## I NDIANA 

## D EPARTMENT OF 

## E NVIRONMENTAL 

## M ANAGEMENT

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 Commissione r

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 effectiv eness 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 a nd IC 13-15-6-1 require that you file a petition for administrative review. This petition may include a reque st for stay of effectiveness and must be submitted to the Office of Environmental Adjudication, 100 No rth 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 comple te 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 contai ning 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 repres ented 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 wh ich, 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 enclos ed documents, please contact the Office of Air Quality, Permits Branch at (317) 233-0178. Calle rs from within Indiana may call toll-free at 1-800-451- 6027, ext. 3-0178.

Enclosures

FNPER.dot 6/13/13IPL Eagle Valley Generating Station Page 2 of 3 Martinsville, IN PSD/Source Modification No. 109

- 32471

- 00004

new affected source s .]

(c) One ( 1 ) evaporative cooling t ower

, 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 con denser, permitted in 2013, and equipped with high efficiency drift eliminator s

.

(d) Electrical Circuit Breakers containing sulfur hexafluoride (SF 6 ) 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 201 3

.

The following construction conditions are applicabl e 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 construct ion 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 aut horizes 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 unti l 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

.IPL Eagle Valley Generating Station Page 2 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 Propert y 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 T ermination 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 [32 6 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] [I C 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 [3 26 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 S tack Height [326 IAC 1- 7]
C. 8 Asbestos Abatement Projects [326 IAC 14

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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.1 6 Emergency Reduction Plans [32 6 IAC 1-5- 2] [326 IAC 1-5- 3]
C.1 7 Risk Management Plan [326 IAC 2-7- 5(12)] [40 CFR 68]
C.1 8 Response to Excursions or Exceedances [326 IAC 2-7- 5] [326 IAC 2-7- 6]
C.1 9 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.2 1 General Record Keeping Requirements [326 IAC 2- 2] [326 IAC 2- 3] [326 IAC 2-7- 5(3)] [326 IAC 2-7- 6]
C.2 2 G eneral 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.2 3 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 (SO 2 ) [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 Recor d 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]IPL Eagle Valley Generating Station Page 4 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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D.2.2 Temporary Alternative Opacity Limitations [326 IAC 5-1- 3]
D.2.3 Sulfur Dioxide (SO 2 ) [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 Requirement s [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.2.1 0 Opacity Readings [326 IAC 2-7- 6(1)] [326 IAC 2-7- 5(1)]

D.2.1 1 SO 2 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.2.1 2 Record Keeping Requirements

D.2.1 3 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 (SO 2 ) [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 Re quirements [326 IAC 2-7- 5(3)] [326 IAC 2-7- 19]
D.3. 3 R ecord 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

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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 Fugitiv e 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, PM 10 and PM 2.5 PSD BACT [326 IAC 2-2-3]

D.7 .2 H 2 SO 4 PSD BACT [326 IAC 2-2-3]

D.7 .3 CO PSD BACT [326 I AC 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 S tartup, Shutdown and Other Opacity Limits [326 IAC 5-1-3] Compliance Determinatio n Requirements

D.7 .9 Oxidation Catalyst Control

D.7

. 10 Nitrogen Oxide Control

D.7

. 11 H 2 SO 4 Compliance Determination Requirements [326 IAC 2

- 2]

D.7

. 12 Greenhouse Gases (GHGs) Calculations

D.7

. 13 HAPs Minor Limits Calculations

D.7.1 4 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 Re porting Requirement s

D.8 . EMISSIONS UNIT OPERATION CONDITIONS

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

D.8 .1 PM, PM 10 and PM 2.5 PSD BACT [ 326 IAC 2-2-3]IPL Eagle Valley Generating Station Page 6 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 H 2 SO 4 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 Re porting Requirement s

D.9 . EMISSIONS UNIT OPERATION CONDITIONS

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

D.9 .1 PM, PM 10 and PM 2.5 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 H 2 SO 4 Compliance Determination Requirements [326 IAC 2

- 2]

D.9 .9 G reenhouse Gases (GHGs) Calculations

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

D.9.1 0 Record Keeping Requirement

D.9.11 Re porting Requirement s

D.10

. EMISSIONS UNIT OPERATION CONDITIONS

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

D.10.1 PM, PM 10 , PM 2.5 , H 2 SO 4 , VOC, CO, NOx and GHGs PSD BACT [326 IAC 2-2-3]

D.10.2 PM, PM 10 , PM 2.5 , H 2 SO 4 , VOC, CO, NOx and GHGs PSD BACT [326 IAC 2-2-3] Complia nce 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 Re porting Requirement sIPL Eagle Valley Generating Station Page 7 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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D.11 . EMISSIONS UNIT OPERATION COND ITIONS

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

D.11.1 PM, PM 10 and PM 2.5 PSD BACT [326 IAC 2-2-3] Compliance Determination Requirements

D.11 .2 PM, PM 10 and PM 2.5 Control [326 IAC 2- 1.1

- 11]

Record Keeping and Reporting Requirements [326 IA C 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.1 3 . EMISSIONS UNIT OPERATION CONDITIONS

Emission Limi tations 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, PM 10 and PM 2.5 PSD BACT [326 IAC 2-2- 3]

E .1 ACID RAIN PROGRAM CON DITIONS

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 Standard s [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 6 0, Subpart KKKK] [ 326 IAC 1 2]

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

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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 1 2] [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 R ecord 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 Martinsville, Indiana PSD/Significant Source Modification No. 109

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Certification Emergency Occurrence Report Quarterly Report s Quarterl y 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 ZZZZIPL Eagle Valley Generating Station Page 10 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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SECTION A SOURCE SUMMARY

This p ermit 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 NO X and
SO 2 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 ov erfire air (SOFA)

and low NO X burners (LNB) for control of NO X 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 NO X and SO 2 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
NO X 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 NO X and SO 2 and a continuous opacity monitor (COM).IPL Eagle Valley Generating Station Page 11 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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(e) One (1) tangentially

- fir ed 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 NO X 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 ons ite may be combusted in Unit 6 as supplemental fuel for energy recovery. Unit 6 has had

low

- NO X burners installed. Stack 3

- 1 has continuous emission monitoring systems (CEMS) for NO X and SO 2 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 200 9

, 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 in put capacity of 2,542 MMBtu/hr; with NO

x 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

s tacks S

- 1 and S

- 2. Each stack has continuous emissions monitors (CEMS) for NOx.

*N ote: 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 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 regul ated, 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 d own 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, SO 2 5 pounds per hour or 25 pounds per day, NO X 5 pounds per hour or 25 pounds per day, CO 25 pounds per day, PM 10 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) distilla te 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 (SF 6 ) 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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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).IPL Eagle Valley Generating Station Page 14 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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SECTION B GENERAL CONDITIONS

B.1 Definitions [326 IA C 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

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, 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 desig ned 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 modif ying, 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.IPL Eagle Valley Generating Station Page 15 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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

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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 3 26 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).IPL Eagle Valley Generating Station Page 16 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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

s chedule 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

reasona ble 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 potentia l 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 -8 00

- 451

- 6027 (ask for Office of Air Quality, Compliance Section), or Telephone Number: 317

- 233

- 0178 (ask for Compliance Section)

Facsimile Number: 317

- 233

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(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
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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 ste ps 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.IPL Eagle Valley Generating Station Page 18 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 permi t 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 thi s 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 fo llowing:

(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 o r 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 Clea n 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)]IPL Eagle Valley Generating Station Page 19 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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B.13 Prior Permits Superseded [326 IAC 2- 1.1

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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 , a ll 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

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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 th e 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:

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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 init iated 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.
Su ch 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

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(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.IPL Eagle Valley Generating Station Page 21 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 A ir 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

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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

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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

scenario s 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 per mit 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 SO 2 or NO X under 326 IAC 21 or

326 IAC 10

- 4.

B.21 S ource Modification Requirement [326 IAC 2-7- 10.5] (a) A modification, construction, or reconstruction is governed by the requirements of

326 IAC 2.IPL Eagle Valley Generating Station Page 23 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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

326 IAC 2- 2.

B.22 Insp ection 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

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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

r equest for an administrative amendment immediately upon submittal of the request. [326 IAC 2-7- 11(c)(3)]IPL Eagle Valley Generating Station Page 24 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 admi nistrative 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.IPL Eagle Valley Generating Station Page 25 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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.IPL Eagle Valley Generating Station Page 26 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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

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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), complian ce 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)IPL Eagle Valley Generating Station Page 27 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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

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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

ca lculations, 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

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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)

ho urs 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 6 0 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 NO X or SO 2 emissions pursuant to

40 CFR 75 (Title IV Acid Rain program) or 326 IAC 10

- 4 (NO X Budget Trading Program), the Permittee shall comply with the relevant requirements o f

40 CFR 75 Subpart D - Missing Data Substitution Procedures.

(2) IF the CEM is not used to monitor NO X or SO 2 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, 4 0 CFR 60 Appendix B, 40 CFR 63, or other approved methods as specified in this permit.IPL Eagle Valley Generating Station Page 29 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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

twent y 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

qu antity, 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

emissio ns 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;

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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 -2 251

The emission statement does require the certification by the “responsible official” as defined by 326 IAC 2-7- 1(34).IPL Eagle Valley Generating Station Page 31 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 Gener al 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)), t he 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.IPL Eagle Valley Generating Station Page 32 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 submi tted 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:IPL Eagle Valley Generating Station Page 33 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 IA C 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 f or 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

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(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.IPL Eagle Valley Generating Station Page 34 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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. T he 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
Q 0.16 = 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)]IPL Eagle Valley Generating Station Page 35 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 (SO 2 ) [326 IAC 7-4- 11]

Pursuant to 326 IAC 7-4- 11 (Morgan County Sulfur Dioxide Emission Limitations), the SO 2 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]

C ompliance 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 tes ting 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

rep etition 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 CF R 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

oper ation 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; orIPL Eagle Valley Generating Station Page 36 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 - R esponse to Excursions or
Exceedan ces. 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 - R esponse 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

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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 SO 2 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 conten t.

(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 Generating Station Page 38 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 NO X and SO 2 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 lo w NO X burners (LNB) for
control of NO X 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 syste ms (CEMS) for NO X and SO 2 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 NO X 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 NO X and SO 2 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 NO X 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

- NO X burners installed.
Stack 3

- 1 has continuous emission monitoring systems (CEMS) for NO X and SO 2 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 S tandards [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. T he 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:IPL Eagle Valley Generating Station Page 39 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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Pt = 0.87 Where Q = total source capacity (MMBtu/hr) on June 8, 1972
Q 0.16 = 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 limi tation
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 32 6 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 (SO 2 ) [326 IAC 7-4- 11]

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

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

(b) SO 2 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 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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. Test ing 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 Continuo us 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, SO 2 , and either CO 2 or O 2 , 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,

an d 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) Purs uant 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, SO 2 emissions may be determined by use of CEM in lieu of any other method prescribed herein.IPL Eagle Valley Generating Station Page 41 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 C FR 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

t ransformer

- 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 SO 2 Monitor Downtime [326 IAC 2-7- 6] [326 IAC 2-7- 5(3)] (a) Whenever the SO 2 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 SO 2 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 Generating Station Page 42 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 mo nitoring readings.

(b) To document compliance with SO 2 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 SO 2 limits as required in Condition D.2.3. The Permittee shall maintain records in accordance with (2) and (3) or (4) below during SO 2 CEM system downtime.

(1) All SO 2 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 SO 2 CEM downtime, in
accordance with Condition D.2.1 1.

(3) Calculated actual fuel usage during each SO 2 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 SO 2 CEM downtime,

in accordance with Condition D.2.1 1.IPL Eagle Valley Generating Station Page 43 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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(c) Pursuant to 326 IAC 7-4- 11(9), the Permittee shall maintain and make available to the depart ment 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 Generating Station Page 44 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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

permane ntly discontinue the operation of the emission units in Section D.3 before commercial operation of the Combined Cycle Combustion Turbine Generation Facility. T he requirements of this section will no longer be applicable after the units are permanently shut down

.

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

- 2]

Pursuant to 326 IAC 7- 1.1

- 2 (Sulfur Dioxide Emission Limitations), the SO 2 emissions from Unit

PR

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

Compliance Determination Requirements

D.3.2 Sul fur 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 SO 2 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.IPL Eagle Valley Generating Station Page 45 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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)] [32 6 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 Martinsville, Indiana PSD/Significant Source Modification No. 109

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SECTION D.4 FACILITY OPER ATION 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. T he 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 P 0.11

- 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 pou nds 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 Generating Station Page 47 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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(b) Visible emission notations of the rail car unloading shall be performed once per w eek 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 - R esponse to Excursions or Exceedan ces

. Failure to take response steps in accordance with Section C - R esponse to Excursions or Exceedan ces

, 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 Generating Station Page 48 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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SECTION D.5 FACILITY OPERATION CONDITIONS

Facility Descri ption [326 IAC 2

- 7

- 5(15)]:

(j) One (1) pneumati c Fly Ash Conveyance and Silo Storage ( fly ash storage silo and handling system ) , to be constructed in 200 9 , 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 [3 26 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. T he 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 PM 10 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 hourIPL Eagle Valley Generating Station Page 49 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 re paired 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

no rm al, 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 Vis ible 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) Fo r processes operated continuously, "normal" means those conditions prevailing, or expected to prevail, eighty percent (80%) of the time the process is in operation, not

counti ng 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 emissi ons 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

re sponse 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 a nd 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 ac cordance with Section C - Response to Excursions or Exceedances, shall be considered a deviation from this permit.IPL Eagle Valley Generating Station Page 50 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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The instrument used for determining the pressure shall comply with condition C.14 - Instrument Specifications, be subject to approval by IDE M, 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

re placed. 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 Generating Station Page 51 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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. T he 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:

P R = (1.5 ± N) P

Where N = Fraction of fugitive dust that is respirable dust;

P R = 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.IPL Eagle Valley Generating Station Page 52 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 Requirem ents [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) I n 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 - R esponse to Excursions or Exceedances. Failure to take response steps in accordance with Section C - R esponse 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.IPL Eagle Valley Generating Station Page 53 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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SECTION D.7 EMISSIONS UNIT OPERATION CONDITIONS

Emissions U nit 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 NO

x 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 monito rs (CEMS) for NOx.

*N ote: 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, PM 10 and PM 2.5 PSD BACT [326 IAC 2-2- 3] Pursuant to PSD/Significant Source Modification 109

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gas

- fired combined cycle combustion turbines, identified as EU

- 1 and EU

- 2 shall be as follows:

( a) The PM

, PM 10 and PM 2.5 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

combust ion practices and fuel specification.

(b) The PM, PM 10 and PM 2.5 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 p ipeline natural gas shall be fired in the combined cycle combustion turbines
identified as EU

- 1 and EU

- 2.

D.7.2 H 2 SO 4 PSD BACT [326 IAC 2-2- 3] Pursuant to PSD/Significant Source Modification 109

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gas

- fired combined cycle combustion turbines, identified as EU

- 1 and EU

- 2 shall be as follows:

(a) The H 2 SO 4 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

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gas

- fired combined cycle combustion turbines, identified as EU

- 1 and EU

- 2 shall be as follows:IPL Eagle Valley Generating Station Page 54 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 p ipeline 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

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- 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% O 2 , with duct burners based on

3- hour average.

(c) The VOC emissions shall not exceed 1.0 ppmvd @15% O 2 , without duct burners
based on 3

- hour average.

(d) Only p ipeline 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

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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% O 2 with duct burners based on a 3

- hour average.

(c) Only p ipeline 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

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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 CO 2 e e missions for both combined cycle combustion turbines shall be limited to less than 2,649,570 tons of CO 2 e per twelve (12) consecutive month period with compliance determined at the end of each month.IPL Eagle Valley Generating Station Page 55 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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.

Compl iance 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

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(a) A startup is defined as the operation in the period beginning when continuous fuel flow to the combustion turbine is initiated and ending when the CCCT achieves consecutive CEMS data points in compliance with the primary BACT limits.

(b) Steady

- state operating condition shall be defined as the period of time that the combustion turbine is operating in dry low NOx (premix) mode and in compliance with the primary BACT limit.

(c) A shutdown is defined as operation beginning when the combustion turbine exits dry 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 NO X , 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 NO X 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.IPL Eagle Valley Generating Station Page 56 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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

- fi red 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 H 2 SO 4 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 CO 2 e emissions from the natural gas

- fired combined cycle combustion turbines, identified as EU

- 1 and EU -2:

CO 2 e emissions (tons/month) = [(Fuel Usage (mmscf/month) x Heat Content (mmbtu/mmscf)) x (CO 2 EF (lb/mmbtu) x CO 2 GWP + C H 4 EF (lb/mmbtu) x CH 4 GWP + N 2 O EF (lb/mmbtu) x N 2 O 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
CO 2 EF (lb/mmbtu) = 120 lbs/mmbtu for combustion with duct firing and 122 lbs/mmbtu for combustion without duct firing
CH 4 EF (lb/mmbtu) = 0.0022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas

N 2 O EF (lb/mmbtu) = 0.00022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas CO 2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)
CH 4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N 2 O GWP = 310 glo bal 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 th e 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 conditionsIPL Eagle Valley Generating Station Page 57 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 O 2 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 O 2 CEMS is down for more than twenty

- four (24) hours, the

Permit tee 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 tempera ture 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, PM 10 and PM 2.5 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, PM 10 and PM 2.5 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 - P erformance 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 theIPL Eagle Valley Generating Station Page 58 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 follo wing 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 purpo ses 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 500 o 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.IPL Eagle Valley Generating Station Page 59 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 - H 2 SO 4 PSD B ACT, 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

Perm ittee shall maintain monthly records of the CO 2e 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 d ata;

(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.7.1 4 - Maintenance of Continuous Emission Monitoring Equipment, the Permittee shall record the output of the continuous

mon itoring 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 O 2 continuous emission monitoring system (CEMS) occurs in Condition D.7.1 4 - Mainten ance 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.7.1 4 - 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.7.1 6 - 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.IPL Eagle Valley Generating Station Page 60 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 Condit ions 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.IPL Eagle Valley Generating Station Page 61 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 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, PM 10 and PM 2.5 PSD BACT [326 IAC 2-2- 3] Pursuant to PSD/Significant Source Modification 109

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- 00004 and 326 IAC 2-2- 3 (Prev ention 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, PM 2.5 and PM 10 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 H 2 SO 4 PSD BACT [326 IAC 2-2- 3] Pursuant to PSD/Significant Source Modification 109

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gas

- fired auxiliary boiler, identified as EU

- 3 shall be as follows:

(a) The H 2 SO 4 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

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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

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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 -h r 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

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gas

- fired auxiliary boiler, identified as EU

- 3 shall be as follows:

(a) The NOx emissions from the Auxiliary Boiler, identified as E U- 3 shall be controlled by Low
NOx Burners with Flue Gas Recirculation.IPL Eagle Valley Generating Station Page 62 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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

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- 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 CO 2 e emissions for Auxiliary Boiler shall be limited to less than 40,63 9 tons of
CO 2 e 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 H 2 SO4 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, PM 10 and PM 2.5 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, PM 10 and PM 2.5 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 beIPL Eagle Valley Generating Station Page 63 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 Greenh ouse Gases (GHGs) Calculations To determine the compliance status with Condition D.8.6(h), the following equation shall be used

to determine the CO 2 e emissions from the Auxiliary Boiler :

CO 2 e emissions (ton/month) = [(Fuel Usage (mmscf/month) x Heat Content (mmbtu/mmscf)) x (CO 2 EF (lb/mmbtu) x CO 2 GWP + CH 4 EF (lb/mmbtu) x CH 4 GWP + N 2 O EF (lb/mmbtu) x N 2 O 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
CO 2 EF (lb/mmbtu) = 117 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas
CH 4 EF (lb/mmbtu) = 0.0022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C)IPL Eagle Valley Generating Station Page 64 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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for natural gas

N 2 O EF (lb/mmbtu) = 0.00022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas CO 2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)
CH 4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N 2 O 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.8.1 1 , 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 - H 2 SO 4 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) T o document the compliance status with Condition D.8.6 (h) - GHGs PSD BACT, the Permittee shall maintain the monthly records of the total CO 2e 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 Generating Station Page 65 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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, PM 10 and PM 2.5 PSD BACT [326 IAC 2-2- 3] Pursuant to PSD/Significant Source Modification 109

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- 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, PM 10 and PM 2.5 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 H 2 SO 4 PSD BACT [326 IAC 2-2- 3] Pursuant to PSD/Significant Source Modification 109

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- 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 H 2 SO 4 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 month ly average basis

.

D.9.3 CO PSD BACT [326 IAC 2-2- 3] Pursuant to PSD/Significant Source Modification 109

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- 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

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- 00004 and 326 IAC 2-2- 3 (Prevention

o f 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 l bs/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

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- 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:IPL Eagle Valley Generating Station Page 66 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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(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 de w 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 CO 2 e emissions for Dew Point Heater shall be limited to less than 10,659 tons of
CO 2 e 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, PM 10 and PM 2.5 PSD BACT

and D.9.2 - H 2 SO 4 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 CO 2 e emissions from the dew point heater, identified as EU -4:

CO 2 e emissions (ton/month) = [(Fuel Usage (mmscf/month) x Heat Content (mmbtu/mmscf)) x (CO 2 EF (lb/mmbtu) x CO 2 GWP + CH 4 EF (lb/mmbtu) x CH 4 GWP + N 2 O EF (lb/mmbtu) x N 2 O 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
CO 2 EF (lb/mmbtu) = 117 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas
CH 4 EF (lb/mmbtu) = 0.0022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas

N 2 O EF (lb/mmbtu) = 0.00022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas CO 2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)
CH 4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N 2 O GWP = 310 global warming potential from GHG MRR (40 CFR 98, Subpart A)IPL Eagle Valley Generating Station Page 67 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 CO 2e emissions from the auxiliary boilers

.

(c) Section C - Gen eral 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 Generating Station Page 68 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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,
S ubpart 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, PM 10 , PM 2.5 , NOx, CO, H 2 SO 4 and GHGs PSD BACT [326 IAC 2-2- 3] Pursuant to PSD/Significant Source Modification 109

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- 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, PM 10 and PM 2.5 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 H 2 SO4 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 0 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 CO 2 e emissions for Emergency Diesel Generator shall be limited to less
than 605 tons of CO 2 e per twelve (12) consecutive month period with compliance
determined at the end of each month.

D.10.2 PM, PM 10 , PM 2.5 , NOx, CO, H 2 SO 4 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 Generating Station Page 69 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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Emergency Fire Pump Engine, identified as EU

- 6:

(a) The PM, PM 10 and PM 2.5 emissions from the Emergency Fire Pump Engine shall not exceed 0.15 g/hp

- hr through the use of combustion design control.

(b ) H 2 SO 4 BACT Limits

1. The sulfur content of the fuel oil sha ll 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 tota l CO 2 e emissions for Firewater Pump Engine shall be limited to less than

15 8 tons of CO 2 e 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 CO 2 e emissions from the Emergency Diesel Generator (EU

- 5):

CO 2 e emissions (ton/month) = [(Fuel Usage (gal/month) x Heat Content (mmbtu/gal)) x (CO 2 EF (lb/mmbtu) x CO 2 GWP + CH 4 EF (lb/mmbtu) x CH 4 GWP +

N 2 O EF (lb/mmbtu) x N 2 O GWP)] x 1/2000 (ton/lb)

Where:

Fuel Usage (gal/month) = monthly emergency generato r fuel usage data from company records Heat Content (mmbtu/gal) = standard value in AP

- 42 for diesel fuel, or vendor data, if

available
CO 2 EF (lb/mmbtu) = 163 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for diesel fuel
CH 4 EF (lb/mmbtu) = 0.00661 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for diesel fuel

N 2 O EF (lb/mmbtu) = 0.00132 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for diesel fuel
CO 2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)
CH 4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N 2 O 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 CO 2e emissions from the Emergency Fire Pump Engine (EU

- 6):

CO 2 e emissions (ton/month) = [(Fuel Usage (gal/month) x Heat Content (mmbtu/gal)) x (CO 2 EF (lb/mmbtu) x CO 2 GWP + CH 4 EF (lb/mmbtu) x CH 4 GWP +IPL Eagle Valley Generating Station Page 70 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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N 2 O EF (lb/mmbtu) x N 2 O 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
CO 2 EF (lb/mmbtu) = 163 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for diesel fuel
CH 4 EF (lb/mmbtu) = 0.00661 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for diesel fuel

N 2 O EF (lb/mmbtu) = 0.00132 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for diesel fuel
CO 2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)
CH 4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N 2 O 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.1 0.4 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 complian ce 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 CO 2e 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 complian ce 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

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SECTION D.11 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: Insign ificant Activities

(e) One (1) evaporative cooling tower

, identified as emission unit U

- 7, rate d 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, PM 10 and PM 2.5 PSD BACT [326 IAC 2-2- 3] Pursuant to PSD/Significant Source Modification 10 9- 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, PM 10 and PM 2.5 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 (T DS ) shall be less than 5000 ppm.

(b) The PM, PM 10 and PM 2.5 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, PM 10 and PM 2.5 Control (a) In order to ensure compliance with Conditions D.11.1 - PM and PM 10 and PM 2.5 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, PM 10 , and PM 2.5 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) / 10 6

Where:

E = mass emission rate in lbs/hr for PM, PM 10 and PM 2.5; c = particle size fraction (c=1 for PM; 0.635 for PM 10 and 0.00213 for PM 2.5 ) ; 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

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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 req uest

.

(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

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SECTION D.12 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: Insignificant Activities

(f) Electrical Circuit Breakers containing sulfur hexafluoride (SF 6 ) 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

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(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 SF 6 emissions from all the circuit breakers shall not exceed 59.8 tons of CO 2 e 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

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SECTION D.13 EMISSIONS UNIT OPERATION C ONDITIONS

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
info rmation 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

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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

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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, PM 10 and PM 2.5 PSD BACT [326 IAC 2-2- 3] Pursuant to PSD/Significant Source Modification 109

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Turbine Lube Oil Demister Vents shall be as follows:

The PM, PM 10 and PM 2.5 emissions from the Turbine Lube Oil Demister Vents shall be the use of good design and operating practices

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SECTION E TITLE IV CONDITIONS

Oris Code: 991

Title IV Source Description:

(a) T wo (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 w et

- 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, exhaust ing
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 NO X and SO 2 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 NO X burners (LNB)

f or control of NO X 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 NO X and SO 2 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 NO X 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 NO X and SO 2 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 (COF A) for control of NO X 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

- NO X burners installed. Stack 3

- 1 has continuous emission monitoring systems (CEMS) for NO X and SO 2 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 NO

x 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

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* N ote: 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

Pro gram 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 applicab le 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

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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 MMB tu/hr; with NO

x 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.

*N ote: 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

w ith 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. 4 0 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 60.44 20IPL Eagle Valley Generating Station Page 79 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 d escriptive 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

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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 emergen cy 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 e ngine 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 60.4219IPL Eagle Valley Generating Station Page 81 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 cons idered 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 no t 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 63.6645IPL Eagle Valley Generating Station Page 82 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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SECTION F RESERVEDIPL Eagle Valley Generating Station Page 83 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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SECTION G Clean Air Interstate Rule (CAIR) Nitrogen Oxides Annual, Sulfur Dioxide, and Nitrogen Oxides Ozone Season Trading Programs – CAIR Permit for CAIR Unit s 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

de sign 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 NO X and SO 2 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 NO X burners (LNB) for
control of NO X 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 NO X and SO 2 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 NO X 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 NO X and SO 2 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 NO X 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

- NO X burners installed. Stack 3- 1 has continuous emission monitoring systems (CEMS) for NO X and SO 2 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 NO

x 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

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* N ote: 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 NO X source, CAIR SO 2 source, and CAIR NO X ozone season source and CAIR NO X unit, CAIR SO 2 unit, and CAIR NO X ozone season unit shall operate each source and unit in compliance with this CAIR permit.

(b) The CAIR NO X units, CAIR SO 2 units, and CAIR NO X 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)] [3 26 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 NO X source, CAIR SO 2 source, and CAIR NO X ozone season source and CAIR NO X uni t, CAIR SO 2 unit, and CAIR NO X 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 NO X source, CAIR SO 2 source, and CAIR NO X ozone season source with the CAIR NO X emissions limitation under 326 IAC 24 -1- 4(c), CAIR SO 2 emissions limitation under 326 IAC 24 -2- 4(c), and CAIR NO X 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 NO X source and each CAIR NO X unit at the source shall hold, in the source’s compliance account, CAIR NO X 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 NO X units at the source, as
determined in accordance with 326 IAC 24 -1- 11

.

(b) A CAIR NO X 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 NO X 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 NO X allowance was allocated.IPL Eagle Valley Generating Station Page 85 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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(d) CAIR NO X allowances shall be held in, deducted from, or transferred into or among CAIR
NO X 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 CA IR NO X allowance is a limited authorization to emit one (1) ton of nitrogen oxides in
accordance with the CAIR NO X annual trading program. No provision of the CAIR NO X annual trading program, the CAIR permit application, the CAIR permit, or an exemption

un der 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 NO X 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
NO X allowance to or from a CAIR NO X 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 SO 2 source and each CAIR SO 2 unit at the source shall hold, in the sou rce’s compliance account, a tonnage equivalent of CAIR SO 2 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 f rom all CAIR SO 2 units at the source, as determined in accordance with

326 IAC 24 -2- 10.

(b) A CAIR SO 2 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 SO 2 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 SO 2 allowance was allocated.

(d) CAIR SO 2 allowances shall be held in, deducted from, or transferred into or among CAIR
SO 2 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 SO 2 allowance is a limite d authorization to emit sulfur dioxide in accordance with
the CAIR SO 2 trading program. No provision of the CAIR SO 2 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 SO 2 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 SO 2 allowance to or
from a CAIR SO 2 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

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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 NO X ozone season source and each CAIR NO X ozone season unit at the source shall hold, in the source’s compliance account, CAIR NO X 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 NO X ozone season units at the source, as determined
in accordance with 326 IAC 24 -3- 11.

(b) A CAIR NO X 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 NO X 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 NO X ozone season allowance was allocated.

(d) CAIR NO X ozone season allowances shall be held in, deducted from, or transferred into or among CAIR NO X 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 NO X ozone season allowance is a limited authorization to emit one (1) ton of nitrogen oxides in accordance with the CAIR NO X ozone season trading program. No provision of the CAIR NO X 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 NO X 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
NO X ozone season allowance to or from a CAIR NO X ozone season source's co mpliance 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 CA IR NO X source and each CAIR NO X unit that emits nitrogen oxides during any control period in excess of the CAIR NO X emissions limitation shall do the following:

(1) Surrender the CAIR NO X 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 SO 2 source and each CAIR SO 2 unit that emits sulfur dioxide during any control period in excess of the CAIR SO 2 emissions limitation
shall do the following:

(1) Surrender the CAIR SO 2 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

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(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 NO X ozone season source and ea ch CAIR NO X ozone season unit that emits nitrogen oxides during any control period in excess of the
CAIR NO X ozone season emissions limitation shall do the following:

(1) Surrender the CAIR NO X 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 NO X source, CAIR SO 2 source, and CAIR NO X ozone season source and each CAIR NO X unit, CAIR SO 2 unit, and CAIR NO X 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
NO X unit, CAIR SO 2 unit, and CAIR NO X 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 -1-1 1,

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 NO X annual trading program, CAIR SO 2 trading program, and CAIR NO X ozone season trading program.

(d) Copies of all documents used to complete a CAIR permit application and any other
submission under the CAIR NO X annual trading program, CAIR SO 2 trading program, and
CAIR NO X ozone season trading program or to demonstrate compliance with the requirements of the CAIR NO X annual trading program, CAIR SO 2 trading program, and
CAIR NO X 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

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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 NO X source, CAIR SO 2 source, and
CAIR NO X ozone season source and each CAIR NO X unit, CAIR SO 2 unit, and CAIR NO X ozone season unit at the source shall submit the reports required under the CAIR NO X annual trading program, CAIR SO 2 trading program, and CAI R NO X 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 NO X annual trading program, CAIR SO 2 trading program, and CAIR NO X 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 NO X source, CAIR SO 2 source, and CAIR NO X ozone season source and each CAIR NO X unit, CAIR SO 2 unit, and CAIR NO X ozone season unit shall
be liable as follows:

(a) Each CAIR NO X source, CAIR SO 2 source, and CAIR NO X ozone season source and
each CAIR NO X unit, CAIR SO 2 unit, and CAIR NO X ozone season unit shall meet the requirements of the CAIR NO X annu al trading program, CAIR SO 2 trading program, and
CAIR NO X ozone season trading program, respectively

.IPL Eagle Valley Generating Station Page 89 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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(b) Any provision of the CAIR NO X annual trading program, CAIR SO 2 trading program, and
CAIR NO X ozone season trading program that applies to a CAIR NO X source, CAIR SO 2 source, and CAIR NO X ozone season source or the CAIR designated representative of a
CAIR NO X source, CAIR SO 2 source, and CAIR NO X ozone season source shall also apply to the owners and operators of such source and of the CAIR NO X unit s

, CAIR SO 2 unit s , and CAIR NO X ozone season unit s at the source

.

(c) Any provision of the CAIR NO X annual trading program, CAIR SO 2 trading program, and
CAIR NO X ozone season trading program that applies to a CAIR NO X unit, CAIR SO 2 unit,
and CAIR NO X ozone season unit or the CAIR designated representative of a CAIR NO X unit, CAIR SO 2 unit, and CAIR NO X 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 IA C 24 -3- 4(g)] [40 CFR 97.106(g)] [40 CFR 97.206(g)] [40 CFR 97.306(g)] No provision of the CAIR NO X annual trading program, CAIR SO 2 trading program, and CAIR NO X 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 NO X source, CAIR SO 2 source, and CAIR NO X ozone season source or CAIR NO X unit, CA IR SO 2 unit, and CAIR NO X 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 NO X source, CAIR SO 2 source, and CAIR NO X ozone season source, including all CAIR NO X units, CAIR SO 2 units, and CAIR NO X 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 NO X annual trading program, CAIR SO 2 trading program,
and CAIR NO X ozone season trading program concerning the source or any CAIR NO X unit, CAIR SO 2 unit, and CAIR NO X 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 NO X source, CAIR SO 2 source, and CAIR NO X 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

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### 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 sta tements 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

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## INDIANA DEPARTMENT OF ENVIRONMENTAL MANA GEMENT

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 EmergencyIPL Eagle Valley Generating Station Page 92 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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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 SO 2 VOC NO X 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 emis sions:

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

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## 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

Mai ling Address: 4040 Blue Bluff Road, Martinsville, IN 46151
Part 70 Permit No.: T 109

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- 00004 Facility: Units 1, 2, and PR

- 10
Parameter: SO 2 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) SO 2 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

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## INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT
OFFICE OF AIR QUALITY
COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

S ource 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 Em issions

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 re ported 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

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## 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
Fac ility: 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 qua rter.

 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

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## 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

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## 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 Addre ss: 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

c ompliance 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 d eviation 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

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## 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, 63 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 99 of 104 Martinsville, Indiana PSD/Significant Source Modification No. 109

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## 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 quar ter.

 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

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## 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 mont h.

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.

 Devia tion/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

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## 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.

QUA RTER : 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 D EPARTMENT 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 Deviation s:

Probable Cause of Deviation:

Response Steps Taken:

Form Completed By:

Title/Position:

Date:

Phone:

Atta ch 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 D c ] [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 Modificatio n No.: 109

- 32476

- 00004
Permit Reviewer: Josiah Balogun

**Subpart Dc**

**— Standards of Performance for Small Industrial** 

**- Commercial** 

**- Institutional Steam**  **Generating Units**

S OURCE : 72 FR 32759, June 13, 2007, unless otherwise noted.



## § **60.40c Applicability and dele**  **gation 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 J une 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 (SO

2 ) 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 defin ed 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 oth er 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 t his part.)IPL Eagle Valley Gen. Station Page 2 of 23
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(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 EP A 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 P M and NO

X standards under this subpart and the SO

2 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 st eam 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 durin g 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 durin g 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,

an d 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 mixture s, 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 pe r 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.

Combus tion 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 emission s 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 atm osphere 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 desu lfurization technology, atmospheric fluidized bed combustion technology, and oil hydrodesulfurization technology.IPL Eagle Valley Gen. Station Page 3 of 23
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Distillate oil means fuel oil that complies with the specifications for fuel oil numbers 1 or 2, as defined by the American Society for Testin g 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 Ame rican Society of Testing and Materials in ASTM D7467 (incorporated by reference, see § 60.17).

Dry flue gas desulfurization technology means a SO

2 control system that is located between the steam generating unit and the exhaust vent or stack, and that remo ves 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
defini tion 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 combus ts 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 SO

2 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 co mbustion; 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 pret reatment 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 pr eheated 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 genera ting 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; orIPL Eagle Valley Gen. Station Page 4 of 23
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(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 pe rcent 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 theoretic al SO

2 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 initiat e 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

m idnight 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 distil late oil with a potential
SO

2 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, t railers, 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 co nsecutive 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 duri ng 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 t he residence time requirements of this definition.IPL Eagle Valley Gen. Station Page 5 of 23
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Wet flue gas desulfurization technology means an SO

2 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 uni t to control emissions of PM or SO

2 .

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 f rom 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 (SO** 

**2** 

## ).

(a) Except as provided in paragraphs (b), (c), and (e) of this section, on an d 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 atmospher e from the affected facility any gases that contain SO

2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO

2 emission rate (90 percent reduction), nor cause to be discharged into the atmosphere from the affected facilit y any gases that contain SO

2 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 SO

2 in

ex cess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO

2 emission rate (90 percent reduction), nor cause to be discharged into the atmosphere from the affected facility any gases
that contain SO

2 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 fi rst, 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 contai n SO

2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 20 percent (0.20) of the potential SO

2 emission rate (80 percent reduction); nor

(ii) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO

2 in
excess of SO

2 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 SO

2 emissions limit or the 90 percent SO

2 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 SO

2 emissions shall
neither:

(i) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO

2 in excess of 50 percent (0.50) of the potential SO

2 emission rate (50 percent reduction); norIPL Eagle Valley Gen. Station Page 6 of 23
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(ii) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO

2 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 perc ent SO

2 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 SO

2 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 3 0 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 af ter 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 SO

2 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 t han 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, whichev er 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 SO

2 in excess of the followin g:

(1) The percent of potential SO

2 emission rate or numerical SO

2 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 inp ut 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 coa l and oil with any other fuel:IPL Eagle Valley Gen. Station Page 7 of 23
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Where:

E

s = SO

2 emission limit, expressed in ng/J or lb/MMBtu heat input;

K

a = 520 ng/J (1.2 lb/MMBtu);

K
b = 260 ng/J (0.60 lb/MMBtu);

K

c = 215 ng/J (0.50 lb/MMBtu);

H

a = 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];

H
b = Heat input from the combustion of coal in an affected facility subject to paragraph (b)(2) of this section, in J (MMBtu); and

H

c = Heat input from the combustion of oil, in J (MMBtu).

(f) Reduction in the potential SO

2 emission rate through fuel pretreatment is not credited toward the percent reduction requirement und er paragraph (b)(2) of this section unless:

(1) Fuel pretreatment results in a 50 percent (0.50) or greater reduction in the potential SO

2 emission rate;
and

(2) Emissions from the pretreated fuel (without either combustion or post

- combustion SO

2 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 SO

2 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.IPL Eagle Valley Gen. Station Page 8 of 23
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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 discha rged 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 ann ual 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 s ubject 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 wi th 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 th at 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, main tain, 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 sp ecified 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 require d 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 i nput, except as provided in paragraphs (e)(2), (e)(3), and (e)(4) of this section.IPL Eagle Valley Gen. Station Page 9 of 23
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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 F ebruary 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 facil ity 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, o il, 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 2 8, 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 exc ess 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 sulf ur 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 SO

2 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 § 6 0.8(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 SO

2 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 repre sentative 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 SO

2 emission limits under § 60.42c is based on the average

perc ent reduction and the average SO

2 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 SO

2 em ission 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 SO

2 emis sion rate (E
ho ) and theIPL Eagle Valley Gen. Station Page 10 of 23
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30

- day average SO

2 emission rate (E

ao ). 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 E

ao when using daily fuel sampling or Meth od 6B of appendix A of this part.

(e) If coal, oil, or coal and oil are combusted with other fuels:

(1) An adjusted E
ho (E
ho o) is used in Equation 19

- 19 of Method 19 of appendix A of this part to compute the adjusted E

ao (E

ao o). The E
ho o is computed usi ng the following formula:

Where:

E
ho o = Adjusted E
ho , ng/J (lb/MMBtu);

E
ho = Hourly SO

2 emission rate, ng/J (lb/MMBtu);

E

w = SO

2 concentration in fuels other than coa l 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 bei ng combusted. The owner or operator does not have to measure E

w if the owner or operator elects to assume E

w = 0.

X

k = Fraction of the total heat input from fuel combustion derived from coal and oil, as determined by applicable procedures in Method 19 of a ppendix 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 E

w or X
k if the owner or operator of the a ffected 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 SO

2 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 SO

2 emission rate is computed using the following
formula:

Where:

%P

s = Potential SO

2 emission rate, in percent;

%R

g = SO

2 removal efficiency o f the control device as determined by Method 19 of appendix A of this part, in percent;

and

%R
f = SO

2 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:IPL Eagle Valley Gen. Station Page 11 of 23
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(i) To compute the %P

s , an adjusted %R

g (%R

g o) is computed from E

ao o from paragraph (e)(1) of this section and an adju sted average SO

2 inlet rate (E
ai o) using the following formula:

Where:

%R

g o = Adjusted %R

g , in percent;

E

ao o = Adjusted E

ao , ng/J (lb/MMBtu); and

E
ai o = Adjusted average SO

2 inlet rate, ng/J (lb/MMBtu).

(ii) To compute E
ai o, an adjusted hourly SO

2 inlet rate (E

hi o) is used. The E

hi o is computed using the following formula:

Wh ere:

E

hi o = Adjusted E

hi , ng/J (lb/MMBtu);

E

hi = Hourly SO

2 inlet rate, ng/J (lb/MMBtu);

E

w = SO

2 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 ap pendix 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

X

k = 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 com pliance 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 sub ject to § 60.42c(h)(1), (2), or (3) where the owner or operator seeks to demonstrate compliance with the SO

2 standards based on fuel supplier certification, the performance test shall consist of the certification from the fuel supplier, as described in § 6 0.48c(f), as applicable.

(i) The owner or operator of an affected facility seeking to demonstrate compliance with the SO

2 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 f acility 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 ma ximum design heat input capacity provided by the manufacturer shall be used.IPL Eagle Valley Gen. Station Page 12 of 23
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(j) The owner or operator of an affected facility shall use all valid SO

2 emissions data in calculating %P

s and E
ho under paragraphs (d), (e), or (f) of this section, as applicabl e, 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 %P

s or E
ho pursuant to par agraphs (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 affecte d 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 stan dards 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 P M 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 c onjunction 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 con junction 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 vo lumes 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 (O

2 ) or carbon dioxide (CO

2 ) 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 lo cation.

(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:IPL Eagle Valley Gen. Station Page 13 of 23
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(i) The O

2 or CO

2 measurements and PM measurements obtained under this section, (ii) The dr y 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 operat or 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 hou rs. 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 inpu t 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 emission s 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 o f 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 complete d 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 determin ing 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 th is 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 appendi x 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 ave rages 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) [Reser ved]IPL Eagle Valley Gen. Station Page 14 of 23
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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 a rithmetic 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 paragrap h (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 O

2 (or CO

2 ) 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 th is part or Method 17 of appendix A

- 6 of this part shall be used; and

(ii) For O2 (or CO

2 ), 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 perform ed 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, rep airs, 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 dat a 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 subpa rt, 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 h ttp://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 owne r 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 SO

2 emission limits under § 60.42c shall install, calibrate, maintain, and operate a CEMS for measuring SO

2 concentrations and either O

2 or CO

2 concentrations at the outlet of the SO

2 control device (or the outlet of the steam generating unit if no SO

2 control device is used), and shall record the output of the system. The owner or operator of an affected facility subject to the percentIPL Eagle Valley Gen. Station Page 15 of 23
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reduct ion requirements under § 60.42c shall measure SO

2 concentrations and either O

2 or CO

2 concentrations at both the inlet and outlet of the SO

2 control device.

(b) The 1

- hour average SO

2 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 SO

2 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). Hourl y SO

2 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 i nstallation, 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 calibra tion 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 SO

2 CEMS at the inlet to the SO

2 control device s hall be 125 percent of the maximum estimated hourly potential SO

2 emission rate of the fuel combusted, and the span value of the SO

2 CEMS at the
outlet from the SO

2 control device shall be 50 percent of the maximum estimated hourly potential SO

2 emission r ate 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 SO

2 CEMS at the outlet from the SO

2 control device (or outlet of the steam generating unit if
no SO

2 contro l device is used) shall be 125 percent of the maximum estimated hourly potential SO

2 emission rate of the fuel combusted.

(d) As an alternative to operating a CEMS at the inlet to the SO

2 control device (or outlet of the steam generating unit if no SO

2 con trol device is used) as required under paragraph (a) of this section, an owner or operator may elect to determine the average SO

2 emission rate by sampling the fuel prior to combustion. As an alternative to operating a CEMS at the outlet from the SO

2 contr ol device (or outlet of the steam generating unit if no SO

2 control device is used) as required under paragraph (a) of this section, an owner or operator may elect to determine the average SO

2 emission rate by using Method 6B of appendix A of this part. Fu el 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

proce dures for converting these measurements into the format to be used in calculating the average SO

2 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 ste am 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 sh ipment 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 ofIPL Eagle Valley Gen. Station Page 16 of 23
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subsequent oil shipments is low enough to cause the 30

- day roll ing 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 SO

2 at the inlet or
outlet of the SO

2 control system. An initial stratification test is required to verify t he 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 SO

2 and CO

2 measurement train operated at the candidate location and a second similar train operated accordi ng 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

dem onstrate compliance with the SO

2 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

- f ired 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 n ot 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 ap plicable 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 sectio n. 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 combust ed, whichever is later;IPL Eagle Valley Gen. Station Page 17 of 23
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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 equ al 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 s tandard 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 con duct 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 visibl e 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 procedur es 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 m onitoring 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

Vi sible 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 Progr ams 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.IPL Eagle Valley Gen. Station Page 18 of 23
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(c) Owners and operators of an affected facilities that burn only distillate oil that conta ins 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 ar e 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, a nd 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 fo r 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 technolog y (except a wet scrubber) for reducing PM, SO

2 , 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 f rom 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 demons trate 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 C O 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 pe r 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 usin g 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

i nput 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 avera ge 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

eq uipment 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 lev el 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 andIPL Eagle Valley Gen. Station Page 19 of 23
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time during which t he 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 ope rate 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 predict ive 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 weigh t 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 para meters 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. 1 6, 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 notificat ion 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 f or 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 SO

2 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 Administra tor 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 A dministrator.

(b) The owner or operator of each affected facility subject to the SO

2 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 perfo rmance tests and, if applicable, the performance evaluation of the CEMS and/or COMS using the applicable performance specifications in appendix B of this part.IPL Eagle Valley Gen. Station Page 20 of 23
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(c) In addition to the applicable requirements in § 60.7, the owner or operator of an affected f acility 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 s pecified 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 participa ting 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 info rmation 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) Cop ies 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 applic able 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 SO

2 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 SO

2 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 da tes covered in the reporting period.

(2) Each 30

- day average SO

2 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 SO

2 emission rate calculated during the reporting period, ending with the last 30

- day period; reasons for any noncompliance with the em ission standards; and a description of the corrective actions taken.IPL Eagle Valley Gen. Station Page 21 of 23
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(4) Identification of any steam generating unit operating days for which SO

2 or diluent (O

2 or CO

2 ) data have not been obtained by an approved method for at least 75 percent of the opera ting 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 d ata; 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 determin ation, 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 th e 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 t his 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 analys is 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.IPL Eagle Valley Gen. Station Page 22 of 23
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(3) For coal:

(i) The name of the coal supplier;

(ii) The location of the coal when the samp le 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 pla nt, 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 th e 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 suppl ier 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 par agraphs (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 SO

2 standard, fuels not subject to an emissions standard (excluding opa city), 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, disti llate oil meeting the most current requirements in § 60.42C to use fuel certification to demonstrate compliance with the SO

2 standard, and/or fuels, excluding coal and residual oil, not subject to an emissions standard (excluding opacity) may elect to

reco rd 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 cap acity 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 capacit y 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.IPL Eagle Valley Gen. Station Page 23 of 23
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(j) The reporting period fo r 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 Cover **s**

**§ 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 1 1, 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 st ationary 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 a n 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 40IPL E agle Valley Gen. Station Page 2 of 23
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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 subp art 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 non

emergency 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 t han 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 non

emergency stationary CI ICE with a maximum engine power greater than 2,237 KW (3,00 0 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 mod el year and later non

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 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 la ter 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 to the certification emission standards for new marine CI engines in 40 CFR 94.8, as applicable, for all polluta nts, 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 specif ied 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 y ear and later engines.IPL E agle Valley Gen. Station Page 3 of 23
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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 f or 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 displacem ent 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 p ollutants, 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 pollutan ts.

(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, stati onary 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 engine**  **s 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 u seful 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

- 200 7 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 pre

2007 model year non

- emergency stationary CI ICE with a disp lacement 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 disp lacement 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 dis placement 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 (NO X ) emissions by 90 percent or more, or limit the emissions of NO X in the stationary CI

intern al 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).IPL E agle Valley Gen. Station Page 4 of 23
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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

yea r 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 NO X emissions by 90 percent or more, or limit the emissions of NO X in th e 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

sta ndards 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 subpa rt 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 t he 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.IPL E agle Valley Gen. Station Page 5 of 23
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Owners and operators must demonstrate in their peti tion 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 Admin istrator.

(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 s tationary 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 Dece mber 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 mod el 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 mee t 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 m eet 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 pe r 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 operator s 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 st ationary 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 non

resettable 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 aIPL E agle Valley Gen. Station Page 6 of 23
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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 certi fied 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 lat er 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 t o 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 par t 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 m ust 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) Statio nary 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 l abeled 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 engi nes, 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 nonro ad 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 suc h 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 wo uld apply to engines for export and the manufacturers must label such engines according to 40 CFR 1068.230.IPL E agle Valley Gen. Station Page 7 of 23
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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 (inc luding 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 th e 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 pr ovisions 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 cont ains 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) Manuf acturers 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 non

emergency 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 e mergency 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 change d 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 ma y 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 engin e 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 a**  **m 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'sIPL E agle Valley Gen. Station Page 8 of 23
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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 ma nufacturer. 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 spec ified 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 demonst rate 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. T he 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 stand ards.

(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 inte rnal 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 engin e 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 m odel 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 s pecified 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 NO X and 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 NO X and 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 m onitor these parameters, as well as the relative accuracy and precision of these methods and instruments; andIPL E agle Valley Gen. Station Page 9 of 23
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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 op erated 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 re adiness 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 emer gency 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 meth ods 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) E xhaust 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 e mission 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,

det ermined 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, st ationary 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), §60.4 205(a), or §60.4205(c), determined from the equation in paragraph (c) of this section.

Where:IPL E agle Valley Gen. Station Page 10 of 23
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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 perc ent 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 requi red 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:

C i = concentration of NO X or PM at the control d evice inlet,

C
o = concentration of NO X or PM at the control device outlet, and

R = percent reduction of NO X or PM emissions.

(2) You must normalize the NO X or PM concentrations at the inlet and outlet of the control device to a dry basis and to 15 percent oxyg en (O 2 ) using Equation 3 of this section, or an equivalent percent carbon dioxide (CO 2 ) using the procedures described in paragraph (d)(3) of this section.

W here:

C adj = Calculated NO X or PM concentration adjusted to 15 percent O 2

.

C d = Measured concentration of NO X or PM, uncorrected.IPL E agle Valley Gen. Station Page 11 of 23
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5.9 = 20.9 percent O 2 −15 percent O 2 , the defined O 2 correction value, percent.

%O 2 = Measured O 2 concentration, dry basis, percent.

( 3) If pollutant concentrations are to be corrected to 15 percent O 2 and CO 2 concentration is measured in lieu of
O 2 concentration measurement, a CO 2 correction factor is needed. Calculate the CO 2 correction factor as described in paragraphs (d)(3)(i) through (i ii) of this section.

(i) Calculate the fuel

- specific F o value for the fuel burned during the test using values obtained from Method 19, Section 5.2, and the following equation:

Where:

F
o = Fuel factor based on the ratio of O 2 volume to the ultimate CO 2 volume produced by the fuel at zero percent excess air.

0.209 = Fraction of air that is O 2 , percent/100.

F d = Ratio of the volume of dry effluent gas to the gross ca lorific value of the fuel from Method 19, dsm 3 /J (dscf/10 6 Btu).

F
c = Ratio of the volume of CO 2 produced to the gross calorific value of the fuel from Method 19, dsm 3 /J (dscf/10 6 Btu).

(ii) Calculate the CO 2 correction factor for correcting measurement dat a to 15 percent O 2 , as follows:

Where:

X CO2 = CO 2 correction factor, percent.

5.9 = 20.9 percent O 2 −15 percent O 2 , the defined O 2 correction value, percent.

(ii i) Calculate the NO X and PM gas concentrations adjusted to 15 percent O 2 using CO 2 as follows:

Where:

C adj = Calculated NO X or PM concentration adjusted to 15 per cent O 2

.

C d = Measured concentration of NO X or PM, uncorrected.

%CO 2 = Measured CO 2 concentration, dry basis, percent.IPL E agle Valley Gen. Station Page 12 of 23
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(e) To determine compliance with the NO X mass per unit output emission limitation, convert the concentration of
NO X in the engine exhaust using Equation 7 of this section:

Where:

ER = Emission rate in grams per KW

- hour.

C d = Measured NO X concentration in ppm.

1.912x10 −3 = Conversion constant for ppm NO X to 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.

C adj = 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 a re 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.IPL E agle Valley Gen. Station Page 13 of 23
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(i) Name and address of the owner or operator;

(ii) The address of the af fected 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 eng ine, 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 t he emergency engine does not meet t he 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 co rrective 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, o**  **r 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 stationar y 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 ar e 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 Fe deral Aid Highway System should refer to 40 CFR part 69 to determine the diesel fuel requirements applicable to such engines.IPL E agle Valley Gen. Station Page 14 of 23
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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 th e 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 Ai r 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 em**  **ission 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 Provis ions 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 an y ancillary components and sub

components 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 wit h 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 o peration 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 loc al 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 anIPL E agle Valley Gen. Station Page 15 of 23
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electric grid or that supply powe r 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 station ary 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

man ufactures 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 eng ine 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

mu st 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 a fter 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 p arts 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 I CE 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 competit ion. 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 Standa**  **rds for Stationary Pre**

  ** 2007 Model Year Engines With a Displacement of <10 Liters per Cylinder**IPL E agle Valley Gen. Station Page 16 of 23
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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 6 0.4205(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 wi th a displacement of <10 liters per cylinder in g/KW

- hr (g/HP

- hr)

NMHC + NO X 

### HC NO X 

### 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 Displac**  **ement 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)IPL E agle Valley Gen. Station Page 17 of 23
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### Model year(s) NO X 

### + 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 + NO X 

### 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)IPL E agle Valley Gen. Station Page 18 of 23
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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 revol utions 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 li mitations 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:]IPL E agle Valley Gen. Station Page 19 of 23
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### Mode No. Engine speed 1 

### 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** 
**Station ary 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 requi rement 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

NO X 

### emissions 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 O 2 

### at 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

O 2 

### concentration must

be made at the same

time as the

measurements for

NO X 

### concentration.

iii. If necessary,

measure moisture

content at the inlet

and outlet of the control device; and, (3) Method 4 of 40 CFR p art 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

NO X 

### concentration.IPL E agle Valley Gen. Station Page 20 of 23
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### §60.17)

iv. Measure NO X 

### at
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) NO X 

### concentration must be at 15 percent

O 2 

### , dry basis. Resu lts

of this test consist of the average of the three

1

- hour or longer runs.

b. Limit the

concentration of

NO X 

### in the stationary CI

internal

combustion engine exhaust. i. Select the sampling port

location and the

number of traverse points; (1) Method 1 o r 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

O 2 

### concentration of the stationary

internal combustion engine exhaust at the sampling port

locati on; and, (2) Method 3, 3A,

or 3B of 40 CFR part 60, appendix

A (b) Measurements to

determine

O 2 

### concentration must

be made at the same

time as the

measurement for

NO X 

### concentration.

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 mus t be made

at the same time as the

measurement for

NO X 

### concentration.

iv. Measure NO X 

### at
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 (in corporated (d) NO X 

### concentration must be at 15 percent

O 2 

### , dry basis. Results

of this test consist of the average of the three

1

- hour or longer runs.IPL E agle Valley Gen. Station Page 21 of 23
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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 O 2 

### at 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

O 2 

### concentration 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

cont rol 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) Meth od 5 of 40 CFR part 60, appendix A (d) PM concentration must be at 15 percent

O 2 

### , 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 engin e 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

O 2 

### concentration 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

O 2 

### concentration must

be made at the same

time as the

measurements fo r PM

concentration.

iii. If necessary, (3) Method 4 of (c) Measurements toIPL E agle Valley Gen. Station Page 22 of 23
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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 m ade

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

O 2 

### , dry basis. Results

of t his 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

P rovisions

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 De termination 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 displ acement 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.IPL E agle Valley Gen. Station Page 23 of 23
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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 Incorpo rations 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 estab lishes 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 commen ced 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 thi s 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 (NO X ) emission limits in §60.4320.IPL Eagle Valley Gen. Station Page 2 of 18
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(b) Stationary combustion turb ines 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
NO X emission limits in §60.4320 on a case

- by

- case basis as dete rmined 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/st ands 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 (NO X ) and sulfur dioxide (SO 2 ).



## § **60.4320 What emission limits must I meet for nitro**  **gen oxides (NOX)?**

(a) You must meet the emission limits for NO X specified 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 NO X

.



## § **60.4325 What emissio**  **n 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 perce nt 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 corres ponding 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 (SO**  **2**



## )?

(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 disc harged into the atmosphere from the subject stationary combustion turbine any gases which contain SO 2 in 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 combusti on turbine any fuel which contains total potential sulfur emissions in excess of 26 ng SO 2 /J (0.060 lb SO 2 /MMBtu) heat input. If your turbine simultaneously fires multiple fuels, each fuel must meet this requirement; or

(3) For each stationary combustion t urbine 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 SO 2 in excess of 65 ng SO 2 /J (0.15 lb SO 2 /M MBtu) 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:IPL Eagle Valley Gen. Station Page 3 of 18
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(1) You must not cause to be discharged into the atmosphere from the subject stationary combustion turbine any gases which contain SO 2 in 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 SO 2 /J (0.42 lb SO 2 /MMBtu) heat input. If your turbine simultaneously fires multiple fuels, each fuel m ust 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 NO X emissions limits by measuring the emissions combined with the
emissions from th e 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 affecte d 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 NO X emissions, 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 follo ws:

(1) Install, certify, maintain, and operate a continuous emission monitoring system (CEMS) consisting of a
NO X monitor and a diluent gas (oxygen (O 2 ) or carbon dioxide (CO 2 )) monitor, to determine the hourly NO X emission rate in parts per million (ppm) o r 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 complyi ng 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).IPL Eagle Valley Gen. Station Page 4 of 18
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## § **60.43 40**  **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 NO X emissions, you must perform annual performance tests in accordance with §60.4400 to demonstrate continuous compliance. If the NO X emission result from the performance test is less than or equal to 75 percent of the NO X emission limit for the turbine, you may reduce the frequency of subsequent performance tests to once every 2 years (no more than 26 ca lendar months following the previous performance test). If the results of any subsequent performance test exceed 75 percent of the NO X emission limit for the turbine, you must resume annual performance tests.

(b) As an alternative, you may install, calibrat e, 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 sel ective catalytic reduction (SCR) controls, you must define parameters indicative of the unit's NO X formation characteristics, and you must monitor these parameters continuously.

(ii) For any lean premix stationary combustion turbine, you must continuously m onitor the appropriate parameters to determine whether the unit is operating in low

- NO X mode.

(iii) For any turbine that uses SCR to reduce NO X emissions, you must continuously monitor appropriate parameters to verify the proper operation of the emission con trols.

(iv) For affected units that are also regulated under part 75 of this chapter, with state approval you can monitor the
NO X emission 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 equipmen t, if I choose to use this option?** 

If the option to use a NO X CEMS is chosen:

(a) Each NO X diluent 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 NO X diluent 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 NO X monitor and the diluent monitor must complete a minimum of o ne 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 N O X emission 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.IPL Eagle Valley Gen. Station Page 5 of 18
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(d) Each watt meter, steam flow meter, and each pressure or temperature measurement device shall be installed, calibrated, maintained, and op erated 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 a nd 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 av erage, as described in §60.4345(b), is obtained for both
NO X and diluent monitors, the data acquisition and handling system must calculate and record the hourly
NO X emission rate in units of ppm or lb/MMBtu, using the appropriate equation from method 19 in a ppendix A of this part. For any hour in which the hourly average O 2 concentration exceeds 19.0 percent O 2 (or the hourly average
CO 2 concentration is less than 1.0 percent CO 2 ), a diluent cap value of 19.0 percent O 2 or 1.0 percent CO 2 (as applicable) may be us ed in the emission calculations.

(c) Correction of measured NO X concentrations to 15 percent O 2 is not allowed.

(d) If you have installed and certified a NO X diluent CEMS to meet the requirements of part 75 of this chapter, states can approve that only qualit y 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 monito ring 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 NO X emission rates, in units of the emission sta ndards 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 NO X emission rate, in lb/MWh,

(NO X ) h = hourly NO X emission 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 mechanicalIPL Eagle Valley Gen. Station Page 6 of 18
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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, an d 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 out put, 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 10 6 = 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 = NO X emission rate in lb/MWh,

(NO X )
m = NO X emission 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 wit hout 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 w ith 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).IPL Eagle Valley Gen. Station Page 7 of 18
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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 v alues 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 k eep on

- site a parameter monitoring plan which explains the procedures used to document proper operation of the NO X emission controls. The plan must:

(1) Include the indicators to be monitored and show there is a significant relationship to emissions and pro per operation of the NO X emission 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 yo u 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 vali dity 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 p urposes 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 dif ferences. 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 whi ch 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, t esting 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 ca se, 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 a s 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,

the re 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 NO X emission measurement methodology in appendix E to part 75, y ou 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 appe ndix B to part 75 of this chapter.



## § **60.4360 How do I determine the total sulfur content of the turbine's** 
**combustion fuel?**IPL Eagle Valley Gen. Station Page 8 of 18
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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 conten t 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 SO 2 /J (0.060 lb SO 2 /MMBtu) heat input for units located in continental areas and 180 ng SO 2 /J (0.42 lb SO 2 /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 benef it. 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 t otal 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 SO 2 /J (0.060 lb SO 2 /MMBtu) heat input for continental areas and has potenti al sulfur emissions of less than less than 180 ng SO 2 /J (0.42 lb SO 2 /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 SO 2 /J (0.060 lb SO 2 /MMBtu) heat i nput for continental areas or 180 ng SO 2 /J (0.42 lb SO 2 /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 t o 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 gase ous 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 cont ent 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 pri or 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 req uired 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.IPL Eagle Valley Gen. Station Page 9 of 18
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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 procedu res 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 t han 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 u ntil 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 u se 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 7 20 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 gra ins/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 ac cordance 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 def**  **ined for**IPL Eagle Valley Gen. Station Page 10 of 18
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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 u nit 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 du ring 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 NO X control 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 un it operating period in which the 4

- hour or 30

- day rolling average NO X emission rate exceeds the applicable emission limit in §60.4320. For the purposes of this subpart, a “4

- hour rolling average
NO X emission rate” is the arithmetic average of the average NO X emission 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
NO X emission rates immediately preceding that unit operating hour. Calculate the rolling average if a v alid
NO X emission rate is obtained for at least 3 of the 4 hours. For the purposes of this subpart, a “30

- day rolling average
NO X emission rate” is the arithmetic average of all hourly NO X emission data in ppm or ng/J (lb/MWh) measured by

the continuous emiss ion 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 NO X emissions rates for the preceding 30 unit operating days if a valid NO X emission 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: NO X concentration, CO2 or O 2 concentration, 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 ba sed 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
NO X emission controls:

(1) An excess emission is a 4

- hour rolling unit o perating 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** 
**SO 2**  

## ?

If you choose the option to monitor the sulfur content of the fuel, excess emissions and monitoring downtime are
defined as follows:IPL Eagle Valley Gen. Station Page 11 of 18
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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 beginnin g 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 as

delivered 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 de velopment turbine?** 

(a) If you operate an emergency combustion turbine, you are exempt from the NO X limit and must submit an initial report to the Administrator stating your case.

(b) Combustion turbines engaged by manufacturers in research and development o f equipment for both combustion turbine emission control techniques and combustion turbine efficiency improvements may be exempted from the
NO X limit 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 NO X performance 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 t hat you may use to conduct the performance tests. For each test run:

(i) Measure the NO X concentration (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, concurr ently 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 NO X emission rate:

Where:

E = NO X emission rate, in lb/MWhIPL Eagle Valley Gen. Station Page 12 of 18
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1.194 × 10 −7 = conversion constant, in lb/dscf

- ppm

(NO X )
c = average NO X concentration for the run, in ppm

Q std = stack gas volumetric flow rate, in ds cf/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 he at 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 NO X and 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 an d thermal output of the unit. Use EPA Method 19 in appendix A of this part to calculate the
NO X emission rate in lb/MMBtu. Then, use Equations 1 and, if necessary, 2 and 3 in §60.4350(f) to calculate the
NO X emission rate in lb/MWh.

(2) Sampling traverse poi nts for NO X and (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, w ith 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) Notwithstandin g 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 NO X and 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 perf ormance test:

(A) If each of the individual traverse point NO X concentrations 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
CO 2 ( or O 2 ) 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 NO X concentration during the stratification test; or

(B) For turbines with a NO X standard greater than 15 ppm @ 15% O 2 , 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 NO X concentrations is within ±5 percent of the mean concentration for all traverse points, or the individual traverse point dilue nt concentrations differs by no more than ±3ppm or ±0.3 percent CO 2 (or O 2 ) from the mean for all traverse points; or

(C) For turbines with a NO X standard less than or equal to 15 ppm @ 15% O 2 , 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
NO X concentrations 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 ±1p pm or ±0.15 percent CO 2 (or O 2 ) 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 beIPL Eagle Valley Gen. Station Page 13 of 18
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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 b ackup 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
NO X emissions 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 NO X with no additional post

- combustion NO X control 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 NO X emission

limi t.

(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 NO X emission rate at each tested level meets the applicable emission limit in §60.432 0.

(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 NO X - diluent CEMS under §60.4345, then the initial performance test required unde r §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 ambi ent 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 da ta both to demonstrate compliance with the applicable NO X emission 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 ach ieved if the arithmetic average of all of the
NO X emission 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 para meters?** 

If you have chosen to monitor combustion parameters or parameters indicative of proper operation of NO X emission controls in accordance with §60.4340, the appropriate parameters must be continuously monitored and recorded during each run of the init ial 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?**IPL Eagle Valley Gen. Station Page 14 of 18
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(a) You mus t conduct an initial performance test, as required in §60.8. Subsequent SO 2 performance 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 SO 2 concentration (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 Exha ust 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 a nd 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 SO 2 emission rate:

Where:

E = SO 2 emission rate, in lb/MWh

1.664 × 10 −7 = conversion constant, in lb/dscf

- ppm

(SO 2 )
c = average SO 2 concentration for the run, in ppm

Q std = stack gas volumetric flow rate, in dscf/hr

P = gross electrical and mechanical energy output of th e 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
mechani cal 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 SO 2 and 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, u sing 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 SO 2 emission rate in lb/MMBtu. Then, use Equations 1 and, if necessary, 2 and 3 in §60.4350(f) to
calculate the SO 2 emission rate in lb/MWh.

(b) [Reserved]



## DefinitionsIPL Eagle Valley Gen. Station Page 15 of 18
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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 CO 2

.

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 t emperature 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 com bustion 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 tu rbine, 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 t urbines 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 flo od, 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

sho uld 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 NO X emissions are higher than the applicable emission limit in §60.4320; (2) the total su lfur 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 affe cted 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 mech anical 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.IPL Eagle Valley Gen. Station Page 16 of 18
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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 an d 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 a t 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

stan dard 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

recove r 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 comb ustion 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, ho wever, 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 f or 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 Celsi us 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** IPL Eagle Valley Gen. Station Page 17 of 18
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## New Stationary Combustion Turbines

Combustion turbine type Combustion

turbin e heat input at peak

load (HHV) NO X 

### emission standard

New turbine firing natural gas, electric generating ≤ 50 MMBtu/h 42 ppm at 15 percent

O 2 

### or 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

O 2 

### or 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

O 2 

### or 150 ng/J of useful output (1.2 lb/MWh).

New, modified, or reconstructed turbine firing natural gas > 850 MM Btu/h 15 ppm at 15 percent

O 2 

### or 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

O 2 

### or 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

O 2 

### or 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

O 2 

### or 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

O 2 

### or 160 ng/J of useful output (1.3 lb/MWh).

Modified or reconstructed turbine ≤ 50 MMBtu/h 150 ppm at 15 percent

O 2 

### or 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

O 2 

### or 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

O 2 

### or 590 ng/J of usefulIPL Eagle Valley Gen. Station Page 18 of 18
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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 tur bines, and turbine operating at temperatures less than 0 °F ≤ 30 MW output 150 ppm at 15 percent

O 2 

### or 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 p ercent 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

O 2 

### or 590 ng/J of useful output (4.7 lb/MWh).

Heat recovery units operating independent of the

combu stion turbine All sizes 54 ppm at 15 percent

O 2 

### or 110 ng/J of useful output (0.86 lb/MWh).

## A ttachment 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 Locati on: 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 Modific ation No.: 109

- 32476

- 00004
Permit Reviewer: Josiah Balogun

**Subpart ZZZZ**

**— National Emissions Standards for Hazardous Air Pollutants for Stationary**  **Reciprocating Internal Combustion Engines**

S OURCE : 69 FR 33506, June 15, 2004, unless otherwise noted.



## What T **his 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 t**  **o 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 co mbustion 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.IPL Eagle Valley Gen. Station Page 2 of 72 Martinsville, Indiana TV Permit No.: 1 09

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(d) I f 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 s tationary 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 specifie d 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 are a 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 sour ce 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 ra ting 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 rati ng 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 sou rce of HAP emissions, a stationary RICE is existing if you commenced construction or reconstruction of the stationary RICE before June 12, 2006.IPL Eagle Valley Gen. Station Page 3 of 72 Martinsville, Indiana TV Permit No.: 1 09

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(iv) A change in ownership of an existing stationary RICE does not make that stationary RICE a new or

reconstru cted 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 s tationary 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 H AP 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 reconstr ucted 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 recons tructed 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 re quirements 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 co mbusts 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;IPL Eagle Valley Gen. Station Page 4 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 av ailable 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 st ationary 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 Reg ulations 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 e ngines 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 reconstructe d 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 le ss 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 33 506, 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 y ou 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 limitatio ns 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 le ss 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 requiremen ts 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 anIPL Eagle Valley Gen. Station Page 5 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 majo r 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 ra ting 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 yo ur 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 appli cable 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 wit h 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]IPL Eagle Valley Gen. Station Page 6 of 72 Martinsville, Indiana TV Permit No.: 1 09

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## Emission and Operating Limitations

**§ 63.6600**  **What emission limitations an d 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 th e 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 ratin g 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 thi s 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 th e 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 emis sions, 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 lim**  **itations 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 numerica l 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]IPL Eagle Valley Gen. Station Page 7 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 mus t 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 th e 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 oper ating 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 thi s 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 no t 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 (A MHS), 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.IPL Eagle Valley Gen. Station Page 8 of 72 Martinsville, Indiana TV Permit No.: 1 09

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- 00 004 Permit Reviewer: Josiah Balogun

(c) If you own or operate an existing stationary non

- emerg ency 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 emi ssion 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 a s 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 install ed, 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 t hat 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 syste m 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 Januar y 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 instal lation 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 4S LB 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 r emote 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 stationa ry 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.IPL Eagle Valley Gen. Station Page 9 of 72 Martinsville, Indiana TV Permit No.: 1 09

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- 00 004 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 requiremen**  **ts 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 d epleted.

(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, e xcept 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 i n 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 g eneral 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 a ny 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]IPL Eagle Valley Gen. Station Page 10 of 72 Martinsville, Indiana TV Permit No.: 1 09

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- 00 004 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 sourc**  **e 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 ot her 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 const ruction 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 propos ed 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 be tween 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 n ot 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 con ducted 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 c hanges 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) T he 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 initia l 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** IPL Eagle Valley Gen. Station Page 11 of 72 Martinsville, Indiana TV Permit No.: 1 09

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- 00 004 Permit Reviewer: Josiah Balogun


## 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 d ate 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 loca ted 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 em issions 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 te st 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 r esults 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 t**  **ests?**

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 conduc t each performance test in Tables 3 and 4 of this subpart that applies to you.IPL Eagle Valley Gen. Station Page 12 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 station ary 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 separat e 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 t he percent reduction requirement:



### View or download PDF

Where:

C

i = concentration of carbon monoxide (CO), total hydrocarbons (THC), or formaldehyde at the control device inlet,

C

o = 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, o r 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 (CO

2 ). If pollutant concentrations are to be corrected to 15 percent oxygen and CO

2 concentration is measured in lieu of oxygen concentration measurement, a CO

2 correction factor is needed. Calculate the CO

2 correction factor as described in paragraphs (e)(2)(i) through (iii) of this section.

(i) Calculate the fuel

- specific F

o value for the fuel burned during the test using values obtained from Method 19, Section 5.2, and the following equation:IPL Eagle Valley Gen. Station Page 13 of 72 Martinsville, Indiana TV Permit No.: 1 09

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- 00 004 Permit Reviewer: Josiah Balogun



### View o r download PDF

Where:

F

o = Fuel factor based on the ratio of oxygen volume to the ultimate CO

2 volume produced by the fuel at zero percent

excess air.

0.209 = Fraction of air that is oxygen, percent/100.

F
d = Ratio of the volume of dry effluent gas to th e gross calorific value of the fuel from Method 19, dsm 3 /J (dscf/10 6 Btu).

F

c = Ratio of the volume of CO

2 produced to the gross calorific value of the fuel from Method 19, dsm 3 /J (dscf/10 6 Btu)

(ii) Calculate the CO

2 correction factor for correcting mea surement data to 15 percent O

2 , as follows:



### View or download PDF

Where:

X
CO2 = CO

2 correction facto r, percent.

5.9 = 20.9 percent O

2 — 15 percent O

2 , the defined O

2 correction value, percent.

(iii) Calculate the CO, THC, and formaldehyde gas concentrations adjusted to 15 percent O

2 using CO

2 as follows:



### View or download PDF

Where:

C adj = Calculated concentration of CO, THC, or formaldehyde adjusted to 15 percent O

2.

C

d = Measured concentration of CO, THC, or formaldehyde, uncorrected.

X
CO2 = CO

2 correction factor, percent.

%CO

2 = Measured CO

2 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 compl y 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, y ou 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 a fter 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.IPL Eagle Valley Gen. Station Page 14 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 pa rameters 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 met hods 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 ins truments 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 est ablishing 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 wou ld 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 appl ication. 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 p urchase, 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 expla ined. 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.IPL Eagle Valley Gen. Station Page 15 of 72 Martinsville, Indiana TV Permit No.: 1 09

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- 00 004 Permit Reviewer: Josiah Balogun

[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 O

2 or CO

2 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 i nlet 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 performa nce 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 CO

2 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 li mitations 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 speci fied 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 acqu isition 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) Ongo ing 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).IPL Eagle Valley Gen. Station Page 16 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 tempe rature 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 pro cedures 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 whi ch 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, yo u 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

- trea tment control device (if any) according to the manufacturer's emission

related written instructions or develop your own maintenance plan which must provide to the extent practicable for the maintenance and operation of the engine in a manner consistent wit h 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 o f 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 ra ting 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 loc ated 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;IPL Eagle Valley Gen. Station Page 17 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 r ating 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 ma intenance 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 § 63.660 3(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 t hat 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 a nd 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 subpa rt 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 an alysis 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 engin e 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 subpar t or in items 5, 6, 7, 9, or 11 of Table 2d to thisIPL Eagle Valley Gen. Station Page 18 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 sam e 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

p ercent 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 wi thin 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, whicheve r 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 F R 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 performan ce 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 require ments 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 formaldeh yde. 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 demonstratio n 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

acc ording 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 c onsist 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.IPL Eagle Valley Gen. Station Page 19 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 O

2 using one of the O

2 measurement methods specified in Table 4 of this subpart.
Measurements to determine O

2 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 O

2 emissions simultaneously at the inlet and outlet of the control
device.

[69 FR 33506, June 15, 2004, as amended at 78 FR 6704, Ja n. 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 monitor ing 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 3 3506, 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 emis sion 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 wh ich 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 subpar t. 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 4SR B stationary RICE with a site rating of more than 500 HP located at an area source of HAP that are notIPL Eagle Valley Gen. Station Page 20 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 comp liance 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

sub part, 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 O

2 usin g one of the O

2 measurement methods specified in Table 4 of this subpart.
Measurements to determine O

2 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 p ercent reduction requirement, you must
measure CO or THC emissions and O

2 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 be ing 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

stati onary 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 stationa ry 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 emi ssions, 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 sta tionary 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

.IPL Eagle Valley Gen. Station Page 21 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 u nder 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 prohibit ed. 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) Ther e 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 fo r 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 maintai ns 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 Reliab ility 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 Coordin ator, 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 standar d 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 hou rs 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 i n 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 provi ded 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 non

emergency 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.IPL Eagle Valley Gen. Station Page 22 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 t o 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 o f 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 ex isting 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.IPL Eagle Valley Gen. Station Page 23 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 ra ting 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 subm it 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 stationa ry 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 Complianc e 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 30 th 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 n on

- 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 stat e 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.IPL Eagle Valley Gen. Station Page 24 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 d elivered 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 rep ort 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 la ter 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 sourc e 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 deliv ered 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 d uring a malfunction of anIPL Eagle Valley Gen. Station Page 25 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 em ission 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 stati onary 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 a n 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 thi s 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 du ring 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 RI CE 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 descripti on of the CMS.IPL Eagle Valley Gen. Station Page 26 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 CF R 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 sub part 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 affe cted 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 landfi ll 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 § 63.664 0(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 en gine is contractually obligated to be available for the purposes specified in § 63.6640(f)(2)(ii) and (iii).IPL Eagle Valley Gen. Station Page 27 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 § 63.66 04 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 submi tted 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 Cen tral 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 par agraphs (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 Comp liance 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 mini mize 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 recor ds 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.IPL Eagle Valley Gen. Station Page 28 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 fol lowing 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 emi ssions 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 record ed 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 loc ated 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 fo**  **rm 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 actio n, report, or record, according to § 63.10(b)(1).

[69 FR 33506, June 15, 2004, as amended at 75 FR 9678, Mar. 3, 2010]IPL Eagle Valley Gen. Station Page 29 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 part s 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 ma jor 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 di gester 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 b rake 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 digeste r 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 i mplemented 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 subpa rt 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 auth orities 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 unde r § 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).IPL Eagle Valley Gen. Station Page 30 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 6 3.2, 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 so urce 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 tha t 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 mean s 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, telecommunic ations 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.

C ustody 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 p ipelines 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 s ubject 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 condi tion 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.IPL Eagle Valley Gen. Station Page 31 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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) th at 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 CO

2 .

Dual

- fue l 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 c ombustion 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 d oes 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

situatio n. 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 a ssociated 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 an d 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 ve hicles 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 andIPL Eagle Valley Gen. Station Page 32 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 “ri ch” 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 sta tionary 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 CO

2 .

Lean burn engine means any two

- stroke or four

- stroke spark ignited engine that does not meet the
definition of a rich bur n 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 me ans 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 th at:

(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 u nits, 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 ar e 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 f or 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 a nd 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 opera te 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.IPL Eagle Valley Gen. Station Page 33 of 72 Martinsville, Indiana TV Permit No.: 1 09

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Natural gas mean s 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 reductio n (NSCR) means an add

- on catalytic nitrogen oxides (NO

X ) control device for rich burn engines that, in a two

- step reaction, promotes the conversion of excess oxygen, NO

X , CO, and volatile organic compounds (VOC) into CO

2 , nitrogen, and water.

Oil and ga s 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 transf er; 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 n atural 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 ta nk 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 ef fect 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 sub ject 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 C

3 H
8 .

Remote stationary RICE means stationary RICE meeting any of the following criteria:IPL Eagle Valley Gen. Station Page 34 of 72 Martinsville, Indiana TV Permit No.: 1 09

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(1) Stationary RICE located in an offshore area that is beyond the line of ordi nary 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 criter ia 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 bui lding or a small, well

defined 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 whic h 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 withi n 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 build ing 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 o r 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 re sidential 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 ra tio 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 NO
X (such as p re

- 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 c onditions 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 oth er 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 igni tion engines.IPL Eagle Valley Gen. Station Page 35 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 mob ile 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 sub part 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 79,5 00 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, grave l 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 compres sion 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 36 07, 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**

**RI CE >**  **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

H P 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 e ngine'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 RIC E exhaust to 350 ppbvd or less at 15 percent O 2IPL Eagle Valley Gen. Station Page 36 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 Subpa rt 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

lim itations for existing, new and reconstructed 4SRB stationary RICE >500 HP located at a major source
of HAP emissions:

T ABLE 1 B TO S UBPART ZZZZ OF P ART 63

— O PERATING L IMITATIONS FOR E XISTING , N EW , AND R ECONSTRUCTED SI 4SRB S TATIONARY RICE >500 HP L OCATED AT A M AJOR S OURCE OF HAP E MISSIONS

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 complyin g 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 wit h the requirement to limit the concentration of formaldehyde in the stationary RICE exhaust to 350 ppbvd or less at 15 percent O 2 and using NSCR; a. maintain your catalyst so that the pressure drop across the catalyst does not change by more than
2 inches o f 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 (o r 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 O 2 and not using NSCR.

1 Sources can petition the Administrator pursuant to the requirements of 40 CFR 63.8(f) for a different tempera ture 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.: 1 09

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## >500 HP and New and Reconstructed 4SLB Stationary RICE ≥250 HP **Located at a Major Sour ce 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 form aldehyde in the stationary RICE exhaust to 12 ppmvd or less at 15 percent O 2 . 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
O 2 until 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 app ly. 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 O 2

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 O 2

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 Emissio**  **ns, 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:

T ABLE 2 B TO S UBPART ZZZZ OF P ART 63

— O PERATING L IMITATIONS FOR N EW AND R ECONSTRUCTED 2SLB AND CI S TATIONARY RICE >500 HP L OCATED AT A M AJOR S OURCE OF HAP E MISSIONS , N EW ANDIPL Eagle Valley Gen. Station Page 38 of 72 Martinsville, Indiana TV Permit No.: 1 09

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- 00 004 Permit Reviewer: Josiah Balogun

R ECONSTRUCTED 4SLB S TATIONARY RICE ≥250 HP L OCATED AT A M AJOR S OURCE OF HAP E MISSIONS , E XISTING C I S TATIONARY 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 recon structed 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 tes t;
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 catal yst 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 recons tructed 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

locate d 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 l imit 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, 20 13]IPL Eagle Valley Gen. Station Page 39 of 72 Martinsville, Indiana TV Permit No.: 1 09

- 3 2471

- 00 004 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:

T ABLE 2 C TO S UBPART ZZZ Z OF P ART 63

— R EQUIREMENTS FOR E XISTING C OMPRESSION I GNITION S TATIONARY RICE L OCATED AT A M AJOR S OURCE OF HAP E MISSIONS AND E XISTING S PARK I GNITION S TATIONARY RICE ≤500 HP L OCATED AT A M AJOR S OURCE OF HAP E MISSIONS

For each .

. . You must meet the
followi ng 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 fir st. 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. Insp ect 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 o r less at 15 percent O 2

.

4. Non

- Emergency, non

- black start a. Limit concentration ofIPL Eagle Valley Gen. Station Page 40 of 72 Martinsville, Indiana TV Permit No.: 1 09

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- 00 004 Permit Reviewer: Josiah Balogun

CI stationary RICE 300>HP≤500.”
is corrected to read “4. Non

Emergency, non

- black start CI stationary RICE 300<HP≤500. CO in the stationary RICE exhaust to 49 ppmvd or

l ess at 15 percent O 2 ; 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 O 2 ; or b. Reduce CO emission s 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,

wh ichever 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 stati onary 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.: 1 09

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- 00 004 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 O 2.

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 O 2

.

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 O 2

.

12. Non

- emergen cy, 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 O 2

.

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 b e 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 l aw 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 th e 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 state d in §§ 63.6603 and 63.6640, you must comply with the following requirements for existing stationary RICE located at area sources of HAP emissions:

T ABLE 2 D TO S UBPART ZZZZ OF P ART 63

— R EQUIREMENTS FOR E XISTING S TATIONARY RICE L OCATED

AT A REA S OURCES OF HAP E MISSIONSIPL Eagle Valley Gen. Station Page 42 of 72 Martinsville, Indiana TV Permit No.: 1 09

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- 00 004 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 hour s 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 emiss ion 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 O 2 ;

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 O 2 ;

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 ev ery 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.: 1 09

- 3 2471

- 00 004 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
calend ar 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

o peration 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 ev ery 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. No n

- 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.: 1 09

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whichever comes first; 1

b. Inspect spark plugs every 2,160 hours of operation or annually, whichever comes first,

an d 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 RI CE 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

e very 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 opera tion or annually, whichever comes first, and replace as

necessary.IPL Eagle Valley Gen. Station Page 45 of 72 Martinsville, Indiana TV Permit No.: 1 09

- 3 2471

- 00 004 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 emissi ons 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 o r 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 fir st, 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 duri ng 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 th e 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:

T ABLE 3 TO S UBPART ZZZZ OF P ART 63

— S UBSEQUENT P ERFORM ANCE T ESTS

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 re constructed CI stationary RICE >500 HP located at major sources Reduce CO emissions and not using a CEMS Conduct subsequent performance tests semiannually. 1IPL Eagle Valley Gen. Station Page 4 6 of 72 Martinsville, Indiana TV Permit No.: 1 09

- 3 2471

- 00 004 Permit Reviewer: Josiah Balogun

2. 4SRB stationary RICE ≥5,000 HP located at major

sources Reduce formaldehyde
emissions Conduct s ubsequent 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:

T ABLE 4 TO S UBPART ZZZZ OF P ART 63. R EQUIREMENTS FOR P ERFORMANCE T ESTS

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 O 2 at the
inlet and outlet of the control device; an d (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 O 2 must be
made at the same time
as the measurements
for CO concentration.

ii. Measure the CO at

the inlet and the ou tlet
of the control device (1) ASTM D6522

- 00 (Reapproved 2005) a b c or Method 10 of 40 CFR part 60, appendix A (a) The CO

concentration must be at 15 percent O 2 , dry
basis.

2. 4SRB stationary
RICE a. reduce formaldehyde

emissions i. Select the sampling

po rt 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 O 2 at the (1) Method 3 or 3A or 3B of (a) measurements toIPL Eagle Valley Gen. Station Page 47 of 72 Martinsville, Indiana TV Permit No.: 1 09

- 3 2471

- 00 004 Permit Reviewer: Josiah Balogun

inlet and outlet of the
control device; and 40 CFR part 60, appendix A, or ASTM Method

D6522

- 00 (Reapproved 2005). a determine
O 2 concentration must
be made at the same
time as the
measurements for formaldehyde or THC

concentration.

ii i. 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) Meth od 320 or 323 of 40 CFR part 63, appendix A; or ASTM D6348

- 03, a provided in ASTM

D6348

- 03 Annex A5 (Analyte Spiking Technique), the percent R must be greater than or equal to 70 and less than or equal to 130 (a) formaldehyde

concentration must be at 15 perc ent O 2 , 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
O 2 , 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 o r 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
O 2 concentration 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

determi ne O 2 concentration 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, ap pendix 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 theIPL Eagle Valley Gen. Station Page 48 of 72 Martinsville, Indiana TV Permit No.: 1 09

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and measurements for formaldehyde or CO

concentration.

iv. Measure formaldehy de at the
exhaust of the stationary RICE; or (1) Method 320 or 323 of 40 CFR part 63, appendix A; or ASTM D6348

- 03, a provided in ASTM

D6348

- 03 Annex A5 (Analyte Spiking Technique), the percent R must be greater than or equal to 70 and less than or equal to 130 (a) Formaldehyde

concentration must be at 15 percent O 2 , 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 c Method 320 of 40 CFR part 63, appendix A,
or ASTM D6348

- 03. a (a) CO concentration must be at 15 percent
O 2 , dry basis. Results
of this test consist of the average of the
three 1

- hour or longer

runs.

a Incorporated by referen ce, 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 b oth 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 compl y with the emission and operating limitations as required by the following:

T ABLE 5 TO S UBPART ZZZZ OF P ART 63

— I NITIAL C OMPLIANCE W ITH E MISSION L IMITATIONS , O PERATING L IMITATIONS , AND O THER R EQUIREMENTS

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 RIC E ≥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 non

emergency stationary CI RICE >500 HP a. Reduce CO emissions and using oxidation catalys t, 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

r equirements in § 63.6625(b); and iii. You have recorded the catalystIPL Eagle Valley Gen. Station Page 49 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 th e 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 non

emergency 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 in itial 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 record ed 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. Limi t 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 operatin g 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 2S LB 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 non

emerg ency 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
O 2 or CO 2 at both the inlet and outlet of the oxidation catalyst according to the

req uirements 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;

andIPL Eagle Valley Gen. Station Page 50 of 72 Martinsville, Indiana TV Permit No.: 1 09

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- 00 004 Permit Reviewer: Josiah Balogun

iii. The average reduction of CO calculated using § 63.6620 equals or exceeds the required percent red uction. 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 sour ce 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
O 2 or CO 2 at the outlet of the oxidation

c atalyst 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 i s 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 stati onary 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

per cent 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
form aldehyde
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

de termined from the initial performance test is equal to or greater than 30 percent; andIPL Eagle Valley Gen. Station Page 51 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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

st ationary RICE 250≤HP≤500 located at a major source of HAP, and existing non

emergency 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
NS CR i. The average formaldehyde concentration, corrected to 15 percent
O 2 , 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 temperatur e 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 non

emergency 4SRB stationary RICE >500 HP located at a major source of HAP a. Limit the
concentration of formaldehyde i n the stationary RICE exhaust and not using oxidation catalyst or
NSCR i. The average formaldehyde concentration, corrected to 15 percent
O 2 , dry basis, from the three test runs is less than or equal to the formaldehyde emission limitation; and
ii. You hav e 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 performa nce test.

11. Existing non

- emergency stationary RICE 100≤HP≤500 located at a major source of HAP, and existing non

emergency stationary CI RICE
300<HP≤500 located at an area source of

HAP a. Reduce CO

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 H AP, and existing non

emergency stationary CI RICE
300<HP≤500 located at an area source of

HAP a. Limit the
concentration of formaldehyde or CO in the stationary RICE

exhaust i. The average formaldehyde or CO concentration, as applicable, corrected to 15 pe rcent O 2 , 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 isIPL Eagle Valley Gen. Station Page 52 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 O 2 ;

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 ppm vd at 15 percent O 2 , 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 equipmen t 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 m ust continuously comply with the emissions and operating limitations and work or management practices as required by the following:

T ABLE 6 TO S UBPART ZZZZ OF P ART 63

— C ONTINUOUS C OMPLIANCE W ITH E MISSION L IMITATIONS , AND O THER R EQUIREMENTS

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 ≥2 50 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 f or 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 rollingIPL Eagle Valley Gen. Station Page 53 of 72 Martinsville, Indiana TV Permit No.: 1 09

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major source of HAP averages; and

iv. Maintaining the 4

- hour ro lling 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 limitati on 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

estab lished 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 non

emergency 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 mon itoring 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 d ata 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 rollingIPL Eagle Valley Gen. Station Page 54 of 72 Martinsville, Indiana TV Permit No.: 1 09

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averages within the operating limitations for the catalyst inlet temperature; and

iv. Measuring the press ure 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 rolli ng 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 se miannual 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 pe rcent. a

7. New or reconstructed non

- emergency stationary RICE >500 HP located at a major source of HAP and new or

r econstructed 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 formal dehyde 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 cataly st 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 belowIPL Eagle Valley Gen. Station Page 55 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 with in the operating limitations for the operating parameters established during the performance

test.

9. Existing emergency and black start stationary RICE ≤500 HP located at a major source of HAP, existing non

emergency stationary RICE <100 HP

located at a major source of HAP, existing emergency and black start stationary RICE located at an area source of HAP, existing non

- emergency stationary CI RICE ≤300 HP located at an area source of HAP, existing non

emergency 2SLB stationary RICE located

at an area sou rce of HAP, existing non

emergency 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 non

emergency 4SLB and 4SRB stationary
RICE ≤500 HP located at an area source of HAP, existing non

- emergency 4SLB and 4SRB stationary RICE >500 HP
located at an area source of HAP that operate 24 hours or less per calendar year, and existing non

- emergency 4SLB and 4SRB stationary RICE >500 HP

locat ed 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 a re 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 formalde hyde, 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

te mperature data according to § 63.6625(b); andIPL Eagle Valley Gen. Station Page 56 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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. Measur ing 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

ap propriate, 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 perfor mance
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 tem perature; and

v. Measuring the pressure drop acrossIPL Eagle Valley Gen. Station Page 57 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 s tationary
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

para meter (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 p erformance

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 O 2 ; and either ii. Collecting the catalyst i nlet 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 ppmv d at 15 percent O 2, or the average reduction of emissions of THC is 30 percent or more; and eitherIPL Eagle Valley Gen. Station Page 58 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 rolli ng 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 dem onstrated 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:

T ABLE 7 TO S UBPART ZZZZ OF P ART 63

— R EQUIREMENTS FOR R EPORTS

For each .

. . You must
submit a

. . . The report must contain .

. . You must submit the report .

. . 1. Existing non

- emergency, non

black start st ationary RICE 100≤HP≤500 located at a major source of HAP; existing non

emergency, 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

n on

- emergency, non

- black start stationary CI RICE >300 HP located at an area source of HAP;
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 l ocated 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
durin g 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; o r 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 ar e 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).IPL Eagle Valley Gen. Station Page 59 of 72 Martinsville, Indiana TV Permit No.: 1 09

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§ 63.6650(d). If there were periods during whic h 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

i nformation in § 63.6650(c)(4). i. Semiannually according to the requirements in § 63.6650(b).

2. New or reconstructed non

emergency stationary RICE that combusts landfill gas or digester gas equivalent to 10 percent or more of the gross heat input on an

a nnual 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 th e 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, non

black 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 contra ctually 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 accord ing 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.

G eneral Subject of citation Applies to ExplanationIPL Eagle Valley Gen. Station Page 60 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 Prohibi ted 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 beco me 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 Y es.

§ 63.7(a)(1)

- (2) Performance test dates Yes Subpart ZZZZ contains performance test dates atIPL Eagle Valley Gen. Station Page 61 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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) on ly 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 Z ZZZ 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 ana lysis, 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 NoIPL Eagle Valley Gen. Station Page 62 of 72 Martinsville, Indiana TV Permit No.: 1 09

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§ 63.8(c)(2)

- (3) Monitoring system installation Yes.

§ 63.8(c)(4) Co ntinuous 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 Exc ept 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 reducti on 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 no tifications 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) Notifi cation 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) Notificatio n of visible emission (VE)/opacity test No Subpart ZZZZ does not contain opacity or VE standards.IPL Eagle Valley Gen. Station Page 63 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 CO MS 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 reserve d.

§ 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.IPL Eagle Valley Gen. Station Page 64 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 a nd Carbon Monoxide Concentrations From**  **Certain Engines**

1.0 S COPE AND A PPLICATION

. W HAT IS THIS P ROTOCOL ?

This protocol is a procedure for using portable electrochemical (EC) cells for measuring carbon monoxide (CO) and oxygen (O

2 ) concentrations in contro lled 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 en gine exhaust gas concentrations of carbon monoxide (CO) and oxygen (O

2 ).

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 (O 2 ) 778 2

- 44

- 7IPL Eagle Valley Gen. Station Page 65 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 ins truction 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 an d O

2 , 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 us ed, 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 S UMMARY OF P ROTOCOL

In this protocol, a gas sample is extracted from an engine e xhaust system and then conveyed to a portable EC analyzer for measurement of CO and O

2 gas concentrations. This method provides measurement system performance specifications and sampling protocols to ensure reliable data. You may use additions to, or modif ications 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 D EFINITIONS

3.1 Measurement System. The total equipment required for the measurement of CO and O

2 concentrations. The measurement system consists of the following major subsystems:

3.1.1 Data Recorder. A strip ch art 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, u sed 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 selec tive 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.IPL Eagle Valley Gen. Station Page 66 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 exha ust 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 ca n 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 Er ror. The analyte concentration output exhibited by the EC cell in response to zero

level 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 o perated 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. I n 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 O

2
a nd 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 exce ed 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 I NTERFERENCES

.

When present in sufficient concentrations, NO and NO

2 are two gas species that have been reported to
interfere wi th CO concentration measurements. In the likelihood of this occurrence, it is the protocolIPL Eagle Valley Gen. Station Page 67 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 S A FETY

. [R ESERVED ]

6.0 E QUIPMENT AND S UPPLIES

. 

## 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 non

reactive 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 g as 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 exten d 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 minimiz e 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 sam ple 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 O

2 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 ma ke 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 O

2 ; and one degree (either °C or °F) for temperature. Alternatively, you may use a digital or analog meter having t he same resolution to observe and manually record the analyzer responses.IPL Eagle Valley Gen. Station Page 68 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 wh en the removal agent is exhausted. Periodically replace or replenish it in accordance with
the manufacturer's recommendations.

7.0 R EAGENTS AND S TANDARDS

. W HAT CALIBRATION GASE S ARE NEEDED ?

7.1 Calibration Gases. CO calibration gases for the EC cell must b e CO in nitrogen or CO in a mixture of nitrogen and O

2. 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 O

2 ) is acceptable for calibration

o f the O

2 cell. If needed, any lower percentage O

2 calibration gas must be a mixture of O

2 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 e ach 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

- s cale 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 O

2 gas concentration such that the difference between the gas concentration an d the average stack gas measurement or reading for each sample run is less than 15 percent O

2 . When the average exhaust gas O

2 readings are above 6 percent, you may use dry ambient air (20.9 percent O

2 ) for the up

scale O

2 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.,
CO

2 ).

8.0 S AMPLE C OLLECTION AND A NALYSIS

8.1 Selection of S ampling 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 cent roidal 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 t he first stack gas sampling run, conduct that the pre

sampling 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. The n 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 m inute 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 specific ation given in Section 13.1. Finally, perform the “refresh phase” by introducing dry air, free from CO and otherIPL Eagle Valley Gen. Station Page 69 of 72 Martinsville, Indiana TV Permit No.: 1 09

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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 O

2 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 Q UALITY C ONTROL (R ESERVED )

10.0 C ALIBRATION AND S TANDARDIZATION

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 m anufacturer'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 t he O

2 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 val ue or ± 1 ppm, whichever is less restrictive, for the CO channel and less than or equal to ± 0.3 percent O

2 for the O

2 channel.

10.1.3 Up

- Scale Calibration. Individually introduce each calibration gas to the measurement system (e.g.,

at the calibration ass embly) 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 reading s 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 Calibrat ion 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 O

2 , whichever is less restrictive, respectively. The maximum a llowable 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 O

2 , whichever is less restrictive, respectively.

10.2 Post

- Sampling Calibration Che ck. 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 up

scale calibration error exceeds the respective specification in Sections 10.1.2 and 10.1.4 then all

measurement data collected si nce 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 r un.IPL Eagle Valley Gen. Station Page 70 of 72 Martinsville, Indiana TV Permit No.: 1 09

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11.0 A NALYTICAL P ROCEDURE

The analytical procedure is fully discussed in Section 8.

12.0 C ALCULATIONS AND D ATA A NALYSIS

Determine the CO and O

2 concentrations for each stack gas sampling run by calculating the mean gas
concentrations of the data record ed during the “measurement data phase”.

13.0 P ROTOCOL P ERFORMANCE

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 t he “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, chall enge the interference gas scrubber with NO and NO

2 gas standards that are generally recognized as representative of diesel

- fueled engine NO and NO

2 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 NO

2 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 nomi nal 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 ce ll 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 measuremen t 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 P OLLUTION P REVENTION (R ESERVED )

15.0 W A STE M ANAGEMENT (R ESERVED )

16.0 A LTERNATIVE P ROCEDURES (R ESERVED )IPL Eagle Valley Gen. Station Page 71 of 72 Martinsville, Indiana TV Permit No.: 1 09

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17.0 R EFERENCES

(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.

T ABLE 1: A PPENDIX A

— S AMPLING R UN D ATA

.

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 O 2 CO O 2 CO O 2 CO O 2 CO

Sample Cond.

Phase

′′

′′

′′

′′

Measurement
Data Phase

′′

′′

′′IPL Eagle Valley Gen. Station Page 72 of 72 Martinsville, Indiana TV Permit No.: 1 09

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′′

′′

′′

′′

′′

′′

′′

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 Pe rmit Modification No.: T109

- 32476

- 00004
Permit Reviewer: Josiah Balogun

On September 3 , 201 3 , the Office of Air Quality (OAQ) had a notice published in The Martinsville Daily Reporter

- Times in Martinsville , Indiana, stating that IPL Eagle Valley Generati ng Station

has applied for a Significant Modification to their Part 70 Operating T itle V Permit issued on
December 2, 20 08 relating to the proposed replacement of the current coal and oil fired electric generating units at Indianapolis Power and Light’s (I PL’s) Eagle Valley Generating Station (EVGS) with a state

- of

- the

- art, highly efficient combined cycle combustio n 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 , 201 3 , 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 becau se 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.

1 0 9

- 26292

- 000 04 (language deleted is show n 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 limitIPL Eagle Valley Gen. Station Page 2 of 2
Martinsville , Indiana TSD for PSD/ Significant Source Modification No.: 109

- 32471

- 0000 4
Permit Reviewer: Josia h 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 a lso 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 H 2 SO 4 emissions depend on the su lfur 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 ca n 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

H 2 SO 4 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

- 0000 4 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

Sourc e 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

- 0000 4 on December 2, 2008

. The source has since received the following approvals:

(a) Significant Pe rmit Modification No. 109

- 27356

- 0000 4 , issued on March 16, 2 009 ; and

(b) Acid Rain Renewal Permit No.109

- 28085

- 0000 4 , issued on October 19, 2009

.

County Attainment Status

The source is located in Morgan County.

Pollutant Designation

SO 2 Better than nat ional standards.

CO Unclassifiable or attainment effective November 15, 1990.

O 3 Attainment effective October 19, 2007, for the 8

- hour ozone standard. 1

PM 10 Unclassifiable effective November 15, 1990.

NO 2 Cannot be classified or better than national st andards.

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 Standar ds 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

cons idered 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

Deteri oration (PSD), 326 IAC 2

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(b) PM 2.5 Morgan County has been classified as attainment for PM 2.5 . On May 8, 2008, U.S. EPA promulgated the requirements for Prevention of Significant Deterioration (PSD) for PM 2.5 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 PM 2.5 significant level at ten (10) tons per year. Morgan County was re

- designated attainment County on July 11, 2013 . Therefore, direct PM 2.5 , NOx and SO 2 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 classif ied 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

PM 10 > 100

PM 2.5 > 100

SO 2 > 100

VOC < 100

CO > 100

NO X > 100

GHGs as CO 2 e

---- 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

combustio n turbine electric generation facility. The proposed combined cycle facility would includeIPL Eagle Valley Gen. Station Page 3 of 99
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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 201 3, each with a total rated heat input capacity of 2,542 MMBtu/hr; with NO

x 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.

*N ote: 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

201 3

, with a rated heat input capacity of 79.3 MMBtu/hr, equipped with low NOx burner s (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 201 3, 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

source s .][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Generator is considered
new affected source s .]

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

- 6, permitted in 201 3, 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

source s .][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Fire Pump is considered
new affected source s .]

(c ) One (1 ) evaporative cooling t ower

, 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 e fficiency drift eliminator s

.

(d ) Electrical Circuit Breakers containing sulfur hexafluoride (SF 6 ) 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 Vent s

, permitted in 201 3.

Enforcement Issues

There are no pending enforcement actions regarding this modification

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Emission Cal culations

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. T his 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 Mo dification

Pollutant Potential To Emit (ton/yr)

PM 135

PM 10 1 31

PM 2.5 12 5

SO 2 3 1

VOC 1 7 0

CO 660

NO X 17 6

H 2 SO 4 14
Mercury 0.00011

GHGs as CO 2 e 2,703,157

Single HAPs (Formaldehyde) 15

Total HAPs 2 3

This source modification is subject to 326 IA C 2-7- 10.5(g ) because potential to emit PM, PM 10

, PM 2.5 , VOC and NO X 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 ca se

- by

- case determination of an emission limitation to the existing Part 70 Operating Permit.IPL Eagle Valley Gen. Station Page 5 of 99
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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 practica lly enforceable in the permit.

Table 1 Potential to Emit (Tons per year)

Process PM ( tons) PM 10 (Tons) PM 2.5 (tons) SO 2 VOC NOx CO GHGs as
CO2e H 2 SO 4 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 0.0 1 2 .3 E

- 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 1 0

. 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 1 35

. 4 1 31

. 4 12 4

. 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 NAIPL Eagle Valley Gen. Station Page 6 of 99
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Since PM, PM10, PM 2.5 , NOx, CO, H 2 SO 4 and CO 2 e are emitted in significant levels from the proposed modification

, therefore, netting is triggered for these pollutants. S ummation 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.

SO 2 , 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/y ea r)

Process /

Emission

Unit PM PM 10 PM 2.5 * SO 2 VOC CO NO X GHGs as
CO2e H 2 SO 4 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

Boile r 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 2 51.63 219.5
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 38.5IPL Eagle Valley Gen. Station Page 7 of 99
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Table 3 : Proje cted 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) PM 10 (Tons) PM 2.5 (tons) SO 2 VOC CO NOx GHGs as
CO2e H 2 SO 4 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

Incre ase - 30 0

- 12 86

- 11 30

- 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 NAIPL Eagle Valley Gen. Station Page 8 of 99
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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 involv ed;

(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

M ajor
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 turbine s , idntified as EU

- 1 and EU

- 2 for CO and VOC emissions upon issuance of th is
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 emiss ion unit for CO, VOC, and
NOx. IPL will use NO x CEMS, which meets the definition of a continuous compliance

determ ination 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 c ombustion t urbine s, 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
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(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 steam

g enerating 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 MM Btu/hour). The auxiliary boilers have a

h eat 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/h r. 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 appl y 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 Nat ional 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
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(i) The requirements of Area Source MACT - Na tional 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 2 013, each with a total rated heat input capacity of 2,542 MMBtu/hr; with NO

x 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 includi ng formaldehyde, and exhausting to stacks S

- 1 and S

- 2. Each stack has continuous emissions monitors (CEMS) for NOx.

*N ote: 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 KKK K.

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. 4 0 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)

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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 Unit s

, 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)]. T he 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 boiler s meet the definition of steam generating unit s 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 Su bpart Dc:

(1) One (1) natural gas fired Auxiliary Boiler, identified as emission unit EU -3, permitted in 201 3

, with a rated heat input capacity of 79.3 MMBtu/hr, equipped
with low NOx burner s (LNB) with flue gas recirculation (FGR) to reduce NOx

emissio ns 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 , appl y 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 201 3, 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 source s .][Under 40 CFR 63, Subpart ZZZZ, the fire d Emergency Fire Pump is considered new affected source s .]

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 60.420 2(d)

3. 40 CFR 60.4205(c)

4. 40 CFR 60.420 6

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 201 3, with a rated capacity of 1,826 HP and exhausting through
stack S

- 5. [Under 40 CFR 60, Subpart IIII, the Emergency Generator isIPL Eagle Valley Gen. Station Page 12 of 99
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considered new affected source s .][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Generator is considered new affected source s .]

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 source s .][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Generator is considered new affected s ource s .]

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

- 6, permitted in 201 3, 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 source s .][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Fire Pump is considered new affected source s .]

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
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(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 s ale . The proposed auxiliary boiler do es 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 SO 2 allowances for each ton of SO 2 emitted.
Possession of the SO 2 allowances is not required until after the end of the year in which
the SO 2 is emitted. Therefore, this source is subject to the requirements of 326 IAC 21.

State Rule A pplicability 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 CO 2 . 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 “significan t net emissions increase” for VOCs, CO and CO 2 e only, and there will be significant reductions in

the emissions for NOx, PM, PM 10 , PM 2.5 , and H 2 SO 4 . As such, the requirements of PSD would only apply to VOCs, CO and CO 2 e. 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, PM 10 , PM 2.5 , H 2 SO 4 , VOCs, NOx, CO and CO 2 e.

326 IAC 2 -2- 3 (PSD BACT: Control Technology Review Requirements) Pursuant to PSD/Significant Source Modification 109 -3 2471

- 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 EU 2:

1. The PM, PM 10 and PM 2.5 emissions;

(a) The PM, PM 10 and PM 2.5 emissions from the combined cycle combustion turbines
identified as EU

- 1 and E U-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 PM 10 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 H 2 SO 4 emissions;

(a) The H 2 SO 4 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

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(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% O 2 , 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% O 2 , with duct burners
based on 3

- hr average

.

(c ) The VOC emissions shall not exceed 1.0 ppmvd @15% O 2 , 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% O 2 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 EU 1

- 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 CO 2e emissions for combined cycle combustion turbines shall be limited
to less than 2, 649,570 tons of CO 2 e 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 NO x (premix) mode and in compliance with the primary BACT limit

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(c) A shutdown is defined as operation beginning when the combustion turbine exits dry low

NOx (premix) mode and end ing 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 NO X , 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 NO X 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

- Fire d Auxi liary Boilers, i dentified as EU3 :

1. The PM, PM 10 and PM 2.5 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 H 2 SO 4 emissions;

(a) The H 2 SO 4 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 Boil er ( EU -3) operation shall not exceed 0.0 8 3
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 an d 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 Burner s with Flue Gas Recircula tion

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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

- hr average period.

6. The GHGs BACT for the Auxiliary Boilers, identified as EU3 shall be as follows ;

(a ) Operating and Maintenance (O&M) Pr actices;

(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 (re covery );

(f ) Steam and hot lines will be insulated; and

(g ) Boiler designed for 8 0% thermal efficiency (HHV).

(h ) The total CO 2 e e missions for Auxiliary Boiler shall be limited to less than 40, 63 9
tons of CO 2 e per twelve (12) consecutive month period with compliance

determined at the end of each month.

Dew Point Heater EU -4

1. The PM, PM 10 and PM 2.5 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 H 2 SO 4 emissions;

(a) The H 2 SO 4 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 s hall 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 ) Th e good engineering design and Combustion Practices.

(b) The use of only natural gas

.

(c ) The total CO 2 e e missions for Dew Point Heater shall be limited to less than 10,659 tons of CO 2 e per twelve (12) consecutive month period with compliance

determined at the end of each month.IPL Eagle Valley Gen. Station Page 17 of 99
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Emergency Diesel Generator, identified as E U5 :

1. The PM, PM 10 and PM 2.5 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 H 2 SO 4 e missions;

(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

4.8 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 E U5 shall be as follows :

(a ) The use of a g ood engineering design ;

(b ) The total CO 2 e e missions for Emergency Diesel Generator shall be limited to less
than 605 tons of CO 2 e per twelve (12) consecutive month period with compliance
determined at the end of each month.

Emergency Fire Pump Engine, identified a s EU 6:

1. The PM, PM 10 and PM 2.5 emissions from the Emergency Fire Pump Engine shall not
exceed 0.15 g/hp

- hr through the use of combustion design control

.

2. The H 2 SO4 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 Co mbustion Design Controls

.

5. The GHGs BACT for the Emergency Diesel Generator, Identified as E U-6 shall be as follows :

(a ) The use of a g ood engineering design ; (b ) The total CO 2 e e missions for Firewater Pump Engine shall be limited to less than

157.50 to ns of CO 2 e per twelve (12) consecutive month period with compliance
determined at the end of each month.

Cooling Tower U-7:

1. The PM, PM 10 and PM 2.5 emissions;

(a ) The PM, PM 10 and PM 2.5 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 dissolve d solids (T DS ) shall be less
than 5000 m g/L

.

( b) The PM, PM 10 and PM 2.5 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
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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 CO 2 e e missions for circuit breakers sha ll be limited to less than 59.80 tons of
CO 2 e 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, PM 10 and PM 2.5 emissions from the Turbine Lube Oil Demister Vents shall be the use of good design and operating practice s

.

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 CCCT s. Prior to stack testing the factor will be conservatively assumed to equal 60% of the uncontrolled emission factor.

Compliance with the above limit s 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 SO 2 or PM emissions in levels greater than 25 tons per year. TheIPL Eagle Valley Gen. Station Page 19 of 99
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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 prohibit s excessive
concentrations of PM and SO 2

.

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 O 2 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 an y 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 Heatin g: 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. 2 2 pounds per million Btu heat input (lb/MMBtu), each. This limitation was calculated using the following equation:

Pt = 0.87 Q 0.16

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 b y 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 I AC 6 -2- 4 not applicable to this auxiliary
boiler.IPL Eagle Valley Gen. Station Page 20 of 99
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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 SO 2 emissions less than 25 tons per year.

(b) The potential to emit SO 2 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 SO 2 emissions from each of the combi ned 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 u sing 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 facilitie s.

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 com mencing operation after March 21, 1972 and has CO emissions of more than 100 tons per year. There are no appli cable 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)
Se ction (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 max imum

- 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 NO 2 NAAQS. Additional air quality modeling was not required for the 24

- hour PM 10 and PM 2.5 and the annual PM 2.5 and NO 2 standards. The 1

- hour NO 2 NAAQS modeling results shown in Table 5 of Appendix C had a
violation of the 1

- hour NO 2 standard of 100 parts per billion (ppb) or 188.7 ug/m 3 . The highest 8 th

high 1

- hour NO 2 concentration averaged across five years was 419.7 ug/m 3 resulting in a total 1

- hour NO 2 concentration of 487.6 ug/m 3 with a background concentration of 67.9 ug/m 3 . The highest 8 th

- high maximum daily 1

- hour NO 2 modeled concentration of 419.7 in Table 5 of Appendix C was adjusted from an actual modeled concentration of 524.6 ug/m 3 by using the
NO 2 /NO

x default ambient ratio of 0.8 (524.6 X 0.8 = 419.7) for a 1

- hour concentration. The annualIPL Eagle Valley Gen. Station Page 21 of 99
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NO 2 modeled concentration shown in Table 5 of Appendix C has been adjusted by the 0.75
default ambient ratio for NO

x to NO 2 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 Analy sis

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 ne ar 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 eig hty 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
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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 so urce 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 Dete rmination 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 provisi ons ; 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 R equirements are included in the permit. The C ompliance D etermination

R equirements 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 act ion.

If the Compliance Determination R equirements are not sufficient to demonstrate continuous compliance, they will be supplemented with Compliance Monitoring R equirements, also in Section D of the permit. Unlike Compliance Determination Re quirements, 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 C ompliance D etermination R equirements applicable to this modification are as follows:IPL Eagle Valley Gen. Station Page 23 of 99
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Testing Requirements

(a) Testing Requirements

Note: Compliance with the NOx emission limits for the combustion turbines are demonstrate d 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/PM 10 /PM 2.5 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 C ycle

Combustion

Turbine U nits

EU -1 and EU -2 With Duct Burner 60 days / no

later than 180 days PM , PM 10 and

PM 2.5 5 year 326 IAC 2 -2-3

Without Duct
Burner

Combined C ycle

Combustion

Turbine U nits

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 C ycle

Combustion

Turbine U nits

EU

- 1 and EU -2 Oxidation Catalyst with Duct
Burner 60 days / no

later than 18 0 days VOC 5 year 326 IAC 2 -2-3
Oxidation Catalyst without

Duct Burner

Combined C ycle

Combustion

Turbine U nits

EU

- 1 and EU

- 2 No control 60 days / no

later than 180 days CO 2 (Heat Rate Performance) 5 year 326 IAC 2 -2-3

Combined C ycle

Combustion

Turbine U nits

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 , PM 10 and

PM 2.5 One time testing 326 IAC 2

- 2

- 3

Auxiliary B oiler 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

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(b) The compliance monitoring requirements applicable to this source are as follows:

Control Parameter Frequency Range/

Value Excursions

and

Exceeda nces 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

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. 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 Emis sion 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 NO X and
SO 2 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

electrostati c 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 NO X burners (LNB) for control of NO X emissions, which were voluntarily installe d 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 NO X and SO 2 and a continuous opacity monitor (COM).IPL Eagle Valley Gen. Station Page 25 of 99
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(d) One (1) ta ngentially

- 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 particula te matter, exhausting to stack 3

- 1. Unit 5 is equipped with SOFA and LNB for control of
NO X emissions, which were voluntarily installed and are not required to operate. Unit 5 will combust no. 2 fuel oil during startup, shutdown, and stabilization period s. Stack 3

- 1 has continuous emission monitoring systems (CEMS) for NO X and SO 2 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 NO X 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

- NO X burners installed. Stack 3

- 1 has continuous emission monitoring systems (CEMS) for NO X and SO 2 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 NO

x 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

.

*N ote: 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
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(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, SO 2 5 pounds per hour or 25 pounds per day, NO X 5 pounds per hour or 25 pounds per day, CO 25 pounds per day, PM 10 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 Em ission

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 consid ered 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) evaporati ve 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
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(f ) Electrical C ircuit Breakers containing sulfur hexafluoride (SF 6 ) 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 an d 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 requireme nts 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. T he requirements of this section will no longer b e 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
Q 0.16 = 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

requ ested 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
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(1) Whe n 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 limi t 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 ac cordance with 326 IAC 5-1- 3(d). The Permittee must demonstrate that the alternative limit is needed and justifiable.

D.1.3 Sulfur Dioxide (SO 2 ) [326 IAC 7-4- 11]

Pursuant to 326 IAC 7-4- 11 (Morgan County Sulfur Dioxide Emission Limitations), the SO 2 emiss ions 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 I AC 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
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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

trans ferring 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 NO X 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 N otations [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

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

reasonable response steps in accordance with Section C - R esponse to Excursions or
Exceedan ces. 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 - R esponse 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 sta ck 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 SO 2 limit as r equired 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 p ermit.

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
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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 NO X and SO 2 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 electrostat ic 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 NO X burners (LNB) for
control of NO X 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 NO X and SO 2 and a continuous opacity monitor (COM).

(d) One (1) t angentially

- 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 NO X 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 NO X and SO 2 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 precipitat or (ESP) for control of particulate matter, exhausting to stack 3

- 1. Unit 6 is equipped with
Closed

- coupled Overfire Air (COFA) to control NO X 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

- NO X burners installed.
Stack 3

- 1 has continuous emission monitoring systems (CEMS) for NO X and SO 2 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 F acility. T he 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
Q 0.16 = 4,071 MMBtu/hrIPL Eagle Valley Gen. Station Page 32 of 99
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(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 tempera ture 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 (SO 2 ) [326 IAC 7-4- 11]

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

(a) SO 2 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) SO 2 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 an d 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 yea r 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
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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, SO 2 , and either CO 2 or O 2 , which meet the performance specifications of 326 IAC 3-5- 2.

(b) All c ontinuous 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) Pur suant 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 throu gh

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 obt ained 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, SO 2 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 7-4-1 1(9).IPL Eagle Valley Gen. Station Page 34 of 99
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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 s ystems for the NO X 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 s ets 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 SO 2 Monitor Downtime [326 IAC 2-7- 6] [326 IA C 2-7- 5(3)] (a) Whenever the SO 2 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 SO 2 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
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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 depar tment 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

r eadings taken during any periods of COM downtime.

(4) All ESP parametric monitoring readings.

(b) To document compliance with SO 2 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 SO 2 limits as required in Condition D.2.3. The Permittee shall maintain records in accordance with (2) and (3) or (4) below during SO 2 CEM system downtime.

(1) All SO 2 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 SO 2 CEM downtime, in
accordance with Condition D.2.11.

(3) Calculated actual fuel usage during each SO 2 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 SO 2 CEM downtime, in accordance with Condition D.2.1 1.IPL Eagle Valley Gen. Station Page 36 of 99
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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) A ll 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 do wntime.

(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
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SECTION D.3 FACILITY OPERATION CONDITIONS

Facility Description [32 6 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. T he requirements of th is section will no longer be applicable after the units are permanently

shutdown

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

- 2]

Pursuant to 326 IAC 7- 1.1

- 2 (Sulfur Dioxide Emission Limitations), the SO 2 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 SO 2 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
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(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 Require ments, 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 Requiremen ts, 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
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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 c ar 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 op eration of the Combined Cycle Combustion Turbine Generation Facility. T he 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 P 0.11

- 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
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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 - R esponse to Excursions or Exceedan ces

. Failure to take response steps in accordance with Section C - R esponse to Excursions or Exceedan ces

, 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
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SECTION D.5 FACILITY OPERATION CONDITIONS

Facility Descri ption [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 200 9 , 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. T he 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 PM 10 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 hourIPL Eagle Valley Gen. Station Page 42 of 99
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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

no rmal, 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.

Compli ance 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

counti ng 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 emissi ons 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, th e 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 wit h 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
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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 d rop 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)] [3 26 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 - Parame tric 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
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SECTION D.6 FACILITY COND ITIONS

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 [3 26 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 operati on of the Combined Cycle Combustion Turbine Generation Facility. T he 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 s ixty

- 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 = Numb er 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:

P R = (1.5 ± N) P

Where N = Fraction of fugitive dust that is respirable dust;

P R = 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
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(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 - R esponse to Excursions
or Exceedances. Failure to take response steps in accordance with Section C - R esponse 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.IPL Eagle Valley Gen. Station Page 46 of 99
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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 Descriptio n:

(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 NO

x 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

.

*N ote: 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 emissio ns.

(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, PM 10 and PM 2.5 PSD BACT [326 IAC 2-2- 3] Pursuant to PSD/Significant Source Modification 109

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- fired combined cycle combustion turbines, identified as EU

- 1

and EU

- 2 shall be as follows:

(a) The PM

, PM 10 and PM 2.5 emissions f rom 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

, PM 10 and PM 2.5 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 p ipeline natural gas shall be fired in the combined cycle combustion turbines

identified as EU

- 1 and EU

- 2.

D.7.2 H 2 SO 4 PSD BACT [326 IAC 2-2- 3] Pursuant to PSD/Significant Source Modification 109

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- fired combined cycle combustion turbines, identified as EU

- 1

and EU

- 2 shall be as follows:

(a) The H 2 SO 4 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 a verage basis.

(b ) Only p ipeline natural gas shall be fired in the combined cycle combustion turbines

identified as EU

- 1 and EU

- 2.IPL Eagle Valley Gen. Station Page 47 of 99
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D.7.3 CO PSD BACT [326 IAC 2-2- 3]

Pursuan t to PSD/Significant Source Modification 109

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- 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 p ipeline natural gas shall be fired in the comb ined 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 -0 0004 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% O 2 , with duct burners based

on 3

- hour average.

(c) The VOC emissions shall not exceed 1.0 ppmvd @15% O 2 , without duct burners

based on 3

- hour average.

(d ) Only p ipeline 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

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- fired combined cycle combustion turbines, identified a s 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% O 2 with duct burners based on

a 3

- hour average.

(c) Only p ipeline 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

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- 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).IPL Eagle Valley Gen. Station Page 48 of 99
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(b) The total CO 2 e e missions for both combined cycle combustion turbines shall be

limited to less than 2 ,649,570 tons of CO 2 e 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.

Compl iance 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 St artup and Shutdown Limitations for Combustion Turbines [326 IAC 2 -2- 3] Pursuant to PSD/Significant Source Modification 109

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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

- st ate 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 turbi ne 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/sh utdown 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 NO X , 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 NO X 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 ofIPL Eagle Valley Gen. Station Page 49 of 99
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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

turbine s 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 Catalyt ic 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 H 2 SO 4 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 CO 2 e emissions fr om the natural gas

- fired combined cycle combustion turbines, identified as EU

- 1 and EU -2:

CO 2 e emissions (tons/month) = [(Fuel Usage (mmscf/month) x Heat Content (mmbtu/mmscf)) x (CO 2 EF (lb/mmbtu) x CO 2 GWP + CH 4 EF (lb/mmbtu) x CH 4 GWP + N 2 O EF (lb/mmbtu) x N 2 O 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
CO 2 EF (lb/mmbtu) = 120 lb s/mmbtu for combustion with duct firing and 122 lbs/mmbtu for combustion without duct firing
CH 4 EF (lb/mmbtu) = 0.0022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas

N 2 O EF (lb/mmbtu) = 0.00022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas CO 2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH 4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N 2 O 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:IPL Eagle Valley Gen. Station Page 50 of 99
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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

conser vatively 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 O 2 emissions.

(b) All CEMS required by this permit shall meet all applica ble 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 O 2 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

mini mum 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, PM 10 and PM 2.5 PSD BACT, within sixty (60) days of reaching maximum capacity but no later than oneIPL Eagle Valley Gen. Station Page 51 of 99
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hundred and eighty (180) days after initial startup, the Permittee shall conduct PM,

PM 10 and PM 2.5 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 D ecember 31 of every fi fth 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 con ducted with the duct burners in operation. This test shall be repeated by December 31 of every fi fth 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 fi fth year following the date of the most recent valid compliance demonstrat ion. 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 o rder 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 tes ting for combined cycle combustion turbines utilizing methods as approved by the commissioner. This test shall be repeated by December 31 of every fi fth 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 wi th 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 fi fth year following the date of the most recent va lid 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.IPL Eagle Valley Gen. Station Page 52 of 99
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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 o rder 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 mo nitoring 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 availab le, the Permittee shall operate the oxidation catalyst at or above the 3

- hour average temperature of 500 o 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 obligatio n 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 - H 2 SO 4 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 CO 2e 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.IPL Eagle Valley Gen. Station Page 53 of 99
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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 requir ed 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 O 2 continuous emission monitoring system (CEMS) occurs in Condition D.7.1 4 - 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
Contin uous 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 Cond ition D.7.1 6 - 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
Condit ions 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 cert ification 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 54 of 99
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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 S

3.

(The information describing the process contained in this emissions unit description box is des criptive information and does not constitute enforceable conditions.)

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

D.8.1 PM, PM 10 and PM 2.5 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 (B ACT) for the natural gas

- fired auxiliary boiler, identified as EU

- 3 shall be as follows:

The PM, PM 2.5 and PM 10 emissions from the Auxiliary Boiler, identified as EU

- 3 shall not
exceed 0.005 lb/MMBtu and 0.4 lbs/h our, based on a 3

- hr average period through the use of good combustion practices and fuel specification.

D.8.2 H 2 SO 4 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 H 2 SO 4 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

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- 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 n ot 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

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- 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 BAC T [326 IAC 2-2- 3] Pursuant to PSD/Significant Source Modification 109

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- fired auxiliary boiler, identified as EU

- 3 shall be as follows:IPL Eagle Valley Gen. Station Page 55 of 99
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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 e missions 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 b oiler 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 CO 2 e e missions for Auxiliary Boiler shall be limited to less than 40,63 9
tons of CO 2 e 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), whe n 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

e xcess 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 Determina tion 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 H 2 SO4 Compliance Determination Requirements [326 IAC 2

- 2]

In order to ensure compliance with Condition D.8.2, the Permitt ee 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
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D.8.10 Testing Requirements [326 IAC 2- 1.1

- 11] (a) In order to demonstrate c ompliance with Condition D.8.1 - PM, PM 10 and PM 2.5 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,

PM 10 and PM 2.5 emissions stack test ing 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 - Perf ormance 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. Testin g 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 fi fth y ear 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 CO 2 e e missions from the Auxiliary Boiler :

CO 2 e emissions (ton/month) = [(Fuel Usage (mmscf/month) x Heat Content (mmbtu/mmscf)) x (CO 2 EF (lb/mmbtu) x CO 2 GWP + CH 4 EF (lb/mmbtu) x CH 4 GWP + N 2 O EF (lb/mmbtu) x N 2 OIPL Eagle Valley Gen. Station Page 57 of 99
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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
CO 2 EF (lb/mmbtu) = 117 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas

CH 4 EF (lb/mmbtu) = 0.0022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas

N 2 O EF (lb/mmbtu) = 0.00022 lbs/MMBtu emission factor fro m GHG MRR (40 CFR 98, Subpart C) for natural gas CO 2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH 4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N 2 O 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.8.1 1 , 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 - H 2 SO 4 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 Condi tion D.8.6 (h) - GHGs PSD BACT, the

Per mittee shall maintain the monthly records of the total CO 2e 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.8.1 3 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
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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, PM 10 and PM 2.5 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, PM 10 and PM 2.5 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 H 2 SO 4 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 H 2 SO 4 emissions from t he 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 he ater, 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
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(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 CO 2 e e missions for Dew Point Heater shall be limited to less than 10,659
tons of CO 2 e 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, PM 10 and PM 2.5 PSD

BACT and D.9. 2 - H 2 SO 4 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 sh all
be used to determine the CO 2 e e missions from the dew point heater, identified as EU -4:

CO 2 e emissions (ton/month) = [(Fuel Usage (mmscf/month) x Heat Content (mmbtu/mmscf)) x (CO 2 EF (lb/mmbtu) x CO 2 GWP + CH 4 EF (lb/mmbtu) x CH 4 GWP + N 2 O EF (lb/mmbtu) x N 2 O 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
CO 2 EF (lb/mmbtu) = 117 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas

CH 4 EF (lb/mmbtu) = 0.0022 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for natural gas

N 2 O EF (lb/mmbtu) = 0.00022 lbs/MMBtu emission factor fro m GHG MRR (40 CFR 98, Subpart C) for natural gas CO 2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH 4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N 2 O 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
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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 Conditi on D.9.6 (c) - GHGs PSD BACT, the Permittee shall maintain the monthly records of the total CO 2e 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
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SECTION D.1 0 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 exha usting 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 ZZZ Z, 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 Limitatio ns and Standards [326 IAC 2-7- 5(1)]

D.10.1 PM, PM 10 , PM 2.5 , NOx, CO, H 2 SO 4 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, PM 10 and PM 2.5 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 H 2 SO4 emiss ions;

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 an d 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 CO 2 e e missions for Emergency Diesel Generator shall be limited
to less than 605 tons of CO 2 e per twelve (12) consecutive month period with compliance determined at the end of each month.

D.10.2 PM, PM 10 , PM 2.5 , NOx, CO, H 2 SO 4 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
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Emergency Fire Pump Engine, identified as EU

- 6:

(a) The PM, PM 10 and PM 2.5 emissions from the Emergency Fire Pump Engine shall not exceed 0.15 g/hp

- hr through the use of combustion design control.

(b) H 2 SO 4 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 CO 2 e e missions for Firewater Pump Engine shall be limited to less

than 157.50 tons of CO 2 e 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 compli a nce status with Condition D.10.1 (e)(2 ), the following equation shall be used to determine the CO 2 e e missions from the Emergency

Diesel Generator (EU

- 5):

CO 2 e emissions (ton/month) = [(Fuel Usage (gal/month) x Heat Content (mmbtu/gal)) x (CO 2 EF (lb/mmbtu) x CO 2 GWP + CH 4 EF (lb/mmbtu) x CH 4 GWP +

N 2 O EF (lb/mmbtu) x N 2 O 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 f or diesel fuel, or vendor data, if

available
CO 2 EF (lb/mmbtu) = 163 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for diesel fuel

CH 4 EF (lb/mmbtu) = 0.00661 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for diesel fuel

N 2 O EF (lb/mmbtu) = 0.00132 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for diesel fuel

CO 2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH 4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N 2 O 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 CO 2e emissions from the Emergency Fire Pump Engine (EU -6 ):IPL Eagle Valley Gen. Station Page 63 of 99
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CO 2 e emissions (ton/month) = [(Fuel Usage (gal/month) x Heat Content (mmbtu/gal)) x (CO 2 EF (lb/mmbtu) x CO 2 GWP + CH 4 EF (lb/mmbtu) x CH 4 GWP +

N 2 O EF (lb/mmbtu) x N 2 O 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
CO 2 EF (lb/mmbtu) = 163 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for diesel fuel

CH 4 E F (lb/mmbtu) = 0.00661 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for diesel fuel

N 2 O EF (lb/mmbtu) = 0.00132 lbs/MMBtu emission factor from GHG MRR (40 CFR 98, Subpart C) for diesel fuel

CO 2 GWP = 1.0 global warming potential from GHG MRR (40 CFR 98, Subpart A)

CH 4 GWP = 21 global warming potential from GHG MRR (40 CFR 98, Subpart A)

N 2 O 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.1 0.4 Record Keeping Requirements (a) In order to document the compliance status with Condit ions 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 Permi ttee 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 CO 2e emissions from the emergency diesel engine and fire pump engine

.

(e) Section C - General Record Keeping Requirements contains the Permittee's obliga tions with regard to the record keeping required by this condition.

D.10.5 Reporting Requirements A quarterly summary of the information to document the complian ce 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

certifi cation 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
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S ECTION D.1 1 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: Insignificant Activities

(e) One (1) evaporative cooling tower

, identified as emission unit U

- 7, rat ed with a

circul ation rate of 1 92 ,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, PM 10 and PM 2.5 PSD BACT [326 IAC 2-2- 3] Pursuant to PSD/Significant Source Modification 109

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- 7 shall be as follows:

(a) The PM, PM 10 and PM 2.5 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 ma ximum total dissolved solids (T D S) shall be less than 5000 ppm.

(b) The PM, PM 10 and PM 2.5 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, PM 10 and PM 2.5 Control (a) In order to ensure compliance with Conditions D.11.1 - PM and PM 10 and PM 2.5 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 th e 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, PM 10 , and PM 2.5 emission rates using an equation based on the T DS and water circulation rate using the following formula

.

E = (c x T x Q x 8.34 x 60 x DR) / 10 6

Where:

E = mass emission rate in lbs/hr for PM, PM 10 and PM 2.5 ; c = particle size fraction (c=1 for PM; 0.635 for PM 10 and 0.00213 for PM 2.5 ) ; 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
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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, t he Permittee shall maintain a log that contains the date and result of each blow

- down water qu ality 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
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SECTION D.1 2 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: Insignificant Activities

(f ) Electrical Circuit Breakers containi ng sulfur hexafluoride (SF 6 ) 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

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(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 SF 6 emissions from all the circuit breakers shall not exceed 59.8 to ns of
CO 2 e per twelve (12) consecutive month period with compliance determined at the

end of each month.IPL Eagle Valley Gen. Station Page 67 of 99
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SECTION D.1 3 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description: Insignifi cant 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

descri ptive 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

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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
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SECTION D.1 4 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 infor mation and does not constitute enforceable conditions.)

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

D. 14 .1 PM, PM 10 and PM 2.5 PSD BACT [326 IAC 2-2- 3] Pursuant to PSD/Significant Source Modification 109

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The PM

, PM 10 and PM 2.5 emissions from the Turbine Lube Oil Demister Vents shall be the use of good design and operating practices

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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.

S ECTION 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 NO X and SO 2 and a continuous opacity monitor (CO M).

(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 NO X burners (LNB)
for control of NO X emissions, which were voluntarily installed and are not required to operate.
Unit 4 will combu st no. 2 fuel oil during startup, shutdown, and stabilization periods. Stack 2

- 1 has continuous emission monitoring systems (CEMS) for NO X and SO 2 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 NO X 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 syst ems (CEMS) for NO X and SO 2 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 electro static 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 NO X emissions, which was voluntarily installed and is not required to operate. Unit 6 will com bust 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

- NO X burners installed. Stack 3

- 1 has continuous emission monitoring systems (CEMS) for NO X and SO 2 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 identi fied as EU

- 1 and EU

- 2, permitted in 2013, each with a total rated heat input capacity of 2,542 MMBtu/hr; with NO

x emissions controlled by low combustion burner design and Selective Catalytic Reduction (SCR), and each with an oxidation catalyst system to re duce 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

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*N ote: The heat recovery steam generators are not a source of emissions. They h ave 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 A llowances [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 regulat ions promulgated under Title IV of the Clean Air Act.IPL Eagle Valley Gen. Station Page 71 of 99
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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 NO

x 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

.

*N ote: 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 Performanc e 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

inco rporated 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 60.4420IPL Eagle Valley Gen. Station Page 72 of 99
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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

S ubpart 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

- Institu tional 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 Genera ting 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
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SECTION E.4 EMISSIONS UNI T 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 H P and exhausting through stack S

- 5. [Und er 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, S ubpart 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 Sour ce 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 specifie d 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, Subp art 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 60.4218IPL Eagle Valley Gen. Station Page 74 of 99
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8. 40 CFR 60.4219IPL Eagle Valley Gen. Station Page 75 of 99
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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, permit ted 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 [32 6 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 ZZ ZZ][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 63.6645IPL Eagle Valley Gen. Station Page 76 of 99
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SECTION F RESERVED Nitrogen Oxides B udget Trading Program

- NO X Budget Permit for NO X Budget Units Under 326 IAC 10

- 4

- 1(a)

ORIS Code: 991

NO X 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, respectivel y, 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 mill ion 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. Use d 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 NO X and SO 2 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 syst em for control of particulate matter, exhausting
to stack 2

- 1. Unit 4 is equipped with separated overfire air (SOFA) and low NO X burners (LNB)
for control of NO X emissions, which were voluntarily installed and are not required to operate.
Unit 4 will com bust no. 2 fuel oil during startup, shutdown, and stabilization periods. Stack 2

- 1 has continuous emission monitoring systems (CEMS) for NO X and SO 2 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 equi pped with SOFA and LNB for control of NO X 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

sy stems (CEMS) for NO X and SO 2 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 elect rostatic 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 NO X emissions, which was voluntarily installed and is not required to operate. Unit 6 will c ombust 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

- NO X burners installed. Stack 3

- 1
has continuous emission monitor ing systems (CEMS) for NO X and SO 2 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 NO X 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 NO X budget source and each budget unit shall operate
each unit in compliance with this NO X budget permit.IPL Eagle Valley Gen. Station Page 77 of 99
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(b) The NO X budget units subject to this NO X 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 NO X authorized account representative of the NO X budget source and each NO X 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 7 5 and

326 IAC 10

- 4

- 12 shall be used to determine compliance by each unit with the NO X 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 a nd operators of the NO X budget source and each NO X budget unit at the
source shall hold NO X allowances available for compliance deductions under

326 IAC 10

- 4

- 10(j), as of the NO X allowance transfer deadline, in each boiler’s compliance account and the sour ce’s overdraft account in an amount:

(1) Not less than the total NO X 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 perio d under

326 IAC 10

- 4

- 10(k)(5); or

(3) To account for withdrawal from the NO X budget trading program, or a change in regulatory status of a NO X budget opt

- in unit.

(b) Each ton of NO X emitted in excess of the NO X budget emissions limitation shall constitu te a separate violation of the Clean Air Act (CAA) and 326 IAC 10

- 4.

(c) NO X allowances shall be held in, deducted from, or transferred among NO X 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 NO X 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 NO X allowance was allocated.

(e) A NO X allowance allocated under the NO X budget trading program is a limited authorization to emit one (1) ton of NO X in accordance with the NO X budget trading program. No provision of the NO X budget trading program, the NO X budget permit application, the NO X budget perm it, 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 NO X allowance allocated under the NO X budget trading program does not co nstitute 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 NO X allowance to or from
each NO X budget unit’s compliance account or the overdraft a ccount or the overdraft account of the source where the unit is located is deemed to amend automatically, and become a part of, this NO X budget permit of the NO X 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 NO X budget unit that has excess emissions in any ozone control period shall do the following:IPL Eagle Valley Gen. Station Page 78 of 99
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(a) Surrender the NO X allowances required for deduction under 326 IAC 10

- 4

- 10(k)(5).

(b) Pay any fine, pen alty, 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 NO X budget source and each NO X budge t 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 NO X autho rized account representative
for the source and each NO X 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 docum ents 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 NO X 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 thre e (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 NO X budget trading program.

(d) Copies of all documents us ed to complete a NO X budget permit application and any other
submission under the NO X budget trading program or to demonstrate compliance with the requirements of the NO X 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 receip t 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 NO X authorized account representative of the NO X budget source and each NO X budget unit at the source shall submit the reports and compliance certifications required
under the NO X bud get 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 NO X authorized account r epresentative: “I am authorized to make this submission on behalf of the owners and operators of the NO X budget sources or NO X budget units for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar w ith, 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) W here 326 IAC 10

- 4 requires a submission to IDEM, OAQ, the NO X authorized account representative shall submit required information to:IPL Eagle Valley Gen. Station Page 79 of 99
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Indiana Department of Environmental Management Office of Air Quality
100 North Senate Avenue
MC 61

- 53, IGCN Room 1003

Ind ianapolis, Indiana 46204

- 2251

(d) Where 326 IAC 10

- 4 requires a submission to U.S. EPA, the NO X authorized account representative shall submit required information to:

U.S. Environmental Protection Agency
Clean Air Markets Division 1200 Pennsylvania Ave nue, NW
Mail Code 6204N Washington, DC 20460

F.8 Liability [326 IAC 10

- 4

- 4(f)] The owners and operators of each NO X budget source shall be liable as follows:

(a) Any person who knowingly violates any requirement or prohibition of the NO X budget trading p rogram, a NO X 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 NO X 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 NO X budget trading program that occurs prior to the date that th e revision takes effect.

(d) Each NO X budget source and each NO X budget unit shall meet the requirements of the
NO X budget trading program.

(e) Any provision of the NO X budget trading program that applies to a NO X budget source, including a provision app licable to the NO X authorized account representative of a NO X budget source, shall also apply to the owners and operators of the source and the NO X budget units at the source.

(f) Any provision of the NO X budget trading program that applies to a NO X budge t unit, including a provision applicable to the NO X authorized account representative of a NO X 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 C FR 75 and

326 IAC 10

- 4

- 12, the owners and operators and the NO X authorized account representative of one (1) NO X budget unit shall not be liable for any violation by any other
NO X budget unit of which they are not owners or operators or the NO X authorized account representative and that is located at a source of which they are not owners or operators or
the NO X authorized account representative.

F.9 Effect on Other Authorities [326 IAC 10

- 4

- 4(g)] No provision of the NO X budget trading program, a NO X budget permit application, a NO X 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 NO X authorized account representative a
NO X budget source or NO X 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
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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 NO X and SO 2 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 NO X burners (LNB) for
control of NO X emissi ons, 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 NO X and SO 2 and a continuous op acity 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 NO X 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 NO X and SO 2 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 NO X em issions, 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

- NO X burners installed. Stack 3

- 1 has continuous emission monitoring systems (CEMS) for NO X and SO 2 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 NO

x 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

.

*N ote: 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 inIPL Eagle Valley Gen. Station Page 81 of 99
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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)] [3 26 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 NO X source, CAIR SO 2 source, and CAIR NO X ozone season source and CAIR NO X unit, CAIR SO 2 unit, and CAIR NO X ozone season unit shall operate each source and unit in compliance with this CAIR permit.

(b) The CAIR NO X units, CAIR SO 2 units, and CAIR NO X 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 NO X source, CAIR SO 2 sourc e, and CAIR NO X ozone season source and CAIR NO X unit,
CAIR SO 2 unit, and CAIR NO X 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 NO X source, CAIR SO 2 source, and CAIR NO X ozone season source with the CA IR NO X emissions limitation under 326 IAC 24 -1- 4(c), CAIR SO 2 emissions limitation under 326 IAC 24 -2- 4(c), and CAIR NO X 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 perio d , the owners and operators of
each CAIR NO X source and each CAIR NO X unit at the source shall hold, in the source’s compliance account, CAIR NO X 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 NO X units at the source, as
determined in accordance with 326 IAC 24 -1- 11

.

(b) A CAIR NO X 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 NO X 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 NO X allowance was allocated.

(d) CAIR NO X allowances shall be held in, deducted from, or transferred into or among CAIR
NO X 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
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(e) A CAIR NO X allowance is a limited authorization to emit one (1) ton of nitrogen oxides in
accordance with the CAIR NO X annual trading program. No provision of the CAIR NO X 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 NO X 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
NO X allowance to or from a CAIR NO X 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 SO 2 source and eac h CAIR SO 2 unit at the source shall hold, in the source’s compliance account, a tonnage equivalent of CAIR SO 2 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 SO 2 units at the source, as determined in accordance with

326 IAC 24 -2- 10.

(b) A CAIR SO 2 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 SO 2 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 SO 2 allowance was allocated.

(d) CAIR SO 2 allowances shall be held in, deducted from, or transferred into or among CAIR
SO 2 allowance tracking system accounts in accordance with 326 IAC 24 -2- 8,

326 IAC 24 -2- 9, and 32 6 IAC 24 -2- 11.

(e) A CAIR SO 2 allowance is a limited authorization to emit sulfur dioxide in accordance with
the CAIR SO 2 trading program. No provision of the CAIR SO 2 trading program, the CAIR permit application, the CAIR permit, or an exemption under 32 6 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 SO 2 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 SO 2 allowance to or
from a CAIR SO 2 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 NO X ozone season source and each CAIR NO X ozone season unit at the

source shall hold, in the source’s compliance account, CAIR NO X 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 NO X ozone season units at the source, as determined
in accordance with 326 IAC 24 -3- 11.

(b) A CAIR NO X 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
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(c) A CAIR NO X 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 NO X ozone season allowance was allocated.

(d) CAIR NO X ozone season allowances shall be held in, deducted from, or transferred into or among CAIR NO X 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 NO X ozone season allowance is a limited authorization to emit one (1) ton of nitrogen oxides in accordance with the CAIR NO X ozone season trading program. No provision of the CAIR NO X 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 NO X 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
NO X ozone season allowance to or from a CAIR NO X 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 NO X source and each CAIR NO X unit that emits nitrogen oxides during any control period in excess of the CAIR NO X emissions limitation shall do the following:

(1) Surrender the CAIR NO X 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 SO 2 source and each CAIR SO 2 unit that emits sulfur dioxide during any control period in excess of the CAIR SO 2 emissions limitation shall do the following:

(1) Surrender the CAIR SO 2 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 NO X ozone season source and each CAIR NO X ozone season unit that emits nitrogen oxides during any control period in excess of the
CAIR NO X ozone season emissions limitation shall do the following:

(1) Surrender the CAIR NO X ozone season allowances required for deduction under

326 IAC 24 -3- 9(j)(4).IPL Eagle Valley Gen. Station Page 84 of 99
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(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 NO X source, CAIR SO 2 source, and CAIR NO X ozone season source and each CAIR NO X unit, CAIR SO 2 unit, and CAIR NO X 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
NO X unit, CAIR SO 2 unit, and CAIR NO X 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 monit oring 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 NO X annual trading program, CAIR SO 2 trading program, and CAIR NO X ozone season trading program.

(d) Copies of all documents used to complete a CAIR permit application and any other
submission under the CAIR NO X annual trading program, CAIR SO 2 trading program, and
CAIR NO X ozone season trading program or to demonstrate compliance with the requirements of the CAIR NO X annual trading program, CAIR SO 2 trading program, and
CAIR NO X 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 NO X source, CAIR SO 2 source, and
CAIR NO X ozone season source and each CAIR NO X unit, CAIR SO 2 unit, and CAIR NO X ozone season unit at the source shall submit the reports required under the CAIR NO X

annua l trading program, CAIR SO 2 trading program, and CAIR NO X 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

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(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 NO X annual trading program, CAIR SO 2 trading program, and CAIR NO X 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

statemen ts 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 bel ief 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

I ndianapolis, 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 NO X source, CAIR SO 2 source, and CAIR NO X ozone

s eason source and each CAIR NO X unit, CAIR SO 2 unit, and CAIR NO X ozone season unit shall
be liable as follows:

(a) Each CAIR NO X source, CAIR SO 2 source, and CAIR NO X ozone season source and
each CAIR NO X unit, CAIR SO 2 unit, and CAIR NO X ozone season unit shall meet the requirements of the CAIR NO X annual trading program, CAIR SO 2 trading program, and
CAIR NO X ozone season trading program, respectively

.

(b) Any provision of the CAIR NO X annual trading program, CAIR SO 2 trading program, and
CAIR NO X ozo ne season trading program that applies to a CAIR NO X source, CAIR SO 2 source, and CAIR NO X ozone season source or the CAIR designated representative of a
CAIR NO X source, CAIR SO 2 source, and CAIR NO X ozone season source shall also apply to the owners and operators of such source and of the CAIR NO X unit s , CAIR SO 2 unit s , and CAIR NO X ozone season unit s at the source

.

(c) Any provision of the CAIR NO X annual trading program, CAIR SO 2 trading program, and
CAIR NO X ozone season trading program that applies t o a CAIR NO X unit, CAIR SO 2 unit,
and CAIR NO X ozone season unit or the CAIR designated representative of a CAIR NO X unit, CAIR SO 2 unit, and CAIR NO X ozone season unit shall also apply to the owners and operators of such unit.IPL Eagle Valley Gen. Station Page 86 of 99
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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 NO X annual trading program, CAIR SO 2 trading program, and CAIR NO X 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 NO X source, CAIR SO 2 source, an d CAIR NO X ozone season source or CAIR NO X unit, CAIR SO 2 unit, and CAIR NO X 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 NO X source, CAIR SO 2 source, and CAIR NO X ozone season source, including all CAIR NO X units, CAIR SO 2 units, and CAIR NO X 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 NO X annual trading program, CAIR SO 2 trading program,
and CAIR NO X ozone season trading program concerning the source or any CAIR NO X unit, CAIR SO 2 unit, and CAIR NO X 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 NO X source, CAIR SO 2 source, and CAIR NO X 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
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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 Ad dress: 4040 Blue Bluff Road, Martinsville, IN 46151
Part 70 Permit No.: T 109

- 26292

- 00004 Facility: Units 1, 2, and PR

- 10
Parameter: SO 2 Emissions

Limit: Shall not exceed the pound per million Btu (lb/MMBtu) limit, demonstrated using a

calendar month avera ge

YEAR:

Emission Unit Limit (lb/MMBtu) SO 2 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 e mission units have been shut down and decommissioned.IPL Eagle Valley Gen. Station Page 88 of 99
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## 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: SO 2 Emissions

Limit: Shall not exceed the pound per m illion 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 occur red 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

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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 Turbine s EU

- 1 - EU -2

Parameter: NOx Emissions

Limit: shall not exceed 6 8 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

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- 0000 4 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.

QUART ER : 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 occu rred 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

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- 0000 4 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

Fac ility: 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.

Dev iation 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

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- 0000 4 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

So urce 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: s hall not exceed 2

, 649 ,5 70 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 P revious 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:

Submi tted by:
Title / Position: Signature:

Date:

Phone:



## INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT
OFFICE OF AIR QUALITY
COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly ReportIPL Eagle Valley Gen. Station Page 93 of 99
Martinsville , Indiana TSD for PSD/ Significant Source Modification No.: 109

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- 0000 4 Permit Reviewer: Josiah Balogun TSD for Significant Permit Modification No.: 109

- 32476

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Source Name: Indianapolis Power and Light (IPL) Eagle Valley Generating Station

Sourc e Address: 4040 Blue Bluff Road, Martinsville, IN 46151

Part 70 Permit No.: T 109

- 26292

- 00004 Facility: Auxiliary Boiler EU -3

Parameter: CO2e

Limit: s hall not exceed 40 ,639 tons per twelve (12) consecutive month period with compliance determined a t 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 P oint 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

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- 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) E agle Valley Generating Station

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

Part 70 Permit No.: T 109

- 26292

- 00004 Facility: Emergency Generator E U-5

Parameter: CO2e

Limit: s hall not exceed 6 05 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 TotalIPL Eagle Valley Gen. Station Page 95 of 99
Martinsville , Indiana TSD for PSD/ Significant Source Modification No.: 109

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- 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 ENVIRONMENTA L 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 2IPL Eagle Valley Gen. Station Page 96 of 99
Martinsville , Indiana TSD for PSD/ Significant Source Modification No.: 109

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Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

Deviation has b een 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: I ndianapolis 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) conse cutive 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

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- 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 PM 2.5 Attainment for all other criteria pollutants
Source Status: Part 70 Operating Permit Program Major Source, under PSD Rules and Nonattainm ent 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 Complianc e 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, withIPL Eagle Valley Gen. Station Page 98 of 99
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- 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

malfunctio ns, 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 instal ling 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 sch edule 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 Indianap olis, 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 sh all 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 p roposed PSD/ Part 70 Significant Source Modification No. 109

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- 00004

. The staff recommend s 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

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- 0000 4
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 a t the Indiana Department Environmental Management, Office of Air Quality, Permits Branch, 100 North Senate Avenue, MC 61

- 53 IGCN 1003, Indianapolis, Indiana 46 204

- 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.govEmission Unit MW output MMBtu/hrIPL EagleValleyPage 1 of 11 TSD Appx ACT-1 EU-12463CT-1 w/Duct Burner2542CT-2 EU-22463CT-2 w/ Duct Burner2542Aux. Boiler EU-379.3Basis for Emisison FactorsDew Point Heater EU-420.8Proposed permit Limits Based On Vendor dataAP-42HP MMBtu/hr40 CFR Part 98; Tables A-1, C-1 and C-2Fire PumpEngineEU-5500 3.85Emergency generator EU-61826 14.8Units NOx CO VOC SO2 PM PM10 PM2.5 H2SO4 Fluorides Lead Mercury CO2 CH4 N2Oppmv 2 2 2lbs/hr18.9 14.4 8.99 3.55 16.78 16.78 16.78 2.06 306,306 5.60 0.56lbs/MMBtu0.0014 0.0066 0.0066 0.0066 0.00081 2.20E-03 2.20E-04lbs/hr18.6 11.3 3.25 3.45 13.55 13.55 13.55 1.47 301,647 5.43 0.54lbs/MMBtu0.0014 0.0055 0.0055 0.0055 0.00060 2.20E-03 2.20E-04lbs/MMBtu0.011 0.082 0.0053 0.0014 0.005 0.005 0.005 0.000107 2.55E-07117 2.20E-03 2.20E-04lbs/hr 0.87 6.50 0.42 0.11 0.40 0.40 0.40 0.00850 2.02E-05lbs/MMBtu0.032 0.082 0.0053 0.0014 0.0072 0.0072 0.0072 0.000107 2.55E-07117 2.20E-03 2.20E-04lbs/hr 0.67 1.71 0.11 0.029 0.150 0.150 0.150 0.00223 5.30E-06lbs/MMBtu0.831 0.745 0.029 0.0015 0.043 0.043 0.043 0.000115 163 6.61E-03 1.32E-03lbs/hr 3.20 2.87 0.11 0.0060 0.17 0.17 0.17 0.00044lbs/MMBtu1.27 0.709 0.027 0.0015 0.043 0.043 0.043 0.000115 163 6.61E-03 1.32E-03lbs/hr 18.8 10.50 0.40 0.022 0.64 0.6 0.6 0.00170Lube Oil Demister Vents lbs/hr/vent 0.0174 0.0174 0.01741 21 310 23,900Emission UnitHours/ YearNOx CO VOC SO2 PM PM10 PM2.5 H2SO4 Fluorides Lead Mercury CO2 CH4 N2O SF6 CO2eTotalHAPsFormalde-hydeCT-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 1.27 0.90CT-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 9.54 6.79CT-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 1.27 0.90CT-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 9.54 6.79Auxiliary 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 0.72 0.028Dew 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 0.17 0.007Fire Pump 500 0.80 0.72 0.03 0.0015 0.041 0.041 0.041 156.94 0.0064 0.0013 157.47 0.0037 0.001Emergency Generator 500 4.70 2.63 0.10 0.01 0.16 0.15 0.15 603.29 0.0245 0.0049 605.32 0.0058 0.000Cooling Towers 8760 10.5 6.7 0.020Paved Roads/Parking87600.2160.0430.011Potential to Emit, Tons/Year656 MWnominalcapacityGlobal Warming PotentialsEmission FactorsEmergency Generatorper CT NG w/o ductfiringper CT NG w duct firingFire Pump EngineAux BoilerDew Point HeaterPaved Roads/Parking87600.2160.0430.011Methane leaks 876069.85 1466.9Circuit Breakers 87600.0025 59.83 Lube Oil vents 8760 0.229 0.229 0.229175.5 141.4 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 22.52 15.41CCCT Subtotal163.2 102.1 34.2 30.3 121.9 121.9 121.9 13.5 0.0 0.000 0.00 2,647,08747.74.8 0.0 2,649,569 21.62 15.3740 100 40 40 25 15 10 7 3 0.6 0.1 NA NA NA NA 75,000TotalsSD/NNSR Significance Threshold, tons/yeaPotential to Emit, 8760 Hours: Non-Normal Load Operation (cold, warm, hot starts and shutdown conditions)Page 2 of 11 TSD Appx ANOx CO VOC NOx CO VOCCT-1 @100% load w/ duct firing 1000 18.9 12.6 8.99 9.5 6.3 4.5NOx 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 Starts16 225 7260.0 114.3 904 265.8 3.4 27.1 8.0 Warm Start 220.2 1885.2 481.0CT-1 Warm Starts260 119 8515.7 111 950.5 242.5 28.6 245.1 62.5 Hot Start 34.5 308.8 50.3CT-1 Hot Starts10 50 08.3 41.4 370.6 60.3 0.2 1.5 0.3 Shut Down 10.7 61.9 17.1CT-1 Shutdown286 1781.0 37.9 218.3 60.4 1.5 8.8 2.4CT-1 Annual Total78.7 310.5 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 Starts16 225 7260.0 114.3 904 265.8 3.4 27.1 8.0CT-2 Warm Starts260 119 8515.7 111 950.5 242.5 28.6 245.1 62.5CT-2 Hot Starts10 50 08.3 41.4 370.6 60.3 0.2 1.5 0.3CT-2 Shutdown286 1781.0 37.9 218.3 60.4 1.5 8.8 2.4CT-2 Annual Total78.7 310.5 84.0CT-1 & CT-2 Total157.5 621.0 167.9CT-1 & CT-2 Startup Shutdown Total67.5 565.2 146.4Potential to Emit, 8760 Hours: Non-Normal Load Operation (cold, warm, hot starts and shutdown conditions) CasNOxCO VOC NOxCO VOCCT-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 6.6CT-1 Cold Starts5 229 7219.1 114.3 1295 1686 1.1 12.4 16.1CT-1 Warm Starts260 123 10533.0 111 1363 1538 29.6 363.2 409.9CT-1 Hot Starts10 71 411.8 41.4 527.7 794 0.2 3.1 4.7CT-1 Shutdown275 27123.837.9 245.8671 2.3 15.2 41.5CT-1 Annual Total80.2 423.0 483.3CT-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 Starts5 229 7219.1 114.3 1295 1686 1.1 12.4 16.1CT-2 Warm Starts260 123 10533.0 111 1363 1538 29.6 363.2 409.9CT-2 Hot Starts10 71 411.8 41.4 527.7 794 0.2 3.1 4.7CT-2 Shutdown275 27123.837.9 245.8671 2.3 15.2 41.5CT-2 Annual Total80.2 423.0 483.3CT-1 & CT-2 Total160.4846.1 966.6CT-1 & CT-2 Startup Shutdown Tota66.5787.9944.4Emission Reductions From Shutdown of ExistingUnits 1-6 (based on 2010 and 2011 Actual Emissions)Basis for Emission FactorsCEMs DataAP-4240 CFR Part 98644,000 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 balanceHoursDown/ eventEmissions per event, lbsGlobal Warming PotentialsPTE, tons/yearPTE, tons/yearEmission Rate, lbs/hourHours Down/eventEmission Rate, lbs/hourMinutes/EventEmission UnitEvents/ yearHours/yearHours/ yearMinutes/ EventEvents/ yearEmission Unit1 21 310NOx CO VOC SO2 CPMPM, filt,ControlledPM10, filt,ControlledPM10 Total,ControlledPM2.5,filt,controlledPM2.5, TotalControlledH2SO4 Fluorides Lead Mercury CO2 CH4 N20Boiler 1(Oil)0.03570.00543 0.00929 0.0143 0.0071 0.0164 0.00170.0110 0.00249 9.00E-06 3.00E-06 0.00661 0.00132Boiler 2 (Oil)0.0357 0.00543 0.00929 0.0143 0.0071 0.0164 0.0017 0.0110 0.002499.00E-06 3.00E-060.00661 0.00132Boiler 3 (Coal) Wet Bottom0.0223 0.0018 0.196 0.0580.0435 0.2395 0.0232 0.2192 0.0140.0067 1.88E-05 3.71E-060.02425 0.00353Boiler 4 (Coal) DryBottom0.0223 0.0027 0.196 0.0580.03886 0.23486 0.01682 0.21282 0.0140.0067 1.88E-05 3.71E-060.02425 0.00353Boiler 5 (Coal) DryBottom0.0223 0.0027 0.196 0.0850.05695 0.25295 0.02465 0.22065 0.0140.0067 1.88E-05 3.71E-060.02425 0.00353Boiler 6 (Coal) DryBottom0.0223 0.0027 0.196 0.0850.05695 0.25295 0.02465 0.22065 0.0140.0067 1.88E-05 3.71E-060.02425 0.00353NOx CO VOC SO2 CPMPM, filt,ControlledPM10, filt,ControlledPM10 Total,ControlledPM2.5,filt,controlledPM2.5, TotalControlledH2SO4 Fluorides Lead Mercury CO2 CH4 N20 CO2eMW-hr OutputBoiler 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 0.03 3,2932,893Boiler 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 0.03 3,2592,853Boiler 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 2.16123,048Boiler 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 5.35305,207Boiler 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 5.00304,674Boiler 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 8.86540,349Totals 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 21.4 1,259,1011,279,024439,905812,644806,346CEMS DataEmission Factors, lbs/MMBtu436,4952010 Annual Emissions, Tons798.40 4,199.38,065.0964.00CEMsDataCEMs DataEmission Unit MMBtu/yearEmission Unitlbs/MMBtuUnitsPage 3 of 11 TSD Appx ANOx CO VOC SO2 CPMPM, filt,ControlledPM10, filt,ControlledPM10 Total,ControlledPM2.5,filt,controlledPM2.5, TotalControlledH2SO4 Fluorides Lead Mercury CO2 CH4 N20 CO2eMW-hr OutputBoiler 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 0.013 1,5981,336Boiler 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 0.014 1,6711,434Boiler 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 2.36134,160Boiler 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 4.91278,833Boiler 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 3.51202,182Boiler 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 8.38482,601Totals 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 19.2 1,126,1881,100,5461,782 129.3 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 20 1,192,6441,189,785NOx CO VOC SO2 CPM PM, filterablePM10, filt,ControlledPM10 TotalPM2.5, filt,controlledPM2.5, Total H2SO4 Fluorides Lead Mercury CO2 CH4 N2O SF6 CO2eNew 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 4.9 0.003 2,703,157Shutdown Credits -1,782 -129 -15 -11,570 -432 -1,418 -1,255 -80 -38 -0.11 -0.021 -1,183,423 -139 -20 -1,192,644 -1,192,644Net 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 -15 -1,192,644 1,510,51340 100 40 40 NA 25 NA 15 NA 10 7 3 0.6 0.1 NA NA NA NA 75,000NOx CO VOC SO2PM,filterablePM10TotalPM2.5,TotalH2SO4 Fluorides Lead Mercury CO2eNew Equipment PTE 175.5 660.3 170.4 30.9 135.4 131.5 124.7 13.5 0.000 0.0000 0.0001 2,703,157Reduction s fromShutdown of existingunits-1782 -129.3 -15.0 -11570 -432.1 -1418 -1255.3 -80.5 -38.5 -0.1080 -0.0214 -1,192,644Net Emissions Change -1606 531.0 155.4 -11539 -296.6 -1287 -1130.5 -67.0 -38.5 -0.1080 -0.0213 1,510,513PSD/NNSR SignificanceThresholds40 100 40 40 25 15 10 7 3 0.6 0.1 75,000426,151696,7686,720.220111 Annual Emissions, Tons422,848.4838.2 4,153.9Emission UnitRated capacity,MMBtu/hrTons/yearPSD/NNSR Significance Threshold, tons/year955.12010/2011 Average Emissions, tonsEmissions, tons/year691,367.6Project Net EmissionIncrease (Decrease) (Basedon 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

Forma ld e h y d e 7.89E-05 2.92E-04 1,3-Buta d iene 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/MMBtuPage 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-Buta d iene 3.91E-05 1.48E-05 1,3-Buta d iene 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/yearCT-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

Forma ld e h y d e 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

BurnerPage 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

Formaldeh y de 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

Na p hthalene 1.30E-06 2.31E-04 5.45E-05 4.81E-04 8.16E-05 8.50E-04

Acena p hth y len e NA 6.83E-07 1.61E-07 3.42E-05 4.87E-06 3.99E-05

Acena p hthen e 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

Phenanthren e 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

P y rene 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

Chr y sene 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 )py rene NA 4.55E-07 1.07E-07 9.51E-07 1.81E-07 1.69E-06

Indeno ( 1,2,3-cd )py rene 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 )p er y lene NA 4.55E-07 1.07E-07 2.06E-06 4.71E-07 3.09E-06

2 Meth y lna p thalene NA 9.48E-06 2.23E-06 NA NA 1.17E-05

3 meth y lcloranthen e NA 6.07E-07 1.43E-07 NA NA 7.50E-07
7,12-Dimeth y lbenz ( a ) anthracene NA 6.07E-06 1.43E-06 NA NA 7.50E-06

Dichlorobenzen e 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

Acetaldeh y de 8.66E-01 NA NA 9.32E-05 7.38E-04 8.67E-01

Acrolei n 1.39E-01 NA NA 2.92E-05 8.90E-05 1.39E-01

Eth y lbenzene 6.93E-01 NA NA 6.93E-01

X y lenes 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

Ber y lliu m 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

Chromiu m 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

Man g anese NA 1.44E-04 3.39E-05 NA NA 1.78E-04

Mercur y 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

Seleniu m NA 9.11E-06 2.14E-06 NA NA 1.12E-05

HAP Totals 21.6 0.7 0.2 0.006 0.004 22.5AP-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/hr 1 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/PM 10 /PM 2.5 Emission Factor Calculation

Where,

PM EF AP-42 = AP-42 Emission Factor for PM10 (lb/1000 gal)

TLD design = Design total liquid drift (%)

TLD AP-42 = Design total liquid drift (%)

TDS future = Estimated future total dissolved solid content (mg/L)

TDS AP-42 = Total dissolved solid content used in AP-42 (mg/L)

Cooling Tower PM/PM 10 /PM 2.5 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/PM 10 /PM 2.5

42 42 42 5

. 2 10 

### / /

   

###   

AP future

AP design

AP 

### TDS TDS

TLD TLD EF PM EF PM PM PM

EF PM M R PM PM PM    )

( / / 5

. 2 10Page 9 of 11 TSD Appx A3.0021,900365365100Process Pollutant Emission FactorEmissionFactorUnitsSource of EmissionFactorPotential Emissions(tons/year)Actual Emissions(Tons/Yr)lbs/hourPM0.020 0.2162 0.21620.04935PM-10 0.004 0.0432 0.04320.00987PM-2.5 0.001 0.0106 0.01060.00242PAVED ROAD SPREADSHEETTypical Daysof OperationDetermination of Annual EmissionsAverage Vehicle Weight(W)(tons): Average weight of vehicles from Assumptions Tab0.6Paved Road lb/vmt AP-42Enter 0.6 for public road, 120 for apshalt batching industrial road, 12 for concrete batching industrial road, 70 forsand &gravel processingindustrial road, 8.2 for quarryindustrial road. If facilityhas a permit with a silt loadinglimit, use that sEQUATION40 vehicles; 1.5 miles/day; 365 days per yearVMTPotential Daysof OperationSOURCE OF EMISSION FACTOR:VALUESDays/Year withat Least 0.01 inches ofPrecipitationSee Map - Figure 1for value. 100 maybe enteredas adefault value.EMISSIONS CALCULATIONSThe emission factor is taken fromEquation 1 in AP-42, 13.2.1, PavedRoads (updated January 2011).Road Surface Silt Loading (g/m2):k = constant = 0.0022 for PM-10 and 0.00054 for PM-2.5 from AP42 Table 13.2.1-1 (lb/VMT value)sL = road surface silt loading = 0.6 from AP-42 Table 13.2.1-3 orentered aboveW = Average Vehicle Weight (tons)p = Number of Days per YearEF = [[(k) x [(sL)^0.91] x [(W)^1.02]]((1- (p/1460)) lb/VMTPage 10 of 11 TSD Appx A

No. of

Com p onents SF6/

component,

lbs % leak

Assum p tion SF6, tons/ y ear 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 ControlledPage 11 of 11 TSD Appx A

Hours/

day Days/

week Weeks/

yr Capacity

Factor (%) Days (each) Hours,

total g allons/h r gallons

Total for 3-years PM2.5, gr/HP-hr NMOC/
NOx, gr/HP-hr NOx,gr/HPhr PM2.5 NOx PM2.5 NOx Avera g e 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 Unpaved Road Emissions missions, tons/ y e a Emissions, tons/project Number

of UnitsSite preparationPlant 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)

Track ing and Plant ID : T 109

- 32471

- 000 04

Proposed Project

Indianapo lis Power & Ligh t (IPL) Company has submitted a request for a significant major source modification of their Eagle Valley G enerating Station near Martinsville

, Indiana w ith an increase in carbon monoxide (CO), nitrogen dioxide (NO 2 )

, particulate matter less than 10 microns (PM 10 )

, p articulate m atter
less than 2.5 mic rons (PM 2.5 ) , sulfur dioxide (SO 2 ), and v olatile o rganic c ompounds (VOCs). The increase

in CO, NO 2 , PM 10 , and PM 2.5 emissions will be as a result of the installation of two natural gas fired combined cycle combustion turbines and an auxiliary boiler at th e 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.

E nvironmental 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) re ceived 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 pr ovides 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, NO 2 , PM 10 , and PM 2.5

. The significant impact analysis determined mo deling concentrations for NO 2 , PM 10 , and

PM 2.5 e xceed ed the significant impact levels. A refin ed analysis , PSD increment analysis and National
Ambient Air Qua lity Standards (NAAQS) analysis w ere required. The pre

- construction monitoring requirement was t riggered for the 24

- hour PM 10 and 24

- hour PM 2.5 as a result of this analysis

. An additional impact analysis was conducted and showed no significant impact s

. Based on the modeling results, the proposed PSD major source modification will not have a signific ant 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 i n 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 meteorologica l data used, a description of the model used in the ana lysis, and the receptor grid used for the analyses.IPL Eagle Valley Gen. Station Page 2 of 17
Martinsville

, Indiana PSD/SSM No. T109

- 3 2471

- 00 004
Permit Writer: M ark Neyman

C. Determine the significant impact level s , the area impacted by the source's emissions and background air quality levels.

D. Demonstrate that th e 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 impa ct 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 1 50
kilometers south of Louisville

.

F. Secondary Ozone Formation Analysis

G. Secondary PM 2.5 Formation Analys is

H. Summary of Air Quality Analysis



### Section A

- Pollutants Analyzed for Air Quality Impact

App licability

The PSD requirements, 326 IAC 2

- 2, apply in attainment and unclassifiable areas and require an air quality impact analysis of e ach regulated poll utant 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 class ified as non attainment for the annual PM 2.5 standard, but the United States Environmental Protection Agency (U.S. EPA ) approved the Indiana Department of Environmental Management (IDEM) reques t to redesignate Morgan County to attainment for the annual

PM 2.5 standard effective July 11, 2013 , Federal Register Volume 78, No. 133 dated July 11, 2013.

Proposed Project Emissions

CO

, NO 2 , PM 10 , PM 2.5 , SO 2 , VOCs

, and H 2 SO 4 are the pollutant s which wi ll b e emitte d from the IPL Eagle Valley PSD major source modification

. A n air qualit y analysis is required f or CO, NO 2 , PM 10 and

PM 2.5 pollutant s because potential emissions after controls exceed the significant emission rate s (SER) as shown in Table 1. Sulfuric Acid Mist (SAM) will exceed the significant emiss ion 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 signif icant emission rates in Table 1 were
taken from Table 4

- 2 of the IPL Eagle Valley PSD permit application technical support document for NO 2 , SO 2 , SAM, and VOCs and the modeled emission limits in the case of CO, PM 2.5 , and PM 10

. The modeled
emissions limit s for CO, PM 2.5 , and PM 10 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 PM 10 and PM 2.5 where only two operating scenarios were applicable to particulate

matter.IPL Eagle Valley Gen. Station Page 3 of 17
Martinsville

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- 3 2471

- 00 004
Permit Writer: Mark Neyman

Table 1 Significant Emission Rates for PSD Applicability

CRITERIA

POLLUTANT POTENTIAL EMISSION

RATE ( Source Totals) SIGNIFICANT EMISSION RATE PRELIMINARY A IR Q UALITY
ANALYSIS REQUIRED

(tons/year) (tons/year)

CO 670 100 Yes

NO 2 176.7 40 Yes

PM 10 183 15 Yes

PM 2.5 149.5 10 Yes

SO 2 30.9 40 No

VOC 170 40 Yes

H 2 SO 4 (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)

App licability

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
fo r stacks taller than 65 meters or 213 feet is limited to GEP for the purpose of establishing emission

lim itations. 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

- 3 2471

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Permit Writer: Mark Neyman

Existing Stack

Since the existing stack height s of the unit s 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 A merican Meteorological Society Environmental Protection Agency Regulatory Model (AERMOD) consisted of 200 6 through 201 0 surface meteorological data from the Indianapolis

, Indiana National Weather Service (NWS) station merged with the upper air data from th e Lincoln, Illinois NWS upper air st ation. Additionally, t he Indianapolis 1

- minute Automated Surface Observing System (ASOS) wind speed and wind direction data were processed with the AERMINUTE preprocessor version 11 325

. The meteorological data were prep rocessed into an AERMOD ready format by the OAQ using U.S.EPA’s AERMET , Version 12345, meteorologi cal preprocessor for AERMOD.

Model Description

ERM and OAQ used the most recent version of AERMOD

, Version 12 345

, at the time the permit application was sub mitted 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 t he 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 grid s extende d to a distance approximately 50 kilometers from the plant . Fence line recept ors were closely spaced at 50 to 100 meters along the plant fence line and space d every 100

meters out to a distance of 1 0 0 0 meters from the plant property lines to identify the influence o f aerodynamic building downwash. A total of 723 7 receptors were us ed in the significant impact area air quality analysis for CO, NO 2 , PM 10 , and PM 2.5 with a more refined receptor grid of 4621 receptors for the
NO 2 NAAQS and PSD increment analys es and 2461 recept ors for the PM 10 and the PM 2.5 NAAQS analyses. A total of 7237 receptors were used for the PM 2.5 PSD increment analysis which was essentially the SIL analysis for PM 2.5 and 4621 receptors for the PM 10 PSD increment analysis. Each recept or 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 sour ce's concentrations exceed the SILs , further air quality analys es are required. Refined m odeling for the 1

- hour and 8

- hour CO and the PM 10 annual time averaging period s were not requi red because the results did not excee d the SILs

. SIL s are defined b y 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 op erating scenario had the highest modeled impact on the air quality for the 1

- hour and annual NO 2 and the 24

- hour and annual PM 10 and PM 2.5 . Case 3 operating scenario resulted in the highest modeled concentrations for the 1

- hour and 8

- hour CO. The 1

- hour NO 2IPL Eagle Valley Gen. Station Page 5 of 17
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, Indiana PSD/SSM No. T109

- 3 2471

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Permit Writer: Mark Neyman

SIL shown in Table 2 is the highest 5 year average of the 1

- hour maximum daily concentration s for each receptor modeled . Likewise, the 24

- hour PM 2.5 SIL is the highest 5 year average of the maximum 24

- hour
concentration s for each receptor . Additional ly

, the annual PM 2.5 SIL is the highest 5 year average of the

annual concentration s at each recepto r. The 1

- hour and annual NO 2 model ed results shown in Table 2 were adjusted by the default ambient ratio for the nitrous oxides ( NO

x ) to NO 2 conversion

, whi ch 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
NO 2

.

The 24

- hour and annual PM 2.5 SIL s w ere 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 PM 2.5 SILs to demonstr ate that a
source will not cause or contribute to a violation of the PM 2.5 NAAQS or PSD increments. In the case of IPL Eagle Valley, the annual and 24

- hour PM 2.5 modeling results were above the PM 2.5 SILs and below
the PM 2.5 NAAQS so the use of the PM 2. 5 SILs does not impact the modeling results for the IPL Eagle Valley PSD major source modification.

T able 2 Significant Impact Analysis

CRITERIA

POLLUTANT TIME AVERAGING

PERIOD MAXIMUM MODELED
IMPACT

(ug/m 3 ) SIGNIFICANT
IMPACT LEVEL

(ug/m 3 ) REFINE D AQ ANALYSIS
REQUIRED

CO 1

- Hour 286

. 6 2000 No

CO 8

- Hour 111.5 500 No

NO 2 1

- Hour 68.9 7.5 Yes

NO 2 Annual 1. 4 1 Yes

PM 10 24

- Hour 12.1 5 Yes

PM 10 Annual 0. 5 3 1 No

PM 2.5 24

- Hour 6. 0 1.2 Yes

PM 2.5 Annual 0.3 2 0.3 Yes

Pre construction Monitoring Analy sis

App licability

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 pre construction monitoring threshold is triggered. In most cases, post construction monitoring c an satisfy this requirem ent if t he pre construction monitor ing threshold has been exceeded. In the case of the significant monitoring concentration (SMC) for PM 2.5 , the January 22, 2013 decision by the Circuit Court vacated the use of the 24

- hour PM 2.5 SMC to exempt a source from the preconstruction monitoring data requirement . However, in most cases existing ambient PM 2.5 monitoring data can be used to meet the preconstruction requirement

, as was done here for the IPL Eagle ValleyIPL Eagle Valley Gen. Station Page 6 of 17
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Permit Writer: Mark Neyman

PSD major source modific ation.

Model ing Results

A comparison of the preliminary modeling results was compared to the PSD preconst ruction monitoring thresholds. The criteria pollutants, PM 10 and PM 2.5 , did trigger the preconstruction monitoring requirement. As a result, the pr econstruction monitoring requirement for PM 10 and PM 2.5 is necessary for this PSD major source modification, but the preconstruction monitoring requirement is met by using existing air quality monitoring data for PM 10 and PM 2.5 . The modeling results for t he preconstruction monitoring re quirement 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 NO 2 , PM 10 , and PM 2.5 are required as part of this analysis since the modeling results were above the SILs for NO 2 , PM 10 and PM 2.5 and a subsequent NAAQ S analysis was required. As a result, these analyses were completed for NO 2 , PM 10 and PM 2.5 PSD increments and
NAAQS.

Table 3 Preconstruction Monitoring Analysis

CRITERIA

POLLUTANT TIME

AVERAGING

PERIOD MAXIMUM MODELED
IMPACT (ug/m 3 ) DE MINIM I S

MONITO RING LEVEL (ug/m 3 ) ABOVE DE MINIMI S

MONITORING LEVEL

CO 8

- Hour 111

. 5 575 No

NO 2 Annual 1. 4 14 No

PM 10 24

- Hour 1 2

. 1 10 Yes

PM 2.5 24

- Hour 6. 0 4 Yes

Background Monitors

Background data were taken from the air quality monitoring sites in the Bloomingt on and Evansville area s using the NO 2 and PM 10 monitor s located on Buena Vista Road in Evansville and the Bloomington

- Binford

PM 2.5 monitor located on East 2 nd Street in Bloomington

. The 1

- hour NO 2 background concentration used
the 98 th percentile or the 8 th high averaged over 3 years and the annual NO 2 background used the 3

- year average of the highest annual concentrations. The maximum 2 nd high concentrations were used for the

24

- hour PM 10

. The 24

- hour PM 2.5 background concentration used t he 24

- hour 3

- y ear design value or the

98 th percentile of the 24

- hour value averaged over 3 years

. The annual PM 2.5 background concentration
used the annual 3

- year design value. The NO 2 , PM 10 , and PM 2.5 background concentrations were taken
from the 20 10 to 201 2 air qua lity monitoring data.IPL Eagle Valley Gen. Station Page 7 of 17
Martinsville

, Indiana PSD/SSM No. T109

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Permit Writer: Mark Neyman

Table 4 Existing Monitoring Data Used for Background Concentrations

CRITERIA

POLLUTANT MONITOR SITE MONITOR LOCATION AVERAGING PERIOD CONCENTRATION

( ug/m 3 )

NO 2 18

- 163

- 0021 Evansville 1

- Hour 6 7

. 9

NO 2 18

- 163

- 00 21 Evansville Annual 20. 9

PM 2.5 18

- 105

- 0003 Bloomington 24

- Hour 23

PM 2.5 18

- 105

- 0003 Bloomington Annual 10. 4

PM 10 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 PM 10 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 SIL s for the annual PM 10 of 1 ug/m 3 and the 1

- hour and 8

- hour CO SILs of 2000 ug/m 3 and 500 ug/m 3 , respectively . The OAQ NAAQS modeling results are shown in Table 5 . All
maximum modeled concentrations were compared to the ir respective NAAQS

. All maximum modeled

concentrat ions during the five years of modeling were below the NAAQS standards with the exception of

the 1

- hour NO 2 NAAQS. Additional air quality modeling was not required for the 24

- hour PM 10 and PM 2.5 and the annual PM 2.5 and NO 2 standards. The 1

- hour NO 2 NAAQS modeling results shown in Table 5
had a violation of the 1

- hour NO 2 standard of 100 parts per billion (ppb) or 188 .7 ug/m 3 . The highest 8 th

high 1

- hour NO 2 concentration averaged across five years was 41 9

. 7 ug/m 3 resulting in a total 1

- hour NO 2 concentra tion of 48 7

. 6 ug/m 3 with a background concentration of 67. 9 ug/m 3 . The highest 8 th

- high

max imum daily 1

- hour NO 2 modeled concentration of 41 9

. 7 in Table 5 was adjusted from an actual
modeled concentration of 5 24 .6 ug/m 3 by using the NO 2 /NO

x default ambien t rat io of 0.8 (5 24 .6 X 0.8 =

41 9

. 7 ) for a 1

- hour concentration. The annual NO 2 modeled concentration shown in Table 5 has been adjusted by the 0.75 default ambient ratio for NO

x to NO 2 conversion for an annual concentration.

The 24

- hour PM 2.5 NAAQS anal ysis shown in Table 5 used the 98 th percentile or the 8 th highest 24

- hour concentration averaged across five years of modeling for the modeled concentration which is the same
form of the 24

- hour PM 2.5 standard as the 24

- hour PM 2.5 monitored background conc entration. This change to the 98 th percentile form of the 24

- hour PM 2.5 standard for the NAAQ S analysis is the result of

the recommendation from the “Draft Guidance for PM 2.5 Permit Modelin g” document dated March 4, 2013. Additionally, the annual PM 2.5 NA AQS was revised from 15 ug/m 3 to 12 ug/m 3 by the U.S. EPA on December 14, 2012 with the final rule effective da te of March 18, 2013 , Federal Register dated January 15, 2013. The annual PM 2.5 NAAQS shown in Table 5 reflects this revision in the annual PM 2. 5 standard

to 12 ug/m 3

.IPL Eagle Valley Gen. Station Page 8 of 17
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Table 5 NAAQS Analysis

CRITERIA

POLLUTANT TIME

AVERAGING

PERIOD YEAR MODELED
CONCENTRATION

(ug/m 3 ) BACKGROUND

CONCENTRATION

(ug/m 3 ) TOTAL
CONCENTRATION (ug/m 3 ) NAAQS (ug/m 3 ) NAAQS

VIOLATION

NO 2 1

- Hour 5 Year 41 9

. 7 67. 9 48 7

. 6 188 .7 Yes

NO 2 Annual 200 7 6.9 20. 9 27.8 100 No

PM 2.5 24

- Hour 5 Y ear 3.3 2 3 2 6.3 35 No

PM 2.5 Annual 5 Year 0.5 10. 4 10.9 12 No

PM 10 24

- Hour 2008 6.2 34.7 40. 9 150 No

1

- Hour NO 2 Contribution Analysis and Results

The 8 th

- high 1

- hour NO 2 co ncentration represents the 98 th percentile of the 1

- hour daily maximum concentrations averaged across five years of modeling. A total of 2 7 receptors violated the 1

- hour NO 2 NAAQS of 100 ppb or 188 .7 ug/m 3 . As a result, OAQ performed additional 1

- hour NO 2 modeling for the

2 7 receptors which violated the 1

- hour NO 2 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 m aximum daily contribution output option was selected in AERMOD and the 1

- hour
NO 2 SIL of 7.5 ug/m 3 was used as the threshold value for a significant contribution . For the highest 8 th

high maximum daily 1

- hour NO 2 concentration averaged over five years in Table 5, the total contribution by the IPL PSD major source modification was 0.0 0175 ug/m 3 . The results of the 1

- hour NO 2 contributio n analysis for the highest 1

- hour concentration for a NAAQS violating receptor are shown in Table 6. All 2 7 violating re ceptors had 1

- hour NO 2 contributions from the IPL PSD major source modification which were

below the 1

- hour NO 2 SIL of 7.5 ug/m 3 . As a result

, the IPL PSD major source modification does not have

a significant contribution or impact on any receptor which s howed a 1

- hour NO 2 NAAQS violation.

Table 6

1

- Hour NO 2 Contribution Analysis

CRITERIA

POLLUTANT TIME

AVERAGING

PERIOD YEAR MODELED
CONCENTRATION

(ug/m 3 ) BACKGROUND

CONCENTRATION

(ug/m 3 ) ABOVE
NAAQS

> 188.7 TOTAL
CONTRIBUTION
IPL PSD (ug/m 3 ) SIL (ug/m 3 ) ABOVE
SIL

NO 2 1

- Hour 5 Year 41 9

. 7 67. 9 Yes 0.0 0175 7.5 No

The OAQ performed an additional air quality modeling analysis for all receptors in the 1

- hour NO 2 SIA analysis, a total of 2 535 receptors, which exceeded the 1

- hour NO 2 SIL of 7.5 u g/m 3 to determine if any of these receptors exceeded the 1

- hour NO 2 NAAQS. A total of four receptors did exceed the 1

- hour NO 2 NAAQS when the background concentration of 67. 9 ug/m 3 was added to the modeled concentration

. However, the 8 th

- high (98 th perce ntile) of the maximum daily 1

- hour NO 2 contribution averaged over 5

years from the IPL Eagle Valley PSD major source modification at each of the four receptors was belowIPL Eagle Valley Gen. Station Page 9 of 17
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the SIL of 7.5 u g / m 3

. The results of the 1

- hour NO 2 contribution modeling for each of the four receptors
are shown in Table 7.

Table 7

1

- Hour NO 2 Contribution Analysis for Receptors Exceeding SIL and NAAQS

CRITERIA

POLLUTANT TIME

AVERAGING

PERIOD YEAR MODELED
CONCENTRATION

(ug/m 3 ) BACKGROUND

CONCENTRATION

(ug/m 3 ) ABOVE
NAAQS

> 188.7 TOTAL
CONTRIBUTION
IPL PSD (ug/m 3 ) SIL (ug/m 3 ) ABOVE
SIL

NO 2 1

- Hour 5 Year 204.3 67. 9 Yes 0.00 582 7.5 No

NO 2 1

- Hour 5 Year 138.4 67. 9 Yes 0.00 5 5 5 7.5 No

NO 2 1

- Hour 5 Year 132. 4 67. 9 Yes 0.001 49 7.5 No

NO 2 1

- Hour 5 Year 131. 2 67.9 Yes 0.0 19 89 7.5 No

Analysis and Results of Source Impact on the PSD Increment

Applicability

Maximum allowable increases or PSD inc rements ar e established by 326 IAC 2

- 2 for PM 10 , PM 2.5 , and
NO 2

. This rule also limits a source to no more than 80 percent of the available PSD increme nt to allow for future growth

. Only PM 2.5 emissions increases since the PM 2.5 major source baseline date of October 20,

2010 actually consume PM 2.5 increment. The IPL Eagle Valley PSD major source modification will

establish the PM 2.5 minor source baseline date for Morgan County. The PM 2.5 minor source baseline
date for Morgan County will be the date of the IPL Eagle Valley permit application.

Source Impact

Sin ce the modeled impact s for the annual NO 2 and PM 2.5 , and 24

- hour PM 10 and PM 2.5 from the IPL Eagle Valley major source modification were above the SILs of 5 ug/m 3 (24

- hour PM 10 ) , 1.2 ug/m 3 (24

- hour PM 2.5 )

, 1 ug/m 3 (annual NO 2 ) , and 0.3 ug/m 3 (annual PM 2.5 ) a PSD increment analysis for the

ex isti ng major sources was r equ ired as part of this air quality analysis . The results of the OAQ NO 2 , PM 10 , and PM 2.5 PSD incremen t analysis are shown below in Table 8 . The annual NO 2 modeled
concentration shown in Table 8 has been adjusted by the 0. 75 default ambient ratio for NO

x to NO 2 conversion for an annual concentration.IPL Eagle Valley Gen. Station Page 10 of 17
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Table 8 PSD Increment Analysis

CRITERIA

POLLUTANT TIME

AVERAGING

PERIOD YEAR MODELED
CONCENTRATION

(ug/m 3 ) PSD
INCREMENT

(ug/m 3 ) 80 PERCENT OF
PSD INCREMENT

(ug/m 3 ) PSD
INCREMENT

VIOLATION

NO 2 A nnual 200 7 1.75 25 20 No

PM 2.5 24

- Hour 2008 4.9 9 7.2 No

PM 2.5 Annual 20 07 0.3 9 4 3.2 No

PM 10 24

- Hour 2008 6 .2 30 24 No

The results of the modeling show no PSD increment for NO 2 , PM 10 , and PM 2.5 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 a nalysis assesses the impacts on economic growth, soils and vegetation, wildlife and plant species, and visibility caused by any increase in emissions of any regul ated pollutant
from the source. The IPL Eagle Valley PSD permit app lication provided an addition al impact analysis performed by ERM

.

Economic Growth

No impact from the economic growth is expected from the IPL Eagle Valley PSD permi t major source
modification and physical change s at the IPL Eagle Valley facility . The ex isting Martinsville , Indiana and Morgan County community will be able to adequately handle potential commercial growth asso ciated with
this future plant modification. An additional employment of 30 to 40 people is expected as a result of this facility mod ification.

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 Morga n 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 threshold s necessary to have an advers e impact on the su rrounding soils and vegetation. The results of the soils and vegetation ana lysis are listed in the IPL Eagle Valley PSD Permit Application , section 8, page 26.IPL Eagle Valley Gen. Station Page 11 of 17
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Federal Endangered Species Analysis

Federal and State endangered or threa tened 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 bat s

, and one specie eac h 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 th e endangered species other than that which has already occurred
from the industrial and res id ential activities in the area. The endangered species of bats maintain s habitat s 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 NO 2 and PM 10 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 0.0 16

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 kilomete rs 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 NO 2 , PM 10 , SO 2 , and H 2 SO 4 (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

Fin ally, the results of the additional impact analysis conclude t he operation of the IPL Eagle Valley facility will have no significant impa ct 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, t here are no threatened or endangered plant species in Morgan County.IPL Eagle Valley Gen. Station Page 12 of 17
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### Part F

- Secondary Ozone Formation Analysis

Because of the well established relationship between nitrogen oxides (NO

x )

, volatile organic compounds (VOCs), and the regional transport f ormation 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 NAAQ S in the eastern U.S. The source category responsible for these reductions is Electric Generating Units (EGUs). While th e 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/crossstat erule/techinfo.html

.

Information regarding the NO

x emission s 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 NO

x emissions for Indiana in 201 2 at 4 55,325 tons and base

case annual NO

x emissions by 2014 at 431,342 tons. India na’s total NO

x emission red uction between
these scenarios total s 23,983 tons. All surrounding states make similar significant reductions. IPL Eagle Valley ’s proposed emissions w ou l d be 176.7 tons per year of NO

x and 170.0 tons per year of VOCs for a

tota l of 346.7 tons per year of NO

x 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 20 10

- 201 2 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

- h our ozone concentration for Morgan County is

71.7 ppb for the 201 2 base case and 7 0.2 ppb for the 201 4 base case . This is a decrease of 1.5 ppb as a
result of NO

x emission adjustment s 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 NO

x 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 NO

x 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 NO

x and VOC emissions to Indiana’s 2012 to 2014 base
case NO

x emission reduction was calculated. This ratio was then compared to the modeled ozone impact
f rom the difference between the CSAPR 2012 and 2014 base case modeling results.

1) 346.7 tons IPL Eagle Valley NO

x and VOC emissions / 23,983 tons of Indiana’s NO

x base case
emissions reduced from 2012 to 2014 = 1

. 4 5% ratio of IPL Eagle Valley ’s NO

x and VO C emissions compared to Indiana’s NO

x emissions

2) 1

. 4 5% IPL Eagle Valley emission ratio * 1. 5 ppb maximum 8

- hour 2012 to 2014 Base C ase modeled

results for Morgan County = 0.0 22 ppb of IPL Eagle Valley 8

- hour ozone impactIPL Eagle Valley Gen. Station Page 13 of 17
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3) 0.0 22 ppb of IPL Eagle Vall ey 8

- hour ozone impact / 7 0.2 ppb at Morgan County ozone monitor from

2014 base case maximum modeled results = 0.0 3 % IPL Eagle Valley’s impact o n 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 C ase 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 monitor s and the potential impact s from IPL Eag le 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

(%)

18109000 5 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 NO

x and VOC emissions were compar ed 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 NO

x emission reductions realized from emissio n estimates
associated w ith 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 Mo rgan County and any surrounding
counties

.



### Part G

- Secondary PM 2.5 

### Formation Analysis

In addition to direct emissions of PM 2.5 ; other pollutants, chiefly NO

x and SO 2 , can lead to formation of

PM 2.5 further downwind. The photochemical reactions that tr ansform these pollutants into particulate nitrates and sulfates, which become the major species of PM 2.5 , take place over hours or days. Dispersion modeling for the NO 2 primary pollutant shows the concentrations are well below the respective NAAQS for th e IPL Eagle Valley contribution and will further diminish within the modeling domain of 50

km. Since the 1

- hour NO 2 standard is very restrictive, these levels would likely prevent the pollutants from impacting secondary formation significantly enough to r esult in a violation of the PM 2.5 standards. SO 2 dispersion modeling was not required for this PSD major source permit modification since the SER was below 40 tons per year.

I t is possible that some transformation into nitrates and sulfates from this so urce may occur and be transported downwind. No peer

- reviewed regulatory model presently exists to examine the photochemical impacts of an individual source of SO 2 and NO

x . All photochemical models are regionalIPL Eagle Valley Gen. Station Page 14 of 17
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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 PM 2.5 monitor to IPL Eagle Valley is the West 18 th Street PM 2.5 monitor in western Marion County. The 2011 wind rose taken from the Indianapolis International Airport in Indianapolis, Marion County shows the winds typically blow fr om the southwest and west. IPL Eagle Valley would be con sidered upwind of the West 18 th Street monitor.

Indianapolis 2011

The 20 09

– 201 2 annual PM 2.5 design value at the West 18 th Street monitor in Marion County is 1 2

. 7 μg/m 3 , which is just above the annual PM 2.5 NAAQS of 1 2 .0 μg/ m 3 . The 2009

– 201 2 24

- ho ur PM 2.5 design value at the West 18 th Street monitor in Marion County is 29.0 μg/m 3 , below the 24

- hour PM 2.5 NAAQS of 35.0 μg/m 3

.

Secondary PM 2.5 Weight of Evidence Analysis based on EPA’s CSAPR Modeling

Because of the well established relationship be tween NO

x and SO 2 , and the regional transport and
formation of PM 2.5 , U.S. EPA recently finalized the Cross State Air Pollution Rule (CSAPR) to assist states
to meet the PM 2.5 NAAQS . This rule included extensive modeling to support the emissions reduction s necessary in each state to achieve the PM 2.5 NAAQS in the eastern U.S. The source category responsible for these reductions is Electric Generating Units (EGUs). While th e U.S. Court of Appeals for the D.C. Circuit issued a decision vacating CSAPR on Au gust 21, 2012, the modeling analysis conducted by U.S. EPA is considered valid and will be used for the secondary PM 2.5 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 PM 2.5 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 atIPL Eagle Valley Gen. Station Page 15 of 17
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http://www.epa.gov/crossstaterule/techinfo.html

.

Information regarding SO 2 and NO

x emission reductions necessary to achieve the future year modeled design values can be found in the “ EmissionsSummaries.xlsx” spreadsheet under t he 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 SO 2 and
NO

x emissions for Indiana in 2012 and 2014. Indiana’s total SO 2 and NO

x 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. Poten tial s to emit after controls for IPL Eagle Valley are 176.7 tons per year of NO

x and 3 0

. 9 tons per year of SO 2 for a total of 207.6 tons per year of NO

x and SO 2 emissions.

Table 10
EPA’s Cross

- State Air Pollution Rule Emission Summary for Indiana

Pollut ant 2012
Base Case

Emissions (tons/year) 2014
Base Case

Emissions (tons/year) 2012

- 2014
Difference (tons/year)

I ndiana SO 2 929,162 863,923 65,239

Indiana NO

x 455,325 431,342 23,983

TOTAL 89,222

Annual PM 2.5 Modeling Results

The latest annual P M 2.5 design value (20 10

- 201 2 ) f or the nearest PM 2.5 monitor to IPL Eagle Valley is the
West 18 th Street monitor in Marion County is 12. 7 μg/m 3 . The maximum annual PM 2.5 modeled
concentration for the West 18 th Street PM 2.5 monitor is 1 5.16 μg/m 3 for the 20 1 2 base case and 1 4.65 μg/m 3 for the 2014 base case results . This is a decrease of 0. 51 μg/m 3 . Indiana’s 2014 SO 2 emissions
from EGUs were adjusted by 65,239 tons from the 2012 base case emissions and 2014 NO

x emissions were reduced by 23,983 for a total of 89,222 tons of SO 2 and NO

x . 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 SO 2 and NO

x emission reductions will occur by 2014 , many of which w ill impact th e Marion County monitor . Therefore, to estimate the impact of IPL Eagle Valley on modeled concentrations, the
ratio of IP L Eagle Valley’s SO 2 and NO

x emissions to Indiana’s SO 2 and NO

x decrease s from 2012 and
2014 base case CSAPR emissions w e re calculated. This ratio was then compared to the modeled annual

PM 2.5 impact from the difference between the CSAPR 2012 and 2014 base case annual PM 2.5 modeling
results.

1) 207.6 tons IPL Eagle Valley’s SO 2 and NO

x emissions / 89,222 tons of SO 2 and NO

x e missions reduced through CSAPR model ing = 0.233 %

2) 0. 233 % IPL Eagle Valley SO 2 /NO

x emission ratio * 0.5 1 μg/m 3 modeled annual PM 2.5 CSAPR results

at the West 18 th Street monitor = 0.00 12 μg/m 3 of IPL Eagle Valley annual PM 2.5 impact

3) 0.00 12 μg/m 3 IPL Eagle Valley’s annual PM 2.5 impact / 1 4.65 μg/m 3 of 2014 Base Case annual PM 2.5 modeled results at the West 18 th Street monitor = 0.008 % IPL Eagle Valley’s impact o n the 2014 modeled
Base Case annual PM 2.5 results.IPL Eagle Valley Gen. Station Page 16 of 17
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Tables showing projected base case 2 014 PM 2.5 concentrations at existing monitoring sites versus control

strategy PM 2.5 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 Bas e represents anticipated 2014 emissions, 2014 Remedy represents the 2014 Base emissions with emission reductions from CSAPR factored into the modeling. Table 1 1 on page 15 shows the CSAPR annual PM 2.5 modeled concentrations at the Marion County PM 2.5 moni tors and IPL E agle Valley anticipated impacts.

It should be noted that the monitor at West 18 th Street violates the 2012 PM 2.5 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 SO 2 , NO

x , and direct PM 2.5 will all be reduced by well over 1000 tons each per year. Further, permit condition “D.1.0

Ret irement 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 w ill never operate at the same time as the old units and will emit substantially less pollutants, resulting in less impact on the West 18 th Street monitor than the previous configuration.

Table 1 1
EPA’s Cross

- State Air Pollution Rule

- Annual PM 2.5 Model ing Results

Monitor ID County 2012

Base 2014

Base 2012

- 2014

Base (μg/m 3 ) Anticipated Source Impact (μg/m 3 ) 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 0.00 82%

180970043 * Marion 13.45 12.97 0.48 0.0011 0.0086%

* Monitor not longer active

24

- Hour PM 2.5 Modeling Results

The same emissions and impact analysis methodology used for the annual PM 2.5 impacts were used to
determine the 24

- hour PM 2.5 impacts from IPL Eagle Valley . The latest 24

- hour PM 2.5 design value (20 10

- 201 2 ) f or the nearest PM 2.5 monitor to IPL Eagle Valley is the West 18 th Street monitor in Marion County is

29.0 μg/m 3 . The maximum 24

- hour PM 2.5 modeled concentration for the West 18 th Stree t PM 2.5 monitor is

36.9 μg/m 3 for the 2012 base case and 35.1 μg/m 3 for the 2014 base case . This is a reduction of modeled
concentration of 1.8 μg/m 3

. T o estimate the 24

- hour impact of IPL Eagle Valley on modeled concentrations, the ratio of IPL Eagle Va lley SO 2 and NO

x emissions and the CSAPR SO 2 and NO

x emission reductions w ere calculated. This ratio was then compared to the modeled 24

- hour PM 2.5 impact
from the difference between the CSAPR 2012 and 2014 base case 24

- hour PM 2.5 modeling results.

1) 2 07.6 tons IPL Eagle Valley SO 2 and NO

x emissions / 89,222 tons of SO 2 and NO

x e missions reduced through CSAPR model ing = 0.233 %

2) 0.233 % IPL Eagle Valley SO 2 /NO

x emission ratio * 1.8 μg/m 3 modeled 24

- hour PM 2.5 CSAPR results at
the West 18 th Street monit or = 0.0042 μg/m 3 of IPL Eagle Valley 24

- hour PM 2.5 impact

3) 0.0 04 2 μg/m 3 IPL Eagle Valley 24

- hour PM 2.5 impact / 3 5 .1 μg/m 3 of 2 014 Base Case 24

- hour PM 2.5 modeled results at the West 18 th Street monitor = 0.012 % IPL Eagle Valley’s impact o n the 2014 m odeledIPL Eagle Valley Gen. Station Page 17 of 17
Martinsville

, Indiana PSD/SSM No. T109

- 3 2471

- 00 004
Permit Writer: Mark Neyman

Base Case 24

- hour PM 2.5 concentration

.

Modeling results below in Table 1 2 show 201 2 and 2014 Base Case modeled 24

- hour concentrations and the anticipated IPL Eagle Valley impacts, based on the emissions comparison and estimated impacts.

Table 1 2
EPA’s Cross

- State Air Pollution Rule

- 24

- Hour PM 2.5 Modeling Results

Monitor ID County 2012

Base 2014

Base 2012

- 2014

Base (μg/m 3 ) Anticipated Source Impact (μg/m 3 ) Source Impact on
2014 Base Case

Results (%)

180970081 Marion 36.9 35.1 1.8 0.004 2 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 PM 2.5

IPL Eagle Valley’s SO 2 and NO

x emissions were compared with U.S. EPA CSAPR modeling for a nnual
and 24

- hour PM 2.5 to determine what impacts of PM 2.5 may occur as a result of secondary PM 2.5 formation. When the IPL Eagle Valley emissions were compared with the amount of SO 2 and NO

x 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 near est PM 2.5 monitor is anticipated to be
minimal and will not have an effect on the attainment status of any PM 2.5 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, NO 2 , PM 10 , PM 2. 5 , SO 2 , and VOC emissions

. ERM Consultants in Rolling Meadows, Illinois p repared the air quality analysis portion of the PSD permit application. Morgan County is designated as attainm ent for all criteria pollutants. CO, NO 2 , PM 10 , PM 2.5 and VOC emission rates associated with the proposed IPL Eagle Valley facility PSD major so urce modification did exceed the respective significant emission rates. Modeling results taken from the latest 12 345 version of the
AERMOD model showed the 1

- hour and 8

- hour CO and the annual PM 10 modeled impacts were predicted
to be less than the SIL s an d 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 NO 2 , the 24

- hour PM 10 and PM 2. 5 , and the annual PM 2.5

. Since ther e is c urrently no 1

- hour
NO 2 PSD increment , only an annual NO 2 PSD increment analysis was required for NO 2

. The 1

- hour NO 2 NAAQS analysis showed modeled violations, but the additional NO 2 contribution analysis showed the IPL Eagle Valley facility had an i mpact below the 1

- hour NO 2 SIL for the violating receptors

. IPL Eagle Valley
did trigger the preconstruction monitoring for PM 10 and PM 2.5 which was satisfied by existing monitoring

data

. A secondary ozone formation and a secondary PM 2.5 formation analys is 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 a dditional impact analysis was completed, but the operation of the proposed IPL Eagle Vall ey 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 St ation
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
Si gnificant 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 ste am 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 (B ACT) 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

address ed the following pollutants: PM, PM 10 , PM 2.5 , VOC, CO, NOx, H 2 SO 4 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

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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, permi tted in 201 3, each with a total rated heat input capacity of 2,542 MMBtu/hr; with NO

x 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 VOC s including formaldehyde, and exhausting to
stacks S

- 1 and S

- 2. Each stack has continuous emissions monitors (CEMS) for NOx.

* N ote: The heat recovery steam generators are not a source of emissions. They have been
included for clarit y as they are a part of th e 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

201 3, with a rated heat input capacity of 79.3 MMBtu/hr, equipped with low NOx burner s (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

201 3, 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 fir ed Emergency Generator, identified as emission unit EU

- 5, permitted in 201 3, 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

source s .][Under 40 CFR 63, S ubpart ZZZZ, the fired Emergency Generator is considered
new affected source s .]

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

- 6, permitted in 201 3, with a rated capacity of 500 HP and exhausting through stack S

- 6. [U nder 40 CFR 60, Subpart IIII, the Emergency Fire Pump is considered new affected

source s .][Under 40 CFR 63, Subpart ZZZZ, the fired Emergency Fire Pump is considered
new affected source s .]

(c ) One (1) evaporative cooling tower, identified as emission unit U

- 7, rat ed 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 (SF 6 ) 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 201 3

.IPL Eagle Valley generating Station TSD

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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 cont rol 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: Ide ntify 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 pot entially 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 te chnology 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 comm ercial 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 Genera ting 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 reducti on 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 concer n. 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 envi ronmental 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 eac h 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 underIPL Eagle Valley generating Station TSD

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cons ideration 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 Contr ol 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 t echnologies 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/PM 10 ) BACT

– Combined Cycle Combustion Turbines EU

- 1

- EU

- 2

Step 1: Identify Potential Control Technologies

Emissions of PM and PM 10 are generally controlled with add

- on control equipment de signed 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 PM 10 emissions are controll ed through one of the following

mechanisms:

(1) Fabric Filter Dust Collectors (Baghouses)

.

(2) Electrostatic P recipitators (ESP) ; and

(3) Wet Scrubbers;

(4) Cyclones or Multiclones;

(5) Fuel Specification; and

(6) Good Combustion Practices.

The choice of w hich 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 o f 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 s haped 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. T he 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 dis posal.

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

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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 requi red. 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 characteristi cs, and fabric properties. The most important design parameter is the air

- or gas

- to

- cloth ratio (the amount of gas in ft 3 /min that penetrates one ft 2 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 f ilters (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 whe re 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 fab ric 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 (Sta ndard) 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 p article 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 100,00 0

- 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 Pa rticulate 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 determinat ion, 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

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Wet scrubbers: A wet scrubber is an air pollution control device tha t 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 numerou s 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. Col lection 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 wate r);

(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 scru bbers 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

scrubbe r designs accommodate air flow rates over 100,000 actual cubic feet per minute an d 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 suscepti ble to
corrosion. Natural

- gas fired combustion turbines generate low Particulate emissions an d have large exhaust flowrates, resulting in very low concentrations of Particulates. A wet scrubber would not provide any measurable emission reduction.

Based o n 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 me chanical 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 le ss 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.IPL Eagle Valley generating Station TSD

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The g as 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 P articulate emissions and have large exhaust flow rates, resulting in very low concentrations of P articulates

. Cyclones would not provide any measurable emission reduction.

Based on the inf ormation 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 c lean nat ural 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 PM 10 emissions.

Based on the information reviewed for this BACT determi nation, 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 m aintenance of the combined cycle combustion turbines to keep them in good working order per the manufacturer's specifications will
minimize PM and PM 10 emissions.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined th at
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 bee n id entified for control of PM and PM 10 r esulting 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 Re sults

The following table lists the proposed PM and PM 10 BACT determination along with the existing

PM and PM 10 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 Descript ion 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 PM 10 : 1 6. 8 pounds per
hour and 0.00 66 lbs/MMBtu, with duct firing based

on 3

- hr average Good
Combustion
Practice and
Fuel SpecificationIPL Eagle Valley generating Station TSD

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BACT ID or
Permit # Facility Issued Date Process Descript ion Rating ( MMBtu/hr ) Limitation Control

Method

13.9 pounds per
hour and 0.00 55
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/PM 10 /PM 2.5 : 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 PM 2.5 & P M 10 : 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) PM 10 : 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 fuel

fired Combined Cycle Combustion Turbine, with ultra

low sulfur diesel fuel as backup 1758
MMBt u/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
Combust ion
Turbine 170 MW 0.02 gr/dscf, natural gas specification; 0.0015% sulfur by weight fuel oil spec; 10% opacity NoneIPL Eagle Valley generating Station TSD

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BACT ID or
Permit # Facility Issued Date Process Descript ion 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 PM 10 : 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 PM 10 : 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 fue l 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 PM 10 : 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/PM 10 None

The RBLC was reviewed and a summary of the BACT determinations for PM/PM 10 fine emissions from
combust ion 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 s cience, 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 natu ral 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 fa cility 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 evalua ting 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 o f 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 acti ve control over these site specific and case specific factors, and no known ability to reduce its emissions of PM 2.5 if needed to demonstrate compliance, BACT emission limitationsIPL Eagle Valley generating Station TSD

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for PM and PM 10 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 PM 2.5 from a similar source. In all cases, the only
available control for PM/PM 10 /PM 2.5 for combustion turbines is the use of sweet natural gas (that is pipeline qua lity 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/MM Btu 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 l bs/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 PM 10 emissions from the proposed combined cycle combustion turbines, identified as EU

- 1

- EU

- 2 :

1. The PM and PM 10 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 PM 10 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 Deteri oration (PSD ) ), IDEM has established the following as BACT for PM and PM 10 for the combustion turbines ( EU

- 1

- EU

- 2 )

.

1. The PM and PM 10 emissions from the combined cycle combustion turbines identified as
EU

- 1 and EU

- 2 shall not exceed 16.8 pounds per hou r , 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 PM 10 emissions from the combined cycle combustion turbines identified as
EU

- 1 and EU

- 2 shall not exceed 13.9 poun ds per hour, each and 0.00 55 pounds per MMBtu, each without duct firing based on 3

- hr average through the use of good combustion practices

.

3. Only p ipeline natural gas only shall be f ired in the combined cycle combustion turbines
identified as EU

- 1 and E U

- 2

.IPL Eagle Valley generating Station TSD

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Particulate Matter (PM 2.5 ) BACT

– Combined Cycle Combustion Turbines EU

- 1

- EU

- 2

Step 1: Identify Potential Control Technologies

Emissions of PM 2.5 are generally controlled with add

- on control equipment designed to capture the emissions prior to the t ime 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 2.5 emissions are controlled through one of the following mechanisms:

(1) Fabr ic Filter Dust Collectors (Baghouses)

.

(2) Electrostatic P recipitators (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 a pplication 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 effici ency.

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 betwee n 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 r anging 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 acro ss 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

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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 ft 3 /min that penetrates one ft 2 of fabric) and the usual operating parameter of interest is pressure drop across the filter system. The major operating feature of fabric filters that disti nguishes them from other gas filters is the ability to renew the filtering sur face periodically by cleaning. Common furnace filters, high efficiency particulate air (HEPA) filters, high efficiency air filters (HEAFs), and automotive
induction air filters a re 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 fil ters 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 b y 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 accomplishe d 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 efficienc ies 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 va ries 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 elec trostatic 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 in dustrial 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 gasIPL Eagle Valley generating Station TSD

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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 PM 2.5 , none of the identified traditional particulate control technologies identified would exhibit any meaningful emission control. None of these technologie s 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 eff iciency, 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, cyclon es 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 th an 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 g as 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 para llel). Cyclones typically exhibit lower efficiencies when collecting smaller particles. High

- efficiency units may require substantial pressure drop. Natural

- gas fired combustion turbines generate low P articulate emissions and have large exhaust flow rates , resulting in very low concentrations of P articulates

. 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 fe asible option for the combined cycle combustion turbines (EU

- 1 and EU

- 2) at this source.

Fuel Specifications Combusting only c lean natural gas, which has an inherently low sulfur content, rather than higher
sulfur content fuels alone or in combination wit h natural gas has a very low potential for generating PM 2.5 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 co mbustion
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 w ill
minimize PM 2.5 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 ) a t this source.IPL Eagle Valley generating Station TSD

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Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of PM 2.5 r esulting from the operation of

the combined cycle combustion turbines ( EU

- 1 and EU

- 2 )

.

(1) Fuel Spe cifications ; and

(2) Good Combustion Practices

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM 2.5 BACT determination along with the existing PM 2.5 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 ot her 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 2.5 : 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 0.00 55
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/PM 10 /PM 2.5 : 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 N atural gas

- fired Combined Cycle
Combustion Turbine, with fuel
oil as back

- up 7146
MMBtu/hr PM 2.5 & PM 10 : 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 Pl ant

- Mayes, OK 01/23/2009 Combined Cycle Cogeneration > 25MW (1,882 MMBtu/hr) PM 10 : 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

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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 01/14/20 08 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 fuel

fired Combined Cycle Combustion Turbine, with ultra

low 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
Mu nicipal
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
Cent er

- Suffolk, NY 05/10/2006 Natural gas

- fired Combined Cycle
Combustion

Turbine 2221
MMBtu/hr PM 10 : 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 PM 10 : 0.0510
lb/MMB tu 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
Station

Yuma, AZ 12/01/2004 Natural gas

- fired Combined Cycle
Combustion

Turbine and
HRSG 170 MW PM 10 : 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/PM 10 NoneIPL Eagle Valley generating Station TSD

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T he RBLC was reviewed and a summary of the BACT determinations for PM /PM 10 /PM 2.5 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 pipelin e 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 p ipeline 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 emissi ons 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 r emoved 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 emi ssions 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 t hat 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 PM 2.5 if needed to demonstrate compl iance, BACT emission limitations for PM, PM 10 and PM 2.5 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 PM 2.5 from a similar source. In all cases, the on ly
available control for PM/PM 10 /PM 2.5 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 l evel 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 lo ad 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 2.5 emissions from the proposed combined cycle combustion turbines, identified a s EU

- 1

- EU

- 2:

1. The PM 2.5 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 spec ification

.

2. The PM 2.5 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 f uel specification

.IPL Eagle Valley generating Station TSD

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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 PM 2.5 for the combustion turbines ( EU

- 1

- EU

- 2 )

.

1. The PM 2.5 emissions from the combined cy cle 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 2.5 emissions from the combine d cycle combustion turbines identified as EU

- 1
and EU

- 2 shall not exceed 13.9 pounds per hour, each and 0.00 55 pounds per MMBtu,
each without duct firing based on 3

- hr average through the use of good combustion practices

.

3. Only p ipeline natural gas only shall be fired in the combined cycle combustion turbines
identified as EU

- 1 and EU

- 2

.

Sulfuric Acid (H 2 SO 4 ) BACT

– Combined Cycle Combustion Turbines EU

- 1 & EU

- 2

Step 1: Identify Potential Control Technologies

Emissions of Sulfuric Acid (H 2 SO 4 ) emissions depend upon the sulfur content of the fuel and
oxidation of SO 2 to SO 3 , followed by immediate conversion of SO 3 to H 2 SO 4 when water vapor is present. Sulfuric Acid (H 2 SO 4 ) emissions are generally controlled with add

- on control equipment designed to captur e 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 depen ds 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. H 2 SO 4 emis sions 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 us es 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 SO 2 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 tow ers 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 SO 2 from the exhaust stream, conversion of SO 2 to SO 3 and H 2 SO 4 is

r educed. 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 cool ed as appropriate, and dry systems require use of particulate controls to collect the solid netural salts.IPL Eagle Valley generating Station TSD

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FGD systems are not listed in the RBLC as BACT for the control of H 2 SO 4 emissions for large combined cycle combustion turbines

. Technology has not b een applied to natural gas combined cycle combustion turbines due to very low SO 2 and H 2 SO 4 emissions. Controls would not provide any measurable emission reduction.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined t hat
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 sorb ent reacts with SO 2 and
SO 3 and is removed downstream by p articulate control equipment. The reduced availability of
SO 2 and SO 3 in the exhaust stream reduces H 2 SO 4 formation, thereby reducing H 2 SO 4 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 SO 2 and H 2 SO 4 emissions. Controls would not provide any measurable emission reduction. Dry sorbent injection is not listed i n the RBLC as BACT for the control of H 2 SO 4 emissions for large combined cycle combustion turbines

.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that
the use of d ry 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 natu ral gas ha s a very low potential for generating H 2 SO 4 emissions. Fuel Specifications is included in RBLC for the control of H 2 SO 4 from combined cycle combustion turbines

.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determ ined 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 i dentified for control of H 2 SO 4 r esulting 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 H 2 SO 4 BACT determination along with the existing H 2 SO 4 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 Pe rmit
No. 109

- 32471

- 00004 Proposed
Limit IPL Eagle Valley Generating
Station Proposed Combined Cycle
Combustion Turbines (EU

2,542 MMBtu/hr,

each H 2 SO 4: 0.75 gr S/100 scf of natural gas Fuel SpecificationIPL Eagle Valley generating Station TSD

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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 H 2 SO 4: 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 Fu el 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 g r 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 propos ing a natural gas sulfur content limit of 0.75 gr S/100 scf which is the most stringent limit for H 2 SO 4 emissions. Note that H 2 SO 4 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 n ot 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 H 2 SO 4 emissions from the proposed combined cycle combustion turbines, identified as EU

- 1

- EU

- 2:

(a) The H 2 SO 4 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 H 2 SO 4 for the combined cycl e combustion turbines ( EU

- 1

- EU

- 2 )

.

(a) The H 2 SO 4 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) On ly 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

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Carbon Monoxide (CO) BACT

– Combined Cycle Combustion Turbines EU

- 1 and EU

- 2

Step 1: Identify Potential Control Technologies

Emissions of carbon m onoxide (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 Syste m;

(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 o f 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 a cid 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 mu st 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 2,000 o F. Once the unit is designed and built, the residence time is not easily changed, so that the required re action 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 construct ed 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 ga ses 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 recove ry (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 C O from properly operated natural gas combustion units without the use of a catalyst.IPL Eagle Valley generating Station TSD

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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 opt ion for the combined cycle combustion turbines (EU

- 1 and EU

- 2) at this source.

Recuperative Thermal Oxidizers This control technology o xidizes 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 o pe rating temperature ranges from 1,100

- 1,2 00 o 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

p roperly 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 u tilizes a single catalyst to remove NO X , CO, and VOC through oxidation. Now operating as EmeraChem, the current version of t he technology is now marketed as EM X

. The o perating temperature ranges from 300

- 700 o F. The SCONO X Catalyst is sensitive to contamination by sulfur, so it must be used in conjunction with the SCOSO X catalyst, which favors sulfur compound absorption. T his t echnology 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 reactio n 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 ft 3 of catalyst per 1000 standard ft 3 per gas flow rate.
Similar to thermal inciner ation; 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

w aste s tream inlet f low r ate ranges from 700

- 50,000 scfm and w aste s tream i nlet p ollutant

c o ncentration 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 specificati ons. Also, sulfur and other compounds may foul the catalyst, leading to decreased efficiency. This control is w idely accepted as BACT for control of CO emissions from combined cycle combustion turbines

.

Based on the information reviewed for this BACT det ermination, 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

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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 t he use of flare for this stream would be the creation of additional emissions from burning supplemental fuel, including NO x . Flares have not been utilized or demonstrated as a control device for CO from this type of high

- volume process stream.
In additio n, 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 comb ustion turbines (EU

- 1 and EU

- 2) at this source

Good Combustion Controls
G ood 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

e ssentially 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 t emperatures, 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 C ontrols is a technically feasible o ption 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 ap plication 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 Iss ued 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 % O 2 , 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% O 2 , with

duct burners
based on 3

- hr

ave rage Oxidation CatalystIPL Eagle Valley generating Station TSD

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BACT ID or
Permit # Facility Iss ued Date Process Description Rating ( MMBtu/hr ) Limitation Control

Method

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 3.00 ppmvd @
15% O 2 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%
O 2 , 3

- hr avg(w/out duct firing); 3.2 ppm @ 15% O 2 , 3

- hr avg(w/duct firing); 208 tpy Catalytic

ox idation

OK

- 0129 Associated
Electric Cooperative,
Inc. Chouteau

Power Plant

Mayes, 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

- 0 304 Florida Municipal
Power Agency, Cane

Island Power
Park

Osceola, 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
Center

Orlando, 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

- 02 24 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% O 2 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% O 2 , 1 hr

block and 4.3 lb/hr (w/out DB); 1.7 ppmvd @
15% O 2 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 catalystIPL Eagle Valley generating Station TSD

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BACT ID or
Permit # Facility Iss ued Date Process Description Rating ( MMBtu/hr ) Limitation Control

Method County Facility

Warren, VA each with a
HRSG and 500 MMbtu/hr DB) augmentation

MN

- 0071 Minnesota Municipal
Power Agency,
Fairbaul Tenergy Park

Rice, 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
Plant

Pinellas, 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% O 2 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 Middles ex, 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 Klee n Energy Systems facility in Middletown, Connecticut provides a BACT limit of 1.7 ppmvd at 15% O 2 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 t his 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% O 2 including duct firing is consistent with other demonstrated permit
limits in the RBLC database.

The following ha s 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 sha ll not exceed 2.0ppmv @15% O2 , based on a 3

- hr average.IPL Eagle Valley generating Station TSD

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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 CO for the combined cycle combustion turbines:

(1) The C O emissions from the combined cycle combustion turbines shall be controlled by catalytic oxidation

(2) The CO emissions shall not exceed 2.0 ppmvd @15% O 2 , based on a 3

- hour

average.

(3) Only p ipeline natural gas only shall be fired in the combined cy cle combustion turbines
identified as EU

- 1 and EU

- 2

.

Carbon Monoxide (CO) BACT d uring 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

met hod 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 NO

x combustor. Combustion turbines always default to diffusion flame and pilot mode (in stead 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 gre atly 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 poten tially 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 reaso ns, 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 a nd 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

numb er 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 meanin gful limitation described in units of ppmvd @ 15% O 2 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 a re list of alternative potential control technologies tha t 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 firi ng of a single combustion turbine to maintain HRSG/STG temperatures as ready for warm or hot starts when practicableIPL Eagle Valley generating Station TSD

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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 Techni cally 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 o perational 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 pre

programmed 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 red uction 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 technical ly 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. T his 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 determin ation, 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 boi ler 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 mark et conditions support auxiliary boiler firing to provide steam to the turbine seals, to minimize steam side thermal stress and to enable rapid return to ful l firing when next called upon. This is a technique that favors the system’s maintenance schedule a nd, when economically advantageous may represent a preferred operating strategy. However, suchIPL Eagle Valley generating Station TSD

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operation is not a technically feasible requirement or operating limitation to reduce emissions of CO during startups and shutdowns because market conditions ma y 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 u se of auxili ary 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 deter mined 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 per

event and rolli ng 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 alternat ives 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

ma rket 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 f rom 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 E U

- 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) Regenerativ e thermal oxidation;

(b) Recuperative thermal oxidizer

(c) SCONOx Catalytic Absorption System;

(d) Catalytic oxidation;IPL Eagle Valley generating Station TSD

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(e) Good Combustion Controls ; and

(f) Flares.

Step 2: Eliminate Technically Infeasible Options

Regenerative Thermal Oxidizers
The the rmal 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, neverthel ess 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 co ntrolling 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 dictate s 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 2,000 o F. Once t he 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 re covery 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 cer amic 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 switc hed, 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 auxiliar y 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 o xidizes combustible materials by raisin g 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 o pe rating temperature ranges from 1,100

- 1.2 00 o F and the waste stream inlet poll utants 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 hig hly 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

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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 u tilizes a single catalyst to remove NO X , CO, and VOC through oxidation. Now operating as EmeraChem, the current version of the technology is now marketed as EM X

. The o perating temperature ranges from 300

- 700 o F. The SCONO X Catalyst is sensitive to contamination by sulfur, so it must be used in conjunction with th e SCOSO X catalyst, which favors sulfur compound absorption. T his t echnology 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 Cata lytic 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 ft 3 of catalyst per 1000 standard ft 3 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

w aste s tream inlet f low r ate ranges from 70 0

- 50,000 scfm and w aste s tream i nlet p ollutant

c oncentration 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 achie ved if exhaust flow rates exceed design specifications. Also, sulfur and other compounds may foul the catalyst, leading to decreased efficiency. This control is w idely accepted as BACT for control of VOC emissions from

combustion turbines.

Based on the i nformation 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 str eam 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 NO x . Flares have not been
utilized or demonstrated as a control device for VOC from this type of high

- volume proce ss 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 t he combined cycle combustion turbines
at this source

Good Combustion Controls
G ood 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 isIPL Eagle Valley generating Station TSD

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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 control s 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 inclu de 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 C ontrols 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 dete rminations for similar plants. All data in the table is based on the information obtained from the permit ap plication 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 Iss ued 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% O 2 , with

duct burners
based on 3

- hr

average Oxidation Catalyst

1 .0 ppmvd @15% O 2 , with out 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% O 2 , with

duct burners
based on 3

- hr

average Oxidation Catalyst 1 .0 ppmvd @15% O 2 , with out duct
burners based on

3

- hr average

GA

- 0138 Live Oaks Company, LLC,
Live Oaks

Power Plant

Glynn, GA 04/08/2010 Natural gas

- fir ed Combined Cycle
Combustion

Turbine 600 MW 2.0 ppm @ 15%
O 2 , 3

- hr average Catalytic oxidation, good
combustion practices

LA

- 0224 Southwest

Electric Power 03/20/2008 Combined Cycle
Gas Turbines 2,110
MMBtu/hr 12.06l b/hr; 4.9 ppmvd @ 15% NoneIPL Eagle Valley generating Station TSD

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BACT ID or
Permit # Facility Iss ued Date Process Description Rating ( MMBtu/hr ) Limitation Control

Method

Co. Arsenal Hill

Power Plant

Caddo, LA O 2 annual

average

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) 1,944
MMBtu/hr 1.0 ppmvd w/o ut 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% O 2 3

- hour
w/d uct burner; 1.0 ppm @ 15%
O 2 w/out duct burner (LAER) Oil: 4.0 ppm @15% O 2 , 3

- hour (LAER) Oxidation catalyst

MN

- 0071 Minnesota Municipal Power Agency,
Fairbaul Tenergy Park

Rice, 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
Pla nt

- 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% O 2 (CT only); 1.5 ppmvd @
15% O 2 (CT and DB) None

AZ

- 0047 Dome Valley Energy Partners,
Wellton
Mohawk Generating
Sta tion

- Yuma,

AZ 12/01/2004 Natural gas

- fired Combined Cycle
Combustion

Turbine and
HRSG 170 MW 3.0 ppm @ 15%
O 2 , 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% O 2 calendar day avg w/DB; 0.8 ppmdv@ 15% O 2 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% O 2 , 3

- hr avg w/DB; 1.9 ppmvd @ 15@ Oxidation catalystIPL Eagle Valley generating Station TSD

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BACT ID or
Permit # Facility Iss ued Date Process Description Rating ( MMBtu/hr ) Limitation Control

Method

Power

- Clark,

NV O 2 3

- hr avg w/out DB (LAER)

There are three other sources which have been identified as having lower limits: t he 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 l imits 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 sch eduled 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 facili ty 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 CO 2 , and are emitted as the fairly unstable molecu le 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 p roposed IPL limits with the limits cited above for the Port Washington Generating station since the averaging periods for the differen t limits differ significantly. The Port Washington facility has a slightly lower numeric value but compliance is

determine d over a daily average rather than over a 3

- hour period

. A 3

- hour period as proposed by IPL is a more stringen t averaging period than daily. Based on the different averaging periods

IDEM do not believe the limits for the Port Washington facility are in fac t 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

test s compliance basis.

Therefore, t he proposed limits of 1.0 ppmvd @15% O 2 , without duct burners, and of 2.0 ppmvd @15% O 2 , 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 VO C 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

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(2) The VOC emissions shall not exceed 2.0 ppmvd @15% O 2 , with duct burners bas ed on

3

- hr average

.

(3) The VOC emissions shall not exceed 1.0 ppmvd @15% O 2 , 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% O 2 , with duct burners based on

3

- hr average

.

(3) The VOC emis sions shall not exceed 1.0 ppmvd @15% O 2 , without duct burners based

on 3

- hr average

.

(4) Only p ipeline 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 Star tup 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 combust ion are normally controlled via precise fuel: air ratio control in the dry low NO

x 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 des ign 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, resu lting 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 highe r mass emissions) will result. During hot, warm and especially cold starts, th e oxidation catalyst is also not at sufficient temperature to effectively complete oxidation of all prod ucts 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 C lass 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 m ass 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% O 2 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 reduc tion of VOC from industrial power generation turbines during startup and shutdown conditions.IPL Eagle Valley generating Station TSD

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The following a re 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 o r 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

Th e 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 o perational 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 pre

programmed into the automated control systems, cannot be altered by the operator, and if attempted wou ld 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 turbin e 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 fr equent 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 economical ly 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 wit hin 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 combust ion turbine to minimize steam

- side starts is not aIPL Eagle Valley generating Station TSD

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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 u sed 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 seal s, to minimize steam side thermal stress and to enable rapid return to ful l 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

– t o 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 feasi ble 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

pro posed combustion turbines during startup and shutdowns are various combined cycle management techniques that may be implemented on a case

- by

- case basis to minimize per

event 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 limitatio ns 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 du ring 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 faci lity 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 combus tion 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 3 26 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

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Nitrogen Oxide (NOx) BACT

– Combined Cycle Combustion Turbines EU

- 1

- EU

- 2

Step 1: Identify Potential Control Techno logies

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 NO x emissions from
CCCTs. The SCR te chnology 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 NO x to N 2 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 NO x reduction performance occurs at the higher end of this range. Temperatures below the optimum decrease catalyst activity and allow both NO x and NH 3 to pass through unreacted; above the optimum range, ammonia will oxidize to form additional NO x

. SCR NO x reduction efficiency is also largely dependent on gaseous mixing and residence time of injected ammonia as well as the
stoichiometric mola r ratio of NH 3 : NO x . For example, variation of the theoretical 1:1 molar ratio of

NH 3 : NO x 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, NO x concentration and NH 3 concentration, especially considering variations in operating load, ramping and duct firing, with very little available mixing and reaction time between the ammonia i njection grid and catalyst bed. Due to these practical limitations, it is necessary to over

- inject ammonia to drive NO x to very low levels, meaning that surplus ammonia will be emitted from the stack as ammonia “slip.” Recent permits for large combined c ycle, natural gas

- fired combustion turbines limit NO x emissions to around 2 ppmvd @ 15% O 2 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 NO x control technology. SCR technology in combination with dry low NO x combustors is also the “top” level of control listed in
the RBLC.

Based on the information reviewed for thi s BACT determination, IDEM, OAQ has determined that

selective catalytic reduction (S CR ) is a technically feasible option for the combined cycle
combustion turbines at this source.IPL Eagle Valley generating Station TSD

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Selective Non

- Catalytic Reduction (SNCR)
Selective Non

- Catalytic Reduction (SNCR) is not applicable for control of NO x from combustion turbines. The SNCR technology removes NO x 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 NO x 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 NO
x ( DLN) Combustors
Low NO

x Burner (LNB) technology (in combustion turbines referred to as dry low NO x combustor/lean pre

- mix combustor technology) reduces the formation of NO x 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 NO x 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 re duces NO

x 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 NO x . Interna l 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 FG R 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 c ombustion
turbines at this source.

Catalytic Combustors Catalytic combustors burn the fuel at low temperature across a catalyst, hence suppressing the
formation of NO x . The only known applications are on very small (1.5 MW scale) Kawasaki

combustion turb ines. 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

Indu strial 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.

SCONO x SCONO x is a potassium based NO x 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. Whil e SCONO x 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 ofIPL Eagle Valley generating Station TSD

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NO x control that has been demonstrated by SCR. Due t o its lack of application, availability or demonstration on F Class industrial power generation combustion turbines, SCONO x technology does not represent technically feasible candidate for NO x control from the proposed combustion
turbines.

Based on the i nformation reviewed for this BACT determination, IDEM, OAQ has determined that
SCONO x 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) NO x emissions with dry low NO x combustors
than those fired with liquid fuels. The lowest NO x emissions listed in the RBLC are all for

combustio n turbines firing natur al 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
NO x formation, within the turbine combust ors. This technology is generally employed on liquid
fuel

- fired units for which dry low NO x combustors are unavailable, but is not capable of equivalent
NO x reduction performance to dry low NO x technology on gas

- fired units.

Based on the information re viewed 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 Effective ness

(1) Selective Catalytic Reduction

— (Up to 90% NOx Reduction)

(2 ) Dry Low NOx Combustors

— ( Up to 6 0% NOx Reduction)

(3) Flue Gas Recirculation;

(4 ) Natural gas firing

— ( Up to 50% NOx Reduction)

Step 4: Evaluate the Most Effective Controls a nd 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 I PL 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 Descrip tion Rating ( MMBtu/hr ) Limitation Control

Method

Draft Permit

No. 109

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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% O 2 , with

duct burners
based on 3

- hr

average SCR and dry

low NOx
combustorsIPL Eagle Valley generating Station TSD

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BACT ID or
Permit # Facility Issued Date Process Descrip tion 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% O 2 , with

duct burners
based on 3

- hr

ave rage 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%
O 2 , 3

- hr average; 87 tpy Dry Low

- NO

x 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% O 2 ; 15.25
lb/hr 1

- hr avg;
568 lb/event 4

- hr startup; 142
lb/event 1

- hr
shutdown Dry Low

NO

x burners,
SCR

FL

- 0304 Florida Municipal
Power Agen cy, 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
Com bustion Turbine, with ultra

low sulfur diesel fuel as backup 300 MW (1,765 MMBtu/hr) 8.0 ppmvd @
15% O 2 , 24

- hr average (oil); 2.0 ppmvd @ 15%
O 2 , 24

- hr average (gas) Low

- NO

x burners and
SCR water injection

LA

- 0224 Southwest

Electric Power
Co. Arsenal

Hil l Power
Plant 03/20/2008 Combined Cycle
Gas Turbines 2,110
MMBtu/hr 30.15 lb/hr; 4.0 ppmvd @ 15%
O 2 annual

average Low

- NO

x burners, duct
burners
combined
with SCR

CT

- 0151 Kleen Energy Systems, Inc. 02/25/2008 Natural gas

- fired

combustion
turbines 2.0

mm cf/hr 2.0 ppmvd @
15% O 2 , 1

- hr block (LAER) Low

- NO

x 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 NO

x 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 (o il); 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

- SCRIPL Eagle Valley generating Station TSD

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BACT ID or
Permit # Facility Issued Date Process Descrip tion Rating ( MMBtu/hr ) Limitation Control

Method Agency,
Treasure Coast Energy
Center hour block (oil)

N Y

- 0095 Caithness Bellport Energy Center 05/10/2006 Natural gas

- fired Combined Cycle
Combustion

Turbine 2221
MMBtu/hr 2.0 ppmvd @

15% O 2 SCR

Fuel oil

- fired Combined Cycle
Combustion

Turbine 2125
MMbtu/hr 6.0 ppmvd @

15% O 2 w/out DB; 6.8 ppmvd @

15% O 2 w/ 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%
O 2 , 30

- day rolling avg, each Dry Low

NO

x burners,
SCR

NV

- 0037 Se mpra Energy Resources, Copper

Mountain
Power 05/14/2004 Natural gas

- fired Combined Cycle
Combustion

Turbine 600 MW 2.0 ppmvd @

15% O 2 3

- hr avg;
17.92 lb/hr Dry Low

NO

x combustor,

steam injection, and
SCR

AZ

- 0049 Allegheny Energy Supply, LLC

La Paz
Genera ting 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

- NO

x burners and
SCR

CA

- 0997 Sacramento Municipal Utility District 09/01/2003 Natural gas

- fired

Turbines 1,611
MMBtu/hr 2.0 ppmvd @

15 % O 2 (LAER) SCR

PA

- 0226 Limerick Partners, LLC
Power Station 04/09/2002 Natural gas

- fired Combined Cycle

Turbine 550 MW 2.0 ppmvd @

15% O 2 (LAER) Low

- NO

x burners

PA

- 0188 Fairless Energy LLC 03/28/2002 Natural gas

- fired Combined Cycle

Turbine 1,190 MW 2. 5 ppmvd @

15% O 2 (LAER) Dry Low

NO

x burners,
SCR

PA

- 0223 Duke Energy Fayette, LLC 01/30/2002 Natural gas

- fired Combined Cycle

Turbine 280 MW 2.5 ppmvd @

15% O 2 (LAER) Low

- NO

x burners, SCR

This top level of control reflects the sequential combination of exclusive natural gas firing, dry low
NO x 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 tha t has been achieved in practice for similar duct fired combustion turbines is an emission rate of 2 ppmvd NO x @ 15% O 2 from the combustion turbines during normal (non

startup, shutdown or malfunction) operation, to be continuously monitored using Part 60 a nd 75 certified continuous emissions monitoring systems (CEMS). This control technology and
emission limitation also constitutes BACT for NO x for normal operation of the CCCTs.IPL Eagle Valley generating Station TSD

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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 D ry L ow N Ox combustors

.

(2) The NOx emissions shall not exceed 2.0ppmv @15% O 2 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 s hall be controlled by Selective Catalytic

Reduction and Dry Low NOx combustors

.

(2) The NOx emissions shall not exceed 2.0ppmv @15% O 2 with duct burners based

on a 3

- hr average.

(3) Only p ipeline natural gas only shall be fired in the combined cycle co mbustion 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 NO x inherent to the
diffusio n 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. T hus, DLN technology is not technically feasible during these operating conditions, and higher NO x concentrations (although not necessarily higher mass emissions) will result. During hot, warm and especially cold starts, the SCR catalyst is not at sufficie nt temperature to initiate ammonia injection for the
NO x 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 NO x per event and/or per annum. Since the combustion condition s of a combustion turbine are transient during these events, there is no meaningful limitation described in units of ppmvd @
15% O 2 because the event can be described as a series of spikes and plateaus. According to the data reviewed there is no applicabl e add

- on control technology that has been demonstrated to be technically feasible for reduction of NO x 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 NO x during startup and shutdown:

(a) Limited number of startup and shutdown events per year (and especially cold starts) ;IPL Eagle Valley generating Station TSD

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(b) Limited duration of various start events (i.e. “rapid start technology”) ;

(c) Mini mum 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 redefin ing the purpose of the project. Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that
the use of o perational limitation on number of startup events per year is not a technically feasible option for the combined cycl e 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 pre

programmed into the automated control systems, cannot be altered by the operato rs 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 tu rbine 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 l imiting the duration of hot, warm and cold startup events does not represent a technically feasible NO x 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 o f 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 technica lly feasible requirement or operating limitation for NO x 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 c ombustion 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 condi tions support auxiliary boiler firing to provide steam to the turbine seals and minimize thermal stress to enable rapid return to full firing the nextIPL Eagle Valley generating Station TSD

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day, etc. This is a technique that favors the system’s maintenance schedule and, when economically adva ntageous may represent a preferred operating strategy. However, such operation is not a technically feasible requirement or operating limitation to reduce emissions of
NO x during startups and shutdowns because market conditions may not support such operat ion 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 technical ly feasible and demonstrated in practice for the proposed combustion turbines to limit emissions of NO x during startup and shutdowns include operational techniques to minimize NO x emissions in terms of lb/event and total annual tons of
NO x per year (rollin g 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 NO x 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 NO x 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 NO x control which also reflects BACT and LAER during startup and s hutdown 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 rest rictions on the total annual NO x emissions totalized for all estimated startup and shutdown events annually. Specifically, BACT for NO x during startup and shutdown events is proposed to be 429 pounds per event and 68 tons per 12

- month rolling period for t he 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 BAC T

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 duri ng startup
and shutdown events is shall not exceed 429 pounds per event and 6 8 tons per twelve (12) consecutive month period

.

Particulate Matter (PM and PM 10 ) BACT

– Auxiliary Boiler EU

- 3

Emissions of PM and PM 10 are generally controlled with add

- on contro l 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 PM 10 emission s are controlled through one of the following
mechanisms:

(1) Fabric Filter Dust Collectors (Baghouses)

.IPL Eagle Valley generating Station TSD

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(2) Electrostatic P recipitators (ESP) ; and

(3) Wet Scrubbers;

(4) Cyclones or Multiclones;

(5) Fuel Specification; and

(6) Good Combustion Practices.

T he 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 conte nt, 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 rou nd, 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 respo nsible 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 col lection 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, g as characteristics, and fabric properties. The most important design parameter is the air

- or gas

- to

- cloth ratio (the amount of gas in ft 3 /min that penetrates one ft 2 of fabric) and the usual operating parameter of interest is pressure drop across the fil ter 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 fram es, 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

concentr ations.IPL Eagle Valley generating Station TSD

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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

- 1 00,000 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 th at 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 strea m. 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 auxi liary boilers generate
low Particulate emissions and have large exhaust flowrates, resulting in very low c oncentrations
of Particulates. Electrostatic precipitator (ESP) would not provide any measurable emission
reduction.

Based on the information reviewe d for this BACT determination, IDEM, OAQ has determined that
the use of a n 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. Colle ction 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 c apital 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

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(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 scrubb ers 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 an d 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 ar e 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 suscep tible to
corrosion. Natural

- gas fired auxiliary boilers generate low Particulate emissions an d have large exhaust flowrates, resulting in very low c oncentrations 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 us ed 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 scrubb ers, baghouses, or ESPs.

Cyclones used as pre

- cleaners are often designed to remove more than 80% of the particles that are greate r than 20 microns in diameter. Smaller particles that escape the cyclone can then be collected by mor e efficient control equ ipment. 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 g as temperature is about 1,000 °F. The typical wa ste 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 fir ed auxiliary boilers generate low P articulate emissions and have large exhaust flowrates, resulting in very low concentrations of P articulates

. Cyclones would not provide any measurable emission reduction.

Based on the information reviewed for this BACT d etermination, 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 c lean 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 PM 10 emissions.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that
the use of Fuel Specif ications is a technically feasible option for the Auxiliary Boiler ( EU

- 3 ) at this

source.IPL Eagle Valley generating Station TSD

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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 manufact urer's specifications will minimize PM and PM 10 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 ( EU

3 ) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of PM and PM 10 r esulting 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 PM 10 BACT determination along with the existing

PM and PM 10 BACT determinations for similar plants. All d ata 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 perm itting 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 PM 2.5 & PM 10 : 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 PM 10 : 1.14 lb/hr; 0.5 tpy; 7.6
lb/MMcf None

LA

- 0231 Lake Charles Generation, LLC
Lake Charles
G asification Facility 06/22/2009 Natural gas

- fired Auxiliary Boiler 938.3
MMBtu/hr PM 10 : 6.99 lb/hr NoneIPL Eagle Valley generating Station TSD

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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 PM 10 : 0.0033
lb/MMBtu None

OH

- 0407 Biomass Center,
South Point

Biomass
Generation 0/04/2006 Natural gas

- fired Auxiliary Boiler 247
MMBtu/hr PM 10 : 1.73 lb/hr; 3.26 tpy;
0.007 lb/MMBtu None

OR

- 0046 Calpine Turner Energy Center,
LLC 0 1/06/2005 Natural gas

- fired Auxiliary Boiler 417,904 MMBtu/yr PM 10 : 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 PM 10 : 0.0033
lb/MMBtu N one

NV

- 0037 Sempra Energy Resources, Copper

Mountain Power 05/14/2004 Natural gas

- fired Auxiliary Boiler 60
MMBtu/hr PM 10 : 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/PM 10 : 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 PM 10 : 1.73 lb/hr nat gas; 3.26 tpy nat gas & fuel oil; 0.007
lb/MMBtu nat

ga s 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 st ringent 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 PM 10 and the reference d test methods are 201A & 202. This permit does not address PM 2.5 . 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 combustionIPL Eagle Valley generating Station TSD

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practices, operating the equipment according to manufacturer specifications and the use of natural g as have been identified and accepted as BACT for CO, VOC, PM 10 , and SO 2 ".

• Longview Power, LLC, Maidsville, West Virginia: The limit in the permit is for PM and PM 10 emissions not for PM 2.5 . The facility was permitted in 2004 and commercial operation wa s 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 PM 10 emissions from the proposed
Aux iliary Boiler , identified as EU

- 3:

The PM and PM 10 emissions from the Auxiliary Boiler, identified as EU

- 3 shall be limited to less
than 0.00 5 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 PM 10 for the Auxiliary Boiler ( EU

- 3 ).

The PM and PM 10 emissions from the Auxiliary B oiler, identified as EU

- 3 shall not exceed 0.0 0 5
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 (PM 2.5 ) BACT

– Auxiliary Boiler EU

- 3

Emissions of P M 2.5 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 comb ustion process. Generally, PM 2.5 emissions are controlled through one of the following mechanisms:

(1) Fabric Filter Dust Collectors (Baghouses)

.

(2) Electrostatic P recipitators (ESP) ; and

(3) Wet Scrubbers;

(4) Cyclones or Multiclones;

(5) Fuel Specifica tion; 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 characte ristics (e.g., temperature, moisture content, presence of reactive materials), and desired collection efficiency.IPL Eagle Valley generating Station TSD

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Step 2: Eliminate Technically Infeasible Options

Fabric Filtration: A fabric filter unit consists of one or more isolated compartments contain ing 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, an d 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 fa bric 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 a re 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 var iables 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 ft 3 /min that penetrates one ft 2 of fabric) and the usual operating parameter o f 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
effici ency 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 du st
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 particulate s.

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 precipi tator (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 ga seous 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

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Once the particles are collected on the plates, they must be removed from the plates with out

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 b y 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 n electrostatic precipitator is not a technically feasible option for the Auxiliary Boiler (EU

- 3) at this source.

Wet scrubbers:
A wet scr ubber 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 the n 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 decre ases 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 comp act 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 ma terials (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 co ntent.

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 t han 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 rem oved 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 an d have largeIPL Eagle Valley generating Station TSD

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exhaust flowrates, resulting in very low c oncentrations 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: Cyclo nes 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 th en 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 g as 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 requi re substantial pressure drop. Natural

- gas fired auxiliary boilers generate low P articulate emissions and have large exhaust flowrates, resulting in very low concentrations of P articulates

. Cyclones would not provide any measurable emission reduction.

Base d 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 c lean 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 2.5 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, PM 10 and

PM 2.5 emissions.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that
the use of Good Combustion Practices is a technically f easible 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 PM 2.5 r esulting from the operation of
the Auxiliary Boiler (E U

- 3).

(1) Fuel Specifications; andIPL Eagle Valley generating Station TSD

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(2) Good Combustion Practices

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM 2.5 BACT determination along with the existing PM 2.5 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 Boiler s ( 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 PM 10 : 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
Cen ter 05/10/2006 Natural gas

- fired Auxiliary Boiler 29.4
MMBtu/hr PM 10 : 0.0033
lb/MMBtu None

OH

- 0407 Biomass Center,
South Point

Biomass
Generation 0/04/2006 Natural gas

- fired Auxiliary Boiler 247
MMBtu/hr PM 10 : 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 PM 10 : 0.0033
lb/MMBtu None

NV

- 0037 Sempra Energy Resources, Copper

Mountain Power 05/14/2004 Natural gas

- fired Auxiliary B oiler 60
MMBtu/hr PM 10 : 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/PM 10 : 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 PM 10 : 1.73 lb/hr nat gas; 3.26 tpy nat gas & fuel NoneIPL Eagle Valley generating Station TSD

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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 PM 10 and the referenced test methods are 201A & 202. This permit does not address PM 2.5 . We believe that this lim it 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, PM 10 , and SO 2 ".

• Longview Power, L LC, Maidsville, West Virginia: The limit in the permit is for PM and PM 10 emissions not for PM 2.5 . 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 s o operation and verification of emission factors could not be confirmed.

The following has been proposed as BACT for PM 2.5 emissions from the proposed Auxiliary Boiler, identified as EU

- 3:

The PM 2.5 emissions from the Auxiliary Boiler, identified as E U

- 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 Deteriorat ion (PSD ) ), IDEM has established the following as BACT for PM 2.5 for the Auxiliary Boiler (EU

- 3 )

.

The PM 2.5 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 thro ugh the use of good combustion practices and fuel specification

.

Sulfuric Acid (H 2 SO 4 ) BACT

– Auxiliary Boiler EU

- 3

Step 1: Identify Potential Control Technologies

Emissions of Sulfuric Acid (H 2 SO 4 ) emissions depend upon the sulfur content of the fuel and
oxidation of SO 2 to SO 3 , followed by immediate conversion of SO 3 to H 2 SO 4 when water vapor is present. Sulfuric Acid (H 2 SO 4 ) 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 ; andIPL Eagle Valley generating Station TSD

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( 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. H 2 SO 4 emissions are not dependent upon combustion

pro perties 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 contro l 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 2,0 00 ppmv. Absorption of SO 2 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 sys tems inject slurry reagent into the exhaust stream to react, dry and be removed downstream by particulate control equipment. By removing SO 2 from the exhaust stream, conversion of SO 2 to SO 3 and H 2 SO 4 is
reduced. Chlorine emissions can result in salt depo sition 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 H 2 SO 4 emissions for large combined cycle combustion turbines

. Technology has not been applied to natural gas combined cycle combusti on turbines due to very low SO 2 and H 2 SO 4 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 (FG D) 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 SO 2 and
SO 3 and is removed downstream by p articulate control equipment. The reduced availability of
SO 2 and SO 3 in the exhaust stream reduces H 2 SO 4 formation, thereby reducing H 2 SO 4 emissions. The system requires use of particulate controls to collect the reaction solids. Technology has not been applied to natural g as combined cycle combustion turbines due to very
low SO 2 and H 2 SO 4 emissions. Controls would not provide any measurable emission reduction. Dry sorbent injection is not listed in the RBLC as BACT for the control of H 2 SO 4 emissions for large combined cycl e combustion turbines

.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that
the use of d ry 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 ha s a very low potential for generating H 2 SO 4 emissions. Fuel Specifications is included in RBLC for the control of H 2 SO 4 from Auxiliary Boiler

.IPL Eagle Valley generating Station TSD

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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 H 2 SO 4 r esulting from the operation of

the Auxiliary Boiler ( EU

- 3 )

.

(1) Fuel Specifications

Step 4: Evaluate the Most Ef fective Controls and Document the Results

The following table lists the proposed H 2 SO 4 BACT determination along with the existing H 2 SO 4 BACT determinations for similar plants. All data in the table is based on the information obtained from the permit appl ication 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 Issue d 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 H 2 SO 4: 0.75 gr S/100 scf natural gas Fuel Sp ecification

FL

- 0330 Port Dolphin Energy, LLC 12/01/2011 Natural gas

fired Boilers NA 0.34 lb/hr, 3

- hr rolling

average None

OH

- 0317 Ohio River Clean Fuels,
LLC 11/20/2008 Natural gas

and tail gas

fired Boiler 1,200

MMB tu/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 gas

fired Auxiliary
Boiler 93
MMB tu/hr 0.0001
lb/mmbtu 3

- hr avg None

OR

- 0046 Calpine Turner Energy, LLC 01/06/2005 Natural gas

fired Auxilia ry Boiler 417,904
MMBtu/hr Use of natural gas
is RACT None

WI

- 0228 Wisconsin Public Service,

Weston Plant 10/19/2004 Natural gas

fired Auxiliary
Boiler 229.80

MMB tu/hr 0.210 lb/hr; 2,000 hrs/

12 month rolling limit None

TX

- 0386 Calpine
Construction

Amell a Energy
Center 03/26/2002 Natural gas

fired 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 H 2 SO 4 emissions from auxiliary boilers fired with natural gas. These emissions are characterized by variability in the sulfur content of pipeline natural gasIPL Eagle Valley generating Station TSD

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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 H 2 SO 4 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 base d 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 ga s, we believe that the use of pipeline quality natural gas will be the most effective means of reducing H 2 SO 4 emissions.

The following has been proposed as BACT for H 2 SO 4 emissions from the proposed auxiliary

boiler , identified as EU

- 3 :

(a) The H 2 SO 4 emis sions 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 H 2 SO 4 for the auxil iary boiler, identified as EU

- 3

.

(a) The H 2 SO 4 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 ox idation, 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 Infeasi ble 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 ap plied 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

combusti on chamber. Oxidizers are not recommended for controlling gases with sulfur containing compounds because of the formation of highly corrosive acid gases

.IPL Eagle Valley generating Station TSD

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- 00004

The required level of CO destruction of the waste gas that must be achieved within the time that it

s pends 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 t ypical temperatures of 1,200 to 2,000 o 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 Rege nerative 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, thereb y 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 ch ambers 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 re viewed 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 o xidizes comb ustible 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 o pe rating temperature ranges from 1,100

- 1.2 00 o 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 bec ause 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, O AQ 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 th e 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 controlli ng 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 ft 3 of catalyst per 1000 standard ft 3 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

w aste s tream in let f low r ate ranges from 700

- 50,000 scfm and w aste s tream i nlet p ollutant

c oncentration 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 t he 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 de termined 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 flar ing. 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

additi onal emissions from burning supplemental fuel, including NO

x . 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 therma l 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 NO x Burner
G ood 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 NO

x control in an ultra

- low NO

x burner. The latest generation of low NO

x burners seeks to optimize emissions of NO

x and CO simul taneously.
CO is minimized in boiler through good combustion practices, including low

- NO

x burners, flue gas recirculation (FGR), and ultra

- low

- NO

x burners that each support effective combustion that minimizes CO generation.

Factors affecting CO emissi ons 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 C ontrols is a tec hnically 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

Ste p 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 f rom 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

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BACT ID or
Permi t # 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% O 2 , 3

- hr

avg None

OK

- 0129 Associated
Electric Coopera tive,
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, lim ited 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 Cente r 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
Genera tion 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 NoneIPL Eagle Valley generating Station TSD

– Appendix B Page 61 of 152 Martinsville, Indiana PSD/ SSM 109

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BACT ID or
Permi t # 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 f acilities 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 l imit 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 PM 10 emissions. The f acility 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 P oint B iomass 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 t able . 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

concentratio n 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 24,5 00 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 expe cted 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 0.0 8 2 lb/MMBtu

and 6.6 5 lbs/hr , each, based on a 3

- hour average through the use of ad vanced ultra

- low NOx

burner

.IPL Eagle Valley generating Station TSD

– Appendix B Page 62 of 152 Martinsville, Indiana PSD/ SSM 109

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- 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 0.0 8 3 lb/MMBtu

and 6.6 5 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

E missions 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 ma intained 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 emi ssions. 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 2,000 o 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 it s 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 proce ss affords very high energy recovery (up to 95%). The higher capital costs associated with these high

- performanceIPL Eagle Valley generating Station TSD

– Appendix B Page 63 of 152 Martinsville, Indiana PSD/ SSM 109

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- 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 o x idizes 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 o pe rating temperature ranges from 1,100

- 1 .2 00 o 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 co mpounds 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 determinat ion, 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 polluta nts 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 f or 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 ft 3 of catalyst per 1000 standard ft 3 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

w aste s tream inlet f low r ate ranges from 700

- 50,000 scfm and w aste s tream i nlet p ollutant

c oncentration is as low as 1ppmv

.

Oxidation efficiency depends on exhaust flow rate and composition. Residence time required for oxidation to take place at the act ive 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 to o 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 crea tion of additional emissions from burning supplemental fuel, including NO

x . 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 v ersus 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 sourceIPL 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 Adva nce Ultra

- Low NOx Burner
G ood 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 co mbustion 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 NO x control in an ultra

- low NO x burner. The latest generation of low NO x burners seeks to optimize emissions of NO x and C O simultaneously. VOC is minimized in boiler through good combustion practices, including low

NO x burners, flue gas recirculation (FGR), and ultra

- low

- NO

x 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 rev iewed for this BACT determination, IDEM, OAQ has determined that
the use of Good Combustion C ontrols 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 version s 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

V alley Generating
Station Proposed Auxiliary Boiler ( EU

- 3 ) 79.3
MMBtu/hr VOCs:

0.005 3
lb/MMBtu

and 0.4 2 lb/hr, based

on 3

- hr

average Advance ultra

low NOx
Burners

Permit No.

141

- 31003

- 00579 St. Joseph Energy Center 12/03/2012 Auxiliary Boilers ( B001 an d 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/M Mscf NoneIPL Eagle Valley generating Station TSD

– Appendix B Page 65 of 152 Martinsville, Indiana PSD/ SSM 109

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- 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 capabil ities 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 inc lude 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 pract ices, operating the equipment according to manufacturer specifications and the use of natural gas have been identified and accepted as BACT for CO, VOC, PM 10 , and SO 2

. "IPL Eagle Valley generating Station TSD

– Appendix B Page 66 of 152 Martinsville, Indiana PSD/ SSM 109

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- 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 y r 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 e missions from the Auxiliary Boiler, identified as EU

- 3 shall not exceed 0.005 3 lb/ MMBtu
and 0.4 2 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 Si gnificant 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 0.005 3
lb/MMBtu and 0.4 2 lbs/hr, each, based on a 3

- hr ave rage 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 NO X to water and N 2 . Under optima l conditions, SCR has a removal efficiency up to 90% when used

o n 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

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- 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

w indow 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

, decre ase 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 rat io 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 (S CR ) is a technically feasible option for the Auxiliary Boilers at this

source.

Selective Non

- Catalytic Reduction (SNCR)

With selective non

- cat alytic reduction (SNCR), NO X is selectiv ely removed by the injection of ammonia or urea into the flue gas at an appropriate temperature window of 1600 ° F to 2 1 00 ° F
and without employing a catalyst. Similar to SCR without a catalyst bed, the injected chemica ls selectively reduce the NO X 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

pr oper temperature, urea decomposes to produce ammonia which is responsible for NO X reduction. At a higher temperature, the rate of a competing reaction for the direct oxidation of ammonia that actually forms NO

x becomes significant

. At a lower temperature, the rates of NO X reduction reactions become too slo w 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 temp erature window while accommodating spatial and production rate temperature variability in the gas stream. The attainment of maximum
NO

x control performance therefore requires that the source exhibit a favorable opportunity for the application of this te chnology 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 B oilers 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 th e 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 ut ilizes a single catalyst to remove NO X , CO, and VOC through oxidation. Now operating as EmeraChem, the current version of the technology is now

marketed as EM X

. The Operating Temperature ranges from 300

- 700 °F. The SCONO X Catalyst

is sensitive to contam ination by sulfur, so it must be used in conjunction with the SCOSO X catalyst, which favors sulfur compound absorption. This t echnology has only been demonstrated on units ranging from 5 to 45 MW.

Based on the information reviewed for this BACT determina tion, 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 Cataly tic 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 dete rminations 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

RA CT/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

Dr aft Permit
No. 109

- 32471

- 00004 Proposed
Limit IPL Eagle Valley Generating
Station Proposed Auxiliary Boiler ( EU

- 3 ) 79.3
MMBtu/hr NOx: 0.0 11
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

- NO

x burners

WY

- 0064 Basin Electric
Power Cooperative, Dry Fork 10/15/2007 Natural gas

- fired

Auxili ary Boiler 134
MMBtu/hr 0.04 lb/MMBtu; 5.4 tpy, limited to 2,000 hrs of Low

- NO

x burners with flue gas
recirculationIPL Eagle Valley generating Station TSD

– Appendix B Page 69 of 152 Martinsville, Indiana PSD/ SSM 109

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- 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 0.03 5
lb/MMBtu for natural gas Low

- NO

x burners with flue gas
recirculation

OH

- 0309 Daimler Chrysler

Toledo Supplier Park

Paint 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

- NO

x burners with flue gas

rec irculation

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 NO

x burners

NY

- 0095 Caithness Bellport Energy Center 05/10/2006 Natural gas

- fired Auxiliary Boiler 29.4
MMBtu/hr 0.0110
lb/MMBtu Low NO

x - burners and
FGR

OH

- 0407 Biomass Center, South

Point Biomass
Generation 0/04/2006 Natural gas

- fi red 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 NO

x - 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 NO

x 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 NO

x - 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

- N Ox burners have been proven to reduce NO x 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

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- 00004 Permit Writer: Josiah Balogun and SPM 109

- 32476

- 00004

Ultra

- Low NO x burner s employ internal or external flue gas recirculation (FGR). FGR reduces
NO x 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 NO x . 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 sh all 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 emissi ons from the Auxiliary Boilers, identified as EU

- 3 shall be controlled by Low NOx Burner s 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.

Particu late Matter (PM and PM 10 ) BACT

– Dew Point heater EU

- 4

Emissions of PM and PM 10 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 be ing emitted is organic, particulate matter may be controlled through a combustion process. Generally, PM and PM 10 emissions are controlled through one of the following
mechanisms:

(1) Fabric Filter Dust Collectors (Baghouses)

.

(2) Electrostatic P recipitat ors (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

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- 00004 Permit Writer: Josiah Balogun and SPM 109

- 32476

- 00004

Step 2: Eliminate Technically Infeasible Options

Fabric Filtr ation: 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 cleanin g. 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 ef ficiencies 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 o f 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 (prim arily 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 i n ft 3 /min that penetrates one ft 2 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 significan t 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 pr ocess 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 He ater (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 Particula tes. 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 n electrostatic precipitator is not a technically feasi ble 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 di stribution 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 par ticulate 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 di sadvantage 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 disadvant age 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 4 0 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 toIPL 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

co rrosion. Natural

- gas fired auxiliary boilers generate low Particulate emissions an d have large exhaust flowrates, resulting in very low c oncentrations of Particulates. A wet scrubber would not provide any measurable emission reduction.

Based on the inform ation 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 remov e 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, baghou ses, 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. Thi s 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 g as 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 auxiliar y boilers generate low P articulate emissions and have large exhaust flowrates, resulting in very low concentrations of P articulates

. Cyclones would not provide any measurable emission reduction.

Based on the information reviewed for this BACT determinatio n, 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 c lean natural gas, which has an inherently low sulfur content, rather than highe r sulfur content fuels alone or in combination with natural gas has a very low potential for generating PM and PM 10 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 speci fications will minimize PM and

PM 10 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 sou rce.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of PM and PM 10 r esulting from the operation of the Dew Point Heater (EU

- 4).

(1) Fuel Specifications ; andIPL 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 Co mbustion Practices

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM and PM 10 BACT determination along with the existing

PM and PM 10 BACT determinations for similar plants. All data in the ta ble 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 agenci es 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

M MBtu/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/PM 10 /PM 2.5 : 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 consist ent with the other limits contained in the RBLC.

The following has been proposed as BACT for PM and PM 10 emissions from the proposed Dew Point Heater, identified as EU

- 4:

The PM and PM 10 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 PM 10 for the Dew P oint Heater (EU

- 4 ).

The PM and PM 10 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 t hrough the use of good combustion practices and fuel specification

.

Particulate Matter (PM 2.5 ) BACT

– Dew Point heater EU

- 4

Emissions of PM 2.5 are generally controlled with add

- on control equipment designed to capture the emissions prior to the time they are exhausted to the atmosphere. In cases where the material being emitted is organic, particulate matter may be controlled through a combustion process. Generally, PM 2.5 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 Filte r Dust Collectors (Baghouses)

.

(2) Electrostatic P recipitators (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 applicati on 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.

St

ep 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 pass es 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 relati vely 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 (temp erature 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

para meter is the air

- or gas

- to

- cloth ratio (the amount of gas in ft 3 /min that penetrates one ft 2 of fabric) and the usual operating parameter of interest is pressure drop across the filter system. The major operating feature of fabric filters that distinguis hes 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 e xamples 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 mo isture. 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 Baghou se 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 s tream 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

maintai ned 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, al lowing 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 temper atures 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. A ir 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 f lowrates, 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 t he 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 eff iciencies 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 efficie ncies 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. W et 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 w hich 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 incr eased 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 an d have large exhaust flowrates, resulting in very low c oncentrations 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 industr ial 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 de signed 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 industri al sites that generate a considerable amount of particulate matter, such as lumber companies, feed mills, cement plants, and smelters.

The g as 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 P articulate emissions and have larg e exhaust flowrates, resulting in very low concentrations of P articulates

. 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 n ot a technically feasible option for the Dew Point Heater (EU

- 4) at this

source.

Fuel Specifications Combusting only c lean natural gas, which has an inherently low sulfur content, rather than higher
sulfur content fuels alone or in combination with natura l gas has a very low potential for generating PM 2.5 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) a t
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 PM 2.5 emissions.

Based on the informa tion 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 Effect iveness

The following measures have been identified for control of PM 2.5 r esulting 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 Docume nt the Results

The following table lists the proposed PM 2.5 BACT determination along with the existing PM 2.5 BACT determinations for similar plants. All data in the table is based on the information obtained from the permit application submitted by IPL Ea gle 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
Combus tion
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/PM 10 /PM 2.5 : 7.6 lb/mmscf, 3

- hr avg None

IA

- 0064 Roquette
America 01/31/2003 De w Point Heater 1.6
MMBtu/hr PM: 0.008
lb/MMB tu; 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 fo r PM 2.5 emissions from the proposed Dew Point Heater, identified as EU

- 4:

The PM 2.5 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 PM 2.5 for the Dew Point Heater (EU

- 4 )

.

The PM 2.5 emissio ns 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 (H 2 SO 4 ) BACT

– Dew Point Hea ter EU

- 4

Step 1: Identify Potential Control Technologies

Emissions of Sulfuric Acid (H 2 SO 4 ) emissions depend upon the sulfur content of the fuel and
oxidation of SO 2 to SO 3 , followed by immediate conversion of SO 3 to H 2 SO 4 when water vapor is present. Sul furic Acid (H 2 SO 4 ) 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 ) F uel 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., tempera ture, moisture content, presence of reactive materials), and desired collection efficiency. H 2 SO 4 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 H 2 SO 4 emissions from emergency engines are very minor, given their limited hours of oper ation. With such insignificant emissions, it would not be considered feasible to employ add

- on control technologies to reduce

H 2 SO 4 emissions 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 ha s a very low potential for generating H 2 SO 4 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 H 2 SO 4 r esulting 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 S pecifications

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 H 2 SO 4 from small natural gas

- fi red 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 agr eed 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 m ost effective means of reducing H 2 SO 4 emissions.

The following has been proposed as BACT for H 2 SO 4 emissions from the proposed dew point heater, identified as EU

- 4:

(a) The H 2 SO 4 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 H 2 SO 4 for the dew po int heater ( EU

- 4).

(a) The H 2 SO 4 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

Ste p 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) R ecuperative 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

Regener ative 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 destructi on 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 theIPL 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. Oxidiz ers 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 therm al 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 temperature s of 1,200 to 2,000 o 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 f irst 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 off set 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 B ACT 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 o xidizes 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 o pe rating temperature ranges from 1,100

- 1.2 00 o 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
forma tion 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 determine d 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 pa ssed 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 ft 3 of catalyst per 100 0 standard ft 3 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. TypicalIPL 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

w aste s tream inlet f low r ate ran ges from 700

- 50,000 scfm and w aste s tream i nlet p ollutant

c oncentration 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 n ot 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 fro m burning supplemental fuel, including NO

x . 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.

Ba sed 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
G ood combustion controls is a continued op eration 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 comb ustion. 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 inf ormation reviewed for this BACT determination, IDEM, OAQ has determined that
the use of Good Combustion C ontrols is a technically feasible option for the Dew Point Heater at
this source

Step 3: Rank the Remaining Control Technologies by Control Effective ness

( 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 determ ination 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 MethodIPL 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

- 00 004 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
G enerating
Station 08/28/2012 Inlet Air Heaters 16.10
MMBtu/hr (each) 0.08
lb/MMB tu, 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/

MMB tu None

IA

- 0058 Midamerican
Ener gy, Greater Des

Moines Energy Center 04/10/2002 Dew Point Heater 10
MMBtu/hr 0.036 lb/

MMB tu ; 1.47 tpy None

FL

- 0303 Florida Power & Light Co. 07/30/2008 Process Heaters 10
MMBtu/hr 0.08 lb/

MMB tu None

The Midamerican Energy, Gr eater Des Moines Energy Ce nter permit , issued on April 10, 2002 operates a 10 MMBtu/hr heater, without controls, an d has a CO limit of 0.036 lb/MMB tu 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 propose d 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 wi th
the BACT deter mination for IPL of 0.082 lb/MMB tu.

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 Shee t 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 6,4 00 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 0.0 82 lb/MMBtu
and 1.7 lbs/hr

, based on a 3

- hour average through th e 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 0.0 82 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 T echnologies

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
combinat ion 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 t hrough 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 co rrosive 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 tem perature 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 2,000 o 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 exchange rs 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

e nergy 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 o xidizes combustible mat erials 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 o pe r ating temperature ranges from 1, 100

- 1, 2 00 o F
and the waste s tream 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 de termined 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

ga s 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 em issions. 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 ft 3 of catalys t per 1000 standard ft 3 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

w aste s tream inlet f low r ate ranges from 700

- 50,000 scfm and w aste s tream i nlet p ollutant

c oncentration 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 catal yst 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 t hat 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 t here 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 emis sions from burning supplemental fuel, including NO

x . 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 oxidi zers.

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
G ood combustion controls is a c ontinued operation of the Boilers at the appropriate oxygen range and temperature to promote complete combustion and minimize VOC formation. Because VOC isIPL 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 minimiz e 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 C ontrols 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
RAC T/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

Dr aft 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,

I nc. 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 co st 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 6,400IPL Eagle Valley generating Station TSD

– Appendix B Page 87 of 152 Martinsville, Indiana PSD/ SSM 109

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- 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 ad d

- on controls
would be at least $ 593

, 750 per ton of VOC removed.

The following has been proposed as BACT for VOC emissions fr om 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 contr olled 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 Te chnology:
NO

x 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 t o 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. Furth er, these technologies would unnecessarily increase emissions of

NH 3 , a precursor to the atmospheric formation of the non

- attainment pollutant PM 2.5

. This adverse environmental impact would render the use of SNCR or SCR as the BACT for the PM 2.5 precursor NO x counterproductive to the goal of decreasing ambient levels of PM 2.5

.

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 NO

x production. The flue gas recirculation (FGR) can be highly effective technique for lowering NO

x 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 NO

x emissions to as
little as 25% of their normal levels. FGR can lower NO

x emissions in two ways: the cooled, relatively inert, recirculated flue gases act as heat sink, absorbing heat from the flame andIPL Eagle Valley generating Station TSD

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lowering peak flam e temperatures and when mixed with the combustion air, recirculated flue gases lower the average oxygen content of the air, starving the NO

x - forming reaction for one of the ingredients they need.

Based on the information reviewed for this BACT determinati on, 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 temperatu re.

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 combusti on 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 opt ion for the Dew Point Heater at this

source.

SCONOx Catalytic Absorption System SCONOx Catalytic Absorption System utilizes a single catalyst to remove NO X , CO, and VOC through oxidation. Now operating as EmeraChem, the current version of the technology i s now marketed as EM X

. The Operating Temperature ranges from 300

- 700 °F. The SCONO X Catalyst is sensitive to contamination by sulfur, so it must be used in conjunction with the SCOSO X catalyst, which favors sulfur compound absorption. T his t echnology ha s 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 Hea ter at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Natural gas firing with low NO

x Burner with Flue Gas Recirculation (LNB/FGR)

(2) Natural gas firing with low NO

x Burner (LNB)

Step 4: Evaluate the Most E ffective 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 applica tion 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

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BACT ID or
Permit # Facility Issued D ate 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 NO

x burners

AK

- 0071 Chugach

Electric
Associati on, Inc.,
International
Station Power

Plant 12/20/2010 Sigma Thermal Auxiliary Heater 12.5
MMBtu/hr 32.0 lb/MMscf, 3

- hr avg Low NO

x burners and
FGR

LA

- 0237 International
Matex Tank
Terminal 05/20/2010 Heaters (6) 37.80 MMBtu/hr,

each 0.036 lb/hr Low NO

x b urners

WY

- 0066 Medicine Bow
Fuel & Power 03/04/2009 Gasification Preheaters (5) 21
MMBtu/hr (each) 0.05
lb/MMBtu Low NO

x 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 L ow NO

x 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 Midameri can 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.

Th e 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

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- 00004

Step 5: Select BACT

Pursuant to 326 IAC 2

- 2

- 3 (Prevention of Significant Deterioration (PSD ) ), IDEM has established the following a s 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 PM 10 ) BACT

– Emergency Generator (EU

- 5)

Step 1: Identify Potential Control Technologies

Emissions of PM and PM 10 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 PM 10 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, includin g 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 Op tions

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 o perating t emperature ranges between 480

- 570°F

. The

e xhaust gas temperat ure must be high enough over an extended period of time to allow for filter regeneration. The type of control is n ot 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 Emergenc y 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 i ncluded 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

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Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that
the use of Good Comb ustion 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 t hat 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 PM 10 BACT determination along with the existing

PM and PM 10 BACT determi nations 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

E U

- 5 1, 826 horsepower PM and PM 10 : 0.15 g/bhp

- hr (0.2 g/kw

- hr) Combustion Design
Controls

Permit No.

141

- 31003

- 00579 St. Jos eph Energy Center 12/03/2012 Emergency
Diesel
Generators
EG01 & EG02 1,006 horsepower,
each PM, PM 10 and

PM 2.5 : 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

- to

Ethanol
Advanced Biorefinery 12/23/2010 Emer gency 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 Non e

ID

- 0018 Idaho Power Company, Langley Gulch

Power Plant 06/25/2010 Emergency
Generator Engine 750 KW 0.200 g/kw

- hr, Tier 2 engine

based NoneIPL Eagle Valley generating Station TSD

– Appendix B Page 92 of 152 Martinsville, Indiana PSD/ SSM 109

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- 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, PM 10 and PM 2.5 from the proposed Emergency Generator :

The PM and PM 10 emissions from the Emergency Generator, Identified as E U

- 5

, shall not exceed 0.15 g/hp

- hr, through the use of combustion design control

.

Step 5: Selec t BACT

Pursuant to 326 IAC 2

- 2

- 3 (Prevention of Significant Deterioration (PSD) ) , IDEM has established the following as BACT for PM and PM 10 for the Emergency Generator (EU

- 5)

.

The PM and PM 10 emissions from the Emergency Generator, Identified as EU

- 5, sh all not exceed 0.15 g/hp

- hr, through the use of combustion design control

.

Particulate Matter (PM 2.5 ) BACT

– Emergency Generator (EU

- 5)

Step 1: Identify Potential Control Technologies

Emissions of PM 2.5 are generally controlled with add

- on control equipmen t 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 2.5 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 o perating t emperature ranges between 480

- 570°F

. The

e xhaust gas temperature must be hig h enough over an extended period of time to allow for filter regeneration. The type of control is n ot 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. SootIPL Eagle Valley generating Station TSD

– Appendix B Page 93 of 152 Martinsville, Indiana PSD/ SSM 109

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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. Th is type of emission control is i ncluded 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 Practice s 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 2.5 BACT determination along with the existing PM 2.5 BACT determinati ons 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/LAE R 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 (H P or KW ) Limitation Control

Method

Draft Permi t
No. 141

- 31003

- 00579 Proposed
Limit St. Joseph Energy Center

- **proposed** Proposed Emergency
Generator
EU

- 5 1,826 horsepower PM 2.5 : 0.15 g/bhp

- hr (0.2 g/kw

- hr) Combustion Design
Controls

Draft Permit

No. 141

- 31003

- 00579 Proposed

Limit St. Joseph Energy Ce nter

- proposed 12/03/2012 Emergency
Diesel
Generators
EG01 & EG02 1,006 horsepower,
each PM, PM 10 and

PM 2.5 : 0.15

g/bhp

- hr Combustion Design
Controls and Usage Limits Emergency
Generator
EG03 2,012 horsepower

FL

- 0323 Gainesville Regional Utility
De erhaven,
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

- to

Ethanol
Advanced Biorefinery 12/23/2010 Emergen cy 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 NoneIPL 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 (H P 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 engine

based 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 particulate limits and compliance with the limits is demonstrated by purchasing certified engines.

The following has been proposed as BACT for PM 2.5 from the proposed Emergency Generator:

The PM 2.5 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 PM 2.5 for the Emergency Generator (EU

- 5)

.

The PM 2.5 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 (H 2 SO 4 ) BACT

– Emergency Generator (EU

- 5)

Step 1: Identify Potential Control Technologies

Emissions of Sulfuric Acid (H 2 SO 4 ) emissions depend upon the sulfur content of the fuel and
oxidation of SO 2 to SO 3 , followed by immediate conversion of SO 3 to H 2 SO 4 when water vapor is present. Sulfuric Acid (H 2 SO 4 ) emissions are generally controlled with add

- on control equipment designed to capture the emissions prior to the time they are exhausted to the atmosp here.

(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. H 2 SO 4 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 H 2 SO 4 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

H 2 SO 4 emissions from emergency engines. Additionally, since control technologies have notIPL Eagle Valley generating Station TSD

– Appendix B Page 95 of 152 Martinsville, Indiana PSD/ SSM 109

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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, w hich has an inherently low sulfur content, rather than higher sulfur content fuels alone or in combination with natural gas ha s a very low potential for generating H 2 SO 4 emissions. Fuel Specifications is included in RBLC for the control of H 2 SO 4 from combi ned 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 th e Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of H 2 SO 4 r esulting from the operation of
the emergency generator ( EU

- 5 )

.

(1) Fuel Specifications

Step 4: Evaluate the Most Effective Cont rols and Document the Results

The following table lists the proposed H 2 SO 4 BACT determination along with the existing H 2 SO 4 BACT determinations for similar plants. All data in the table is based on the information obtained from the permit application subm itted 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 Proce ss Description Rating (H P 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 H 2 SO 4: 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

- f ired 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 NoneIPL Eagle Valley generating Station TSD

– Appendix B Page 96 of 152 Martinsville, Indiana PSD/ SSM 109

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- 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 H 2 SO 4 emissions. Note that H 2 SO 4 emissions depend on the sulfur content of the natural gas available to the facility. The proposed facility will have access to

na tural 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 H 2 SO 4 emissions from th e proposed emergency generator , identified as EU

- 5 :

The H 2 SO 4 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 Deteri oration (PSD ) ), IDEM has established the following as BACT for H 2 SO 4 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 Con trol 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 add ed 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 c ontinues 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

re sidence 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 2,000 o 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

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- 32476

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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 cool ing 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 economic al.

This control is n ot 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 revi ewed 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 o xidizes com bustible 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 o pe rating temperature ranges from 1,100

- 1.2 00 o 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 be cause 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 n ot 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 ft 3 of catalyst per 1000 standard ft 3 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

w aste s tream inlet f low r ate ranges from 700

- 50,000 scfm and w aste s tream i nlet p ollutant

c oncentration 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 toIPL Eagle Valley generating Station TSD

– Appendix B Page 98 of 152 Martinsville, Indiana PSD/ SSM 109

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- 00004 Permit Writer: Josiah Balogun and SPM 109

- 32476

- 00004

decreased efficiency. This control is n ot included in RBLC for the control of CO emissions from fire pump & emergency engines. EPA dete rmined 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 fe asible 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 s tream 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 NO x

. 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 BAC T 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 no t 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 injec tion systems, air management systems, combustion system designs, and pre

- mixed diesel combustion. This type of control is i ncluded 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 C ontrols 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 informati on 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 Contr ols 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 submitte d 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

D escription 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
ControlsIPL Eagle Valley generating Station TSD

– Appendix B Page 99 of 152 Martinsville, Indiana PSD/ SSM 109

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- 00004 Permit Writer: Josiah Balogun and SPM 109

- 32476

- 00004

BACT ID or
Permit # Facility Issued Date Process

D escription Rating (HP or KW ) Limitation Control

Method

Per mit No.

141

- 31003

- 00579 St. Joseph Energy Center 12/03/2012 Emergency
Diesel
Generators EG01
& EG02 1,006 horsepower,
each CO : 2.6 g/bhp

hr Combustion Design
Controls and Usage Limits Emergency
Generator EG03 2,012 horsepower

SC

- 0113 Pyramax
Ceram ics,
LLC 02/08/2012 Emergency Engines, diesel

fired 29 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

- to

Ethanol
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 R equirements 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 engine

based None

The proposed diesel

- fired emergency generators will be subject to the NESH AP found at 40 CFR 63 Subpart ZZZZ and the NSPS found at 40 CFR 60 Subpart IIII, which apply to stationary compression i gnition 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 E U

- 5 :

The CO emissions from the Emergency Generators, Identified as E U

- 5 shall not exceed 2.6 g/hp

hr through the use of combus tion 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 Gene rators, Identified as EU

- 5 shall not exceed 2.6 g/hp

hr 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 compo unds (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 Technica lly 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 t ypically 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 2,000 o 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 exch angers 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 tempera ture. 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 hi gh 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

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- 00004 Permit Writer: Josiah Balogun and SPM 109

- 32476

- 00004

This control is n ot included i n 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, I DEM, 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 o xidizes combustible materials by raisi ng 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 o pe rating temperature ranges from 1,100

- 1.2 00 o F and the waste stream inlet pol lutants 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 h ighly 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 n ot included in RBLC for the control of VOC emissions from fire pump &

emergenc y 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 o xidizer 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 t hen 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 co mpound 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 ft 3 of catalyst per 1000 standard ft 3 per gas flow ra te.

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

w aste s tream inlet f low r ate ranges from 700

- 50,000 scfm and w aste s tream i nlet p ollutant

c oncentration 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 n ot included in RBLC for the control of VOC emissions from fire pump & emergency engines. EPA determined in the d evelopment 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 f or 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

suppo rt 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

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- 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 NO x . Flare s 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 det ermination, 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 ar e 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 i ncluded in RBLC for the control of VOC emissions from fire pump & emergency engines.

Based on the information reviewed for thi s BACT determination, IDEM, OAQ has determined that
the use of a Good Combustion C ontrols 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 Mo st 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 a pplication 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 Is sued Date Process Description Rating (H P 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

P ermit 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, diesel

fired 29 HP each 7.500 g/kw

- H (purchase of NSPS, Subpart
IIII certified engine) NoneIPL 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 Is sued Date Process Description Rating (H P or KW ) Limitation Control

Method

Emergency Generators,

diesel

- fired 757 HP
each 4.000 g/kw

- H (purchase of NSPS, Subpart
IIII certif ied 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 (NO

x + 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 propose d as BACT for VOC emissions from the proposed Emergency Generator, Identified as E U

- 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 t o 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 Catal ytic 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 a nhydrous or aqueous ammonia vapor with flue gas and passing the mixture through a catalytic reactor to reduce NO X to water and N 2 . Under optima l conditions, SCR has a removal efficiency up to 90% when used on steady state processes. The efficiency of rem oval 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

. Temp erature below the optimum, decrease catalyst activity and allow NH3 to slip thr ough; 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%.

U nreacted 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 n ot 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

s elective catalytic reduction (S CR ) 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), NO X is selectiv ely removed by the injection of ammonia or urea into the flue gas at an appropriate temperature window of 1600 ° F to 2 1 00 ° F
and without employing a catalyst. Similar to SCR without a catalyst bed, the injected chemicals selectively reduce the NO X 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 respon sible for NO X reduction. At a higher temperature, the rate of a competing reaction for the direct oxidation of ammonia that actually forms NO

x becomes significant

. At a lower temperature, the rates of NO X reduction reactions become too slo w resulting in ur ea 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 temp erature variability in the gas stream. The attainment of maximum
NO

x 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 n ot 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 rev iewed 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
NO X emissions are caused by oxid ation 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

- f uel ratio control, ignition timing reduction, and exhaust gas recirculation. This type
of control is i ncluded in RBLC for the control of NO X 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 C ontrols 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 D ocument 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 Descriptio n Rating (H P 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

- 31 003

-

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, diesel

fired 29 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

- 0 251 Flopam, Inc. 04/26/2011 Large Diesel

- fired Engines 591

– 1,175 hp 6.4000 g/kw

- hr (NO

x + 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, d iesel

fired NA 0.15 tpy Use of turbo charger after cooler, intake air coolingIPL 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 Descriptio n Rating (H P or KW ) Limitation Control

Method

Emergency
Generator

– Bully NA 0.15 tpy Use of EPA

Tier 2 engines with
low NO

x engine design

FL

- 0323 Gainesville Regional Utility Deerhaven,
Renewable Energy Center 12/28/20 10 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

- to

Ethanol
Advanced Biorefinery 12/23/2010 Emergency Generators, fuel

oil

- fired 2,682 HP

e ach 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 Gu lch
Power Plant 06/25/2010 Emergency Generator Engine 750 KW 6.4 g/kw

- hr (NO

x + 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
Generato r 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 E U

- 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 (Pre vention 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 PM 10 ) BACT

– Emergency Fire Pump (EU

- 6)

Step 1: Identify Potential Control Technologies

Emissions of PM and PM 10 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 PM 10 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 Particul ate 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 o perating t emperature ranges between 480

- 570°F

. The

e xhaust gas temperature must be high enough over an extended period of time to allow for filter regeneration. The type of control is n ot 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 economicall y 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 pyrol ize 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 em ission control is i ncluded 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 techni cally 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

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- 00004 Permit Writer: Josiah Balogun and SPM 109

- 32476

- 00004

Based on the information reviewed for this BACT determination, IDEM, OAQ has determi ned 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 followi ng table lists the proposed PM and PM 10 BACT determination along with the existing

PM and PM 10 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
Stat ion , 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 (H P or KW ) Limitat ion Control

Method

Draft Permit
No. 109

- 32471

- 00004 Proposed
Limit IPL Eagle Valley Generating
Station Proposed Emergency Fire Pump 500 horsepower PM and PM 10 : 0.15 g/bhp

- hr Combustion Design
Controls

Permit No.

141

- 31003

- 00579 St. Joseph Energy Cente r 12/03/2012 Firewater Pump Engines 371 brake horsepower PM, PM 10 and

PM 2.5 : 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

- to

Ethanol
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 C reek
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 engine

based) [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/kW

hr, 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 PM 10 from the proposed Emergen cy Fire Pump Engines:

(1) The PM and PM 10 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 (PS D ) ), IDEM has established the following as BACT for PM and PM 10 for the Fire Pump Engine (EU

- 6)

.

(1) The PM and PM 10 emissions from the Emergency Fire Pump Engine shall not exceed 0.15 g/hp

- hr through the use of combustion design control

.

Particulate Ma tter (PM 2.5 ) BACT

– Emergency Fire Pump (EU

- 6)

Step 1: Identify Potential Control Technologies

Emissions of PM 2.5 are generally controlled with add

- on control equipment designed to capture the emissions prior to the time they are exhausted to the atmospher e. In cases where the material being emitted is organic, particulate matter may be controlled through a combustion process. Generally, PM 2.5 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 characteristi cs (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 trap ped by a ceramic filter and oxidized using a metallic catalyst or a base. The o perating t emperature ranges between 480

- 570°F

. The

e xhaust gas temperature must be high enough over an extended period of time to allow for filter regeneration. The type of co ntrol is n ot 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 thi s 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 c aused 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 i ncluded in RBLC for the control of particulate
emissio ns 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 PM 2.5 BACT determination along with the existing PM 2.5 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 per mits available at the websites of other permitting agencies and IDEM's PSD Permits

.

BACT ID or

Permit # Facility Issued Date Process Description Rating (H P 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 2.5 : 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, PM 10 and

PM 2.5 : 0.1 5

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 Sout heast
Renewable Fuels, Sweet Sorghum

- to

Ethanol
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

En ergy 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, Subpar t
IIII NoneIPL 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 (H P 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 engine

based) [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 equi valent to 0.20 g/kW

hr, is consistent with the most stringent limits contained in the RBLC.

The following has been proposed as BACT for PM 2.5 from the proposed Emergency Fire Pump Engine:

The PM 2.5 emissions from the Emergency Fire Pump Engine shall not e xceed 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 2.5 for the Fire Pump Engine (EU

- 6)

.

The PM 2 .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 (H 2 SO 4 ) BACT

– Emergency Fire Pump (EU

- 6)

Step 1: Identify Potential Control Technologies

Emissions of Sulfuric Aci d (H 2 SO 4 ) emissions depend upon the sulfur content of the fuel and
oxidation of SO 2 to SO 3 , followed by immediate conversion of SO 3 to H 2 SO 4 when water vapor is present. Sulfuric Acid (H 2 SO 4 ) emissions are generally controlled with add

- on control equipmen t 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 specifi c 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 eff iciency. H 2 SO 4 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 (F GD) System

, Dry Sorbent Injection are not possible alternatives because the potential H 2 SO 4 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

H 2 SO 4 emissions from emergency engines. Additionally, since control technologies have notIPL 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 b e 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 ha s a very low potential for generating H 2 SO 4 e missions. Fuel Specifications is included in RBLC for the control of H 2 SO 4 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 opt ion 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 H 2 SO 4 r esulting from the operation of
the combined cycle combustion t urbines ( EU

- 6 )

.

(1) Fuel Specifications

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed H 2 SO 4 BACT determination along with the existing H 2 SO 4 BACT determinations for similar plants. All da ta 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 permi tting agencies and IDEM's PSD Permits

.

BACT ID or

Permit # Facility Issued Date Process Description Rating (H P or KW ) Limitation Control

Method

Draft Permit
No. 109

- 32471

- 00004 Proposed
Limit IPL Eagle Valley Generating
Station Proposed Emergency
Fire Pu mp 500 horsepower H 2 SO 4: 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 ultra

low 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
roll ing limit;

0.003 wt%
sulfur in NoneIPL 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 (H P 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 H 2 SO 4 emissions. Note that H 2 SO 4 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 H 2 SO 4 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 H 2 SO 4 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 cont inues 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
resid ence 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 2,000 o F. Once the unit is designed and built, the residence tim e 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 th e 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. Th is 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 n ot 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 reviewe d 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 o xidizes 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 o pe rating temperature ranges from 1,100

- 1.2 00 o 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 compound s 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 n ot included in RBLC for the control of CO emissi ons 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 us e 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 passe d 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 c atalyst 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 ft 3 of catalyst per 1000 s tandard ft 3 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

w aste s tream inlet f low r ate ranges from 700

- 50,000 scfm and w aste s tream i nlet p ollutant

c oncentration 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 n ot included in RBLC for the control of CO emissions from fire pump & emergency engine s. 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 tec hnically 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 t his 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 fue l, including NO x . 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 rev iewed 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 th rough enhanced fuel injection systems, air management systems, combustion system designs, and pre

- mixed diesel combustion. This type of control is i ncluded in RBLC for the control of CO emissions from fire pump & emergency engines.

Based on the informatio n reviewed for this BACT determination, IDEM, OAQ has determined that
the use of a Good Combustion C ontrols is a technically feasible option for the Emergency Fire

pump Engine at this source

.

Step 3: Rank the Remaining Control Technologies by Control Ef fectiveness

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 I ssued Date Process Description Rating (H P 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
ControlsIPL 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 I ssued Date Process Description Rating (H P 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/bhp

hr Combustion 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

F L

- 0322 Southeast

Renewable Fuels, Sweet Sorghum

- to

Ethanol
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
Rene wable 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,
S ubpart 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 equivale nt 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 P ump 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 Fir e 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 Con trol 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 supple mental 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 heate d

. 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. T he 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 2,000 o F. Once the unit is designed and buil t, 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 e fficiency 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 s tream (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 n ot 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 o xidizes 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 o pe rating temperature ranges from 1,100

- 1.2 00 o 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 n ot 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 control ling 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 ft 3 of catalyst per 1000 standard ft 3 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

w aste s tream inlet f low r ate ranges from 700

- 50,000 scfm and w aste s tream i nlet p ollutant

c oncentration 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 o f 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 n ot 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 catalyt ic 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 i nsufficient organics in this vent stream toIPL 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 NO x . 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.

Ba sed 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 thro ugh 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 imp roving 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 i ncluded in RBLC for the control of VOC emissions from fire pump & emergency

eng ines.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that
the use of a Good Combustion C ontrols is a technically feasible option for the Emergency Fire Pump Engine at this source

.

Step 3: Rank the Remaining Contr ol 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 inform ation 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 (H P 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 C ombustion 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 0 2/08/2012 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 (NO

x + NMHC), Tier 3 NoneIPL 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 (H P or KW ) Limitation Control

Method
Plant engine

- based

As shown i n 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 fr om the Emergency Fire P ump 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 Pote ntial 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 Technica lly 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 NO X to water and N 2 . Under optima l 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 fa ctor 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 t arget temperature is approximately 750 F

. Temp erature 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 stoich iometric 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 th e 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 n ot 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 (S CR ) is not a technically feasible option for the Emergency Fire

P ump Engine at this source.

Selec tive Non

- Catalytic Reduction (SNCR)

With selective non

- catalytic reduction (SNCR), NO X is selectiv ely removed by the injection of ammonia or urea into the flue gas at an appropriate temperature window of 1600 ° F to 2 1 00 ° F
and without employing a catalyst. S imilar to SCR without a catalyst bed, the injected chemicals selectively reduce the NO X 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 f or conducting the necessary chemical reaction. At the proper temperature, urea decomposes to produce ammonia which is responsible for NO X reduction. At a higher temperature, the rate of a competing reaction for the direct oxidation of

ammonia that actual ly forms NO

x becomes significant

. At a lower temperature, the rates of NO X reduction reactions become too slo w resulting in urea slip (i.e. emissions of unreacted urea).

Optimal implementation of SNCR requires the employment of an injection system that c an 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
NO x control performance therefore requires that the source exhib it a favorable opportunity for the application of this technology relative to the location of the reaction temperature range.

This control is n ot 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 feasibl e option for the Emergency
Fire P ump Engine at this source.

Combustion Design Controls
NO X emissions are caused by oxidation of nitrogen gas in the combustion air during fuel combustion. This occurs due to high combustion temperatures and insufficiently m ixed 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 i ncluded in RBLC for the control of NO X 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 C ontrols is a technically feasible option for the Emergency Fire

P ump Engine at t his source

.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

1. Good Combustion C ontrols

.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that the use of combustion design control shall be us ed to reduce the NOx emissions from the Emergency Fire P ump 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 determin ations 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 avail able at the websites of other permitting agencies and IDEM's PSD Permits

.

BACT ID or

Permit # Facility Issued Date Process Description Rating (H P 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 Diesel

fired Engines 591

– 1,175 hp 6.4000 g/kw

- hr (NO

x + 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, S ubpart
IIII certified engine) None

FL

- 0322 Southeast

Renewable Fuels, Sweet Sorghum

- to

Ethanol
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/hp

hr, 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 P ump Engine shall not exceed 3.0 g/bhp

- hr
for NMHC + NOx through the use of Combu stion 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 P ump Engine shall not exceed 3.0 g/bhp

- hr
for NMHC + NOx through the use of Combustion Design Controls

.

Particulate Matter (PM and PM 10 ) BACT

– Cooling Tower E U

- 7

Step 1: Identify Potential Control Technologies

Emissions of Particulate M atter ( PM a nd PM 10 ) 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 PM 10 emissions from the Cooling Towers

.

Drift Eliminator System Cooling towers are a source of particulate matter ( PM/ PM 10 /P M 2.5 ) emissions from the small amount of water mist that is entrained with the cooling air as “dr ift”. The cooling water contains small amounts of dissolved solids which become particulate ( PM/ PM 10 /P M 2.5 ) emissions once the water mist evaporates. To reduce the drift from cooling towers, drift eliminators are typically incorporated into the tower desig n 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 o f 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 T ower 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 wat er 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 ut ilized 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 feasib le option for the Cooling T owers 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 spe cifications. 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 PM 10 BACT determinati on alo ng with the existing
PM and PM 10 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 (RB LC), 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
Pro posed
Limit IPL Eagle Valley Generating
Station Proposed Cooling Tower (U

- 7) 192 ,000

gpm 0.0005% and

T D S ≤ 5 000 m g/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 PM 10 /PM 2.5 : 0.0010 % drift, annual average High efficiency

mist
eliminator

Unit 6 Cooling

Tower 115,847

gpm PM 10 /PM 2.5 : 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 PM 10 /PM 2.5 : 0.0005%
circulation drift High efficiency
drift / mist

eliminator

Cooling Tower P60 200 gpm PM 10 /PM 2.5 : 0.0005% circulation drift;
Dissolved Solids
Limit of 1000 ppm; PM 2 .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 PM 10 : 0.01 lb/hr; NoneIPL 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 12/3 1/2010 Cooling Towers 45,000

gpm

- 61,250

gpm PM 10 : 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 PM 10 : TDS </= 1000 mg/L; Max
drift of 0.0005% Drift

eliminators

DRI 114 & 214:
Unit #1 Clean Water Cooling

Tower 17,611

gpm PM 10 : TDS </= 1000 mg/L; Max
drift of 0.0005% Drift
eliminators

LA

- 0246 Valero Refining

– New Orleans, LLC, St.
Charles
Ref inery 12/31/2010 Cooling Towers 45,000

gpm

- 61,250

gpm PM 10 : 0.08

- 1.2
lb/hr Drift

eliminators

GA

- 0142 Osceola Steel
Co. 12/29/2010 Cooling Towers CT1, CT21, CT22,
and CT23 NA PM 10 : 0.0005% mass flow rate; 1000 mg/L Drift

eliminators

FL

- 0323 Gainesvil le Regional Utility (GRU)

Deerhaven 12/28/2010 Mechanical Draft Cooling Tower 78,000

gpm PM 10 : 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 H ollow
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
eliminatorsIPL 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 Tow er NA PM: 0.0005%
drift rate Drift
eliminators

NV

- 0050 MGM Mirage 11/30/2009 Cooling Towers 10,890

gpm PM 10 : 0.001%
drift rate and TSD

concentration is limited to 3,600

ppm Drift
eliminators

The TDS requirements in cooling towers are very case specifi c 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 well s 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 r iver.

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 yiel ds 0.022 tpy while running at 1000 mg/L would yield 0.004 tpy, a difference of 0.018 tpy.

The following ha s been proposed as BACT for PM and PM 10 emissions from the proposed Cooling Tower (U

- 7):

Therefore, a 0.0005% drift ( mist ) eliminator system is proposed as BACT for PM and PM 10 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 p roposed PM and PM 10 BACT for the Cooling T ower , identified as U

- 7

.

(a) The PM and PM 10 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 dissolve d solids (T D S ) shall b e less than 5 0 00 m g/L

.

(b) The PM and PM 10 emissions from the Cooling Tower shall be less than 2.4 and 1.5 pounds per hour, respectively.

Particulate Matter (PM 2.5 ) BACT

– Cooling Tower U

- 7

Step 1: Identify Potential Control Technologies

Emissions of Par ticulate Matter ( PM 2.5 ) from cooling towers are generally controlled by:

(1) Drift (Mist) eliminator system.

(2) Reducing TDSIPL 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 PM 2.5 emissions from the Cooling Towers

.

Drift Eliminator System Cooling towers are a source of particulate matter ( P M 2.5 ) emissions from the small amount of water mist that is entrained with the cooling air as “dr ift”. The cooling water contains small amounts of dissolved solids which become particulate ( P M 2.5 ) emissions once the water mist evaporates. To reduce the drift from cooling towers, drift eliminators are typically incorporated into the tower design to rem ove 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 cool ed

. 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 pa cking. 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 Coo ling T ower 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 b e 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 a nd 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 f easible option for the Cooling T owers 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 2.5 BACT determination alon g with the existing PM 2.5 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), an d 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

L imit IPL Eagle Valley Generating
Station Proposed Cooling Tower (U

- 7) 192 ,000

gpm 0.0005% and

T D S ≤ 5 000ppm 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 PM 10 /PM 2.5 : 0.0010 % drift, annual average High efficiency

mist
eliminator

Unit 6 Cooling

Tower 115,847

gpm PM 10 /PM 2.5 : 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 PM 10 /PM 2.5 : 0.0005%
circulation drift High efficiency
drift / mist

eliminator

Cooling Tower P60 200 gpm PM 10 /PM 2.5 : 0.0005% circulation drift;
Dissolved Solids
Limit of 1000 ppm; PM 2. 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 PM 10 : 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 PM 10 : 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 P M 10 : TDS </= 1000 mg/L; Max
drift of 0.0005% Drift
eliminators

DRI 114 & 214:
Unit #1 Clean Water Cooling

Tower 17,611

gpm PM 10 : TDS </= 1000 mg/L; Max
drift of 0.0005% Drift

eliminators

LA

- 0246 Valero Refining

– New Orleans, LLC, St.
Charles
Refi nery 12/31/2010 Cooling Towers 45,000

gpm

- 61,250

gpm PM 10 : 0.08

- 1.2
lb/hr Drift

eliminatorsIPL Eagle Valley generating Station TSD

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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 PM 10 : 0.0005% mass flow rate; 1000 mg/L Drift
eliminators

FL

- 0323 Gainesvill e Regional Utility (GRU)

Deerhaven 12/28/2010 Mechanical Draft Cooling Tower 78,000

gpm PM 10 : 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 Ho llow
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 Towe r NA PM: 0.0005%
drift rate Drift
eliminators

NV

- 0050 MGM Mirage 11/30/2009 Cooling Towers 10,890

gpm PM 10 : 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 ri ver.

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 yield s 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

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The following has been proposed as BACT for PM 2.5 emissions from the proposed Cooling Tower (U

- 7):

Therefore, a 0.0005% drift ( mist ) eliminator system is proposed as BACT for PM 2.5 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 PM 2.5 BACT for the Cooling Tower , identified as U

- 7

.

(a) The PM 2.5 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 dissolve d solids (T D S ) shall be less than or equal to 5 00 0 mg/L

.

(b) The PM 2.5 emissions from the Cooling Tower shall be less than 0.005 pounds per hour

.

PM, PM 10 and PM 2.5 BACT

– Turbine Lube Oil Demister Vents

Step 1: Identify Potential Control Technologies

The organic PM, PM 10 and PM 2.5 are generally contro lled with add

- on control equipment designed to capture the emissions prior to the time they are exhausted to the atm osphere. Generally, organic PM, PM 10 and PM 2.5 emissions are controlled through one of the following
mechanisms:

(1) Mechanical Collectors ( such as Cyclones or Multiclones);

( 2 ) Wet Scrubbers;

( 3 ) Electrostatic P recipitators (ESP) ; and

( 4 ) Fabric Filter Dust Collectors (Baghouses)

.

The choice of which technology is most appropriate for a specific application depends upon several factors, inclu ding 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
- Control s The organic PM ( PM 10 and PM 2.5 ) 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, bagh ouses, 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 u sed 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 Demist er Vents at this source.IPL Eagle Valley generating Station TSD

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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 re 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, PM 10 and PM 2.5 BACT determination along with the existing PM, PM 10 and PM 2.5 BAC T 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 perm its 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

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- 00004 Proposed Limit IPL Eagle Valley Generating
S tation 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

V ent 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 (PM 10 and PM 2.5 ) emissions from the proposed Turbine Lube Oi l Demister Vents :

The organic PM (PM 10 and PM 2.5 ) 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, PM 10 and PM 2.5 emissions for the Turbine Lube Oil

Demister Vents

.

The organic PM, PM 10 and PM 2.5 emissions from the Turbine Lube Oil Demister Vents shall be the use of good design and operating pr actices

.

GHGs BACT

– Combined Cycle Combustion Turbines EU

- 1

- EU

- 2

Step 1: Identify Potential Control Technologies

The CO 2 is by far the dominant GHG from this source. CH 4 and N 2 O are present only in very small amounts, are incidental to combustion, an d trend with the CO 2 emissions. There are no known supplemental controls for N 2 O or methane emissions from gas

- fired units. Therefore, this BACT analysis focused on CO 2 as a surrogate for all GHG emissions (CO 2 e)

.

(1) Carbon C apture and Storage (CCS);

(2) High Thermal Efficiency System D esign ;IPL Eagle Valley generating Station TSD

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(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 CO 2 from the flue gas, pressurization of the captured CO 2 and transportation of the CO 2 as a fluid via pipeline, and injection and long

- term storage (usually geologic).

(1) Capture and Separation The capture technologies app licable for fossil fuel combustion include the following:

(i) Pre

- combustion systems designed to separate CO 2 and hydrogen in the high pressure syngas typically produced at coal integrated gasification combined cycle power plants. (ii) Post

- combustion sys tems designed to separate CO 2 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 CO 2 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
develo pment as demonstration projects at coal

- fired power plants using amine and ammonia capture systems to remove the CO 2 from the flue gas. These capture systems are associated with very high energy penalties and still considered to be innovative and not yet c ommercially
available for this source

.

There are several technologies at various stages of development with the potential to separate and capture CO 2 . 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 CO 2 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 CO 2 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 (Inter agency Task Force, 2010).

(2) Sequestration

Carbon sequestration usually involves the injection of CO 2 into deep geological formations of porous rock that are capped by one or more nonporous layers of rock. Injected at high pressure,
the CO 2 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 CO 2 storage. Also,
CO 2 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 locate d 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 CO 2 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 CO 2 waste

- stream and at much lower volumes th an a nominal 656 MW natural gas

- fired power plant.IPL Eagle Valley generating Station TSD

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(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 pl ant 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 Vermil ion 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 (inc luding 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 cleara nces would be necessary.

One additional option would be to construct a pipeline to transport CO 2 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 CO 2 emissions to a pipeline company (Denbury Resources, Inc.) and to oil companies in Texas and Louisiana who would use
the CO 2 for e nhanced 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 CO 2 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 co mpany 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 CO 2 annually compared t o 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 de termination, 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 p otential 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 t echnologies, 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 facil ity 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. Th is second category does not look at the direct GHG emissions from the new source (whichIPL Eagle Valley generating Station TSD

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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 co nsumed 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 equipme nt 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 cy cle 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 determine d 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 containin g fuel. All fossil fuels contain varying amounts of fuel bound carbon that is converted during the combustion process to produce CO and CO 2 . The use of gaseous fuels such as natural gas compared to the use of higher carbon

- containing fuels such as coal, pe t

- coke or fuel oils (residual or distillate) is a potentially feasible alternative to reduce the generation of CO 2 emissions from combustion

turbines.

Natural gas combustion results in significantly lower GHG emissions than coal combustion (117
lb/MMBTU v ersus 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
CO 2 during the combustion process.

Based on the information reviewed for this BAC T 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 ene rgy 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 foss il 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 fa cility. 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 effici ency 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 recaptur ed in theIPL Eagle Valley generating Station TSD

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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 achie ve high system efficiency. Any increase in energy efficiency within the operation of the system yields reductions in the generation of CO 2 emissions on a per unit output basis. US EPA guidance (PSD and Title V Permitting Guidance for Greenhouse Gases, No vember 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
des ign; 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 o f 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 he at 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 CO 2 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 bu t 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 p rocess. 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 a nd 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 ex tract 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 elec trical 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 identif ied is:

( 1) High Thermal Efficiency D esign

(2) Use of low emitting carbon fuelIPL Eagle Valley generating Station TSD

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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 possibil ity 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

ope ration 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 plan ts 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 SF 6 and CH 4 from the facility piping and components. Individual BACT requirements for these fu gitive 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 CO 2 CEMS as specified under 40 CFR 75, to monitor CO 2 emissions from the CT/HRSG

units and r ecord those emissions hourly, track fuel usage in all the combustion sources, and calculate a consecutive rolling 12

- month average CO 2 e emissions. These emissions are proposed to be included in the facility quarterly reports.

The following has been propo sed 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 f or transformer losses).

(2) The total CO 2 e emissions for combined cycle combustion turbines shall be limited to less
than 2

, 649,5 70 tons of CO 2 e per twelve (12) consecutive month period with compliance
determined at the end of each month.

Step 5: Select B ACT

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 CC CT block (ISO conditions, without duct firing or inlet evaporative cooling, and not accounting for transformer losses).

(2) The total CO 2 e e missions for combined cycle combustion turbines shall be limited to less
than 2

, 649,570 tons of CO 2 e per twelve (12) consecutive month period with compliance
determined at the end of each month.IPL Eagle Valley generating Station TSD

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GHGs BACT

– Auxiliary Boiler EU

- 3

Step 1: Identify Potential Control Technologies

The CO 2 is by far the dominant GHG from this source. CH 4 and N 2 O are present only in very

sma ll amounts, are incidental to combustion, and trend with the CO 2 emissions. There are no
known supplemental controls for N 2 O or methane emissions from gas

- fired units. Therefore, this
BACT analysis focused on CO 2 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 Insulati on;

(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 pr oper 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, CO 2 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 re liability 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 sy stems, 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 ac cording 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 emissi ons 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 feasib le option for the Auxiliary Boiler at this source.IPL Eagle Valley generating Station TSD

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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 fue l capability,
low

- and ultra low

- NO X 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 reduce s 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 u p to a 6% reduction of CO 2 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 th at
the use of e fficient 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

e nsure 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 NO X emissions. Up to a 3% reduction in CO 2 emissions

As part of the O&M practices, combustion tun ing 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: Combustio n 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

estimati on, 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.IPL Eagle Valley generating Station TSD

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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 he at 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 t he 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 trans fer 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 ar e 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, com mercial, or institutional boilers as the resulting increases in combustion temperature contribute to elevated emissions of NO X

. 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 opera ting 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 o n 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 f rom 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 condensa te 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 whet her it would be applicable, and, therefore, it is necessary to consider its viability on a case

- by

- case basis.IPL Eagle Valley generating Station TSD

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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 st eam 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 co ndensate 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

He at 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. Leakin g 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 distrib ution 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 dete rmination, IDEM, OAQ has determined that
the use of stream line m aintenance 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 feasibili ty 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% CO 2 Reduction)

(2 ) Efficient Burner Design (6% CO 2 Reduction)

(3) Air Prehe at & Economizers; (5% CO 2 Reduction)

(4) Improved Combustion Measures: Optimization & Digital Control System; (0.5

- 5% CO 2 Reduction)

(5 ) Improved Combustion Measures: Combustion Tuning; (3% CO 2 Reduction)

(6 ) Steam Line Maintenance;IPL Eagle Valley generating Station TSD

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(7 ) Condensat ion 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 ma intenance 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. Effi cient 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 eac h 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 to ns, 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 e conomizer ;

(5 ) The boiler will be equipped with a condensate return system (re covery );

(6 ) Steam and hot lines will be insulated; and

(7 ) Boiler designed for 8 0% thermal efficiency (HHV).

(8) The total CO 2 e e missions for Auxiliary Boiler shall be limited to less than 40,369 tons of
CO 2 e 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 follo wing 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 (re covery );

(6) Steam and hot lines will be insulated; andIPL Eagle Valley generating Station TSD

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(7 ) Boiler designed for 8 0% thermal efficiency (HHV).

(8) The total CO 2 e e missions for Auxiliary Boiler shall be limited to less th an 40, 6 3 9 tons of
CO 2 e 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 CO 2 is by far the dominant GHG f rom this source. CH 4 and N 2 O are present only in very
small amounts, are incidental to combustion, and trend with the CO 2 emissions. There are no
known supplemental controls for N 2 O or methane emissions from gas

- fired units. To the extent

measures are ide ntified that reduce CO 2 , the other GHGs may be also reduced accordingly. Therefore, this BACT analysis focused on CO 2 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 pro posed 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 CO 2 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 CO 2 - emitting facilities

i ncluding fossil fuel

- fired power plants and industrial facilities with high

- purity CO 2 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 U S 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, andIPL Eagle Valley generating Station TSD

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is currently only being contemplated on very large or very concentrated CO 2 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 docume nt suggests should consider CCS.

A CO 2 capture system for the dew point heater is not a reasonable BACT option because the capture of the CO 2 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 CO 2 concentration, low pressure, low quantity of
CO 2 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 CO 2 , which increases the energy required. Also, a low pressure absorption system creates a low pressure CO 2 stream which requires a very high energy dema nd for compression prior to transport. All these factors make the application of CO 2 capture on any small combustion exhaust extremely difficult and expensive. Additionally, the cost of capturing
CO 2 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 CO 2 is not a technically feasible option for the dew point
heater at this source.

Step 3: Rank the R emaining Control Technologies by Control Effectiveness

The only feasible, applicable and available cont rol technologies identified are;

( 1) T he 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 BA CT for GHG from the proposed D ew Point Heater (EU

- 4 ) :

The only feasible, applicable and available control technologies identified are ;

( 1) T he good engineering design and Combustion Practices ; and

( 2) The use of on ly natural gas

.

(3) The total CO 2 e e missions for Dew Point Heater shall be limited to less than 10,659 tons of CO 2 e 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 Deterior ation (PSD), IDEM has established the following as BACT for the GHG s for the dew Point Heater, identified as EU

- 4

.

( 1) T he good engineering design and Combustion Practices; andIPL Eagle Valley generating Station TSD

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( 2) The use of on ly natural gas

.

(3) The total CO 2 e e missions for Dew Poi nt Heater shall be limited to less than 10,659 tons of CO 2 e 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 CO 2 is by far the dominant GHG from this source. CH 4 and N 2 O are present only in very small amounts, are incidental to combustion, and trend with the CO 2 emissions. There are no known supplemental controls for N 2 O or methane emissions from diesel engines. To the extent

m easures are identified that reduce CO 2 , the other GHGs may be also reduced accordingly. Therefore, this BACT analysis focused on CO 2 as a surrogate for all GHG emissions.

Di stillate fuel oil is used because it is an independent source of fuel not related t o 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 type s 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. Thes e 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 CO 2 capture is a relatively new concept. In EPA’s recent GHG BACT guidance, EPA takes the p osition 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 CO 2 - emitting facilities including fossil fuel

- fired power plants and industrial facilities with high

- puri ty CO 2 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 consi stent 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 CO 2 source s. In starkIPL Eagle Valley generating Station TSD

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contrast, the source's Project miscellaneous combustion so urces 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 CO 2 capture system for the emergency diesel engines is not a reasonable BACT option because the capture of the CO 2 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 CO 2 concentration, low pressure, low quantity of CO 2 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 CO 2 , which increases the energy required. Also, a low pressure absorption system creates a low pressure CO 2 stream which requires a very high energy demand for compression prior to transport. All these factors make the application of CO 2 capture on any
small combustion exhaust extremely difficult and expensive. Additionally, the cost of capturing
CO 2 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 CO 2 is not a technically feasible option for the Emergency generators a t 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 en gines is to utilize g ood engineeri ng 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 : t he selection and use of g ood 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 5 00 hours per year. That u se is associated with assuring their readiness in an

emergency. The emergency engine will have the potential to emit greenhouse gases (CO 2 , CH 4 , and N 2 O) because they will combust distillate oil fuel. However, because their normal use is

limited to routin e maintenance, inspection and testing, their total emiss ions are very sm all (less
than 65 0 tons CO 2 e/yr).

The following has been proposed as BACT for GHG emissions from the proposed Emergency
Generator :

(1) The use of a g ood engineering design

.

(2) T he use of Ultra

- low sulfur diesel fuel

(3) The total CO 2 e e missions for Emergency Diesel Generator shall be limited to less than

605 tons of CO 2 e per twelve (12) consecutive month period with compliance determined
at the end of each month.IPL Eagle Valley generating Station TSD

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Step 5: Selec t 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 g ood engineering design ;

(2) The use of Ultra

- low sulfur diesel fuel ; and

(3) The total CO 2 e e missions for Emergency Diesel Generator shall be limited to less than

605 tons of CO 2 e per twelve (12) consecutive month period with compliance determined
at the end of each month.

GHGs BACT

– Emergency Fire Pumps

Step 1: I dentify Potential Control Technologies

The CO 2 is by far the dominant GHG from this source. CH 4 and N 2 O are present only in very small amounts, are incidental to combustion, and trend with the CO 2 emissions. There are no known supplemental controls for N 2 O or methane emissions from diesel engines. To the extent
measures are identified that reduce CO 2 , the other GHGs may be also reduced accordingly. Therefore, this BACT analysis focused on CO 2 as a surrogate for all GHG emissions.

Di stillate fuel oil is us ed 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 type s 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; a nd

(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 NSP S 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 th is 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 F ire pump at this source.

Carbon Capture

Post

- combustion CO 2 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 CO 2 - emitting facilities including fossil fuel

- fired power plants and industrial facilities with high

- purity CO 2 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 theIPL Eagle Valley generating Station TSD

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Appendix F to the above referenced US EPA guidance docum ent, 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 CO 2 source s. 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 CO 2 capture system for the emergency diesel engines is not a reasonable BACT option because the capture of the CO 2 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 CO 2 concentration, low pressure, low quantity of CO 2 available for capture, and the variability of load for these units.

The low concentration and low pressure of the exhausts from these proc esses complicate the absorption and desorption of the CO 2 , which increases the energy required. Also, a low pressure absorption system creates a low pressure CO 2 stream which requires a very high energy demand for compression prior to transport. All thes e factors make the application of CO 2 capture on any small combustion exhaust extremely difficult and expensive. Additionally, the cost of capturing
CO 2 for smaller sources is more expensive due to the lack of economy

- of

- scale. Further, the

emergency eng ines 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 CO 2 is not a technically feasible option for the Emergency

F ire 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 th e emergency f ire pump engine is to utilize g ood 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

Fir e pump engine : t he selection and use of g ood engineering design and fuel efficient design.

This project includes one di stillate oil fired 500 HP standby emergency fire pump . Th is engine is required for safety reasons. The engine is expected to operate le ss 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 (CO 2 , CH 4 , and N 2 O) because they will
combust distillate oil fuel . However, b ecause their normal use is limited to routine maintenance, inspection and testing, their total emiss ions are very small (less than 2 00 tons CO 2 e/yr).

The following has been proposed as BACT for GHG emissions from the proposed Emergency Fire Pump Engine :

(1) The use of a g ood engineering design

.

(2) The use of Ultra

- low sulfur diesel fuel

.IPL Eagle Valley generating Station TSD

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(3) The total CO 2 e e missions for Firewater Pump Engine shall be limited to less than 157.50
tons of CO 2 e per twelve (12) consecutive month period with compl iance de termined 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 g ood engineering desi gn

.

(2) The use of Ultra

- low sulfur diesel fuel

.

(3) The total CO 2 e e missions for Firewater Pump Engine shall be limited to less than 157.50
tons of CO 2 e per twelve (12) consecutive month period with compliance determined at
the end of each month.

GHGs BACT

– Circuit Breakers SF 6

Step 1: Identify Potential Control Technologies

GHG control possibilities identified and addressed in this BACT analysis for these small potential

sources are:

(1) Fully E nclosed 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

- the

art for circuit breakers. A low pressure alarm is installed on each bre aker to alert operators of a
loss of SF 6 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 SF 6 as the insulator and arc quenching substance in
the cir cuit breakers the source is proposing to installed . The unique performance qualities of SF 6 breakers is further supported by the most recent report released by the EPA SF 6 Partnership, which states: “no clear alternative exists for this gas that is used ex tensively 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 SF 6 that have comparable insulating and arc quenching prope rties 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 SF 6 substitute” for high

- voltage app lications. Therefore, the use of a breaker that doesn’t contain SF 6 is judged as not feasible for this application.IPL Eagle Valley generating Station TSD

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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.

S tep 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 SF 6 emissions for circuit breakers shall be limited to less than 59.80 tons of
CO 2 e per twelve (12) consecutive month period with compliance determined at the end
of each month.

Step 5: S elect BACT

Pursuant to 326 IAC 2

- 2

- 3 (Prevention of Significant Deterioration (PSD ) ), IDEM has established the following as BACT for GHGs for Electric al Circuit Breaker

.

(1) The use of totally enclosed pressure system with a design leak rate of 0.5% by we ight and a density alarm for leak detection.

(2) The total SF 6 emissions from all the circuit breakers shall not exceed 59.8 tons of CO 2 e 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 CH 4 . 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 f rom fugitive equipments leaks can be controlled by;

(a) Leakless Technology ;

(b) Instrument Leak detection and rep air (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

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- 00004

Step 2: Eliminate Technically Infeasible Options

Leakless Technology Leakless technology valves may be incorporated in situations where highly toxic or otherwise
hazardous ma terials 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 repa ir, 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 o ption 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 Inst rument 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 instrum ent 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 leak s 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 so urce.

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 Documen t 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 servic e. 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 CO 2 e per year, or about 0.053% of the tota l project’s proposed CO 2 e 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 CO 2 e 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 pro posed Fugitives Equipment
Leaks:IPL Eagle Valley generating Station TSD

– Appendix B Page 151 of 152 Martinsville, Indiana PSD/ SSM 109

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- 00004 Permit Writer: Josiah Balogun and SPM 109

- 32476

- 00004

The BACT for fug itive 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)

Monit oring program for methane leaks.IPL Eagle Valley generating Station TSD

– Appendix B Page 152 of 152 Martinsville, Indiana PSD/ SSM 109

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- 00004 Permit Writer: Josiah Balogun and SPM 109

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- 00004



### Best Available Control Technology during Startup and Shutdown for the
Combustion Turbines, identified as EU 1

- 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 l ow NO x (premix) mode and in compliance with the primary BACT limit

.

(c) A shutdown is defined as operation begin ning when the combustion turbine exits dry low

NOx (premix) mode and end ing 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 s hall 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 NO X , 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 st art 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 NO X 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 t he 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 ($/10 3 ft 3 x 10 3 /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 ($/10 3 ft 3 x 10 3 /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 ($/10 3 ft 3 x 10 3 /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 C atalyst

to Control VOC Emissions from the 20 MMBtu/hr Dew Poi nt 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 ($/10 3 ft 3 x 10 3 /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)=

## I NDIANA 

## D EPARTMENT OF 

## E NVIRONMENTAL 

## M ANAGEMENT

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 Commissione r

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 material s 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 appro priate person within your company to receive this document, please forward it to the correct person.

A copy of the final decision and supporting mate rials 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 enclos ed documents, please contact the Office of Air Quality, Permits Branch at (317) 233-0178, or toll-fr ee 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

## I NDIANA 

## D EPARTMENT OF 

## E NVIRONMENTAL 

## M ANAGEMENT

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 Commissione r

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 av ailable 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 am ple 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 6/13/2013FACSIMILIE OF PS Form 3877Mail Code 61-53IDEM Staff PWAY 10/11/2013Indianapolis Power & Light Co.(IPL)Eagle ValleyGen.Stat 109-32471-00004(final)AFFIX STAMPHERE IFUSED ASCERTIFICATEOF MAILINGName andaddress ofSender►Indiana Department of EnvironmentalManagementOffice of Air Quality – Permits Branch100 N. SenateIndianapolis, IN 46204Type of Mail:CERTIFICATE OFMAILING ONLYLine ArticleNumberName, Address, Street and Post Office Address Postage HandingChargesAct. Value(If Registered)InsuredValueDue Send ifCODR.R.FeeS.D. Fee S.H.FeeRest.Del. FeeRemarks1Angelique Oliger Indianapolis Power & Light Co. Eagle Valley Gener 1 Monument Cir Indianapolis IN 46204 (Source CAATS)2Bradley Scott Sr Dir - Plant Ops Indianapolis Power & Light Co.Eagle Valley Gener PO Box 436 / 6925 N SR 57 Petersburg IN47567(RO CAATS)3Morgan County Commissioners 180 South Main Street Martinsville IN 46151(Local Official)4Martinsville City Council and Mayors Office P.O. Box 1415, 59 South Jefferson Street Martinsville IN 46151(Local Official)5Morgan Co Public Library 110 S Jefferson St Martinsville IN 46151-1999(Library)6Clayton D. & Patricia A. Arthur 5178 Brenda Boulvard Greenwood IN 46143(Affected Party)7Morgan County Health Department 180 S MainStreet, Suite 252 Martinsville IN 46151-1988(Health Department)8David Jones 7977 N. Taylors Rd. Mooresville IN 46158(Affected Party)9Claudia Parker 6761 Centenary Rd. Mooresville IN 46158(Affected Party)10James Swails 6568 E. Rosebud Lane Mooresville IN 46158(Affected Party)11John Thurston 6548 E. Watson Mooresville IN 46158(Affected Party)12Bethany Town Council 7355 Bethany Park Martinsville IN 46151(Local Official)13Tom Rarick Environmental Resources Management (ERM) 11350N Meridian Suite 320 Carmel IN 46032 (Consultant)1415Total number of piecesListed by SenderTotal number of PiecesReceived at Post OfficePostmaster, Per (Name ofReceiving employee)The full declaration of value is required on all domestic and international registered mail. Themaximum indemnity payable for the reconstruction of nonnegotiable documents under ExpressMail document reconstructing insurance is $50,000 perpiece subject to a limit of $50, 000 peroccurrence. The maximum indemnity payable onExpress mil merchandise insurance is $500.The maximum indemnity payable is $25,000 for registered mail, sent with optional postalinsurance. SeeDomestic Mail ManualR900, S913, andS921for limitations of coverage oninured and COD mail. SeeInternational Mail Manualfor limitations o coverage on internationalmail. Special handling charges apply only to Standard Mail (A) and Standard Mail (B) parcels.