Valley Gen. Station Page 5 of 17

Martinsville, Indiana PSD/SSM No. T109-32471-00004

Permit Writer: Mark Neyman

SIL shown in Table 2 is the highest 5 year average of the 1-hour maximum daily concentrations for each 

receptor modeled. Likewise, the 24-hour PM2.5 SIL is the highest 5 year average of the maximum 24-hour 

concentrations for each receptor. Additionally, the annual PM2.5 SIL is the highest 5 year average of the 

annual concentrations at each receptor. The 1-hour and annual NO2 modeled results shown in Table 2 

were adjusted by the default ambient ratio for the nitrous oxides (NOx) to NO2 conversion, which is a 0.8 

default ambient ratio for the 1-hour concentration and is a 0.75 default ambient ratio for the annual 

concentration. This is known as the Tier 2 or the Ambient Ratio Method (ARM) modeling approach for 

NO2.

The 24-hour and annual PM2.5 SILs were vacated and remanded by the United States Court of 

Appeals for the District of Columbia Circuit Court decision on January 22, 2013. U.S. EPA has interpreted 

the Court’s decision for pending PSD permits to not rely solely on the PM2.5 SILs to demonstrate that a 

source will not cause or contribute to a violation of the PM2.5 NAAQS or PSD increments. In the case of

IPL Eagle Valley, the annual and 24-hour PM2.5 modeling results were above the PM2.5 SILs and below 

the PM2.5 NAAQS so the use of the PM2.5 SILs does not impact the modeling results for the IPL Eagle 

Valley PSD major source modification.

Table 2

Significant Impact Analysis

CRITERIA 

POLLUTANT

TIME AVERAGING 

PERIOD

MAXIMUM MODELED 

IMPACT

(ug/m3

)

SIGNIFICANT 

IMPACT LEVEL 

(ug/m3

)

REFINED AQ ANALYSIS 

REQUIRED

CO 1-Hour 286.6 2000 No

CO 8-Hour 111.5 500 No

NO2 1-Hour 68.9 7.5 Yes

NO2 Annual 1.4 1 Yes

PM10 24-Hour 12.1 5 Yes

PM10 Annual 0.53 1 No

PM2.5 24-Hour 6.0 1.2 Yes

PM2.5 Annual 0.32 0.3 Yes

Preconstruction Monitoring Analysis

Applicability

The PSD requirements, 326 IAC 2-2-4, require an air quality analysis of the new source or the major PSD 

modification to determine if the preconstruction monitoring threshold is triggered. In most cases, post 

construction monitoring can satisfy this requirement if the preconstruction monitoring threshold has been 

exceeded. In the case of the significant monitoring concentration (SMC) for PM2.5, the January 22, 2013 

decision by the Circuit Court vacated the use of the 24-hour PM2.5 SMC to exempt a source from the

preconstruction monitoring data requirement. However, in most cases existing ambient PM2.5 monitoring

data can be used to meet the preconstruction requirement, as was done here for the IPL Eagle Valley 
IPL Eagle Valley Gen. Station Page 6 of 17

Martinsville, Indiana PSD/SSM No. T109-32471-00004

Permit Writer: Mark Neyman

PSD major source modification.

Modeling Results

A comparison of the preliminary modeling results was compared to the PSD preconstruction monitoring 

thresholds. The criteria pollutants, PM10 and PM2.5, did trigger the preconstruction monitoring 

requirement. As a result, the preconstruction monitoring requirement for PM10 and PM2.5 is necessary for 

this PSD major source modification, but the preconstruction monitoring requirement is met by using 

existing air quality monitoring data for PM10 and PM2.5. The modeling results for the preconstruction 

monitoring requirement are listed in Table 3 on page 6.

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 air quality monitoring sites for this area. Background air 

quality monitoring concentrations for NO2, PM10, and PM2.5 are required as part of this analysis since the 

modeling results were above the SILs for NO2, PM10 and PM2.5 and a subsequent NAAQS analysis was 

required. As a result, these analyses were completed for NO2, PM10 and PM2.5 PSD increments and 

NAAQS.

Table 3

Preconstruction Monitoring Analysis

CRITERIA 

POLLUTANT

TIME 

AVERAGING 

PERIOD

MAXIMUM MODELED

IMPACT

(ug/m3

)

DE MINIMIS 

MONITORING LEVEL 

(ug/m3

)

ABOVE DE MINIMIS 

MONITORING LEVEL

CO 8-Hour 111.5 575 No

NO2 Annual 1.4 14 No

PM10 24-Hour 12.1 10 Yes

PM2.5 24-Hour 6.0 4 Yes

Background Monitors

Background data were taken from the air quality monitoring sites in the Bloomington and Evansville areas

using the NO2 and PM10 monitors located on Buena Vista Road in Evansville and the Bloomington-Binford

PM2.5 monitor located on East 2nd Street in Bloomington. The 1-hour NO2 background concentration used 

the 98th percentile or the 8th high averaged over 3 years and the annual NO2 background used the 3-year 

average of the highest annual concentrations. The maximum 2nd high concentrations were used for the 

24-hour PM10. The 24-hour PM2.5 background concentration used the 24-hour 3-year design value or the 

98th percentile of the 24-hour value averaged over 3 years. The annual PM2.5 background concentration 

used the annual 3-year design value. The NO2, PM10, and PM2.5 background concentrations were taken 

from the 2010 to 2012 air quality monitoring data.
IPL Eagle Valley Gen. Station Page 7 of 17

Martinsville, Indiana PSD/SSM No. T109-32471-00004

Permit Writer: Mark Neyman

Table 4

Existing Monitoring Data Used for Background Concentrations

CRITERIA

POLLUTANT

MONITOR SITE MONITOR LOCATION AVERAGING PERIOD CONCENTRATION

(ug/m3

)

NO2 18-163-0021

Evansville 1-Hour 67.9

NO2 18-163-0021 Evansville Annual 20.9

PM2.5 18-105-0003 Bloomington 24-Hour 23

PM2.5 18-105-0003 Bloomington Annual 10.4

PM10 18-163-0021 Evansville 24-Hour 34.7

Section D - NAAQS and PSD Increment

NAAQS Compliance Analysis and Results

NAAQS air quality modeling for the annual time averaging period for PM10 and the 1-hour and 8-hour CO 

time averaging periods were not required since the IPL Eagle Valley PSD major source modification air 

quality analysis was below the SILs for the annual PM10 of 1 ug/m3 and the 1-hour and 8-hour CO SILs of 

2000 ug/m3 and 500 ug/m3

, respectively. The OAQ NAAQS modeling results are shown in Table 5. All 

maximum modeled concentrations were compared to their respective NAAQS. All maximum modeled 

concentrations during the five years of modeling were below the NAAQS standards with the exception of 

the 1-hour NO2 NAAQS. Additional air quality modeling was not required for the 24-hour PM10 and PM2.5

and the annual PM2.5 and NO2 standards. The 1-hour NO2 NAAQS modeling results shown in Table 5 

had a violation of the 1-hour NO2 standard of 100 parts per billion (ppb) or 188.7 ug/m3

. The highest 8thhigh 1-hour NO2 concentration averaged across five years was 419.7 ug/m3 resulting in a total 1-hour NO2

concentration of 487.6 ug/m3 with a background concentration of 67.9 ug/m3

. The highest 8th-high 

maximum daily 1-hour NO2 modeled concentration of 419.7 in Table 5 was adjusted from an actual 

modeled concentration of 524.6 ug/m3 by using the NO2/NOx default ambient ratio of 0.8 (524.6 X 0.8 = 

419.7) for a 1-hour concentration. The annual NO2 modeled concentration shown in Table 5 has been 

adjusted by the 0.75 default ambient ratio for NOx to NO2 conversion for an annual concentration.

The 24-hour PM2.5 NAAQS analysis shown in Table 5 used the 98th percentile or the 8th highest 24-hour

concentration averaged across five years of modeling for the modeled concentration which is the same 

form of the 24-hour PM2.5 standard as the 24-hour PM2.5 monitored background concentration. This 

change to the 98th percentile form of the 24-hour PM2.5 standard for the NAAQS analysis is the result of 

the recommendation from the “Draft Guidance for PM2.5 Permit Modeling” document dated March 4, 2013. 

Additionally, the annual PM2.5 NAAQS was revised from 15 ug/m3 to 12 ug/m3 by the U.S. EPA on 

December 14, 2012 with the final rule effective date of March 18, 2013, Federal Register dated January 

15, 2013. The annual PM2.5 NAAQS shown in Table 5 reflects this revision in the annual PM2.5 standard

to 12 ug/m3

.
IPL Eagle Valley Gen. Station Page 8 of 17

Martinsville, Indiana PSD/SSM No. T109-32471-00004

Permit Writer: Mark Neyman

Table 5

NAAQS Analysis

CRITERIA

POLLUTANT

TIME 

AVERAGING 

PERIOD

YEAR

MODELED 

CONCENTRATION

(ug/m3

)

BACKGROUND

CONCENTRATION

(ug/m3

)

TOTAL

CONCENTRATION

(ug/m3

)

NAAQS 

(ug/m3

)

NAAQS

VIOLATION

NO2 1-Hour 5 Year 419.7 67.9 487.6 188.7 Yes

NO2 Annual 2007 6.9 20.9 27.8 100 No

PM2.5 24-Hour 5 Year 3.3 23 26.3 35 No

PM2.5 Annual 5 Year 0.5 10.4 10.9 12 No

PM10 24-Hour 2008 6.2 34.7 40.9 150 No

1-Hour NO2 Contribution Analysis and Results

The 8th-high 1-hour NO2 concentration represents the 98th percentile of the 1-hour daily maximum 

concentrations averaged across five years of modeling. A total of 27 receptors violated the 1-hour NO2

NAAQS of 100 ppb or 188.7 ug/m3. As a result, OAQ performed additional 1-hour NO2 modeling for the 

27 receptors which violated the 1-hour NO2 NAAQS to determine if the impact from the IPL Eagle Valley 

PSD major source modification had a significant contribution to any violating receptor. For this additional 

modeling analysis, the maximum daily contribution output option was selected in AERMOD and the 1-hour 

NO2 SIL of 7.5 ug/m3 was used as the threshold value for a significant contribution. For the highest 8thhigh maximum daily 1-hour NO2 concentration averaged over five years in Table 5, the total contribution 

by the IPL PSD major source modification was 0.00175 ug/m3

. The results of the 1-hour NO2 contribution 

analysis for the highest 1-hour concentration for a NAAQS violating receptor are shown in Table 6. All 27

violating receptors had 1-hour NO2 contributions from the IPL PSD major source modification which were 

below the 1-hour NO2 SIL of 7.5 ug/m3

. As a result, the IPL PSD major source modification does not have 

a significant contribution or impact on any receptor which showed a 1-hour NO2 NAAQS violation.

Table 6

1-Hour NO2 Contribution Analysis

CRITERIA

POLLUTANT

TIME 

AVERAGING 

PERIOD

YEAR

MODELED 

CONCENTRATION

(ug/m3

)

BACKGROUND

CONCENTRATION

(ug/m3

)

ABOVE 

NAAQS 

>

188.7

TOTAL

CONTRIBUTION 

IPL PSD

(ug/m3

)

SIL 

(ug/m3

)

ABOVE

SIL

NO2 1-Hour 5 Year 419.7 67.9 Yes 0.00175 7.5 No

The OAQ performed an additional air quality modeling analysis for all receptors in the 1-hour NO2 SIA 

analysis, a total of 2535 receptors, which exceeded the 1-hour NO2 SIL of 7.5 ug/m3 to determine if any of 

these receptors exceeded the 1-hour NO2 NAAQS. A total of four receptors did exceed the 1-hour NO2

NAAQS when the background concentration of 67.9 ug/m3 was added to the modeled concentration. 

However, the 8th-high (98th percentile) of the maximum daily 1-hour NO2 contribution averaged over 5 

years from the IPL Eagle Valley PSD major source modification at each of the four receptors was below 
IPL Eagle Valley Gen. Station Page 9 of 17

Martinsville, Indiana PSD/SSM No. T109-32471-00004

Permit Writer: Mark Neyman

the SIL of 7.5 ug/m3. The results of the 1-hour NO2 contribution modeling for each of the four receptors 

are shown in Table 7. 

Table 7

1-Hour NO2 Contribution Analysis for Receptors Exceeding SIL and NAAQS

CRITERIA

POLLUTANT

TIME 

AVERAGING 

PERIOD

YEAR

MODELED 

CONCENTRATION

(ug/m3

)

BACKGROUND

CONCENTRATION

(ug/m3

)

ABOVE 

NAAQS

>

188.7

TOTAL

CONTRIBUTION 

IPL PSD

(ug/m3

)

SIL 

(ug/m3

)

ABOVE

SIL

NO2 1-Hour 5 Year 204.3 67.9 Yes 0.00582 7.5 No

NO2 1-Hour 5 Year 138.4 67.9 Yes 0.00555 7.5 No

NO2 1-Hour 5 Year 132.4 67.9 Yes 0.00149 7.5 No

NO2 1-Hour 5 Year 131.2 67.9 Yes 0.01989 7.5 No

Analysis and Results of Source Impact on the PSD Increment

Applicability

Maximum allowable increases or PSD increments are established by 326 IAC 2-2 for PM10, PM2.5, and 

NO2. This rule also limits a source to no more than 80 percent of the available PSD increment to allow for 

future growth. Only PM2.5 emissions increases since the PM2.5 major source baseline date of October 20, 

2010 actually consume PM2.5 increment. The IPL Eagle Valley PSD major source modification will 

establish the PM2.5 minor source baseline date for Morgan County. The PM2.5 minor source baseline 

date for Morgan County will be the date of the IPL Eagle Valley permit application.

Source Impact

Since the modeled impacts for the annual NO2 and PM2.5, and 24-hour PM10 and PM2.5 from the IPL 

Eagle Valley major source modification were above the SILs of 5 ug/m3 (24-hour PM10), 1.2 ug/m3 (24-

hour PM2.5), 1 ug/m3 (annual NO2), and 0.3 ug/m3 (annual PM2.5) a PSD increment analysis for the 

existing major sources was required as part of this air quality analysis. The results of the OAQ NO2,

PM10, and PM2.5 PSD increment analysis are shown below in Table 8. The annual NO2 modeled 

concentration shown in Table 8 has been adjusted by the 0.75 default ambient ratio for NOx to NO2

conversion for an annual concentration.
IPL Eagle Valley Gen. Station Page 10 of 17

Martinsville, Indiana PSD/SSM No. T109-32471-00004

Permit Writer: Mark Neyman

Table 8

PSD Increment Analysis

CRITERIA 

POLLUTANT

TIME 

AVERAGING 

PERIOD

YEAR

MODELED 

CONCENTRATION

(ug/m3

)

PSD 

INCREMENT

(ug/m3

)

80 PERCENT OF 

PSD INCREMENT

(ug/m3

)

PSD 

INCREMENT 

VIOLATION

NO2 Annual 2007 1.75 25 20 No

PM2.5 24-Hour 2008 4.9 9 7.2 No

PM2.5 Annual 2007 0.39 4 3.2 No

PM10 24-Hour 2008 6.2 30 24 No

The results of the modeling show no PSD increment for NO2, PM10, and PM2.5 or 80 percent of any PSD 

increment will be violated as a result of this PSD major source modification at the IPL Eagle Valley facility.

Part E – Qualitative Analysis

Additional Impact Analysis

All PSD permit applicants must prepare additional impacts analysis for each pollutant subject to regulation 

under the Clean Air Act. This analysis assesses the impacts on economic growth, soils and vegetation, 

wildlife and plant species, and visibility caused by any increase in emissions of any regulated pollutant 

from the source. The IPL Eagle Valley PSD permit application provided an additional impact analysis 

performed by ERM.

Economic Growth

No impact from the economic growth is expected from the IPL Eagle Valley PSD permit major source 

modification and physical changes at the IPL Eagle Valley facility. The existing Martinsville, Indiana and 

Morgan County community will be able to adequately handle potential commercial growth associated with 

this future plant modification. An additional employment of 30 to 40 people is expected as a result of this 

facility modification.

Soils and Vegetation Analysis

A soils and vegetation analysis was performed by ERM to assess the impact of the criteria pollutant air 

emissions. Soil types in Morgan County include silt loam, clay loam, and sandy loam soils. Crops in 

Morgan County consist mainly of corn, soybeans, and wheat. Trees in Morgan County are mostly 

hardwoods such as maples and oaks. The results of the soils and vegetation analysis show the modeled 

impacts are well below the thresholds necessary to have an adverse impact on the surrounding soils and 

vegetation. The results of the soils and vegetation analysis are listed in the IPL Eagle Valley PSD Permit 

Application, section 8, page 26.
IPL Eagle Valley Gen. Station Page 11 of 17

Martinsville, Indiana PSD/SSM No. T109-32471-00004

Permit Writer: Mark Neyman

Federal Endangered Species Analysis

Federal and State endangered or threatened species are listed by the Indiana Department of Natural 

Resources; Division of Nature Preserves for Morgan County, Indiana and includes eight species of 

mussels, six species of birds, three species of reptiles, two species of bats, and one specie each of fish

and amphibian. The mussels and birds listed are commonly found along major rivers and lakes while the 

bats are found near caves. The Martinsville Eagle Valley facility is not expected to have any additional 

adverse effects on the habitats of the endangered species other than that which has already occurred 

from the industrial and residential activities in the area. The endangered species of bats maintains

habitats in caves and mines none of which are near the Martinsville facility. Federal and State

endangered or threatened plants are listed by the Indiana Department of Natural Resources, Division of 

Nature Preserves and include no threatened or endangered species of plants in the Morgan County area 

of central Indiana.

Visibility Analysis

The VISCREEN model is designed as a screening model to determine the visual impact parameters from 

a single source plume. It is used basically to determine whether or not a plume is visible as an object 

itself.

The NO2 and PM10 emission limits were used to run a local visibility Level 1 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. A Delta-E of 1.483 and a plume contrast of 0.016

were the maximum visual impacts at Interstate I-70 which is within the study area. The Delta-E and plume 

contrast values located at Interstate I-70 are below the threshold values for the Delta-E of 2.0 and for the 

plume contrast of 0.05.

The nearest Class I area is Mammoth Cave National Park in Kentucky approximately 300 kilometers from 

the IPL Eagle Valley facility in Martinsville, Indiana. A screening visibility was conducted by ERM which 

showed no visibility analysis is required on the Class I area since the Q/D ratio, where Q is the total 

emissions of NO2, PM10, SO2, and H2SO4 (sulfuric acid mist) in tons per year and D is the distance in 

kilometers, resulted in a value of 1.5 which is below the threshold value of 10 required to perform the 

visibility analysis on a Class I area.

Additional Impact Analysis Conclusions

Finally, the results of the additional impact analysis conclude the operation of the IPL Eagle Valley facility 

will have no significant impact on economic growth, soils, vegetation, endangered or threatened species, 

and visibility in the immediate vicinity or on any Class I area. Since the modeled impacts do not extend 

beyond the immediate area just beyond the plant property, no adverse impacts are expected from the 

modification at the IPL Eagle Valley facility in Martinsville, Indiana. Additionally, there are no threatened or 

endangered plant species in Morgan County. 
IPL Eagle Valley Gen. Station Page 12 of 17

Martinsville, Indiana PSD/SSM No. T109-32471-00004

Permit Writer: Mark Neyman

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). While the 

U.S. Court of Appeals for the D.C. Circuit issued a decision vacating CSAPR on August 21, 2012, the 

modeling analysis conducted by U.S. EPA is considered valid and will be used for the ozone analysis.

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 IPL Eagle Valley, results from the modeling U.S. EPA conducted to 

establish the 2012 and 2014 base case emissions in CSAPR were used for this analysis. The CSAPR 

website is located at http://www.epa.gov/crossstaterule/techinfo.html.

Information regarding the NOx emissions modeled for CSAPR 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 in 2012 at 455,325 tons and base 

case annual NOx emissions by 2014 at 431,342 tons. Indiana’s total NOx emission reduction between 

these scenarios totals 23,983 tons. All surrounding states make similar significant reductions. IPL Eagle 

Valley’s proposed emissions would be 176.7 tons per year of NOx and 170.0 tons per year of VOCs for a 

total of 346.7 tons per year of NOx and VOCs.

8-Hour Ozone Modeling Results

The nearest ozone monitor to IPL Eagle Valley is the Monrovia ozone monitor in Morgan County. The 

current design value for 2010-2012 is 69 parts per billion (ppb), below the 8-hour NAAQS of 75 ppb. The 

U.S. EPA CSAPR results show the maximum modeled 8-hour ozone concentration for Morgan County is

71.7 ppb for the 2012 base case and 70.2 ppb for the 2014 base case. This is a decrease of 1.5 ppb as a 

result of NOx emission adjustments between 2012 and 2014 base case emission calculations, based on 

emission growth factors. In order for this modeled 8-hour ozone concentration reduction to occur, 

Indiana’s 2014 NOx emissions were reduced from the 2012 base case emissions by 23,983 tons. The 

Morgan County monitoring site is not necessarily impacted by every EGU in Indiana, but in the 

surrounding states, thousands of tons of annual NOx emission reductions are projected to occur by 2014, 

many of which would impact this site. Therefore, to estimate the impact of IPL Eagle Valley on modeled 

concentrations, the ratio of IPL Eagle Valley’s NOx and VOC emissions to Indiana’s 2012 to 2014 base 

case NOx emission reduction was calculated. This ratio was then compared to the modeled ozone impact 

from the difference between the CSAPR 2012 and 2014 base case modeling results.

1) 346.7 tons IPL Eagle Valley NOx and VOC emissions / 23,983 tons of Indiana’s NOx base case

emissions reduced from 2012 to 2014 = 1.45% ratio of IPL Eagle Valley’s NOx and VOC emissions 

compared to Indiana’s NOx emissions

2) 1.45% IPL Eagle Valley emission ratio * 1.5 ppb maximum 8-hour 2012 to 2014 Base Case modeled 

results for Morgan County = 0.022 ppb of IPL Eagle Valley 8-hour ozone impact
IPL Eagle Valley Gen. Station Page 13 of 17

Martinsville, Indiana PSD/SSM No. T109-32471-00004

Permit Writer: Mark Neyman

3) 0.022 ppb of IPL Eagle Valley 8-hour ozone impact / 70.2 ppb at Morgan County ozone monitor from 

2014 base case maximum modeled results = 0.03% IPL Eagle Valley’s impact on the 2014 base case 

modeled concentration.

Tables are located in CSAPR_AQModeling.pdf, Appendix B, pages B-10 and B-12, for 8-hour ozone 

design values that show the base case 2012 ozone concentrations at surrounding monitoring sites versus 

projected base case 2014 ozone concentrations. 2012 Base Case represents modeled results taken from 

the 2012 and 2014 Base Case emissions, which represents the 2014 Base emissions with emission 

adjustments from growth factors included in the modeling. Table 9 below shows the CSAPR modeling 

results for the Morgan County and nearby monitors and the potential impacts from IPL Eagle Valley.

Table 9

EPA’s Cross-State Air Pollution Rule - 8-Hour Ozone Modeling Results

Monitor ID County

2012

Base

(ppb)

2014

Base

(ppb)

2012 - 2014

Base

(ppb)

Anticipated 

Source Impact

(ppb)

Source Impact 

on 2014 Base 

Results

(%)

181090005 Morgan 71.7 70.2 1.5 0.022 0.031%

180630004 Hendricks 68.9 67.4 1.5 0.022 0.032%

180810002 Johnson 70.7 69.3 1.4 0.020 0.029%

180970057 Marion 70.9 69.6 1.3 0.019 0.027%

Summary of Ozone Results

IPL Eagle Valley’s NOx and VOC emissions were compared with the U.S. EPA CSAPR modeling for 8-

hour ozone to determine what impacts may occur as a result of ozone formation. When IPL Eagle Valley

emissions were compared with the amount of NOx emission reductions realized from emission estimates 

associated with base case emissions for CSAPR and compared with CSAPR modeling results for 8-hour 

ozone, the impacts from IPL Eagle Valley on the Morgan County ozone monitor are anticipated to be 

minimal and not have a significant impact on the attainment status of Morgan County and any surrounding 

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. 

Dispersion modeling for the NO2 primary pollutant shows the concentrations are well below the respective 

NAAQS for the IPL Eagle Valley contribution and will further diminish within the modeling domain of 50 

km. Since the 1-hour NO2 standard is very restrictive, these levels would likely prevent the pollutants from 

impacting secondary formation significantly enough to result in a violation of the PM2.5 standards. SO2

dispersion modeling was not required for this PSD major source permit modification since the SER was 

below 40 tons per year.

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 and NOx. All photochemical models are regional 
IPL Eagle Valley Gen. Station Page 14 of 17

Martinsville, Indiana PSD/SSM No. T109-32471-00004

Permit Writer: Mark Neyman

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 nearest active PM2.5 monitor to IPL Eagle Valley is the West 18th Street PM2.5 monitor in western 

Marion County. The 2011 wind rose taken from the Indianapolis International Airport in 

Indianapolis, Marion County shows the winds typically blow from the southwest and west. IPL Eagle 

Valley would be considered upwind of the West 18th Street monitor.

Indianapolis 2011

The 2009 – 2012 annual PM2.5 design value at the West 18th Street monitor in Marion County is 12.7

μg/m3

, which is just above the annual PM2.5 NAAQS of 12.0 μg/m3. The 2009 – 2012 24-hour PM2.5

design value at the West 18th Street monitor in Marion County is 29.0 μg/m3

, below the 24-hour PM2.5 

NAAQS of 35.0 μg/m3. 

Secondary PM2.5 Weight of Evidence Analysis based on EPA’s CSAPR Modeling

Because of the well established relationship between NOx and SO2, and the regional transport and 

formation of PM2.5, U.S. EPA recently finalized the Cross State Air Pollution Rule (CSAPR) to assist states 

to meet the PM2.5 NAAQS. 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). While the U.S. Court of Appeals for 

the D.C. Circuit issued a decision vacating CSAPR on August 21, 2012, the modeling analysis conducted 

by U.S. EPA is considered valid and will be used for the secondary PM2.5 analysis. 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 IPL Eagle Valley, 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
IPL Eagle Valley Gen. Station Page 15 of 17

Martinsville, Indiana PSD/SSM No. T109-32471-00004

Permit Writer: Mark Neyman

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 CSAPR website for technical information : 

http://www.epa.gov/crossstaterule/techinfo.html. The spreadsheet shows the base case annual SO2 and 

NOx emissions for Indiana in 2012 and 2014. Indiana’s total SO2 and NOx emission reductions between 

these two base cases scenarios are 89,222 tons, summarized in Table 10 on page 14. All surrounding 

states make similar significant reductions. Potentials to emit after controls for IPL Eagle Valley are 176.7

tons per year of NOx and 30.9 tons per year of SO2 for a total of 207.6 tons per year of NOx and SO2

emissions.

Table 10

EPA’s Cross-State Air Pollution Rule Emission Summary for Indiana

Pollutant

2012 

Base Case

Emissions

(tons/year)

2014 

Base Case

Emissions

(tons/year)

2012-2014 

Difference

(tons/year)

Indiana SO2 929,162 863,923 65,239

Indiana NOx 455,325 431,342 23,983

TOTAL 89,222

Annual PM2.5 Modeling Results

The latest annual PM2.5 design value (2010-2012) for the nearest PM2.5 monitor to IPL Eagle Valley is the 

West 18th Street monitor in Marion County is 12.7 μg/m3

. The maximum annual PM2.5 modeled 

concentration for the West 18th Street PM2.5 monitor is 15.16 μg/m3 for the 2012 base case and 14.65

μg/m3 for the 2014 base case results. This is a decrease of 0.51 μg/m3

. Indiana’s 2014 SO2 emissions 

from EGUs were adjusted by 65,239 tons from the 2012 base case emissions and 2014 NOx emissions 

were reduced by 23,983 for a total of 89,222 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 and NOx emission reductions will occur by 2014, many of which will impact the Marion 

County monitor. Therefore, to estimate the impact of IPL Eagle Valley on modeled concentrations, the 

ratio of IPL Eagle Valley’s SO2 and NOx emissions to Indiana’s SO2 and NOx decreases from 2012 and 

2014 base case CSAPR emissions were calculated. This ratio was then compared to the modeled annual 

PM2.5 impact from the difference between the CSAPR 2012 and 2014 base case annual PM2.5 modeling 

results.

1) 207.6 tons IPL Eagle Valley’s SO2 and NOx emissions / 89,222 tons of SO2 and NOx emissions 

reduced through CSAPR modeling = 0.233%

2) 0.233% IPL Eagle Valley SO2/NOx emission ratio * 0.51 μg/m3 modeled annual PM2.5 CSAPR results 

at the West 18th Street monitor = 0.0012 μg/m3 of IPL Eagle Valley annual PM2.5 impact 

3) 0.0012 μg/m3 IPL Eagle Valley’s annual PM2.5 impact /14.65 μg/m3 of 2014 Base Case annual PM2.5

modeled results at the West 18th Street monitor = 0.008% IPL Eagle Valley’s impact on the 2014 modeled 

Base Case annual PM2.5 results.
IPL Eagle Valley Gen. Station Page 16 of 17

Martinsville, Indiana PSD/SSM No. T109-32471-00004

Permit Writer: Mark Neyman

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 on page 15 shows the CSAPR annual PM2.5 modeled 

concentrations at the Marion County PM2.5 monitors and IPL Eagle Valley anticipated impacts.

It should be noted that the monitor at West 18th Street violates the 2012 PM2.5 NAAQS. The impact from

the new IPL Eagle Valley project taken by itself, even though below detection limits of a monitor, would

contribute to a NAAQS violation. However, as noted in “Table 3: Projected Net Emissions 

Increase/Decreases based on 2010 and 2011 Actual Emissions (Tons per year)”, emissions of SO2, NOx, 

and direct PM2.5 will all be reduced by well over 1000 tons each per year. Further, permit condition “D.1.0 

Retirement of Existing Operations. (a)” specifies that IPL Eagle Valley will permanently discontinue the 

operation of existing emission units prior to the startup of the turbines. Therefore, the new turbines will 

never operate at the same time as the old units and will emit substantially less pollutants, resulting in less 

impact on the West 18th Street monitor than the previous configuration.

Table 11

EPA’s Cross-State Air Pollution Rule - Annual PM2.5 Modeling Results

Monitor ID County

2012

Base

2014

Base

2012 - 2014

Base

(μg/m3)

Anticipated 

Source Impact

(μg/m3)

Source Impact on 

2014 Base Case

Results (%)

180970081 Marion 15.16 14.65 0.51 0.0012 0.0081%

180970083 Marion 15.06 14.55 0.51 0.0012 0.0082%

180970043 * Marion 13.45 12.97 0.48 0.0011 0.0086%

* Monitor not longer active

24-Hour PM2.5 Modeling Results

The same emissions and impact analysis methodology used for the annual PM2.5 impacts were used to 

determine the 24-hour PM2.5 impacts from IPL Eagle Valley. The latest 24-hour PM2.5 design value (2010-

2012) for the nearest PM2.5 monitor to IPL Eagle Valley is the West 18th Street monitor in Marion County is

29.0 μg/m3

. The maximum 24-hour PM2.5 modeled concentration for the West 18th Street PM2.5 monitor is

36.9 μg/m3 for the 2012 base case and 35.1 μg/m3 for the 2014 base case. This is a reduction of modeled 

concentration of 1.8 μg/m3

. To estimate the 24-hour impact of IPL Eagle Valley on modeled 

concentrations, the ratio of IPL Eagle Valley SO2 and NOx emissions and the CSAPR SO2 and NOx

emission reductions were calculated. This ratio was then compared to the modeled 24-hour PM2.5 impact 

from the difference between the CSAPR 2012 and 2014 base case 24-hour PM2.5 modeling results.

1) 207.6 tons IPL Eagle Valley SO2 and NOx emissions / 89,222 tons of SO2 and NOx emissions 

reduced through CSAPR modeling = 0.233%

2) 0.233% IPL Eagle Valley SO2/NOx emission ratio * 1.8 μg/m3 modeled 24-hour PM2.5 CSAPR results at 

the West 18th Street monitor = 0.0042 μg/m3 of IPL Eagle Valley 24-hour PM2.5 impact 

3) 0.0042 μg/m3 IPL Eagle Valley 24-hour PM2.5 impact /35.1 μg/m3 of 2014 Base Case 24-hour PM2.5

modeled results at the West 18th Street monitor = 0.012% IPL Eagle Valley’s impact on the 2014 modeled 
IPL Eagle Valley Gen. Station Page 17 of 17

Martinsville, Indiana PSD/SSM No. T109-32471-00004

Permit Writer: Mark Neyman

Base Case 24-hour PM2.5 concentration.

Modeling results below in Table 12 show 2012 and 2014 Base Case modeled 24-hour concentrations and 

the anticipated IPL Eagle Valley 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

2012

Base

2014

Base

2012 - 2014

Base

(μg/m3)

Anticipated 

Source Impact

(μg/m3)

Source Impact on

2014 Base Case

Results (%)

180970081 Marion 36.9 35.1 1.8 0.0042 0.012%

180970083 Marion 34.5 32.7 1.8 0.0042 0.013%

180970043 * Marion 33.5 32.1 1.4 0.0033 0.010%

* Monitor not longer active

Summary Annual and 24-Hour PM2.5

IPL Eagle Valley’s 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 IPL Eagle Valley emissions were compared with the amount of SO2 and NOx

emission 

reductions realized from the CSAPR modeling analysis and compared with CSAPR modeling results for 

annual and 24-hour, the impacts from IPL Eagle Valley on the nearest PM2.5 monitor is anticipated to be 

minimal and will not have an effect on the attainment status of any PM2.5 monitors in the area.

Part I - Summary of Air Quality Analysis

IPL Eagle Valley has applied for a PSD major source modification of their facility in Martinsville, Indiana 

with an increase in CO, NO2, PM10, PM2.5, SO2, and VOC emissions. ERM Consultants in Rolling 

Meadows, Illinois prepared the air quality analysis portion of the PSD permit application. Morgan County

is designated as attainment for all criteria pollutants. CO, NO2, PM10, PM2.5 and VOC emission rates 

associated with the proposed IPL Eagle Valley facility PSD major source modification did exceed the 

respective significant emission rates. Modeling results taken from the latest 12345 version of the 

AERMOD model showed the 1-hour and 8-hour CO and the annual PM10 modeled impacts were predicted 

to be less than the SILs and the NAAQS and PSD increment analyses were not required for these specific 

pollutant’s time averaging periods. The NAAQS and PSD increment analysis were required for the 1-hour 

and annual NO2, the 24-hour PM10 and PM2.5, and the annual PM2.5. Since there is currently no 1-hour 

NO2 PSD increment, only an annual NO2 PSD increment analysis was required for NO2. The 1-hour NO2

NAAQS analysis showed modeled violations, but the additional NO2 contribution analysis showed the IPL 

Eagle Valley facility had an impact below the 1-hour NO2 SIL for the violating receptors. IPL Eagle Valley

did trigger the preconstruction monitoring for PM10 and PM2.5 which was satisfied by existing monitoring 

data. A secondary ozone formation and a secondary PM2.5 formation analysis were performed. The 

nearest Class I area is Mammoth Cave National Park near Cave City, Kentucky approximately 300

kilometers from the IPL Eagle Valley plant. An additional impact analysis was completed, but the 

operation of the proposed IPL Eagle Valley facility will have no significant impact on the region 

surrounding the facility or on the Class I area.
Page 1 of 152

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: IPL Eagle Valley Generating Station

Source Location: 4040 Blue Bluff Road, Martinsville, Indiana, 

46151

County: Morgan

SIC Code: 4911

Operation Permit No.: T109-26292-00004

Operation Permit Issuance Date: December 2, 2008

PSD/Significant Source Modification No.: T109-32471-00004

Significant Permit Modification No.: T109-32476-00004

Permit Reviewer: Josiah Balogun

Proposed Expansion

IPL Eagle Valley Generating Station is proposing to replace the current coal and oil fired electric 

generating units at Indianapolis Power and Light’s (IPL’s) Eagle Valley Generating Station (EVGS) with a 

state-of-the-art, highly efficient combined cycle combustion turbine generation facility. The proposed 

combined cycle facility would include two nominal 192.5 Mega Watt (MW) combustion turbines with steam 

waste heat recovery to drive a nominal 271 MW steam turbine generator. The new facility would have a 

total nominal capacity of 656 MW (net). The exclusive fuel for the new combustion turbines will be natural 

gas.

IPL Eagle Valley Generating Station is required to undergo a review of control technology for 

pollutants above the significant levels under Federal and State Prevention of Significant Deterioration 

(PSD) Regulations.

IPL Eagle Valley Generating Station is located at the 4040 Blue Bluff Road, Martinsville, Indiana, 

in Morgan County. IPL Eagle Valley Generating Station submitted a PSD application to IDEM, OAQ on 

October 31, 2012.

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 

modification because the modification 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, VOC, CO, NOx, H2SO4 and Greenhouse Gases 

that exceeded the PSD significant levels. 

See Appendix A – Emission Calculations – of this TSD for detailed Potential to Emit (PTE) calculations.
IPL Eagle Valley generating Station TSD – Appendix B Page 2 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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) Two (2) natural gas fired combustion turbine units each with a natural gas fired duct 

burner identified as EU-1 and EU-2, permitted in 2013, each with a total rated heat input 

capacity of 2,542 MMBtu/hr; with NOx emissions controlled by low combustion burner 

design and Selective Catalytic Reduction (SCR), and each with an oxidation catalyst 

system to reduce emissions of CO and VOCs including formaldehyde, and exhausting to 

stacks S-1 and S-2. Each stack has continuous emissions monitors (CEMS) for NOx.

*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 and combustion turbines which are a source of emissions.

(b) One (1) natural gas fired Auxiliary Boiler, identified as emission unit EU-3, permitted in 

2013, with a rated heat input capacity of 79.3 MMBtu/hr, equipped with low NOx burners

(LNB) with flue gas recirculation (FGR) to reduce NOx emissions exhausting to stack S-3. 

(c) One (1) natural gas fired Dew Point Heater, identified as emission unit EU-4, permitted in 

2013, with a rated heat input capacity of 20.8 MMBtu/hr exhausting to stack S-4.

Insignificant and Trivial Activities 

The source also consists of the following insignificant activities as defined in 326 IAC 2-7-1(21):

(a) One (1) distillate oil fired Emergency Generator, identified as emission unit EU-5, 

permitted in 2013, with a rated capacity of 1,826 HP and exhausting through stack S-5.

[Under 40 CFR 60, Subpart IIII, the Emergency Generator is considered new affected 

sources.][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Generator is considered 

new affected sources.]

(b) One (1) distillate oil fired Emergency Fire Pump, identified as emission unit EU-6, 

permitted in 2013, with a rated capacity of 500 HP and exhausting through stack S-6.

[Under 40 CFR 60, Subpart IIII, the Emergency Fire Pump is considered new affected 

sources.][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Fire Pump is considered 

new affected sources.]

(c) One (1) evaporative cooling tower, identified as emission unit U-7, rated with a circulation 

rate of 192,000 gpm to provide non-contact cooling water to the steam turbine 

condenser, permitted in 2013, and equipped with high efficiency drift eliminators. 

(d) Electrical Circuit Breakers containing sulfur hexafluoride (SF6) identified as emissions 

unit F-1, permitted in 2013, with fugitive emissions controlled by full enclosure.

(e) Fugitive equipment leaks from the natural gas supply lines, identified as F-2 controlled by 

a Leak Detection and Repair (LDAR) program.

(f) Three (3) Turbine Lube Demister Vents, permitted in 2013.
IPL Eagle Valley generating Station TSD – Appendix B Page 3 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

Summary of the Best Available Control Technology (BACT) Process

BACT is an emission limitation based on the maximum degree of pollution reduction of emissions,

which is continuously achievable as a practical matter on a case-by-case basis. This 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, IPL 

Eagle Valley Generating Station will be required to demonstrate that the emissions will be reduced to 

the 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

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. IPL 

Eagle Valley Generating Station has not submitted any innovative control technology. 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 and any more stringent limits established 

from other RBLC Permits.

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
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consideration cannot be eliminated based on adverse energy, environmental, or economic

impacts. In no case can the selected BACT be less stringent than any New Source 

Performance Standard (NSPS), National Emission Standards for Hazardous Air Pollutants 

(NESHAP) or Reasonably Available Control Technologies (RACT) standard emission limit.

Step 5: Select BACT

The fifth and final step is to select as BACT the most effective of the remaining technologies 

under consideration for each pollutant of concern. For the technologies determined to be 

feasible, there may be several different limits that have been set as BACT for the same 

control technology. The permitting agency has to choose the most stringent limit as BACT 

unless the applicant demonstrates in a convincing manner why that limit is not feasible.

Particulate Matter (PM/PM10) BACT – Combined Cycle Combustion Turbines EU-1 - EU-2

Step 1: Identify Potential Control Technologies

Emissions of PM and PM10 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 and PM10 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. 
IPL Eagle Valley generating Station TSD – Appendix B Page 5 of 152

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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. 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 combustion turbines 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 (EU-1 and EU-2) 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. Natural-gas fired CCCTs generate low Particulate emissions and have large exhaust 

flow-rates, resulting in very low concentrations of Particulates. Electrostatic precipitator (ESPs) 

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 (EU-1 and EU-2) at this source.
IPL Eagle Valley generating Station TSD – Appendix B Page 6 of 152

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Wet scrubbers:

A wet scrubber is an air pollution control device that removes particulate matter 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 particulate matter. Collection efficiencies for 

wet scrubbers vary with the particle size distribution of the waste gas stream. In general, 

collection efficiency decreases as the particulate matter 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 particulate matter 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. The 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 combustion turbines generate low Particulate emissions and have 

large exhaust flowrates, resulting in very low concentrations of Particulates. A wet scrubber

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 combined cycle combustion 

turbines (EU-1 and EU-2) 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.
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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 combustion turbines generate low Particulate emissions and 

have large exhaust flow rates, resulting in very low concentrations of Particulates. Cyclones

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 (EU-1 and EU-2) 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 and PM10 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 (EU-1 and EU-2) 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 and PM10 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 (EU-1 and EU-2) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of PM and PM10 resulting from the 

operation of the combined cycle combustion turbines (EU-1 and EU-2). 

(1) Fuel Specifications; and 

(2) Good Combustion Practices 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM and PM10 BACT determination along with the existing 

PM and PM10 BACT determinations for similar plants. All data in the table is based on the 

information obtained from the permit application submitted by IPL Eagle Valley Generating 

Station, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of 

permits available at the websites of other permitting agencies and IDEM's PSD Permits. 

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Combined Cycle 

Combustion 

Turbines (EU-1 & 

EU-2)

2,542 

MMBtu/hr, 

each

PM and PM10: 

16.8 pounds per 

hour and 0.0066

lbs/MMBtu, with 

duct firing based 

on 3-hr average

Good 

Combustion 

Practice and 

Fuel 

Specification
IPL Eagle Valley generating Station TSD – Appendix B Page 8 of 152

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Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

13.9 pounds per 

hour and 0.0055

lbs/MMBtu without 

duct firing based 

on 3-hr average

Permit No. 

141-31003-

00579

St. Joseph 

Energy 

Center -

proposed

12/03/2012

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

LA-0254 Entergy 

Louisiana, 

LLC, 

Ninemile 

Point Electric 

Generating 

Plant -

Jefferson, LA

08/16/2011

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine, with fuel 

oil as back-up

7146 

MMBtu/hr

PM2.5 & PM10: 

26.23 lb/hr, hourly 

avg w/out duct 

burner; 33.16 

lb/hr, hourly avg 

w/duct burner

None

OK-0129

Associated 

Electric 

Cooperative, 

Inc. 

Chouteau 

Power Plant -

Mayes, OK

01/23/2009 Combined Cycle 

Cogeneration 

> 25MW 

(1,882 

MMBtu/hr)

PM10: 6.59 lb/hr 

3-hr avg; 0.0035 

lb/MMBtu 24-hr 

avg

None 

(Oxidation 

catalyst was 

not used)

VA-0308

Virginia 

Electric & 

Power Co, 

Warren 

County 

Facility -

Warren, VA

01/14/2008

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine (2 units 

each with a HRSG 

and 500 MMbtu/hr 

DB)

1,717 

MMBtu/hr 0.013 lb/MMBtu None

MN-0071

Minnesota 

Municipal 

Power 

Agency, 

Fairbaul 

Tenergy Park 

- Rice, MN

06/05/2007

Natural gas-fired 

and Distillate fuelfired Combined 

Cycle Combustion 

Turbine, with ultralow sulfur diesel 

fuel as backup

1758 

MMBtu/hr

0.01 lb/MMBtu 

(CTG NG or CTG 

& DB NG); 0.015 

lb/MMBtu (CTG 

NG & DB oil); 0.03 

lb/MMBtu (CTG oil 

& DB Not operate 

or NG or oil)

None

FL-0280

Florida 

Municipal 

Power 

Agency, 

Treasure 

Coast Energy 

Center - St. 

Lucie, FL

05/30/2006

Combined Cycle 

Combustion 

Turbine

170 MW

0.02 gr/dscf, 

natural gas 

specification; 

0.0015% sulfur by 

weight fuel oil 

spec; 10% opacity

None
IPL Eagle Valley generating Station TSD – Appendix B Page 9 of 152

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Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

NY-0095

Caithness 

Bellport 

Energy 

Center -

Suffolk, NY

05/10/2006 Natural gas-fired 

Combined Cycle 

Combustion 

Turbine

2221 

MMBtu/hr

PM10: 0.0055 

lb/MMBtu w/out 

DB; 0.006 

lb/MMBtu w/DB; 

Low sulfur fuel

None

Fuel oil-fired 

Combined Cycle 

Combustion 

Turbine

2125 

MMBtu/hr

PM10: 0.0510 

lb/MMBtu w/out 

DB 90-100% load; 

0.0610 lb/MMBtu 

w/out DB 75-90% 

load; 0.0410 

lb/MMBtu w/DB; 

Low sulfur fuel

None

AZ-0047

Dome Valley 

Energy 

Partners, 

Wellton 

Mohawk 

Generating 

StationYuma, AZ

12/01/2004

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine and 

HRSG

170 MW PM10: 29.8 lb/hr, 

3-hr avg None

WI-0227

WE Energies 

(Port 

Washington 

Generating 

Station)-

Washington, 

WI

10/13/2004

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine (4 units 

with duct burner, 

HRSG)

2,096 

MMBtu/hr

33.0 lb/hr 

PM/PM10

None

The RBLC was reviewed and a summary of the BACT determinations for PM/PM10 fine emissions from 

combustion turbines is shown in the table above. It should be noted that there were no facilities identified 

that listed any add-on control technologies to limit particulate emissions from combustion turbines. These 

emission levels appear to be as much art as science, and are at most characterized by the case specific 

sulfur content of pipeline natural gas which varies from pipeline to pipeline. Gas pipeline sulfur content (as 

well as other potential impurities) must meet the ASTM specification for pipeline natural gas, but will vary 

over time and from pipeline to pipeline based on the source and quality of the gas wells serving the 

system. The quality of pipeline natural gas received on the day of a given performance test is outside the 

direct control of the facility that receives its natural gas from the pipeline, and this variability may in part 

help explain the variability in resulting particulate emissions that have been observed by the combustion 

turbine manufacturers. 

Another case-specific factor may be ambient levels of airborne particulate emissions that were present on 

the day of the test. Such particulate emissions would not be expected to be removed in the combustion 

turbine inlet filter, but would be fine enough to go right on through. From evaluating EPA monitoring data, 

the that ambient levels of particulate vary with location and with local meteorology, and hence might 

influence tested emissions measured on one day versus another. This too represents a case-specific 

factor outside the control of the facility. 

The selection of BACT must result in an emission limitation which is achievable (including a reasonable 

compliance margin) such that the facility has the ability to assure that compliance can be maintained. 

Since the facility has no active control over these site specific and case specific factors, and no known 

ability to reduce its emissions of PM2.5 if needed to demonstrate compliance, BACT emission limitations 
IPL Eagle Valley generating Station TSD – Appendix B Page 10 of 152

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for PM and PM10 must be set at levels for which compliance can be assured by the facility as a practical 

matter. 

The RBLC search revealed only limited entries for PM2.5 from a similar source. In all cases, the only 

available control for PM/PM10/PM2.5 for combustion turbines is the use of sweet natural gas (that is 

pipeline quality natural gas) and this “control technology”, albeit variable from site to site and month to 

month, was determined to represent the top level of control for emission of fine particulate. The lowest 

BACT limitation resulting from exclusive use of sweet pipeline natural gas in similar combined cycle 

combustion turbines with duct firing and oxidation catalyst technology identified was for the Caithness 

project in NY with the identical “control technology” as the IPL project, and limitations of 0.0055 lb/MMBtu 

from the turbines only at full load (full load operation is defined by the test methods of 40 CFR 60) of 

0.0055 lb/MMBtu, and at full load with duct firing at 0.0066 lb/MMBtu.

The Chouteau facility in Oklahoma permitted in 2009 has a limit of 0.0035 lbs/MMBtu (24-hour average) 

as compared with limit proposed by IPL of 0.0055 lbs/MMBtu (w/o duct burners). This 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 following has been proposed as BACT for PM and PM10 emissions from the proposed combined 

cycle combustion turbines, identified as EU-1 - EU-2:

1. The PM and PM10 emissions from the combined cycle combustion turbines identified as 

EU-1 - EU-2 shall not exceed 16.8 lb/hour and 0.0066 lb/MMBtu with duct firing based on 

3-hr average through the use of good combustion practices and fuel specification. 

2. The PM and PM10 emissions from the combined cycle combustion turbines identified as 

EU-1 - EU-2 shall not exceed 13.9 pounds per hour and 0.0055 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 and PM10 for the combustion turbines (EU-1 - EU-2).

1. The PM and PM10 emissions from the combined cycle combustion turbines identified as 

EU-1 and EU-2 shall not exceed 16.8 pounds per hour, each and 0.0066 pounds per 

MMBtu, each with duct firing based on 3-hr average through the use of good combustion 

practices. 

2. The PM and PM10 emissions from the combined cycle combustion turbines identified as 

EU-1 and EU-2 shall not exceed 13.9 pounds per hour, each and 0.0055 pounds per 

MMBtu, each without duct firing based on 3-hr average through the use of good 

combustion practices. 

3. Only pipeline natural gas only shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.
IPL Eagle Valley generating Station TSD – Appendix B Page 11 of 152

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Permit Writer: Josiah Balogun and SPM 109-32476-00004

Particulate Matter (PM2.5) BACT – Combined Cycle Combustion Turbines EU-1 - EU-2

Step 1: Identify Potential Control Technologies

Emissions of 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, 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. 

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.
IPL Eagle Valley generating Station TSD – Appendix B Page 12 of 152

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Permit Writer: Josiah Balogun and SPM 109-32476-00004

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. 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 combustion turbines 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 (EU-1 and EU-2) 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. Natural-gas fired CCCTs generate low Particulate emissions and have large exhaust 

flow-rates, resulting in very low concentrations of Particulates. An electrostatic precipitator (ESP) 

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 (EU-1 and EU-2) at this source.

Wet scrubbers:

Wet high energy scrubber technology may also be employed to control solid particulate matter in 

certain industrial applications. Wet scrubbers operate in such a manner that flue gas passes 

through a water (or other solvent) stream whereby particles in the gas stream are removed 

through inertial impaction and/or condensation of liquid droplets on the particles in the gas 
IPL Eagle Valley generating Station TSD – Appendix B Page 13 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

stream. High energy scrubbers are marginally effective at controlling fine filterable particulate, but 

are incapable of controlling condensable particulate below the flue gas saturation temperature. 

In the case of natural gas-fired combustion turbines, whose particulate emissions are understood 

to exist almost exclusively as condensable PM2.5, none of the identified traditional particulate 

control technologies identified would exhibit any meaningful emission control. None of these 

technologies has ever been applied to a combined cycle industrial combustion turbine and are 

certainly not demonstrated in practice in such an application. Further, their application would 

result in a significant increase in turbine backpressure, which would rob efficiency, and in order to 

produce the same output would result in a collateral increase in all other criteria air pollutants. 

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 (EU-1 and EU-2) 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 combustion turbines generate low Particulate emissions and 

have large exhaust flow rates, resulting in very low concentrations of Particulates. Cyclones

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 (EU-1 and EU-2) 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 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 (EU-1 and EU-2) 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 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 (EU-1 and EU-2) at this source.
IPL Eagle Valley generating Station TSD – Appendix B Page 14 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of PM2.5 resulting from the operation of 

the combined cycle combustion turbines (EU-1 and EU-2). 

(1) Fuel Specifications; and 

(2) Good Combustion Practices 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM2.5 BACT determination along with the existing PM2.5

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permits. 

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Combined Cycle 

Combustion 

Turbines (EU-1 & 

EU-2)

2,542 

MMBtu/hr, 

each

PM2.5: 16.8 pounds 

per hour and 

0.0066 lbs/MMBtu, 

with duct firing 

based on 3-hr 

average

Good 

Combustion 

Practice and 

Fuel 

Specification

13.9 pounds per 

hour and 0.0055 

lbs/MMBtu without

duct firing based 

on 3-hr average

Permit No. 

141-31003-

00579

St. Joseph 

Energy 

Center -

proposed

12/03/2012

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

LA-0254

Entergy 

Louisiana, 

LLC, 

Ninemile 

Point Electric 

Generating 

Plant -

Jefferson, LA

08/16/2011

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine, with fuel 

oil as back-up

7146 

MMBtu/hr

PM2.5 & PM10: 

26.23 lb/hr, hourly 

avg w/out duct 

burner; 33.16 

lb/hr, hourly avg 

w/duct burner

None

OK-0129

Associated 

Electric 

Cooperative, 

Inc. 

Chouteau 

Power Plant -

Mayes, OK

01/23/2009 Combined Cycle 

Cogeneration 

> 25MW 

(1,882 

MMBtu/hr)

PM10: 6.59 lb/hr 

3-hr avg; 0.0035 

lb/MMBtu 24-hr 

avg

None 

(Oxidation 

catalyst was 

not used)
IPL Eagle Valley generating Station TSD – Appendix B Page 15 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

VA-0308

Virginia 

Electric & 

Power Co, 

Warren 

County 

Facility -

Warren, VA

01/14/2008

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine (2 units 

each with a HRSG 

and 500 MMbtu/hr 

DB)

1,717 

MMBtu/hr 0.013 lb/MMBtu None

MN-0071

Minnesota 

Municipal 

Power 

Agency, 

Fairbaul 

Tenergy Park 

- Rice, MN

06/05/2007

Natural gas-fired 

and Distillate fuelfired Combined 

Cycle Combustion 

Turbine, with ultralow sulfur diesel 

fuel as backup

1758 

MMBtu/hr

0.01 lb/MMBtu 

(CTG NG or CTG 

& DB NG); 0.015 

lb/MMBtu (CTG 

NG & DB oil); 0.03 

lb/MMBtu (CTG oil 

& DB Not operate 

or NG or oil)

None

FL-0280

Florida 

Municipal 

Power 

Agency, 

Treasure 

Coast Energy 

Center - St. 

Lucie, FL

05/30/2006

Combined Cycle 

Combustion 

Turbine

170 MW

0.02 gr/dscf, 

natural gas 

specification; 

0.0015% sulfur by 

weight fuel oil 

spec; 10% opacity

None

NY-0095

Caithness 

Bellport 

Energy 

Center -

Suffolk, NY

05/10/2006 Natural gas-fired 

Combined Cycle 

Combustion 

Turbine

2221 

MMBtu/hr

PM10: 0.0055 

lb/MMBtu w/out 

DB; 0.006 

lb/MMBtu w/DB; 

Low sulfur fuel

None

Fuel oil-fired 

Combined Cycle 

Combustion 

Turbine

2125 

MMBtu/hr

PM10: 0.0510 

lb/MMBtu w/out 

DB 90-100% load; 

0.0610 lb/MMBtu 

w/out DB 75-90% 

load; 0.0410 

lb/MMBtu w/DB; 

Low sulfur fuel

None

AZ-0047

Dome Valley 

Energy 

Partners, 

Wellton 

Mohawk 

Generating 

StationYuma, AZ

12/01/2004

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine and 

HRSG

170 MW PM10: 29.8 lb/hr, 

3-hr avg None

WI-0227

WE Energies 

(Port 

Washington 

Generating 

Station)-

Washington, 

WI

10/13/2004

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine (4 units 

with duct burner, 

HRSG)

2,096 

MMBtu/hr

33.0 lb/hr 

PM/PM10

None
IPL Eagle Valley generating Station TSD – Appendix B Page 16 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

The RBLC was reviewed and a summary of the BACT determinations for PM/PM10/PM2.5 fine emissions 

from combustion turbines is shown in the table above. It should be noted that there were no facilities 

identified that listed any add-on control technologies to limit particulate emissions from combustion 

turbines. These emission levels appear to be as much art as science, and are at most characterized by 

the case specific sulfur content of pipeline natural gas which varies from pipeline to pipeline. Gas pipeline 

sulfur content (as well as other potential impurities) must meet the ASTM specification for pipeline natural 

gas, but will vary over time and from pipeline to pipeline based on the source and quality of the gas wells 

serving the system. The quality of pipeline natural gas received on the day of a given performance test is 

outside the direct control of the facility that receives its natural gas from the pipeline, and this variability 

may in part help explain the variability in resulting particulate emissions that have been observed by the 

combustion turbine manufacturers. 

Another case-specific factor may be ambient levels of airborne particulate emissions that were present on 

the day of the test. Such particulate emissions would not be expected to be removed in the combustion 

turbine inlet filter, but would be fine enough to go right on through. From evaluating EPA monitoring data, 

the that ambient levels of particulate vary with location and with local meteorology, and hence might 

influence tested emissions measured on one day versus another. This too represents a case-specific 

factor outside the control of the facility. 

The selection of BACT must result in an emission limitation which is achievable (including a reasonable 

compliance margin) such that the facility has the ability to assure that compliance can be maintained. 

Since the facility has no active control over these site specific and case specific factors, and no known 

ability to reduce its emissions of PM2.5 if needed to demonstrate compliance, BACT emission limitations 

for PM, PM10 and PM2.5 must be set at levels for which compliance can be assured by the facility as a 

practical matter. 

The RBLC search revealed only limited entries for PM2.5 from a similar source. In all cases, the only 

available control for PM/PM10/PM2.5 for combustion turbines is the use of sweet natural gas (that is 

pipeline quality natural gas) and this “control technology”, albeit variable from site to site and month to 

month, was determined to represent the top level of control for emission of fine particulate. The lowest 

BACT limitation resulting from exclusive use of sweet pipeline natural gas in similar combined cycle 

combustion turbines with duct firing and oxidation catalyst technology identified was for the Caithness 

project in NY with the identical “control technology” as the IPL project, and limitations of 0.0055 lb/MMBtu 

from the turbines only at full load (full load operation is defined by the test methods of 40 CFR 60) of 

0.0055 lb/MMBtu, and at full load with duct firing at 0.0066 lb/MMBtu. 

The Chouteau facility in Oklahoma permitted in 2009 has a limit of 0.0035 lbs/MMBtu (24-hour average) 

as compared with limit proposed by IPL of 0.0055 lbs/MMBtu (w/o duct burners). This 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 following has been proposed as BACT for PM2.5 emissions from the proposed combined cycle 

combustion turbines, identified as EU-1 - EU-2:

1. The PM2.5 emissions from the combined cycle combustion turbines identified as EU-1 -

EU-2 shall not exceed 16.8 lb/hour and 0.0066 lb/MMBtu with duct firing based on 3-hr 

average through the use of good combustion practices and fuel specification. 

2. The PM2.5 emissions from the combined cycle combustion turbines identified as EU-1 -

EU-2 shall not exceed 13.9 pounds per hour and 0.0055 lb/MMBtu without duct firing 

based on 3-hr average through the use of good combustion practices and fuel 

specification. 
IPL Eagle Valley generating Station TSD – Appendix B Page 17 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD)), IDEM has established 

the following as BACT for PM2.5 for the combustion turbines (EU-1 - EU-2).

1. The PM2.5 emissions from the combined cycle combustion turbines identified as EU-1 

and EU-2 shall not exceed 16.8 pounds per hour, each and 0.0066 pounds per MMBtu, 

each with duct firing based on 3-hr average through the use of good combustion 

practices. 

2. The PM2.5 emissions from the combined cycle combustion turbines identified as EU-1 

and EU-2 shall not exceed 13.9 pounds per hour, each and 0.0055 pounds per MMBtu, 

each without duct firing based on 3-hr average through the use of good combustion 

practices. 

3. Only pipeline natural gas only shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

Sulfuric Acid (H2SO4) BACT – Combined Cycle Combustion Turbines EU-1 & EU-2

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.
IPL Eagle Valley generating Station TSD – Appendix B Page 18 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 (EU-1 and EU-2) 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.

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.

Dry sorbent injection is not listed in the RBLC as BACT for the control of H2SO4 emissions for 

large combined cycle combustion turbines.

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 (EU-1 and EU-2) 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 (EU-1 and EU-2) 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 (EU-1 and EU-2). 

(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 IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Combined 

Cycle 

Combustion 

Turbines (EU2,542 

MMBtu/hr, 

each

H2SO4: 0.75 

gr S/100 scf 

of natural gas

Fuel 

Specification
IPL Eagle Valley generating Station TSD – Appendix B Page 19 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

1 & EU-2)

Permit No. 

141-31003-

00579

St. Joseph

Energy Center 

12/03/2012 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 gr S/100 scf 

gas

Fuel 

Specification

IDEM is proposing a natural gas sulfur content limit of 0.75 gr S/100 scf which 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. 

The following has been proposed as BACT for H2SO4 emissions from the proposed combined 

cycle combustion turbines, identified as EU-1 - EU-2:

(a) The H2SO4 emissions from the combined cycle combustion turbines identified as EU-1 

and EU-2 shall be limited by restricting the S content of the natural gas to 0.75 gr S/100 

scf on a monthly average basis.

(b) Only pipeline natural gas shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

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 (EU-1 - EU-2).

(a) The H2SO4 emissions from the combined cycle combustion turbines identified as EU-1 

and EU-2 shall be limited by restricting the S content of the natural gas to 0.75 gr S/100 

scf on a monthly average basis.

(b) Only pipeline natural gas shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.
IPL Eagle Valley generating Station TSD – Appendix B Page 20 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

Carbon Monoxide (CO) BACT – Combined Cycle Combustion Turbines EU-1 and EU-2

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.

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. Oxidizers are not recommended for controlling gases with sulfur containing 

compounds because of the formation of highly corrosive acid gases.

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.
IPL Eagle Valley generating Station TSD – Appendix B Page 21 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 (EU-1 and EU-2) 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 (EU-1 and EU-2) 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. This 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 (EU-1 and EU-2) 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 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 (EU-1 and EU-2) at this source.
IPL Eagle Valley generating Station TSD – Appendix B Page 22 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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

(EU-1 and EU-2) 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 (EU-1 and EU-2) at this source

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 IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Combined Cycle 

Combustion 

Turbines (EU-1 

& EU-2)

2,542 

MMBtu/hr, 

each

CO: 2.0 ppmvd 

@15% O2, with 

duct burners 

based on 3-hr 

average

Oxidation 

Catalyst

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center 

12/03/2012 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
IPL Eagle Valley generating Station TSD – Appendix B Page 23 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

LA-0254

Entergy 

Louisiana, 

LLC, Ninemile 

Point Electric 

Generating 

PlantJefferson, LA

08/16/2011

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine, with fuel 

oil as back-up

7146 

MMBtu/hr

3.00 ppmvd @ 

15% O2 hourly 

avg

Oxidation

catalyst

GA-0138

Live Oaks 

Company, 

LLC, Live 

Oaks Power 

Plant- Glynn, 

GA

04/08/2010

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine

600 MW

2.0 ppm @ 15% 

O2, 3-hr 

avg(w/out duct 

firing); 3.2 ppm 

@ 15% O2, 3-hr 

avg(w/duct 

firing); 208 tpy

Catalytic 

oxidation

OK-0129

Associated 

Electric 

Cooperative, 

Inc. Chouteau 

Power PlantMayes, OK

01/23/2009 Combined Cycle 

Cogeneration 

> 25MW 

(1,882 

MMBtu/hr)

8.0 ppmv 1-hr 

avg; 51.32 ppm 

3-hr avg; 1,596 

lb/event 4-hr 

startup; 399 

lb/event 1-hr 

shutdown

None

FL-0304

Florida 

Municipal 

Power 

Agency, Cane 

Island Power 

ParkOsceola, FL

09/08/2008

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine

300 MW 

(1,860 

MMBtu/hr)

6.00 ppmvd, 12-

month; 8.00 

ppmvd, 24-hr

None

FL-0305

Orlando 

Utilities 

Commission, 

OUC Curtis H.

Stanton 

Energy 

CenterOrlando, FL

05/12/2008

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine, with 

ultra-low sulfur 

diesel fuel as 

backup

300 MW 

(1,765 

MMBtu/hr)

8.0 ppmvd 

@15%, 24-hr; 

14 ppmvd 

@15% 24-hr 

during PA; 6 

ppmvd @15% 

12-month 

None

LA-0224

Southwest 

Electric Power 

Co. Arsenal 

Hill Power 

Plant- Caddo, 

LA

03/20/2008 Combined Cycle 

Gas Turbines

2,110 

MMBtu/hr

143.31 lb/hr; 

10.0 ppmvd @ 

15% O2 annual 

average

None

CT-0151

Kleen Energy 

Systems, Inc.-

Middlesex, CT

02/25/2008

Natural gas-fired 

combustion 

turbines

2.0 

mmcf/hr

0.9 ppmvd 

@15% O2, 1 hrblock and 4.3 

lb/hr (w/out DB); 

1.7 ppmvd @ 

15% O2 and 8.4 

l/hr w/DB

Oxidation 

catalyst

VA-0308

Virginia 

Electric & 

Power Co, 

Warren 

01/14/2008

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine (2 units 

1,717 

MMBtu/hr

12.8 lb/hr w/DB; 

7.2 lb/hr w/out 

DB; 1.30 ppmvd 

w/out power 

Oxidation 

catalyst
IPL Eagle Valley generating Station TSD – Appendix B Page 24 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

County 

FacilityWarren, VA

each with a 

HRSG and 500 

MMbtu/hr DB)

augmentation

MN-0071

Minnesota 

Municipal 

Power 

Agency, 

Fairbaul 

Tenergy ParkRice, MN

06/05/2007

Natural gas-fired 

and Distillate 

fuel-fired 

Combined Cycle 

Combustion 

Turbine, with 

ultra-low sulfur 

diesel fuel as 

backup

1758 

MMBtu/hr

No DB: 9.0 ppm 

3-hr avg (gas), 

20 ppm 3-hr avg 

(oil)

DB: 11 ppm 3-hr 

avg (gas or oil)

None

FL-0285

Progress 

Energy 

Florida, 

Progress 

Bartow Power 

PlantPinellas, FL

01/26/2007

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine

1,972 

MMBtu/hr

(1,280 

MW)

8.0 ppmvd 24-hr 

block avg None

NY-0095

Caithness 

Bellport 

Energy Center 

- Suffolk, NY 05/10/2006

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine

2221 

MMBtu/hr

2.0 ppmvd @ 

15% O2

Oxidation 

catalyst

The Virginia Electric & Power Company, in Warren County, Virginia, submitted a new application to revise 

the CO BACT limits, which have a broad range for the various modes of operation, with one limit has high 

as 2.5 ppm. It is difficult to compare the limits to IPL’s proposed BACT limits due to this broad range. 

The lowest limit found in the RBLC was for the Kleen Energy Systems facility, located in Middlesex, 

Connecticut, which has a slightly lower BACT limit at 1.7 ppmvd. The “outlier” is the Kleen Energy 

Systems permit issued in 2008 in Connecticut which has a limit of 0.9 ppm with duct burners and 1.7 ppm 

without duct burners. 

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 the BACT for the IPL 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. No other constructed facilities have established a BACT limit less than 2.0 ppmvd. The 

proposed limit of 2.0 ppmvd @ 15% O2 including duct firing is consistent with other demonstrated permit 

limits in the RBLC database. 

The following has been proposed as BACT for CO emissions from the proposed combined cycle 

combustion turbines, identified as EU-1 - EU-2:

(1) The CO emissions from the combined cycle combustion turbines shall be controlled by catalytic 

oxidation

(2) The CO emissions shall not exceed 2.0ppmv @15% O2, based on a 3-hr average.
IPL Eagle Valley generating Station TSD – Appendix B Page 25 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 combined cycle combustion turbines shall be controlled by 

catalytic oxidation

(2) The CO emissions shall not exceed 2.0 ppmvd @15% O2, based on a 3-hour

average. 

(3) Only pipeline natural gas only shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

Carbon Monoxide (CO) BACT during Startup and Shutdown – Combined Cycle Combustion 

Turbines EU-1 and EU-2

Startup and shutdown events may result in temporarily elevated emissions of CO inherent to the 

method of operation of the combustion turbines. Emissions of products of incomplete combustion 

are normally controlled via precise fuel: air ratio control in the dry low NOx combustor. 

Combustion turbines always default to diffusion flame and pilot mode (instead of lean pre-mix, 

DLN mode) when operating outside of their continuous operation design conditions, such as 

during a startup or shutdown. During the process of ramping and thermal “soaking” required 

during startup conditions, fuel:air ratios vary greatly before combustion temperatures are 

sufficient to burn out all of the fuel, resulting in short-term CO spikes. However, DLN mode 

operation is not available or technically feasible during these conditions, and higher CO 

concentrations (as well as potentially higher mass emissions) will result. During hot, warm and 

especially cold starts, the oxidation catalyst is also not at sufficient temperature to effectively 

complete oxidation of all products of incomplete combustion. For this combination of reasons, 

separate BACT limits are required to govern operations under these transient conditions, 

especially since these combustion turbines may be called upon for periodic cycling duty. 

Step 1: Identify Potential Control Technologies

The RBLC, vendor data and literature were reviewed and a summary of the listed BACT 

determinations for CO from F Class industrial power generation combustion turbines. All of the 

entries, with the exception of one which netted out of PSD review, have attempted to limit the 

number and duration of startup events, and in particular cold startup events, to minimize the mass 

emissions of CO per event and/or per annum. Since the combustion conditions of a combustion 

turbine are highly transient during these events, there is no meaningful limitation described in 

units of ppmvd @ 15% O2 because the event can be described as a series of spikes and 

plateaus. Since the most stringent CO emission levels during startup and shutdown are based on 

operating limitations, there is no applicable add-on control technology that has been 

demonstrated to be technically feasible for reduction of CO from industrial power generation 

turbines during startup and shutdown conditions. 

The following are list of alternative potential control technologies that have been proposed to limit 

emissions of CO during startup and shutdown:

(a) Limited number of startup and shutdown events per year (and especially cold starts)

(b) Limited duration of various start events (i.e. “rapid start technology”)

(c) Minimum firing of a single combustion turbine to maintain HRSG/STG temperatures as 

ready for warm or hot starts when practicable
IPL Eagle Valley generating Station TSD – Appendix B Page 26 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

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(d) Use of auxiliary boiler firing to reduce HRSG/STG “cold iron” conditions to minimize cold 

and/or warm starts 

Step 2: Eliminate Technically Infeasible Options

Operational limitation on number of startup events per year

The emission units being permitted are specifically defined as being capable of daily and 

weekend cycling in response to market conditions for power, and in order to serve this dispatch 

flexibility require the ability for daily hot starts, weekly warm starts and several cold starts each 

year. While the source does propose to limit the per-event and annual emissions of CO resulting 

from start events from the subject project, they could not be further limited without redefining the 

fundamental purpose of the project. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of operational limitation on number of startup events per year is not a technically feasible 

option for the combined cycle combustion turbines (EU-1 and EU-2) at this source

Limited duration of startup events

The duration of startup events is pre-defined by the combustion turbine vendors, is preprogrammed into the automated control systems, cannot be altered by the operator, and if 

attempted would void the warranties (and potentially damage the equipment).. While some 

vendors tout “rapid start technology”, especially on simple cycle engines, such technology can

only be supplied within the design constraints of the case-specific combustion turbine and steam 

side design of the combined cycle system. Further limiting the duration of hot, warm and cold 

startup events does not represent a technically feasible CO reduction strategy during startup and 

shutdown of the proposed combined cycle combustion turbines. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of limited duration of startup events is not a technically feasible option for the combined 

cycle combustion turbines (EU-1 and EU-2) at this source

Minimum firing of a single combustion turbine to minimize steam-side starts

This operating technique can and will be used as one option to minimize annual startup 

emissions (as well as to potentially minimize wear and tear on the equipment) when frequent 

cycling is required, and when market conditions support continuing to operate one machine at low 

load to enable rapid return to full firing when next called upon. This is a technique that favors the 

system’s maintenance schedule and, when economically advantageous represents a preferred 

operating strategy. However, such operation is not a technically feasible requirement or 

operating limitation for CO control during startups and shutdowns because market conditions may 

not support such operation within the definition and purpose of the project – to provide clean, 

reliable and low cost power to IPL’s customers. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Minimum firing of a single combustion turbine to minimize steam-side starts is not a 

technically feasible option for the combined cycle combustion turbines (EU-1 and EU-2) at this 

source

Use of auxiliary boiler steam to minimize steam-side starts

This operating technique can and will be used as another option to minimize annual startup 

emissions (as well as to potentially minimize wear and tear on the equipment when frequent 

cycling is required, and when market conditions support auxiliary boiler firing to provide steam to 

the turbine seals, to minimize steam side thermal stress and to enable rapid return to full firing 

when next called upon. This is a technique that favors the system’s maintenance schedule and, 

when economically advantageous may represent a preferred operating strategy. However, such 
IPL Eagle Valley generating Station TSD – Appendix B Page 27 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

operation is not a technically feasible requirement or operating limitation to reduce emissions of 

CO during startups and shutdowns because market conditions may not support such operation 

within the definition and purpose of the project – to provide clean, reliable and low cost power to 

IPL’s customers

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of auxiliary boiler steam to minimize steam-side starts is not a technically feasible option 

for the combined cycle combustion turbines (EU-1 and EU-2) at this source

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The only controls determined to be technically feasible and demonstrated in practice for the 

proposed combustion turbines during startup and shutdowns are various combined cycle 

management techniques that may be implemented on a case-by-case basis to minimize perevent and rolling annual emissions by managing the number, type and duration of startup events. 

Step 4: Evaluate the Most Effective Controls and Document the Results

BACT limits listed for other projects in the RBLC are highly project specific as they are influenced 

by the particular engine model, combined cycle steam side heat up limitations and the operational 

specifications of the facility itself based on local projected market conditions. The source 

proposes to employ operations management techniques, to the extent practicable, to limit per 

event and rolling 12-month emissions of CO during startups and shutdowns. These operational 

procedures are technically feasible only to the extent that they do not re-define the source being 

permitted. No other control alternatives have been identified as demonstrated in practice for a 

similar facility capable of any further reductions in CO under transient startup and shutdown 

conditions. Vendor data was used to define the levels of mass emissions per event that 

represent the top level of control during startup and shutdown of the proposed combustion 

turbines. Rolling 12-month emissions were determined based on assumptions regarding 

maximum annual cold, warm and hot starts to enable the facility to meet a range of projected 

market conditions in the IPL system. 

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:

The combined CO emissions from the combined cycle combustion turbines stacks during startup 

and shutdown events shall not exceed 3390 pounds per event and 565 tons per twelve (12) 

consecutive month period.

Volatile Organic Compounds (VOCs) BACT – Combined Cycle Combustion Turbines EU-1 - EU-2

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) SCONOx Catalytic Absorption System; 

(d) Catalytic oxidation; 
IPL Eagle Valley generating Station TSD – Appendix B Page 28 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

(e) Good Combustion Controls; and

(f) Flares.

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. Oxidizers are not recommended for controlling gases with sulfur containing 

compounds because of the formation of highly corrosive acid gases.

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. 

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.
IPL Eagle Valley generating Station TSD – Appendix B Page 29 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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. This 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. 

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 
IPL Eagle Valley generating Station TSD – Appendix B Page 30 of 152

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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 IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Combined Cycle 

Combustion 

Turbines (EU-1 

& EU-2)

2,542 

MMBtu/hr, 

each

2.0 ppmvd 

@15% O2, with 

duct burners 

based on 3-hr 

average

Oxidation 

Catalyst

1.0 ppmvd 

@15% O2, 

without duct 

burners based 

on 3-hr average

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center 

- proposed

12/03/2012 Combined Cycle 

Combustion 

Turbines (CCCT1 

-CCCT4) 

2,300 

MMBtu/hr 

2.0 ppmvd 

@15% O2, with 

duct burners 

based on 3-hr 

average Oxidation 

1.0 ppmvd Catalyst

@15% O2, 

without duct 

burners based on 

3-hr average

GA-0138

Live Oaks 

Company, LLC, 

Live Oaks 

Power PlantGlynn, GA

04/08/2010

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine

600 MW 2.0 ppm @ 15% 

O2, 3-hr average

Catalytic 

oxidation, 

good 

combustion 

practices

LA-0224 Southwest 

Electric Power 03/20/2008 Combined Cycle Gas Turbines

2,110 

MMBtu/hr

12.06lb/hr; 4.9 

ppmvd @ 15% None
IPL Eagle Valley generating Station TSD – Appendix B Page 31 of 152

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BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

Co. Arsenal Hill 

Power PlantCaddo, LA

O2annual 

average

VA-0308

Virginia Electric 

& Power Co, 

Warren County 

FacilityWarren, VA

01/14/2008

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine (2 units 

each with a 

HRSG and 500 

MMbtu/hr DB)

1,944 

MMBtu/hr

1.0 ppmvd w/out 

DB; 0.7 ppmvd 

w/DB

Oxidation 

catalyst

GA-0127

Southern 

Company / 

Georgia Power, 

Plant 

McDounough 

Combined 

Cycle- Cobb, 

GA

01/07/2008

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine with 

diesel fuel as 

backup

254 MW

Gas: 1.80 ppm @ 

15% O2 3-hour 

w/duct burner; 

1.0 ppm @ 15% 

O2 w/out duct 

burner (LAER) 

Oil: 4.0 ppm 

@15% O2, 3-

hour (LAER)

Oxidation 

catalyst

MN-0071

Minnesota 

Municipal 

Power Agency, 

Fairbaul 

Tenergy ParkRice, MN

06/05/2007

Natural gas-fired 

and Distillate 

fuel-fired 

Combined Cycle 

Combustion 

Turbine, with 

ultra-low sulfur 

diesel fuel as 

backup

1758 

MMBtu/hr

1.5 ppmvd (CTG 

NG or CTG & DB 

NG); 3.0 ppmvd 

(CTG NG & DB 

oil); 3.5 ppmvd 

(CTG oil & DB 

Not operate or 

NG or oil)

None

FL-0285

Progress 

Energy Florida, 

Progress 

Bartow Power 

Plant- Pinellas, 

FL

01/26/2007

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine with Duct 

Burner

1,972 

MMBtu/hr

(1,280 MW)

1.2 ppmvd @ 

15% O2 (CT 

only);

1.5 ppmvd @ 

15% O2 (CT and 

DB)

None

AZ-0047

Dome Valley 

Energy 

Partners, 

Wellton 

Mohawk 

Generating 

Station- Yuma, 

AZ

12/01/2004

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine and 

HRSG

170 MW

3.0 ppm @ 15% 

O2, 3-hr avg; 8.4 

lb/hr 3-hr avg

Oxidation 

catalyst

WI-0227

WE Energies 

(Port 

Washington 

Generating 

Station)-

Washington, 

WI

10/13/2004

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine (4 units 

with duct burner, 

HRSG)

2,096 

MMBtu/hr

1.2 ppmdv 

@15% O2

calendar day avg 

w/DB; 0.8 

ppmdv@ 15% O2

calendar day avg 

w/out DB

Oxidation 

catalyst

NV-0037

Sempra Energy 

Resources, 

Copper 

Mountain 

05/14/2004

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine

600 MW

4.0 ppmvd 

@15% O2, 3-hr 

avg w/DB; 1.9 

ppmvd @ 15@ 

Oxidation 

catalyst
IPL Eagle Valley generating Station TSD – Appendix B Page 32 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

Power- Clark,

NV

O23-hr avg w/out 

DB (LAER)

There are three other sources which have been identified as having lower limits: the Chouteau 

facility in Oklahoma which has a limit of 0.3 ppm; a Virginia Electric Power facility permitted in 

2009 with limits of 1 ppm with duct burning and 0.7 ppm without duct burning; and the Progress 

Energy facility permitted in 2007 in Florida with limits of 1.5 ppm with duct burning and 1.2 ppm 

without duct burning. 

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 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. In addition, it does not appear that the Chouteau 

facility is permitted with an oxidation catalyst and has a CO limit of 8 ppm, and as such the VOC 

limit represented for this facility is inconsistent for this facility.

Carbon Monoxide (CO) is a product of incomplete combustion, whereby trace quantities of 

carbon molecules in the hydrocarbon fuel fail to become oxidized completely to CO2, and are 

emitted as the fairly unstable molecule CO. CO emissions from low level sources such as 

automobiles in confined spaces (such as urban city canyons) pose a threat to air quality. VOC is 

defined as non-methane, non-ethane hydrocarbons (NMHC) which are also emitted from 

combustion turbines as products of incomplete combustion, in this case when molecules of both 

hydrogen and carbon pass though the combustion system without being fully oxidized 

(combusted). 

The information provided in the RBLC for the Progress Energy facility in Florida does not indicate 

that an oxidation catalyst or other control method will be used and the CO limit in that permit is 8 

ppm (24-hour average). As such, the VOC limit identified in the RBLC is inconsistent for this 

facility. 

IDEM cannot directly compare the proposed IPL limits with the limits cited above for the Port 

Washington Generating station since the averaging periods for the different limits differ 

significantly. The Port Washington facility has a slightly lower numeric value but compliance is 

determined over a daily average rather than over a 3-hour period. A 3-hour period as proposed 

by IPL is a more stringent averaging period than daily. Based on the different averaging periods 

IDEM do not believe the limits for the Port Washington facility are in fact more stringent than the 

limit proposed by IPL. IDEM also believe that the 3-hour averaging period is a more appropriate 

averaging period for VOC emissions as it is consistent with the standard three one-hour source 

tests compliance basis. 

Therefore, the proposed limits of 1.0 ppmvd @15% O2, without duct burners, and of 2.0 ppmvd 

@15% O2, with duct burners, based on a 3-hr average are consistent with all other limits in the 

RBLC for this type of operation.

The following has been proposed as BACT for VOC emissions from the proposed combined cycle 

combustion turbines, identified as EU-1 - EU-2:

(1) The VOC emissions from the CCCT shall be controlled by catalytic oxidation.
IPL Eagle Valley generating Station TSD – Appendix B Page 33 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

(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.

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 combined cycle combustion turbines:

(1) The VOC emissions from the CCCTs shall be controlled by 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) Only pipeline natural gas only shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

Volatile Organic Compounds (VOC) BACT during Startup and Shutdown – Combined Cycle 

Combustion Turbines EU-1 and EU-2

Startup and shutdown events may result in temporarily elevated emissions of VOC inherent to the 

method of operation of the combustion turbines. Emissions of products of incomplete combustion 

are normally controlled via precise fuel: air ratio control in the dry low NOx combustor. 

Combustion turbines always default to diffusion flame and pilot mode (instead of lean pre-mix, 

DLN mode) when operating outside of their continuous operation design conditions, such as

during a startup or shutdown. During the process of ramping and thermal “soaking” required 

during startup conditions, fuel:air ratios vary greatly before combustion temperatures are 

sufficient to burn out all of the fuel, resulting in short-term CO spikes. However, DLN mode 

operation is not available or technically feasible during these conditions, and higher VOC

concentrations (as well as potentially higher mass emissions) will result. During hot, warm and 

especially cold starts, the oxidation catalyst is also not at sufficient temperature to effectively 

complete oxidation of all products of incomplete combustion. For this combination of reasons, 

separate BACT limits are required to govern operations under these transient conditions,

especially since these combustion turbines may be called upon for periodic cycling duty. 

Step 1: Identify Potential Control Technologies

The RBLC, vendor data and literature were reviewed and a summary of the listed BACT 

determinations for VOC from F Class industrial power generation combustion turbines. All of the 

entries, with the exception of one which netted out of PSD review, have attempted to limit the 

number and duration of startup events, and in particular cold startup events, to minimize the mass 

emissions of VOC per event and/or per annum. Since the combustion conditions of a combustion 

turbine are highly transient during these events, there is no meaningful limitation described in 

units of ppmvd @ 15% O2 because the event can be described as a series of spikes and 

plateaus. Since the most stringent VOC emission levels during startup and shutdown are based 

on operating limitations, there is no applicable add-on control technology that has been 

demonstrated to be technically feasible for reduction of VOC from industrial power generation 

turbines during startup and shutdown conditions. 
IPL Eagle Valley generating Station TSD – Appendix B Page 34 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

The following are list of alternative potential control technologies that have been proposed to limit 

emissions of VOC during startup and shutdown:

(a) Limited number of startup and shutdown events per year (and especially cold starts)

(b) Limited duration of various start events (i.e. “rapid start technology”)

(c) Minimum firing of a single combustion turbine to maintain HRSG/STG temperatures as 

ready for warm or hot starts when practicable

(d) Use of auxiliary boiler firing to reduce HRSG/STG “cold iron” conditions to minimize cold 

and/or warm starts 

Step 2: Eliminate Technically Infeasible Options

Operational limitation on number of startup events per year

The emission units being permitted are specifically defined as being capable of daily and 

weekend cycling in response to market conditions for power, and in order to serve this dispatch 

flexibility require the ability for daily hot starts, weekly warm starts and several cold starts each 

year. While the source does propose to limit the per-event and annual emissions of VOC

resulting from start events from the subject project, they could not be further limited without 

redefining the fundamental purpose of the project. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of operational limitation on number of startup events per year is not a technically feasible 

option for the combined cycle combustion turbines (EU-1 and EU-2) at this source

Limited duration of startup events

The duration of startup events is pre-defined by the combustion turbine vendors, is preprogrammed into the automated control systems, cannot be altered by the operator, and if 

attempted would void the warranties (and potentially damage the equipment).. While some 

vendors tout “rapid start technology”, especially on simple cycle engines, such technology can 

only be supplied within the design constraints of the case-specific combustion turbine and steam 

side design of the combined cycle system. Further limiting the duration of hot, warm and cold 

startup events does not represent a technically feasible VOC reduction strategy during startup 

and shutdown of the proposed combined cycle combustion turbines. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of limited duration of startup events is not a technically feasible option for the combined 

cycle combustion turbines (EU-1 and EU-2) at this source

Minimum firing of a single combustion turbine to minimize steam-side starts

This operating technique can and will be used as one option to minimize annual startup 

emissions (as well as to potentially minimize wear and tear on the equipment) when frequent 

cycling is required, and when market conditions support continuing to operate one machine at low 

load to enable rapid return to full firing when next called upon. This is a technique that favors the 

system’s maintenance schedule and, when economically advantageous represents a preferred 

operating strategy. However, such operation is not a technically feasible requirement or 

operating limitation for VOC control during startups and shutdowns because market conditions 

may not support such operation within the definition and purpose of the project – to provide clean, 

reliable and low cost power to IPL’s customers. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Minimum firing of a single combustion turbine to minimize steam-side starts is not a 
IPL Eagle Valley generating Station TSD – Appendix B Page 35 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

technically feasible option for the combined cycle combustion turbines (EU-1 and EU-2) at this 

source

Use of auxiliary boiler steam to minimize steam-side starts

This operating technique can and will be used as another option to minimize annual startup 

emissions (as well as to potentially minimize wear and tear on the equipment when frequent 

cycling is required, and when market conditions support auxiliary boiler firing to provide steam to 

the turbine seals, to minimize steam side thermal stress and to enable rapid return to full firing 

when next called upon. This is a technique that favors the system’s maintenance schedule and, 

when economically advantageous may represent a preferred operating strategy. However, such 

operation is not a technically feasible requirement or operating limitation to reduce emissions of 

VOC during startups and shutdowns because market conditions may not support such operation 

within the definition and purpose of the project – to provide clean, reliable and low cost power to 

IPL’s customers

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Use of auxiliary boiler steam to minimize steam-side starts is not a technically feasible 

option for the combined cycle combustion turbines (EU-1 and EU-2) at this source

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The only controls determined to be technically feasible and demonstrated in practice for the 

proposed combustion turbines during startup and shutdowns are various combined cycle 

management techniques that may be implemented on a case-by-case basis to minimize perevent and rolling annual emissions by managing the number, type and duration of startup events. 

Step 4: Evaluate the Most Effective Controls and Document the Results

BACT limits listed for other projects in the RBLC are highly project specific as they are influenced 

by the particular engine model, combined cycle steam side heat up limitations and the operational 

specifications of the facility itself based on local projected market conditions. The source 

proposes to employ operations management techniques, to the extent practicable, to limit per 

event and rolling 12-month emissions of VOC during startups and shutdowns. These operational 

procedures are technically feasible only to the extent that they do not re-define the source being 

permitted. No other control alternatives have been identified as demonstrated in practice for a 

similar facility capable of any further reductions in VOC under transient startup and shutdown 

conditions. Vendor data was used to define the levels of mass emissions per event that 

represent the top level of control during startup and shutdown of the proposed combustion 

turbines. Rolling 12-month emissions were determined based on assumptions regarding 

maximum annual cold, warm and hot starts to enable the facility to meet a range of projected 

market conditions in the IPL system. 

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 combined cycle combustion turbines:

The combined VOC emissions from the combined cycle combustion turbines stacks, during 

startup and shutdown events, shall not exceed 146 tons per twelve (12) consecutive month 

period with compliance determined at the end of each month.
IPL Eagle Valley generating Station TSD – Appendix B Page 36 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

Nitrogen Oxide (NOx) BACT– Combined Cycle Combustion Turbines EU-1 - EU-2

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) Low NOx Combustors;

(d) Flue gas Recirculation;

(e) Catalytic Combustors;

(f) SCONOx;

(g) Natural gas Firing; and

(h) Water Injection.

Step 2: Eliminate Technically Infeasible Options

Selective Catalytic Reduction (SCR)

Selective Catalytic Reduction (SCR) is a well proven technology for reducing NOx emissions from 

CCCTs. The SCR technology mixes exhaust gases with ammonia (which may be received and 

stored as anhydrous ammonia, aqueous ammonia or liquid urea) which then pass through a 

catalyst reactor to reduce NOx to N2 and water. 

The most important factor affecting SCR efficiency is catalyst operating temperature. SCR can 

operate in a flue gas window ranging from 500°F to 1100°F, although best NOx reduction 

performance occurs at the higher end of this range. Temperatures below the optimum decrease 

catalyst activity and allow both NOx and NH3 to pass through unreacted; above the optimum 

range, ammonia will oxidize to form additional NOx. SCR NOx reduction efficiency is also largely 

dependent on gaseous mixing and residence time of injected ammonia as well as the 

stoichiometric molar ratio of NH3: NOx. For example, variation of the theoretical 1:1 molar ratio of 

NH3: NOx to 0.5:1 ratio would theoretically reduce the removal efficiency to 50%. However, even 

at the theoretical molar ratio, 100% reduction cannot be achieved. The HRSG is a fixed 

geometry device with uneven temperature, flow rate, NOx concentration and NH3 concentration, 

especially considering variations in operating load, ramping and duct firing, with very little 

available mixing and reaction time between the ammonia injection grid and catalyst bed. Due to 

these practical limitations, it is necessary to over-inject ammonia to drive NOx to very low levels, 

meaning that surplus ammonia will be emitted from the stack as ammonia “slip.” Recent permits 

for large combined cycle, natural gas-fired combustion turbines limit NOx emissions to around 2 

ppmvd @ 15% O2 including duct firing, with ammonia slip limits as high as 10 ppm. Such control 

systems have been operated successfully in a number of similar applications for many years and 

are considered to be reliable and well proven state-of-the-art NOx control technology. SCR 

technology in combination with dry low NOx combustors is also the “top” level of control listed in 

the RBLC. 

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.
IPL Eagle Valley generating Station TSD – Appendix B Page 37 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

Selective Non-Catalytic Reduction (SNCR)

Selective Non-Catalytic Reduction (SNCR) is not applicable for control of NOx from combustion 

turbines. The SNCR technology removes NOx through ammonia or urea injection into boiler flue 

gas within a temperature range of 1600°F to 2000°F and without the use of a catalyst. SNCR has 

never been applied to a combustion turbine because combustion turbines lack the physical time, 

turbulence and temperature window for the technology to work. SNCR does not represent a 

technically feasible alternative for NOx control from the proposed combustion turbines. 

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 combined 

cycle combustion turbines at this source.

Dry Low NOx (DLN) Combustors

Low NOx Burner (LNB) technology (in combustion turbines referred to as dry low NOx

combustor/lean pre-mix combustor technology) reduces the formation of NOx through control of 

the fuel-air mixture to limit peak flame temperature and oxygen availability in the peak 

temperature zone of the flame. This technology is capable of reducing NOx emissions to the 

range of 9-25 ppmvd in combustion turbines, and is employed nearly universally on new, natural 

gas-fired power generation turbines in the U.S. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

dry low NOx (DLN) combustor is a technically feasible option for the combined cycle combustion 

turbines at this source.

Flue Gas Recirculation (FGR)

FGR reduces NOx emissions by recirculating a portion of the exhaust gas back into the 

combustion flame. This results in lower combustion temperatures and oxygen levels in the 

combustion air/flue gas mixture, thus retarding the formation of thermal NOx. Internal flue gas 

recirculation (within the combustors) is employed in the design of all combustion turbine DLN 

technology, and therefore does not represent a separate technology for consideration as a 

candidate for BACT for these units. In any event internal FGR is inherently incorporated into the 

design of all modern DLN combustors. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

flue gas recirculation (FGR) is a technically feasible option for the combined cycle combustion 

turbines at this source.

Catalytic Combustors

Catalytic combustors burn the fuel at low temperature across a catalyst, hence suppressing the 

formation of NOx. The only known applications are on very small (1.5 MW scale) Kawasaki 

combustion turbines. Catalytic combustors cannot achieve the same levels of control 

demonstrated by SCR, and would provide no control of duct burner emissions. This technology is 

not commercially available, and has never been demonstrated in practice on any F Class 

Industrial combustion turbine. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the catalytic combustor is not a technically feasible option for the combined cycle combustion 

turbines at this source.

SCONOx

SCONOx is a potassium based NOx absorption and regeneration technology that has been 

installed commercially on a few < 10 MW combined heat and power combustion turbines. It has 

never been applied or demonstrated in practice on F Class combustion turbines. While SCONOx

technology enjoyed brief interest in the 1990s, it has failed to become a viable commercial 

product. Finally, even if it were deemed transferrable technology, it is not capable of the level of 
IPL Eagle Valley generating Station TSD – Appendix B Page 38 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

NOx control that has been demonstrated by SCR. Due to its lack of application, availability or 

demonstration on F Class industrial power generation combustion turbines, SCONOx technology 

does not represent technically feasible candidate for NOx control from the proposed combustion 

turbines. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

SCONOx is not a technically feasible option for the combined cycle combustion turbines at this 

source.

Natural Gas Firing

Natural gas does not contain fuel bound nitrogen, and therefore gas-only fired combustion 

turbines are capable of lower (down to single digits) NOx emissions with dry low NOx combustors 

than those fired with liquid fuels. The lowest NOx emissions listed in the RBLC are all for 

combustion turbines firing natural gas. The proposed project will fire exclusively natural gas and 

will incorporate this control technique into its best available control strategy. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the natural gas firing is a technically feasible option for the combined cycle combustion turbines at 

this source.

Water Injection

Water injection is a control technique designed to lower peak flame temperature, and therefore 

NOx formation, within the turbine combustors. This technology is generally employed on liquid 

fuel-fired units for which dry low NOx combustors are unavailable, but is not capable of equivalent 

NOx reduction performance to dry low NOx technology on gas-fired units. 

Based on the information reviewed for this BACT and LAER determination, IDEM, OAQ has 

determined that the water injection 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 — (Up to 90% NOx Reduction)

(2) Dry Low NOx Combustors — (Up to 60% NOx Reduction)

(3) Flue Gas Recirculation;

(4) Natural gas firing — (Up to 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 IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Combined Cycle 

Combustion 

Turbines (EU-1 & 

EU-2)

2,542 

MMBtu/hr, 

each

NOx: 2.0 ppmvd 

@15% O2, with 

duct burners

based on 3-hr 

average

SCR and dry 

low NOx 

combustors
IPL Eagle Valley generating Station TSD – Appendix B Page 39 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center 

- proposed

12/03/2012 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

GA-0138

Live Oaks 

Company, 

LLC, Live 

Oaks Power 

Plant

04/08/2010

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine

600 MW

2.5 ppm @ 15% 

O2, 3-hr average; 

87 tpy

Dry Low-NOx

burners, SCR

OK-0129

Associated 

Electric 

Cooperative, 

Inc. Chouteau 

Power Plant

01/23/2009 Combined Cycle 

Cogeneration 

> 25MW 

(1,882 

MMBtu/hr)

2.0 ppm 1-hr avg 

@ 15% O2; 15.25 

lb/hr 1-hr avg; 

568 lb/event 4-hr 

startup; 142 

lb/event 1-hr 

shutdown

Dry LowNOx burners, 

SCR

FL-0304

Florida 

Municipal 

Power 

Agency, Cane 

Island Power 

Park

09/08/2008

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine

300 MW 

(1,860 

MMBtu/hr)

2.0 ppmvd 24-hr SCR

FL-0305

Orlando 

Utilities 

Commission, 

OUC Curtis H. 

Stanton 

Energy Center

05/12/2008

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine, with ultralow sulfur diesel 

fuel as backup

300 MW 

(1,765 

MMBtu/hr)

8.0 ppmvd @ 

15% O2, 24-hr 

average (oil); 2.0 

ppmvd @ 15% 

O2, 24-hr 

average (gas)

Low- NOx

burners and 

SCR water 

injection

LA-0224

Southwest 

Electric Power 

Co. Arsenal 

Hill Power 

Plant

03/20/2008 Combined Cycle 

Gas Turbines

2,110 

MMBtu/hr

30.15 lb/hr; 4.0 

ppmvd @ 15% 

O2 annual 

average

Low- NOx

burners, duct 

burners 

combined 

with SCR 

CT-0151 Kleen Energy 

Systems, Inc. 02/25/2008

Natural gas-fired 

combustion 

turbines

2.0 

mmcf/hr

2.0 ppmvd @ 

15% O2, 1-hr 

block (LAER)

Low- NOx

burners, SCR

VA-0308

Virginia 

Electric & 

Power Co, 

Warren 

County Facility

01/14/2008

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine (2 units 

each with a HRSG 

and 500 MMbtu/hr 

DB)

1,944 

MMBtu/hr

2.0 ppm, 17.9 

lb/hr

2-stage 

premix NOx

combustion, 

SCR

FL-0285

Progress 

Energy 

Florida, 

Progress 

Bartow Power 

Plant

01/26/2007

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine

1,972 

MMBtu/hr

(1,280 

MW)

15 ppmvd 30-day 

basis (gas); 42 

ppmvd 30-day 

basis (oil);

Water 

injection, if 

needed 

(project 

netted out of 

PSD review)

FL-0280

Florida 

Municipal 

Power 

05/30/2006

Combined Cycle 

Combustion 

Turbine

170 MW

2.0 ppmvd 24-

hour block (gas); 

8.0 ppmvd 24-

SCR
IPL Eagle Valley generating Station TSD – Appendix B Page 40 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

Agency, 

Treasure 

Coast Energy 

Center

hour block (oil)

NY-0095

Caithness 

Bellport 

Energy Center 

05/10/2006

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine

2221 

MMBtu/hr

2.0 ppmvd @ 

15% O2

SCR

Fuel oil-fired 

Combined Cycle 

Combustion 

Turbine

2125 

MMbtu/hr

6.0 ppmvd @ 

15% O2w/out DB; 

6.8 ppmvd @ 

15% O2w/DB

SCR

WI-0227

WE Energies 

(Port 

Washington 

Generating 

Station)

10/13/2004

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine (4 units 

with duct burner, 

HRSG)

2,096 

MMBtu/hr

3.0 ppm @ 15% 

O2, 30-day rolling 

avg, each

Dry LowNOx burners, 

SCR

NV-0037

Sempra 

Energy 

Resources, 

Copper 

Mountain 

Power

05/14/2004

Natural gas-fired 

Combined Cycle 

Combustion 

Turbine

600 MW

2.0 ppmvd @ 

15% O2 3-hr avg; 

17.92 lb/hr

Dry LowNOx

combustor, 

steam 

injection, and 

SCR

AZ-0049

Allegheny 

Energy 

Supply, LLC 

La Paz 

Generating 

Facility

09/04/2003

Combined Cycle 

Combustion 

Turbines and 

HRSGs

1080 MW

2.0 ppmvd @ 

15% O 3-hr avg; 

16.0 lb/hr

Low- NOx

burners and 

SCR

CA-0997

Sacramento 

Municipal 

Utility District

09/01/2003 Natural gas-fired 

Turbines

1,611 

MMBtu/hr

2.0 ppmvd @ 

15% O2 (LAER) SCR

PA-0226

Limerick 

Partners, LLC 

Power Station

04/09/2002

Natural gas-fired 

Combined Cycle 

Turbine

550 MW 2.0 ppmvd @ 

15% O2 (LAER)

Low- NOx

burners

PA-0188 Fairless 

Energy LLC 03/28/2002

Natural gas-fired 

Combined Cycle 

Turbine

1,190 MW 2.5 ppmvd @ 

15% O2 (LAER)

Dry LowNOx burners, 

SCR

PA-0223 Duke Energy 

Fayette, LLC 01/30/2002

Natural gas-fired 

Combined Cycle 

Turbine

280 MW 2.5 ppmvd @ 

15% O2 (LAER)

Low- NOx

burners, SCR

This top level of control reflects the sequential combination of exclusive natural gas firing, dry low 

NOx combustors and SCR, and this combination of control technology reflects the maximum or 

“top” level of control that has been demonstrated in practice in similar applications. The lowest 

limitation identified that has been achieved in practice for similar duct fired combustion turbines is 

an emission rate of 2 ppmvd NOx @ 15% O2 from the combustion turbines during normal (nonstartup, shutdown or malfunction) operation, to be continuously monitored using Part 60 and 75 

certified continuous emissions monitoring systems (CEMS). This control technology and 

emission limitation also constitutes BACT for NOx for normal operation of the CCCTs. 
IPL Eagle Valley generating Station TSD – Appendix B Page 41 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

The following has been proposed as BACT for NOx emissions from the proposed combined cycle 

combustion turbines, identified as EU-1 - EU-2:

(1) The NOx emissions from the CCCT shall be controlled by Selective Catalytic Reduction 

and Dry Low NOx combustors.

(2) The NOx emissions shall not exceed 2.0ppmv @15% O2 with duct burners based on a 3-

hr average.

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 Selective Catalytic 

Reduction and Dry Low NOx combustors.

(2) The NOx emissions shall not exceed 2.0ppmv @15% O2 with duct burners based 

on a 3-hr average.

(3) Only pipeline natural gas only shall be fired in the combined cycle combustion turbines

identified as EU-1 and EU-2.

Nitrogen Oxide (NOx) BACT during Startup and Shutdown – Combined Cycle Combustion 

Turbines EU-1 and EU-2

Startup and shutdown events may result in temporarily elevated emissions of NOx inherent to the 

diffusion flame startup mode of the combustion turbines. Combustion turbines always default to 

diffusion flame and pilot mode (instead of lean pre-mix, DLN mode) when operating outside of 

their continuous operating regime, such as during a startup or shutdown. Thus, DLN technology 

is not technically feasible during these operating conditions, and higher NOx concentrations 

(although not necessarily higher mass emissions) will result. During hot, warm and especially 

cold starts, the SCR catalyst is not at sufficient temperature to initiate ammonia injection for the 

NOx control reaction to proceed. For this combination of reasons, separate BACT limits are 

proposed for these transient conditions, since the proposed combustion turbines may be called 

upon for periodic cycling duty. 

Step 1: Identify Potential Control Technologies

The RBLC, vendor data and the literature were reviewed and a summary of the listed BACT 

determinations for F Class industrial power generation combustion turbines. All of the entries, 

with the exception of one which netted out of PSD review, have attempted to limit the number and 

duration of startup events, and in particular cold startup events, to minimize the mass emissions 

of NOx per event and/or per annum. Since the combustion conditions of a combustion turbine 

are transient during these events, there is no meaningful limitation described in units of ppmvd @ 

15% O2 because the event can be described as a series of spikes and plateaus. According to 

the data reviewed there is no applicable add-on control technology that has been demonstrated 

to be technically feasible for reduction of NOx from industrial power generation turbines during 

startup and shutdown conditions. 

The following is a list of alternative potential control technologies that have been proposed to limit 

emissions of NOx during startup and shutdown:

(a) Limited number of startup and shutdown events per year (and especially cold starts);
IPL Eagle Valley generating Station TSD – Appendix B Page 42 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

(b) Limited duration of various start events (i.e. “rapid start technology”);

(c) Minimum firing of a single combustion turbine to maintain HRSG/STG temperatures as 

ready for warm or hot starts;

(d) Use of auxiliary boiler firing to reduce HRSG/STG “cold iron” conditions to minimize cold 

and/or warm starts.

Step 2: Eliminate Technically Infeasible Options

Operational limitation on number of startup events per year

The emission units being permitted are specifically defined as being capable of daily and 

weekend cycling in response to market conditions for power, and in order to serve this dispatch 

flexibility require the ability for daily hot starts, weekly warm starts and several cold starts each 

year. While IPL does propose to limit the annual start events from the subject project, the events 

could not be further limited without redefining the purpose of the project. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of operational limitation on number of startup events per year is not a technically feasible 

option for the combined cycle combustion turbines (EU-1 and EU-2) at this source

Limited duration of startup events

The duration of startup events is pre-defined by the combustion turbine vendors, is preprogrammed into the automated control systems, cannot be altered by the operators and to do so 

would void the warranties (and potentially damage the equipment). While some vendors tout 

“rapid start technology”, especially on simple cycle engines, such technology can only be 

supplied within the design constraints of the combustion turbine and steam system equipment 

(HRSG, steam turbine generator, pumps and piping, etc.) being purchased. The design of the 

complete combined cycle plant, and especially the steam side, is a case specific feature of each 

project being permitted. Further limiting the duration of hot, warm and cold startup events does 

not represent a technically feasible NOx reduction strategy for minimizing the duration of, and 

resulting emissions from startup and shutdown of the proposed combustion turbines. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of limited duration of startup events is not a technically feasible option for the combined 

cycle combustion turbines (EU-1 and EU-2) at this source

Minimum firing of a single combustion turbine to minimize steam-side starts

This operating technique can and will be used to minimize wear and tear on the equipment when 

frequent cycling is required, and when market conditions support continuing to operate one 

machine at low load to enable rapid return to full firing the next day, etc. This is a technique that 

favors the system’s maintenance schedule and, when economically advantageous represents the 

preferred operating strategy. However, such operation is not a technically feasible requirement or 

operating limitation for NOx control during startups and shutdowns because market conditions 

may not support such operation within the definition and purpose of the project – to provide clean, 

reliable and low cost power to our customers. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Minimum firing of a single combustion turbine to minimize steam-side starts is not a 

technically feasible option for the combined cycle combustion turbines (EU-1 and EU-2) at this 

source

Use of auxiliary boiler steam to minimize steam-side starts

This operating technique can and will be used to minimize wear and tear on the equipment when 

frequent cycling is required, and when market conditions support auxiliary boiler firing to provide 

steam to the turbine seals and minimize thermal stress to enable rapid return to full firing the next 
IPL Eagle Valley generating Station TSD – Appendix B Page 43 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

day, etc. This is a technique that favors the system’s maintenance schedule and, when 

economically advantageous may represent a preferred operating strategy. However, such 

operation is not a technically feasible requirement or operating limitation to reduce emissions of 

NOx during startups and shutdowns because market conditions may not support such operation 

within the definition and purpose of the project – to provide clean, reliable and low cost power to 

our customers

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Use of auxiliary boiler steam to minimize steam-side starts is not a technically feasible 

option for the combined cycle combustion turbines (EU-1 and EU-2) at this source

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The only controls determined to be technically feasible and demonstrated in practice for the 

proposed combustion turbines to limit emissions of NOx during startup and shutdowns include 

operational techniques to minimize NOx emissions in terms of lb/event and total annual tons of 

NOx per year (rolling 12-months) achieved by managing, to the extent possible, the number, type 

and duration of startup events. The source proposes to employ all of these techniques, to the 

extent practicable, to limit per event and annual emissions of NOx from startups and shutdowns. 

These operational procedures are technically feasible only to the extent that they do not re-define 

the source being permitted. No other control alternatives have been identified as demonstrated in 

practice for any similar facility as capable of further reductions in NOx under transient startup and 

shutdown conditions. Vendor requirements were used to define the levels of mass emissions per 

event that represent the top level of NOx control which also reflects BACT and LAER during 

startup and shutdown of the proposed combined cycle combustion turbines. 

Step 4: Evaluate the Most Effective Controls and Document the Results

This top level of control reflects the vendor data used to define the levels of mass emissions per 

event, and proposed restrictions on the total annual NOx emissions totalized for all estimated 

startup and shutdown events annually. Specifically, BACT for NOx during startup and shutdown 

events is proposed to be 429 pounds per event and 68 tons per 12-month rolling period for the 

two CCCT units combined. Compliance with these emission limitations from the combustion 

turbines during startup and shutdown events will be determined through Part 60 and 75 certified 

continuous emissions monitoring systems (CEMS). 

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:

The combined NOx emissions from the combined cycle combustion turbines stacks during startup 

and shutdown events is shall not exceed 429 pounds per event and 68 tons per twelve (12) 

consecutive month period.

Particulate Matter (PM and PM10) BACT – Auxiliary Boiler EU-3

Emissions of PM and PM10 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 and PM10 emissions are controlled through one of the following 

mechanisms:

(1) Fabric Filter Dust Collectors (Baghouses).
IPL Eagle Valley generating Station TSD – Appendix B Page 44 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

(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. 

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. 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.
IPL Eagle Valley generating Station TSD – Appendix B Page 45 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 Boiler (EU-3) 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. Electrostatic precipitator (ESP) 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 Auxiliary Boiler 

(EU-3) at this source.

Wet scrubbers:

A wet scrubber is an air pollution control device that removes particulate matter 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 particulate matter. Collection efficiencies for 

wet scrubbers vary with the particle size distribution of the waste gas stream. In general, 

collection efficiency decreases as the particulate matter 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 particulate matter with the following 

characteristics:

(1) Sticky and/or hygroscopic materials (materials that readily absorb water);

(2) Combustible, corrosive and explosive materials;
IPL Eagle Valley generating Station TSD – Appendix B Page 46 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

(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. 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. A wet scrubber 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 Boiler (EU-3) 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 auxiliary boilers generate low Particulate emissions and have 

large exhaust flowrates, resulting in very low concentrations of Particulates. Cyclones 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 Boiler (EU-3) 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 and PM10 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 Boiler (EU-3) at this 

source.
IPL Eagle Valley generating Station TSD – Appendix B Page 47 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 and PM10

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 Boiler (EU3) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of PM and PM10 resulting from the 

operation of the Auxiliary Boiler (EU-3).

(1) Fuel Specifications; and 

(2) Good Combustion Practices 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM and PM10 BACT determination along with the existing 

PM and PM10 BACT determinations for similar plants. All data in the table is based on the 

information obtained from the permit application submitted by IPL Eagle Valley Generating 

Station, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of 

permits available at the websites of other permitting agencies and IDEM's PSD Permits.

BACT ID 

or Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control Method

Draft 

Permit No. 

109-32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Auxiliary Boiler 

(EU-3)

79.3 

MMBtu/hr

PM and PM10: 

0.005 lb/MMBtu 

and 0.4 lb/hr, 

each, based on 

3-hr average

Good 

Combustion 

Practices and 

Fuel 

Specifications

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center 

12/03/2012 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

LA-0254

Entergy 

Louisiana, LLC, 

Ninemile Point 

Electric 

Generating 

Plant

08/16/2011 Natural gas-fired 

Auxiliary Boiler

3380 

MMBtu/hr

PM2.5 & PM10: 

7.6 lb/MMscf 

annual avg

None

OH-0310

American 

Municipal Power 

Generating 

Station

10/08/2009 Natural gas-fired 

Auxiliary Boiler 

150 

MMBtu/hr

PM10: 1.14 lb/hr; 

0.5 tpy; 7.6 

lb/MMcf

None

LA-0231

Lake Charles 

Generation, LLC 

Lake Charles 

Gasification 

Facility

06/22/2009 Natural gas-fired 

Auxiliary Boiler

938.3 

MMBtu/hr PM10: 6.99 lb/hr None
IPL Eagle Valley generating Station TSD – Appendix B Page 48 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID 

or Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control Method

AR-0094

Southwest 

Electric Power 

Plant Company, 

John W. Turk 

Power Plant

11/05/2008 Natural gas-fired 

Auxiliary Boiler

555 

MMBtu/hr

0.0040 

lb/MMBtu, 3-hr 

avg

None

PA-0257 Sunnyside 

Ethanol, LLC 05/07/2007

Natural gas-fired 

Auxiliary Boiler 

with diesel fuel 

capabilities

76,000 

cf/hr

PM: 0.024 

lb/MMBtu for 

natural gas

None

NY-0095

Caithness 

Bellport Energy 

Center 

05/10/2006 Natural gas-fired 

Auxiliary Boiler

29.4 

MMBtu/hr

PM10: 0.0033 

lb/MMBtu None

OH-0407

Biomass Center, 

South Point 

Biomass 

Generation

0/04/2006 Natural gas-fired 

Auxiliary Boiler

247 

MMBtu/hr

PM10: 1.73 

lb/hr; 3.26 tpy; 

0.007 lb/MMBtu

None

OR-0046

Calpine Turner 

Energy Center, 

LLC

01/06/2005 Natural gas-fired 

Auxiliary Boiler

417,904 

MMBtu/yr

PM10: Use of 

natural gas is 

RACT

None

AZ-0047

Dome Valley 

Energy 

Partners, 

Wellton Mohawk 

Generating 

Station

12/01/2004 Natural gas-fired 

Auxiliary Boiler

38.0 

MMBtu/hr

PM10: 0.0033 

lb/MMBtu None

NV-0037

Sempra Energy 

Resources, 

Copper 

Mountain Power

05/14/2004 Natural gas-fired 

Auxiliary Boiler

60 

MMBtu/hr

PM10: 0.5 lb/hr; 

natural gas only 

(LAER)

None

WV-0023

Longview 

Power, LLC, 

Maidsville

03/02/2004 Natural gas-fired 

Auxiliary Boiler

225

MMBtu/hr

PM/PM10: 

0.0022 

lb/MMBtu 6-hr 

rolling avg

None

OH-0269

Biomass 

Energy, LLC –

South Point 

Power

01/05/2004

Natural gas- and 

fuel oil-fired 

Auxiliary Boiler

247 

MMBtu/hr

PM10: 1.73 lb/hr 

nat gas; 3.26 tpy 

nat gas & fuel 

oil; 0.007 

lb/MMBtu nat 

gas

None

The source proposed a limit of 0.005 lb/MMBtu for the auxiliary boiler, which is consistent with the limit 

recently established by IDEM for St. Joseph Energy, a similar facility. There were four facilities identified 

in the RBLC that show more stringent emission limits than the proposed BACT limit, as further described 

below: 

• Caithness Bellport Energy Center, New York: The RBLC identifies a BACT limit of 0.0033 

lb/MMBtu. The facility’s permit states that the limit is for PM10 and the referenced test methods 

are 201A & 202. This permit does not address PM2.5. We believe that this limit is an outlier and 

there is insufficient information or operational experience for facilities such as this to support this 

limit. 

• Dome Valley Energy Partners, Wellton Mohawk Generating Station, Arizona: The technical 

review on the EPA website does not include a limit for this facility but states "Good combustion 
IPL Eagle Valley generating Station TSD – Appendix B Page 49 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

practices, operating the equipment according to manufacturer specifications and the use of 

natural gas have been identified and accepted as BACT for CO, VOC, PM10, and SO2 ".

• Longview Power, LLC, Maidsville, West Virginia: The limit in the permit is for PM and PM10

emissions not for PM2.5. The facility was permitted in 2004 and commercial operation was 

supposed to begin in 2011. There are no updates on the company’s website since June 2011 so 

operation and verification of emission factors could not be confirmed. 

The following has been proposed as BACT for PM and PM10 emissions from the proposed 

Auxiliary Boiler, identified as EU-3:

The PM and PM10 emissions from the Auxiliary Boiler, identified as EU-3 shall be limited to less 

than 0.005 lb/MMBtu and 0.4 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 and PM10 for the Auxiliary Boiler (EU-3).

The PM and PM10 emissions from the Auxiliary Boiler, identified as EU-3 shall not exceed 0.005 

lb/MMBtu and 0.4 lbs/hour, each, based on a 3-hr average period through the use of good 

combustion practices and fuel specification. 

Particulate Matter (PM2.5) BACT – Auxiliary Boiler EU-3

Emissions of 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, 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.
IPL Eagle Valley generating Station TSD – Appendix B Page 50 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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. 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 Boiler (EU-3) 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.
IPL Eagle Valley generating Station TSD – Appendix B Page 51 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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. An electrostatic precipitator (ESP) 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 Auxiliary Boiler 

(EU-3) at this source.

Wet scrubbers:

A wet scrubber is an air pollution control device that removes particulate matter 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 particulate matter. Collection efficiencies for 

wet scrubbers vary with the particle size distribution of the waste gas stream. In general, 

collection efficiency decreases as the particulate matter 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 particulate matter 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. 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 
IPL Eagle Valley generating Station TSD – Appendix B Page 52 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

exhaust flowrates, resulting in very low concentrations of Particulates. A wet scrubber 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 Boiler (EU-3) 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 auxiliary boilers generate low Particulate emissions and have 

large exhaust flowrates, resulting in very low concentrations of Particulates. Cyclones 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 Boiler (EU-3) 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 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 Boiler (EU-3) 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 Boiler (EU3) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of PM2.5 resulting from the operation of 

the Auxiliary Boiler (EU-3).

(1) Fuel Specifications; and 
IPL Eagle Valley generating Station TSD – Appendix B Page 53 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

(2) Good Combustion Practices 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM2.5 BACT determination along with the existing PM2.5

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permit.

BACT ID 

or Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control Method

Draft 

Permit No. 

109-32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Auxiliary Boiler 

(EU-3)

79.3 

MMBtu/hr

PM2.5: 0.005 

lb/MMBtu and 

0.4 lb/hr, each, 

based on 3-hr 

average

Good 

Combustion 

Practices and 

Fuel 

Specifications

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center -

proposed

12/03/2012 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

OH-0310

American 

Municipal Power 

Generating 

Station

10/08/2009 Natural gas-fired 

Auxiliary Boiler 

150 

MMBtu/hr

PM10: 1.14 lb/hr; 

0.5 tpy; 7.6 

lb/MMcf

None

PA-0257 Sunnyside 

Ethanol, LLC 05/07/2007

Natural gas-fired 

Auxiliary Boiler 

with diesel fuel 

capabilities

76,000 

cf/hr

PM: 0.024 

lb/MMBtu for 

natural gas

None

NY-0095

Caithness 

Bellport Energy 

Center 

05/10/2006 Natural gas-fired 

Auxiliary Boiler

29.4 

MMBtu/hr

PM10: 0.0033 

lb/MMBtu None

OH-0407

Biomass Center, 

South Point 

Biomass 

Generation

0/04/2006 Natural gas-fired 

Auxiliary Boiler

247 

MMBtu/hr

PM10: 1.73 

lb/hr; 3.26 tpy; 

0.007 lb/MMBtu

None

AZ-0047

Dome Valley 

Energy 

Partners, 

Wellton Mohawk 

Generating 

Station

12/01/2004 Natural gas-fired 

Auxiliary Boiler

38.0 

MMBtu/hr

PM10: 0.0033 

lb/MMBtu None

NV-0037

Sempra Energy 

Resources, 

Copper 

Mountain Power

05/14/2004 Natural gas-fired 

Auxiliary Boiler

60 

MMBtu/hr

PM10: 0.5 lb/hr; 

natural gas only 

(LAER)

None

WV-0023

Longview 

Power, LLC, 

Maidsville

03/02/2004 Natural gas-fired 

Auxiliary Boiler

225 

MMBtu/hr

PM/PM10: 

0.0022 

lb/MMBtu 6-hr 

rolling avg

None

OH-0269

Biomass 

Energy, LLC –

South Point

01/05/2004

Natural gas- and 

fuel oil-fired 

Auxiliary Boiler

247 

MMBtu/hr

PM10: 1.73 lb/hr 

nat gas; 3.26 tpy 

nat gas & fuel 

None
IPL Eagle Valley generating Station TSD – Appendix B Page 54 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID 

or Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control Method

Power oil; 0.007 

lb/MMBtu nat 

gas

The source proposed a limit of 0.005 lb/MMBtu for the auxiliary boiler, which is consistent with the limit 

recently established by IDEM for St. Joseph Energy that is a similar facility. There were four facilities 

identified in the RBLC that show more stringent emission limits than the proposed BACT limit, as further 

described below: 

• Caithness Bellport Energy Center, New York: The RBLC identifies a BACT limit of 0.0033 

lb/MMBtu. The facility’s permit states that the limit is for PM10 and the referenced test methods 

are 201A & 202. This permit does not address PM2.5. We believe that this limit is an outlier and 

there is insufficient information or operational experience for facilities such as this to support this 

limit. 

• Dome Valley Energy Partners, Wellton Mohawk Generating Station, Arizona: The technical 

review on the EPA website does not include a limit for this facility but states "Good combustion 

practices, operating the equipment according to manufacturer specifications and the use of 

natural gas have been identified and accepted as BACT for CO, VOC, PM10, and SO2 ".

• Longview Power, LLC, Maidsville, West Virginia: The limit in the permit is for PM and PM10

emissions not for PM2.5. The facility was permitted in 2004 and commercial operation was 

supposed to begin in 2011. There are no updates on the company’s website since June 2011 so 

operation and verification of emission factors could not be confirmed. 

The following has been proposed as BACT for PM2.5 emissions from the proposed Auxiliary 

Boiler, identified as EU-3:

The PM2.5 emissions from the Auxiliary Boiler, identified as EU-3 shall be limited to less than 

0.005 lb/MMBtu and 0.4 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 PM2.5 for the Auxiliary Boiler (EU-3).

The PM2.5 emissions from the Auxiliary Boiler, identified as EU-3 shall not exceed 0.005 

lb/MMBtu and 0.4 lbs/hour, each, based on a 3-hr average period through the use of good 

combustion practices and fuel specification. 

Sulfuric Acid (H2SO4) BACT – Auxiliary Boiler EU-3

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
IPL Eagle Valley generating Station TSD – Appendix B Page 55 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

(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 

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 2,000 ppmv. 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 

Auxiliary Boiler (EU-3) 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.

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.

Dry sorbent injection is not listed in the RBLC as BACT for the control of H2SO4 emissions for 

large combined cycle combustion turbines.

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 Boiler (EU-3) 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 Auxiliary Boiler.
IPL Eagle Valley generating Station TSD – Appendix B Page 56 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 Boiler (EU-3) 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 Auxiliary Boiler (EU-3). 

(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 IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Auxiliary 

Boiler (EU-3)

79.3

MMBtu/hr, 

each

H2SO4: 0.75 

gr S/100 scf 

natural gas

Fuel 

Specification

FL-0330 Port Dolphin 

Energy, LLC 12/01/2011 Natural gasfired Boilers NA

0.34 lb/hr, 3-

hr rolling 

average

None

OH-0317

Ohio River 

Clean Fuels, 

LLC

11/20/2008

Natural gasand tail gasfired Boiler

1,200 

MMBtu/hr

0.17 lb/hr, 3-

hr average; 

0.75 tpy per 

rolling 12-

month 

period

None

MD-0040

Competitive 

Power Ventures, 

Inc. CPB St. 

Charles

11/12/2008

Natural gasfired Auxiliary 

Boiler

93 

MMBtu/hr

0.0001 

lb/mmbtu 3-

hr avg

None

OR-0046 Calpine Turner 

Energy, LLC 01/06/2005

Natural gasfired Auxiliary 

Boiler

417,904 

MMBtu/hr

Use of 

natural gas 

is RACT

None

WI-0228

Wisconsin 

Public Service, 

Weston Plant

10/19/2004

Natural gasfired Auxiliary 

Boiler

229.80 

MMBtu/hr

0.210 lb/hr; 

2,000 hrs/ 

12 month 

rolling limit

None

TX-0386

Calpine 

Construction 

Amella Energy 

Center

03/26/2002

Natural gasfired Auxiliary 

Boiler

155 

MMBtu/hr 0.129 lb/hr None

The RBLC was reviewed and a summary of the BACT determinations from auxiliary boilers is 

shown in above table. It should be noted that there were no facilities identified that utilized any 

add-on control technologies to reduce H2SO4 emissions from auxiliary boilers fired with natural 

gas. These emissions are characterized by variability in the sulfur content of pipeline natural gas 
IPL Eagle Valley generating Station TSD – Appendix B Page 57 of 152

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which varies from pipeline to pipeline, and month to month, and is outside the direct control of the 

facility that receives its natural gas from the pipeline. 

There are no technically feasible control technologies that have been identified that are capable 

of reducing or controlling emissions of H2SO4 from small natural gas-fired industrial boilers. The 

top level of control would be that emission rate that results from the limitation to utilize pipeline 

quality natural gas. Variations in this value are believed to occur simply based on the level of risk 

that previous applicants have agreed to accept and/or variations in natural gas sulfur content from 

pipeline to pipeline. While the RBLC does not identify any facilities that have determined BACT 

to be the use of pipeline natural gas, we believe that the use of pipeline quality natural gas will be 

the most effective means of reducing H2SO4 emissions.

The following has been proposed as BACT for H2SO4 emissions from the proposed auxiliary 

boiler, identified as EU-3:

(a) The H2SO4 emissions from the auxiliary boiler, identified as EU-3 shall be limited by 

limiting the S content of the natural gas to 0.75 gr S/100 scf on a monthly average basis. 

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 auxiliary boiler, identified as EU-3.

(a) The H2SO4 emissions from the auxiliary boiler, identified as EU-3 shall be limited by 

limiting the S content of the natural gas to 0.75 gr S/100 scf on a monthly average basis. 

Carbon Monoxide (CO) BACT – Auxiliary Boiler EU-3

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 via Advance Ultra-Low NOx Burner; and

(e) Flares.

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. Oxidizers are not recommended for controlling gases with sulfur containing 

compounds because of the formation of highly corrosive acid gases.
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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 Auxiliary 

Boiler 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 Auxiliary 

Boiler 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.
IPL Eagle Valley generating Station TSD – Appendix B Page 59 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 Boiler 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 Auxiliary Boiler at this source

Good Combustion Controls via Advance Ultra-Low NOx Burner

Good combustion controls is a continued operation of the auxiliary boiler 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 is formed in a package boiler as a trade-off with NOx control in an ultra-low NOx burner. The 

latest generation of low NOx burners seeks to optimize emissions of NOx and CO simultaneously.

CO is minimized in boiler through good combustion practices, including low- NOx burners, flue 

gas recirculation (FGR), and ultra-low- NOx burners that each support effective combustion that 

minimizes CO generation. 

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 Boiler at this 

source

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Oxidation Catalyst - (75% destruction efficiency)

(2) Combustion Control via Advance Ultra-low NOx burner

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 IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permit.
IPL Eagle Valley generating Station TSD – Appendix B Page 60 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(MMBtu/hr)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Auxiliary Boiler 

(EU-3)

79.3 

MMBtu/hr

CO: 0.082 

lb/MMBtu and 

6.5 lb/hr,

based on 3-hr 

average

Combustion 

Control via

Advance 

ultra-low NOx 

Burners

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center 

- proposed

12/03/2012 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

10/08/2009 Natural gas-fired 

Auxiliary Boiler 

150 

MMBtu/hr

12.6 lb/hr; 

5.52 tpy; 400 

ppm by vol, 

dry basis to 

3% O2, 3-hr 

avg

None

OK-0129

Associated 

Electric 

Cooperative, 

Inc. Chouteau 

Power Plant

01/23/2009 Natural gas-fired 

Auxiliary Boiler

33.5 

MMBtu/hr 5.02 lb/hr None

WY-0064

Basin Electric 

Power 

Cooperative, 

Dry Fork 

Station

10/15/2007 Natural gas-fired 

Auxiliary Boiler

134 

MMBtu/hr

0.08 lb/ 

MMBtu; 10.7 

tpy, limited to 

2,000 hrs of 

operation/year

None

FL-0285

Progress 

Energy 

Florida, 

Progress 

Bartow Power 

Plant

01/26/2007 Natural gas-fired 

Auxiliary Boiler

99 

MMBtu/hr

0.08 lb/ 

MMBtu, 400 

ppmvd

None

FL-0286

Florida Power 

& Light Co., 

FPL West 

County 

Energy Center

01/10/2007 Natural gas-fired 

Auxiliary Boiler 

99.8 

MMbtu/hr 0.08 lb/MMBtu None

NY-0095

Caithness 

Bellport 

Energy Center 

05/10/2006 Natural gas-fired 

Auxiliary Boiler

29.4 

MMBtu/hr

0.036 

lb/MMBtu None

OH-0407

Biomass 

Center, South 

Point Biomass 

Generation

0/04/2006 Natural gas-fired 

Auxiliary Boiler

247 

MMBtu/hr

27.17 lb/hr; 

48.32 tpy; 

0.11 lb/MMBtu

None

AZ-0047

Dome Valley 

Energy 

Partners, 

Wellton 

Mohawk 

Generating 

Station

12/01/2004 Natural gas-fired 

Auxiliary Boiler

38.0 

MMBtu/hr 0.08 lb/MMBtu None
IPL Eagle Valley generating Station TSD – Appendix B Page 61 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(MMBtu/hr)

Limitation Control 

Method

NV-0037

Sempra 

Energy 

Resources, 

Copper 

Mountain 

Power

05/14/2004 Natural gas-fired 

Auxiliary Boiler

60 

MMBtu/hr

0.08 

lb/MMBtu; 4.8 

lb/hr (LAER)

None

WV-0023

Longview 

Power, LLC, 

Maidsville

03/02/2004 Natural gas-fired 

Auxiliary Boiler

225 

MMBtu/hr

0.04 

lb/MMBtu 3-

hour rolling 

avg

None

OH-0269

Biomass 

Energy, LLC –

South Point 

Power

01/05/2004

Natural gas- and 

fuel oil-fired 

Auxiliary Boiler

247 

MMBtu/hr

27.17 lb/hr nat 

gas; 48.23 tpy 

nat gas & fuel 

oil; 0.011 

lb/MMBtu nat 

gas

None

There were four facilities identified in the RBLC that show more stringent emission limits than the 

proposed BACT limit, as further described below: 

• Caithness Bellport Energy Center, New York: The RBLC identifies a BACT limit of 0.036 

lb/MMBtu. Again, we believe this limit is an outlier and there is insufficient information available 

to support such a limit as being achievable on an ongoing basis.

• Longview Power, LLC, Maidsville, West Virginia: The permit has a limit of 0.04 lbs/MMBtu for PM 

and PM10 emissions. The facility was permitted in 2004 and commercial operation was supposed 

to begin in 2011. There are no updates on the company’s website since June 2011 so operation 

and verification of emission factors could not be confirmed. 

• Biomass Center, South Point Biomass Generation, Ohio: The RBLC shows a limit of 27.17 lb/hr, 

and indicates a basis of 0.11 lbs/MMBtu and not 0.011 lbs/MMBtu as shown in RBLC table. As 

such IDEM believe that the CO limit for this facility is not more stringent than that that proposed 

by IPL. 

Cost Analysis for Regenerative Incinerators

The cost of add-on control technology to control CO emissions is not cost effective due to the low 

concentration of CO in the exhaust stream. The U.S. EPA’s Air Pollution Control Technology Fact 

Sheet for Regenerative Incinerators (EPA-452/F-03-021) provides annualized costs ranging from 

$8 to $33/cfm for regenerative thermal oxidizers and $11 to $41/cfm for catalytic oxidizers. The 

auxiliary boiler has a design exhaust flow rate of approximately 24,500 cfm, but a low maximum 

potential CO emission rate (28.5 tpy based on 8,760 hours per yr at full load), and using a 

conservative cost of $8/cfm, the cost effectiveness of installing add-on controls would be at least 

$56,000/ton of CO removed. Under expected operating conditions (500 hours/yr), the cost 

effectiveness would be more than $560,000 ton controlled. As such, neither regenerative thermal 

oxidation nor thermal oxidation could possibly be considered to be cost effective. 

The following has been proposed as BACT for CO emissions from the proposed Auxiliary Boiler, 

identified as EU-3:

The CO emissions from the Auxiliary Boiler (EU-3) operation shall not exceed 0.082 lb/MMBtu 

and 6.65 lbs/hr, each, based on a 3 - hour average through the use of advanced ultra -low NOx 

burner.
IPL Eagle Valley generating Station TSD – Appendix B Page 62 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 (EU-3).

The CO emissions from the Auxiliary Boiler (EU-3) operation shall not exceed 0.083 lb/MMBtu 

and 6.65 lbs/hr, each, based on a 3 - hour average through the use of advanced ultra -low NOx 

burner.

Volatile Organic Compounds (VOCs) BACT - Auxiliary Boiler EU-3

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 via Advance Ultra-Low NOx Burner; and

(e) Flares.

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 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. Oxidizers are not recommended for controlling gases with 

sulfur containing compounds because of the formation of highly corrosive acid gases.

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 
IPL Eagle Valley generating Station TSD – Appendix B Page 63 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 Boiler 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 

Boiler 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 

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 Boiler at this source
IPL Eagle Valley generating Station TSD – Appendix B Page 64 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

Good Combustion Controls via Advance Ultra-Low NOx Burner

Good combustion controls is a continued operation of the boiler at the appropriate oxygen range 

and temperature to promote complete combustion and minimize VOC formation. 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 is formed in a package boiler as a trade-off with NOx control in an ultra-low NOx burner. 

The latest generation of low NOx burners seeks to optimize emissions of NOx and CO 

simultaneously. VOC is minimized in boiler through good combustion practices, including lowNOx burners, flue gas recirculation (FGR), and ultra-low- NOx burners that each support effective 

combustion that minimizes VOC generation. 

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 Boiler at this 

source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Oxidation Catalyst - (75% destruction efficiency)

(2) Combustion Control via Ultra-low NOx burner

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 IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permit.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(MMBtu/hr)

Limitation Control Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Auxiliary Boiler 

(EU-3)

79.3 

MMBtu/hr

VOCs: 

0.0053

lb/MMBtu 

and 0.42

lb/hr, based 

on 3-hr 

average

Advance ultralow NOx 

Burners

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center 

12/03/2012 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 

OH-0310

American 

Municipal 

Power 

Generating 

Station

10/08/2009 Natural gas-fired 

Auxiliary Boiler 

150 

MMBtu/hr

0.83 lb/hr; 

0.36 tpy; 5.5 

lb/MMscf

None
IPL Eagle Valley generating Station TSD – Appendix B Page 65 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(MMBtu/hr)

Limitation Control Method

OK-0129

Associated 

Electric 

Cooperative, 

Inc. Chouteau 

Power Plant

01/23/2009 Natural gas-fired 

Auxiliary Boiler

33.5 

MMBtu/hr 0.54 lb/hr None

PA-0257 Sunnyside 

Ethanol, LLC 05/07/2007

Natural gas-fired 

Auxiliary Boiler with 

diesel fuel 

capabilities

76,000 

cf/hr

0.014 

lb/MMBtu for 

natural gas

None

OH-0407

Biomass 

Center, South 

Point Biomass 

Generation

0/04/2006 Natural gas-fired 

Auxiliary Boiler

247 

MMBtu/hr

0.99 lb/hr; 

1.76 tpy; 

0.004 

lb/MMBtu

None

AZ-0047

Dome Valley 

Energy 

Partners, 

Wellton

Mohawk 

Generating 

Station

12/01/2004 Natural gas-fired 

Auxiliary Boiler

38.0 

MMBtu/hr

0.0033 

lb/MMBtu None

NV-0037

Sempra 

Energy 

Resources, 

Copper 

Mountain 

Power

05/14/2004 Natural gas-fired 

Auxiliary Boiler

60 

MMBtu/hr

0.40 lb/hr 

(LAER) None

WV-0023

Longview 

Power, LLC, 

Maidsville

03/02/2004 Natural gas-fired 

Auxiliary Boiler

225 

MMBtu/hr

0.0054 

lb/MMBtu 3-

hr rolling avg

None

OH-0269

Biomass 

Energy, LLC –

South Point 

Power

01/05/2004

Natural gas- and 

fuel oil-fired 

Auxiliary Boiler

247 

MMBtu/hr

0.99 lb/hr nat 

gas; 1.76 tpy 

nat gas & fuel 

oil

None

There were three facilities identified in the RBLC that show more stringent emission limits than the 

proposed BACT limit, as further described below: 

• Calpine Turner Energy Center, Oregon: This facility was not built.

• Biomass Center, South Point Biomass Generation, Ohio: A review of the Title V permit shows 

that this limit was not included in the permit. The permit includes a limit of 0.99 lbs VOC/hr (as 

shown in IPL's BACT submittal), but does not include a lbs/mmbtu value.

• Dome Valley Energy Partners, Wellton Mohawk Generating Station, Arizona: The final permit 

could not be obtained. The Technical Review on the EPA website does not include a limit for this 

facility but states "Good combustion practices, operating the equipment according to 

manufacturer specifications and the use of natural gas have been identified and accepted as 

BACT for CO, VOC, PM10, and SO2."
IPL Eagle Valley generating Station TSD – Appendix B Page 66 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

Cost Analysis for Regenerative Incinerators

The cost of add-on control technology to control VOC emissions is not cost effective due to the 

low concentration of VOC in the exhaust stream. The U.S. EPA’s Air Pollution Control 

Technology Fact Sheet for Regenerative Incinerators (EPA-452/F-03-021) provides annualized 

costs ranging from $8 to $33/cfm for regenerative thermal oxidizers and $11 to $41/cfm for 

catalytic oxidizers. The auxiliary boiler has a design exhaust flow rate of approximately 24,500 

cfm, but a low maximum potential VOC emission rate (28.5 tpy based on 8,760 hours per yr at full 

load), and using a conservative cost of $8/cfm, the cost effectiveness of installing add-on controls 

would be at least $56,000/ton of VOC removed. Under expected operating conditions (500 hours 

/yr, the cost effectiveness would be more than $560,000 ton controlled. As such, neither 

regenerative thermal oxidation nor thermal oxidation could possibly be considered to be cost 

effective. 

The following has been proposed as BACT for VOC emissions from the proposed Auxiliary Boiler 

(EU-3):

The VOC emissions from the Auxiliary Boiler, identified as EU-3 shall not exceed 0.0053 lb/MMBtu

and 0.42 lbs/hr, each, based on a 3-hr average period through the use of advanced ultra -low NOx 

burner.

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 Boiler (EU-3).

The VOC emissions from the Auxiliary Boiler, identified as EU-3 shall not exceed 0.0053

lb/MMBtu and 0.42 lbs/hr, each, based on a 3-hr average period through the use of advanced 

ultra - low NOx burner.

Nitrogen Oxide (NOx) BACT - Auxiliary Boiler EU-3

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; and

(d) Ultra-Low NOx Burners (LNB).

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.
IPL Eagle Valley generating Station TSD – Appendix B Page 67 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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. 

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.
IPL Eagle Valley generating Station TSD – Appendix B Page 68 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 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)

(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 IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permit.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(MMBtu/hr)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Auxiliary Boiler 

(EU-3)

79.3 

MMBtu/hr

NOx: 0.011

lb/MMBtu and 

0.87 pounds 

per hour, 

based on 3-hr 

average

Low NOx 

Burner with 

Flue Gas 

Recirculation

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy Center 

- proposed

12/03/2012 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

OK-0129

Associated 

Electric 

Cooperative, 

Inc. Chouteau 

Power Plant

01/23/2009 Natural gas-fired 

Auxiliary Boiler

33.5 

MMBtu/hr

0.07 

lb/MMBtu; 

2.36 lb/hr

Low-NOx

burners

WY-0064

Basin Electric 

Power 

Cooperative, 

Dry Fork 

10/15/2007 Natural gas-fired 

Auxiliary Boiler

134 

MMBtu/hr

0.04 

lb/MMBtu; 5.4 

tpy, limited to 

2,000 hrs of 

Low-NOx

burners with 

flue gas 

recirculation
IPL Eagle Valley generating Station TSD – Appendix B Page 69 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(MMBtu/hr)

Limitation Control 

Method

Station operation/year

PA-0257 Sunnyside 

Ethanol, LLC 05/07/2007

Natural gas-fired 

Auxiliary Boiler with 

diesel fuel 

capabilities

76,000 

cf/hr

0.035 

lb/MMBtu for 

natural gas

Low-NOx

burners with 

flue gas 

recirculation

OH-0309

Daimler 

Chrysler 

Toledo 

Supplier ParkPaint Shop

05/03/2007 Natural gas-fired 

boilers

20.40 

MMBtu/hr

0.035 

lb/MMBtu; 7.2 

lb/hr; 3.5 tpy 

(LAER)

Low-NOx

burners with 

flue gas 

recirculation

FL-0286

Florida Power 

& Light Co., 

FPL West 

County 

Energy Center

01/10/2007 Natural gas-fired 

Auxiliary Boiler 

99.8 

MMbtu/hr 0.05 lb/MMBtu None

OK-0115

Energetix 

Lawton 

Energy Cogen 

Facility

12/12/2006 Natural gas-fired 

Auxiliary Boiler NA 0.036 lb/MMBtu

Dry-Low NOx

burners

NY-0095

Caithness 

Bellport 

Energy Center

05/10/2006 Natural gas-fired 

Auxiliary Boiler

29.4 

MMBtu/hr

0.0110 

lb/MMBtu

Low NOx -

burners and 

FGR

OH-0407

Biomass 

Center, South 

Point Biomass 

Generation

0/04/2006 Natural gas-fired 

Auxiliary Boiler

247 

MMBtu/hr

14.82 lb/hr; 

27.02 tpy; 

0.06 lb/MMBtu

None

AZ-0047

Dome Valley 

Energy 

Partners, 

Wellton 

Mohawk 

Generating 

Station

12/01/2004 Natural gas-fired 

Auxiliary Boiler

38.0 

MMBtu/hr

0.37 lb/ 

MMBtu

Low NOx -

burners

NV-0037

Sempra

Energy 

Resources, 

Copper 

Mountain 

Power

05/14/2004 Natural gas-fired 

Auxiliary Boiler

60 

MMBtu/hr

0.035 lb/ 

MMBtu; 9.6 

tpy

Low NOx

burners with 

either internal 

or external 

FGR

WV-0023

Longview 

Power, LLC, 

Maidsville

03/02/2004 Natural gas-fired 

Auxiliary Boiler

225 

MMBtu/hr

0.098 lb/ 

MMBtu

Low NOx -

burners

OH-0269

Biomass 

Energy, LLC –

South Point 

Power

01/05/2004

Natural gas- and 

fuel oil-fired 

Auxiliary Boiler

247 

MMBtu/hr

14.82 lb/hr nat 

gas; 27.02 tpy 

nat gas & fuel 

oil; 0.06 lb/ 

MMBtu nat 

gas

None

Ultra-low-NOx burners have been proven to reduce NOx emissions to 0.011 lb/MMBtu, which has 

been determined to be the top level of control for small natural gas-fired auxiliary boilers used to 

back up combined cycle power plants. 
IPL Eagle Valley generating Station TSD – Appendix B Page 70 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

Ultra-Low NOx burners employ internal or external flue gas recirculation (FGR). FGR reduces 

NOx emissions in industrial boilers by recirculating a portion of the exhaust gas back into the 

combustion process. This results in lower combustion temperatures and oxygen levels in the 

combustion air/flue gas mixture, thus retarding the formation of thermal NOx. More traditional 

burners operate with less combustion staging and less overall pressure drop. 

The following has been proposed as BACT for NOx emissions from the proposed Auxiliary Boiler, 

identified as EU-3:

(1) The NOx emissions from the Auxiliary Boilers, identified as EU-3 shall be controlled 

by a Low NOx Burner with Flue Gas Recirculation.

(2) The NOx emissions shall be limited to less than 0.011 lb/MMBtu pounds per hour, 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 EU-3:

(1) The NOx emissions from the Auxiliary Boilers, identified as EU-3 shall be controlled 

by Low NOx Burners with Flue Gas Recirculation.

(2) The NOx emissions shall be limited to less than 0.011 lb/MMBtu and 0.87 pounds per 

hour, based on a 3-hr average period.

Particulate Matter (PM and PM10) BACT – Dew Point heater EU-4

Emissions of PM and PM10 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 and PM10 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.
IPL Eagle Valley generating Station TSD – Appendix B Page 71 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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. 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 Dew Point Heater (EU-4) 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.
IPL Eagle Valley generating Station TSD – Appendix B Page 72 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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. An electrostatic precipitator (ESP) 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 Dew Point Heater 

(EU-4) at this source.

Wet scrubbers:

A wet scrubber is an air pollution control device that removes particulate matter 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 particulate matter. Collection efficiencies for 

wet scrubbers vary with the particle size distribution of the waste gas stream. In general, 

collection efficiency decreases as the particulate matter 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 particulate matter 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 
IPL Eagle Valley generating Station TSD – Appendix B Page 73 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

corrosion. Natural-gas fired auxiliary boilers generate low Particulate emissions and have large 

exhaust flowrates, resulting in very low concentrations of Particulates. A wet scrubber 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 Dew Point Heater (EU-4) 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 auxiliary boilers generate low Particulate emissions and have 

large exhaust flowrates, resulting in very low concentrations of Particulates. Cyclones 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 Dew Point Heater (EU-4) 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 and PM10 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 Dew Point Heater (EU-4) at 

this source.

Good Combustion Practices 

Good combustion practices as well as operation and maintenance of the Dew Point Heater to 

keep them in good working order per the manufacturer's specifications will minimize PM and 

PM10 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 Dew Point Heater 

(EU-4) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of PM and PM10 resulting from the 

operation of the Dew Point Heater (EU-4).

(1) Fuel Specifications; and
IPL Eagle Valley generating Station TSD – Appendix B Page 74 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

(2) Good Combustion Practices 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM and PM10 BACT determination along with the existing 

PM and PM10 BACT determinations for similar plants. All data in the table is based on the 

information obtained from the permit application submitted by IPL Eagle Valley Generating 

Station, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of 

permits available at the websites of other permitting agencies and IDEM's PSD Permit.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control Method

Draft Permit 

No. 109-32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Dew Point 

Heater (EU-4)

20.8 

MMBtu/hr

PM and PM10: 

0.0072 lb/MMBtu 

and 0.15 lb/hr, 

each, based on 

3-hr average

Good 

Combustion 

Practices and 

Fuel 

Specifications

AK-0071

Chugach 

Electric 

Association, 

Inc., 

International 

Station Power 

Plant

12/20/2010

Sigma 

Thermal 

Auxiliary 

Heater

12.5 

MMBtu/hr

PM/PM10/PM2.5: 

7.6 lb/mmscf, 3-

hr avg

None

IA-0064 Roquette 

America 01/31/2003 Dew Point Heater 1.6 MMBtu/hr

PM: 0.008 

lb/mmbtu; 0.120 

lb/hr

None

As shown in the above table, a limit of 0.0072 lb/MMBtu which is the most stringent is consistent 

with the other limits contained in the RBLC.

The following has been proposed as BACT for PM and PM10 emissions from the proposed Dew 

Point Heater, identified as EU-4:

The PM and PM10 emissions from the Dew Point Heater, identified as EU-4 shall be limited to 

less than 0.0072 lb/MMBtu and 0.15 lbs/hr, 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 and PM10 for the Dew Point Heater (EU-4).

The PM and PM10 emissions from the Dew Point Heater, identified as EU-4 shall be limited to 

less than 0.0072 lb/MMBtu and 0.15 lbs/hr, based on a 3-hr average period through the use of 

good combustion practices and fuel specification. 

Particulate Matter (PM2.5) BACT – Dew Point heater EU-4

Emissions of 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, PM2.5 emissions are controlled through one of the following mechanisms:
IPL Eagle Valley generating Station TSD – Appendix B Page 75 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

(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. 

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. 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.
IPL Eagle Valley generating Station TSD – Appendix B Page 76 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 Dew Point Heater (EU-4) 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. An electrostatic precipitator (ESP) 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 Dew Point Heater 

(EU-4) at this source.

Wet scrubbers:

A wet scrubber is an air pollution control device that removes particulate matter 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 particulate matter. Collection efficiencies for 

wet scrubbers vary with the particle size distribution of the waste gas stream. In general, 

collection efficiency decreases as the particulate matter 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 particulate matter with the following 

characteristics:

(1) Sticky and/or hygroscopic materials (materials that readily absorb water);

(2) Combustible, corrosive and explosive materials;
IPL Eagle Valley generating Station TSD – Appendix B Page 77 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

(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. 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. A wet scrubber 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 Dew Point Heater (EU-4) 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 auxiliary boilers generate low Particulate emissions and have 

large exhaust flowrates, resulting in very low concentrations of Particulates. Cyclones 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 Dew Point Heater (EU-4) 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 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 Dew Point Heater (EU-4) at 

this source.
IPL Eagle Valley generating Station TSD – Appendix B Page 78 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

Good Combustion Practices 

Good combustion practices as well as operation and maintenance of the Dew Point Heater to 

keep them in good working order per the manufacturer's specifications will minimize 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 Dew Point Heater 

(EU-4) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of PM2.5 resulting from the operation of 

the Dew Point Heater (EU-4).

(1) Fuel Specifications; and

(2) Good Combustion Practices 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM2.5 BACT determination along with the existing PM2.5

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permits.

BACT ID 

or Permit #

Facility Issued Date Process 

Description

Rating 

(MMBtu/hr)

Limitation Control Method

Draft 

Permit No. 

109-32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Dew Point 

Heater (EU-4)

20.8 

MMBtu/hr

PM2.5: 0.0072 

lb/MMBtu and 

0.15 lb/hr, 

each, based on 

3-hr average

Good 

Combustion 

Practices and 

Fuel 

Specifications

AK-0071

Chugach 

Electric 

Association, 

Inc., 

International 

Station Power 

Plant

12/20/2010 Sigma Thermal 

Auxiliary Heater

12.5 

MMBtu/hr

PM/PM10/PM2.5: 

7.6 lb/mmscf, 3-

hr avg

None

IA-0064 Roquette 

America 01/31/2003 Dew Point Heater 1.6 MMBtu/hr

PM: 0.008 

lb/MMBtu; 0.120 

lb/hr

None

As shown in the above table, a limit of 0.0072 lb/MMBtu which is the most stringent is consistent 

with the other limits contained in the RBLC.

The following has been proposed as BACT for PM2.5 emissions from the proposed Dew Point 

Heater, identified as EU-4:

The PM2.5 emissions from the Dew Point Heater, identified as EU-4 shall be limited to less than 

0.072 lb/MMBtu and 0.15 lbs per hour, based on a 3-hr average period through the use of good 

combustion practices and fuel specification. 
IPL Eagle Valley generating Station TSD – Appendix B Page 79 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD)), IDEM has established 

the following as BACT for PM2.5 for the Dew Point Heater (EU-4).

The PM2.5 emissions from the Dew Point Heater, identified as EU-4 shall be limited to less than 

0.0072 lb/MMBtu and 0.15 lbs/hr, based on a 3-hr average period through the use of good 

combustion practices and fuel specification. 

Sulfuric Acid (H2SO4) BACT – Dew Point Heater EU-4

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

Add-on Control Technology

Add-on particulate control devices such as Flue Gas Desulfurization (FGD) System, Dry Sorbent 

Injection are not possible alternatives because the potential H2SO4 emissions from emergency 

engines are very minor, given their limited hours of operation. With such insignificant emissions, 

it would not be considered feasible to employ add-on control technologies to reduce 

H2SO4emissions from emergency engines. Additionally, since control technologies have not 

been implemented in practice to control emissions from emergency engines, there is no evidence 

that such measures would be technically feasible. 

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. 

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 Dew Point Heater (EU-4) 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 Dew Point Heater (EU-4). 
IPL Eagle Valley generating Station TSD – Appendix B Page 80 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

(1) Fuel Specifications 

Step 4: Evaluate the Most Effective Controls and Document the Results

There are no technically feasible control technologies that have been identified that are capable 

of reducing or controlling emissions of H2SO4 from small natural gas-fired heaters. The top level 

of control would be that emission rate that results from the limitation to utilize pipeline quality 

natural gas. Variations in this value are believed to occur simply based on the level of risk that 

previous applicants have agreed to accept and/or variations in natural gas sulfur content from 

pipeline to pipeline. While the RBLC does not identify any facilities that have determined BACT 

to be the use of pipeline natural gas, the use of pipeline quality natural gas will be the most 

effective means of reducing H2SO4 emissions.

The following has been proposed as BACT for H2SO4 emissions from the proposed dew point 

heater, identified as EU-4:

(a) The H2SO4 emissions from the dew point heater, identified as EU-4 shall be limited by

limiting the S content of the natural gas to 0.75 gr S/100 scf on a monthly average basis. 

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 dew point heater (EU-4).

(a) The H2SO4 emissions from the dew point heater, identified as EU-4 shall be limited by 

limiting the S content of the natural gas to 0.75 gr S/100 scf on a monthly average basis. 

Carbon Monoxide (CO) BACT – Dew Point Heater EU-4

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 CO is heated. The mixture continues to react as it flows through the 
IPL Eagle Valley generating Station TSD – Appendix B Page 81 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

combustion chamber. Oxidizers are not recommended for controlling gases with sulfur containing 

compounds because of the formation of highly corrosive acid gases.

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 Dew Point 

Heater 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 Dew Point 

Heater 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 
IPL Eagle Valley generating Station TSD – Appendix B Page 82 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 Dew Point Heater 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 Dew Point Heater 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 Dew Point Heater at 

this source

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Oxidation Catalyst - (75% destruction efficiency)

(2) Combustion Control via good combustion design and low NOx burners

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 IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permit.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(MMBtu/hr)

Limitation Control Method
IPL Eagle Valley generating Station TSD – Appendix B Page 83 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(MMBtu/hr)

Limitation Control Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Dew Point Heater 

(EU-4)

20.8 

MMBtu/hr

CO: 0.082 

lb/MMBtu 

and 1.7 

lb/hr, based 

on 3-hr 

average

Good 

Combustion 

Design and 

low NOx 

Burners

WY-0070

Black Hills 

Power, Inc., 

Cheyenne 

Prairie 

Generating 

Station

08/28/2012 Inlet Air Heaters

16.10 

MMBtu/hr 

(each)

0.08 

lb/MMBtu, 3-

hr avg; 1.3 

lb/hr, 3-hr 

avg

None

WY-0066 Medicine Bow 

Fuel & Power 03/04/2009 Gasification Preheaters (5)

21 

MMBtu/hr, 

each

0.08 lb/

MMBtu None

IA-0058

Midamerican 

Energy, 

Greater Des 

Moines 

Energy Center

04/10/2002 Dew Point Heater 10 

MMBtu/hr

0.036 lb/

MMBtu; 1.47 

tpy

None

FL-0303 Florida Power 

& Light Co. 07/30/2008 Process Heaters 10 MMBtu/hr

0.08 lb/

MMBtu None

The Midamerican Energy, Greater Des Moines Energy Center permit, issued on April 10, 2002 

operates a 10 MMBtu/hr heater, without controls, and has a CO limit of 0.036 lb/MMBtu and 1.47 

tpy. This emission limit is an outlier. The heater is small compare in size with the IPL dew point 

heater and IPL’s proposed CO emission limit of 0.082 MMBtu/hour which is consistent with the 

AP-42 emission factor for mid-size heaters. Additionally, there is a preponderance of BACT 

determinations for small natural gas-fired heaters in the past few years that are consistent with 

the BACT determination for IPL of 0.082 lb/MMBtu.

The cost of add-on control technology to control CO emissions is not cost effective due to the low 

concentration of CO in the exhaust stream. The U.S. EPA’s Air Pollution Control Technology 

Fact Sheet for Regenerative Incinerators (EPA-452/F-03-021) provides annualized costs ranging 

from $8 to $33/cfm for regenerative thermal oxidizers and $11 to $41/cfm for catalytic oxidizers. 

The dew point heater has a design exhaust flow rate of approximately 6,400 cfm, and a low 

maximum potential CO emission rate (7.5 tpy based on 8,760 hours per year at full load). Using a 

conservative cost of $8/cfm, the cost effectiveness of installing add-on controls would be at least 

$38,000 per ton of CO removed. 

The following has been proposed as BACT for CO emissions from the proposed Dew Point 

Heater, identified as EU-4:

The CO emissions from the Dew Point Heater (EU-4) operation shall not exceed 0.082 lb/MMBtu 

and 1.7 lbs/hr, based on a 3 - hour average through the use of good combustion and low NOx 

burners.

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 Dew Point Heater (EU-4).
IPL Eagle Valley generating Station TSD – Appendix B Page 84 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

The CO emissions from the Dew Point Heater (EU-4) operation shall not exceed 0.082 lb/MMBtu 

and 1.7 lbs/hr, based on a 3 - hour average through the use of good combustion and low NOx 

burners.

Volatile Organic Compounds (VOCs) BACT - Dew Point Heater EU-4

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.

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 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. Oxidizers are not recommended for controlling gases with 

sulfur containing compounds because of the formation of highly corrosive acid gases.

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. 
IPL Eagle Valley generating Station TSD – Appendix B Page 85 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 Dew Point Heater

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 Dew Point 

Heater 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 

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 Dew Point Heater 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 Dew Point Heater 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 
IPL Eagle Valley generating Station TSD – Appendix B Page 86 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 Dew Point Heater at 

this source

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Oxidation Catalyst - (75% destruction efficiency); and

(2) Combustion Control via good combustion design and low NOx burners

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 IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(MMBtu/hr)

Limitation Control Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Dew Point Heater 

(EU-4)

20.8 

MMBtu/hr

VOCs: 

0.0053 

lb/MMBtu 

and 0.42 

lb/hr, based 

on 3-hr 

average

Good 

Combustion 

Design and 

low NOx 

Burners

LA-0237

International

Matex Tank 

Terminal

05/20/2010 Heaters (6)

37.80 

MMBtu/hr, 

each

0.0055 

lb/mmbtu None

OK-0134

Pryor Plant 

Chemical 

Company

02/23/2009 Nitric Acid 

Preheaters No. 1

20 

MMBtu/hr

0.11 lb/hr and 

0.0050 

lbs/MMBtu

None

OK-0129

Associated 

Electric 

Cooperative, 

Inc. Chouteau 

Power Plant

01/23/2009 Fuel Gas Heater 18.8 

MMBtu/hr

0.1 lb/hr ad 

0.0053 

lbs/MMBtu

None

As shown in the above table, a limit of 0.0053 lb/MMBtu which is the most stringent is consistent 

with the other limits contained in the RBLC.

The cost of add-on control technology to control VOC emissions is not cost effective due to the 

low concentration of VOC in the exhaust stream. The U.S. EPA’s Air Pollution Control 

Technology Fact Sheet for Regenerative Incinerators (EPA-452/F-03-021) provides annualized 

costs ranging from $8 to $33/cfm for regenerative thermal oxidizers and $11 to $41/cfm for 

catalytic oxidizers. The dew point heater has a design exhaust flow rate of approximately 6,400 
IPL Eagle Valley generating Station TSD – Appendix B Page 87 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

cfm, and a low maximum potential VOC emission rate (0.48 tpy based on 8,760 hours per year at 

full load). Using a conservative cost of $8/cfm, the cost effectiveness of installing add-on controls 

would be at least $593,750 per ton of VOC removed. 

The following has been proposed as BACT for VOC emissions from the proposed Dew Point 

Heater (EU-4):

The VOC emissions from the Dew Point Heater, identified as EU-3 shall not exceed 0.0053 

lb/MMBtu and 0.11 lbs/hr, based on a 3-hr average period through the use of good combustion and 

low NOx burners.

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 Dew Point Heater (EU-4).

The VOC emissions from the Dew Point Heater, identified as EU-3 shall not exceed 0.0053 

lb/MMBtu and 0.11 lbs/hr, based on a 3-hr average period through the use of good combustion and 

low NOx burners.

Nitrogen Oxide (NOx) BACT - Dew Point Heater EU-4

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)

Step 2: Eliminate Technically Infeasible Options

Add-on Control Technology:

NOx add-on controls including SCR and SNCR are not considered to be technically feasible for 

small natural gas fired heaters such as the dew point heater. These technologies would not be 

cost effective for small natural gas-fired heaters. Due to their small size and limited use, the 

emissions would not be significant and would result in excessive cost per ton removed of 

emissions. No such technology has ever been installed or demonstrated in practice for a small 

natural gas fired heater. Further, these technologies would unnecessarily increase emissions of 

NH3, a precursor to the atmospheric formation of the non-attainment pollutant PM2.5. This 

adverse environmental impact would render the use of SNCR or SCR as the BACT for the PM2.5

precursor NOx counterproductive to the goal of decreasing ambient levels of PM2.5.

Flue Gas Recirculation

Recirculating a portion of the flue gas to the combustion zone can lower the peak flame 

temperature and result in reduced thermal NOx production. The flue gas recirculation (FGR) can 

be highly effective technique for lowering NOx emissions from burners and it's relatively 

inexpensive to apply. Most of the early FGR work was done on boilers, and investigators found 

that recirculating up to 25% of the flue gases through the burner could lower NOx emissions to as 

little as 25% of their normal levels. FGR can lower NOx emissions in two ways: the cooled, 

relatively inert, recirculated flue gases act as heat sink, absorbing heat from the flame and 
IPL Eagle Valley generating Station TSD – Appendix B Page 88 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

lowering peak flame temperatures and when mixed with the combustion air, recirculated flue 

gases lower the average oxygen content of the air, starving the NOx-forming reaction for one of 

the ingredients they need.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of flue gas recirculation is a technically feasible option for the Dew Point Heater 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 Dew Point Heater 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 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 Dew 

Point Heater at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Natural gas firing with low NOx Burner with Flue Gas Recirculation (LNB/FGR) 

(2) Natural gas firing with low NOx Burner (LNB) 

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 IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permits.
IPL Eagle Valley generating Station TSD – Appendix B Page 89 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(MMBtu/hr)

Limitation Control Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Dew Point Heater 

(EU-4)

20.8 

MMBtu/hr

NOx: 0.032 

lb/MMBtu 

and 0.67 

pounds per 

hour, based 

on 3-hr 

average

Low NOx 

Burner with 

Flue Gas 

Recirculation

LA-0262

Cornerstone 

Chemical 

Company

05/03/2012 Acid Plant Air 

Preheater

86 

MMBtu/hr

2.96 lb/hr 

max, 0.034 

lb/MMBtu 

and

11.79 tpy

External FGR 

and low NOx

burners

AK-0071

Chugach 

Electric 

Association, 

Inc., 

International 

Station Power 

Plant

12/20/2010 Sigma Thermal 

Auxiliary Heater

12.5 

MMBtu/hr

32.0 

lb/MMscf, 3-

hr avg

Low NOx

burners and 

FGR

LA-0237

International 

Matex Tank 

Terminal

05/20/2010 Heaters (6)

37.80 

MMBtu/hr, 

each

0.036 lb/hr Low NOx

burners

WY-0066 Medicine Bow 

Fuel & Power 03/04/2009 Gasification Preheaters (5)

21 

MMBtu/hr 

(each)

0.05 

lb/MMBtu

Low NOx

burners

OK-0134

Pryor Plant 

Chemical 

Company

02/23/2009 Nitric Acid 

Preheaters No. 1

20 

MMBtu/hr

0.98 lb/hr, 

168-hr rolling 

average

Low NOx

burners

OK-0129

Associated 

Electric 

Cooperative, 

Inc. Chouteau 

Power Plant

01/23/2009 Fuel Gas Heater 18.8 

MMBtu/hr 2.7 lb/hr None

IA-0064 Roquette 

America 01/31/2003 Dew Point Heater 1.6 MMBtu/hr

0.15 

lb/MMBtu; 

0.24 lb/hr

None

IA-0058

Midamerican 

Energy, 

Greater Des 

Moines 

Energy Center

04/10/2002 Dew Point Heater NA

0.036 

lb/MMBtu; 

1.47 tpy

None

As shown in the above table, a limit of 0.032 lb/MMBtu which is the most stringent is consistent 

with the other limits contained in the RBLC.

The following has been proposed as BACT for NOx emissions from the proposed Dew Point 

Heater, identified as EU-4:

(1) The NOx emissions from the Dew Point Heater, identified as EU-4 shall be controlled 

by a Low NOx Burner with Flue Gas Recirculation.

(2) The NOx emissions shall be limited to less than 0.032 lb/MMBtu and 0.67 pounds per 

hour, based on a 3-hr average period.
IPL Eagle Valley generating Station TSD – Appendix B Page 90 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 Dew Point Heater, identified as EU-4:

(1) The NOx emissions from the Dew Point Heater, identified as EU-4 shall be controlled 

by a Low NOx Burner with Flue Gas Recirculation.

(2) The NOx emissions shall be limited to less than 0.032 lb/MMBtu and 0.67 pounds per 

hour, based on a 3-hr average period.

Particulate Matter (PM and PM10) BACT –Emergency Generator (EU-5)

Step 1: Identify Potential Control Technologies

Emissions of PM and PM10 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 and PM10 emissions are controlled through one of the following 

mechanisms:

(1) Catalyzed Diesel Particulate Filter (CDPF);

(2) Good Combustion Practices; and

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 technically 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 a technically feasible option for the 

Emergency Generator 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.
IPL Eagle Valley generating Station TSD – Appendix B Page 91 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 

Generator 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 Generator at this source.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM and PM10 BACT determination along with the existing 

PM and PM10 BACT determinations for emergency engines. All data in the table is based on the 

information obtained from the permit application submitted by IPL Eagle Valley Generating 

Station, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of 

permits available at the websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy Center

- proposed

Proposed Emergency 

Generator

EU-5

1,826

horsepower

PM and PM10:

0.15 g/bhp-hr

(0.2 g/kw-hr)

Combustion 

Design 

Controls 

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center 

12/03/2012 Emergency 

Diesel 

Generators 

EG01 & EG02

1,006 

horsepower, 

each

PM, PM10 and 

PM2.5: 0.15 

g/bhp-hr

Combustion 

Design 

Controls and 

Usage Limits

Emergency 

Generator 

EG03

2,012 

horsepower

FL-0323

Gainesville 

Regional Utility

Deerhaven, 

Renewable 

Energy Center

12/28/2010

Emergency 

Generator, 

fuel oil-fired

564 kw

0.2000 g/kw-H 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

FL-0322

Southeast 

Renewable 

Fuels, Sweet 

Sorghum-toEthanol 

Advanced 

Biorefinery

12/23/2010

Emergency 

Generators, 

fuel oil-fired

2,682 HP each

0.2000 g/kw-H 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

SD-0005

Basin Electric 

Power 

Cooperative, 

Deer Creek 

Station

06/29/2010 Emergency 

Generator 2,000 KW

Requirements of 

NSPS, Subpart 

IIII

None

ID-0018

Idaho Power 

Company, 

Langley Gulch 

Power Plant

06/25/2010

Emergency 

Generator 

Engine

750 KW

0.200 g/kw-hr, 

Tier 2 enginebasedNone
IPL Eagle Valley generating Station TSD – Appendix B Page 92 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

The proposed diesel-fired emergency generators will be subject to the NESHAP found at 40 CFR 

63 Subpart ZZZZ and the NSPS found at 40 CFR 60 Subpart IIII, which apply to stationary 

compression ignition reciprocating engines. The standards establish particulate limits and 

compliance with the limits is demonstrated by purchasing certified engines.

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed 

Emergency Generator:

The PM and PM10 emissions from the Emergency Generator, Identified as EU-5, shall not exceed 

0.15 g/hp-hr, through the use of combustion design 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 PM and PM10 for the Emergency Generator (EU-5).

The PM and PM10 emissions from the Emergency Generator, Identified as EU-5, shall not exceed 

0.15 g/hp-hr, through the use of combustion design control. 

Particulate Matter (PM2.5) BACT–Emergency Generator (EU-5)

Step 1: Identify Potential Control Technologies

Emissions of 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, PM2.5 emissions are controlled through one of the following mechanisms:

(1) Catalyzed Diesel Particulate Filter (CDPF);

(2) Good Combustion Practices; and

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 technically 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 a technically feasible option for the 

Emergency Generator 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 
IPL Eagle Valley generating Station TSD – Appendix B Page 93 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 

Generator 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 Generator at this source.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM2.5 BACT determination along with the existing PM2.5

BACT determinations for emergency engines. All data in the table is based on the information 

obtained from the permit application submitted by IPL Eagle Valley Generating Station, the U.S. 

EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at 

the websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy Center

- proposed

Proposed Emergency 

Generator

EU-5

1,826

horsepower

PM2.5: 0.15 

g/bhp-hr (0.2 

g/kw-hr)

Combustion 

Design 

Controls 

Draft Permit 

No. 141-

31003-

00579

Proposed

Limit

St. Joseph 

Energy Center 

- proposed

12/03/2012 Emergency 

Diesel 

Generators 

EG01 & EG02

1,006 

horsepower, 

each

PM, PM10 and 

PM2.5: 0.15 

g/bhp-hr

Combustion 

Design 

Controls and 

Usage Limits

Emergency 

Generator 

EG03

2,012 

horsepower

FL-0323

Gainesville 

Regional Utility 

Deerhaven, 

Renewable 

Energy Center

12/28/2010

Emergency 

Generator, 

fuel oil-fired

564 kw

0.2000 g/kw-H 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

FL-0322

Southeast 

Renewable 

Fuels, Sweet 

Sorghum-toEthanol 

Advanced 

Biorefinery

12/23/2010

Emergency 

Generators, 

fuel oil-fired

2,682 HP each

0.2000 g/kw-H 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

SD-0005

Basin Electric 

Power 

Cooperative, 

Deer Creek 

Station

06/29/2010 Emergency 

Generator 2,000 KW

Requirements of 

NSPS, Subpart 

IIII

None
IPL Eagle Valley generating Station TSD – Appendix B Page 94 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

ID-0018

Idaho Power 

Company, 

Langley Gulch 

Power Plant

06/25/2010

Emergency 

Generator 

Engine

750 KW

0.200 g/kw-hr, 

Tier 2 enginebasedNone

The proposed diesel-fired emergency generators will be subject to the NESHAP found at 40 CFR 

63 Subpart ZZZZ and the NSPS found at 40 CFR 60 Subpart IIII, which apply to stationary 

compression ignition reciprocating engines. The standards establish particulate limits and 

compliance with the limits is demonstrated by purchasing certified engines.

The following has been proposed as BACT for PM2.5 from the proposed Emergency Generator:

The PM2.5 emissions from the Emergency Generator, Identified as EU-5, shall not exceed 0.15 

g/hp-hr, through the use of combustion design 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 PM2.5 for the Emergency Generator (EU-5).

The PM2.5 emissions from the Emergency Generator, Identified as EU-5, shall not exceed 0.15 

g/hp-hr, through the use of combustion design control. 

Sulfuric Acid (H2SO4) BACT – Emergency Generator (EU-5)

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

Add-on Control Technology:

Add-on particulate control devices such as Flue Gas Desulfurization (FGD) System, Dry Sorbent 

Injection are not possible alternatives because the potential H2SO4 emissions from emergency 

engines are very minor, given their limited hours of operation. With such insignificant emissions, 

it would not be considered feasible to employ add-on control technologies to reduce 

H2SO4emissions from emergency engines. Additionally, since control technologies have not 
IPL Eagle Valley generating Station TSD – Appendix B Page 95 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

been implemented in practice to control emissions from emergency engines, there is no evidence 

that such measures would be technically feasible. 

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 emergency generator (EU-5)

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 emergency generator (EU-5). 

(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 IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Emergency 

Generator EU-5

1,826

horsepower

H2SO4:

sulfur 

content of 

15ppm

Ultra-low 

sulfur diesel 

fuel

MD-0040

Competitive 

Power 

Ventures, 

Inc., CPV 

St. Charles

11/12/2008

Diesel-fired 

Emergency 

Generator

1,500 KW

Exclusive use 

of ultra-low 

sulfur diesel 

with sulfur 

content not to 

exceed 15 

ppm

None

WI-0228

Wisconsin 

Public 

Service, 

Weston 

Plant

Diesel-fired 

Booster Pump 265 HP

0.0832 lb/hr, 

200 hr/12 

month rolling 

limit; 0.003 

wt% sulfur in 

diesel fuel

None

Main Fire Pump 460 HP

0.014 lb/hr, 

200 hr/12 

month rolling 

limit; 0.003 

wt% sulfur in 

diesel fuel

None
IPL Eagle Valley generating Station TSD – Appendix B Page 96 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

IDEM is proposing a weight percent (wt %) of sulfur in the diesel fuel of 0.75 gr S/100 scf which 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. 

The following has been proposed as BACT for H2SO4 emissions from the proposed emergency 

generator, identified as EU-5:

The H2SO4 emissions from the emergency generator, identified as EU-5 is proposed to be the 

use of ultra low S diesel fuel.

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 emergency generator (EU-5).

(1) The sulfur content of the fuel oil shall not exceed 15ppm. 

Carbon Monoxide (CO) BACT – Emergency Generator (EU-5)

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.

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. 
IPL Eagle Valley generating Station TSD – Appendix B Page 97 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 

Generator 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 

Generator 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 
IPL Eagle Valley generating Station TSD – Appendix B Page 98 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 Generator 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 Generator 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 

Generator 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 Emergency Generator 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 IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Emergency 

Generator EU-5

1,826

horsepower

CO: 2.6 

g/bhp-hr 

(3.5 g/kw-hr)

Combustion 

Design 

Controls 
IPL Eagle Valley generating Station TSD – Appendix B Page 99 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center 

12/03/2012 Emergency 

Diesel 

Generators EG01 

& EG02

1,006 

horsepower, 

each

CO: 2.6 g/bhphrCombustion 

Design 

Controls and 

Usage Limits

Emergency 

Generator EG03

2,012 

horsepower

SC-0113

Pyramax 

Ceramics, 

LLC

02/08/2012

Emergency 

Engines, dieselfired29 HP each

5.500 gr/kw-H 

(purchase of 

NSPS, 

Subpart IIII 

certified 

engine)

None

Emergency 

Generators, 

diesel-fired

757 HP each

3.500 gr/kw-H 

(purchase of 

NSPS, 

Subpart IIII 

certified 

engine)

None

FL-0323

Gainesville 

Regional 

Utility 

Deerhaven, 

Renewable 

Energy Center

12/28/2010

Emergency 

Generator, fuel 

oil-fired

564 kw

3.500 gr/kw-H 

(purchase of 

NSPS, 

Subpart IIII 

certified 

engine)

None

FL-0322

Southeast 

Renewable 

Fuels, Sweet 

Sorghum-toEthanol

Advanced 

Biorefinery

12/23/2010

Emergency 

Generators, fuel 

oil-fired

2,682 HP 

each

3.500 gr/kw-H 

(purchase of 

NSPS, 

Subpart IIII 

certified 

engine)

None

SD-0005

Basin Electric 

Power 

Cooperative, 

Deer Creek 

Station

06/29/2010 Emergency 

Generator 2,000 KW

Requirements 

of NSPS, 

Subpart IIII

None

ID-0018

Idaho Power 

Company, 

Langley Gulch 

Power Plant

06/25/2010 Emergency 

Generator Engine 750 KW

3.5 g/kw-hr, 

Tier 2 enginebased None

The proposed diesel-fired emergency generators will be subject to the NESHAP found at 40 CFR 

63 Subpart ZZZZ and the NSPS found at 40 CFR 60 Subpart IIII, which apply to stationary 

compression ignition reciprocating engines. The standards establish CO limits and compliance 

with the limits is demonstrated by purchasing certified engines.

The following has been proposed as BACT for CO emissions from the proposed Emergency 

Diesel Generators, Identified as EU-5:

The CO emissions from the Emergency Generators, Identified as EU-5 shall not exceed 2.6 g/hphr through the use of combustion design controls. 
IPL Eagle Valley generating Station TSD – Appendix B Page 100 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 Generator (EU-5).

The CO emissions from the Emergency Generators, Identified as EU-5 shall not exceed 2.6 g/hphr through the use of combustion design controls. 

Volatile Organic Compounds (VOCs) BACT - Emergency Generator (EU-5)

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.

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. 
IPL Eagle Valley generating Station TSD – Appendix B Page 101 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 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.

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. 
IPL Eagle Valley generating Station TSD – Appendix B Page 102 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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.

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 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 IPL Eagle Valley Generating Station, the U.S. 

EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at 

the websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Emergency 

Generator EU-5

1,826

horsepower

4.8 g/bhp-hr Combustion 

Design 

Controls 

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center 

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

SC-0113

Pyramax 

Ceramics, 

LLC

02/08/2012

Emergency 

Engines, dieselfired29 HP each

7.500 g/kw-H 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None
IPL Eagle Valley generating Station TSD – Appendix B Page 103 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

Emergency 

Generators, 

diesel-fired

757 HP 

each

4.000 g/kw-H 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

IA-0102

Alcoa, Inc. 

Davenport 

Works

02/01/2012 Emergency 

Generator

2115 cf/hr 

(225 kw) 0.66 lb/hr None

ID-0018

Idaho Power 

Company, 

Langley Gulch 

Power Plant

06/25/2010 Emergency 

Generator Engine 750 KW

6.4 g/kw-hr 

(NOx + 

NMHC), Tier 2 

engine-based 

None

As shown in the above table, the source has proposed a limit of 4.8 g/bhp-hr NOx + NMHC, 

which is equivalent to 0.011 lb/bhp-hr, which is consistent with the most stringent limits contained 

in the RBLC.

The following has been proposed as BACT for VOC emissions from the proposed Emergency 

Generator, Identified as EU-5:

The VOC emissions from the Emergency Generator shall be limited to less than 4.8 g/bhp-hr 

through the use of Combustion Design Controls. 

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 Generator (EU-5).

The VOC emissions from the Emergency Generator shall be limited to less than 4.8 g/bhp-hr 

through the use of Combustion Design Controls. 

Nitrogen Oxide (NOx) BACT - Emergency Generator (EU-5)

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); and

(c) Combustion Design Controls.

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.
IPL Eagle Valley generating Station TSD – Appendix B Page 104 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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.

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 the 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.
IPL Eagle Valley generating Station TSD – Appendix B Page 105 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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.

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 

BACT determinations for emergency pumps. All data in the table is based on the information 

obtained from the permit application submitted by IPL Eagle Valley Generating Station, the U.S. 

EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at 

the websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Emergency 

Generator EU-5

1,826

horsepower

NMNC + NOx:

4.8 g/bhp-hr 

Combustion 

Design 

Controls 

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center 

12/03/2012 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

SC-0113

Pyramax 

Ceramics, 

LLC

02/08/2012

Emergency 

Engines, dieselfired29 HP each

7.500 gr/kw-H 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

Emergency 

Generators, 

diesel-fired

757 HP 

each

4.000 gr/kw-H 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

LA-0251 Flopam, Inc.

04/26/2011 Large Diesel-fired 

Engines 

591 – 1,175 

hp

6.4000 g/kw-hr 

(NOx + NMHC); 

6.3200 lb/hr (591 

HP units); 

10.3600 lb/hr 

(1175 HP units) 

(LAER)

None

FL-0329 Shell 

Offshore, Inc.

11/28/2011 Standby 

Generator –

Deepwater 

Nautilus, dieselfired

NA 0.15 tpy

Use of turbo 

charger after 

cooler, intake 

air cooling
IPL Eagle Valley generating Station TSD – Appendix B Page 106 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

Emergency 

Generator – Bully NA 0.15 tpy

Use of EPA 

Tier 2 

engines with 

low NOx

engine 

design

FL-0323

Gainesville 

Regional 

Utility 

Deerhaven, 

Renewable 

Energy Center

12/28/2010

Emergency 

Generator, fuel 

oil-fired

564 kw

6.4000 gr/kw-H 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

FL-0322

Southeast 

Renewable 

Fuels, Sweet 

Sorghum-toEthanol 

Advanced 

Biorefinery

12/23/2010

Emergency 

Generators, fuel 

oil-fired

2,682 HP 

each

6.4000 gr/kw-H 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

SD-0005

Basin Electric 

Power 

Cooperative, 

Deer Creek 

Station

06/29/2010 Emergency 

Generator 2,000 KW

Requirements of 

NSPS, Subpart 

IIII

None

ID-0018

Idaho Power 

Company, 

Langley Gulch 

Power Plant

06/25/2010 Emergency 

Generator Engine 750 KW

6.4 g/kw-hr (NOx

+ NMHC), Tier 2 

engine-based 

None

CA-0988 Pacific Bell 02/01/2003 Emergency 

Generator 2,935 HP 6.9000 g/bhp-hr (LAER) None

CA-0998 Western 

Devcon 01/07/2003 Emergency Generator

415 HP 6.9000 g/bhp-hr 

(LAER) None

CA-0991

Cenic DBA 

UC Davis 

Communicatio

ns Resources

08/09/2002 Emergency 

Generator 277 HP 6.9000 g/bhp-hr (LAER) None

CA-0989

Folsom 

Surgical 

Center

05/01/2002 Emergency 

Generator 68 HP 6.9000 g/bhp-hr (LAER) 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, which is consistent with the most stringent limits contained in the RBLC.

The following has been proposed as BACT for NOx emissions from the proposed Emergency 

Generators, Identified as EU-5:

The NOx emissions from the Emergency Generator shall be limited to less than 4.8 g/bhp-hr for 

NMHC + NOx through the use of Combustion Design Controls. 

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 Generator (EU-5).
IPL Eagle Valley generating Station TSD – Appendix B Page 107 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

The NOx emissions from the Emergency Generator shall be limited to less than 4.8 g/bhp-hr for 

NMHC + NOx through the use of Combustion Design Controls. 

Particulate Matter (PM and PM10) BACT – Emergency Fire Pump (EU-6)

Step 1: Identify Potential Control Technologies

Emissions of PM and PM10 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 and PM10 emissions are controlled through one of the following 

mechanisms:

(1) Catalyzed Diesel Particulate Filter (CDPF); and

(2) 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

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 a technically 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 

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.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

1. Good Combustion Practices.
IPL Eagle Valley generating Station TSD – Appendix B Page 108 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 and PM10 BACT determination along with the existing 

PM and PM10 BACT determinations for emergency engines. All data in the table is based on the 

information obtained from the permit application submitted by IPL Eagle Valley Generating 

Station, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of 

permits available at the websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Emergency Fire 

Pump 

500

horsepower

PM and PM10:

0.15 g/bhp-hr

Combustion 

Design 

Controls 

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center 

12/03/2012 Firewater Pump 

Engines 

371 brake 

horsepower

PM, PM10 and 

PM2.5: 0.15 

g/bhp-hr

Combustion 

Design 

Controls and 

Usage Limits

FL-0323

Gainesville 

Regional 

Utility 

Deerhaven, 

Renewable 

Energy Center

12/28/2010 Emergency 

Diesel Fire Pump 275 hp

0.1500 g/hp-hr 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

FL-0322

Southeast 

Renewable 

Fuels, Sweet 

Sorghum-toEthanol 

Advanced 

Biorefinery

12/23/2010 Emergency 

Diesel Fire Pump NA

0.1500 g/hp-hr 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

FL-0324

Solid Waste 

Authority of 

Palm Beach 

County, Palm 

Beach 

Renewable 

Energy Park

12/23/2010 Emergency 

Diesel Fire Pump 250 HP

0.1500 g/hp-hr 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

SD-0005

Basin Electric 

Power 

Cooperative, 

Deer Creek 

Station

06/29/2010 Diesel Fire Water 

Pump 577 HP

Requirements of 

NSPS, Subpart 

IIII

None

ID-0018

Idaho Power 

Co., Langley 

Gulch Power 

Plant

06/25/2010 Diesel Fire Pump 

Engine 235 KW

0.2000 g/kw-hr 

(Tier 3 enginebased) [converts 

to 0.15 g/hp-hr]

None

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.
IPL Eagle Valley generating Station TSD – Appendix B Page 109 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

The following has been proposed as BACT for PM and PM10 from the proposed Emergency Fire 

Pump Engines:

(1) The PM and PM10 emissions from the Emergency Fire Pump Engine shall not exceed

0.15 g/hp-hr through the use of combustion design 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 PM and PM10 for the Fire Pump Engine (EU-6).

(1) The PM and PM10 emissions from the Emergency Fire Pump Engine shall not exceed

0.15 g/hp-hr through the use of combustion design control. 

Particulate Matter (PM2.5) BACT – Emergency Fire Pump (EU-6)

Step 1: Identify Potential Control Technologies

Emissions of 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, PM2.5 emissions are controlled through one of the following mechanisms:

(1) Catalyzed Diesel Particulate Filter (CDPF); and

(2) 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

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 technically 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 a technically 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 

combustion. This type of emission control is included in RBLC for the control of particulate

emissions from fire pump and emergency engines.
IPL Eagle Valley generating Station TSD – Appendix B Page 110 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

1. Good Combustion Practices.

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 PM2.5 BACT determination along with the existing PM2.5

BACT determinations for emergency engines. All data in the table is based on the information 

obtained from the permit application submitted by IPL Eagle Valley Generating Station, the U.S. 

EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at 

the websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Emergency Fire 

Pump 

500

horsepower

PM2.5: 0.15 

g/bhp-hr

Combustion 

Design 

Controls 

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center 

- proposed

12/03/2012 Firewater Pump 

Engines 

371 brake 

horsepower

PM, PM10 and 

PM2.5: 0.15 

g/bhp-hr

Combustion 

Design 

Controls and 

Usage Limits

FL-0323

Gainesville 

Regional 

Utility 

Deerhaven, 

Renewable 

Energy Center

12/28/2010 Emergency 

Diesel Fire Pump 275 hp

0.1500 g/hp-hr 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

FL-0322

Southeast 

Renewable 

Fuels, Sweet 

Sorghum-toEthanol 

Advanced 

Biorefinery

12/23/2010 Emergency 

Diesel Fire Pump NA

0.1500 g/hp-hr 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

FL-0324

Solid Waste 

Authority of 

Palm Beach 

County, Palm 

Beach 

Renewable 

Energy Park

12/23/2010 Emergency 

Diesel Fire Pump 250 HP

0.1500 g/hp-hr 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

SD-0005

Basin Electric 

Power 

Cooperative, 

06/29/2010 Diesel Fire Water 

Pump 577 HP

Requirements of 

NSPS, Subpart 

IIII

None
IPL Eagle Valley generating Station TSD – Appendix B Page 111 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

Deer Creek 

Station

ID-0018

Idaho Power 

Co., Langley 

Gulch Power 

Plant

06/25/2010 Diesel Fire Pump 

Engine 235 KW

0.2000 g/kw-hr 

(Tier 3 enginebased) [converts 

to 0.15 g/hp-hr]

None

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.

The following has been proposed as BACT for PM2.5 from the proposed Emergency Fire Pump 

Engine:

The PM2.5 emissions from the Emergency Fire Pump Engine shall not exceed 0.15 g/hp-hr 

through the use of combustion design 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 PM2.5 for the Fire Pump Engine (EU-6).

The PM2.5 emissions from the Emergency Fire Pump Engine shall not exceed 0.15 g/hp-hr 

through the use of combustion design control. 

Sulfuric Acid (H2SO4) BACT – Emergency Fire Pump (EU-6)

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

Add-on Control Technology:

Add-on particulate control devices such as Flue Gas Desulfurization (FGD) System, Dry Sorbent 

Injection are not possible alternatives because the potential H2SO4 emissions from emergency 

engines are very minor, given their limited hours of operation. With such insignificant emissions, 

it would not be considered feasible to employ add-on control technologies to reduce 

H2SO4emissions from emergency engines. Additionally, since control technologies have not 
IPL Eagle Valley generating Station TSD – Appendix B Page 112 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

been implemented in practice to control emissions from emergency engines, there is no evidence 

that such measures would be technically feasible. 

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 Emergency Fire pump.

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 Fire pump (EU-6)

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 (EU-6). 

(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 IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Emergency 

Fire Pump 

500

horsepower

H2SO4:

sulfur 

content of 15 

ppm

Ultra-low 

sulfur diesel 

fuel

MD-0040

Competitive 

Power Ventures, 

Inc., CPV St. 

Charles

11/12/2008

Diesel-fired 

Emergency 

Generator

1,500 KW

Exclusive 

use of ultralow sulfur 

diesel with 

sulfur 

content not

to exceed 

15 ppm

None

WI-0228

Wisconsin 

Public Service, 

Weston Plant

10/19/2004

Diesel-fired 

Booster Pump 265 HP

0.0832 lb/hr, 

200 hr/12 

month 

rolling limit; 

0.003 wt% 

sulfur in 

diesel fuel

None

Main Fire 

Pump 460 HP

0.014 lb/hr, 

200 hr/12 

month 

rolling limit; 

0.003 wt% 

sulfur in 

None
IPL Eagle Valley generating Station TSD – Appendix B Page 113 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

diesel fuel

IDEM is proposing a Ultra-low sulfur diesel fuel of 0.75 gr S/100 scf which is the most stringent 

limit for H2SO4 emissions. Note that H2SO4 emissions depend on the sulfur content of the fuel 

available to the facility. The proposed facility will have access to fuel from a single supplier for 

the region, and will not have the option to receive fuel from any other source or require the 

supplier to provide lower sulfur content fuel. 

The following has been proposed as BACT for H2SO4 emissions from the proposed Emergency 

Fire pump, identified as EU-6:

(a) The sulfur content for the fuel oil shall not exceed 15ppm. 

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 Emergency Fire Pump Engine (EU-6).

(a) The sulfur content for the fuel oil shall not exceed 15ppm. 

Carbon Monoxide (CO) BACT – Emergency Fire Pump (EU-6)

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.

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, 
IPL Eagle Valley generating Station TSD – Appendix B Page 114 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 

Fire pump Engine 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 

Fire pump Engine 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.
IPL Eagle Valley generating Station TSD – Appendix B Page 115 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 Fire pump Engine

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 Fire pump Engine 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 Fire 

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 shall be used to reduce the CO emissions from the 

Emergency Fire pump Engine 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 IPL Eagle Valley Generating Station, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-

IPL Eagle 

Valley 

Generating 

Proposed Emergency Fire 

Pump 

500

horsepower

CO:

2.6 g/bhp-hr

(3.5 g/kw-hr)

Combustion 

Design

Controls 
IPL Eagle Valley generating Station TSD – Appendix B Page 116 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

00004

Proposed

Limit

Station

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center 

12/03/2012 Firewater Pump 

Engines 

371 brake 

horsepower

CO: 2.6 g/bhphrCombustion 

Design 

Controls and 

Usage Limits

SC-0113

Pyramax 

Ceramics, 

LLC

02/08/2012 Fire Pump, 

diesel-fired 500 hp

3.500 gr/kw-H 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

FL-0323

Gainesville 

Regional 

Utility 

Deerhaven, 

Renewable 

Energy Center

12/28/2010 Emergency 

Diesel Fire Pump 275 hp

2.6 g/hp-hr 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

FL-0322

Southeast 

Renewable 

Fuels, Sweet 

Sorghum-toEthanol 

Advanced 

Biorefinery

12/23/2010 Emergency 

Diesel Fire Pump NA

2.6 g/hp-hr 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

FL-0324

Solid Waste 

Authority of 

Palm Beach 

County, Palm 

Beach 

Renewable 

Energy Park

12/23/2010 Emergency 

Diesel Fire Pump 250 HP

2.6 g/hp-hr 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

SD-0005

Basin Electric 

Power 

Cooperative, 

Deer Creek 

Station

06/29/2010 Diesel Fire Water 

Pump 577 HP

Requirements 

of NSPS, 

Subpart IIII

None

ID-0018

Idaho Power 

Company, 

Langley Gulch 

Power Plant

06/25/2010 Diesel Fire Pump 

Engine 235 KW

No emission 

limits are 

available; Tier 

3 engine-based

None

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.

The following has been proposed as BACT for CO emissions from the proposed Emergency Fire 

pump Engine:

(1) The CO emissions from the Emergency Fire Pump Engine shall not exceed 2.6 g/hp-hr 

through the use of combustion design controls. 
IPL Eagle Valley generating Station TSD – Appendix B Page 117 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 Engine (EU-6).

(1) The CO emissions from the Emergency Fire pump Engine shall not exceed 2.6 g/hp-hr 

through the use of combustion design controls. 

Volatile Organic Compounds (VOCs) BACT - Emergency Fire Pump (EU-6)

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.

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. 
IPL Eagle Valley generating Station TSD – Appendix B Page 118 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 Emergency 

Fire pump Engine 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 

Fire pump Engine 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 Fire pump Engine

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 
IPL Eagle Valley generating Station TSD – Appendix B Page 119 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 Fire pump Engine 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 Emergency Fire 

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 shall be used to reduce the VOC emissions from the 

Emergency Fire Pump Engine 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 IPL Eagle Valley Generating Station, the U.S. 

EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at 

the websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Emergency Fire 

Pump 

500

horsepower

VOC: 3.0 

g/bhp-hr

Combustion 

Design 

Controls and 

Usage Limits

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center 

- proposed

12/03/2012 Firewater Pump 

Engines

371 brake 

horsepower

VOC: 0.16 

lbs/hr

Combustion 

Design 

Controls and 

Usage Limits

SC-0113

Pyramax 

Ceramics, 

LLC

02/08/2012 Fire Pump, 

diesel-fired 500 hp

4.000 g/kw-H 

(purchase of 

NSPS certified 

engine)

None

ID-0018

Idaho Power 

Co., Langley 

Gulch Power 

06/25/2010 Diesel Fire Pump 

Engine 235 KW

4.000 g/kw-hr 

(NOx + 

NMHC), Tier 3 

None
IPL Eagle Valley generating Station TSD – Appendix B Page 120 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control 

Method

Plant engine-based 

As shown in the above table, a limit of 3.0 g/bhp-hr which is the most stringent is consistent with 

the other limits contained in the RBLC.

The following has been proposed as BACT for VOC emissions from the proposed Emergency 

Fire pump Engine:

The VOC emissions from the Emergency Fire Pump Engine shall not exceed 3.0 g/bhp-hr

through the use of Combustion Design 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 Fire Pump Engine (EU-6).

The VOC emissions from the Emergency Fire pump Engine shall not exceed 3.0 g/bhp-hr

through the use of Combustion Design Control. 

Nitrogen Oxide (NOx) BACT - Emergency Fire Pump (EU-6)

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); and

(c) Combustion Design Controls.

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.

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.
IPL Eagle Valley generating Station TSD – Appendix B Page 121 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 Fire 

Pump Engine 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 Emergency 

Fire Pump Engine 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 Fire 

Pump Engine at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

1. Good Combustion Controls.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of combustion design control shall be used to reduce the NOx emissions from the 

Emergency Fire Pump Engine at this source.
IPL Eagle Valley generating Station TSD – Appendix B Page 122 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 IPL Eagle Valley Generating Station, the U.S. 

EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at 

the websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(HP or KW)

Limitation Control Method

Draft Permit 

No. 109-

32471-00004

Proposed

Limit

IPL Eagle 

Valley 

Generating

Station

Proposed Emergency 

Fire Pump 

500

horsepower

NMNC + : NOx 

3.0 g/bhp-hr 

Combustion 

Design 

Controls 

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center -

proposed

12/03/2012 Firewater 

Pump Engines

371 brake 

horsepower

NOx + NMNC: 

3.0 g/bhp-hr 

Combustion 

Design 

Controls and 

Usage Limits

SC-0113 Pyramax 

Ceramics, LLC 02/08/2012 Fire Pump, diesel-fired 500 hp

4.0 g/kw-H 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

LA-0251 Flopam, Inc. 04/26/2011 Large Dieselfired Engines 

591 – 1,175

hp

6.4000 g/kw-hr 

(NOx + 

NMHC); 6.3200 

lb/hr (591 HP 

units); 10.3600 

lb/hr (1175 HP 

units) (LAER)

None

FL-0323

Gainesville 

Regional Utility 

Deerhaven, 

Renewable 

Energy Center

12/28/2010

Emergency 

Diesel Fire 

Pump

275 hp

3.000 g/hp-hr 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

FL-0322

Southeast 

Renewable 

Fuels, Sweet 

Sorghum-toEthanol 

Advanced 

Biorefinery

12/23/2010

Emergency 

Diesel Fire 

Pump

NA

3.000 g/hp-hr 

(purchase of 

NSPS, Subpart 

IIII certified 

engine)

None

SD-0005

Basin Electric 

Power

Cooperative, 

Deer Creek 

Station

06/29/2010 Diesel Fire 

Water Pump 577 HP

Requirements 

of NSPS, 

Subpart IIII

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.

The following has been proposed as BACT for NOx emissions from the proposed Fire Pump 

Engines:
IPL Eagle Valley generating Station TSD – Appendix B Page 123 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

(1) The NOx emissions from the Emergency Fire Pump Engine shall not exceed 3.0 g/bhp-hr 

for NMHC + NOx through the use of Combustion Design Controls. 

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 Engine (EU-6).

(1) The NOx emissions from the Emergency Fire Pump Engine shall not exceed 3.0 g/bhp-hr 

for NMHC + NOx through the use of Combustion Design Controls. 

Particulate Matter (PM and PM10) BACT – Cooling Tower EU-7

Step 1: Identify Potential Control Technologies

Emissions of Particulate Matter (PM and PM10) from cooling towers are generally controlled by:

(1) Drift (Mist) eliminator system. 

(2) Reducing TDS

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 and PM10 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 Tower at this 

source.

Reducing TDS

Particulate emissions are related to the level of Total Dissolved Solids (TDS) in the cooling water. 

The level of TDS is a function of the source water, and the recycle rate. The TDS level in the 

source water can be reduced by use of reverse osmosis. The amount of cooling water recycled 

is a function of the overall volume capacity of the water withdrawal system. Maximizing the 

recycling of the cooling water will also reduce the amount of water resources utilized and would 

also reduce the overall mass loading of the cooling water blow-down discharged to the river. 
IPL Eagle Valley generating Station TSD – Appendix B Page 124 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Reducing TDS 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) Reducing TDS

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 and PM10 BACT determination along with the existing 

PM and PM10 BACT determinations for cooling towers. All data in the table is based on the 

information obtained from the permit application submitted by IPL Eagle Valley Generating 

Station, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of 

permits available at the websites of other permitting agencies and IDEM's PSD Permits.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(gpm)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Cooling Tower

(U-7)

192,000 

gpm

0.0005% and 

TDS ≤ 5000mg/L

Drift 

Eliminator 

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center 

- proposed

12/03/2012 Cooling Towers 

(CT01 and CT02) 

170,000 

gpm 

0.0005% Drift 

Eliminator 

LA-0254

Entergy 

Louisiana, 

LLC, Ninemile 

Point Electric 

Generating 

Plant

12/12/2011

Chiller Cooling 

Tower

12,000 

gpm

PM10/PM2.5: 

0.0010 % drift, 

annual average

High 

efficiency 

mist 

eliminator

Unit 6 Cooling 

Tower

115,847 

gpm

PM10/PM2.5: 

0.0005% drift, 

annual average

High 

efficiency 

mist 

eliminator

WI-0252

Specialty 

Minerals, Inc. 

– Superior

07/22/2011

Cooling Towers 

P40, P50

700 gpm 

each

PM10/PM2.5: 

0.0005% 

circulation drift

High 

efficiency 

drift / mist 

eliminator

Cooling Tower P60 200 gpm

PM10/PM2.5: 

0.0005% 

circulation drift; 

Dissolved Solids 

Limit of 1000 

ppm; PM2.5 is not 

more than 42% of 

total PM

High 

efficiency 

drift / mist 

eliminator

LA-0251 Flopam, Inc. 04/26/2011 Cooling Towers (10 3,640 gpm PM10: 0.01 lb/hr; None
IPL Eagle Valley generating Station TSD – Appendix B Page 125 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(gpm)

Limitation Control 

Method

Facility units) 0.01 tpy

LA-0246

Valero 

Refining –

New Orleans, 

LLC, St. 

Charles 

Refinery

12/31/2010 Cooling Towers

45,000 

gpm -

61,250 

gpm

PM10: 0.08 - 1.2 

lb/hr

Drift 

eliminators

LA-0248

Consolidated 

Environmental 

Management, 

Inc. Nucor / 

Direct 

Reduction Iron 

Plant

01/27/2011 DRI 113 & 213: 

Units #1 and 2 

Process Water 

Cooling Tower

26,857 

gpm

PM10: TDS </= 

1000 mg/L; Max 

drift of 0.0005%

Drift 

eliminators 

DRI 114 & 214: 

Unit #1 Clean 

Water Cooling 

Tower

17,611 

gpm

PM10: TDS </= 

1000 mg/L; Max 

drift of 0.0005%

Drift 

eliminators 

LA-0246

Valero 

Refining –

New Orleans, 

LLC, St. 

Charles 

Refinery

12/31/2010 Cooling Towers

45,000 

gpm -

61,250 

gpm

PM10: 0.08 - 1.2 

lb/hr

Drift 

eliminators

GA-0142 Osceola Steel 

Co. 12/29/2010

Cooling Towers 

CT1, CT21, CT22, 

and CT23

NA

PM10: 0.0005% 

mass flow rate; 

1000 mg/L

Drift 

eliminators

FL-0323

Gainesville 

Regional 

Utility (GRU) 

Deerhaven

12/28/2010 Mechanical Draft 

Cooling Tower

78,000 

gpm

PM10: 0.0005% 

max drift

Drift 

eliminators

OH-0341 Nucor Steel 

Marion, Inc. 12/23/2010 Cooling Tower NA PM: 0.005% drift rate

Drift 

eliminators

NH-0018 Laidlaw Berlin

Biopower, LLC 07/26/2010 Wet Cooling Tower 60,000 gpm

PM: 0.0005% 

drift rate

Drift 

eliminators

ID-0018

Idaho Power 

Company, 

Langley Gulch 

Power Plant

06/25/2010 Cooling Tower 63,200 

gpm

NA Drift 

eliminators

LA-0239

Consolidated 

Environmental 

Mgmt, Inc.

Nucor Steel 

Louisiana

05/24/2010

Blast Furnace 

Cooling Tower, Iron 

Solidification 

Cooling Tower & 

Air Separation 

Plant Cooling 

Tower

NA

PM: TDS </= 

1000 mg/L; Max 

drift of 0.0005%

Drift 

eliminators 

TX-0552

Stark Power 

Generation II 

Holdings, LLC, 

Wolf Hollow 

Power Plant

03/03/2010 Cooling Tower NA PM: 0.0005% 

drift rate

Drift 

eliminators 

TX-0551

Panda 

Sherman 

Power Station

02/03/2010 Cooling Tower NA PM: 0.0005% 

drift rate

Drift 

eliminators 
IPL Eagle Valley generating Station TSD – Appendix B Page 126 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(gpm)

Limitation Control 

Method

TX-0553

Lindale 

Renewable 

Energy, LLC

01/08/2010 Cooling Tower NA PM: 0.0005% 

drift rate

Drift 

eliminators 

NV-0050 MGM Mirage 11/30/2009 Cooling Towers 10,890 

gpm

PM10: 0.001% 

drift rate and TSD 

concentration is 

limited to 3,600 

ppm

Drift 

eliminators

The TDS requirements in cooling towers are very case specific due to available water supplies 

(quality and quantity), costs of equipment, size and use of cooling towers, site development 

limitations, and regulations governing water use. Te source is proposing to install cooling towers 

utilizing existing water wells to avoid impacts to the White River through installation of a new 

cooling water intake structure. By utilizing the well water, we start at higher values of TDS in the 

source water compared to the River. By relaxing the TDS limit in the air permit, this allows the 

source to use less water from the wells, and reduce impacts to the White River in the discharge.

This occurs because less water is used and consequentially, there is less mass of dissolved 

material that subsequently requires discharge to the river.

Finally, managing TDS to lower levels than the proposed 5,000 mg/L would be extremely 

ineffective as a way to control particulate from the source. For example, PM2.5 from the cooling 

towers at 5000 mg/L assuming 8760 annual hours of operation yields 0.022 tpy while running at 

1000 mg/L would yield 0.004 tpy, a difference of 0.018 tpy.

The following has been proposed as BACT for PM and PM10 emissions from the proposed 

Cooling Tower (U-7):

Therefore, a 0.0005% drift (mist) eliminator system is proposed as BACT for PM and PM10

emissions from the Cooling Towers, identified as U-7. 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD)), IDEM, OAQ has 

approved the proposed PM and PM10 BACT for the Cooling Tower, identified as U-7. 

(a) The PM and PM10 emissions from the Cooling Tower, identified as U-7 shall be controlled 

by High efficiency drift eliminators designed with a drift loss rate of less than 0.0005%

and maximum total dissolved solids (TDS) shall be less than 5000 mg/L.

(b) The PM and PM10 emissions from the Cooling Tower shall be less than 2.4 and 1.5 

pounds per hour, respectively.

Particulate Matter (PM2.5) BACT – Cooling Tower U-7

Step 1: Identify Potential Control Technologies

Emissions of Particulate Matter (PM2.5) from cooling towers are generally controlled by:

(1) Drift (Mist) eliminator system. 

(2) Reducing TDS
IPL Eagle Valley generating Station TSD – Appendix B Page 127 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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 PM2.5 emissions from the Cooling Towers.

Drift Eliminator System

Cooling towers are a source of particulate matter (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 (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 Tower at this 

source.

Reducing TDS

Particulate emissions are related to the level of Total Dissolved Solids (TDS) in the cooling water. 

The level of TDS is a function of the source water, and the recycle rate. The TDS level in the 

source water can be reduced by use of reverse osmosis. The amount of cooling water recycled 

is a function of the overall volume capacity of the water withdrawal system. Maximizing the 

recycling of the cooling water will also reduce the amount of water resources utilized and would 

also reduce the overall mass loading of the cooling water blow-down discharged to the river. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Reducing dissolved solids 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) Reducing TDS

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 PM2.5 BACT determination along with the existing PM2.5

BACT determinations for cooling towers. All data in the table is based on the information 

obtained from the permit application submitted by IPL Eagle Valley Generating Station, the U.S. 

EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at 

the websites of other permitting agencies and IDEM's PSD Permits.
IPL Eagle Valley generating Station TSD – Appendix B Page 128 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(gpm)

Limitation Control 

Method

Draft Permit 

No. 109-

32471-

00004

Proposed

Limit

IPL Eagle 

Valley 

Generating 

Station

Proposed Cooling Tower

(U-7)

192,000 

gpm

0.0005% and 

TDS ≤ 5000ppm

Drift 

Eliminator 

Permit No. 

141-31003-

00579

St. Joseph 

Energy Center 

- proposed

12/03/2012 Cooling Towers 

(CT01 and CT02) 

170,000 

gpm 

0.0005% Drift 

Eliminator 

LA-0254

Entergy 

Louisiana, 

LLC, Ninemile 

Point Electric 

Generating 

Plant

12/12/2011

Chiller Cooling 

Tower

12,000 

gpm

PM10/PM2.5: 

0.0010 % drift, 

annual average

High 

efficiency 

mist 

eliminator

Unit 6 Cooling 

Tower

115,847 

gpm

PM10/PM2.5: 

0.0005% drift, 

annual average

High 

efficiency 

mist 

eliminator

WI-0252

Specialty 

Minerals, Inc. 

– Superior

07/22/2011

Cooling Towers 

P40, P50

700 gpm 

each

PM10/PM2.5: 

0.0005% 

circulation drift

High 

efficiency 

drift / mist 

eliminator

Cooling Tower P60 200 gpm

PM10/PM2.5: 

0.0005% 

circulation drift; 

Dissolved Solids 

Limit of 1000 

ppm; PM2.5 is not 

more than 42% of 

total PM

High 

efficiency 

drift / mist 

eliminator

LA-0251 Flopam, Inc. 

Facility 04/26/2011 Cooling Towers (10 units) 3,640 gpm PM10: 0.01 lb/hr; 0.01 tpy None

LA-0246

Valero 

Refining –

New Orleans, 

LLC, St. 

Charles 

Refinery

12/31/2010 Cooling Towers

45,000 

gpm -

61,250 

gpm

PM10: 0.08 - 1.2 

lb/hr

Drift 

eliminators

LA-0248

Consolidated 

Environmental 

Management, 

Inc. Nucor / 

Direct 

Reduction Iron 

Plant

01/27/2011 DRI 113 & 213: 

Units #1 and 2 

Process Water 

Cooling Tower

26,857 

gpm

PM10: TDS </= 

1000 mg/L; Max 

drift of 0.0005%

Drift 

eliminators 

DRI 114 & 214: 

Unit #1 Clean 

Water Cooling 

Tower

17,611 

gpm

PM10: TDS </= 

1000 mg/L; Max 

drift of 0.0005%

Drift 

eliminators 

LA-0246

Valero 

Refining –

New Orleans, 

LLC, St. 

Charles 

Refinery

12/31/2010 Cooling Towers

45,000 

gpm -

61,250 

gpm

PM10: 0.08 - 1.2 

lb/hr

Drift 

eliminators
IPL Eagle Valley generating Station TSD – Appendix B Page 129 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(gpm)

Limitation Control 

Method

GA-0142 Osceola Steel 

Co. 12/29/2010

Cooling Towers 

CT1, CT21, CT22, 

and CT23

NA

PM10: 0.0005% 

mass flow rate; 

1000 mg/L

Drift 

eliminators

FL-0323

Gainesville 

Regional 

Utility (GRU) 

Deerhaven

12/28/2010 Mechanical Draft 

Cooling Tower

78,000 

gpm

PM10: 0.0005% 

max drift

Drift 

eliminators

OH-0341 Nucor Steel 

Marion, Inc. 12/23/2010 Cooling Tower NA PM: 0.005% drift rate

Drift 

eliminators

NH-0018 Laidlaw Berlin 

Biopower, LLC 07/26/2010 Wet Cooling Tower 60,000 gpm

PM: 0.0005% 

drift rate

Drift 

eliminators

ID-0018

Idaho Power 

Company, 

Langley Gulch 

Power Plant

06/25/2010 Cooling Tower 63,200 

gpm

NA Drift 

eliminators

LA-0239

Consolidated 

Environmental 

Mgmt, Inc. 

Nucor Steel 

Louisiana

05/24/2010

Blast Furnace 

Cooling Tower, Iron 

Solidification 

Cooling Tower & 

Air Separation 

Plant Cooling 

Tower

NA

PM: TDS </= 

1000 mg/L; Max 

drift of 0.0005%

Drift 

eliminators 

TX-0552

Stark Power 

Generation II 

Holdings, LLC, 

Wolf Hollow 

Power Plant

03/03/2010 Cooling Tower NA PM: 0.0005% 

drift rate

Drift 

eliminators 

TX-0551

Panda 

Sherman 

Power Station

02/03/2010 Cooling Tower NA PM: 0.0005% 

drift rate

Drift 

eliminators 

TX-0553

Lindale 

Renewable 

Energy, LLC

01/08/2010 Cooling Tower NA PM: 0.0005% 

drift rate

Drift 

eliminators 

NV-0050 MGM Mirage 11/30/2009 Cooling Towers 10,890 

gpm

PM10: 0.001% 

drift rate and TSD 

concentration is 

limited to 3,600 

ppm

Drift 

eliminators

The TDS requirements in cooling towers are very case specific due to available water supplies 

(quality and quantity), costs of equipment, size and use of cooling towers, site development 

limitations, and regulations governing water use. Te source is proposing to install cooling towers 

utilizing existing water wells to avoid impacts to the White River through installation of a new 

cooling water intake structure. By utilizing the well water, we start at higher values of TDS in the 

source water compared to the River. By relaxing the TDS limit in the air permit, this allows the 

source to use less water from the wells, and reduce impacts to the White River in the discharge.

This occurs because less water is used and consequentially, there is less mass of dissolved 

material that subsequently requires discharge to the river.

Finally, managing TDS to lower levels than the proposed 5,000 mg/L would be extremely 

ineffective as a way to control particulate from the source. For example, PM2.5 from the cooling 

towers at 5000 mg/L assuming 8760 annual hours of operation yields 0.022 tpy while running at 

1000 mg/L would yield 0.004 tpy, a difference of 0.018 tpy.
IPL Eagle Valley generating Station TSD – Appendix B Page 130 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

The following has been proposed as BACT for PM2.5 emissions from the proposed Cooling Tower 

(U-7):

Therefore, a 0.0005% drift (mist) eliminator system is proposed as BACT for PM2.5 emissions 

from the Cooling Towers, identified as U-7.

 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD)), IDEM, OAQ has 

approved the proposed PM2.5 BACT for the Cooling Tower, identified as U-7. 

(a) The PM2.5 emissions from the Cooling Tower, identified as U-7 shall be controlled by 

High efficiency drift eliminators designed with a drift loss rate of less than 0.0005% and 

maximum total dissolved solids (TDS) shall be less than or equal to 5000 mg/L.

(b) The PM2.5 emissions from the Cooling Tower shall be less than 0.005 pounds per hour.

PM, PM10 and PM2.5 BACT– Turbine Lube Oil Demister Vents 

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.

 
IPL Eagle Valley generating Station TSD – Appendix B Page 131 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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

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 IPL Eagle Valley 

Generating Station, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic 

versions of permits available at the websites of other permitting agencies and IDEM's PSD 

Permits.

BACT ID or Permit 

#

Facility Issued Date Process 

Description

Rating Limitation Control Method

Draft Permit No. 

109-32471-00004

Proposed Limit

IPL Eagle Valley 

Generating 

Station

Proposed Turbine Lube 

Oil Demister 

Vent

-- None Good Design 

and Operating 

Practices

TX-0453 Bayport Energy 

Center LP 10/20/2003 Lube Oil Vent NA 0.1 lb/hr; 0.2 tpy None

TX-0374

BP Amoco 

Chemical Co., 

Chocolate Bayou 

Plant

03/24/2003

GT Lube Oil 

Vent for 

Cogen Trains 

2 & 3

NA

0.05 lb/hr, 

each;

0.22 tpy, 

each

None

Proposal: IPL Eagle Valley Generating Station – Martinsville, Indiana

The following has been proposed as BACT for organic PM (PM10 and PM2.5) emissions from the 

proposed Turbine Lube Oil Demister Vents:

The organic PM (PM10 and PM2.5) emissions from the Turbine Lube Oil Demister Vents 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 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 shall be 

the use of good design and operating practices. 

GHGs BACT – Combined Cycle Combustion Turbines EU-1 - EU-2

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 (CO2e). 

(1) Carbon Capture and Storage (CCS); 

(2) High Thermal Efficiency System Design;
IPL Eagle Valley generating Station TSD – Appendix B Page 132 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

(3) Use of low carbon emitting fuel; and

(4) Good combustion Turbine Design.

Step 2: Eliminate Technically Infeasible Options

Carbon Capture and Storage (CCS)

CCS consists of three (3) distinct unit operations: the separation and capture of CO2 from the flue 

gas, pressurization of the captured CO2 and transportation of the CO2 as a fluid via pipeline, and 

injection and long-term storage (usually geologic).

(1) Capture and Separation

The capture technologies applicable for fossil fuel combustion include the following:

(i) Pre-combustion systems designed to separate CO2 and hydrogen in the high 

pressure syngas typically produced at coal integrated gasification combined 

cycle power plants.

(ii) Post-combustion systems designed to separate CO2 from the flue gas produced 

by the combustion process.

(iii) Oxy-combustion systems that use high-purity oxygen rather than air in the 

combustion process to produce a highly concentrated CO2 stream.

Pre-combustion systems are not applicable to this facility, since they would fundamentally 

redefine the nature of the proposed source (natural gas as opposed to a coal IGCC plant). Both 

post- and oxy-combustion systems could be considered available, and both are currently in 

development as demonstration projects at coal-fired power plants using amine and ammonia 

capture systems to remove the CO2 from the flue gas. These capture systems are associated 

with very high energy penalties and still considered to be innovative and not yet commercially 

available for this source.

There are several technologies at various stages of development with the potential to separate 

and capture CO2. Some have been demonstrated at the pilot scale, while others are at the 

bench-top or laboratory stage of development. Most of the existing applications, and those in the 

planning stage, are designed to control CO2 from the combustion of fossil fuels, primarily coal 

and natural gas. US EPA considers municipal solid waste to be a solid biomass fuel that can be

co-fired with fossil fuels to reduce the CO2 emissions from boilers (EPA, 2010). Several 

demonstration projects are being supported through the U.S. Department of Energy’s Clean Coal 

Power Initiative, but these facilities will exclusively burn coal (Interagency Task Force, 2010). 

(2) Sequestration

Carbon sequestration usually involves the injection of CO2 into deep geological formations of 

porous rock that are capped by one or more nonporous layers of rock. Injected at high pressure, 

the CO2 exists as a liquid that flows through the porous rock to fill the voids. Saline formations, 

exhausted oil and gas fields, and un-mineable coal seams are candidates for CO2 storage. Also, 

CO2 injected for enhanced oil recovery (EOR) projects can result in long-term sequestration 

depending on the geologic conditions. Other systems include liquid storage in the ocean, solid 

storage by reactions leading to the creation of carbonates, and terrestrial sequestration. The 

nearest sequestration site in the Midwest is located in Decatur, Illinois adjacent to an ethanol 

plant owned by Archer Daniels Midland, Inc. This site (operated by the Midwest Geologic 

Sequestration Consortium) is currently exclusively sequestering CO2 from this ADM facility. This 

was being accomplished as a demonstration or pilot study and has been successful at current 

levels of sequestration. It is worthwhile to point out that the fermentation tanks of an ethanol plant 

already produce a highly concentrated CO2 waste-stream and at much lower volumes than a 

nominal 656 MW natural gas-fired power plant.
IPL Eagle Valley generating Station TSD – Appendix B Page 133 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

(3) Transportation

As noted above, the nearest sequestration site is located in Decatur, IL at the Midwest Geologic 

Sequestration Consortium well adjacent to the Archer Daniels Midland Company’s ethanol plant 

location (4666 E Faries Parkway # 1, Decatur, IL), which is more than 150 miles from the EVGS 

site. The intervening terrain would also make pipeline construction challenging: 3 major river 

crossings (West Fork White River, Wabash River, and the Vermilion River), crossing or going 

around Lake Decatur in Illinois (still necessitating a crossing of the Sangamon River which forms 

Lake Decatur), crossing two major interstates (I-70 in Indiana and I-57 in Illinois) and several 

smaller streams and rivers (including the Eel River in Indiana). There is no existing right-of-way 

available for such a pipeline, so a major land acquisition process would need to be established. 

Furthermore, this would be an interstate pipeline so lengthy federal environmental clearances 

would be necessary. 

One additional option would be to construct a pipeline to transport CO2 from the proposed project 

site to Rockville, Indiana where the proposed Indiana Gasification facility might be constructed. 

This option is not available to the source today, and may never be. As part of Indiana 

Gasification’s business plan, they plan to sell a portion of their CO2 emissions to a pipeline 

company (Denbury Resources, Inc.) and to oil companies in Texas and Louisiana who would use 

the CO2 for enhanced oil recovery (EOR). This pipeline would also be approximately 150 miles 

long to get to the Rockport location and face many of the same hurdles as the Decatur, IL 

pipeline option. However, in order for this option to be feasible, the proposed and existing 

infrastructure would have to have been designed and constructed with the additional CO2 in 

mind. It has not and a lot of the infrastructure is already in the ground in Texas. In order to 

accommodate the additional material flows, the pipeline company would need to expand existing 

infrastructure, redesign proposed infrastructure, and move forward with construction. This 

pipeline has not been constructed yet. The IPL project will generate approximately 2.65 million 

tons of CO2 annually compared to Indiana Gasification’s approximately 6 million tons for pipeline 

shipment. Therefore, the infrastructure would need to be able to accommodate approximately 

44% more material. Furthermore, it is unknown whether there is sufficient market available in the

region to purchase or even utilize these emissions. For these reasons discussed above, this 

option is not discussed further since the Decatur, IL sequestration site has fewer unknowns 

associated with it.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a carbon capture and storage (CCS) is not a technically feasible option for the 

combined cycle combustion turbine at this source.

High Thermal Efficiency System Design

Increased energy efficiency is a potential means of reducing GHG emissions and has also been 

considered as a potential control technology for GHG emissions from the proposed project. There 

are generally two types of energy efficiency improvement categories. The first category consists 

of technologies, process improvements, or other means of increasing the energy efficiency of the 

new source. Increased energy efficiency of the new source will result in less quantity of fuel 

combusted per unit of output. In the case of a combined-cycle facility designed purely for 

electricity generation, the unit of output would be kilowatt-hours of electrical output. In the case of 

an auxiliary boiler, the output would be in thousand pounds of steam produced. Emergency 

diesel engine outputs are measured in horsepower or in the case of an emergency diesel engine 

generator in kW-hr. For a process heater such as the proposed natural gas dew point heater, 

there is no applicable measurable output. Reciprocating engine efficiency can be inferred from 

the amount of fuel combusted and the stack exit temperature and flow rate.

The second category of energy efficiency improvements consists of technologies, process 

improvement, or other means of improving the amount of energy that is generated or used on the 

site. This second category does not look at the direct GHG emissions from the new source (which 
IPL Eagle Valley generating Station TSD – Appendix B Page 134 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

was evaluated in the first category of energy efficiency options) but looks at other facility 

processes or ancillary equipment that could reduce the amount of energy consumed to produce 

the equivalent output. Potential technologies included in this category may include increasing the 

efficiency of process equipment such as a heat exchangers, fans, pumps, etc., as well increasing 

the energy efficiency of ancillary equipment such as standalone emergency generators, firewater 

pumps, hot water heaters, lighting, etc. US EPA does not recommend an individual evaluation of 

all energy efficiency options in this second category due to the extremely large number of options. 

Rather, US EPA recommends new facilities evaluate their overall energy efficient technologies 

against a high-level performance facility in the industry to demonstrate that the facility will achieve 

comparable levels of energy efficiency. The proposed combined cycle project is being designed 

specifically to be a highly fuel efficient generation plant in keeping with IPL’s criterion of providing 

low-cost power to its customers. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a high thermal efficiency system design is a technically feasible option for the 

combined cycle combustion turbine at this source.

Use of Low Carbon Emitting Fuels

Carbon dioxide is produced as a combustion product of any carbon containing fuel. All fossil fuels 

contain varying amounts of fuel bound carbon that is converted during the combustion process to 

produce CO and CO2. The use of gaseous fuels such as natural gas compared to the use of 

higher carbon-containing fuels such as coal, pet-coke or fuel oils (residual or distillate) is a 

potentially feasible alternative to reduce the generation of CO2 emissions from combustion 

turbines.

Natural gas combustion results in significantly lower GHG emissions than coal combustion (117 

lb/MMBTU versus 210 lb/MMBTU). The use of lower carbon containing fuels in combustion 

turbines, pending the definition of the source, is an effective means to reduce the generation of 

CO2 during the combustion process.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a low carbon emitting fuel is a technically feasible option for the combined cycle 

combustion turbine at this source.

Combustion Turbine Design

Available technologies considered for CTs focus on energy efficient facility design inherent to 

combined cycle technology. An emissions reduction strategy focused on energy efficiency options 

primarily focuses on optimizing the thermal efficiency of the generating facility such that it would 

require less fossil fuel for a given output, resulting ultimately in lower emissions of GHGs.

The designers of such systems use sophisticated computer models such as Thermoflow’s GT 

Master to optimize the efficiency and generation capability of the system. This iterative analysis 

is done much more effectively by computer than could previously be accomplished by hand 

calculations. The use of this tool optimizes the heat rate (efficiency) of the proposed system over 

the entire range of operating design conditions of the facility. Finally, the source has a real and 

present economic incentive to design and operate the proposed generation facility as efficiently 

as practicable. In a brand new power plant, being designed from the ground up to achieve high 

efficiency (so as to produce least cost power from the minimum amount of purchased fossil fuel), 

substantial further “efficiency improvement projects” do not exist in the same sense that they 

might at an older, existing power plant. 

More Efficient EGU

Maximizing EGU efficiency is an alternative available to reduce the consumption of fuel required 

to generate a fixed amount of output. The largest efficiency losses for a combustion turbine are 

related to exhaust heat. In a combined cycle system, this exhaust heat is recaptured in the 
IPL Eagle Valley generating Station TSD – Appendix B Page 135 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

HRSG, and this is the fundamental technology that provides combined cycle technology with 

among the highest efficiency of any fossil fuel-fired power plant technology. In a combined cycle 

application, all of the components work together to achieve high system efficiency. Any increase 

in energy efficiency within the operation of the system yields reductions in the generation of CO2

emissions on a per unit output basis. US EPA guidance (PSD and Title V Permitting Guidance 

for Greenhouse Gases, November 2010) evaluated the availability of high efficiency combustion 

turbine combined cycle systems with recognized thermal efficiencies in the range of 50 to over 

56%. That summary addressed applications where an increased efficiency was achieved via 

design; the very technology that will be employed by the source. The source is proposing to 

install a state-of-the-art combustion turbine and heat recovery steam generator as part of this 

project within the case-specific features and operational parameters of the proposed project.

Combustion Air Cooling

A common method utilized to increase the electrical output of combustion turbines is to cool the 

combustion air during summer months prior to entering the combustion turbine. Cooling the 

combustion air via heat exchange systems maximizes the expansion of the air molecules and 

enhances the work these expanding gases perform on the turbine blades and hence higher 

amounts of electricity. The Hyperion Energy Center Best Available Control Technology (BACT) 

Analysis for Emissions of Carbon Dioxide, March 2009, claimed that achievable reductions in fuel 

usage and CO2 emissions could be in the range of 10–15% for their project. In any event, this 

technology has no impact on turbine performance or BACT Limits on any but the hottest summer 

day. 

Cogeneration / CHP as a CO2 Reduction Technique

Combined Heat and Power (CHP) is a technique involving the operation of a combustion system 

to generate heat for electric power generation as well as provide thermal energy to a process. 

The electric power is distributed for use, while thermal energy is used locally to support heating 

systems or industrial processes. A CHP system allows for the use of energy in the form of heat to 

provide thermal energy that would otherwise be lost in cooling water for a traditional EGU. For 

combustion turbine systems, the more likely CHP technique would be to provide space heating 

for nearby buildings or to provide makeup heat to nearby coal-fired EGUs (likely application for 

power plants with CT and coal-fired EGUs onsite). The use of this otherwise lost heat would 

thereby improve the overall efficiency of the EGU or process and subsequently reduce overall 

CO2 emissions, on an equivalent basis.

The use of a CHP system provides an opportunity to extract additional energy from heat 

otherwise lost in a traditional EGU. This type of system however does require the removal of 

steam from the steam turbine, which would thus reduce the magnitude of electric power 

generation recognized in the CHP. This electrical energy is instead transformed to thermal energy 

for use on a more local basis. The advantage to a CHP system is the net improvement of overall 

fuel efficiency compared to a traditional EGU operation.

For a CHP system to be beneficial there must be a local need for thermal energy as thermal 

energy cannot be effectively transported over extended distances. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The only feasible, applicable and available control technologies identified is:

(1) High Thermal Efficiency Design 

(2) Use of low emitting carbon fuel
IPL Eagle Valley generating Station TSD – Appendix B Page 136 of 152

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Permit Writer: Josiah Balogun and SPM 109-32476-00004

Step 4: Evaluate the Most Effective Controls and Document the Results

The source proposes the exclusive use of pipeline quality natural gas, which is the lowest carbon 

fossil fuel, resulting in reduced GHG emissions. IPL also proposes to procure, install and operate 

a high efficiency, low heat rate combined cycle generation facility. The expected net heat rate for 

the system operating at full load with duct firing is not more than 7,750 Btu/kW-hr (HHV-net), 

which is consistent with best design practices of other similar facilities. This figure is based upon 

a reasonable margin of compliance (total 12.8%) for the equipment including a 3.3% design 

margin, reflecting the possibility that the constructed facility may not achieve the design heat rate, 

a 6% performance margin reflecting efficiency losses due to equipment degradation prior to 

maintenance overhauls, as well as a 3.5% degradation margin reflecting the variability in 

operation of auxiliary plant equipment (e.g. the cooling towers) due to use over time. 

As stated previously, there is no meaningful GHG BACT technology for these small, intermittent 

sources contained in any PSD permits for similar combined cycle power plants beyond good 

engineering practice and the use of 40 CFR 98 emission factors. This annual mass emission limit 

does not include potential fugitive emissions of SF6 and CH4 from the facility piping and 

components. Individual BACT requirements for these fugitive emissions are proposed later. 

The GHG BACT emissions from the combined cycle combustion turbines shall not exceed 

2,649,570 tons, on a carbon dioxide equivalent basis (CO2e) in any consecutive rolling 12-month 

period. 

Methane and nitrous oxide emissions from the CTs shall be calculated in accordance with the 

methodology and emission factors noted in 40 CFR 98, Subpart D. The source proposes to 

install a CO2 CEMS as specified under 40 CFR 75, to monitor CO2 emissions from the CT/HRSG 

units and record those emissions hourly, track fuel usage in all the combustion sources, and 

calculate a consecutive rolling 12-month average CO2e emissions. These emissions are 

proposed to be included in the facility quarterly reports.

The following has been proposed as BACT for GHG emissions from the proposed combined 

cycle combustion turbines:

(1) The net heat rate shall not exceed 7,750 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 CO2e emissions for combined cycle combustion turbines shall be limited to less 

than 2,649,570 tons of CO2e 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 the GHG for the combined cycle combustion turbines:

(1) The net heat rate shall not exceed 7,750 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 CO2e emissions for combined cycle combustion turbines shall be limited to less 

than 2,649,570 tons of CO2e per twelve (12) consecutive month period with compliance 

determined at the end of each month.
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GHGs BACT – Auxiliary Boiler EU-3

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) Boiler Insulation;

(7) Condensation Return System; and 

(8) Steam Line Maintenance.

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.

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 Boiler at this source. 
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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 Boiler 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 Boiler 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 

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 Boiler at this source. 
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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 boiler 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 Boiler 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 Boiler 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.
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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 Boiler 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 Boiler 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 Boiler.

(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) Improved Combustion Measures: Combustion Tuning; (3% CO2 Reduction)

(6) Steam Line Maintenance;
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(7) Condensation Return System;

(8) Operating and Maintenance (O&M) Practices;

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 GHG BACT emissions from the auxiliary boiler shall not exceed 40,369 tons, on a carbon 

dioxide equivalent basis (CO2e) in any consecutive rolling 12-month period. 

The proposed natural gas boilers are stand-by, auxiliary units that are not intended to operate a 

significant number of hours. 

The following has been proposed as BACT for GHG emissions from the proposed auxiliary boiler:

(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) The boiler will be equipped with a condensate return system (recovery);

(6) Steam and hot lines will be insulated; and

(7) Boiler designed for 80% thermal efficiency (HHV).

(8) The total CO2e emissions for Auxiliary Boiler shall be limited to less than 40,369 tons of 

CO2e 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 the GHG for the Auxiliary Boiler:

(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) The boiler will be equipped with a condensate return system (recovery);

(6) Steam and hot lines will be insulated; and
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(7) Boiler designed for 80% thermal efficiency (HHV).

(8) The total CO2e emissions for Auxiliary Boiler shall be limited to less than 40,639 tons of 

CO2e per twelve (12) consecutive month period with compliance determined at the end 

of each month.

Greenhouse Gases (GHG) BACT – Dew Point Heater (EU-4)

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. 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.

GHG control possibilities identified and addressed in this BACT analysis for the dew point heater 

are as follows:

(1) The use of natural gas fuel, a low-carbon fuel source. 

(2) Good engineering design and good combustion practices 

(3) Post combustion carbon capture

Step 2: Eliminate Technically Infeasible Options

Natural Gas Use

This heater is proposed to use only natural gas. As a low-carbon fuel source, this will minimize 

greenhouse gas emissions.

Good Engineering Design and Good Combustion Practices

The combustion of natural gas is inherently efficient, and good engineering design of the burner

will assure efficient combustion. 

Beyond the use of good engineering design and the use of clean natural gas as previously 

mentioned, no additional applicable good combustion practices have been identified. 

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 

small combustion sources such as the dew point heater 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 
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is currently only being contemplated on very large or very concentrated CO2 sources. In stark 

contrast, this Project miscellaneous combustion source only uses 20.8 MMBtu/hr. As such it is 

two orders of magnitude smaller than EPA’s boiler example, and significantly smaller still than the 

categories that US EPA’s guidance document suggests should consider CCS. 

A CO2 capture system for the dew point heater 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. 

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 dew point 

heater at this source. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The only feasible, applicable and available control technologies identified are;

(1) The good engineering design and Combustion Practices; and

(2) The use of only natural gas. 

Step 4: Evaluate the Most Effective Controls and Document the Results

The GHG BACT emissions from the Dew Point Heater shall not exceed 10,659 tons, on a carbon 

dioxide equivalent basis (CO2e) in any consecutive rolling 12-month period. 

The following has been proposed as BACT for GHG from the proposed Dew Point Heater (EU-4): 

The only feasible, applicable and available control technologies identified are;

(1) The good engineering design and Combustion Practices; and 

(2) The use of only natural gas. 

(3) The total CO2e emissions for Dew Point Heater shall be limited to less than 10,659 tons 

of CO2e 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 the GHGs for the dew Point Heater, identified as EU-4.

(1) The good engineering design and Combustion Practices; and 
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(2) The use of only natural gas. 

(3) The total CO2e emissions for Dew Point Heater shall be limited to less than 10,659 tons 

of CO2e per twelve (12) consecutive month period with compliance determined at the 

end of each month.

GHGs BACT – Emergency Generator

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.

Distillate fuel oil 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 generator engines is to utilize good engineering design and fuel 

efficient design. 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following has been proposed as BACT for GHG emissions from the proposed Emergency 

generator engine: the selection and use of good engineering design and fuel efficient design.

This project includes one (1) distillate oil-fired emergency generator 1,826 HP KW standby 

emergency generator. This engine is required for safety reasons. The engine is expected to 

operate at 500 hours per year. That use is associated with assuring their readiness in an 

emergency. The emergency engine will have the potential to emit greenhouse gases (CO2, CH4, 

and N2O) because they will combust distillate oil fuel. However, because their normal use is 

limited to routine maintenance, inspection and testing, their total emissions are very small (less 

than 650 tons CO2e/yr). 

The following has been proposed as BACT for GHG emissions from the proposed Emergency 

Generator:

(1) The use of a good engineering design.

(2) The use of Ultra-low sulfur diesel fuel

(3) The total CO2e emissions for Emergency Diesel Generator shall be limited to less than

605 tons of CO2e per twelve (12) consecutive month period with compliance determined 

at the end of each 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 Generator:

(1) The use of a good engineering design;

(2) The use of Ultra-low sulfur diesel fuel; and

(3) The total CO2e emissions for Emergency Diesel Generator shall be limited to less than

605 tons of CO2e per twelve (12) consecutive month period with compliance determined 

at the end of each month.

GHGs BACT – Emergency Fire 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.

Distillate fuel oil 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 Fire pump 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 
IPL Eagle Valley generating Station TSD – Appendix B Page 147 of 152

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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 Emergency 

Fire pump 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 fire pump engine is to utilize good engineering design and fuel 

efficient design. 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following has been proposed as BACT for GHG emissions from the proposed Emergency 

Fire pump engine: the selection and use of good engineering design and fuel efficient design.

This project includes one distillate oil fired 500 HP standby emergency fire pump. This engine is

required for safety reasons. The engine is expected to operate less than 500 hours per year. 

That use is associated with assuring their readiness in an emergency. This emergency diesel 

engine will have the potential to emit greenhouse gases (CO2, CH4, and N2O) because they will 

combust distillate oil fuel. However, because their normal use is limited to routine maintenance, 

inspection and testing, their total emissions are very small (less than 200 tons CO2e/yr). 

The following has been proposed as BACT for GHG emissions from the proposed Emergency 

Fire Pump Engine:

(1) The use of a good engineering design.

(2) The use of Ultra-low sulfur diesel fuel.
IPL Eagle Valley generating Station TSD – Appendix B Page 148 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

(3) The total CO2e emissions for Firewater Pump Engine shall be limited to less than 157.50 

tons of CO2e 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 the GHG for the Firewater Pump Engine:

(1) The use of a good engineering design.

(2) The use of Ultra-low sulfur diesel fuel.

(3) The total CO2e emissions for Firewater Pump Engine shall be limited to less than 157.50 

tons of CO2e per twelve (12) consecutive month period with compliance determined at 

the end of each 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) Fully Enclosed SF6 breaker.

(2) Alternative Dielectric Material.

Step 2: Eliminate Technically Infeasible Options

Pressurized and enclosed breakers

The use of fully enclosed circuit breakers with leak detection (low pressure alarm) is state-of-theart for circuit breakers. 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 pressurized and enclosed breaker 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 

the circuit breakers the source is proposing to installed. 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 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.
IPL Eagle Valley generating Station TSD – Appendix B Page 149 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

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

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% by weight and a density alarm for leak detection.

(2) The total SF6 emissions for circuit breakers shall be limited to less than 59.80 tons of 

CO2e 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 GHGs for Electrical Circuit Breaker.

(1) The use of totally enclosed pressure system with a design leak rate of 0.5% by weight 

and a density alarm for leak detection.

(2) The total SF6 emissions from all the circuit breakers shall not exceed 59.8 tons of CO2e

per twelve (12) consecutive month period with compliance determined at the end of each

month.

Greenhouse Gases (GHG) BACT – Fugitive Equipment Leaks 

Step 1: Identify Potential Control Technologies

The source estimates there will be a small amount of GHG emissions from piping component, 

precisely CH4. These fugitive emissions are so small relative to the overall facility emissions and 

in an absolute sense that further control of fugitive emissions would have minimal additional 

benefit. 

The GHG emissions from fugitive equipments leaks can be controlled by;

(a) Leakless Technology;

(b) Instrument Leak detection and repair (LDAR) programs; and

(c) Auditory, Visual, and Olfactory (AVO) Monitoring.
IPL Eagle Valley generating Station TSD – Appendix B Page 150 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

Step 2: Eliminate Technically Infeasible Options

Leakless Technology

Leakless technology valves may be incorporated in situations where highly toxic or otherwise 

hazardous materials are present. Likewise, some technologies, such as bellows valves, cannot 

be repaired without a unit shutdown. Because natural gas is not considered highly toxic nor a 

hazardous material, this gas does not warrant the risk of unit shut down for repair, and therefore 

leakless valve technology for fuel lines is considered technically impracticable.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Leakless technology is not a technically feasible option for the fugitive equipment leaks 

at this source. 

Instrument Leak Detection and Repair (LDAR) Programs

Instrument LDAR programs and the alternative work practice of remote sensing using an infrared 

camera have been determined by EPA to be equivalent methods of piping fugitive controls. 

Some of the more stringent LDAR programs provide for 97% control credit for valves, flanges, 

and connectors.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Instrument Leak detection and repair (LDAR) programs is a technically feasible option 

for the fugitive equipment leaks at this source. 

Auditory, Visual and Olfactory (AVO) Monitoring 

As-observed AVO methods are generally somewhat less effective than instrument LDAR 

programs, since they are not conducted at specific intervals. However, since pipeline natural gas 

is odorized with very small quantities of mercaptan, as-observed olfactory observation is a very 

effective method for identifying and correcting leaks in natural gas systems.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Auditory, Visual, and Olfactory (AVO) Monitoring is a technically feasible option for the 

fugitive equipment leaks at this source. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(a) Instrument Leak detection and repair (LDAR) programs; and 

(b) Auditory, Visual, and Olfactory (AVO) Monitoring

Step 4: Evaluate the Most Effective Controls and Document the Results

Although instrument LDAR programs of piping fugitive emissions in natural gas lines may be 

somewhat more effective than as-observed AVO methods, these methods are not economically 

practicable for GHG control from components in fuel gas service. No other proposed or recently 

issued permits for natural gas CCCT installations have required an LDAR program. The 

incremental GHGs controlled by implementation of an LDAR program is approximately 1,442.9 

tons CO2e per year, or about 0.053% of the total project’s proposed CO2e annual emissions. 

This project will consist of approximately 1,852 various components and an LDAR annual cost 

per component would be approximately $16 per component for an annual cost of about $29,632. 

This corresponds to about $20.54 per ton of CO2e reduction for this project. The LDAR program 

for methane leaks is considered economically impracticable for this project.

The following has been proposed as BACT for GHGs from the proposed Fugitives Equipment 

Leaks:
IPL Eagle Valley generating Station TSD – Appendix B Page 151 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

The BACT for fugitive GHG emissions is proposed to be use of Auditory, Visual, and Olfactory 

(AVO) Monitoring program for methane leaks with repairs to be made as soon as it is safe and 

practicable to do so. 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD)), IDEM has established 

the following as BACT for GHG for Fugitives Equipment Leaks.

The BACT for fugitive GHG emissions shall be use of Auditory, Visual, and Olfactory (AVO) 

Monitoring program for methane leaks.
IPL Eagle Valley generating Station TSD – Appendix B Page 152 of 152

Martinsville, Indiana PSD/SSM 109-32471-00004

Permit Writer: Josiah Balogun and SPM 109-32476-00004

Best Available Control Technology during Startup and Shutdown for the 

Combustion Turbines, identified as EU1-EU2.

(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 - 3,390 lb/event

NOx - 429 lb/event

(h) The NOX emissions from the combined cycle combustion turbines stacks shall not 

exceed 68 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 

565 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 146 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. 
Cost Effectiveness Assessment for use of an Oxidation catalyst 

to Control CO Emissions from the 79.3 MMBtu/hr Auxiliary Boiler

Average 

Cost Item Cost Factor Cost ($s) Basis of Costs

Direct Costs:

Catalytic Oxidizer for Auxiliary Boiler (26,000 cfm) $ 1,366,000 EPA Cost Estimation Tool

 Instruments/controls 0.10 $ 136,600 EPA Cost Manual Table 2.8

 Taxes 0.05 $ 68,300 EPA Cost Manual Table 2.8

 Freight 0.05 $ 68,300 EPA Cost Manual Table 2.8

 Base Price: $ 1,639,200

 Installation costs, direct:

 Foundations/Supports 0.08 $ 131,136

 Erection/handling 0.14 $ 229,488

 Electrical 0.04 $ 65,568

 Piping 0.02 $ 32,784

 Insulation 0.01 $ 16,392

 Painting 0.01 $ 16,392

 Total Installation Costs: $ 491,760

 TOTAL DIRECT COSTS (Base Price + Installation)= $ 2,130,960

 Installation costs, indirect:

 Engineering/supervision 0.10 $ 163,920

 Construction/field expenses 0.05 $ 81,960

 Construction fee 0.10 $ 163,920

 Start-up 0.02 $ 32,784

 Performance Test 0.01 $ 16,392

 Contingencies 0.03 $ 49,176

 TOTAL INDIRECT COSTS= $ 508,152

TOTAL CAPITAL COSTS (Direct + Indirect)= $ 2,639,112

Direct Operating Costs: hours/year

 Operator ($/HR X HRS/YR) 15.5 547.5 $ 8,486 EPA guidance - 0.5 hour per 

shift per device

 Supervision(15% of labor) $ 1,273 EPA Cost Manual

Operating Materials:

 Maintenance Labor 40 547.5 $ 21,900 EPA Guidance (.5 

hour/shift/device)

 Maitenance Materials (100% of labor) $ 21,900

 Replacement parts (as required) 5% of equipment 

costs $ 68,300

 Utilities:

 Electricity ($/KWHxKWH/yr) $0.04/kw $ 7,106

 Gas ($/103

ft3x 103/yr) $4/MMBtu $ 78,325

TOTAL DIRECT OPERATING COSTS (A)= $ 207,290

Indirect operating (fixed) costs:

 Overhead $ 32,136

 Property Tax $ 26,391

 Insurance $ 26,391

 Administration $ 52,782

 Capital Recovery CRF= 0.13 (5.0% for 

10 years) $ 343,085

TOTAL FIXED COSTS (B)= $ 480,785

TOTAL ANNUALIZED COSTS (A +B minus C)= $ 688,075

28.5

75.0%

7.13

21.38

$32,191

"EPA Air Pollution Control Cost Manual, Sixth Edition", EPA-452-02-001, January 2002.

EPA Cost Manual Table 2.8

EPA Cost Manual Table 2.8

60% of O & M labor/materials

EPA Cost Manual

1% of capital costs

1% of capital costs

2% of capital costs

Uncontrolled CO Emissions Rate (tons/year) based on 79.3 MMBTU/hr NG Fired 

Aux Boiler operating 8760 hours/year

 Control System Efficiency based on 100% capture and 75% control 

Controlled Emissions Rate (tons/year)= 

CO Controlled, tons/year

Cost ($/ton)= 
IPL Eagle Valley Gen. Station Cost Analysis Page 2 of 4

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Cost Effectiveness Assessment for use of an Oxidation catalyst 

to Control VOC Emissions from the 79.3 MMBtu/hr Auxiliary Boiler

Average 

Cost Item Cost Factor Cost ($s) Basis of Costs

Direct Costs:

Catalytic Oxidizer for Auxiliary Boiler (26,000 cfm) $ 1,366,000 EPA Cost Estimation Tool

 Instruments/controls 0.10 $ 136,600 EPA Cost Manual Table 2.8

 Taxes 0.05 $ 68,300 EPA Cost Manual Table 2.8

 Freight 0.05 $ 68,300 EPA Cost Manual Table 2.8

 Base Price: $ 1,639,200

 Installation costs, direct:

 Foundations/Supports 0.08 $ 131,136

 Erection/handling 0.14 $ 229,488

 Electrical 0.04 $ 65,568

 Piping 0.02 $ 32,784

 Insulation 0.01 $ 16,392

 Painting 0.01 $ 16,392

 Total Installation Costs: $ 491,760

 TOTAL DIRECT COSTS (Base Price + Installation)= $ 2,130,960

 Installation costs, indirect:

 Engineering/supervision 0.10 $ 163,920

 Construction/field expenses 0.05 $ 81,960

 Construction fee 0.10 $ 163,920

 Start-up 0.02 $ 32,784

 Performance Test 0.01 $ 16,392

 Contingencies 0.03 $ 49,176

 TOTAL INDIRECT COSTS= $ 508,152

TOTAL CAPITAL COSTS (Direct + Indirect)= $ 2,639,112

Direct Operating Costs: hours/year

 Operator ($/HR X HRS/YR) 15.5 547.5 $ 8,486 EPA guidance - 0.5 hour per 

shift per device

 Supervision(15% of labor) $ 1,273 EPA Cost Manual

Operating Materials:

 Maintenance Labor 40 547.5 $ 21,900 EPA Guidance (.5 

hour/shift/device)

 Maitenance Materials (100% of labor) $ 21,900

 Replacement parts (as required) 5% of equipment 

costs $ 68,300

 Utilities:

 Electricity ($/KWHxKWH/yr) $0.04/kw $ 7,106

 Gas ($/103ft3x 103/yr) $4/MMBtu $ 78,325

TOTAL DIRECT OPERATING COSTS (A)= $ 207,290

Indirect operating (fixed) costs:

 Overhead $ 32,136

 Property Tax $ 26,391

 Insurance $ 26,391

 Administration $ 52,782

 Capital Recovery CRF= 0.13 (5.0% for 

10 years) $ 343,085

TOTAL FIXED COSTS (B)= $ 480,785

TOTAL ANNUALIZED COSTS (A +B minus C)= $ 688,075

1.8

75.0%

0.45

1.35

$509,685

"EPA Air Pollution Control Cost Manual, Sixth Edition", EPA-452-02-001, January 2002.

EPA Cost Manual Table 2.8

EPA Cost Manual Table 2.8

60% of O & M labor/materials

EPA Cost Manual

1% of capital costs

1% of capital costs

2% of capital costs

Uncontrolled VOC Emissions Rate (tons/year) based on 79.3 MMBTU/hr NG Fired 

Aux Boiler operating 8760 hours/year

 Control System Efficiency based on 100% capture and 75% control 

Controlled Emissions Rate (tons/year)= 

VOC Controlled, tons/year

Cost ($/ton)= 
IPL Eagle Valley Gen. Station Cost Analysis Page 3 of 4

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Cost Effectiveness Assessment for use of an Oxidation catalyst 

to Control CO Emissions from the 20 MMBtu/hr Dew Point Heater

Average 

Cost Item Cost Factor Cost ($s) Basis of Costs

Direct Costs:

Catalytic Oxidizer for Dew Point Heater (6200 cfm) $ 475,000 EPA Cost Estimation Tool

 Instruments/controls 0.10 $ 47,500 EPA Cost Manual Table 2.8

 Taxes 0.05 $ 23,750 EPA Cost Manual Table 2.8

 Freight 0.05 $ 23,750 EPA Cost Manual Table 2.8

 Base Price: $ 570,000

 Installation costs, direct:

 Foundations/Supports 0.08 $ 45,600

 Erection/handling 0.14 $ 79,800

 Electrical 0.04 $ 22,800

 Piping 0.02 $ 11,400

 Insulation 0.01 $ 5,700

 Painting 0.01 $ 5,700

 Total Installation Costs: $ 171,000

 TOTAL DIRECT COSTS (Base Price + Installation)= $ 741,000

 Installation costs, indirect:

 Engineering/supervision 0.10 $ 57,000

 Construction/field expenses 0.05 $ 28,500

 Construction fee 0.10 $ 57,000

 Start-up 0.02 $ 11,400

 Performance Test 0.01 $ 5,700

 Contingencies 0.03 $ 17,100

 TOTAL INDIRECT COSTS= $ 176,700

TOTAL CAPITAL COSTS (Direct + Indirect)= $ 917,700

Direct Operating Costs: hours/year

 Operator ($/HR X HRS/YR) 15.5 547.5 $ 8,486 EPA guidance - 0.5 hour per 

shift per device

 Supervision(15% of labor) $ 1,273 EPA Cost Manual

Operating Materials:

 Maintenance Labor 40 547.5 $ 21,900 EPA Guidance (.5 

hour/shift/device)

 Maitenance Materials (100% of labor) $ 21,900

 Replacement parts (as required) 5% of equipment 

costs $ 23,750

 Utilities:

 Electricity ($/KWHxKWH/yr) $0.04/kw $ 1,695

 Gas ($/103ft3x 103/yr) $4/MMBtu $ 18,551

TOTAL DIRECT OPERATING COSTS (A)= $ 97,554

Indirect operating (fixed) costs:

 Overhead $ 32,136

 Property Tax $ 9,177

 Insurance $ 9,177

 Administration $ 18,354

 Capital Recovery CRF= 0.13 (5.0% for 

10 years) $ 119,301

TOTAL FIXED COSTS (B)= $ 188,145

TOTAL ANNUALIZED COSTS (A +B minus C)= $ 285,699

7.5

75.0%

1.87

5.60

$50,995

"EPA Air Pollution Control Cost Manual, Sixth Edition", EPA-452-02-001, January 2002.

EPA Cost Manual Table 2.8

EPA Cost Manual Table 2.8

60% of O & M labor/materials

EPA Cost Manual

1% of capital costs

1% of capital costs

2% of capital costs

Uncontrolled CO Emissions Rate (tons/year) based on 20 MMBTU/hr NG Fired Dew 

Point Heater operating 8760 hours/year

 Control System Efficiency based on 100% capture and 75% control 

Controlled Emissions Rate (tons/year)= 

CO Controlled, tons/year

Cost ($/ton)= 
IPL Eagle Valley Gen. Station Cost Analysis Page 4 of 4

Martinsville, Indiana TSD for PSD/Significant Source Modification No.: 109-32471-00004

Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109-32476-00004

Cost Effectiveness Assessment for use of an Oxidation Catalyst 

to Control VOC Emissions from the 20 MMBtu/hr Dew Point Heater

Average 

Cost Item Cost Factor Cost ($s) Basis of Costs

Direct Costs:

Catalytic Oxidizer for Dew Point Heater (6200 cfm) $ 475,000 EPA Cost Estimation Tool

 Instruments/controls 0.10 $ 47,500 EPA Cost Manual Table 2.8

 Taxes 0.05 $ 23,750 EPA Cost Manual Table 2.8

 Freight 0.05 $ 23,750 EPA Cost Manual Table 2.8

 Base Price: $ 570,000

 Installation costs, direct:

 Foundations/Supports 0.08 $ 45,600

 Erection/handling 0.14 $ 79,800

 Electrical 0.04 $ 22,800

 Piping 0.02 $ 11,400

 Insulation 0.01 $ 5,700

 Painting 0.01 $ 5,700

 Total Installation Costs: $ 171,000

 TOTAL DIRECT COSTS (Base Price + Installation)= $ 741,000

 Installation costs, indirect:

 Engineering/supervision 0.10 $ 57,000

 Construction/field expenses 0.05 $ 28,500

 Construction fee 0.10 $ 57,000

 Start-up 0.02 $ 11,400

 Performance Test 0.01 $ 5,700

 Contingencies 0.03 $ 17,100

 TOTAL INDIRECT COSTS= $ 176,700

TOTAL CAPITAL COSTS (Direct + Indirect)= $ 917,700

Direct Operating Costs: hours/year

 Operator ($/HR X HRS/YR) 15.5 547.5 $ 8,486 EPA guidance - 0.5 hour per 

shift per device

 Supervision(15% of labor) $ 1,273 EPA Cost Manual

Operating Materials:

 Maintenance Labor 40 547.5 $ 21,900 EPA Guidance (.5 

hour/shift/device)

 Maitenance Materials (100% of labor) $ 21,900

 Replacement parts (as required) 5% of equipment 

costs $ 23,750

 Utilities:

 Electricity ($/KWHxKWH/yr) $0.04/kw $ 1,695

 Gas ($/103ft3x 103/yr) $4/MMBtu $ 18,551

TOTAL DIRECT OPERATING COSTS (A)= $ 97,554

Indirect operating (fixed) costs:

 Overhead $ 32,136

 Property Tax $ 9,177

 Insurance $ 9,177

 Administration $ 18,354

 Capital Recovery CRF= 0.13 (5.0% for 

10 years) $ 119,301

TOTAL FIXED COSTS (B)= $ 188,145

TOTAL ANNUALIZED COSTS (A +B minus C)= $ 285,699

0.48

75.0%

0.12

0.36

$793,608

"EPA Air Pollution Control Cost Manual, Sixth Edition", EPA-452-02-001, January 2002.

EPA Cost Manual Table 2.8

EPA Cost Manual Table 2.8

60% of O & M labor/materials

EPA Cost Manual

1% of capital costs

1% of capital costs

2% of capital costs

Uncontrolled VOC Emissions Rate (tons/year) based on 20 MMBTU/hr NG Fired 

Dew Point Heater operating 8760 hours/year

 Control System Efficiency based on 100% capture and 75% control 

Controlled Emissions Rate (tons/year)= 

VOC Controlled, tons/year

Cost ($/ton)= 
INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

We Protect Hoosiers and Our Environment. 

100 N. Senate Avenue • Indianapolis, IN 46204

(800) 451-6027 • (317) 232-8603 • www.idem.IN.gov

 Michael R. Pence Thomas W. Easterly 

 Governor Commissioner

An Equal Opportunity Employer Recycled Paper

SENT VIA U.S. MAIL: CONFIRMED DELIVERY AND SIGNATURE REQUESTED 

TO: Angelique Oliger

 IPL - Eagle Valley 

1 Monument Circle 

 Indianapolis, Indiana 46204 

 

DATE: October 11, 2013 

FROM: Matt Stuckey, Branch Chief 

 Permits Branch 

 Office of Air Quality 

SUBJECT: Final Decision 

 PSD/Significant Source Modification to Part 70 Renewal 

 109-32471-00004 

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: 

Bradley Scott, Responsible Official 

Tom Rarick, Environmental Resources Management (ERM) 

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 6/13/2013 
INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

We Protect Hoosiers and Our Environment. 

100 N. Senate Avenue • Indianapolis, IN 46204

(800) 451-6027 • (317) 232-8603 • www.idem.IN.gov

 Michael R. Pence Thomas W. Easterly 

 Governor Commissioner

An Equal Opportunity Employer Recycled Paper

October 11, 2013 

TO: Morgan County Public Library 

From: Matthew Stuckey, Branch Chief 

 Permits Branch 

 Office of Air Quality 

Subject: Important Information for Display Regarding a Final Determination 

 Applicant Name: IPL - Eagle Valley 

 Permit Number: 109-32471-00004 

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 6/13/2013
FACSIMILIE OF PS Form 3877 

Mail Code 61-53 

IDEM Staff PWAY 10/11/2013 

Indianapolis Power & Light Co. (IPL) Eagle Valley Gen.Stat 109-32471-00004 (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 

RF

1 Angelique Oliger Indianapolis Power & Light Co. Eagle Valley Gener 1 Monument Cir Indianapolis IN 46204 (Source CAATS) 2 Bradley Scott Sr Dir - Plant Ops Indianapolis Power & Light Co. Eagle Valley Gener PO Box 436 / 6925 N SR 57 Petersburg IN 47567 (RO CAATS)3 Morgan County Commissioners 180 South Main Street Martinsville IN 46151 (Local Official)4 Martinsville City Council and Mayors Office P.O. Box 1415, 59 South Jefferson Street Martinsville IN 46151 (Local Official)5 Morgan Co Public Library 110 S Jefferson St Martinsville IN 46151-1999 (Library)6 Clayton D. & Patricia A. Arthur 5178 Brenda Boulvard Greenwood IN 46143 (Affected Party)7 Morgan County Health Department 180 S Main Street, Suite 252 Martinsville IN 46151-1988 (Health Department)8 David Jones 7977 N. Taylors Rd. Mooresville IN 46158 (Affected Party)9 Claudia Parker 6761 Centenary Rd. Mooresville IN 46158 (Affected Party)10 James Swails 6568 E. Rosebud Lane Mooresville IN 46158 (Affected Party)11 John Thurston 6548 E. Watson Mooresville IN 46158 (Affected Party)12 Bethany Town Council 7355 Bethany Park Martinsville IN 46151 (Local Official)13 Tom Rarick Environmental Resources Management (ERM) 11350 N Meridian Suite 320 Carmel IN 46032 (Consultant) 14 15 Total number of pieces Listed by Sender 

Total number of Pieces Received at Post Office 

Postmaster, Per (Name of Receiving employee) 

The full declaration of value is required on all domestic anmaximum indemnity payable for the reconstruction of nonMail document reconstructing insurance is $50,000 per pioccurrence. The maximum indemnity payable on ExpresThe maximum indemnity payable is $25,000 for registereinsurance. See Domestic Mail Manual R900, S913, an

inured and COD mail. See International Mail Manual fomail. Special handling charges apply only to Standard Ma