INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

We Protect Hoosiers and Our Environment. 

Mitchell E. Daniels Jr. 100 North Senate Avenue 

Governor Indianapolis, Indiana 46204 

(317) 232-8603 

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

Commissioner www.idem.IN.gov

Page 1 of 2 

 FNTVOP.dot 03/23/06 

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TO: Interested Parties / Applicant 

DATE: June 27, 2012 

RE: Indiana Gasification LLC / 147-30464-00060 

FROM: Matthew Stuckey, Branch Chief 

 Permits Branch 

 Office of Air Quality 

Notice of Decision: Approval – Effective Immediately 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

to the filing: 

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

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

OEA by U.S. mail; or 

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

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

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

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

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

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

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

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

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

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

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

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

governing documents of the type issued by the Commissioner. 

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

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

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

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

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

U.S. Environmental Protection Agency 

401 M Street 

Washington, D.C. 20406 

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

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

6027, ext. 3-0178. 

 

Enclosures 

FNTVOP.dot12/3/07

Indiana Gasification, LLC Page 2 of 6

Rockport, IN PSD/Part 70 Permit No. 147-30464-00060

(e) One (1) rail conveyor belt to the stacker, identified as EU-012K, to be 

permitted in 2012, with one (1) control device, identified as C-012K, 

exhausting through one (1) vent, identified as S-012K; 

(f) Two (2) stacker belts to the radial stacker, identified as EU-012L and EU012M, to be permitted in 2012, with two (2) control devices, identified as 

C-012L and C-012M, respectively, exhausting through two (2) vents, 

identified as S-012L through S-012M, respectively; 

(g) Two (2) classification towers, identified as EU-012T and EU-012U, to be 

permitted in 2012, with two (2) control devices, identified as C-012T and 

C-012U, respectively, exhausting through two (2) vents, identified as S012T through S-012U, respectively; 

(h) One (1) classification tower to a day bin, identified as EU-012V, to be 

permitted in 2012, with one (1) control device, identified as C-012V, 

exhausting through one (1) vent, identified as S-012V;

(i) Three (3) truck stations unloading to a truck hopper, identified as EU012Z, EU-012AB and EU-012AC, to be permitted in 2012, with three (3) 

control devices, identified as C-012Z, C-012AB and C-012AC, 

respectively, exhausting through three (3) vents, identified as S-012Z, S012AB and S-012AC, respectively;

(j) One (1) truck hopper unloading to the conveyor belts, identified as EU012AA, to be permitted in 2012, with one (1) control device, identified as 

C-012AA exhausting through one (1) vent, identified as S-012AA; and 

(k) One (1) truck/rail conveyor transfer tower, identified as EU-012Y, to be 

permitted in 2012, with one (1) control device, identified as C-012Y, 

exhausting through one (1) vent, identified as S-012Y;

(3) Two (2) radial stackers to the pile, nominally rated at 3,000 tons per hour each, to 

be permitted in 2012, with particulate emissions controlled by telescoping chutes 

with two (2) fabric filters identified as C-012N and C-012O, exhausting through 

two (2) stacks, identified as S-012N and S-012O.

(4) Two (2) transfer systems consisting of hoppers and conveyor belts transferring 

feed stock from the piles to classification towers, identified as EU-012R and EU012S, to be permitted in 2012, with particulate emissions controlled with two (2) 

dust extraction systems or baghouses, identified as C-012R and C-012S, 

respectively, each nominally rated at 6,000 acfm, exhausting through two (2) 

vents, identified as S-012R and S-012S, respectively.

(5) Two (2) dozer activities on the piles, nominally rated at 1,500 tons per hour each, 

identified as EU-012P and EU-012Q, to be permitted in 2012, with particulate 

emissions controlled by wet suppression. 

(6) Two (2) storage piles with a nominal capacity of 300,000 tons each, identified as 

EU-012W and EU-012X, to be permitted in 2012, with particulate emissions 

controlled by wet suppression and compaction. 

(B) Two (2) process area solid feedstock conveying, storage, and feed bins (main and spare), 

identified as EU-011A and EU-011B, to be permitted in 2012, with particulate emissions 

controlled by two (2) baghouses identified as C-011A and C-011B, respectively, each 
Indiana Gasification, LLC Page 3 of 6

Rockport, IN PSD/Part 70 Permit No. 147-30464-00060

nominally rated at 33,760 dscfm, exhausting through two (2) stacks, identified as S-011A 

and S-011B, respectively. [Under 40 CFR 60, Subpart Y, the process area solid feedstock 

conveying, storage, and feed bins (main and spare) are new affected sources.]

(C) One (1) syngas hydrocarbon flare, with a pilot nominally rated at 0.27 MMBtu/hr HHV and 

identified as EU-001, to be permitted in 2012, exhausting through one (1) tip, identified as 

S-001.

(D) One (1) acid gas flare, with a pilot nominally rated at 0.27 MMBtu/hr HHV and identified as 

EU-002, to be permitted in 2012, exhausting through one (1) tip, identified as S-002. 

(E) Two (2) Acid Gas Removal (AGR) Unit vents, identified as EU-007A and EU-007B, to be 

permitted in 2012, with methanol, H2S, COS, and CO emissions controlled by two (2) 

regenerative thermal oxidizers (RTO) identified as C-007A and C-007B, respectively, 

each nominally rated at 38.8 MMBtu/hr HHV fuel input, exhausting through two (2) stacks, 

identified as S-007A and S-007B.

(F) Two (2) Wet Sulfuric Acid (WSA) plant trains, each nominally rated at 800 stpd H2SO4

and identified as EU-015A and EU-015B, to be permitted in 2012, with NOx, SO2, H2SO4

emissions controlled by two (2) selective catalytic reduction (SCR) systems identified as 

C-015-1A and C-015-1B, respectively, and two (2) hydrogen peroxide scrubbers identified 

as C-015-2A and C-015-2B, respectively, exhausting through two (2) stacks, identified as 

S-015A and S-015B respectively. These emissions units also include two (2) preheat 

burners (one for each train), each nominally rated at 35.00 MMBtu/hr HHV, venting 

through the same stacks.

(G) Two (2) natural gas-fired auxiliary boilers, nominally rated at 408 MMBtu/hr HHV each, 

identified as EU-005A and EU-005B, to be permitted in 2012, with NOx emissions 

controlled by ultra-low NOx burners/Flue Gas Recirculation (ULNB/FGR), with both boilers 

exhausting through one (1) stack, identified as S-005. [Under 40 CFR 60, Subpart Db, the 

natural gas-fired auxiliary boilers are new affected sources.]

(H) Five (5) natural gas-fired and SNG fuel-fired gasifier preheat burners, each nominally 

rated with a heat input of 35.00 MMBtu/hr HHV, and identified as EU-008A through EU008E, to be permitted in 2012, exhausting through five (5) vents, identified as S-008A 

through S-008E, respectively. 

(I) One (1) ZLD-Spray Dryer, to be permitted in 2012, nominally rated at 5.6 MMBtu/hr with 

PM emissions controlled by a baghouse identified as C-032, nominally rated at 2,735 

dscfm, and identified as EU-032, with low NOx burners (LNB), exhausting through one (1) 

stack, identified as S-014.

(J) Methanol Tanks:

(1) One (1) Methanol De-Inventory Tank, with a nominal capacity of 700,000 gallons, 

identified as EU-024, to be permitted in 2012, with emissions controlled by a 

vapor recovery system and exhausting through one (1) vent, identified as S-024.

[40 CFR 60 Subpart Kb]. 

(2) One (1) Fresh Methanol Storage Tank, with a nominal capacity of 332,000 

gallons, identified as EU-025, to be permitted in 2012, with emissions controlled 

by a vapor recovery system and exhausting through one (1) vent, identified as S025. [40 CFR 60 Subpart Kb].

(K) Paved Plant Haul Roads are identified as emissions unit FUG-ROAD. 

(L) Electrical Circuit Breakers (approximately six) containing sulfur hexafluoride (SF6) 
Indiana Gasification, LLC Page 4 of 6

Rockport, IN PSD/Part 70 Permit No. 147-30464-00060

identified as emissions unit FUG-SF6, to be permitted in 2012, with fugitive GHG 

emissions controlled by full enclosure.

(M) Fugitive Equipment Leaks from the gasification, shift conversion, gas cooling, AGR, CO2

compression, WSA and methanation are identified as emissions units FUG and FUGWSA and will be controlled by a Leak Detection and Repair (LDAR) program.

(N) One (1) ZLD Inert Gas Vent identified as EU-033, to be permitted in 2012, with mercury 

(Hg) emissions controlled by a sulfided carbon adsorbent identified as C-033, exhausting 

through one (1) stack, identified as S-033.

Insignificant and Trivial Activities 

The source also consists of the following insignificant activities as defined in 326 IAC 2-7-1(21):

(a) Two (2) emergency diesel generators, each nominally rated at 1,341 horsepower, 

identified as EU-009A and EU-009B, to be permitted in 2012, exhausting through two (2) 

vents, identified as S-009A and S-009B, respectively. [Under 40 CFR 60, Subpart IIII, 

each, emergency diesel fired generator is considered a new affected source.][Under 40 

CFR 63, Subpart ZZZZ, each, emergency diesel fired generator is considered a new 

affected source.]

(b) Three (3) firewater pump diesel engines, each nominally rated at 575 horsepower and 

identified as EU-010A through EU-010C, to be permitted in 2012, exhausting through 

three (3) vents, identified as S-010A through S-010C, respectively. [Under 40 CFR 60, 

Subpart IIII, each firewater pump diesel engine is considered a new affected 

source.][Under 40 CFR 63, Subpart ZZZZ, each firewater pump diesel engine is 

considered a new affected source.]

(c) Four (4) rod mill eductor vent stacks, to be permitted in 2012, nominally rated at 180 cfm 

and identified as EU-013A through EU-013D, and exhausting through four (4) vents, 

identified as S-013A through S-013D, respectively. 

(d) One (1) six (6) cell ASU cooling tower, nominally rated with a circulation rate of 54,960 

gpm and identified as EU-016A, to be permitted in 2012, with high efficiency drift/mist 

eliminators, and exhausting through six (6) vents, identified as S-016A-A through 

S-016A-F.

(e) One (1) twenty-four (24) cell main cooling tower, nominally rated with a circulation rate of 

404,700 gpm and identified as EU-016B, to be permitted in 2012, with high efficiency 

drift/mist eliminators, and exhausting through twenty-four (24) vents, identified as S-016BA through S-016B-X.

(f) Two (2) Air Separation Unit (ASU) molecular sieve regeneration train vents, which each 

vent a nominal 187,000 cubic feet per minute during regenerations, identified as EU-017A 

and EU-017B, to be permitted in 2012, exhausting through two (2) vents, identified as S017A andS-017B, respectively.

(g) One (1) slag handling storage pad, to be permitted in 2012, nominally rated at 43 tons per 

hour, identified as EU-034A, with fugitive particulate emissions controlled by wet 

suppression. 

(h) One (1) front-end loader activity on the slag storage pad, to be permitted in 2012, 

nominally rated at 1,440 tons per day, identified as EU-034C, with fugitive particulate 

emissions controlled by wet suppression. 
Indiana Gasification, LLC Page 5 of 6

Rockport, IN PSD/Part 70 Permit No. 147-30464-00060

(i) One (1) fixed roof recycle solid tank, to be permitted in 2012, with a nominal capacity of 

14,400 gallons, identified as EU-019. 

(j) Five (5) fixed roof slurry run tanks, each, to be permitted in 2012, with a nominal capacity

of 47,700 gallons, identified as EU-020A through EU-020E. 

(k) Two (2) fixed roof grey water tanks, to be permitted in 2012, each with a nominal capacity 

of 88,000 gallons, identified as EU-021A and EU-021B. 

(l) One (1) fixed roof slurry additive tank, to be permitted in 2012, with a nominal capacity of 

28,500 gallons, identified as EU-022. 

(m) Five (5) open slag sumps, to be permitted in 2012, each with a nominal capacity of 15,600 

gallons, identified as EU-023A through EU-023E.

(n) One (1) pressurized Sour Water Stripper Surge Tank, to be permitted in 2012, with a 

nominal capacity of 175,000 gallons, identified as EU-026.

(o) Six (6) fixed roof sulfuric acid storage tanks, to be permitted in 2012, each with a nominal 

capacity of 866,500 gallons - identified as EU-027A through EU-027F.

(p) Two (2) fixed roof aqueous ammonia storage tanks, to be permitted in 2012, each with a 

nominal capacity of 31,000 gallons - identified as EU-028A and EU-028B, with ammonia 

emissions controlled with two (2) water scrubbers identified as C-028A and C-028B, 

respectively.

(q) One (1) fixed roof Diesel Fuel Storage Tank, to be permitted in 2012, with a nominal 

capacity of 9,240 gallons, identified as EU-029. 

(r) One (1) fixed roof Gasoline Fuel Storage Tank, to be permitted in 2012, with a nominal 

capacity of 1,030 gallons, identified as EU-030.

(s) One (1) fixed roof triethylene glycol storage tank, to be permitted in 2012, with a nominal 

capacity of less than 10,000 gallons, identified as EU-031.

The following construction conditions are applicable to the proposed project:

General Construction Conditions

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

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

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

by the Office of Air Quality (OAQ).

2. This approval to construct does not relieve the permittee of the responsibility to comply 

with the provisions of the Indiana Environmental Management Law (IC 13-11 through 13-

20; 13-22 through 13-25; and 13-30), the Air Pollution Control Law (IC 13 17) and the 

rules promulgated thereunder, as well as other applicable local, state, and federal 

requirements.

3. Effective Date of the Permit

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

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

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

this approval or if construction is suspended for a continuous period of one (1) year or 

more.


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Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

TABLE OF CONTENTS

A. SOURCE SUMMARY

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

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

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

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

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

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

B. GENERAL CONDITIONS

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

C. SOURCE OPERATION CONDITIONS

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

C.1 Particulate Emission Limitations For Processes with Process Weight Rates 

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

C.2 Opacity [326 IAC 5-1]

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

C.4 Incineration [326 IAC 4-2] [326 IAC 9-1-2]
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C.5 Fugitive Dust Emissions [326 IAC 6-4]

C.6 Fugitive Particulate Matter Emission Limitations [326 IAC 6-5]

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

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

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

C.14 Risk Management Plan [326 IAC 2-7-5(11)] [40 CFR 68]

C.15 Response to Excursions or Exceedances [326 IAC 2-7-5][40 CFR 64][326 IAC 3-8]

[326 IAC 2-7-6]

C.16 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.17 Emission Statement [326 IAC 2-7-5(3)(C)(iii)][326 IAC 2-7-5(7)][326 IAC 2-7-19(c)]

[326 IAC 2-6]

C.18 General Record Keeping Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-6] [326 IAC 2-2]

[326 IAC 2-3]

C.19 General Reporting Requirements [326 IAC 2-7-5(3)(C)][326 IAC 2-1.1-11] 

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

Stratospheric Ozone Protection

C.20 Compliance with 40 CFR 82 and 326 IAC 22-1

D.1. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.1.1 Permit No Defense 

Effective Date of the Permit

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

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

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

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

D.1.5 Preventive Maintenance Plan [326 IAC 1-6-3]
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Compliance Determination Requirements

D.1.6 PM, PM10 and PM2.5 Control [326 IAC 2-7-6(6)]

D.1.7 Testing Requirements [326 IAC 2-1.1-11]

D.1.8 Broken or Failed Bag Detection 

D.1.9 Wet Dust Extraction System Failed Bag Detection 

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

D.1.10 Visible Emission Notations

D.1.11 Parametric Monitoring

D.1.12 Ambient Temperature Monitoring

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

D.1.13 Record Keeping Requirements

D.2. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.2.1 Permit No Defense 

Effective Date of the Permit

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

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

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

D.2.4 PM, PM10, PM2.5, CO, SO2, NOx and GHGs PSD BACT [326 IAC 2-2-3]

D.2.5 Hazardous Air Pollutants (HAPs) Minor Limits

D.2.6 Preventive Maintenance Plan [326 IAC 1-6-3]

Compliance Determination Requirements

D.2.7 Flare Pilot Flame 

D.2.8 Complaince determination Requirements [326 IAC 2-2-3]

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

D.2.9 Flare Parametric Monitoring 

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

D.2.10 Record Keeping Requirements

D.3. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.3.1 Permit No Defense 

Effective Date of the Permit

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

D.3.3 Modification to Construction Conditions [326 IAC 2]
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Permit Reviewer: Josiah Balogun

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

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

D.3.5 Preventive Maintenance Plan [326 IAC 1-6-3]

Compliance Determination Requirements

D.3.6 Flare Pilot Flame 

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

D.3.7 Flare Parametric Monitoring 

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

D.3.8 Record Keeping Requirements

D.4. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.4.1 Permit No Defense 

Effective Date of the Permit

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

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

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

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

D.4.5 CO PSD BACT [326 IAC 2-2-3]

D.4.6 SO2 PSD BACT [326 IAC 2-2-3]

D.4.7 NOx PSD BACT [326 IAC 2-2-3]

D.4.8 VOC Best Available Control Technology (BACT) [326 IAC 8-1-6]

D.4.9 GHGs PSD BACT [326 IAC 2-2-3]

D.4.10 Alternate Emissions Limitation During Gasifier Startup Flaring

D.4.11 Hazardous Air Pollutants (HAPs) Minor Limits

D.4.12 Preventive Maintenance Plan [326 IAC 1-6-3]

Compliance Determination Requirements

D.4.13 PM, PM10 and PM2.5 Calculations [326 IAC 2-2] 

D.4.14 Nitrogen Oxide Control

D.4.15 Sulfur Dioxide Control and Calculations

D.4.16 Greenhouse Gases (GHGs) Calculations

D.4.17 Thermal Oxidizer Operation 

D.4.18 Water Wash Tower Control

D.4.19 Testing Requirements [326 IAC 2-1.1-11]

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

D.4.20 Thermal Oxidizer Parametric Monitoring

D.4.21 Water Wash Tower Parametric Monitoring

D.4.22 Vent Flow Monitoring

D.4.23 Compliance Assurance Monitoring [40 CFR 64]
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Record Keeping and Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-19]

D.4.24 Record Keeping Requirements

D.4.25 Reporting Requirements

D.5. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.5.1 Permit No Defense 

Effective Date of the Permit

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

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

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

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

D.5.5 H2SO4 PSD BACT [326 IAC 2-2-3]

D.5.6 CO PSD BACT [326 IAC 2-2-3]

D.5.7 SO2 PSD BACT [326 IAC 2-2-3]

D.5.8 NOx PSD BACT [326 IAC 2-2-3]

D.5.9 GHGs PSD BACT [326 IAC 2-2-3]

D.5.10 Alternate Emissions Limitation During Gasifier Startup Flaring 

D.5.11 Preventive Maintenance Plan [326 IAC 1-6-3]

Compliance Determination Requirements

D.5.12 Nitrogen Oxide Control

D.5.13 Sulfur Dioxide Control

D.5.14 PM, PM10, PM2.5 and H2SO4 Control

D.5.15 Maintenance of Continuous Emission Monitoring Equipment [326 IAC 3-5][326 IAC 2-2-3]

D.5.16 Testing Requirements [326 IAC 2-1.1-11]

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

D.5.17 Scrubber Parametric Monitoring 

D.5.18 Scrubber Failure Detection 

D.5.19 Compliance Assurance Monitoring [40 CFR 64]

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

D.5.20 Record Keeping Requirements

D.5.21 Reporting Requirements

D.6. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.6.1 Permit No Defense 

Effective Date of the Permit

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

D.6.3 Modification to Construction Conditions [326 IAC 2]
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Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.6.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

D.6.5 CO PSD BACT [326 IAC 2-2-3]

D.6.6 SO2 PSD BACT [326 IAC 2-2-3]

D.6.7 NOx PSD BACT [326 IAC 2-2-3]

D.6.8 GHGs PSD BACT [326 IAC 2-2-3]

D.6.9 Hazardous Air Pollutants (HAPs) Minor Limits

D.6.10 Operational Limit

D.6.11 Preventive Maintenance Plan [326 IAC 1-6-3]

Compliance Determination Requirements

D.6.12 Nitrogen Oxide Control

D.6.13 Maintenance of Continuous Emission Monitoring Equipment [326 IAC 3-5][326 IAC 2-2-3]

D.6.14 Testing Requirements [326 IAC 2-1.1-11]

D.6.15 Compliance Determination Requirements 

D.6.16 Greenhouse Gases (GHGs) Calculations

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

D.6.17 Record Keeping Requirements

D.6.18 Reporting Requirements

D.7. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.7.1 Permit No Defense 

Effective Date of the Permit

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

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

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

D.7.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

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

D.7.6 SO2 PSD BACT [326 IAC 2-2-3]

D.7.7 NOx PSD BACT [326 IAC 2-2-3]

D.7.8 GHGs PSD BACT [326 IAC 2-2-3]

D.7.9 Preventive Maintenance Plan [326 IAC 1-6-3]

Compliance Determination Requirements

D.7.10 Compliance Determination Requirements 

D.7.11 Greenhouse Gases (GHGs) Calculations

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

D.7.12 Record Keeping Requirements

D.7.13 Reporting Requirements
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D.8. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.8.1 Permit No Defense 

Effective Date of the Permit

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

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

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

D.8.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

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

D.8.6 SO2 PSD BACT [326 IAC 2-2-3]

D.8.7 NOx PSD BACT [326 IAC 2-2-3]

D.8.8 GHGs PSD BACT [326 IAC 2-2-3]

D.8.9 Preventive Maintenance Plan [326 IAC 1-6-3]

Compliance Determination Requirements

D.8.10 Nitrogen Oxide Control

D.8.11 Compliance Determination Requirements 

D.8.12 PM, PM10 and PM2.5 Control

D.8.13 Testing Requirements [326 IAC 2-1.1-11]

D.8.14 Greenhouse Gases (GHGs) Calculations

D.8.15 Broken or Failed Bag Detection 

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

D.8.16 Visible Emission Notation 

D.8.17 Parametric Monitoring 

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

D.8.18 Record Keeping Requirements

D.8.19 Reporting Requirements

D.9. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.9.1 Permit No Defense 

Effective Date of the Permit

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

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

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

D.9.4 PM, PM10, PM2.5, CO, SO2, NOx and GHGs PSD BACT [326 IAC 2-2-3]

D.9.5 Operating Restriction During Gasifier Startup Flaring 

Compliance Determination Requirements

D.9.6 Greenhouse Gases Calculations
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Record Keeping and Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-19]

D.9.7 Record Keeping Requirements

D.9.8 Reporting Requirements

D.10. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.10.1 Permit No Defense 

Effective Date of the Permit

D.10.2 Effective Date of the Permit [IC 13-15-5-3]

D.10.3 Modification to Construction Conditions [326 IAC 2]

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

D.10.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Compliance Determination Requirements

D.10.5 PM, PM10 and PM2.5 Control [326 IAC 2-7-6(6)]

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

D.10.6 TSD Monitoring 

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

D.10.7 Record Keeping Requirements

D.11. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.11.1 Permit No Defense 

Effective Date of the Permit

D.11.2 Effective Date of the Permit [IC 13-15-5-3]

D.11.3 Modification to Construction Conditions [326 IAC 2]

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

D.11.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

D.11.5 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

D.12. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.12.1 Permit No Defense 

Effective Date of the Permit

D.12.2 Effective Date of the Permit [IC 13-15-5-3]

D.12.3 Modification to Construction Conditions [326 IAC 2]
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Emission Limitations and Standards [326 IAC 2-7-5(1)]

D.12.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Compliance Determination Requirements

D.12.5 Compliance Determination Requirements

Compliance Monitoring Requirements

D.12.6 Ambient Temperature Monitoring

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

D.12.7 Record Keeping Requirements

D.13. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.13.1 Permit No Defense 

Effective Date of the Permit

D.13.2 Effective Date of the Permit [IC 13-15-5-3]

D.13.3 Modification to Construction Conditions [326 IAC 2]

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

D.13.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Compliance Determination Requirements

D.13.5 Compliance Determination Requirements

Compliance Monitoring Requirements

D.13.6 Ambient Temperature Monitoring

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

D.13.7 Record Keeping Requirements

D.14. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.14.1 Permit No Defense 

Effective Date of the Permit

D.14.2 Effective Date of the Permit [IC 13-15-5-3]

D.14.3 Modification to Construction Conditions [326 IAC 2]

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

D.14.4 GHGs PSD BACT [326 IAC 2-2-3]
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D.15. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.15.1 Permit No Defense 

Effective Date of the Permit

D.15.2 Effective Date of the Permit [IC 13-15-5-3]

D.15.3 Modification to Construction Conditions [326 IAC 2]

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

D.15.4 CO, H2SO4 and SO2 PSD BACT [326 IAC 2-2-3]

D.15.5 Hazardous Air Pollutants (HAPs) Minor Limits

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

D.15.6 Record Keeping Requirements

D.16. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.16.1 Permit No Defense 

Effective Date of the Permit

D.16.2 Effective Date of the Permit [IC 13-15-5-3]

D.16.3 Modification to Construction Conditions [326 IAC 2]

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

D.16.4 H2SO4 PSD BACT [326 IAC 2-2-3]

D.17. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.17.1 Permit No Defense 

Effective Date of the Permit

D.17.2 Effective Date of the Permit [IC 13-15-5-3]

D.17.3 Modification to Construction Conditions [326 IAC 2]

Compliance Determination Requirements

D.17.4 Vapor Recovery System

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

D.17.5 Vapor Recovery System Parametric Monitoring

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

D.17.6 Record Keeping Requirement
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D.18. EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions

D.18.1 Permit No Defense 

Effective Date of the Permit

D.18.2 Effective Date of the Permit [IC 13-15-5-3]

D.18.3 Modification to Construction Conditions [326 IAC 2]

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

D.18.4 Hazardous Air Pollutants (HAPs) Control

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

D.18.5 Parametric Monitoring

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

D.18.6 Record Keeping Requirement

E.1. EMISSIONS UNIT OPERATION CONDITIONS

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

E.1.1 General Provisions Relating to NSPS Db [326 IAC 12][40 CFR Part 60, Subpart A]

E.1.2 Standard of Performance for Industrial-Commercial-Institutional Steam Generating Units 

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

E.2. EMISSIONS UNIT OPERATION CONDITIONS

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

E.2.1 General Provisions Relating to NSPS Kb [326 IAC 12-1][40 CFR Part 60, Subpart A]

E.2.2 Standard of Performance for Volatile Organic Liquid Storage Vessels [326 IAC 12][40 

CFR Part 60, Subpart Kb]

E.3. EMISSIONS UNIT OPERATION CONDITIONS

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

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

D.3.2 New Source Performance Standard of performance Coal Preparation and Processing 

Plants Requirements [326 IAC 12][40 CFR Part 60, Subpart Y]

E.4. EMISSIONS UNIT OPERATION CONDITIONS

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

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

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

Engines [326 IAC 12][40 CFR Part 60, Subpart IIII]
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E.5. EMISSIONS UNIT OPERATION CONDITIONS

National Emission Standard for Hazardous Air Pollutants [40 CFR Part 63]

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

Reciprocating Internal Combustion Engines [326 IAC 20-82-1][40 CFR Part 63, Subpart 

ZZZZ]

E.6. EMISSIONS UNIT OPERATION CONDITIONS

National Emission Standard for Hazardous Air Pollutants [40 CFR Part 63]

E.6.1 LDAR Standards For Fugitive Equipments [40 CFR 63 Subpart H]

Certification

Emergency Occurrence Report

Quarterly Report

Quarterly Deviation and Compliance Monitoring Report

Affidavit of Construction

Attachment A - NESHAP 40 CFR 63, Subpart ZZZZ

Attachment B - NSPS 40 CFR 60, Subpart Y

Attachment C - NSPS 40 CFR 60, Subpart Db 

Attachment D - NSPS 40 CFR 60, Subpart Kb 

Attachment E - NSPS 40 CFR 60, Subpart IIII 

Attachment F - NESHAP 40 CFR 63, Subpart H

Attachment G - Fugitive Dust Control Plan 
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SECTION A SOURCE SUMMARY

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

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

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

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

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

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

applicable requirements presented in the permit application.

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

The Permittee owns and operates a stationary natural gas (SNG) and liquefied carbon dioxide 

(CO2) production plant. 

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

General Source Phone Number: 317-490-5078

SIC Code: 4925, 2819

County Location: Spencer

Source Location Status: Attainment for all criteria pollutants 

Source Status: Part 70 Operating Permit Program 

Major Source, under PSD Rules

Minor Source, Section 112 of the Clean Air Act

1 of 28 Source Categories

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

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

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

(A) Incoming solid feedstock materials handling system, transferring material from the barge 

unloading facility and railcar unloading facility to storage piles and day bins, consisting of: 

[Under 40 CFR 60, Subpart Y, the incoming solid feedstock materials handling system, 

transferring material from the barge unloading facility and railcar unloading facility to 

storage piles and day bins are new affected sources.]

(1) One (1) barge unloading to hopper transfer point, permitted in 2012, nominally 

rated at 750 tons per hour, identified as EU-012A, with particulate emissions 

controlled by wet suppression.

(2) The following twenty (20) transfer points, each with particulate emissions 

controlled with a dust extraction system or baghouse nominally rated at 1,500 

acfm: 

(a) One (1) barge unloading from the hopper to the belt, identified as EU012B, permitted in 2012, with one (1) control device, identified as C012B, exhausting through one (1) vent, identified as S-012B; 

(b) Four (4) barge conveyor transfer points, identified as EU-012C through 

EU-012F, permitted in 2012, with four (4) control devices, identified as C-
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012C through C-012F, respectively, exhausting through four (4) vents, 

identified as S-012C through S-012F, respectively; 

(c) Two (2) rail unloading to rail hoppers, identified as EU-012G and EU012H, permitted in 2012, with two (2) control devices, identified as C012G through C-012H, respectively, exhausting through two (2) vents, 

identified as S-012G through S-012H, respectively;

(d) Two (2) rail hoppers unloading to the conveyor belts, identified as EU012I and EU-012J, permitted in 2012, with two (2) control devices, 

identified as C-012I and C-012J, respectively, exhausting through two 

(2) vents, identified as S-012I through S-012J, respectively; 

(e) One (1) rail conveyor belt to the stacker, identified as EU-012K, 

permitted in 2012, with one (1) control device, identified as C-012K, 

exhausting through one (1) vent, identified as S-012K; 

(f) Two (2) stacker belts to the radial stacker, identified as EU-012L and EU012M, permitted in 2012, with two (2) control devices, identified as C012L and C-012M, respectively, exhausting through two (2) vents, 

identified as S-012L through S-012M, respectively; 

(g) Two (2) classification towers, identified as EU-012T and EU-012U, 

permitted in 2012, with two (2) control devices, identified as C-012T and 

C-012U, respectively, exhausting through two (2) vents, identified as S012T through S-012U, respectively; 

(h) One (1) classification tower to a day bin, identified as EU-012V, 

permitted in 2012, with one (1) control device, identified as C-012V, 

exhausting through one (1) vent, identified as S-012V;

(i) Three (3) truck stations unloading to a truck hopper, identified as EU012Z, EU-012AB and EU-012AC, permitted in 2012, with three (3) 

control devices, identified as C-012Z, C-012AB and C-012AC, 

respectively, exhausting through three (3) vents, identified as S-012Z, S012AB and S-012AC, respectively;

(j) One (1) truck hopper unloading to the conveyor belts, identified as EU012AA, permitted in 2012, with one (1) control device, identified as C012AA exhausting through one (1) vent, identified as S-012AA; and 

(k) One (1) truck/rail conveyor transfer tower, identified as EU-012Y, 

permitted in 2012, with one (1) control device, identified as C-012Y, 

exhausting through one (1) vent, identified as S-012Y; 

(3) Two (2) radial stackers to the pile, nominally rated at 3,000 tons per hour each,

permitted in 2012, with particulate emissions controlled by telescoping chutes 

with two (2) fabric filters identified as C-012N and C-012O, exhausting through 

two (2) stacks, identified as S-012N and S-012O.
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(4) Two (2) transfer systems consisting of hoppers and conveyor belts transferring 

feed stock from the piles to classification towers, identified as EU-012R and EU012S, permitted in 2012, with particulate emissions controlled with two (2) dust 

extraction systems or baghouses, identified as C-012R and C-012S, respectively, 

each nominally rated at 6,000 acfm, exhausting through two (2) vents, identified 

as S-012R and S-012S, respectively.

(5) Two (2) dozer activities on the piles, nominally rated at 1,500 tons per hour each, 

identified as EU-012P and EU-012Q, permitted in 2012, with particulate 

emissions controlled by wet suppression. 

(6) Two (2) storage piles with a nominal capacity of 300,000 tons each, identified as 

EU-012W and EU-012X, permitted in 2012, with particulate emissions controlled 

by wet suppression and compaction. 

(B) Two (2) process area solid feedstock conveying, storage, and feed bins (main and 

spare), identified as EU-011A and EU-011B, permitted in 2012, with particulate emissions 

controlled by two (2) baghouses identified as C-011A and C-011B, respectively, each 

nominally rated at 33,760 dscfm, exhausting through two (2) stacks, identified as S-011A 

and S-011B, respectively. [Under 40 CFR 60, Subpart Y, the process area solid 

feedstock conveying, storage, and feed bins (main and spare) are new affected sources.]

(C) One (1) syngas hydrocarbon flare, with a pilot nominally rated at 0.27 MMBtu/hr HHV and 

identified as EU-001, permitted in 2012, exhausting through one (1) tip, identified as S001.

(D) One (1) acid gas flare, with a pilot nominally rated at 0.27 MMBtu/hr HHV and identified 

as EU-002, permitted in 2012, exhausting through one (1) tip, identified as S-002. 

(E) Two (2) Acid Gas Removal (AGR) Unit vents, identified as EU-007A and EU-007B, 

permitted in 2012, with HAP, VOC and CO emissions controlled by two (2) regenerative 

thermal oxidizers (RTO) identified as C-007A and C-007B, respectively, each nominally 

rated at 38.8 MMBtu/hr HHV fuel input, exhausting through two (2) stack, identified as S007A and S-007B.

(F) Two (2) Wet Sulfuric Acid (WSA) plant trains, each nominally rated at 800 stpd H2SO4

and identified as EU-015A and EU-015B, permitted in 2012, with NOx, emissions 

controlled by two (2) selective catalytic reduction (SCR) systems identified as C-015-1A

and C-015-1B, respectively, and particulate, H2SO4, and SO2 emissions controlled by 

two (2) hydrogen peroxide scrubbers identified as C-015-2A and C-015-2B, respectively, 

and particulate and H2SO4 emissions controlled by a high efficiency mist eliminator,

exhausting through two (2) stacks, identified as S-015A and S-015B respectively. These 

emissions units also include two (2) preheat burners (one for each train), each nominally 

rated at 35.00 MMBtu/hr HHV, venting through the same stacks.

(G) Two (2) natural gas-fired auxiliary boilers, nominally rated at 408 MMBtu/hr HHV each, 

identified as EU-005A and EU-005B, permitted in 2012, with NOx emissions controlled by 

ultra-low NOx burners/Flue Gas Recirculation (ULNB/FGR), with both boilers exhausting 
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through one (1) stack, identified as S-005. [Under 40 CFR 60, Subpart Db, the natural 

gas-fired auxiliary boilers are new affected source.]

(H) Five (5) natural gas-fired and SNG fuel-fired gasifier preheat burners, each nominally 

rated with a heat input of 35.00 MMBtu/hr HHV, and identified as EU-008A through EU008E, permitted in 2012, exhausting through five (5) vents, identified as S-008A through 

S-008E, respectively. 

(I) One (1) ZLD-Spray Dryer, permitted in 2012, nominally rated at 5.6 MMBtu/hr with 

particulate emissions controlled by a baghouse identified as C-032, nominally rated at 

2,735 dscfm, and identified as EU-032, with low NOx burners (LNB), exhausting through 

one (1) stack, identified as S-014.

(J) Methanol Tanks:

(1) One (1) Methanol De-Inventory Tank, with a nominal capacity of 700,000 gallons, 

identified as EU-024, permitted in 2012, with emissions controlled by a vapor 

recovery system and exhausting through one (1) vent, identified as S-024. [40 

CFR 60 Subpart Kb]. 

(2) One (1) Fresh Methanol Storage Tank, with a nominal capacity of 332,000 

gallons, identified as EU-025, permitted in 2012, with emissions controlled by a 

vapor recovery system and exhausting through one (1) vent, identified as S-025.

[40 CFR 60 Subpart Kb]

(K) Paved Plant Haul Roads are identified as emissions unit FUG-ROAD. 

(L) Electrical Circuit Breakers (approximately six) containing sulfur hexafluoride (SF6) 

identified as emissions unit FUG-SF6, permitted in 2012, with fugitive GHG emissions 

controlled by full enclosure.

(M) Fugitive Equipment Leaks from the gasification, shift conversion, gas cooling, AGR, CO2

compression, WSA, and methanation are identified as emissions unit FUG and FUGWSA and will be controlled by a Leak Detection and Repair (LDAR) program.

(N) One (1) ZLD Inert Gas Vent identified as EU-033, permitted in 2012, with mercury (Hg) 

emissions controlled by a sulfided carbon adsorbent identified as C-033, exhausting 

through one (1) stack, identified as S-033.

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

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

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

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

(a) Two (2) emergency diesel generators, each nominally rated at 1,341 horsepower, 

identified as EU-009A and EU-009B, permitted in 2012, exhausting through two (2) vents, 

identified as S-009A and S-009B, respectively. [Under 40 CFR 60, Subpart IIII, each, 

emergency diesel fired generator is considered a new affected source.][Under 40 CFR 
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63, Subpart ZZZZ, each, emergency diesel fired generator is considered a new affected 

source.]

(b) Three (3) firewater pump diesel engines, each nominally rated at 575 horsepower and 

identified as EU-010A through EU-010C, permitted in 2012, exhausting through three (3) 

vents, identified as S-010A through S-010C, respectively. [Under 40 CFR 60, Subpart IIII, 

each firewater pump diesel engine is considered a new affected source.][Under 40 CFR 

63, Subpart ZZZZ, each firewater pump diesel engine is considered a new affected 

source.]

(c) Four (4) rod mill eductor vent stacks, permitted in 2012, nominally rated at 180 cfm and 

identified as EU-013A through EU-013D, and exhausting through four (4) vents, identified 

as S-013A through S-013D, respectively. 

(d) One (1) six (6) cell ASU cooling tower, nominally rated with a circulation rate of 54,960

gpm and identified as EU-016A, permitted in 2012, with high efficiency drift/mist 

eliminators, and exhausting through six (6) vents, identified as S-016A-A through S016A-F.

(e) One (1) twenty-four (24) cell main cooling tower, nominally rated with a circulation rate of 

404,700 gpm and identified as EU-016B, permitted in 2012, with high efficiency drift/mist 

eliminators, and exhausting through twenty-four (24) vents, identified as S-016B-A 

through S-016B-X.

(f) Two (2) Air Separation Unit (ASU) molecular sieve regeneration train vents, which each 

vent a nominal 187,000 cubic feet per minute during regenerations, identified as EU017A and EU-017B, permitted in 2012, exhausting through two (2) vents, identified as S017A andS-017B, respectively.

(g) One (1) slag handling storage pad, permitted in 2012, nominally rated at 43 tons per 

hour, identified as EU-034A, with fugitive particulate emissions controlled by wet 

suppression. 

(h) One (1) front-end loader activity on the slag storage pad, permitted in 2012, nominally 

rated at 1,440 tons per day, identified as EU-034C, with fugitive particulate emissions 

controlled by wet suppression. 

(i) Six (6) fixed roof sulfuric acid storage tanks, permitted in 2012, each with a nominal

capacity of 866,500 gallons - identified as EU-027A through EU-027F.

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).
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SECTION B GENERAL CONDITIONS

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

proposed.

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

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

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

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

of Air Quality (OAQ) to this permit.

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

(a) This permit, T147-30464-00060, is issued for a fixed term of five (5) years from the 

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

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

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

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

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

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

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

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

denied.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

IDEM, OAQ may request in writing to determine whether cause exists for modifying, 

revoking and reissuing, or terminating this permit, or to determine compliance with this 

permit. Upon request, the Permittee shall also furnish to IDEM, OAQ copies of records 

required to be kept by this permit.

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

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

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

confidentiality in accordance with 40 CFR 2, Subpart B.

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

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

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

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

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

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

accurate, and complete. 

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

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

submittal.

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

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

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

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

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

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

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

July 1 of each year to:

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

and

United States Environmental Protection Agency, Region V

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

77 West Jackson Boulevard

Chicago, Illinois 60604-3590

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

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

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

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

on or before the date it is due.

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

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

basis of the certification;

(2) The compliance status;

(3) Whether compliance was continuous or intermittent;

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

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

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

require to determine the compliance status of the source.

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

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

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

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

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

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

including the following information on each facility:

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

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

schedule for said items or conditions; and

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

in inventory for quick replacement.

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

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

additional ninety (90) days provided the Permittee notifies:

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

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

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

326 IAC 2-7-1(34).

The Permittee shall implement the PMPs.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

affirmative defense of an emergency is demonstrated through properly signed, 

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

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

the causes of the emergency;

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

minimize levels of emissions that exceeded the emission standards or other 

requirements in this permit;

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

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

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

reasonably should have been discovered; 

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

Compliance and Enforcement Branch), or

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

Compliance and Enforcement Branch)

Facsimile Number: 317-233-6865

Southeast Regional Office phone: (812) 358-2027; fax: (812) 358-2058.

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

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

facsimile to:

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

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

due to the emergency.

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

following:

(A) A description of the emergency;

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

(C) Corrective actions taken.

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

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

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

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

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

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

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

requirement.

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

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

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

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

revised in response to an emergency.

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

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

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

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

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

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

and minimize emissions.

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

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

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

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

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

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

determination that other specifically identified requirements are not applicable. The 

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

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

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

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

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

granted.

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

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

such new requirements.

(b) In addition to the nonapplicability determinations set forth in Section D of this permit, the 

IDEM, OAQ has made the following determinations regarding this source.

(1) 40 CFR Part 63 Subpart JJJJJJ - National Emission Standards for 

Hazardous Air Pollutants for Industrial, Commercial, and Institutional 

Boilers at Area Sources: This source is not subject to 40 CFR Part 63 Subpart 

JJJJJJ because the final EPA rule does not regulate area source boilers that fire 

only natural gas fuel – because they do not emit sufficient urban air toxics to 

require regulation.
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(2) 40 CFR Part 63 Subpart VVVVVV—National Emission Standards for 

Hazardous Air Pollutants for Chemical Manufacturing Area Sources While 

this facility is an area source of HAPs, This source is not subject to 40 CFR Part 

63 Subpart VVVVVV because this rule only regulates facilities that use as 

feedstocks, generates as byproducts, or produces as products any of the 

hazardous air pollutants (HAP) listed in Table 1 to this subpart. This facility does 

not use any of the listed HAPs as a feedstock or generate them as products or 

byproducts.

(3) 40 CFR 60, Subpart D - Standards of Performance for Fossil-Fuel Fired 

Steam Generators for which construction is commenced after August 17, 

1971:

(A) This source is not subject to 40 CFR Part 60, Subpart D because 

Although the auxiliary boilers (EU 005A/B) have a heat input capacity 

greater than 250 MMBtu/hr, each and are steam-generating units, 

pursuant to 40 CFR 60.40b(j) the auxiliary boilers are exempt from the 

requirements of NSPS Subpart D because it is instead subject to the 

requirements of NSPS Subpart Db. 

(B) This source is not subject to 40 CFR Part 60, Subpart D because the 

thermal oxidizers (EUs 007A, B) and the gasifier pre-heat burners (EUs 

008A-E) have a maximum design heat input capacity less than 73 MW 

(250 MMBtu/hr) and they are not steam-generating units.

(4) 40 CFR 60, Subpart Da - Standards of Performance for Electric Utility Steam 

Generating Units for which Construction is Commenced after September 

18, 1978: 

(A) This source is not subject to 40 CFR Part 60, Subpart Da because the 

auxiliary boilers, which can supply steam to an electric generating steam 

turbine are steam-generating units, but they are not considered an 

electric utility unit because they will not supply more than 1/3 of its 

potential electrical output capacity to any utility power distribution 

system. 

(B) This source is not subject to 40 CFR Part 60, Subpart Da because the 

thermal oxidizers (EUs 007A, B) or gasifier pre-heat burners (EUs 008AE) since they do not meet the definition of an electric utility steam 

generating unit. Specifically, the thermal oxidizers and the pre-heat 

burners do not generated steam, and thus are not steam generating 

units.

(5) 40 CFR 60, Subpart Dc Standards of Performance for Small Industrial 

Commercial Institutional Steam Generating Units: This source is not subject 

to 40 CFR Part 60, Subpart Dc because the auxiliary boilers (EU 005A/B) have a 

heat input capacity greater 100 MMBtu/hr and the thermal oxidizers (EUs 007A, 

B) and the burners (EUs 008A-E) are not steam generating units.
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(6) 40 CFR 60, Subpart H - Standards of Performance for Sulfuric Acid Plants: 

This source is not subject to 40 CFR Part 60, Subpart H because the Sulfuric 

Acid Plant, does not meet the rule’s definition of a sulfuric acid production unit.

(7) 40 CFR 60 Subparts VVa, III, NNN, RRR and YYY –Standards of Performance 

that apply to the Synthetic Organic Chemicals Manufacturing Industry. This 

facility does not manufacturer any of the SOCMI chemicals listed in 40 CFR 

60.489.

(8) 40 CFR 60 Subparts J, GGGa, and QQQ – Standards of Performance that apply to 

petroleum refineries. This facility does not process petroleum and therefore does 

not meet the definition of petroleum refinery under these standards.

(9) 40 CFR 60 Subparts KKK and LLL – Standards of Performance that apply to 

natural gas processing facilities. These rules apply to facilities that extract and 

process natural gas liquids from field gas. This facility does not meet the 

definition of a natural gas processing facility under these two rules.

(10) 40 CFR 60, Subpart Kb - Standards of Performance for Volatile Organic 

Liquid Storage Vessels (including Petroleum Liquid Storage Vessels) for 

Which Construction, Reconstruction, or Modification Commenced after 

July 23, 1984: These storage tanks listed below are not subject to 40 CFR Part 

60, Subpart Ka because these tanks do not store organic materials and have 

capacities and maximum true vapor pressure less than 151 cubic meters (m3

) 

and 3.5 kPa.

EU No. Tank ID Tank Capacity 

(Gal)

Max. Vapor 

Pressure Psia

40 CFR 60, 

Supart Kb

Tank Vents to:

023 A Slag Sump 25,284 1.52 No (1) Atmosphere

023 B Slag Sump 25,284 1.52 No (1) Atmosphere

023 C Slag Sump 25,284 1.52 No (1) Atmosphere

023 D Slag Sump 25,284 1.52 No (1) Atmosphere

023 E Slag Sump 25,284 1.52 No (1) Atmosphere

027 A Sulfuric Acid Storage 

Tank

564,016 <0.5 No (1) Atmosphere

027 B Sulfuric Acid Storage 

Tank

564,016 <0.5 No (1) Atmosphere

027 C Sulfuric Acid Storage 

Tank

564,016 <0.5 No (1) Atmosphere

027 D Sulfuric Acid Storage 

Tank

564,016 <0.5 No (1) Atmosphere

027 E Sulfuric Acid Storage 

Tank

564,016 <0.5 No (1) Atmosphere

027 F Sulfuric Acid Storage 

Tank

564,016 <0.5 No (1) Atmosphere

028 A Aqueous Ammonia 

Tank

32,243 5.38 No (1) Atmosphere

028 B Aqueous Ammonia 

Tank

32,243 5.38 No (1) Atmosphere

030 Gasoline Tank 1,175 6.20 No (2) Atmosphere

Note: (1) Tank does not store VOCs.
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 (2) This source is not subject to NSPS Subpart Kb because the tank does not meet the 

capacity criteria.

(11) Proposed Standards of Performance for Greenhouse Gas Emissions for 

New Stationary Sources: Electric Utility Generating Units: The source will 

not be subject to any finalized requirements of the “Standards of Performance for 

Greenhouse Gas Emissions for New Stationary Sources: Electric Utility 

Generating Units” proposed by U.S. EPA on April 13, 2012 (77 Fed. Reg. 

22392), because no electric generating unit at the facility is a steam electric 

generating unit that is constructed for the purpose of supplying more than onethird of its potential electric output capacity and more than 25 MW net-electrical 

output to any utility power distribution system for sale.

(12) 326 IAC 24 Clean Air Interstate Rule (CAIR): The source is not subject to the 

requirements of 326 IAC 24 or the federal final rule issued on August 8, 2011 

limiting the interstate transport of NOx and SO2 (76 Fed. Reg. 48208 et seq).

Pursuant to 326 IAC 24-1(b)(1)(B) and the applicability requirements of 76 Fed. 

Reg. 48208, neither rule applies to a boiler serving a generator that supplies, in 

any calendar year, less than 1/3 of the unit's potential electric output capacity or 

219,000 MW-hours (25 MW), whichever is greater, to any utility power 

distribution system for sale.

(13) 40 CFR Part 72-78 Acid Rain Program: This source is not subject to the 

requirements of 40 CFR Part 72-78 because it does not sell greater than 1/3 its 

generated electricity.

(c) 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.

(d) 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.

(e) Nothing in 326 IAC 2-7-15 or in this permit shall alter or affect the following:

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

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

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

or at the time of this permit's issuance;

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

408(a) of the Clean Air Act; and
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(4) The ability of U.S. EPA to obtain information from the Permittee under Section 

114 of the Clean Air Act.

(f) 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).

(g) 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)]

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

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

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

(a) All terms and conditions of permits established prior to T147-30464-00060 and issued 

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

either:

(1) incorporated as originally stated,

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

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

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

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

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

Air Act and 326 IAC 21 (Acid Deposition Control)

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

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

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

expiration of the source’s existing permit, consistent with 326 IAC 2-7-3 and 326 IAC 2-7-4(a).

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

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

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

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

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

anticipated noncompliance does not stay any condition of this permit. 

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

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

326 IAC 2-7-1(34).

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

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

(1) That this permit contains a material mistake.
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(2) That inaccurate statements were made in establishing the emissions standards 

or other terms or conditions.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Request for renewal shall be submitted to:

Indiana Department of Environmental Management

Permit Administration and Support Section, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

(b) A timely renewal application is one that is:

(1) Submitted at least nine (9) months prior to the date of the expiration of this 

permit; and

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

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

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

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

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

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

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

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

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

additional information identified as being needed to process the application.
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B.19 Permit Amendment or Modification [326 IAC 2-7-11][326 IAC 2-7-12] [40 CFR 72]

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

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

this permit.

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

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

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

Air Act. [40 CFR 72]

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

submitted to:

Indiana Department of Environmental Management

Permit Administration and Support Section, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

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

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

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

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

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

B.20 Permit Revision Under Economic Incentives and Other Programs 

[326 IAC 2-7-5(8)][326 IAC 2-7-12(b)(2)]

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

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

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

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

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

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

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

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

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

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

(a) The Permittee may make any change or changes at the source that are described in 326 

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

met:

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

Act;

(2) Any preconstruction approval required by 326 IAC 2-7-10.5 has been obtained;
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(3) The changes do not result in emissions which exceed the limitations provided in 

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

emissions);

(4) The Permittee notifies the:

Indiana Department of Environmental Management

Permit Administration and Support Section, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

and

United States Environmental Protection Agency, Region V

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

77 West Jackson Boulevard

Chicago, Illinois 60604-3590

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

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

Permittee's copy of this permit; and

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

document all such changes and emission trades that are subject to 

326 IAC 2-7-20(b) or (c). The Permittee shall make such records available, upon 

reasonable request, for public review. 

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

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

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

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

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

required written notification shall include the following:

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

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

(3) Any change in emissions; and 

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

change.

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

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

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

defined by 326 IAC 2-7-1(34).
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(c) Emission Trades [326 IAC 2-7-20(c)]

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

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

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

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

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

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

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

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

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

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

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

326 IAC 10-4.

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

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

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

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

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

assert that the information collected by the agency is confidential and entitled to be treated as 

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

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

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

other change in the permit is necessary.

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

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

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

application shall be submitted to:

Indiana Department of Environmental Management

Permit Administration and Support Section, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

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

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

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

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

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

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

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

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

from IDEM, OAQ the applicable fee is due April 1 of each year.

(b) Except as provided in 326 IAC 2-7-19(e), failure to pay may result in administrative 

enforcement action or revocation of this permit.

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

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

appropriate permit fee. 

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

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

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

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

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

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

Entire Source

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

C.1 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 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 5-1-1 

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

the following, unless otherwise stated in this permit:

(a) Opacity shall not exceed an average of 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 nonoverlapping 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 except as provided in 326 IAC 4-2 or in this permit. 

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

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

C.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 Fugitive Particulate Matter Emission Limitations [326 IAC 6-5]

Pursuant to 326 IAC 6-5 (Fugitive Particulate Matter Emission Limitations), fugitive particulate 

matter emissions shall be controlled according to the attached plan in Attachment G. The 

provisions of 326 IAC 6-5 are not federally enforceable.
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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.

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

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

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

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

thirty-five (35) cubic feet on all facility components, then the notification requirements of 

326 IAC 14-10-3 are mandatory. All demolition projects require notification whether or 

not asbestos is present.

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

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

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

necessary, including, but not limited to the following:

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

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

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

(A) Asbestos removal or demolition start date;

(B) Removal or demolition contractor; or

(C) Waste disposal site.

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

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

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

326 IAC 14-10-3(3).

All required notifications shall be submitted to:

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

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

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

and project supervisors will be used to implement the asbestos removal project. The 
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notifications do not require a certification that meets the requirements of 326 IAC 2-7-6(1)

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

(e) Procedures for Asbestos Emission Control

The Permittee shall comply with the applicable emission control procedures in 

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

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

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

of at least 0.75 cubic feet on all facility components.

(f) Demolition and Renovation

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

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

40 CFR 61.145(a).

(g) Indiana Licensed Asbestos Inspector

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

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

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

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

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

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

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

elsewhere in this permit, shall be submitted to:

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

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

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

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

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

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

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

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

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

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

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

not later than five (5) days prior to the end of the initial forty-five (45) day period.
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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) Unless otherwise specified in this permit, for all monitoring requirements not already 

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

permit issuance or of initial start-up of the emission unit for which the monitoring is 

required, whichever is later, to begin such monitoring. If due to circumstances beyond 

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

installed and operated no later than ninety (90) days after permit issuance or the date of 

initial startup of the emission unit for which the monitoring is required, whichever is later, 

the Permittee may extend the compliance schedule related to the equipment for an 

additional ninety (90) days provided the Permittee notifies:

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

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

justification of the reasons for the inability to meet this date.

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

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

326 IAC 2-7-1(34).

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

monitoring for new emission units or emission units added through a source modification

shall be implemented when operation begins.

(b) 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.

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

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

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

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

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

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

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

calculations, or fulfilling a minimum data availability requirement, if applicable. The owner 
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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 Instrument Specifications [326 IAC 2-1.1-11] [326 IAC 2-7-5(3)] [326 IAC 2-7-6(1)]

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

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

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

twenty percent (20%) of full scale.

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

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

alternative instrument specification will adequately ensure compliance with permit 

conditions requiring the measurement of the parameters.

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

C.13 Emergency Reduction Plans [326 IAC 1-5-2] [326 IAC 1-5-3] 

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

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

safe operating procedures.

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

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

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

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

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

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

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

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

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

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

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

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

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

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

C.14 Risk Management Plan [326 IAC 2-7-5(11)] [40 CFR 68]

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

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

C.15 Response to Excursions or Exceedances [40 CFR 64][326 IAC 3-8][326 IAC 2-7-5] 

[326 IAC 2-7-6]

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

exceedance of a limitation in this permit:

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

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

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

control practices for minimizing excess emissions.

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

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

(1) initial inspection and evaluation;

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

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

or

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

operation. 

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

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

but is not limited to, the following:

(1) monitoring results;

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

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

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

permit.

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

(II) 

(a) CAM Response to excursions or exceedances. 
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(1) Upon detecting an excursion or exceedance, subject to CAM, the 

Permittee shall restore operation of the pollutant-specific emissions unit 

(including the 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. 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). Such actions may include initial 

inspection and evaluation, recording that operations returned to normal 

without operator action (such as through response by a computerized 

distribution control system), or 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.

(2) 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, monitoring 

results, review of operation and maintenance procedures and records, 

and inspection of the control device, associated capture system, and the 

process.

(b) If the Permittee identifies a failure to achieve compliance with an emission 

limitation, subject to CAM, or standard, subject to CAM, for which the approved 

monitoring did not provide an indication of an excursion or exceedance while 

providing valid data, or the results of compliance or performance testing 

document a need to modify the existing indicator ranges or designated 

conditions, the Permittee shall promptly notify the IDEM, OAQ and, if necessary, 

submit a proposed significant permit modification to this permit to address the 

necessary monitoring changes. Such a modification may include, but is not 

limited to, reestablishing indicator ranges or designated conditions, modifying the 

frequency of conducting monitoring and collecting data, or the monitoring of 

additional parameters.

(c) Based on the results of a determination made under paragraph (II)(a)(2) of this 

condition, the EPA or IDEM, OAQ may require the Permittee to develop and 

implement a QIP. The Permittee shall develop and implement a QIP if notified to 

in writing by the EPA or IDEM, OAQ.

(d) Elements of a QIP:

The Permittee shall maintain a written QIP, if required, and have it available for 

inspection. The plan shall conform to 40 CFR 64.8 b (2).

(e) If a QIP is required, the Permittee shall develop and implement a QIP as 

expeditiously as practicable and shall notify the IDEM, OAQ if the period for 

completing the improvements contained in the QIP exceeds 180 days from the 

date on which the need to implement the QIP was determined.

(f) Following implementation of a QIP, upon any subsequent determination pursuant 

to paragraph (II)(a)(2) of this condition the EPA or the IDEM, OAQ may require
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that the Permittee make reasonable changes to the QIP if the QIP is found to 

have:

(1) Failed to address the cause of the control device performance problems; 

or

(2) Failed to provide adequate procedures for correcting control device 

performance problems as expeditiously as practicable in accordance 

with good air pollution control practices for minimizing emissions.

(g) Implementation of a QIP shall not excuse the Permittee from compliance with 

any existing emission limitation or standard, or any existing monitoring, testing, 

reporting or recordkeeping requirement that may apply under federal, state, or 

local law, or any other applicable requirements under the Act.

(h) CAM recordkeeping requirements. 

(1) The Permittee shall maintain records of monitoring data, monitor 

performance data, corrective actions taken, any written quality 

improvement plan required pursuant to paragraph (II)(a)(2) of this 

condition and any activities undertaken to implement a quality 

improvement plan, and other supporting information required to be 

maintained under this condition (such as data used to document the 

adequacy of monitoring, or records of monitoring maintenance or 

corrective actions). Section C - General Record Keeping Requirements 

of this permit contains the Permittee's obligations with regard to the 

records required by this condition.

(2) Instead of paper records, the owner or operator may maintain records on 

alternative media, such as microfilm, computer files, magnetic tape disks, 

or microfiche, provided that the use of such alternative media allows for 

expeditious inspection and review, and does not conflict with other 

applicable recordkeeping requirements.

C.16 Actions Related to Noncompliance Demonstrated by a Stack Test [326 IAC 2-7-5][326 IAC 2-7-6]

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

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

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

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

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

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

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

extend the retesting deadline

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

noncompliant stack tests.

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

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

326 IAC 2-7-1(34).
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Record Keeping and Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-19]

C.17 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]

In accordance with the compliance schedule specified in 326 IAC 2-6-3(b)(1), starting in 2004 and 

every three (3) years thereafter, the Permittee shall submit by July 1 an emission statement 

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

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

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

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

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

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

The statement must be submitted to:

Indiana Department of Environmental Management

Technical Support and Modeling Section, Office of Air Quality

100 North Senate Avenue

MC 61-50 IGCN 1003

Indianapolis, Indiana 46204-2251

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

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

C.18 General Record Keeping Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-6] [326 IAC 2-2]

[326 IAC 2-3]

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

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

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

(AA) All calibration and maintenance records.

(BB) All original strip chart recordings for continuous monitoring

instrumentation.

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

Records of required monitoring information include the following:

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

measurements.

(BB) The dates analyses were performed.

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

(DD) The analytical techniques or methods used.

(EE) The results of such analyses.

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

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

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

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

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

the Commissioner within a reasonable time.
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(b) Unless otherwise specified in this permit, for all record keeping requirements not already 

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

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

keeping.

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

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

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

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

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

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

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

Permittee shall comply with following:

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

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

document and maintain the following records:

(A) A description of the project.

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

source review pollutant could be affected by the project.

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

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

(i) Baseline actual emissions;

(ii) Projected actual emissions;

(iii) Amount of emissions excluded under section 

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

(kk)(2)(A)(iii); and

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

netting calculations, if applicable.

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

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

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

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

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

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

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

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

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

(1)(B) above; and
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(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.19 General Reporting Requirements [326 IAC 2-7-5(3)(C)] [326 IAC 2-1.1-11] [326 IAC 2-2][326 IAC 

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

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

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

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

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

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

an applicable requirement that exists independent of this permit, shall be reported 

according to the schedule stated in the applicable requirement and does not need to be 

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

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

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

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

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

On and after the date by which the Permittee must use monitoring that meets the 

requirements of 40 CFR Part 64 and 326 IAC 3-8, the Permittee shall submit CAM 

reports to the IDEM, OAQ.

A report for monitoring under 40 CFR Part 64 and 326 IAC 3-8 shall include, at a 

minimum, the information required under paragraph (a) of this condition and the following 

information, as applicable:

(1) Summary information on the number, duration and cause (including unknown 

cause, if applicable) of excursions or exceedances, as applicable, and the 

corrective actions taken;

(2) Summary information on the number, duration and cause (including unknown 

cause, if applicable) for monitor downtime incidents (other than downtime 

associated with zero and span or other daily calibration checks, if applicable); 

and

(3) A description of the actions taken to implement a QIP during the reporting period 

as specified in Section C-Response to Excursions or Exceedances. Upon 

completion of a QIP, the owner or operator shall include in the next summary 

report documentation that the implementation of the plan has been completed 

and reduced the likelihood of similar levels of excursions or exceedances 

occurring.

The Permittee may combine the Quarterly Deviation and Compliance Monitoring Report 

and a report pursuant to 40 CFR 64 and 326 IAC 3-8.

(b) The address for report submittal is: 

Indiana Department of Environmental Management
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Permit Reviewer: Josiah Balogun

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

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

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

certified mail receipt, or affixed by the shipper on the private shipping receipt, is on or 

before the date it is due. If the document is submitted by any other means, it shall be 

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

(d) The first report shall cover the period commencing on the date of issuance of this permit 

or the date of initial start-up, whichever is later, and ending on the last day of the 

reporting period. Reporting periods are based on calendar years, unless otherwise 

specified in this permit. For the purpose of this permit, “calendar year” means the twelve 

(12) month period from January 1 to December 31 inclusive.

(e) If the Permittee is required to comply with the recordkeeping provisions of (d) in Section 

C - General Record Keeping Requirements for any “project” (as defined in 326 IAC 2-2-1 

(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:

(1) The annual emissions, in tons per year, from the project identified in (c)(1) in 

Section C- General Record Keeping Requirements exceed the baseline actual 

emissions, as documented and maintained under Section C- General Record 

Keeping Requirements (c)(1)(C)(i), by a significant amount, as defined in 

326 IAC 2-2-1 (xx) and/or 326 IAC 2-3-1 (qq), for that regulated NSR pollutant, 

and

(2) The emissions differ from the preconstruction projection as documented and 

maintained under Section C - General Record Keeping Requirements

(c)(1)(C)(ii). 

(f) The report for project at an existing emissions unit shall be submitted no later than sixty 

(60) days after the end of the year and contain the following:

(1) The name, address, and telephone number of the major stationary source.

(2) The annual emissions calculated in accordance with (d)(1) and (2) in Section C -

General Record Keeping Requirements.

(3) The emissions calculated under the actual-to-projected actual test stated in 

326 IAC 2-2-2(d)(3) and/or 326 IAC 2-3-2(c)(3).

(4) Any other information that the Permittee wishes to include in this report such as 

an explanation as to why the emissions differ from the preconstruction projection.

Reports required in this part shall be submitted to:
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Permit Reviewer: Josiah Balogun

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

(g) The Permittee shall make the information required to be documented and maintained in 

accordance with (c) in Section C- General Record Keeping Requirements available for 

review upon a request for inspection by IDEM, OAQ. The general public may request 

this information from the IDEM, OAQ under 326 IAC 17.1.

Stratospheric Ozone Protection

C.20 Compliance with 40 CFR 82 and 326 IAC 22-1

Pursuant to 40 CFR 82 (Protection of Stratospheric Ozone), Subpart F, except as provided for 

motor vehicle air conditioners in Subpart B, the Permittee shall comply with applicable standards 

for recycling and emissions reduction.
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SECTION D.1 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(A) Incoming solid feedstock materials handling system, transferring material from the 

barge unloading facility and railcar unloading facility to storage piles and day bins, 

consisting of: [Under 40 CFR 60, Subpart Y, the incoming solid feedstock materials 

handling system, transferring material from the barge unloading facility and railcar 

unloading facility to storage piles and day bins are new affected sources.]

(1) One (1) barge unloading to hopper transfer point, permitted in 2012, nominally 

rated at 750 tons per hour, identified as EU-012A, with particulate emissions 

controlled by wet suppression.

(2) The following twenty (20) transfer points, each with particulate emissions 

controlled with a dust extraction system or baghouse nominally rated at 1,500 

acfm: 

(a) One (1) barge unloading from the hopper to the belt, identified as EU012B, permitted in 2012, with one (1) control device, identified as C012B, exhausting through one (1) vent, identified as S-012B; 

(b) Four (4) barge conveyor transfer points, identified as EU-012C 

through EU-012F, permitted in 2012, with four (4) control devices, 

identified as C-012C through C-012F, respectively, exhausting 

through four (4) vents, identified as S-012C through S-012F, 

respectively; 

(c) Two (2) rail unloading to rail hoppers, identified as EU-012G and EU012H, permitted in 2012, with two (2) control devices, identified as C012G through C-012H, respectively, exhausting through two (2) 

vents, identified as S-012G through S-012H, respectively;

(d) Two (2) rail hoppers unloading to the conveyor belts, identified as EU012I and EU-012J, permitted in 2012, with two (2) control devices, 

identified as C-012I and C-012J, respectively, exhausting through two 

(2) vents, identified as S-012I through S-012J, respectively; 

(e) One (1) rail conveyor belt to the stacker, identified as EU-012K, 

permitted in 2012, with one (1) control device, identified as C-012K,

exhausting through one (1) vent, identified as S-012K; 

(f) Two (2) stacker belts to the radial stacker, identified as EU-012L and 

EU-012M, permitted in 2012, with two (2) control devices, identified as 

C-012L and C-012M, respectively, exhausting through two (2) vents, 

identified as S-012L through S-012M, respectively; 
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Emissions Unit Description:

(g) Two (2) classification towers, identified as EU-012T and EU-012U,

permitted in 2012, with two (2) control devices, identified as C-012T 

and C-012U, respectively, exhausting through two (2) vents, identified 

as S-012T through S-012U, respectively; 

(h) One (1) classification tower to a day bin, identified as EU-012V, 

permitted in 2012, with one (1) control device, identified as C-012V, 

exhausting through one (1) vent, identified as S-012V;

(i) Three (3) truck stations unloading to a truck hopper, identified as EU012Z, EU-012AB and EU-012AC, permitted in 2012, with three (3) 

control devices, identified as C-012Z, C-012AB and C-012AC, 

respectively, exhausting through three (3) vents, identified as S-012Z, 

S-012AB and S-012AC, respectively;

(j) One (1) truck hopper unloading to the conveyor belts, identified as 

EU-012AA, permitted in 2012, with one (1) control device, identified as 

C-012AA exhausting through one (1) vent, identified as S-012AA; and 

(k) One (1) truck/rail conveyor transfer tower, identified as EU-012Y, 

permitted in 2012, with one (1) control device, identified as C-012Y, 

exhausting through one (1) vent, identified as S-012Y; 

(3) Two (2) radial stackers to the pile, nominally rated at 3,000 tons per hour 

each, permitted in 2012, with particulate emissions controlled by telescoping 

chutes with two (2) fabric filters identified as C-012N and C-012O, exhausting 

through two (2) stacks, identified as S-012N and S-012O.

(4) Two (2) transfer systems consisting of hoppers and conveyor belts transferring 

feed stock from the piles to classification towers, identified as EU-012R and 

EU-012S, permitted in 2012, with particulate emissions controlled with two (2) 

dust extraction systems or baghouses, identified as C-012R and C-012S, 

respectively, each nominally rated at 6,000 acfm, exhausting through two (2) 

vents, identified as S-012R and S-012S, respectively.

(5) Two (2) dozer activities on the piles, nominally rated at 1,500 tons per hour 

each, identified as EU-012P and EU-012Q, permitted in 2012, with particulate 

emissions controlled by wet suppression. 

(6) Two (2) storage piles with a nominal capacity of 300,000 tons each, identified 

as EU-012W and EU-012X, permitted in 2012, with particulate emissions 

controlled by wet suppression and compaction. 
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Emissions Unit Description:

(B) Two (2) process area solid feedstock conveying, storage, and feed bins (main and 

spare), identified as EU-011A and EU-011B, permitted in 2012, with particulate 

 emissions controlled by two (2) baghouses identified as C-011A and C-011B, 

respectively, each nominally rated at 33,760 dscfm, exhausting through two (2) stacks, 

identified as S-011A and S-011B, respectively. [Under 40 CFR 60, Subpart Y, the 

process area solid feedstock conveying, storage, and feed bins (main and spare) are 

new affected sources.]

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.1.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

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

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

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

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

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

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the 

Incoming Solid feedstock material handling and the Process area solid feedstock conveying 

storage, identified as EU-011A/B and EU-012A-AC shall be as follows:

(a) The PM, PM10 and PM2.5 emissions from the Process Area Solid Feedstock Conveying, 

storage and feedbin (EU-011A/B) operation shall be limited as follows:

(1) The PM, PM10 and PM2.5 emissions from the Process Area Solid Feedstock 

Conveying, storage and feedbin (EU-011A/B) shall be limited through the use of 

a baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf.
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(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

(b) The PM, PM10 and PM2.5 emissions from the barge unloading to hopper transfer point 

(EU-012A) operation shall be controlled by wet suppression with a control efficiency of 

90%.

(c) The PM, PM10 and PM2.5 emissions from the Railcar Unloading to Rail Hoppers (EU012G/H) operation shall be limited as follows:

(1) The PM, PM10 and PM2.5 emissions from the railcar unloading to rail hoppers 

shall be controlled by a wet dust extraction system or the use of a baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf. 

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

(d) The PM, PM10 and PM2.5 emissions from the Barge Unloading from the Hopper to the 

Belt (EU-012B) and Barge Conveyor Transfer Points (EU-012C-F) operation shall be 

limited as follows:

(1) The PM, PM10 and PM2.5 emissions from the Barge Unloading from the Hopper to 

the Belt (EU-012B) and Barge Conveyor Transfer Points (EU-012C-F) shall be 

controlled by a wet dust extraction system or the use of a baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf. 

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

(e) The PM, PM10 and PM2.5 emissions from the Rail Hoppers Unloading to the Belts (EU012I-J) and Rail Conveyor Belt to the Stacker (EU-012K) operation shall be limited as 

follows:

(1) The PM, PM10 and PM2.5 emissions shall be controlled by a wet dust extraction

system or the use of a baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf. 

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

(f) The PM, PM10 and PM2.5 emissions from the Stacker Belt to Radial Stacker (EU-012L-M) 

operation shall be limited as follows:

(1) The PM, PM10 and PM2.5 emissions from the Stacker Belts to the Radial Stacker 

shall be controlled by a wet dust extraction system or the use of a baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf. 

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.
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(g) The PM, PM10 and PM2.5 emissions from the Transfer systems consisting of hoppers and 

conveyor belts transferring feed stock from the piles to classification towers (EU-012R-S); 

Classification towers (EU-012T-U); and Classification tower to a day bin (EU-012V) 

operation shall be limited as follows:

(1) The PM, PM10 and PM2.5 emissions shall be controlled by a wet dust extraction

system or the use of a baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf. 

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

(h) The PM, PM10 and PM2.5 emissions from the Radial Stacker to Pile (EU-012N-O) 

operation shall be limited as follows:

(1) The PM, PM10 and PM2.5 emissions shall be controlled by a Telescoping chute 

with dust collection.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf. 

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

(i) The PM, PM10 and PM2.5 emissions from the Storage Piles (EU-012W/X) operation shall 

be controlled by wet suppression with pile compaction with a control efficiency of 90 %.

(j) The PM, PM10 and PM2.5 emissions from the Dozer Activities (EU-012P/Q) operation 

shall be controlled by wet suppression with pile compaction with a control efficiency of 90 

%.

(k) The PM, PM10 and PM2.5 emissions from the Truck/rail conveyor transfer tower (EU012Y); truck stations unloading to a truck hopper (EU-012Z, AB, and AC); and truck 

hopper unloading to the conveyor Belts (EU-012AA) operation shall be limited as follows:

(1) The PM, PM10 and PM2.5 emissions shall be controlled by an enclosed vent to a 

wet dust extraction system or the use of a baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf. 

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

D.1.5 Preventive Maintenance Plan [326 IAC 1-6-3]

A Preventive Maintenance Plan (PMP) is required for these units and their control devices. 

Section B - Preventive Maintenance Plan contains the Permittee's obligations with regard to the 

preventive maintenance plan required by this condition.

Compliance Determination Requirements

D.1.6 PM, PM10 and PM2.5 Control [326 IAC 2-7-6(6)]

(a) In order to ensure compliance with Condition D.1.4, the baghouses, fabric 

filter/telescoping chutes, wet dust extraction systems, and the wet suppression for 

particulate control shall be in operation and control emissions from the Incoming Solid 
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feedstock material handling and the Process area solid feedstock conveying storage, 

identified as EU-011A/B and EU-012A-AC at all times that the associated emission unit is 

in operation.

(b) In the event that bag failure is observed in a multi-compartment baghouse, if operations 

will continue for ten (10) days or more after the failure is observed before the failed units 

will be repaired or replaced, the Permittee shall promptly notify the IDEM, OAQ of the 

expected date the failed units will be repaired or replaced. The notification shall also 

include the status of the applicable compliance monitoring parameters with respect to 

normal, and the results of any response actions taken up to the time of notification.

(c) In order to ensure compliance with Condition D.1.4(b), wet suppression using water 

sprays or water fogging at the barge unloading hopper (EU-012A) shall be used 

continuously when feedstock is being dropped into the hopper. Additionally, the level of 

the feedstock in the hopper shall not exceed the height of the sides of the hopper. 

Wet suppression is not required when:

- It is raining or snowing at the time of the barge unloading, or

- The ambient air temperature is at or below 32o

F.

(d) In order to ensure compliance with Conditions D.1.4(i) and (j), wet suppression using 

water sprays shall be used daily on active areas of the pile (areas with dozer activity and 

/or new feedstock being loaded). The non-active areas of the pile will have wet 

suppression applications weekly.

Wet suppression treatments of feedstock piles may be delayed until the next day whenever:

- It is raining or snowing at the time of the scheduled treatment, or

- The ambient air temperature is at or below 32o

F 

- The subject area is covered by ice or snow or standing water.

D.1.7 Testing Requirements [326 IAC 2-1.1-11]

(a) In order to demonstrate compliance status with Condition D.1.4(a), not later than one 

hundred and eighty (180) days after initial startup of the second gasifier but not later than 

365 days after the initial startup of the first gasifier, the Permittee shall conduct stack 

testing of the emissions from a representative baghouse controlling the process area 

solid feedstock conveying, storage and feed bins identified as EU-011A/B to determine 

compliance with the PM, PM10, and PM2.5 emissions limitations, utilizing methods as 

approved by the commissioner. This test shall be repeated at least once every five years 

from the date of the most recent valid compliance demonstration. Testing shall be 

conducted in accordance with the provisions of 326 IAC 3-6 (Source Sampling 

Procedures). Section C - Performance Testing contains the Permittee's obligations with 

regard to the performance testing required by this condition. 

(b) In order to demonstrate compliance with Conditions D.1.4(c) - (h) and (k), not later than 

one hundred and eighty (180) days after initial startup of the first gasifier, the Permittee 

shall conduct stack testing of the emissions from a representative dust extraction system

or baghouse or one of each if both are used controlling rail unloading to rail hoppers (EU-
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012G/H); Barge Unloading from the Hopper to the Belt (EU-012B) and Barge Conveyor 

Transfer Points (EU-012C-F); Rail Hoppers Unloading to the Conveyor Belts (EU-012I-J) 

and Rail Conveyor Belt to the Stacker (EU-012K); Stacker Belts to the Radial Stacker 

(EU-012L-M); Transfer Systems Consisting of Hoppers and Conveyor Belts Transferring 

Feedstock from the Piles to Classification Tower (EU-012R-S), Classification Towers

(EU-012T-U), and Classification Tower to a Day Bin (EU-012V); Truck/Rail Conveyor 

Transfer Tower (EU-012Y); the truck stations unloading to a truck hopper (EU-012Z, AB 

and AC); and truck hopper unloading to the conveyor belts (EU-012AA); and one 

representative baghouse controlling the Radial Stackers to the Pile (EU-012N-O) to 

determine compliance with the PM, PM10, and PM2.5 emissions limitations, utilizing 

methods as approved by the commissioner. These tests shall be repeated at least once 

every five years from the date of the most recent valid compliance demonstration. 

Testing shall be conducted in accordance with the provisions of 326 IAC 3-6 (Source 

Sampling Procedures). Section C - Performance Testing contains the Permittee's 

obligations with regard to the performance testing required by this condition. 

D.1.8 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. Operations may continue only if the 

event qualifies as an emergency and the Permittee satisfies the requirements of the 

emergency provisions of this permit (Section B - Emergency Provisions).

(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 process line. Operations may continue only if the event 

qualifies as an emergency and the Permittee satisfies the requirements of the emergency 

provisions of this permit (Section B - Emergency Provisions).

Bag failure can be indicated by a significant drop in the baghouses pressure reading with 

abnormal visible emissions, by an opacity violation, or by other means such as gas temperature, 

flow rate, air infiltration, leaks, dust traces or triboflows.

D.1.9 Wet Dust Extraction System Failure Detection

(a) For a wet dust extraction system 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. Operations may continue only if the 

event qualifies as an emergency and the Permittee satisfies the requirements of the 

emergency provisions of this permit (Section B - Emergency Provisions).

(b) For a wet dust extraction system 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 line. Operations may continue only if the event qualifies 

as an emergency and the Permittee satisfies the requirements of the emergency 

provisions of this permit (Section B - Emergency Provisions).
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Compliance Monitoring Requirements [326 IAC 2-7-5(1)][326 IAC 2-7-6(1)]

D.1.10 Visible Emissions Notations 

(a) Visible emission notations of the Process area solid feedstock conveying storage, and 

feedbins, identified as EU-011A/B, and Incoming Solid feedstock material handling points 

EU-012B-O, R-V, and Y-AC stack exhausts shall be performed once per day 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, at least eighty percent (80%) of the time the process is in operation, 

not counting startup or shut down time. 

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

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

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

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

for that specific process. 

(e) If abnormal emissions are observed, the Permittee shall take reasonable response steps. 

Failure to take response steps shall be considered a deviation from this permit. Section C 

- Response to Excursions or Exceedances contains the Permittee's obligation with regard 

to the reasonable response steps required by this condition.

D.1.11 Parametric Monitoring 

(a) In order to demonstrate the compliance status with Condition D.1.4(a), the Permittee 

shall record the pressure drop across the baghouse used in conjunction with the Process 

area solid feedstock conveying, storage and feed bins (EU-011A/B) operations at least 

once per day when this unit is in operation. When the pressure drop across the 

baghouse is outside the normal range of 1.0 and 5.0 inches of water or a range 

established during the latest stack test, the Permittee shall take reasonable response 

steps. Section C - Response to Excursions or Exceedances contains the Permittee's 

obligation with regard to the reasonable response steps required by this condition. A 

pressure reading that is outside the above mentioned range is not a deviation from this 

permit. Failure to take response steps shall be considered a deviation from this permit.

(b) In order to demonstrate the compliance status with Condition D.1.4(h), the Permittee 

shall record the pressure drop across the Telescoping Chute/Fabric filter used in 

conjunction with the Incoming Solid Feed stock Radial Stackers to the Pile (EU-012N-O)

operations at least once per day when these unit is in operation. When the pressure drop 

across the baghouse is outside the normal range of 1.0 and 5.0 inches of water or a 

range established during the latest stack test, the Permittee shall take reasonable 

response steps. Section C - Response to Excursions or Exceedances contains the 

Permittee's obligation with regard to the reasonable response steps required by this 

condition. A pressure reading that is outside the above mentioned range is not a 

deviation from this permit. Failure to take response steps shall be considered a deviation 

from this permit.

(c) In order to demonstrate the compliance status with Conditions D.1.4(c), (d), (e), (f) and 

(k), the Permittee shall record the flow rate of the scrubbing water used in conjunction 
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with each wet dust extraction system, if one is used, at least once per day when the 

Incoming Solid Feed stock material handling emission units, identified as EU-012 (B-M, 

T-V, Y- AC) are in operation. When for any one reading, the water flow rate is below 1.5 

gpm, the Permittee shall take reasonable response steps. If a baghouse is used, the 

Permittee shall record the pressure drop across the baghouse at least once a day when 

the unit is in operation. When the pressure drop across the baghouse is outside the 

normal range of 1.0 and 5.0 inches of water or a range established during the latest stack 

test, the Permittee shall take reasonable response steps. Failure to take response steps 

shall be considered a deviation of this permit. Section C - Response to Excursions or 

Exceedances contains the Permittee's obligation with regard to the reasonable response 

steps required by this condition.

(d) In order to demonstrate the compliance status with Condition D.1.4(g), the Permittee 

shall record the flow rate of the scrubbing water used in conjunction with the wet dust 

extraction system, if one is used, at least once per day when the Incoming Solid Feed 

stock material handling emission units, identified as EU-012 (R-S) are in operation. 

When for any one reading, the water flow rate is below 5 gpm, the Permittee shall take 

reasonable response steps. If a baghouse is used, the Permittee shall record the 

pressure drop across the baghouse at least once a day when the unit is in operation. 

When the pressure drop across the baghouse is outside the normal range of 1.0 and 5.0 

inches of water or a range established during the latest stack test, the Permittee shall 

take reasonable response steps. Failure to take response steps shall be considered a 

deviation of this permit. Section C - Response to Excursions or Exceedances contains 

the Permittee's obligation with regard to the reasonable response steps required by this 

condition.

The instruments used for determining the pressure or flow rate shall comply with Section C -

Instrument Specifications, of this permit, shall be subject to approval by IDEM, OAQ, and shall be 

calibrated or replaced at least once every six (6) months or other time period specified by the 

manufacturer. The Permittee shall maintain records of the manufacturer specifications, if used.

D.1.12 Ambient Temperature Monitoring

To demonstrate the compliance status with Conditions D.1.6(c) and (d), the Permittee shall 

maintain an ambient temperature monitor when ambient temperatures may drop below 32o

F.

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

D.1.13 Record Keeping Requirements

(a) To document the compliance status with Condition D.1.10 - Visible Emission Notation, 

the Permittee shall maintain a daily record of the visible emission notations from the 

Process area solid feedstock conveying, storage and feedbins, identified as EU-011A/B

and Incoming Solid feedstock material handling points EU-012B-O, R-V, and Y--AC. The 

Permittee shall include in its daily record when a visible emission notation is not taken 

and the reason for the lack of visible emission notation, (e.g. the process did not operate 

that day).

(b) To document the compliance status with Conditions D.1.11(a) and (b) - Parametric 

Monitoring, the Permittee shall maintain a daily record of the pressure drop across the 

baghouse controlling the Process area solid feedstock conveying storage, and feedbins 
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and across the fabric filter used in conjunction with the Incoming Solid Feed stock Radial 

Stackers to the Pile (EU-012N-O) when venting to the atmosphere. 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) To document the compliance status with Conditions D.1.11(c) and (d) - Parametric 

Monitoring, the Permittee shall maintain a daily record of the flow rate of the scrubbing 

water of each wet dust extractor and a daily record of the pressure drop across each 

baghouse controlling the Incoming Solid Feed stock enclosed handling, identified as EU012 (B-M), EU-012 (R-V) and (EU-012Y-AC) when venting to the atmosphere. The 

Permittee shall include in its daily record when a flow rate of the scrubbing water or the 

pressure drop reading is not taken and the reason for the lack of a reading, (e.g. the 

process did not operate that day).

(d) To document the compliance status with Conditions D.1.4(b) - PM, PM10 and PM2.5 PSD 

BACT and D.1.6(c) - PM, PM10 and PM2.5 Control, the permittee shall maintain the 

following daily records:

- The date of each unloading operation.

- A log indicating whether or not water sprays were used and whether or not the 

level in the hopper ever exceeded the height of the sides of the barge unloading 

hopper during each unloading.

If a treatment is not required and not performed pursuant to D.1.6(c), records shall be 

maintained documenting the reason (i.e.: the ambient temperature or precipitation).

(e) To document the compliance status with Conditions D.1.4(i), and (j) - PM, PM10 and 

PM2.5 PSD BACT and D.1.6(d) - PM, PM10 and PM2.5 Control, the Permittee shall 

maintain the following daily records :

- The date and approximate time of each feedstock pile watering treatment.

- If a treatment is not required and not performed pursuant to D.1.6(d), records 

shall be maintained documenting the reason (i.e.: the ambient temperature, 

precipitation, or the subject area is covered by ice or snow or standing water.

(e) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition.
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SECTION D.2 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(C) One (1) syngas hydrocarbon flare, with a pilot nominally rated at 0.27 MMBtu/hr HHV 

and identified as EU-001, permitted in 2012, exhausting through one (1) tip, identified 

as S-001.

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.2.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

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

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

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

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

D.2.4 PM, PM10 and PM2.5, CO, SO2, NOx and GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Syngas 

Hydrocarbon Flare, identified as EU-001 shall be as follows:

(1) The PM, PM10 and PM2.5 emissions from the Syngas Hydrocarbon Flare, identified as 

(EU-001) shall be limited as follows:

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

PM, PM10 and PM2.5 emissions during startups, shutdowns and other flaring 

events.

During a planned shutdown of a gasifier, the permittee shall route the contents of 

each gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during 

initial depressurization to one of the Wet Sulfuric Acid (WSA) plants. 
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The permittee shall reduce gasifier feed rates such that all syngas can be 

processed through one gas treatment train prior to a scheduled gas treatment 

train outage. This limits the amount of syngas that will have to be sent to the 

syngas hydrocarbon flare. 

The permittee shall have written procedures for the above operations and the 

permittee shall train the operators on these procedures.

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented.

B. Comply with the following flare best practices: 

a. Flares shall be designed for and operated with no visible emissions, 

except for periods not to exceed 5 minutes during any 2 consecutive 

hours.

b. Flares shall be operated with a flame present at all times.

c. Flares shall be continuously monitored to assure the presence of a pilot 

flame with a thermocouple, infrared monitor, or other approved device.

 

C. The Syngas Hydrocarbon Flare PM/PM10 emissions shall not exceed 3.21 

lb/hour during startup or shutdown, based on a 3-hour average.

D. The Syngas Hydrocarbon Flare PM2.5 emissions shall not exceed 3.01 lb/hour

during startup or shutdown, based on a 3-hour average.

(2) The CO emissions from the Syngas Hydrocarbon Flare, identified as (EU-001) shall be

limited as follows:

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

CO emissions during startups, shutdowns and other flaring events.

During a planned shutdown of a gasifier, the permittee shall route the contents of 

each gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during 

initial depressurization to one of the Wet Sulfuric Acid (WSA) plants. 

The permittee shall reduce gasifier feed rates such that all syngas can be 

processed through one gas treatment train prior to a scheduled gas treatment 

train outage. This limits the amount of syngas that will have to be sent to the 

syngas hydrocarbon flare. 

The permittee shall have written procedures for the above operations and the 

permittee shall train the operators on these procedures.

The Permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented.
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B. Comply with the following flare best practices: 

a. Flares shall be designed for and operated with no visible emissions, 

except for periods not to exceed 5 minutes during any 2 consecutive 

hours.

b. Flares shall be operated with a flame present at all times.

c. Flares shall be continuously monitored to assure the presence of a pilot 

flame with a thermocouple, infrared monitor, or other approved device. 

C. The Syngas Hydrocarbon Flare CO emissions shall not exceed 172.4 lbs/hour 

during startup or shutdown based on a 3 hour average.

(3) The SO2 emissions from the Syngas Hydrocarbon Flare, identified as (EU-001) shall be

limited as follows:

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

SO2 emissions during startups, shutdowns, and other flaring events.

The permittee will use methanol, rather than coal or pet coke, as the feedstock in 

each gasifier during startup conditions requiring syngas flaring, thereby reducing 

emissions of sulfur dioxide at the syngas hydrocarbon flare.

During a planned shutdown of a gasifier, the permittee shall route the contents of 

each gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during 

initial depressurization to one of the Wet Sulfuric Acid (WSA) plants. 

The permittee shall reduce gasifier feed rates such that all syngas can be 

processed through one gas treatment train prior to a scheduled gas treatment 

train outage. This limits the amount of syngas that will have to be sent to the 

syngas hydrocarbon flare. 

The permittee shall have written procedures for the above operations and the 

permittee shall train the operators on these procedures.

 

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented

The SO2 emissions from the Syngas Hydrocarbon Flare during a shutdown event 

shall not exceed 85.21 lb/hr based on a 3-hour average and shall not exceed 

255.6 lbs per 24 hours and shall not exceed 1.92 tons per twelve (12) 

consecutive month period with compliance determined at the end of each month. 

The SO2 emissions from the Syngas Hydrocarbon Flare shall not exceed 0.35 

lb/hour during startup, based on a 3-hour average and shall not exceed 0.05 tons 

per twelve (12) consecutive month period with compliance determined at the end 

of each month.

(4) The NOx emissions from the Syngas Hydrocarbon Flare, identified as (EU-001) shall be

limited as follows:

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

NOx emissions during startups, shutdowns, and other flaring events.
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During a planned shutdown of a gasifier, the permittee shall route the contents of 

each gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during 

initial depressurization to one of the Wet Sulfuric Acid (WSA) plants. 

The permittee shall reduce gasifier feed rates such that all syngas can be 

processed through one gas treatment train prior to a scheduled gas treatment 

train outage. This limits the amount of syngas that will have to be sent to the 

syngas hydrocarbon flare. 

In addition, the permittee shall have written procedures for the above operations 

and the permittee shall train the operators on these procedures.

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented.

B. The Syngas Hydrocarbon Flare NOx emissions shall not exceed 43.09 lbs/hour 

during startup or shutdown based on a 3 hour average.

(5) The GHGs emissions from the Syngas Hydrocarbon Flare, identified as (EU-001) shall 

be limited as follows:

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

GHG emissions during startups, shutdowns, and other flaring events.

During a planned shutdown of a gasifier, the permittee shall route the contents of 

each gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during 

initial depressurization to one of the Wet Sulfuric Acid (WSA) plants. 

The permittee shall reduce gasifier feed rates such that all syngas can be 

processed through one gas treatment train prior to a scheduled gas treatment 

train outage. This limits the amount of syngas that will have to be sent to the 

syngas hydrocarbon flare. 

In addition, the permittee shall have written procedures for the above operations 

and the permittee shall train the operators on these procedures.

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented.

D.2.5 Hazardous Air Pollutants (HAPs) Minor Limits

The single HAP and total HAP from the syngas hydrocarbon flare identified as EU-001 shall be 

limited by compliance with the SO2 emission limit is Condition D.2.4(3) and, combined with the 

potential to emit HAP emissions from all other emission units, this requirement will limit the 

potential to emit from this source to less than ten (10) tons per year of any individual HAP and 

twenty-five (25) tons per year of any combination of HAPs and make the source an area source 

of HAPs.
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D.2.6 Preventive Maintenance Plan [326 IAC 1-6-3]

A Preventive Maintenance Plan (PMP) is required for this unit and its control device. Section B -

Preventive Maintenance Plan contains the Permittee's obligations with regard to the preventive 

maintenance plan required by this condition.

Compliance Determination Requirements

D.2.7 Flare Pilot Flame

In order to ensure compliance with Condition D.2.4, the flare must be operated with a flame 

present at all times when the Syngas Hydrocarbon Flare is in operation and at least one gasifier 

is in operation or in startup or shutdown. Only natural gas or SNG shall be used in the pilot for the 

Syngas Hydrocarbon Flare (EU-001).

D.2.8 Compliance Determination Requirements [326 IAC 2-2-3]

The following equations shall be used for determining compliance status with the emission limits 

in Condition D.2.4:

a. For PM, PM10, PM2.5, and NOx:

E = F x HHV x EF + PE

Where:

E = Pollutant emissions (lb/hour)

F = Flow of flared gases (MMscf/hour)

HHVstartup = 124.5 Btu/scf, or other value determined by testing

HHVshutdown = 118.6 Btu/scf, or other value determined by testing

EFPM/PM10 = 0.0075 lb/MMBtu

EFPM2.5 = 0.0070 lb/MMBtu 

EFNOx = 0.010 lb/MMBtu

PEPM/PM10/PM2.5 = 0.0020 lb/hr from pilot

PENOx = 0.053 lb/hr from pilot

b. For CO:

E = F x (1 lb mole/379.49 scf) x (%CO/100) x (28.01 lb/lb mole) x (1 – (DRE/100)) + PE

Where:

E = lb/hr CO

F = Flow of flared gases (scf/hour)
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%COstartup = Percent CO in flared gas during startup = 13.5% or other value determined 

 by testing

%COshutdown = Percent CO in flared gas during shutdown = 20.4% or other value 

 determined by testing

DRE = Destruction Removal Efficiency = 99.5%

PE = 0.013 lb/hr CO from pilot flame

c. For SO2:

E = F x EF + PE

Where:

F = Flow of flared gases (scf/hour)

EFstartup = 0.10 x 10-6 lbs/scf

EFshutdown = 0.001264 lbs/scf

PE = 0.0002 lb/hr SO2 from Pilot

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

D.2.9 Flare Parametric Monitoring

(a) To demonstrate the compliance status with Conditions D.2.4:

(1) The Permittee shall continuously monitor the presence of the flare pilot flame 

using a thermocouple or any other equivalent device to detect the presence of a 

flame. For the purpose of this condition, continuous means no less than once 

per minute; and

(2) The Permittee shall determine the flare visible emissions by Reference Method 

22 once per day.

(b) The Permittee shall continuously monitor the flow rate, in CFM, of the total gas flow to the 

flare, including syngas and natural gas or SNG. 

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

D.2.10 Record Keeping Requirements

(a) To document the compliance status with Conditions D.2.4:

(1) The Permittee shall maintain records of the monitoring required by Condition 

D.2.8(a); and

(2) The Permittee shall maintain records of the daily flare visible emissions checks 

by Reference Method 22
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(b) To document the compliance status with Condition D.2.9(b) and Condition D.2.8 –

Compliance Determination Requirements, the Permittee shall maintain records of the 

following:

(1) Monthly records of flow rate, in cubic feet per minute (CFM), of the total gas flow 

to the flare, including syngas and natural gas or SNG.

(c) To document the compliance status with Condition D.2.4, the Permittee shall maintain 

records of the date, time, and total number of minutes for each startup and shutdown

flaring event.

(d) To document the compliance status with Conditions D.2.4(1)(A), (2)(A), (3)(A), (4)(A), 

and (5)(A), the Permittee shall maintain a record of: 

i. The feedstock used during each gasifier startup that requires flaring.

ii. The routing of gas whenever a gasifier is depressurized during a planned gasifier 

shutdown.

iii. The operating rate of each gasifier prior to and during a planned shutdown of a gas 

treatment train.

In addition, the Permittee shall have available for inspection copies of the procedures 

used to implement the measures in the FMP and records of training sessions on those 

procedures. The Permittee shall have a written record of each root cause analysis, the 

actions recommended from the analysis, and documentation on the implementation of 

any corrective actions stemming from the root cause analyses under the FMP.

(e) To document the compliance status with the emission limits in Condition D.2.4, the 

Permittee shall maintain monthly records of the PM, PM10, PM2.5 , NOx, CO, and SO2

emissions.

(f) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition.
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SECTION D.3 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(D) One (1) acid gas flare, with a pilot nominally rated at 0.27 MMBtu/hr HHV and 

identified as EU-002, permitted in 2012, exhausting through one (1) tip, identified as S002. 

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.3.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

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

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

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

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

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

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Acid 

Gas Flare, identified as EU-002 shall be as follows:

(1) The PM, PM10 and PM2.5 emissions from the Acid Gas Flare, identified as (EU-002) shall 

be limited as follows:

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

emissions during flaring events.

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented.

B. Comply with the following flare best practices: 
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a. Flares shall be designed for and operated with no visible emissions, 

except for periods not to exceed 5 minutes during any 2 consecutive 

hours.

b. Flares shall be operated with a flame present at all times.

c. Flares shall be continuously monitored to assure the presence of a pilot 

flame with a thermocouple, infrared monitor, or other approved device. 

(2) The CO emissions from the Acid Gas Flare, identified as (EU-002) shall be limited as 

follows:

A The permittee shall comply with the following Flare Minimization Plan to reduce 

emissions during flaring events.

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented.

B Comply with the following flare best practices: 

a. Flares shall be designed for and operated with no visible emissions, 

except for periods not to exceed 5 minutes during any 2 consecutive 

hours.

b. Flares shall be operated with a flame present at all times.

c. Flares shall be continuously monitored to assure the presence of a pilot 

flame with a thermocouple, infrared monitor, or other approved device. 

(3) The SO2 emissions from the Acid Gas Flare, identified as (EU-002) shall be limited as 

follows:

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

emissions during flaring events.

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented.

(4) The NOx emissions from the Acid Gas Flare, identified as (EU-002) shall be limited as 

follows:

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

emissions during flaring events.

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented.
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(5) The GHG emissions from the Acid Gas Flare, identified as (EU-002) shall be:

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

emissions during flaring events.

 The permittee shall investigate the “root cause” of malfunction events that 

cause gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented.

D.3.5 Preventive Maintenance Plan [326 IAC 1-6-3]

A Preventive Maintenance Plan (PMP) is required for this unit and its control device. Section B -

Preventive Maintenance Plan contains the Permittee's obligations with regard to the preventive 

maintenance plan required by this condition.

Compliance Determination Requirements

D.3.6 Flare Pilot Flame

In order to ensure compliance with Condition D.3.4, the flare must be operated with a flame 

present at all times when the Acid Gas Flare, identified as EU-002 is in operation and at least one 

gasifier is in operation or in startup or shutdown. Only natural gas or SNG shall be used in the 

pilot for the Acid gas Flare (EU-002).

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

D.3.7 Flare Parametric Monitoring

To demonstrate the compliance status with Condition D.3.4:

1. The Permittee shall continuously monitor the presence of the flare pilot flame using a 

thermocouple or any other equivalent device to detect the presence of a flame. For the 

purpose of this condition, continuous means no less than once per minute; and

2. The Permittee shall determine the flare visible emissions by Reference Method 22 once 

per day.

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

D.3.8 Record Keeping Requirements

(a) To document the compliance status with Condition D.3.4:

(1) The Permittee shall maintain records of the monitoring required by Condition 

D.3.7; and

(2) The Permittee shall maintain records of the daily flare visible emissions checks

by Reference Method 22.

(b) To document the compliance status with Conditions D.3.4(1)(A), (2)(A), (3)(A), (4)(A), 

and (5)(A), the Permittee shall maintain a record of, and have available for inspection, 

copies of the procedures used to implement the measures in the FMP and records of 

training sessions on those procedures. The Permittee shall have a written record of each 

root cause analysis, the actions recommended from the analysis, and documentation on 
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the implementation of any corrective actions stemming from the root cause analyses 

under the FMP.

(c) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition.
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SECTION D.4 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(E) Two (2) Acid Gas Removal (AGR) Unit vents, identified as EU-007A and EU-007B,

permitted in 2012, with HAPs, VOC and CO emissions controlled by two (2) 

regenerative thermal oxidizers (RTO) identified as C-007A and C-007B, respectively, 

each nominally rated at 38.8 MMBtu/hr HHV fuel input, exhausting through two (2) 

stacks, identified as S-007A and S-007B.

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.4.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

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

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

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

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

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

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Acid 

Gas Removal (AGR) Unit vents, identified as EU-007A/B shall be as follows:

The PM, PM10 and PM2.5 emissions from operation of the AGR Regenerative Thermal Oxidizers

(C-007A/B) shall not exceed 0.29 pounds per hour, each and good combustion practices shall be 

used. Only natural gas or SNG shall be used in the AGR Regenerative Thermal Oxidizers (C007A/B). 
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D.4.5 CO PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Acid 

Gas Removal (AGR) Unit vents, identified as EU-007A/B shall be as follows:

The CO emissions shall be controlled by the use of regenerative thermal oxidizer (RTO) and the 

CO emissions shall not exceed 48 pounds per hour for the Acid Gas Removal Unit Vents (EU007A/B), each, based on a 3-hour average.

D.4.6 SO2 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Acid 

Gas Removal (AGR) Unit vents, identified as EU-007A/B shall be as follows:

The SO2 emissions shall be reduced by the use of a Rectisol process and SO2 emissions shall 

not exceed 3.17 pounds per hour for each Acid Gas Removal Unit Vent (EU-007A/B), based on a 

3-hour average.

D.4.7 NOx PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Acid 

Gas Removal (AGR) Unit vents, identified as EU-007A/B shall be as follows:

The NOx emissions from the Acid Gas Removal Unit Vents (EU-007A/B) shall be controlled by 

Low NOx Performance with natural gas injection and the NOx emissions shall not exceed 1.98

pounds per hour from each AGR/RTO unit based on a 3-hour average. 

D.4.8 VOC Best Available Control Technology (BACT) [326 IAC 8-1-6]

Pursuant to 326 IAC 8-1-6 (New Facilities, General Reduction Requirements), the Best Available 

Control Technology (BACT) for the for the Acid Gas Recovery Unit vents (EU-007A/B).shall be as 

follows:

The VOC emissions from the Acid Gas Recovery Unit vents (EU-007A/B) shall be controlled 

through the use of a Regenerative Thermal Oxidizer on each vent and the VOC emissions for

each vent shall not exceed 1.05 pounds per hour based on a 3-hour average.

D.4.9 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Acid 

Gas Removal (AGR/RTO) Unit vents, identified as EU-007A/B shall be as follows:

(a) The CO2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed 

4,690,000 tons of CO2 during the first 12 months of operation.

(b) The CO2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed 

6,430,000 tons of CO2 during the second 12 months of operation.

(c) The CO2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed 

1, 290,000 tons of CO2 during the third 12 months of operation.
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(d) Thereafter, the CO2 emissions from the Acid Gas Recovery (AGR) Vents shall not 

exceed 1,290,000 tons CO2 per twelve (12) consecutive month period with compliance 

determined at the end of each month.

D.4.10 Alternate Emissions Limitation During Gasifier Startup Flaring

During startup flaring of the gasifiers, the NOx emissions from the AGR units (EU-007A/B) shall 

be limited to 2.97 lbs per hour, combined, from both AGR units (EU-007A/B) and shall be 

applicable beginning when a starting up gasifier first begins to flare generated syngas and ends 

when the generated syngas begins diversion from the flare to the downstream AGR/WSA trains. 

D.4.11 Hazardous Air Pollutants (HAPs) Minor Limits

(a) The Acid Gas Recovery Units, identified as EU-007A/B, Methanol and Carbonyl Sulfide 

(COS) emissions shall, each 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 Acid Gas Recovery Units, identified as EU-007A/B, combined Hazardous Air 

Pollutants (HAPs) emissions shall be limited to less than 17.0 tons per twelve (12) 

consecutive month period, with compliance determined at the end of each month.

(c) The methanol emissions from the AGRs shall be calculated by the following equation:

Methanol emissions = Vent Flow x Methanol Emissions Factor

Where:

Vent Flow = Total AGR vent flow to the thermal oxidizers (million SCF/period) 

to be monitored continuously by the Permittee.

Methanol Emissions Factor = Methanol emitted per million standard cubic feet of vent 

gas to the thermal oxidizer (lbs methanol/MMSCF of vent gas) as determined in the most 

recent compliance stack test of the oxidizer. Until the initial compliance stack testing is 

performed, the engineering estimate of 0.127 lbs methanol emitted/million SCF of vent 

flow shall be used.

(d) The carbonyl sulfide emissions from the AGRs shall be calculated by the following 

equation:

Carbonyl Sulfide emissions = Vent Flow x Carbonyl Sulfide Emissions Factor 

Where:

Vent Flow = Total AGR vent flow to the thermal oxidizers (million SCF/period) 

to be monitored continuously by the Permittee.

Carbonyl Sulfide Emissions Factor = Pounds of Carbonyl Sulfide emitted per million 

standard cubic feet of vent gas to the thermal oxidizer (lbs. COS/MMSCF of vent gas) as 

determined in the most recent compliance stack test of the oxidizer. Until the initial 
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compliance stack testing is performed, the engineering estimate of 0.0062 lbs. carbonyl 

sulfide emitted/million SCF vent gas shall be used.

(e) Total HAP emissions from the AGRs shall be calculated by the following equations:

When there is no AGR vent flow and RTO is in Standby Mode: 

Total HAPs Emissions = RTO Fuel Flow in MMBtu/hr. x HAP Emission Factor of 0.00185 

lb HAP/MMBtu

When there is AGR vent flow to the RTO:

Total HAP emissions = Methanol Emissions + Carbonyl Sulfide Emissions + 

Other HAPs Emissions

Where:

Methanol Emissions = Methanol Emissions as quantified in D.4.11(c)

Carbonyl Sulfide Emissions = Carbonyl Sulfide Emissions as quantified in 

D.4.11(d) 

Other HAPs Emissions are calculated by the following formula:

Other HAPs Emissions (with AGR vent flow) = Vent Flow x (Hexane Emissions Factor + 

Formaldehyde Emissions Factor + Additional HAPs emissions factor)

Where:

Vent Flow = Total AGR vent flow to the thermal oxidizers (million SCF/period) to be 

monitored continuously by the Permittee.

Hexane Emissions factor = Pounds of Hexane emitted per million standard cubic feet of 

vent gas to the thermal oxidizer (lbs. hexane/MMSCF of vent gas) as determined in the 

most recent compliance stack test of the oxidizer. If no compliance stack test has been 

performed, the engineering estimate of 0.0054 lbs. hexane emitted/million SCF vent gas 

shall be used.

Formaldehyde Emissions factor = Pounds of Formaldehyde emitted per million standard 

cubic feet of vent gas to the thermal oxidizer (lbs. formaldehyde/MMSCF of vent gas) as 

determined in the most recent compliance stack test of the oxidizer. If no compliance 

stack test has been performed, the engineering estimate of 0.00023 lbs. formaldehyde 

emitted/million SCF vent gas shall be used. 

Additional HAPS Emissions factor = Pounds of any other HAP besides methanol, 

carbonyl sulfide, hexane, or formaldehyde emitted per million standard cubic feet of vent 

gas to the thermal oxidizer (lbs. HAP/MMSCF of vent gas) as determined in the most 

recent compliance stack test of the oxidizer. If no compliance stack test has been 
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performed, the engineering estimate of 0.00004 lbs. additional HAPs emitted/million SCF 

vent gas shall be used.

Compliance with the above limits 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 any individual HAP and twenty-five (25) tons per year of any combination of HAPs and 

make the source an area source of HAPs. 

 

D.4.12 Preventive Maintenance Plan [326 IAC 1-6-3]

A Preventive Maintenance Plan (PMP) is required for these units and control devices. Section B -

Preventive Maintenance Plan contains the Permittee's obligations with regard to the preventive 

maintenance plan required by this condition.

Compliance Determination Requirements

D.4.13 PM, PM10 and PM2.5 Calculations [326 IAC 2-2]

(a) In order to ensure compliance with Condition D.4.4 - PM, PM10 and PM2.5 PSD BACT, 

the Permittee shall only use natural gas or SNG in the AGR Regenerative Thermal 

Oxidizers (C-007A/B). 

(b) The following equation shall be used for determining compliance status with Condition 

D.4.4 - PM, PM10 and PM2.5 PSD BACT:

E = FNG x HHV x EF

Where:

E = PM, PM10 and PM2.5 emissions, pounds/hour

FNG = Flow of natural gas or SNG to RTO, MMscf/hour

HHV = higher heating value for the fuel combusted

EF = 0.0075 lb PM, PM10 and PM2.5 /MMBtu

D.4.14 Nitrogen Oxide Control

(a) In order to ensure compliance with Conditions D.4.7 - NOx PSD BACT and D.4.10 -

Alternate Emissions Limitation During Gasifier Startup Flaring, the Low NOx burner and 

natural gas injection system shall be in operation and control emissions from the RTO at 

all times that the AGR is venting.

(b) The following equation shall be used for determining compliance status with Condition 

D.4.10 - Alternate Emissions Limitation During Gasifier Startup Flaring:

E = Fng * HHV * EF

Where:

E = Pollutant emissions (lb/hr)

Fng = flow of NG or SNG to RTO (mmscf/hr)
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HHV = higher heating value of the fuel combusted, in Btu/scf

EFNOx = 0.05 lb/MMBtu until the initial stack test. Thereafter, use factor 

(lb/MMBtu) developed from most recent stack test

D.4.15 Sulfur dioxide Control and Calculations

(a) In order to ensure compliance with Condition D.4.6, the Rectisol system shall be in 

operation and control emissions from the Acid Gas Removal (AGR) Unit vents at all times 

that the AGR is venting. The sulfur content of the vent stream to one of the RTOs shall 

be sampled monthly in any month in which there are at least twenty-four (24) hours of 

venting to one of the RTOs.

(b) The following equation shall be used for determining compliance status with the SO2 limit 

for the Acid Gas Removal (AGR) Unit vents (EU-007A/B) in Condition D.4.6:

ESO2 = FAGR x (Sppm/1,000,000) x (1 lb mole/379.49scf) x (64.06 lbs SO2/lb mole sulfur) x 

(DRE/100) + FNG x EF

Where:

ESO2 = SO2 emissions, pounds/hour

FAGR = Vent flow from AGR to RTO, scf/hour

DRE = Destruction Removal Efficiency of sulfur to SO2 = 98%

FNG = Flow of natural gas or SNG to RTO, MMscf/hour

EF = 0.6 lb SO2/MMscf

Sppm = Molar concentration of all sulfur compounds in the vent stream from the 

 AGR to the RTO in ppm, determined during the most recent monthly 

 sampling event

D.4.16 Greenhouse Gases (GHGs) Calculations

To determine the compliance status with Condition D.4.9, the following equation shall be used to 

determine the CO2 emission limit for the Acid Gas Removal (AGR/RTO) Unit vents (EU-007A/B):

ECO2 = FNG x HHV x EF CO2 x (ton/2000 lb) + FAGR x (1 lb mole/379.49 scf) * ((%CO2 + ((%CO + 

%Cother) x (DRE/100)))/100) x (44.01 lb CO2/lb mole) x (ton/2000lb) 

Where:

ECO2 = Total CO2 emissions, tons/month

FNG = flow of natural gas or SNG to RTO, MMscf/month

HHV = higher heating value for the fuel combusted, in Btu/scf

EF CO2 = 116.89 lb CO2/MMBtu 

FAGR = Vent flow from AGR to RTO, scf/month
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%CO2 = 99% or other value determined by sampling

%CO = 1.0% or other value determined by sampling

%Cother = 0.0209% (allowance for trace CH4, COS, and CH3OH) 

DRE = Destruction Removal Efficiency for CO, CH3OH, CH4, COS = 99%

D.4.17 Thermal Oxidizer Operation

In order to ensure compliance with Conditions D.4.5, D.4.8 and D.4.11, the associated thermal 

oxidizer(s) shall be in operation at all times when the Acid Gas Removal (AGR) Unit vents are in 

operation.

D.4.18 Water Wash Tower Control 

In order to ensure compliance with Conditions D.4.11, if the final design of the AGR unit includes 

a water wash tower, it shall be in operation at all times when the Acid Gas Removal (AGR) Unit 

vent are in operation, unless a compliant stack test on the AGR unit vents demonstrates that use 

of the water wash tower is not required to demonstrate compliance.

D.4.19 Testing Requirements [326 IAC 2-1.1-11]

(a) In order to demonstrate compliance with Condition D.4.5 – CO PSD BACT, not later than 

180 days after initial startup of the second gasifier, but not later than 365 days after the 

initial startup of the first gasifier, the Permittee shall conduct CO emissions stack testing 

of the emissions from the first of the Acid Gas Removal (AGR) units EU-007A or EU007B that has been started up. Not later than 180 days after initial startup of the fourth 

gasifier, the Permittee shall conduct CO emissions stack testing of the emissions from 

the other of the Acid Gas Removal (AGR) units EU-007A or EU-007B. The testing shall 

utilize methods as approved by the Commissioner. These tests shall be repeated at least 

once every five years from the date of the most recent valid compliance demonstration. 

Testing shall be conducted in accordance with the provisions of 326 IAC 3-6 (Source 

Sampling Procedures). Section C - Performance Testing contains the Permittee's 

obligation with regard to the performance testing required by this condition.

(b) In order to demonstrate compliance with Condition D.4.7 – NOx PSD BACT, not later 

than 180 days after initial startup of the second gasifier, but not later than 365 days after 

the initial startup of the first gasifier, the Permittee shall conduct NOx emissions stack 

testing of the emissions from the first of the Acid Gas Removal (AGR) units EU-007A or 

EU-007B that has been started up. Not later than 180 days after initial startup of the 

fourth gasifier, the Permittee shall conduct NOx emissions stack testing of the emissions 

from the other of the Acid Gas Removal (AGR) units EU-007A or EU-007B. The testing 

shall utilize methods as approved by the Commissioner. The tests for each AGR for NOx 

emissions shall be done once. Testing shall be conducted in accordance with the 

provisions of 326 IAC 3-6 (Source Sampling Procedures). Section C - Performance 

Testing contains the Permittee's obligation with regard to the performance testing 

required by this condition.
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(c) In order to demonstrate compliance with Condition D.4.8 – VOC BACT, not later than 180 

days after initial startup of the second gasifier, but not later than 365 days after the initial 

startup of the first gasifier, the Permittee shall conduct VOC emissions stack testing of 

the emissions from the first of the Acid Gas Removal (AGR) units EU-007A or EU-007B 

that has been started up. Not later than 180 days after initial startup of the fourth gasifier, 

the Permittee shall conduct VOC emissions stack testing of the emissions from the other 

of the Acid Gas Removal (AGR) units EU-007A or EU-007B. These tests shall utilize 

methods as approved by the Commissioner. These tests shall be repeated at least once 

every five years from the date of the most recent valid compliance demonstration. Testing 

shall be conducted in accordance with the provisions of 326 IAC 3-6 (Source Sampling 

Procedures). Section C - Performance Testing contains the Permittee's obligation with 

regard to the performance testing required by this condition.

(d) In order to demonstrate compliance with Condition D.4.11 – Hazardous Air Pollutants 

Minor Limit, not later than 180 days after initial startup of the second gasifier, but not later 

than 365 days after the initial startup of the first gasifier, the Permittee shall conduct 

methanol, carbonyl sulfide and other HAPs (as determined by IDEM, using the results of 

the screening test required by Condition D.4.19(e)) emissions stack testing of the 

emissions from the first of the Acid Gas Removal (AGR) units EU-007A or EU-007B that 

has been started up. Not later than 180 days after initial startup of the fourth gasifier, the 

Permittee shall conduct methanol carbonyl sulfide and other HAPs emissions stack 

testing of the emissions from the other of the Acid Gas Removal (AGR) units EU-007A or 

EU-007B. These tests shall utilize methods as approved by the Commissioner. These 

tests shall be repeated at least once every five years from the date of the most recent 

valid compliance demonstration. Testing shall be conducted in accordance with the 

provisions of 326 IAC 3-6 (Source Sampling Procedures). Section C - Performance 

Testing contains the Permittee's obligation with regard to the performance testing 

required by this condition.

(e) Not later than 60 days prior to the emissions stack testing required by Condition 

D.4.19(d), the Permittee shall conduct a screening test for other HAPs present in the first 

of the Acid Gas Removal (AGR) units EU-007A or EU-007B that has been started up. 

These tests shall utilize methods as approved by the Commissioner. This requirement 

shall also apply to the repeat testing required by Condition D.4.19(d). 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.4.20 Thermal Oxidizer Parametric Monitoring

(a) In order to ensure compliance with Conditions D.4.5, D.4.8 and D.4.11, a continuous 

monitoring system shall be calibrated, maintained, and operated on each thermal oxidizer

for measuring operating temperature. For the purposes of this condition, continuous 

monitoring means recording the temperature no less often than every 15 minutes when 

the unit is in operation. The output of this system shall be recorded as a three (3) hour 

average.

(b) From the date of startup until the initial stack test results are available, the RTO 

temperature shall be maintained at a three (3)-hour average temperature of 1,600°F at all 
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times that the AGR vent is in operation. On and after the date the stack test results are 

available, the minimum specified temperature is the three (3)-hour average temperature 

as observed during the most recent compliant stack test. 

.

(c) Section C - Response to Excursions or Exceedences contains the Permittee's obligation 

with regard to the reasonable response steps required by this condition. A temperature 

average below the three hour average 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.

D.4.21 Water Wash Tower Parametric Monitoring

(a) This condition applies if the final design of the AGR unit includes a water wash tower, 

unless a compliant stack test on the AGR unit vents demonstrates that use of the water 

wash tower is not required to demonstrate compliance. In order to ensure compliance 

with Condition D.4.11, a continuous monitoring system shall be calibrated, maintained, 

and operated for measuring the wash water flow rate to the tower. For the purpose of 

this condition, continuous means no less than once per fifteen (15) minutes. The output 

of this system shall be recorded as a three (3)-hour average. From the date of startup 

until the initial stack test results are available, the wash water flow rate shall be 

maintained at the manufacturer’s recommended flow rate at all times the AGR vent is in 

operation. On and after the date the stack test results are available, the minimum 

specified wash water flow rate is the three (3)-hour average flow rate as observed during 

the compliant stack test. 

(b) Section C - Response to Excursions or Exceedances contains the Permittee's obligation 

with regard to the reasonable response steps required by this condition. A flow rate 

average below the three hour average 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.

D.4.22 Vent Flow Monitoring 

In order to demonstrate the compliance status with Conditions D.4.6 – SO2 PSD BACT, D.4.9 -

GHGs PSD BACT, D.4.11 – HAPs Minor Limit, D.4.15 – Sulfur Dioxide Control, and D.4.16 -

Greenhouse Gases (GHGs) Calculations, a continuous monitoring system shall be calibrated, 

maintained, and operated on AGR vent flow to continuously monitor the vent flow from the AGR 

to the thermal oxidizers. For the purposes of this condition, continuous monitoring shall mean no 

less often than once per fifteen (15) minutes. The output from this monitoring system shall be 

recorded whenever the AGRs are in operation. 

D.4.23 Compliance Assurance Monitoring (CAM) [40 CFR 64]

The requirements of 40 CFR Part 64 – Compliance Assurance Monitoring (CAM) apply to the 

Acid Gas Removal (AGR) Unit for CO emissions. Compliance with the CAM plan attached as 

Appendix D satisfies 40 CFR 64, Compliance Assurance Monitoring (CAM) for the Acid Gas 

Removal (AGR) Unit for CO emissions.

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

D.4.24 Record Keeping Requirements

(a) In order to document the compliance status with Conditions D.4.4 - PM, PM10 and PM2.5

PSD BACT, D.4.6 – SO2 PSD BACT, D.4.9 - GHGs PSD BACT, D.4.13 – PM, PM10, 

and PM2.5 Calculations, D.4.15 – Sulfur Dioxide Control and Calculations, and D.4.16 –

Greenhouse Gases (GHGs) Calculations, the Permittee shall maintain monthly records of 
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the amount and type of fuel combusted in the RTOs for the Acid Gas Removal (AGR) 

Unit vents.

(b) To document the compliance status with Conditions D.4.9 - GHGs PSD BACT, D.4.4 -

PM, PM10 and PM2.5 PSD BACT, and D.4.6 - SO2 PSD BACT the Permittee shall 

maintain monthly records of the CO2, PM, PM10 and PM2.5 , and SO2 emissions. 

(c) To document the compliance status with Condition D.4.10 – Alternate Emissions 

Limitation During Gasifier Startup Flaring, the Permittee shall maintain monthly records of 

the NOx emissions during gasifier startup flaring.

(d) To document the compliance status with condition D.4.11, the Permittee shall maintain 

records in accordance with (1) through (4) below. Records maintained for (1) through (4) 

shall be taken monthly when the unit is in operation and shall be complete and sufficient 

to establish compliance with the HAP emission limits established in condition D.4.11.

(1) The monthly records of the methanol, carbonyl sulfide, and total HAPs 

emissions.

(2) Monthly records of when the RTO is in standby mode.

(3) The water flow rate of the water wash tower (if used).

(4) The results of the most recent stack test, setting the emission factors for 

methanol, carbonyl sulfide, and total HAPs emissions. 

(e) In order to document the compliance status with Conditions D.4.6 – SO2 PSD BACT and 

D.4.15 – Sulfur Dioxide Control, the Permittee shall maintain monthly records of the sulfur 

content in the AGR vent stream. 

(f) In order to document the compliance status with Condition D.4.22 - Vent Flow Monitoring, 

the Permittee shall maintain monthly records of the vent flow from the AGRs into the 

RTOs.

(g) In order to document the compliance status with Condition D.4.10 - Alternate Emissions 

Limitation During Gasifier Startup Flaring, the Permittee shall maintain records of the 

amount and type of fuel combusted in the RTOs for the Acid Gas Removal (AGR) Unit 

vents during each hour during which a startup flaring event occurs.

(h) In order to document the compliance status with Condition D.4.20 - Thermal Oxidizer 

Parametric Monitoring, the Permittee shall maintain continuous temperature records (on 

a 3 - hour average basis) for each thermal oxidizer to demonstrate compliance.

(i) Section C - General Record Keeping Requirements contains the Permittee's obligations 

with regard to the record keeping required by this condition.

D.4.25 Reporting Requirements

A quarterly summary of the information to document the compliance status with Conditions D.4.9 

and D.4.11(a) and (b) 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 
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requirements of 326 IAC 2-7-6(1) by a “responsible official” as defined by 326 IAC 2-7-1(34). 

Section C - General Reporting Requirements contains the Permittee's obligations with regard to 

the reporting required by this condition.
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SECTION D.5 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(F) Two (2) Wet Sulfuric Acid (WSA) plant trains, each nominally rated at 800 stpd H2SO4

and identified as EU-015A and EU-015B, permitted in 2012, with NOx, emissions 

controlled by two (2) selective catalytic reduction (SCR) systems identified as C-015-

1A and C-015-1B, respectively, and particulate, H2SO4, and SO2 emissions controlled 

by two (2) hydrogen peroxide scrubbers identified as C-015-2A and C-015-2B, 

respectively, and particulate and H2SO4 emissions controlled by a high efficiency mist 

eliminator, exhausting through two (2) stacks, identified as S-015A and S-015B 

respectively. These emissions units also include two (2) preheat burners (one for 

each train), each nominally rated at 35.00 MMBtu/hr HHV, venting through the same 

stacks.

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.5.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

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

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

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

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

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

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Wet 

Sulfuric Acid (WSA) plant, identified as EU-015A and B shall be as follows:
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The PM, PM10 and PM2.5 emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall be 

controlled by a high Efficiency Mist Eliminator and H2O2 scrubber and the PM, PM10 and PM2.5

emissions shall not exceed 0.15 pounds per ton of acid produced and 5 lb/hour, each, based on a 

3-hour average. 

D.5.5 H2SO4 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Wet 

Sulfuric Acid (WSA) plant, identified as EU-015A and B shall be as follows:

The H2SO4 emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall be controlled by a 

high Efficiency Mist Eliminator and H2O2 scrubber and the H2SO4 emissions shall not exceed 

0.15 pounds per ton of acid produced and 5 lb/hour, each, based on a 3-hour average. 

D.5.6 CO PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Wet 

Sulfuric Acid (WSA) plant, identified as EU-015A and B shall be as follows:

The CO emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall not exceed 18.7 pounds 

per hour, each based on a 3-hour average. 

D.5.7 SO2 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Wet 

Sulfuric Acid (WSA) plant, identified as EU-015A and B shall be as follows:

The SO2 emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall be controlled by a 

peroxide scrubber, the SO2 emissions shall not exceed 0.25 lb/ton acid produced and 8.3 lbs 

SO2 per hour, each based on a 24-hour block daily average. 

D.5.8 NOx PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Wet 

Sulfuric Acid (WSA) plant, identified as EU-015A and B shall be as follows:

The NOx emissions shall not exceed 10.2 pounds per hour NOx based on a 24-hour block daily 

average for each Wet Sulfuric Acid unit and, when acid gases are being fed to the unit, the NOx 

emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall be controlled by the use of 

selective catalytic reduction (SCR).

D.5.9 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Wet 

Sulfuric Acid (WSA) plant, identified as EU-015A and B shall be as follows:

The CO2 emissions from the Wet Sulfuric Acid Plant operation shall not exceed 474,000 tons per 

twelve (12) consecutive month period, with compliance determined at the end of each month.
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D.5.10 Alternative Emissions Limitation During Gasifier Startup Flaring

During startup flaring of the gasifiers, the NOx emissions from the WSA units (EU-015A/B) shall 

be limited to 15.26 lbs/hr combined from both WSA units (EU-015A/B) and shall be applicable 

beginning when a starting up gasifier first begins to flare generated syngas and ends when the 

generated syngas begins diversion from the flare to the downstream AGR/WSA trains. 

D.5.11 Preventive Maintenance Plan [326 IAC 1-6-3]

A Preventive Maintenance Plan (PMP) is required for these units and control devices. Section B -

Preventive Maintenance Plan contains the Permittee's obligations with regard to the preventive 

maintenance plan required by this condition.

Compliance Determination Requirements

D.5.12 Nitrogen Oxide Control

In order to ensure compliance with Condition D.5.8, the selective catalytic reduction (SCR) shall 

be in operation and control emissions from each Wet Sulfuric Acid (WSA) unit at all times that 

acid gases are being fed to the unit.

D.5.13 Sulfur dioxide Control

In order to ensure compliance with Condition D.5.7, the peroxide scrubber for SO2 removal shall 

be in operation and control emissions from each WSA at all times that the WSA is in operation.

D.5.14 PM, PM10, PM2.5 and H2SO4 Control

In order to ensure compliance with Conditions D.5.4 and D.5.5, the high Efficiency Mist Eliminator 

and H2O2 scrubber shall be in operation and control emissions from each WSA at all times when 

the WSA is in operation.

D.5.15 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, CO2 and SO2

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, SO2, or CO2 CEM is down for more than twenty-four (24) hours, the 

Permittee shall follow good air pollution control practices.

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

operate a continuous emission monitoring system pursuant to 40 CFR 60, 40 CFR 75 

and 40 CFR 96.

D.5.16 Testing Requirements [326 IAC 2-1.1-11]

(a) In order to demonstrate compliance with Condition D.5.4 – PM, PM10 and PM2.5 PSD 

BACT, not later than 180 days after initial startup of the second gasifier but not later than 
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365 days after the initial startup of the first gasifier, the Permittee shall conduct PM, PM10

and PM2.5 emissions stack testing of the emissions from the first of the Wet Sulfuric Acid 

EU-015A or EU-015B that has been started up. Not later than 180 days after initial 

startup of the fourth gasifier, the Permittee shall conduct PM, PM10 and PM2.5 emissions 

stack testing of the emissions from the other of the Wet Sulfuric Acid EU-015A or EU015B. The tests shall utilize methods approved by the Commissioner. These tests shall 

be repeated at least once every five years from the date of the most recent valid 

compliance demonstration. Testing shall be conducted in accordance with the provisions 

of 326 IAC 3-6 (Source Sampling Procedures). Section C - Performance Testing 

contains the Permittee's obligation with regard to the performance testing required by this 

condition.

(b) In order to demonstrate compliance with Condition D.5.5 – H2SO4 PSD BACT, not later 

than 180 days after initial startup of the second gasifier but not later than 365 days after 

the initial startup of the first gasifier, the Permittee shall conduct H2SO4 emissions stack 

testing of the emissions from the first of the Wet Sulfuric Acid EU-015A or EU-015B that 

has been started up. Not later than 180 days after initial startup of the fourth gasifier, the 

Permittee shall conduct H2SO4 emissions stack testing of the emissions from the other of 

the Wet Sulfuric Acid EU-015A or EU-015B. The tests shall utilize methods approved by 

the Commissioner. These tests shall be repeated at least once every five years from the 

date of the most recent valid compliance demonstration. Testing shall be conducted in 

accordance with the provisions of 326 IAC 3-6 (Source Sampling Procedures). Section C 

- Performance Testing contains the Permittee's obligation with regard to the performance 

testing required by this condition.

(c) In order to demonstrate compliance with Condition D.5.6 – CO PSD BACT, not later than 

180 days after initial startup of the second gasifier but not later than 365 days after the 

initial startup of the first gasifier, the Permittee shall conduct CO emissions stack testing 

of the emissions from the first of the Wet Sulfuric Acid (WSA) EU-015A or EU-015B that 

has been started up. Not later than 180 days after initial startup of the fourth gasifier, the 

Permittee shall conduct CO emissions stack testing of the emissions from the other of the 

Wet Sulfuric Acid EU-015A or EU-015B. These tests shall utilize methods approved by 

the Commissioner. These tests for each WSA shall be done 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.

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

D.5.17 Scrubber Parametric Monitoring

(a) In order to demonstrate the compliance status with Conditions D.5.4 and D.5.5, the 

Permittee shall monitor and record the pressure drop across the scrubber, at least once 

per day. When for any one reading, the pressure drop across the scrubber is outside the 

normal range of 1.0 to 5 inches of water or a range established during the latest stack 

test, the Permittee shall take reasonable response steps. Failure to take response steps 

shall be considered a deviation from this permit. Section C - Response to Excursions or 

Exceedances contains the Permittee's obligation with regard to the reasonable response 

steps required by this condition.
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(b) In order to demonstrate the compliance status with Conditions D.5.4 and D.5.5, the 

Permittee shall monitor the flow rate of the scrubbing liquid daily. When for any one 

reading, the flow rate is below the normal minimum or a minimum established during the 

latest stack test, the Permittee shall take reasonable response steps. Failure to take 

response steps shall be considered a deviation from this permit. Section C - Response to 

Excursions or Exceedances contains the Permittee's obligation with regard to the 

reasonable response steps required by this condition.

(c) The instruments used for determining the pressure and flow rate shall comply with 

Section C - Instrument Specifications, of this permit, shall be subject to approval by 

IDEM, OAQ, and shall be calibrated or replaced at least once every six (6) months or 

other time period specified by the manufacturer. The Permittee shall maintain records of 

the manufacturer specifications, if used.

D.5.18 Scrubber Failure Detection

(a) For a scrubber 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. Operations may continue only if the event qualifies as an 

emergency and the Permittee satisfies the requirements of the emergency provisions of 

this permit (Section B - Emergency Provisions).

(b) For a scrubber 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 line. Operations may continue only if the event qualifies as an emergency 

and the Permittee satisfies the requirements of the emergency provisions of this permit 

(Section B - Emergency Provisions).

D.5.19 Compliance Assurance Monitoring (CAM) [40 CFR 64]

The requirements of 40 CFR Part 64 – Compliance Assurance Monitoring (CAM) apply to the Wet 

Sulfuric Acid (WSA) Plant for NOx, H2SO4 and SO2 emissions. Compliance with the CAM plan 

attached as Appendix D satisfies 40 CFR 64, Compliance Assurance Monitoring (CAM) for the 

Wet Sulfuric Acid (WSA) Plant for NOx, H2SO4 and SO2 emissions.

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

D.5.20 Record Keeping Requirements

(a) To document the compliance status with Condition D.5.15, the Permittee shall record the 

output of the continuous monitoring systems and shall perform the required record 

keeping and reporting, pursuant to 326 IAC 3-5-6 and 326 IAC 3-5-7.

(b) In the event that a breakdown of the NOx, SO2, or CO2 continuous emission monitoring 

system (CEMS) occurs in Condition D.5.15, the Permittee shall maintain records of all 

CEMS malfunctions, out of control periods, calibration and adjustment activities, and 

repair or maintenance activities.

(c) To document compliance with Condition D.5.17(a), the Permittee shall maintain records 

of the pressure drop readings of the scrubber once per day. The Permittee shall include 

in its daily record when a reading is not taken and the reason for the lack of reading (e.g. 

the process did not operate that day).
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(d) To document compliance with Condition D.5.17(b), the Permittee shall maintain records 

of the flow rate of the scrubber. The Permittee shall include in its daily record when a 

reading is not taken and the reason for the lack of reading (e.g. the process did not 

operate that day).

(e) Section C - General Record Keeping Requirements, contains the Permittee's obligation 

with regard to the records required by this condition.

D.5.21 Reporting Requirements

(a) Pursuant to 326 IAC 3-5-7(c)(4), 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; and

(5) nature of system repairs and adjustments.

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

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

(b) A quarterly summary of the information to document the compliance status with Condition 

D.5.9 shall be submitted, using the reporting forms located at the end of this permit, or 

their equivalent, not later than thirty (30) days following the end of each calendar quarter. 

The report submitted by the Permittee does require a certification that meets the 

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

326 IAC 2-7-1(34). Section C - General Reporting Requirements contains the 

Permittee's obligations with regard to the reporting required by this condition.
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SECTION D.6 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(G) Two (2) natural gas-fired auxiliary boilers, nominally rated at 408 MMBtu/hr HHV each, 

identified as EU-005A and EU-005B, permitted in 2012, with NOx emissions controlled 

by ultra-low NOx burners/Flue Gas Recirculation (ULNB/FGR), with both boilers 

exhausting through one (1) stack, identified as S-005. [Under 40 CFR 60, Subpart Db, 

the natural gas-fired auxiliary boilers are new affected sources.]

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.6.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

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

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

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

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

D.6.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Auxiliary 

natural gas -fired Boiler, identified as EU-005A and B shall be as follows:

The PM, PM10 and PM2.5 emissions from the Auxiliary Boilers (EU-005A/B) operation shall not 

exceed 0.0075 lb per MMBtu and only natural gas or SNG shall be used.

D.6.5 CO PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Auxiliary 

natural gas -fired Boiler, identified as EU-005A and B shall be as follows:
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The CO emissions from the Auxiliary Boilers (EU-005A/B) operation shall not exceed 0.036 

lb/MMBtu based on a 3 - hour average and good combustion practices shall be used.

D.6.6 SO2 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Auxiliary 

natural gas -fired Boiler, identified as EU-005A and B shall be as follows:

The SO2 emissions from the Auxiliary Boilers (EU-005A/B) operation shall not exceed 0.0006 

lb/MMBtu and only natural gas or SNG shall be used.

D.6.7 NOx PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Auxiliary 

natural gas -fired Boiler, identified as EU-005A and B shall be as follows:

The NOx emissions from the Auxiliary Boilers (EU-005A/B) operation shall not exceed 0.0125 

lb/MMBtu based on a 24-hour block daily average basis and Ultra Low NOx burners with FGR

shall be used.

D.6.8 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Auxiliary 

natural gas -fired Boiler, identified as EU-005A and B shall be as follows:

The GHGs BACT for the Auxiliary Boilers shall be as follows:

(a) Use of natural gas or SNG; and 

(b) Energy efficient boiler design (utilizing an economizer, condensate recovery, inlet air 

controls and blowdown heat recovery.) 

(c) Boiler designed for 81% thermal efficiency (HHV).

(d) The total CO2 emissions from the auxiliary boilers shall not exceed 88,167 tons per 

twelve (12) consecutive month period, with compliance determined at the end of each 

month.

D.6.9 Hazardous Air Pollutants (HAPs) Minor Limits

The single HAP and total HAPs from the natural gas-fired auxiliary boilers identified as EU-005A

and EU-005B shall be limited by compliance with Condition D.6.10 - Operational Limit and, 

combined with the potential to emit HAP emissions from all other emission units, this requirement 

will limit the potential to emit from this source to less than ten (10) tons per year of any individual 

HAP and twenty-five (25) tons per year of any combination of HAPs and make the source an area 

source of HAPs.

D.6.10 Operational Limit

The total throughput of fuel to the two (2) natural gas-fired auxiliary boilers, identified as EU005A/B, shall not exceed a total firing rate of 1430 billion Btu per twelve (12) consecutive month 

period, with compliance determined at the end of each month. 
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D.6.11 Preventive Maintenance Plan [326 IAC 1-6-3]

A Preventive Maintenance Plan (PMP) is required for these units and control devices. Section B -

Preventive Maintenance Plan contains the Permittee's obligations with regard to the preventive 

maintenance plan required by this condition.

Compliance Determination Requirements

D.6.12 Nitrogen Oxide Control

In order to ensure compliance with Condition D.6.7, the Ultra Low NOx burner with FGR shall be 

installed and utilized at all times that the auxiliary boilers are in operation.

D.6.13 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 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 CEMS is down for more than twenty-four (24) hours, the Permittee 

shall follow the best combustion practice.

(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.6.14 Testing Requirements [326 IAC 2-1.1-11]

(a) In order to demonstrate compliance with Condition D.6.5 – CO PSD BACT, not later than 

180 days after initial startup of the first gasifier, the Permittee shall perform CO emissions 

stack testing of the emissions auxiliary boilers EU-005A and EU-005B utilizing methods 

approved by the Commissioner. These tests shall be done once. Testing shall be 

conducted in accordance with the provisions of 326 IAC 3-6 (Source Sampling 

Procedures). Section C - Performance Testing contains the Permittee's obligation with 

regard to the performance testing required by this condition.

(b) In order to demonstrate compliance with Condition D.6.8(c) – PSD GHG BACT, not later 

than 180 days after initial startup of the first gasifier, the Permittee shall perform thermal 

efficiency testing of the auxiliary boilers EU-005A and EU-005B utilizing methods 

approved by the Commissioner. These tests shall be done once. Testing shall be 

conducted in accordance with the provisions of 326 IAC 3-6 (Source Sampling 

Procedures). Section C - Performance Testing contains the Permittee's obligation with 

regard to the performance testing required by this condition.
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D.6.15 Compliance Determination Requirements [326 IAC 2-2]

In order to determine compliance status with Conditions D.6.4 - PM, PM10 and PM2.5 PSD BACT 

and D.6.6 - SO2 PSD BACT, the Permittee shall only use natural gas or SNG in the auxiliary 

boilers EU-005A and EU-005B. 

D.6.16 Greenhouse Gases (GHGs) Calculations

To determine the compliance status with Condition D.6.8(d), the following equation shall be used 

to determine the CO2 emission limit for the Auxiliary Boilers:

ECO2 = F x HHV x EF CO2 x (ton/2000 lb)

Where:

ECO2 = Total CO2 emissions, tons/month

F = Total amount of natural gas or SNG combusted in the auxiliary boilers, MMscf/month

HHV = higher heating value for the fuel combusted, in Btu/scf

EF CO2 = 116.89 lb CO2/MMBtu 

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

D.6.17 Record Keeping Requirements

(a) To document the compliance status with Condition D.6.13, the Permittee shall record the 

output of the continuous monitoring systems and shall perform the required record 

keeping and reporting, pursuant to 326 IAC 3-5-6 and 326 IAC 3-5-7.

(b) In the event that a breakdown of the NOx continuous emission monitoring systems 

(CEMS) occurs in Condition D.6.13, the Permittee shall maintain records of all CEMS 

malfunctions, out of control periods, calibration and adjustment activities, and repair or 

maintenance activities.

(c) In order to document the compliance status with Conditions D.6.4, D.6.6, D.6.8(a) and 

(d), D.6.10, and D.6.16, the Permittee shall maintain monthly records of the type and 

amount of fuel combusted in the auxiliary boilers.

(d) To document the compliance status with Condition D.6.8(d), the Permittee shall maintain 

the monthly records of the total CO2 emissions from the auxiliary boilers.

(e) To document the compliance status with Condition D.6.10, the Permittee shall maintain 

the monthly records of the total firing rate of the auxiliary boilers.

(f) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition.

D.6.18 Reporting Requirements

(a) Pursuant to 326 IAC 3-5-7(c)(4), reporting of continuous monitoring system instrument 

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

include the following:
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(1) date of downtime;

(2) time of commencement;

(3) duration of each downtime;

(4) reasons for each downtime; and

(5) nature of system repairs and adjustments.

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

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

(b) A quarterly summary of the information to document the compliance status with 

Conditions D.6.8(d) and D.6.10 shall be submitted, using the reporting forms located at 

the end of this permit, or their equivalent, not later than thirty (30) days following the end 

of each calendar quarter. The report submitted by the Permittee does require a 

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

defined by 326 IAC 2-7-1(34). Section C - General Reporting Requirements contains the 

Permittee's obligations with regard to the reporting required by this condition.
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SECTION D.7 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(H) Five (5) natural gas-fired and SNG fuel-fired gasifier preheat burners, each nominally 

rated with a heat input of 35.00 MMBtu/hr HHV, and identified as EU-008A through 

EU-008E, permitted in 2012, exhausting through five (5) vents, identified as S-008A 

through S-008E, respectively. 

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.7.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

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

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

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

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

D.7.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Gasifier 

Preheat Burners, identified as EU-008A - E shall be as follows:

The PM, PM10 and PM2.5 emissions from the Gasifier Preheat Burners (EU-008A-E) operation 

shall not exceed 0.0007 lb /MMBtu, each and only natural gas or SNG shall be used. 

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

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Gasifier 

Preheat Burners, identified as EU-008A - E shall be as follows:
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The CO emissions from the Gasifier Preheat Burners (EU-008A-E) operation shall not exceed

0.056 lb CO/MMBtu, each and shall use good combustion practices. 

D.7.6 SO2 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Gasifier 

Preheat Burners, identified as EU-008A - E shall be as follows:

The SO2 emissions from the Gasifier Preheat Burners (EU-008A-E) operation shall be not 

exceed 0.0006 lb SO2/MMBtu, each and natural gas or SNG shall be used.

D.7.7 NOx PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Gasifier 

Preheat Burners, identified as EU-008A - E shall be as follows:

The NOx emissions from the Gasifier Preheat Burners (EU-008A-E) operation shall not exceed 

0.10 lb NOx /MMBtu, each and good combustion practices shall be used.

D.7.8 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Gasifier 

Preheat Burners, identified as EU-008A - E shall be as follows:

The GHGs BACT for the Gasifier Preheat Burners shall be as follows:

a. The use of good engineering design; and 

b. The use of natural gas or SNG.

c. The CO2 emissions from the Gasifier Preheater Burners shall not exceed 6,438 tons CO2

per twelve (12) consecutive month period, with compliance determined at the end of each 

month.

D.7.9 Preventive Maintenance Plan [326 IAC 1-6-3]

A Preventive Maintenance Plan (PMP) is required for these units and its control device. Section 

B - Preventive Maintenance Plan contains the Permittee's obligations with regard to the 

preventive maintenance plan required by this condition.

Compliance Determination Requirements

D.7.10 Compliance Determination Requirements [326 IAC 2-2]

In order to determine compliance status with Conditions D.7.4 - PM, PM10 and PM2.5 PSD BACT, 

D.7.5 - CO PSD BACT, D.7.6 - SO2 PSD BACT, D.7.7 - NOx PSD BACT and D.7.8(b) - GHGs 

PSD BACT, the Permittee shall only use natural gas or SNG in the Gasifier Preheat Burners (EU008A-E). 

D.7.11 Greenhouse Gases (GHGs) Calculations

To determine the compliance status with Condition D.7.8(c), the following equation shall be used 

to determine the CO2 emission limit for the Gasifier Preheat Burners (EU-008A-E):
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ECO2 = F x HHV x EF CO2 x (ton/2000 lb)

Where:

ECO2 = Total CO2 emissions, tons/month

F = Total amount of natural gas or SNG combusted in the Gasifier Preheat Burners, 

MMscf/month

HHV = higher heating value of the fuel combusted, in Btu/scf

EF CO2 = 116.89 lb CO2/MMBtu 

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

D.7.12 Record Keeping Requirement

(a) In order to document the compliance status with Conditions D.7.4, D.7.5, D.7.6, D.7.7, 

D.7.8 and D.7.11, the Permittee shall maintain monthly records of the type and amount of 

fuel combusted in the Gasifier Preheat Burners.

(b) To document the compliance status with Condition D.7.8(c), the Permittee shall maintain 

the monthly records of the CO2 emissions from the Gasifier Preheat Burners.

(c) Section C - General Record Keeping Requirements contains the Permittee's obligations 

with regard to the record keeping required by this condition.

D.7.13 Reporting Requirements

A quarterly summary of the information to document the compliance status with Conditions 

D.7.8(c) shall be submitted, using the reporting forms located at the end of this permit, or their 

equivalent, not later than thirty (30) days following the end of each calendar quarter. The report 

submitted by the Permittee does require a certification that meets the requirements of 

326 IAC 2-7-6(1) by a “responsible official” as defined by 326 IAC 2-7-1(34). Section C - General 

Reporting Requirements contains the Permittee's obligations with regard to the reporting required 

by this condition.
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SECTION D.8 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(I) One (1) ZLD-Spray Dryer, permitted in 2012, nominally rated at 5.6 MMBtu/hr with 

particulate emissions controlled by a baghouse identified as C-032, nominally rated at 

2,735 dscfm, and identified as EU-032, with low NOx burners (LNB), exhausting 

through one (1) stack, identified as S-014.

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.8.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

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

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

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

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

D.8.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the ZLDSpray Dryer, identified as EU-032 shall be as follows:

The PM, PM10 and PM2.5 emissions from the Zero Liquid Discharge (ZLD) Spray Dryer shall be 

controlled by a fabric filter baghouse and the PM, PM10 and PM2.5 emissions shall not exceed 

0.005 gr/dscf based on a 3 hour average.

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

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the ZLDSpray Dryer, identified as EU-032 shall be as follows:
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The CO emissions from the Zero Liquid Discharge (ZLD) Spray Dryer shall not exceed 0.036 

lb/MMBtu and good combustion practices shall be used.

D.8.6 SO2 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the ZLDSpray Dryer, identified as EU-032 shall be as follows:

The SO2 emissions from the Zero Liquid Discharge (ZLD) Spray Dryer shall be limited through 

the use of natural gas or SNG.

D.8.7 NOx PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the ZLDSpray Dryer, identified as EU-032 shall be as follows:

The NOx emissions from the Zero Liquid Discharge (ZLD) Spray Dryer shall not exceed 0.035 

lb/MMBtu and a Low NOx Burner (LNB) shall be used.

D.8.8 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the ZLDSpray Dryer, identified as EU-032 shall be as follows:

The GHGs BACT for the Zero Liquid Discharge (ZLD) Spray Dryer shall be as follows:

a. The BACT for the Zero Liquid Discharge (ZLD) Spray Dryer shall be the use of good 

engineering design and the use of natural gas or SNG. 

b. The CO2 emissions from the ZLD Spray Dryer shall be not exceed 2,884 tons CO2 per 

twelve (12) consecutive month period with compliance determined at the end of each 

month.

D.8.9 Preventive Maintenance Plan [326 IAC 1-6-3]

A Preventive Maintenance Plan (PMP) is required for this unit and its control device. Section B -

Preventive Maintenance Plan contains the Permittee's obligations with regard to the preventive 

maintenance plan required by this condition.

Compliance Determination Requirements

D.8.10 Nitrogen Oxide Control

In order to ensure compliance with Condition D.8.7, the low NOx burner shall be installed and

utilized at all times that this ZLD-Spray Dryer is in operation.

D.8.11 Compliance Determination Requirements [326 IAC 2-2]

In order to ensure compliance with Conditions D.8.5 – CO PSD BACT, D.8.6 - SO2 PSD BACT, 

D.8.7 – NOx PSD BACT and D.8.8(a) - GHGs PSD BACT, the Permittee shall only use natural 

gas or SNG in the ZLD-Spray Dryer (EU-032).
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D.8.12 PM, PM10 and PM2.5 Control [326 IAC 2-7-6(6)]

(a) in order to ensure compliance with Condition D.8.4, the baghouse for particulate control 

shall be in operation and control emissions from the ZLD-Spray Dryer at all times that this 

facility is in operation.

(b) In the event that bag failure is observed in a multi-compartment baghouse, if operations 

will continue for ten (10) days or more after the failure is observed before the failed units 

will be repaired or replaced, the Permittee shall promptly notify the IDEM, OAQ of the 

expected date the failed units will be repaired or replaced. The notification shall also 

include the status of the applicable compliance monitoring parameters with respect to 

normal, and the results of any response actions taken up to the time of notification.

D.8.13 Testing Requirements [326 IAC 2-1.1-11]

In order to demonstrate the compliance status with Condition D.8.4 - PM, PM10 and PM2.5 PSD 

BACT, not later than 180 days after initial startup of the fourth gasifier, but not later than 365 days 

after the initial startup of the first gasifier, the Permittee shall conduct stack testing on the 

baghouse controlling emissions from the ZLD-Spray Dryer, identified as EU-032 to determine 

compliance with the PM, PM10 and PM2.5 emissions limitations, utilizing methods as approved by 

the Commissioner. This test shall be repeated at least once every five years from the date of the 

most recent valid compliance demonstration. Testing shall be conducted in accordance with the 

provisions of 326 IAC 3-6 (Source Sampling Procedures). Section C - Performance Testing 

contains the Permittee's obligation with regard to the performance testing required by this 

condition.

D.8.14 Greenhouse Gases (GHGs) Calculations 

To determine the compliance status with Condition D.8.8(b), the following equation shall be used 

to determine the CO2 emission limit for the ZLD Spray Dryer:

ECO2 = F x HHV x EF CO2 x (ton/2000 lb)

Where:

ECO2 = Total CO2 emissions, tons/month

F = Total amount of natural gas or SNG combusted in the ZLD Spray Dryer, MMscf/month

HHV = higher heating value of the fuel combusted, in Btu/scf

EF CO2 = 116.89 lb CO2/MMBtu

D.8.15 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. Operations may continue only if the 

event qualifies as an emergency and the Permittee satisfies the requirements of the 

emergency provisions of this permit (Section B - Emergency Provisions).

(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 
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processing of the material in the process line. Operations may continue only if the event 

qualifies as an emergency and the Permittee satisfies the requirements of the emergency 

provisions of this permit (Section B - Emergency Provisions).

Bag failure can be indicated by a significant drop in the baghouses pressure reading with 

abnormal visible emissions, by an opacity violation, or by other means such as gas temperature, 

flow rate, air infiltration, leaks, dust traces or triboflows.

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

D.8.16 Visible Emissions Notations 

(a) Visible emission notations of the ZLD-Spray Dryer, identified as EU-032 stack exhausts 

(S-014) shall be performed once per day 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, at least eighty percent (80%) of the time the process is in operation, 

not counting startup or shut down time. 

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

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

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

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

for that specific process. 

(e) If abnormal emissions are observed, the Permittee shall take reasonable response steps. 

Failure to take response steps shall be considered a deviation from this permit. Section C 

- Response to Excursions or Exceedances contains the Permittee's obligation with regard 

to the reasonable response steps required by this condition.

D.8.17 Parametric Monitoring 

In order to demonstrate the compliance status with Condition D.8.4, the Permittee shall record the 

pressure drop across the baghouse used in conjunction with the ZLD-Spray Dryer operations at 

least once per day when this unit is in operation. When the pressure drop across the baghouse is 

outside the normal range of 1.0 and 5.0 inches of water or a range established during the latest 

stack test, the Permittee shall take reasonable response steps. Section C - Response to 

Excursions or Exceedances contains the Permittee's obligation with regard to the reasonable 

response steps required by this condition. A pressure reading that is outside the above 

mentioned range is not a deviation from this permit. Failure to take response steps shall be 

considered a deviation from this permit.

The instrument used for determining the pressure shall comply with Section C - Instrument 

Specifications, of this permit, shall be subject to approval by IDEM, OAQ, and shall be calibrated 

at least once every six (6) months.
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Record Keeping and Reporting Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-19]

D.8.18 Record Keeping Requirements

(a) In order to document the compliance status with Conditions D.8.5, D.8.6 and D.8.7, 

D.8.8, and D.8.14, the Permittee shall maintain monthly records of the type and amount 

of fuel combusted in the ZLD-Spray Dryer.

(b) To document the compliance status with Condition D.8.8(b) - GHGs PSD BACT, the 

Permittee shall maintain the monthly records of the CO2 emissions from each of ZLDSpray Dryer.

(c) To document the compliance status with Condition D.8.16 - Visible Emission Notation, 

the Permittee shall maintain a daily record of visible emission notations from the ZLDSpray Dryer. The Permittee shall include in its daily record when a visible emission 

notation is not taken and the reason for the lack of visible emission notation, (e.g. the 

process did not operate that day).

(d) To document the compliance status with Condition D.8.17 - Parametric Monitoring, the 

Permittee shall maintain a daily record of the pressure drop across the baghouse 

controlling the ZLD-Spray Dryer when venting to the atmosphere. 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).

(e) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition.

D.8.19 Reporting Requirements

A quarterly summary of the information to document the compliance status with Condition 

D.8.8(b) shall be submitted, using the reporting forms located at the end of this permit, or their 

equivalent, not later than thirty (30) days following the end of each calendar quarter. The report 

submitted by the Permittee does require a certification that meets the requirements of 

326 IAC 2-7-6(1) by a “responsible official” as defined by 326 IAC 2-7-1(34). Section C - General 

Reporting Requirements contains the Permittee's obligations with regard to the reporting required 

by this condition.
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SECTION D.9 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(a) Two (2) emergency diesel generators, each nominally rated at 1,341 horsepower, 

identified as EU-009A and EU-009B, permitted in 2012, exhausting through two (2) 

vents, identified as S-009A and S-009B, respectively. [Under 40 CFR 60, Subpart IIII, 

each, emergency diesel fired generator is considered a new affected source.][Under 

40 CFR 63, Subpart ZZZZ, each, emergency diesel fired generator is considered a 

new affected source.]

(b) Three (3) firewater pump diesel engines, each nominally rated at 575 horsepower and 

identified as EU-010A through EU-010C, permitted in 2012, exhausting through three 

(3) vents, identified as S-010A through S-010C, respectively. [Under 40 CFR 60, 

Subpart IIII, each firewater pump diesel engine is considered a new affected 

source.][Under 40 CFR 63, Subpart ZZZZ, each firewater pump diesel engine is 

considered a new affected source.]

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.9.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

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

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

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

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

D.9.4 PM, PM10, PM2.5, NOx, CO, SO2 and GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the two (2)

emergency diesel generators, identified as EU-009A and EU-009B and three (3) firewater pump 

diesel engines, identified as EU-010A - C shall be as follows:

(a) NOx: emissions shall be limited through the implementation of good combustion 

practices and limited hours of non-emergency operation;
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(b) CO: emissions shall be limited through the implementation of good combustion 

practices and limited hours of non-emergency operation; 

(c) PM, PM10 and PM2.5: emissions shall be limited through the use of low-S diesel (less 

than15ppm sulfur) and limited hours of non-emergency operation;

(d) SO2: emissions shall be limited through the use of low-S diesel (less than15 ppm sulfur) 

and limited hours of non-emergency operation; 

(e) Each emergency diesel engine shall not exceed 52 hours per year of non-emergency 

operation; and

(f) The total CO2 emissions from the emergency engines (EU-009A/B and EU-010A/B/C)

shall not exceed 84 tons CO2 per twelve (12) consecutive month period from nonemergency operation, with compliance determined at the end of each month.

D.9.5 Operating Restrictions During Gasifier Startup Flaring

During startup flaring of the gasifiers, the Permittee shall not test an emergency engine (EU009A/B and EU-010A/B/C). This operating restriction shall be applicable beginning when a 

starting up gasifier first begins to flare generated syngas and ends when the generated syngas 

begins diversion from the flare to the downstream AGR/WSA trains. 

Compliance Determination Requirements

D.9.6 Greenhouse Gases (GHGs) Calculations

To determine the compliance status with Condition D.9.4(f), the following equation shall be used 

to determine the CO2 emission limit for the emergency engines (EU-009A/B and EU-010A/B/C):

ECO2 (tons/month) = FD x HHV x EF CO2 x (ton/2000 lb)

Where:

ECO2 = Total CO2 emissions, tons/month

FD = Total amount of diesel fuel used in non-emergency operation of the emergency engines 

(EU-009A/B and EU-010A/B/C), gallons/month

HHV = 0.138 MMBtu/gal

EF CO2 = 163.05 lb CO2/MMBtu 

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

D.9.7 Record Keeping Requirements

(a) In order to document the compliance status with Conditions D.9.4(c) and (d), the 

Permittee shall maintain monthly records of the percent sulfur content of the fuel used in 

the emergency diesel engines and the firewater pump diesel engines.

(b) To document compliance with Condition D.9.4(e), the Permittee shall maintain monthly 

records of hours of operation of the emergency diesel engines and the firewater pump 

diesel engines.
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(c) To document the compliance status with Conditions D.9.4(f) and D.9.6, the Permittee 

shall maintain records of the total amount of fuel used each month in non-emergency 

operation of the emergency engines (EU-009A/B and EU-010A/B/C) and the total CO2

emissions from the emergency engines (EU-009A/B and EU-010A/B/C).

(d) To document the compliance status with Condition D.9.5, the Permittee shall maintain a 

record of the date and period of emergency engine testing, and whether startup flaring of 

the gasifiers occurred during the testing period.

(e) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition

D.9.8 Reporting Requirements

A quarterly summary of the information to document the compliance status with Conditions 

D.9.4(e) and (f) shall be submitted, using the reporting forms located at the end of this permit, or 

their equivalent, not later than thirty (30) days following the end of each calendar quarter. The 

report submitted by the Permittee does require a certification that meets the requirements of 

326 IAC 2-7-6(1) by a “responsible official” as defined by 326 IAC 2-7-1(34). Section C - General 

Reporting Requirements contains the Permittee's obligations with regard to the reporting required 

by this condition.
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SECTION D.10 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(d) One (1) six (6) cell ASU cooling tower, nominally rated with a circulation rate of 54,960 

gpm and identified as EU-016A, permitted in 2012, with high efficiency drift/mist 

eliminators, and exhausting through six (6) vents, identified as S-016A-A through 

S-016A-F.

(e) One (1) twenty-four (24) cell main cooling tower, nominally rated with a circulation rate 

of 404,700 gpm and identified as EU-016B, permitted in 2012, with high efficiency 

drift/mist eliminators, and exhausting through twenty-four (24) vents, identified as S016B-A through S-016B-X.

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.10.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.10.2 Effective Date of the Permit [IC 13-15-5-3]

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

D.10.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

D.10.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the ASU 

Cooling Tower (EU-016A) and the Main Cooling Tower (EU-016B) shall be as follows:
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The PM, PM10 and PM2.5 emissions from the ASU Cooling Tower (EU-016A) and the Main 

Cooling Tower (EU-016B) shall be controlled by High efficiency drift eliminators designed with a 

drift loss rate of less than 0.0005% and total dissolved solids shall not exceed 1500 ppm based 

on a daily average.

Compliance Determination

D.10.5 PM, PM10 and PM2.5 Control

In order to ensure compliance with Condition D.10.4, 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 tower is in operation.

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

D.10.6 TDS Monitoring

To demonstrate the compliance status with Conditions D.10.4:

The Permittee shall sample the ASU and main cooling towers for total dissolved solids (TDS) 

once per week.

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

D.10.7 Record Keeping Requirements

(a) In order to document the compliance status with Condition D.10.4, the Permittee shall 

maintain weekly records of the total dissolved solids (TDS) sampling from the ASU and 

Main cooling towers.

(b) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition.
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SECTION D.11 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(c) Four (4) rod mill eductor vent stacks, permitted in 2012, nominally rated at 180 cfm 

and identified as EU-013A through EU-013D, and exhausting through four (4) vents, 

identified as S-013A through S-013D, respectively. 

(f) Two (2) Air Separation Unit (ASU) molecular sieve regeneration train vents, which 

each vent a nominal 187,000 cubic feet per minute during regenerations, identified as 

EU-017A and EU-017B, permitted in 2012, exhausting through two (2) vents, identified 

as S-017A andS-017B, respectively.

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.11.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.11.2 Effective Date of the Permit [IC 13-15-5-3]

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

D.11.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

D.11.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Rod Mill 

Vent, identified as EU-013 A - D shall be as follows:

(1) The PM and PM10 emissions from each Rod Mill Vents shall not exceed 0.025 pounds 

per hour based on a 3-hour average.

(2) The PM2.5 emissions from each Rod Mill Vent shall not exceed 0.0074 pounds per hour 

based on a 3-hour average.
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D.11.5 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Air 

Separation Unit (ASU), identified as EU-017A-B shall be as follows:

(1) The PM and PM10 emissions from each Air Separation Unit (ASU) shall not exceed 0.026 

pounds per hour based on a daily average. 

(2) The PM2.5 emissions from the Air Separation Unit (ASU) shall not exceed 0.009 pounds 

per hour based on a daily average. 
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SECTION D.12 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(K) Paved Plant Haul Roads are identified as emissions unit FUG-ROAD. 

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.12.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.12.2 Effective Date of the Permit [IC 13-15-5-3]

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

D.12.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

D.12.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Paved 

Plant Haul Roads (FUG-ROAD) shall be as follows:

The PM, PM10 and PM2.5 emissions from the paved road (FUG-ROAD) shall be controlled by;

1. Paving all plant haul roads;

2. Use of wet or chemical suppression; 

3. Prompt cleanup of any spilled materials; and

with a control efficiency of 90%.

Compliance Determination Requirements

D.12.5 Compliance Determination Requirements

To demonstrate compliance status with Condition D.12.4 - PM, PM10 and PM2.5 PSD BACT: 
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(a) Wet Suppression for roadway dust control shall be performed on paved Haul Roads, 

except when:

- It is raining or snowing at the time of the scheduled treatment, 

- The subject portion of the haul road is covered by ice or snow or remains wet 

from recent precipitation or the previous wet suppression, or

- The road is not being used as a haul road on that day.

If the ambient air temperature is below 32oF at the time of a scheduled wet suppression 

treatment, the permittee may clean the roadway dust with a vacuum sweeper in lieu of 

the wet suppression treatment.

(b) Compliance shall be demonstrated for each active haul road using records of haul road 

usage and control measures. The frequency of required roadway dust control treatments 

for haul roads with between one (1) and ten (10) truck trips per day shall be at least 

every other day, unless a treatment is not required for one of the reasons under (a) 

above. For haul roads with more than 10 trucks per day, the frequency shall be sufficient 

to achieve 90% control based on the following formula or an equivalent:

Control Efficiency = 96 – (0.263 * (T/C))

Where:

Control Efficiency = percent control efficiency

T = Daily truck trips on roadway (truck trips/calendar day)

C = Number of roadway dust control treatments per calendar day 

For the purposes of this formula, if at the time of a scheduled roadway dust control 

treatment, the treatment is not required for one of the reasons under (a) above, such an 

event shall be counted as a roadway dust control treatment.

(c) Haul truck speed limits on haul roads shall be posted as 15 miles per hour or less. 

Compliance Monitoring Requirements 

D.12.6 Ambient Temperature Monitoring

To demonstrate the compliance status with Condition D.12.5, the Permittee shall 

maintain an ambient temperature monitor when ambient temperatures may drop below 32o

F.

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

D.12.7 Record Keeping Requirements

To document the compliance status with Conditions D.12.4 - PM, PM10 and PM2.5 PSD BACT 

and Condition D.12.5 – Compliance Determination Requirements, the Permittee shall maintain 

the following daily records for haul roads:

(1) The number of trucks on the haul road each calendar day.

(2) The date, approximate time, and type of each roadway dust control treatment.
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(3) If a treatment is not required and not performed pursuant to D.12.5(a), records shall 

be maintained documenting the reason (i.e.: the ambient temperature, precipitation, 

already wet roads, haul road not used, etc.).
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SECTION D.13 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(g) One (1) slag handling storage pad, permitted in 2012, nominally rated at 43 tons per 

hour, identified as EU-034A, with fugitive particulate emissions controlled by wet 

suppression. 

(h) One (1) front-end loader activity on the slag storage pad, permitted in 2012, nominally 

rated at 1,440 tons per day, identified as EU-034C, with fugitive particulate emissions 

controlled by wet suppression. 

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.13.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.13.2 Effective Date of the Permit [IC 13-15-5-3]

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

D.13.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

D.13.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Frontend Loader Slag Handling (EU-034A) and Vehicle Dust on Slag Pile (EU-034C) shall be as 

follows:

The PM, PM10 and PM2.5 emissions from the Front-end Loader Slag Handling (EU-034A) and 

Vehicle Dust on Slag Pile (EU-034C) shall be controlled by a Wet Suppression or Chemical 

suppression with 90% control efficiency.
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Compliance Determination Requirements

D.13.5 Compliance Determination Requirements

To demonstrate compliance status with Condition D.13.4 - PM, PM10 and PM2.5 PSD BACT, wet 

suppression shall be applied weekly to the entire slag storage pile/pad. Dust control is aided by 

the fact that the incoming slag is inherently wet. Additional wet suppression should be applied if 

any visible emissions are observed. 

Wet suppression treatments of the slag pile area may be delayed until the next day whenever:

- It is raining or snowing at the time of the scheduled treatment,

- The ambient air temperature is at or below 32o

F, or 

- There is no material stored and no vehicle traffic at the temporary slag storage area.

Compliance Monitoring Requirements 

D.13.6 Ambient Temperature Monitoring

To demonstrate the compliance status with Conditions D.13.5, the Permittee shall 

maintain an ambient temperature monitor when ambient temperatures may drop below 32o

F.

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

D.13.7 Record Keeping Requirement

To document the compliance status with Conditions D.13.4 - PM, PM10 and PM2.5 PSD BACT 

and D.13.5 – Compliance Determination Requirements, the Permittee shall maintain the following 

weekly records:

(1) The date and approximate time of each feedstock pile watering treatment.

(2) If a treatment is not required and not performed pursuant to D.13.5, records shall be 

maintained documenting the reason (i.e.: the ambient temperature, precipitation, or there 

is no material stored and no vehicle traffic at the temporary slag storage area)
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SECTION D.14 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(L) Electrical Circuit Breakers (approximately six) containing sulfur hexafluoride (SF6) 

identified as emissions unit FUG-SF6, permitted in 2012, with fugitive GHG 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.)

Construction Conditions

General Construction Conditions

D.14.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.14.2 Effective Date of the Permit [IC 13-15-5-3]

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

D.14.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

D.14.4 GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the 

Electrical Circuit Breakers (FUG-SF6) shall be as follows:

The GHGs BACT for the Electrical Circuit Breaker (FUG-SF6) shall be the use of fully enclosed 

pressurized SF6 circuit breakers with leak detection (low pressure alarm). 
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SECTION D.15 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(M) Fugitive Equipment Leaks from the gasification, shift conversion, gas cooling, AGR,

CO2 compression, WSA, and methanation are identified as emissions unit FUG & 

FUG-WSA and will be controlled by a Leak Detection and Repair (LDAR) program.

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.15.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.15.2 Effective Date of the Permit [IC 13-15-5-3]

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

D.15.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

D.15.4 CO, H2SO4 SO2 and GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Fugitive 

Equipment Leaks from the gasification, shift conversion, gas cooling, AGR, CO2 compression,

WSA, and methanation, identified as emissions unit FUG & FUG-WSA shall be as follows:

(1) The BACT for fugitive leaks of CO and H2SO4 is no-controls. 

(2) The BACT for the fugitive leaks of SO2 in the WSA is the use of a Leak Detection and 

Repair (LDAR) program. 

(3) The BACT for fugitive GHG emissions is the use of a leak detection and repair (LDAR) 

program for the natural gas and SNG piping and weekly audio/visual inspection of the 

CO2 compressors while they are in operation in any week in which there are at least 

twenty-four (24) hours of operation of the CO2 compressor to be inspected. 

The LDAR program is incorporated into the permit in Section E.6
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D.15.5 Hazardous Air Pollutants (HAPs) Minor Limits

The single HAP and total HAPs from the Fugitive Equipment Leaks from the gasification, shift 

conversion, gas cooling, AGR, CO2 compression, WSA, and methanation identified as FUG & 

FUG-WSA shall be limited by compliance with the LDAR program incorporated in Section E.6 for 

equipment in methanol service and, combined with the potential to emit HAP emissions from all 

other emission units, this requirement will limit the potential to emit from this source to less than

ten (10) tons per year of any individual HAP and twenty-five (25) tons per year of any combination 

of HAPs and make the source an area source of HAPs.

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

D.15.6 Record Keeping Requirements

(a) In order to document the compliance status with Condition D.15.4(3), the Permittee shall 

maintain weekly records of the hours of operation each CO2 compressor.

(b) Section C - General Record Keeping Requirements contains the Permittee's 

obligations with regard to the record keeping required by this condition.
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SECTION D.16 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(g) Six (6) fixed roof sulfuric acid storage tanks, permitted in 2012, each with a nominal 

capacity of 866,500 gallons - identified as EU-027A through EU-027F.

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.16.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.16.2 Effective Date of the Permit [IC 13-15-5-3]

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

D.16.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

D.16.4 H2SO4 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the fixed 

roof sulfuric acid storage tanks, identified as EU-027A - EU-027F shall be as follows:

The H2SO4 emissions from the Sulfuric Acid tanks shall be limited by the use of a fixed roof tank 

and submerged fill.
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SECTION D.17 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(J) Methanol Tanks:

(1) One (1) Methanol De-Inventory Tank, with a nominal capacity of 700,000 

gallons, identified as EU-024, permitted in 2012, with emissions controlled by 

a vapor recovery system and exhausting through one (1) vent, identified as S024. [40 CFR 60 Subpart Kb]. 

(2) One (1) Fresh Methanol Storage Tank, with a nominal capacity of 332,000 

gallons, identified as EU-025, permitted in 2012, with emissions controlled by 

a vapor recovery system and exhausting through one (1) vent, identified as S025. [40 CFR 60 Subpart Kb].

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.17.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.17.2 Effective Date of the Permit [IC 13-15-5-3]

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

D.17.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

Compliance Determination Requirements

D.17.4 Vapor Recovery System

In order to ensure compliance, the vapor recovery system must be operated at all times when the 

methanol tanks, identified as EU-024 and EU-025 are in operation.
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Compliance Monitoring Requirements [326 IAC 2-7-5(1)][326 IAC 2-7-6(1)]

D.17.5 Vapor Recovery System Parametric Monitoring

(a) In order to ensure compliance, a continuous monitoring system shall be calibrated, 

maintained, and operated on each vapor recovery system for measuring the temperature

of the coolant. For the purposes of this condition, continuous monitoring means 

recording the temperature no less often than every 15 minutes. The output of this system 

shall be recorded as a three (3) hour average.

(b) The temperature of the coolant shall be maintained at or below zero (0) degree 

Fahrenheit or other temperature if demonstrated by stack test or engineering calculations 

to provide at least 95% control.

(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 above the above temperature in (b) 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.17.6 Record Keeping Requirements

In order to document the compliance status with Condition D.17.5, the Permittee shall maintain 

continuous temperature records (on a 3 - hour average basis) for each vapor recovery system to 

demonstrate compliance.
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SECTION D.18 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(N) One (1) ZLD Inert Gas Vent identified as EU-033, permitted in 2012, with mercury (Hg) 

emissions controlled by a sulfided carbon adsorbent identified as C-033, exhausting 

through one (1) stack, identified as S-033.

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

information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.18.1 Permit No Defense

This permit to construct does not relieve the Permittee of the responsibility to comply with the 

provisions of the Indiana Environmental Management Law (IC 13-11 through 13-20; 13-22 

through 13-25; and 13-30), the Air Pollution Control Law (IC 13-17) and the rules promulgated 

thereunder, as well as other applicable local, state, and federal requirements.

Effective Date of the Permit

D.18.2 Effective Date of the Permit [IC 13-15-5-3]

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

D.18.3 Modification to Construction Conditions [326 IAC 2]

All requirements of these construction conditions shall remain in effect unless modified in a 

manner consistent with procedures established for revisions pursuant to 326 IAC 2.

Operating Conditions

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

D.18.4 Hazardous Air Pollutants (HAPs) Control

The Permittee shall operate a carbon adsorber on the ZLD Inert Gas Vent. The carbon adsorber 

shall be used at all times the ZLD inert gas vent is in operation except during carbon adsorber

maintenance, repair or carbon replacement. The system shall be designed with a carbon

replacement interval of no less than once per year (based on maximum design flow rate and 

mercury concentration). 

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

D.18.5 Parametric Monitoring 

In order to demonstrate the compliance status with Condition D.18.4, the Permittee shall record 

the pressure drop across the Sulfided Carbon Adsorbent used on the ZLD Inert Gas Vent at least 

once per week when this unit is in operation. When the pressure drop exceeds the 

manufacturer’s recommended maximum pressure drop, the Permittee shall take appropriate 

action as soon as practicable and not later than during the next scheduled outage of the ZLD 

system. Actions may include replacement of the carbon, maintenance or repair. A pressure 
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reading that exceeds the manufacturer’s recommended maximum pressure drop is not a 

deviation from this permit. Failure to take response steps pursuant to this condition 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.18.6 Record Keeping Requirement

To document the compliance status with Condition D.18.5 - Parametric Monitoring, the Permittee 

shall maintain a weekly record of the pressure drop across the Sulfided Carbon Adsorbent 

controlling the ZLD Inert Gas Vent when venting to the atmosphere. The Permittee shall include 

in its weekly 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).
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SECTION E.1 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(G) Two (2) natural gas-fired auxiliary boilers, nominally rated at 408 MMBtu/hr HHV each, 

identified as EU-005A and EU-005B, permitted in 2012, with NOx emissions controlled 

by ultra-low NOx burners/Flue Gas Recirculation (ULNB/FGR), with both boilers 

exhausting through one (1) stack, identified as S-005. [Under 40 CFR 60, Subpart Db, 

the natural gas-fired auxiliary boilers are new affected source.]

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

information and does not constitute enforceable conditions.)

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

E.1.1 General Provisions Relating to NSPS Db [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 boilers described in this section except when otherwise 

specified in 40 CFR Part 60, Subpart Db.

E.1.2 Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units 

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

The Permittee who operates a steam generating unit that will commence construction, 

modification, or reconstruction after June 19, 1984, and that has a heat input capacity from fuels 

combusted in the steam generating unit of greater than 29 megawatts (MW) (100 MMBtu/hr) shall 

comply with the following provisions of 40 CFR Part 60, Subpart Db, included as Attachment C of 

this permit. The source is subject to the following portions of Subpart Db:

(1) 40 CFR 60.40b(a);

(2) 40 CFR 60.40b(j);

(3) 40 CFR 60.41b(b);

(4) 40 CFR 60.42b(k)(2);

(5) 40 CFR 60.44b(h);

(6) 40 CFR 60.44b(i);

(7) 40 CFR 60.44b(l);

(8) 40 CFR 60.46b(a); 

(9) 40 CFR 60.46b(c);

(10) 40 CFR 60.46b(e)(1);

(11) 40 CFR 60.46b(e)(3);

(12) 40 CFR 60.48b(b);

(13) 40 CFR 60.48b(c); 

(14) 40 CFR 60.48b(d);

(15) 40 CFR 60.48b(e)(2);

(16) 40 CFR 60.48b(e)(3);

(17) 40 CFR 60.48b(f);

(18) 40 CFR 60.49b(a);

(19) 40 CFR 60.49b(b);

(20) 40 CFR 60.49b(d);

(21) 40 CFR 60.49b(g); 
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(22) 40 CFR 60.49b(i); and

(23) 40 CFR 60.49b(o).
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SECTION E.2 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(J) Methanol Tanks:

(1) One (1) Methanol De-Inventory Tank, with a nominal capacity of 700,000 

gallons, identified as EU-024, permitted in 2012, with emissions controlled by 

a vapor recovery system and exhausting through one (1) vent, identified as S024. [40 CFR 60 Subpart Kb] 

(2) One (1) Fresh Methanol Storage Tank, with a nominal capacity of 332,000 

gallons, identified as EU-025, permitted in 2012, with emissions controlled by 

a vapor recovery system and exhausting through one (1) vent, identified as S025. [40 CFR 60 Subpart Kb]

(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 Part 60, Subpart Kb]

E.2.1 General Provisions Relating to NSPS Subpart Kb [326 IAC 12-1] [40 CFR 60, Subpart A]

Pursuant to 40 CFR Part 60, 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 storage tanks, identified as Methanol De-Inventory Tank and Fresh Methanol Storage Tank, 

except when otherwise specified in 40 CFR Part 60, Subpart Kb (Standards of Performance for 

Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which 

Construction, Reconstruction, or Modification Commenced After July 23, 1984).

E.2.2 Standard of Performance for Volatile Organic Liquid Storage Vessels (NSPS) [40 CFR 60, 

Subpart Kb] [326 IAC 12]

The Permittee, which operates the volatile organic liquid storage vessels designated as Methanol 

De-Inventory Tank and Fresh Methanol Storage Tank shall comply with the following provisions 

of 40 CFR Part 60, Subpart Kb (included as Attachment D of this permit), which are incorporated 

by reference as 326 IAC 12:

(1) 40 CFR 60.110b(a); 

(2) 40 CFR 60.110b(e); 

(3) 40 CFR 60.111b; 

(4) 40 CFR 60.112b(a)(3); 

(5) 40 CFR 60.112b(a)(4); 

(6) 40 CFR 60.113b(c);

(7) 40 CFR 60.114b(c);

(8) 40 CFR 60.115b(c);

(9) 40 CFR 60.116b(a);

(10) 40 CFR 60.116b(b);

(11) 40 CFR 60.116b(e); and

(12) 40 CFR 60.116b(g).
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SECTION E.3 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(A) Incoming solid feedstock materials handling system, transferring material from the 

barge unloading facility and railcar unloading facility to storage piles and day bins, 

consisting of: [Under 40 CFR 60, Subpart Y, the incoming solid feedstock materials 

handling system, transferring material from the barge unloading facility and railcar 

unloading facility to storage piles and day bins are new affected sources.]

(1) One (1) barge unloading to hopper transfer point, permitted in 2012, nominally 

rated at 750 tons per hour, identified as EU-012A, with particulate emissions 

controlled by wet suppression.

(2) The following twenty (20) transfer points, each with particulate emissions 

controlled with a dust extraction system or baghouse nominally rated at 1,500 

acfm: 

(a) One (1) barge unloading from the hopper to the belt, identified as EU012B, permitted in 2012, with one (1) control device, identified as C012B, exhausting through one (1) vent, identified as S-012B; 

(b) Four (4) barge conveyor transfer points, identified as EU-012C 

through EU-012F, permitted in 2012, with four (4) control devices, 

identified as C-012C through C-012F, respectively, exhausting 

through four (4) vents, identified as S-012C through S-012F, 

respectively; 

(c) Two (2) rail unloading to rail hoppers, identified as EU-012G and EU012H, permitted in 2012, with two (2) control devices, identified as C012G through C-012H, respectively, exhausting through two (2) 

vents, identified as S-012G through S-012H, respectively;

(d) Two (2) rail hoppers unloading to the conveyor belts, identified as EU012I and EU-012J, permitted in 2012, with two (2) control devices, 

identified as C-012I and C-012J, respectively, exhausting through two 

(2) vents, identified as S-012I through S-012J, respectively; 

(e) One (1) rail conveyor belt to the stacker, identified as EU-012K, 

permitted in 2012, with one (1) control device, identified as C-012K, 

exhausting through one (1) vent, identified as S-012K; 

(f) Two (2) stacker belts to the radial stacker, identified as EU-012L and 

EU-012M, permitted in 2012, with two (2) control devices, identified as 

C-012L and C-012M, respectively, exhausting through two (2) vents, 

identified as S-012L through S-012M, respectively; 
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(g) Two (2) classification towers, identified as EU-012T and EU-012U, 

permitted in 2012, with two (2) control devices, identified as C-012T 

and C-012U, respectively, exhausting through two (2) vents, identified 

as S-012T through S-012U, respectively; 

(h) One (1) classification tower to a day bin, identified as EU-012V, 

permitted in 2012, with one (1) control device, identified as C-012V, 

exhausting through one (1) vent, identified as S-012V;

(i) Three (3) truck stations unloading to a truck hopper, identified as EU012Z, EU-012AB and EU-012AC, permitted in 2012, with three (3) 

control devices, identified as C-012Z, C-012AB and C-012AC, 

respectively, exhausting through three (3) vents, identified as S-012Z, 

S-012AB and S-012AC, respectively;

(j) One (1) truck hopper unloading to the conveyor belts, identified as 

EU-012AA, permitted in 2012, with one (1) control device, identified as 

C-012AA exhausting through one (1) vent, identified as S-012AA; and 

(k) One (1) truck/rail conveyor transfer tower, identified as EU-012Y,

permitted in 2012, with one (1) control device, identified as C-012Y, 

exhausting through one (1) vent, identified as S-012Y; 

(3) Two (2) radial stackers to the pile, nominally rated at 3,000 tons per hour 

each, permitted in 2012, with particulate emissions controlled by telescoping 

chutes with two (2) fabric filters identified as C-012N and C-012O, exhausting 

through two (2) stacks, identified as S-012N and S-012O.

(4) Two (2) transfer systems consisting of hoppers and conveyor belts transferring 

feed stock from the piles to classification towers, identified as EU-012R and 

EU-012S, permitted in 2012, with particulate emissions controlled with two (2) 

dust extraction systems or baghouses, identified as C-012R and C-012S, 

respectively, each nominally rated at 6,000 acfm, exhausting through two (2) 

vents, identified as S-012R and S-012S, respectively.

(5) Two (2) dozer activities on the piles, nominally rated at 1,500 tons per hour 

each, identified as EU-012P and EU-012Q, permitted in 2012, with particulate 

emissions controlled by wet suppression. 

(6) Two (2) storage piles with a nominal capacity of 300,000 tons each, identified 

as EU-012W and EU-012X, permitted in 2012, with particulate emissions 

controlled by wet suppression and compaction. 

(B) Two (2) process area solid feedstock conveying, storage, and feed bins (main and 

spare), identified as EU-011A and EU-011B, permitted in 2012, with particulate 

emissions controlled by two (2) baghouses identified as C-011A and C-011B, 

respectively, each nominally rated at 33,760 dscfm, exhausting through two (2) stacks, 

identified as S-011A and S-011B, respectively. [Under 40 CFR 60, Subpart Y, the 
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process area solid feedstock conveying, storage, and feed bins (main and spare) are 

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 Part 60, Subpart Y]

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 

emission units identified as EU-012 A-AC and EU-011A-B, except as otherwise specified in 40 

CFR Part 60, Subpart Y.

E.3.2 New Source Performance Standards of Performance for Coal Preparation and Processing 

Plants Requirements [40 CFR Part 60, Subpart Y] [326 IAC 12] 

Pursuant to 40 CFR Part 60, Subpart Y, the Permittee shall comply with the provisions of New 

Source Performance Standards for Coal Preparation and Processing Plants, which are 

incorporated by reference as 326 IAC 12, (included as Attachment B of this permit), for the above 

emission units as specified as follows:

(1) 40 CFR 60.250(a); 

(2) 40 CFR 60.250(d); 

(3) 40 CFR 60.251; 

(4) 40 CFR 60.254(b); 

(4) 40 CFR 60.254(c);

(5) 40 CFR 60.255(b); 

(6) 40 CFR 60.255(c); 

(7) 40 CFR 60.255(d); 

(8) 40 CFR 60.255(e); 

(9) 40 CFR 60.255(f); 

(10) 40 CFR 60.255(g);

(11) 40 CFR 60.255(h);

(12) 40 CFR 60.256(b)(1);

(13) 40 CFR 60.256(b)(3);

(14) 40 CFR 60.256(c); 

(15) 40 CFR 60.257(a); 

(16) 40 CFR 60.258(a)(1); 

(17) 40 CFR 60.258(a)(2); 

(18) 40 CFR 60.258(a)(3;

(19) 40 CFR 60.258(a)(4); 

(20) 40 CFR 60.258(a)(5); 

(21) 40 CFR 60.258(a)(6); 

(22) 40 CFR 60.258(a)(7); 

(23) 40 CFR 60.258(a)(8); 

(24) 40 CFR 60.258(a)(10); 

(25) 40 CFR 60.258(b)(2); 

(26) 40 CFR 60.258(b)(3); 
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(27) 40 CFR 60.258(c); and 

(28) 40 CFR 60.258(d).
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SECTION E.4 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(a) Two (2) emergency diesel generators, each nominally rated at 1,341 horsepower, identified as 

EU-009A and EU-009B, permitted in 2012, exhausting through two (2) vents, identified as S009A and S-009B, respectively. [Under 40 CFR 60, Subpart IIII, emergency diesel fired 

generator is considered a new affected source.][Under 40 CFR 63, Subpart ZZZZ, 

emergency diesel fired generator is considered a new affected source.].

(b) Three (3) firewater pump diesel engines, each nominally rated at 575 horsepower and 

identified as EU-010A through EU-010C, permitted in 2012, exhausting through three (3) vents, 

identified as S-010A through S-010C, respectively. [Under 40 CFR 60, Subpart IIII, emergency 

diesel fired generator is considered a new affected source.][Under 40 CFR 63, Subpart ZZZZ, 

emergency diesel fired generator is considered a new affected source.].

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

information and does not constitute enforceable conditions.)

New Source Performance Standards [326 IAC 12] [40 CFR Part 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 generators and the firewater pump 

diesel engines 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 Attachment E of this permit. The source is subject to the following portions of Subpart IIII:

(1) 40 CFR 60.4200(a);

(2) 40 CFR 60.4205(b); 

(3) 40 CFR 60.4205(c);

(4) 40 CFR 60.4206;

(5) 40 CFR 60.4207(a);

(6) 40 CFR 60.4207(b);

(7) 40 CFR 60.4208(a);

(8) 40 CFR 60.4208(b);

(9) 40 CFR 60.4208(g);

(10) 40 CFR 60.4209(a);

(11) 40 CFR 60.4211(a);

(12) 40 CFR 60.4211(c);

(13) 40 CFR 60.4211(e);

(14) 40 CFR 60.4212(a);

(15) 40 CFR 60.4212(b);

(16) 40 CFR 60.4212(c);
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(17) 40 CFR 60.4214(b);

(18) 40 CFR 60.4218;

(19) 40 CFR 60.4219;

(20) Table 4 to Subpart IIII of Part 60 - Emission Standard for Stationary Fire Pump 

Engines;

(21) Table 5 to Subpart IIII of Part 60 - Labeling and Recordkeeping Requirements for 

New Stationary Emergency Engines;

(22) Table 6 to Subpart IIII of Part 60 - Optional 3-Mode Test Cycle for Stationary Fire 

Pump Engines; and

(23) Table 8 to Subpart IIII of Part 60 - Applicability of General Provisions to 

Subpart III.
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SECTION E.5 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(a) Two (2) emergency diesel generators, each nominally rated at 1,341 horsepower, 

identified as EU-009A and EU-009B, permitted in 2012, exhausting through two (2) 

vents, identified as S-009A and S-009B, respectively. [Under 40 CFR 60, Subpart IIII, 

each, emergency diesel fired generator is considered a new affected source.][Under 

40 CFR 63, Subpart ZZZZ, each, emergency diesel fired generator is considered a 

new affected source.]

(b) Three (3) firewater pump diesel engines, each nominally rated at 575 horsepower and 

identified as EU-010A through EU-010C, permitted in 2012, exhausting through three 

(3) vents, identified as S-010A through S-010C, respectively. [Under 40 CFR 60, 

Subpart IIII, each firewater pump diesel engine is considered a new affected 

source.][Under 40 CFR 63, Subpart ZZZZ, each firewater pump diesel engine is 

considered a new affected source.]

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

information and does not constitute enforceable conditions.)

National Emission Standards for Hazardous Air Pollutants (NESHAP) [40 CFR 63 Subpart ZZZZ]

E.5.1 National Emissisions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal 

Combustion Engines [326 IAC 20-82-1][40 CFR 63, Subpart ZZZZ]

The Permittee owns and operates stationary reciprocating internal combustion engines (RICE) 

located at an area source of HAP emissions shall comply with the following provisions of 40 CFR 

Part 63, Subpart ZZZZ, included as Attachment A of this permit. The source is subject to the 

following portions of Subpart ZZZZ:

(1) 40 CFR 63.6590(c)(1);
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SECTION E.6 LEAK DETECTION AND REPAIR (LDAR) CONDITIONS FOR THE FUGITIVE 

EQUIPMENTS LEAKS

Emissions Unit Description:

(M) Fugitive Equipment Leaks from the gasification, shift conversion, gas cooling, AGR,

CO2 compression, WSA and methanation are identified as emissions unit FUG-WSA

and will be controlled by a Leak Detection and Repair (LDAR) program.

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

information and does not constitute enforceable conditions.)

LDAR as BACT, Following National Emission Standards for Hazardous Air Pollutants (NESHAP) 

[40 CFR 63 Subpart H]

 

E.6.1 CO, H2SO4, SO2, and GHG PSD BACT [326 IAC 2-2-3] and Hazardous Air Pollutants (HAPs) 

Minor Limits

The source is not a major source of HAPs and is not subject to any of the MACT standards under 

40 CFR Part 63. However, in the context of the BACT determination for this source and the 

limitation of HAP emissions, the requirements of 40 CFR 63 Subpart H, addressing equipment 

leaks, that are listed below, apply to the pumps, compressors, pressure relief devices, sampling 

connection systems, open-ended valves or lines, valves, connectors, instrumentation systems, 

and control devices or systems that are in service at the facility for the following process streams: 

methanol streams, propylene streams, and product SNG streams. The same Subpart H 

requirements apply to any leaks of SO2 in the Wet Sulfuric Acid unit piping between the 

combustor and oxidation reactor, beginning with the connector at the combustor and ending with 

the connector at the oxidation reactor, except that references in the regulations to methane or 

VOCs will instead be applied to the pollutant SO2. These requirements apply to the above listed 

streams irrespective of the HAP content of the specified streams.

1. 40 CFR 63.161;

2. 40 CFR 63.162(a);

3. 40 CFR 63.162(c);

4. 40 CFR 63.162(d); 

5. 40 CFR 63.162(f); 

6. 40 CFR 63.162(g); 

7. 40 CFR 63.162(h);

8. 40 CFR 63.163; 

9. 40 CFR 63.164; 

10. 40 CFR 63.165;

11. 40 CFR 63.166

12. 40 CFR 63.167; 

13. 40 CFR 63.168; 

14. 40 CFR 63.169; 

15. 40 CFR 63.170; 

16. 40 CFR 63.171; 

17. 40 CFR 63.172; 

18. 40 CFR 63.173; and

19. 40 CFR 63.174. 
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The alternative quality improvement program for valves under 40 CFR 63.175 and pumps under 

40 CFR 63.176 may be used in lieu of the specified requirements of 40 CFR 63.168 and 40 CFR 

63.163. The source may apply any alternative method approved by the EPA Administrator under 

40 CFR 63.177(e) with written notification to IDEM 30 days in advance of the use of the 

alternative method. That notification shall include a copy of the EPA approval of the alternative 

method and an indication of where at the plant the alternative will be applied.

The test methods and procedures used shall be those delineated under 40 CFR 63.180. For the 

SO2 monitoring of the components in the Wet Sulfuric Acid (WSA), references to methane or 

VOCs in 40 CFR 63.180 or 40 CFR 60 Appendix A, Method 21 shall be applied instead to the 

pollutant SO2. If a monitor is used that has a range lower than the defined leak rate, then any 

reading within 90% of the monitor’s range shall be treated as a leak.

For Greenhouse Gases BACT any leakage determined by audio/visual or other inspection shall 

be repaired within the time frames specified in 40 CFR 63.164 (g) except as provided by 63.171.

Recordkeeping shall conform to the provisions of 40 CFR 63.181.
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INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY

COMPLIANCE AND ENFORCEMENT BRANCH

PART 70 OPERATING PERMIT

CERTIFICATION

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

This certification shall be included when submitting monitoring, testing reports/results or other 

documents as required by this permit.

Please check what document is being certified:

 Annual Compliance Certification Letter

 Test Result (specify) 

 Report (specify) 

 Notification (specify) 

 Affidavit (specify) 

 Other (specify) 

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

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

Signature:

Printed Name:

Title/Position:

Phone:

Date:
Indiana Gasification, LLC Page 131 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

Phone: (317) 233-0178

Fax: (317) 233-6865

PART 70 OPERATING PERMIT

EMERGENCY OCCURRENCE REPORT

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

This form consists of 2 pages Page 1 of 2 

 This is an emergency as defined in 326 IAC 2-7-1(12)

• The Permittee must notify the Office of Air Quality (OAQ), within four (4) business 

hours (1-800-451-6027 or 317-233-0178, ask for Compliance Section); and

• The Permittee must submit notice in writing or by facsimile within two (2) working days 

(Facsimile Number: 317-233-6865), and follow the other requirements of 

326 IAC 2-7-16.

If any of the following are not applicable, mark N/A

Facility/Equipment/Operation:

Control Equipment:

Permit Condition or Operation Limitation in Permit:

Description of the Emergency:

Describe the cause of the Emergency: 
Indiana Gasification, LLC Page 132 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

If any of the following are not applicable, mark N/A Page 2 of 2

Date/Time Emergency started:

Date/Time Emergency was corrected:

Was the facility being properly operated at the time of the emergency? Y N

Type of Pollutants Emitted: TSP, PM-10, SO2, VOC, NOX, CO, Pb, other:

Estimated amount of pollutant(s) emitted during emergency:

Describe the steps taken to mitigate the problem:

Describe the corrective actions/response steps taken:

Describe the measures taken to minimize emissions:

If applicable, describe the reasons why continued operation of the facilities are necessary to prevent 

imminent injury to persons, severe damage to equipment, substantial loss of capital investment, or loss 

of product or raw materials of substantial economic value:

Form Completed by:

Title / Position:

Date:

Phone: 

 
Indiana Gasification, LLC Page 133 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: Syngas Hydrocarbon Flare 

Parameter: SO2 emission during Shutdown event 

Limit: not exceed 1.92 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month. 

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 
Indiana Gasification, LLC Page 134 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: Syngas Hydrocarbon Flare 

Parameter: SO2 emission during Startup event 

Limit: not exceed 0.05 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 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 Gasification, LLC Page 135 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: Wet Sulfuric Acid Plant

Parameter: CO2 Emissions

Limit: shall not exceed 474,000 tons per twelve (12) consecutive month period with 

compliance determine at the end of each month

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
Indiana Gasification, LLC Page 136 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: Auxiliary Boilers

Parameter: Natural Gas Throughput

Limit: Shall not exceed 1,430 billion Btu per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
Indiana Gasification, LLC Page 137 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: Gasifier Pre-heater Burners

Parameter: CO2 Emissions

Limit: shall not exceed 6,438 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
Indiana Gasification, LLC Page 138 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: ZLD Sprayer Dryer

Parameter: CO2 Emissions

Limit: shall not exceed 2,884 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
Indiana Gasification, LLC Page 139 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: Emergency Diesel Engines (Use one form for each engine)

Parameter: Number of Hours

Limit: for each engine shall not exceed 52 hours per twelve (12) consecutive month 

period with compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
Indiana Gasification, LLC Page 140 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: Emergency Diesel Engines

Parameter: CO2 Emissions

Limit: shall not exceed 84 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
Indiana Gasification, LLC Page 141 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: Auxiliary Boilers

Parameter: CO2 Emissions

Limit: shall not exceed 88,164 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
Indiana Gasification, LLC Page 142 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: Acid Gas Removal Unit Vents (EU-007A/B)

Parameter: CO2 Emissions

Limit: shall not exceed 4,960,000 tons during the first 12 months of operation.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous Months of 

this 12-month 

period

To-date 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 Gasification, LLC Page 143 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: Acid Gas Removal Unit Vents (EU-007A/B)

Parameter: CO2 Emissions

Limit: shall not exceed 6,430,000 tons during the second 12 months of operation.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous months of 

this 12- Month

period

To-date 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 Gasification, LLC Page 144 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: Acid Gas Removal Unit Vents (EU-007A/B)

Parameter: CO2 Emissions

Limit: shall not exceed 1,290,000 tons during the third 12 months of operation.

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous months of 

the 12-Month

period

To-date 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 Gasification, LLC Page 145 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: Acid Gas Removal Unit Vents (EU-007A/B)

Parameter: CO2 Emissions

Limit: shall not exceed 1,290,000 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 months of 

the 12-Month

period

To-date 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 Gasification, LLC Page 146 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: Acid Gas Removal Unit Vents (EU-007A/B)

Parameter: Single HAPs Emissions (Methanol)

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: 

 
Indiana Gasification, LLC Page 147 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: Acid Gas Removal Unit Vents (EU-007A/B)

Parameter: Single HAPs Emissions (Carbonyl Sulfide)

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: 
Indiana Gasification, LLC Page 148 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

 

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: Acid Gas Removal Unit Vents (EU-007A/B)

Parameter: Total HAPs Emissions 

Limit: less than 17 tons per twelve (12) consecutive month period with 

compliance determined at the end of each month. 

QUARTER : YEAR: 

Month

Column 1 Column 2 Column 1 + Column 2

This Month Previous 11 Months 12 Month Total

Month 1

Month 2

Month 3

 No deviation occurred in this quarter.

 Deviation/s occurred in this quarter.

 Deviation has been reported on: 

Submitted by:

Title / Position:

Signature:

Date: 

Phone: 

 
Indiana Gasification, LLC Page 149 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

PART 70 OPERATING PERMIT

QUARTERLY DEVIATION AND COMPLIANCE MONITORING REPORT

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Months: to Year: 

Page 1 of 2

This report shall be submitted quarterly based on a calendar year. Any deviation from the 

requirements of this permit, the date(s) of each deviation, the probable cause of the deviation, and 

the response steps taken must be reported. A deviation required to be reported pursuant to an 

applicable requirement that exists independent of the permit, shall be reported according to the 

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

Additional pages may be attached if necessary. If no deviations occurred, please specify in the box 

marked "No deviations occurred this reporting period".

 NO DEVIATIONS OCCURRED THIS REPORTING PERIOD.

 THE FOLLOWING DEVIATIONS OCCURRED THIS REPORTING PERIOD

Permit Requirement (specify permit condition #)

Date of Deviation: Duration of Deviation:

Number of Deviations:

Probable Cause of Deviation:

Response Steps Taken:

Permit Requirement (specify permit condition #)

Date of Deviation: Duration of Deviation:

Number of Deviations:

Probable Cause of Deviation:

Response Steps Taken:
Indiana Gasification, LLC Page 150 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

Page 2 of 2

Permit Requirement (specify permit condition #)

Date of Deviation: Duration of Deviation:

Number of Deviations:

Probable Cause of Deviation:

Response Steps Taken:

Permit Requirement (specify permit condition #)

Date of Deviation: Duration of Deviation:

Number of Deviations:

Probable Cause of Deviation:

Response Steps Taken:

Permit Requirement (specify permit condition #)

Date of Deviation: Duration of Deviation:

Number of Deviations:

Probable Cause of Deviation:

Response Steps Taken:

Form Completed by:

Title / Position:

Date:

Phone: 

 
Indiana Gasification, LLC Page 151 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

Mail to: Permit Administration and Support Section

Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

Indiana Gasification, LLC

CR 200 N and Base Road

Rockport, Indiana 47635

Affidavit of Construction

I, , being duly sworn upon my oath, depose and say:

(Name of the Authorized Representative)

1. I live in County, Indiana and being of sound mind 

and over twenty-one (21) years of age, I am competent to give this affidavit.

2. I hold the position of for .

 (Title) (Company Name)

3. By virtue of my position with , I have personal

(Company Name)

knowledge of the representations contained in this affidavit and am authorized to make

these representations on behalf of .

(Company Name)

4. I hereby certify that Indiana Gasification, LLC CR 200 N and Base Road, Rockport, 

Indiana 47635, completed construction of the natural gas (SNG) and liquefied carbon 

dioxide (CO2) production plant on in conformity with the 

requirements and intent of the construction permit application received by the Office of 

Air Quality on April 20, 2011 and as permitted pursuant to New Source Construction 

Permit and Part 70 Operating Permit No. T147-30464-00060, Plant ID No. 147-00060

issued on .

5. Permittee, please cross out the following statement if it does not apply: Additional 

(operations/facilities) were constructed/substituted as described in the attachment to this 

document and were not made in accordance with the construction permit. 

Further Affiant said not.

I affirm under penalties of perjury that the representations contained in this affidavit are true, to the best of 

my information and belief.

Signature

Date

STATE OF INDIANA)

 )SS
Indiana Gasification, LLC Page 152 of 152

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

COUNTY OF )

Subscribed and sworn to me, a notary public in and for County and 

State of Indiana on this day of , 20 . My 

Commission expires: .

Signature

Name (typed or 

printed)
Indiana Gasification, LLC Analysis of Lead Emissions

Lead Emissions: Lead is present in trace amounts in the coal and petroleum coke that are fed 

to the IG gasifiers. Coal, coke, and the natural gas that is used as fuel are the only potential 

sources of air emissions of lead at the IG facility. Although both coal and coke have very low 

levels of lead content, coal has the greater lead content. Therefore, in this assessment of 

emissions, the analysis assumes operation on 100% coal.

The highest lead concentration in Indiana coal reported by the Indiana Geological Survey was 

167 ppm by weight on a dry basis. This concentration equates to 145 pounds of lead per hour 

entering the IG gasifier, based on 433 tons per hour of dry coal feed. 

When coal is combusted at a power plant, much of the lead is contained in the fly ash and bottom 

ash but some is emitted in the particulate emissions of the power plant. At the IG facility the coal 

is gasified rather than combusted and particulate emissions containing lead do not occur. 

Instead, the lead and certain other metals are substantially removed during the separation of 

solids from the raw gas and the purification of the gas for conversion to substitute natural gas 

(SNG). Approximately 33% of the lead ends up in the slag removed from the bottom of the 

gasifier and is managed as a by-product and shipped off site. Whatever small amount of lead 

that remains is contained in the syngas. As a result of the temperature and pressure of the 

quenched syngas, the lead is almost all present as a solid. This solid lead is then removed 

through the following sequence of processing the syngas to SNG:

1) Syngas water scrubbing

2) Filtering in the shift catalyst bed (about 70% of raw syngas)

3) Filtering in the sulfide carbon bed, that is used to remove mercury

4) Syngas water scrubbing in Rectisol ammonia absorber

5) Syngas methanol scrubbing in Rectisol main absorber

6) Filtering in Guard Bed which is upstream of the Methanation Reactors

7) Filtering in the Methanation Reactor catalyst beds that are in series

The particulate matter, including the lead, removed by these steps ends up in spent catalyst, 

spend sulfided carbon, spent sulfur guard adsorbent, and spent filter media which will be 

managed as waste and shipped off-site.

A very small concentration of lead remains as vapor in the SNG, 2.90E-06 lb lead per million BTU 

HHV. The lead content of natural gas is 4.90E-07 lb lead per million BTU HHV natural gas 

according to EPA’s AP-42 factor for natural gas combustion. Accordingly, as presented in the 

lead and mercury spreadsheets, attached, the maximum emissions of lead from the use of SNG 

and natural gas at the site are about 6.6 lbs/year.

The other source of lead emissions is the lead present in particulate emissions from the coal 

handling, conveying and mill operation. As presented in the attached spreadsheet, the maximum 

emissions of lead in the coal dust are estimated to be an additional 5.7 lbs/year for a plant wide 

total of 12.3 lbs/year of lead emissions.

PSD Non-Applicability for Lead Emissions: The PSD significant emissions rate for lead 

emissions is 0.6 tons/yr. Because the Indiana Gasification facility total lead emissions are well 

below this level, the PSD regulations require no further analysis for lead emissions. 
Indiana Gasification, LLC Analysis of Mercury Emissions

Mercury is present in trace amounts in the coal and the petroleum coke that are fed to the 

gasifiers. The coal and coke used as feedstocks and natural gas fuel are the sole sources of 

mercury that has the potential to be emitted to the air. While both coal and coke have very low 

levels of mercury; of the two, coal has the greater mercury content. Therefore, in this 

assessment of emissions, the analysis assumes operation on 100% coal.

The highest mercury concentration reported by the Indiana Geological Survey for Indiana coal is 

0.86 ppm by weight on a dry basis. This is equivalent to 0.745 pounds of mercury per hour 

entering the gasifier, based on 433 tons per hour of dry coal feed. 

When coal is combusted at a power plant, much of the mercury is vaporized. Some is chemically 

bound in ash and the rest is emitted. At the IG facility, the coal is gasified rather than combusted 

and those emissions do not occur. Instead, most of the mercury remains as a vapor in the 

syngas. That mercury is substantially removed during the purification of the syngas for 

conversion to substitute natural gas (SNG). This is done by passing the syngas through sulfided 

carbon beds where the mercury is captured. The sulfided carbon beds are periodically replaced 

and the spent beds are shipped off site for disposal.

A very small amount of the mercury may be present in the product SNG. As a conservative 

estimate of what remains, we have used the vendor guaranteed performance of the sulfide 

carbon guard beds. This translates to a SNG emission factor for mercury of 1.65 lb/1012 Btu 

HHV. This is the factor used to determine maximum emissions of mercury when product SNG is 

used at the site. On occasions, purchased natural gas is also used. The mercury content of 

natural gas is estimated at 0.26 lb/1012 Btu HHV. As presented in the lead and mercury 

spreadsheets, attached, the maximum emissions of mercury from the use of SNG and natural 

gas at the site are estimated to be 3.74 lbs/year.

Some of the mercury also ends up in the quench water which is sent to the Zero Liquid Discharge 

(ZLD) system. The mercury in the wastewater is then released in the evaporization and 

crystalization system into an inert gas stream which is also treated with a sulfided carbon 

adsorption bed. This sulfided carbon bed is also periodically replaced and the spent sorbent is 

shipped off site for proper disposal. The inert gas vent on the ZLD system is at a very low flow 

and due to the treatment with the sulfided carbon filter; it represents only 0.72 lbs/year of mercury 

emissions. 

The remaining source of mercury emissions is the mercury present in particulate emissions from 

the coal handling, conveying and milling operations. As presented in the attached spreadsheet, 

the maximum emissions of mercury in the coal dust are another 0.03 lbs/year for a plant wide 

total of 4.6 lbs/year of mercury emissions. 
Appendix G: Fugitive Coal and Particulate Matter Dust Emissions Control Plan

Indiana Gasification, LLC

CR 200 North and Base Road

Rockport, Indiana 47635

Introduction

This Fugitive Coal Dust Emissions Control Plan meets the requirements of 40 CFR 60, Subpart Y –

Standards for coal processing and conveying equipment, coal storage system, transfer and loading 

systems, and open storage piles. This plan addresses fugitive coal dust emissions from:

- Barge unloading to hopper, nominally rated at 750 tons per hour, identified as EU-012A; 

- Dozer activities on the piles, nominally rated at 1,500 tons per hour each, identified as EU-012P 

and EU-012Q; and

- Incoming feedstock storage piles, with a nominal capacity of 300,000 tons each, identified as EU012W and EU-012X. 

Additionally, this plan meets the requirements of 326-IAC-6-5 - Fugitive Particulate Matter Emissions 

Limitations as it applies to the above listed sources as well as the following non-coal fugitive dust 

emission sources:

- Paved Plant Haul Roads (FUG-ROAD); 

- Slag Handling Storage Pad, nominally rated at 43 tons per hour, identified as EU-034A; and

- Front-end Loader on the Slag Storage Pad, nominally rated at 1,440 tons per day, identified as 

EU-034C. 

Other material handling and conveyance operations at the site will be enclosed and routed to control 

equipment. As such, they are not sources of fugitive particulate emissions and are not addressed in this 

plan. 

Two maps showing fugitive dust sources at the facility are attached. Although the conveyors and transfer 

points are enclosed and routed to control equipment and therefore are not fugitive dust sources, they are 

represented on the maps pursuant to 326 IAC 6-5-5(a). 

Indiana Gasification, LLC is responsible for the execution this plan.

Description of Control Measures to be Used

Barge Unloading [EU-012A]

Coal received by barge will be unloaded by a crane and hopper arrangement mounted on a floating 

barge. The crane will swivel and dump the material into the surge hopper. Because the crane is on a 

floating barge and swivels to unload coal from a barge onto land, the most appropriate control measure is 

wet suppression. Water sprays will be used on an “as-needed” basis to reduce fugitive coal dust 

emissions. Also, the hopper into which the coal is dropped will be partially enclosed. It will have an open 

top for accepting the coal, but the sides will be higher than the level of the feedstock (coal) inside which 
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will serve to help contain emissions. Wet suppression with water sprays and partial enclosure are the 

only practical methods of control for this type of source.

Dozer Activities on Piles [EU-012P and EU-012Q]

Fugitive coal dust emissions from dozer activities on piles will be controlled by wet suppression and 

compaction. Due to the large size of the piles, they can’t reasonably be enclosed or controlled by any 

other method.

Coal/Coke Storage Piles [EU-012W and EU-012X]

The storage piles shall be sprayed with water on an “as-needed” basis to reduce fugitive coal dust 

emissions. In addition, compaction will be implemented on the piles to further control fugitive coal dust 

emissions. Due to the large size of the piles, they can’t reasonably be enclosed or controlled by any other 

method.

Equipment used to maintain the pile: A bull dozer or front end loader such as a Caterpillar 824H Wheel 

Dozer.

Paved Plant Haul Roads [FUG-ROAD]

The number and mix of vehicular traffic on plant haul roads is anticipated to be as follows:

- Coal/Coke Haul Trucks: Max. 187 trucks per day, Avg. 36,800 trucks/year, average 25.7 

tons/truck. 

- Other haul vehicles/parking lots: Equivalent to Max. 83 trucks per day, average 19.7 tons/truck. 

Fugitive dust emissions from vehicular traffic on paved plant haul roads will be controlled on an “asneeded” basis by the use of:

1. Paving all plant roads;

2. Use of wet suppression; 

3. Prompt cleanup of any spilled materials that may create fugitive dust; and

4. Pursuant to 326 IAC 6-5-4(e), fugitive particulate matter emissions resulting from 

transportation of aggregate material by truck, front end loaders, or similar vehicles shall 

be controlled using one or more of the following measures:

a. Use of completely enclosed vehicles;

b. Tarping the vehicle;

c. Maintaining the vehicle body in such a condition that prevents leaks of aggregate 

 material; 

d. Spraying the materials in the vehicle with a suitable and effective dust suppressant; or

e. An alternate measure.

Slag Handling Storage Pad [EU-034A] and Front-end Loader on the Slag Storage Pad [EU-034C]

Fugitive dust emissions from the Slag Handling Storage Pad and Front-end Loader on the Slag Storage 

Pad shall be controlled on an “as-needed” basis by wet suppression. 

Equipment used to maintain the pile: A bull dozer or front end loader such as a Caterpillar 824H Wheel 

Dozer.
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Dust Suppressant Material

For the above controls which specify the use of wet suppression, Indiana Gasification currently plans to 

use water. Prior to using any chemical suppressant (with or instead of water), Indiana Gasification will 

provide the specifications for that material to IDEM OAQ for review and approval.

Recordkeeping

Records shall be kept and maintained which document all control measures and activities to be 

implemented in accordance with the approved control plan. Said records shall be available upon the 

request of the commissioner, and shall be retained for three (3) years.

Compliance Schedule

For the fugitive coal dust sources subject to Subpart Y, this plan shall be fully implemented upon startup 

pursuant to Subpart Y. For sources subject to 326 IAC 6-5, this plan shall be implemented when the 

facility commences operation. 

For the fugitive coal dust sources subject to Subpart Y, this plan shall be revised as needed to reflect any 

changing conditions at the facility. Such revisions will be dated and submitted to the Indiana Department 

of Environmental Management before operation pursuant to the revisions. For sources subject to 326 IAC 

6-5, this plan shall be updated at the time of reapplication for the source's operation permit or as required 

in 326 IAC 2.
Attachment A to a PSD/Part 70 Operating Permit

40 CFR 63, Subpart ZZZZ—National Emission Standards for 

Hazardous Air Pollutants for Stationary Reciprocating Internal 

Combustion Engines:

Source Name: Indiana Gasification LLC

Source Location: CR 200 N and Base Road, Rockport, IN 47635

County: Spencer

SIC Code: 4925, 2819

Operation Permit No.: T 147-30464-00060

Operation Permit Issuance Date: Yet to be Issued

Permit Reviewer: Josiah Balogun

Subpart ZZZZ—National Emissions Standards for Hazardous Air Pollutants for 

Stationary Reciprocating Internal Combustion Engines

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

What This Subpart Covers

§ 63.6580 What is the purpose of subpart ZZZZ?

Subpart ZZZZ establishes national emission limitations and operating limitations for hazardous air pollutants (HAP) emitted from 

stationary reciprocating internal combustion engines (RICE) located at major and area sources of HAP emissions. This subpart 

also establishes requirements to demonstrate initial and continuous compliance with the emission limitations and operating 

limitations.

[73 FR 3603, Jan. 18, 2008]

§ 63.6585 Am I subject to this subpart?

You are subject to this subpart if you own or operate a stationary RICE at a major or area source of HAP emissions, except if the 

stationary RICE is being tested at a stationary RICE test cell/stand.

(a) A stationary RICE is any internal combustion engine which uses reciprocating motion to convert heat energy into mechanical 

work and which is not mobile. Stationary RICE differ from mobile RICE in that a stationary RICE is not a non-road engine as 

defined at 40 CFR 1068.30, and is not used to propel a motor vehicle or a vehicle used solely for competition.

(b) A major source of HAP emissions is a plant site that emits or has the potential to emit any single HAP at a rate of 10 tons (9.07 

megagrams) or more per year or any combination of HAP at a rate of 25 tons (22.68 megagrams) or more per year, except that 

for oil and gas production facilities, a major source of HAP emissions is determined for each surface site.

(c) An area source of HAP emissions is a source that is not a major source.

(d) If you are an owner or operator of an area source subject to this subpart, your status as an entity subject to a standard or other 

requirements under this subpart does not subject you to the obligation to obtain a permit under 40 CFR part 70 or 71, provided 

you are not required to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a) for a 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 
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as applicable.

(e) If you are an owner or operator of a stationary RICE used for national security purposes, you may be eligible to request an 

exemption from the requirements of this subpart as described in 40 CFR part 1068, subpart C.

[69 FR 33506, June 15, 2004, as amended at 73 FR 3603, Jan. 18, 2008]

§ 63.6590 What parts of my plant does this subpart cover?

This subpart applies to each affected source.

(a) Affected source. An affected source is any existing, new, or reconstructed stationary RICE located at a major or area source of 

HAP emissions, excluding stationary RICE being tested at a stationary RICE test cell/stand.

(1) Existing stationary RICE. 

(i) For stationary RICE with a site rating of more than 500 brake horsepower (HP) located at a major source of HAP emissions, a 

stationary RICE is existing if you commenced construction or reconstruction of the stationary RICE before December 19, 2002.

(ii) For stationary RICE with a site rating of less than or equal to 500 brake HP located at a major source of HAP emissions, a 

stationary RICE is existing if you commenced construction or reconstruction of the stationary RICE before June 12, 2006.

(iii) For stationary RICE located at an area source of HAP emissions, a stationary RICE is existing if you commenced construction 

or reconstruction of the stationary RICE before June 12, 2006.

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

RICE.

(2) New stationary RICE. (i) A stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP 

emissions is new if you commenced construction of the stationary RICE on or after December 19, 2002.

(ii) A stationary RICE with a site rating of equal to or less than 500 brake HP located at a major source of HAP emissions is new if 

you commenced construction of the stationary RICE on or after June 12, 2006.

(iii) A stationary RICE located at an area source of HAP emissions is new if you commenced construction of the stationary RICE 

on or after June 12, 2006.

(3) Reconstructed stationary RICE. (i) A stationary RICE with a site rating of more than 500 brake HP located at a major source of 

HAP emissions is reconstructed if you meet the definition of reconstruction in §63.2 and reconstruction is commenced on or after 

December 19, 2002.

(ii) A stationary RICE with a site rating of equal to or less than 500 brake HP located at a major source of HAP emissions is 

reconstructed if you meet the definition of reconstruction in §63.2 and reconstruction is commenced on or after June 12, 2006.

(iii) A stationary RICE located at an area source of HAP emissions is reconstructed if you meet the definition of reconstruction in 

§63.2 and reconstruction is commenced on or after June 12, 2006.

(b) Stationary RICE subject to limited requirements. (1) An affected source which meets either of the criteria in paragraphs

(b)(1)(i) through (ii) of this section does not have to meet the requirements of this subpart and of subpart A of this part except for 

the initial notification requirements of §63.6645(f).

(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.
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(ii) The stationary RICE is a new or reconstructed limited use stationary RICE with a site rating of more than 500 brake HP located 

at a major source of HAP emissions.

(2) A new or reconstructed stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP 

emissions which combusts landfill or digester gas equivalent to 10 percent or more of the gross heat input on an annual basis 

must meet the initial notification requirements of §63.6645(f) and the requirements of §§63.6625(c), 63.6650(g), and 63.6655(c). 

These stationary RICE do not have to meet the emission limitations and operating limitations of this subpart.

(3) The following stationary RICE do not have to meet the requirements of this subpart and of subpart A of this part, including 

initial notification requirements:

(i) Existing spark ignition 2 stroke lean burn (2SLB) stationary RICE with a site rating of more than 500 brake HP located at a 

major source of HAP emissions;

(ii) Existing spark ignition 4 stroke lean burn (4SLB) stationary RICE with a site rating of more than 500 brake HP located at a 

major source of HAP emissions;

(iii) Existing emergency stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions;

(iv) Existing limited use stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions;

(v) Existing stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions that 

combusts landfill gas or digester gas equivalent to 10 percent or more of the gross heat input on an annual basis;

(vi) Existing residential emergency stationary RICE located at an area source of HAP emissions;

(vii) Existing commercial emergency stationary RICE located at an area source of HAP emissions; or

(viii) Existing institutional emergency stationary RICE located at an area source of HAP emissions.

(c) Stationary RICE subject to Regulations under 40 CFR Part 60. An affected source that meets any of the criteria in paragraphs 

(c)(1) through (7) of this section must meet the requirements of this part by meeting the requirements of 40 CFR part 60 subpart 

IIII, for compression ignition engines or 40 CFR part 60 subpart JJJJ, for spark ignition engines. No further requirements apply for 

such engines under this part.

(1) A new or reconstructed stationary RICE located at an area source;

(2) A new or reconstructed 2SLB stationary RICE with a site rating of less than or equal to 500 brake HP located at a major 

source of HAP emissions;

(3) A new or reconstructed 4SLB stationary RICE with a site rating of less than 250 brake HP located at a major source of HAP

emissions;

(4) A new or reconstructed spark ignition 4 stroke rich burn (4SRB) stationary RICE with a site rating of less than or equal to 500 

brake HP located at a major source of HAP emissions;

(5) A new or reconstructed stationary RICE with a site rating of less than or equal to 500 brake HP located at a major source of 

HAP emissions which combusts landfill or digester gas equivalent to 10 percent or more of the gross heat input on an annual 

basis;

(6) A new or reconstructed emergency or limited use stationary RICE with a site rating of less than or equal to 500 brake HP 

located at a major source of HAP emissions;

(7) A new or reconstructed compression ignition (CI) stationary RICE with a site rating of less than or equal to 500 brake HP

located at a major source of HAP emissions.
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[69 FR 33506, June 15, 2004, as amended at 73 FR 3604, Jan. 18, 2008; 75 FR 9674, Mar. 3, 2010; 75 FR 37733, June 30, 

2010; 75 FR 51588, Aug. 20, 2010]

§ 63.6595 When do I have to comply with this subpart?

(a) Affected sources. (1) If you have an existing stationary RICE, excluding existing non-emergency CI stationary RICE, with a site 

rating of more than 500 brake HP located at a major source of HAP emissions, you must comply with the applicable emission 

limitations and operating limitations no later than June 15, 2007. If you have an existing non-emergency CI stationary RICE with a 

site rating of more than 500 brake HP located at a major source of HAP emissions, an existing stationary CI RICE with a site 

rating of less than or equal to 500 brake HP located at a major source of HAP emissions, or an existing stationary CI RICE 

located at an area source of HAP emissions, you must comply with the applicable emission limitations and operating limitations no 

later than May 3, 2013. If you have an existing stationary SI RICE with a site rating of less than or equal to 500 brake HP located 

at a major source of HAP emissions, or an existing stationary SI RICE located at an area source of HAP emissions, you must 

comply with the applicable emission limitations and operating limitations no later than October 19, 2013.

(2) If you start up your new or reconstructed stationary RICE with a site rating of more than 500 brake HP located at a major

source of HAP emissions before August 16, 2004, you must comply with the applicable emission limitations and operating 

limitations in this subpart no later than August 16, 2004.

(3) If you start up your new or reconstructed stationary RICE with a site rating of more than 500 brake HP located at a major

source of HAP emissions after August 16, 2004, you must comply with the applicable emission limitations and operating 

limitations in this subpart upon startup of your affected source.

(4) If you start up your new or reconstructed stationary RICE with a site rating of less than or equal to 500 brake HP located at a 

major source of HAP emissions before January 18, 2008, you must comply with the applicable emission limitations and operating

limitations in this subpart no later than January 18, 2008.

(5) If you start up your new or reconstructed stationary RICE with a site rating of less than or equal to 500 brake HP located at a 

major source of HAP emissions after January 18, 2008, you must comply with the applicable emission limitations and operating 

limitations in this subpart upon startup of your affected source.

(6) If you start up your new or reconstructed stationary RICE located at an area source of HAP emissions before January 18, 

2008, you must comply with the applicable emission limitations and operating limitations in this subpart no later than January 18, 

2008.

(7) If you start up your new or reconstructed stationary RICE located at an area source of HAP emissions after January 18, 2008, 

you must comply with the applicable emission limitations and operating limitations in this subpart upon startup of your affected 

source.

(b) Area sources that become major sources. If you have an area source that increases its emissions or its potential to emit such 

that it becomes a major source of HAP, the compliance dates in paragraphs (b)(1) and (2) of this section apply to you.

(1) Any stationary RICE for which construction or reconstruction is commenced after the date when your area source becomes a 

major source of HAP must be in compliance with this subpart upon startup of your affected source.

(2) Any stationary RICE for which construction or reconstruction is commenced before your area source becomes a major source 

of HAP must be in compliance with the provisions of this subpart that are applicable to RICE located at major sources within 3 

years after your area source becomes a major source of HAP.

(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]
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Emission and Operating Limitations

§ 63.6600 What emission limitations and operating limitations must I meet if I own 

or operate a stationary RICE with a site rating of more than 500 brake HP located at 

a major source of HAP emissions?

Compliance with the numerical emission limitations established in this subpart is based on the results of testing the average of 

three 1-hour runs using the testing requirements and procedures in §63.6620 and Table 4 to this subpart.

(a) If you own or operate an existing, new, or reconstructed spark ignition 4SRB stationary RICE with a site rating of more than 

500 brake HP located at a major source of HAP emissions, you must comply with the emission limitations in Table 1a to this 

subpart and the operating limitations in Table 1b to this subpart which apply to you.

(b) If you own or operate a new or reconstructed 2SLB stationary RICE with a site rating of more than 500 brake HP located at

major source of HAP emissions, a new or reconstructed 4SLB stationary RICE with a site rating of more than 500 brake HP 

located at major source of HAP emissions, or a new or reconstructed CI stationary RICE with a site rating of more than 500 brake 

HP located at a major source of HAP emissions, you must comply with the emission limitations in Table 2a to this subpart and the 

operating limitations in Table 2b to this subpart which apply to you.

(c) If you own or operate any of the following stationary RICE with a site rating of more than 500 brake HP located at a major 

source of HAP emissions, you do not need to comply with the emission limitations in Tables 1a, 2a, 2c, and 2d to this subpart or 

operating limitations in Tables 1b and 2b to this subpart: an existing 2SLB stationary RICE; an existing 4SLB stationary RICE; a 

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

basis; an emergency stationary RICE; or a limited use stationary RICE.

(d) If you own or operate an existing non-emergency stationary CI RICE with a site rating of more than 500 brake HP located at a 

major source of HAP emissions, you must comply with the emission limitations in Table 2c to this subpart and the operating 

limitations in Table 2b to this subpart which apply to you.

[73 FR 3605, Jan. 18, 2008, as amended at 75 FR 9675, Mar. 3, 2010]

§ 63.6601 What emission limitations must I meet if I own or operate a new or 

reconstructed 4SLB stationary RICE with a site rating of greater than or equal to 

250 brake HP and less than or equal to 500 brake HP located at a major source of 

HAP emissions?

Compliance with the numerical emission limitations established in this subpart is based on the results of testing the average of 

three 1-hour runs using the testing requirements and procedures in §63.6620 and Table 4 to this subpart. If you own or operate a 

new or reconstructed 4SLB stationary RICE with a site rating of greater than or equal to 250 and less than or equal to 500 brake 

HP located at major source of HAP emissions manufactured on or after January 1, 2008, you must comply with the emission 

limitations in Table 2a to this subpart and the operating limitations in Table 2b to this subpart which apply to you.

[73 FR 3605, Jan. 18, 2008, as amended at 75 FR 9675, Mar. 3, 2010; 75 FR 51589, Aug. 20, 2010]

§ 63.6602 What emission limitations 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 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.
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[75 FR 51589, Aug. 20, 2010]

§ 63.6603 What emission limitations and operating limitations must I meet if I own 

or operate an existing stationary RICE located at an area source of HAP emissions?

Compliance with the numerical emission limitations established in this subpart is based on the results of testing the average of 

three 1-hour runs using the testing requirements and procedures in §63.6620 and Table 4 to this subpart.

(a) If you own or operate an existing stationary RICE located at an area source of HAP emissions, you must comply with the 

requirements in Table 2d to this subpart and the operating limitations in Table 1b and Table 2b to this subpart that apply to you.

(b) If you own or operate an existing stationary non-emergency CI RICE greater than 300 HP located at area sources in areas of 

Alaska not accessible by the Federal Aid Highway System (FAHS) you do not have to meet the numerical CO emission limitations 

specified in Table 2d to this subpart. Existing stationary non-emergency CI RICE greater than 300 HP located at area sources in 

areas of Alaska not accessible by the FAHS must meet the management practices that are shown for stationary non-emergency 

CI RICE less than or equal to 300 HP in Table 2d to this subpart.

[75 FR 9675, Mar. 3, 2010, as amended at 75 FR 51589, Aug. 20, 2010; 76 FR 12866, Mar. 9, 2011]

§ 63.6604 What fuel requirements must I meet if I own or operate an existing 

stationary CI RICE?

If you own or operate an existing non-emergency, non-black start CI stationary RICE with a site rating of more than 300 brake HP 

with a displacement of less than 30 liters per cylinder that uses diesel fuel, you must use diesel fuel that meets the requirements 

in 40 CFR 80.510(b) for nonroad diesel fuel. Existing non-emergency CI stationary RICE located in Guam, American Samoa, the 

Commonwealth of the Northern Mariana Islands, or at area sources in areas of Alaska not accessible by the FAHS are exempt 

from the requirements of this section.

[75 FR 51589, Aug. 20, 2010]

General Compliance Requirements

§ 63.6605 What are my general requirements for complying with this subpart?

(a) You must be in compliance with the emission limitations and operating limitations in this subpart that apply to you at all times.

(b) At all times you must operate and maintain any affected source, including associated air pollution control equipment and 

monitoring equipment, in a manner consistent with safety and good air pollution control practices for minimizing emissions. The 

general duty to minimize emissions does not require you to make any further efforts to reduce emissions if levels required by this 

standard have been achieved. Determination of whether such operation and maintenance procedures are being used will be 

based on information available to the Administrator which may include, but is not limited to, monitoring results, review of operation 

and maintenance procedures, review of operation and maintenance records, and inspection of the source.

[75 FR 9675, Mar. 3, 2010]

Testing and Initial Compliance Requirements

§ 63.6610 By what date must I conduct the initial performance tests or other initial 

compliance demonstrations if I own or operate a stationary RICE with a site rating 

of more than 500 brake HP located at a major source of HAP emissions?
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If you own or operate a stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions 

you are subject to the requirements of this section.

(a) You must conduct the initial performance test or other initial compliance demonstrations in Table 4 to this subpart that apply to 

you within 180 days after the compliance date that is specified for your stationary RICE in §63.6595 and according to the 

provisions in §63.7(a)(2).

(b) If you commenced construction or reconstruction between December 19, 2002 and June 15, 2004 and own or operate 

stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions, you must demonstrate

initial compliance with either the proposed emission limitations or the promulgated emission limitations no later than February 10, 

2005 or no later than 180 days after startup of the source, whichever is later, according to §63.7(a)(2)(ix).

(c) If you commenced construction or reconstruction between December 19, 2002 and June 15, 2004 and own or operate 

stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions, and you chose to 

comply with the proposed emission limitations when demonstrating initial compliance, you must conduct a second performance 

test to demonstrate compliance with the promulgated emission limitations by December 13, 2007 or after startup of the source,

whichever is later, according to §63.7(a)(2)(ix).

(d) An owner or operator is not required to conduct an initial performance test on units for which a performance test has been 

previously conducted, but the test must meet all of the conditions described in paragraphs (d)(1) through (5) of this section.

(1) The test must have been conducted using the same methods specified in this subpart, and these methods must have been 

followed correctly.

(2) The test must not be older than 2 years.

(3) The test must be reviewed and accepted by the Administrator.

(4) Either no process or equipment changes must have been made since the test was performed, or the owner or operator must 

be able to demonstrate that the results of the performance test, with or without adjustments, reliably demonstrate compliance

despite process or equipment changes.

(5) The test must be conducted at any load condition within plus or minus 10 percent of 100 percent load.

[69 FR 33506, June 15, 2004, as amended at 73 FR 3605, Jan. 18, 2008]

§ 63.6611 By what date must I conduct the initial performance tests or other initial 

compliance demonstrations if I own or operate a new or reconstructed 4SLB SI 

stationary RICE with a site rating of greater than or equal to 250 and less than or 

equal to 500 brake HP located at a major source of HAP emissions?

If you own or operate a new or reconstructed 4SLB stationary RICE with a site rating of greater than or equal to 250 and less than 

or equal to 500 brake HP located at a major source of HAP emissions, you must conduct an initial performance test within 240 

days after the compliance date that is specified for your stationary RICE in §63.6595 and according to the provisions specified in 

Table 4 to this subpart, as appropriate.

[73 FR 3605, Jan. 18, 2008, as amended at 75 FR 51589, Aug. 20, 2010]

§ 63.6612 By what date must I conduct the initial performance tests or other initial 

compliance demonstrations if I own or operate an existing stationary RICE with a 

site rating of less than or equal to 500 brake HP located at a major source of HAP 
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emissions or an existing stationary RICE located at an area source of HAP 

emissions?

If you own or operate an existing stationary RICE with a site rating of less than or equal to 500 brake HP located at a major 

source of HAP emissions or an existing stationary RICE located at an area source of HAP emissions you are subject to the 

requirements of this section.

(a) You must conduct any initial performance test or other initial compliance demonstration according to Tables 4 and 5 to this 

subpart that apply to you within 180 days after the compliance date that is specified for your stationary RICE in §63.6595 and 

according to the provisions in §63.7(a)(2).

(b) An owner or operator is not required to conduct an initial performance test on a unit for which a performance test has been 

previously conducted, but the test must meet all of the conditions described in paragraphs (b)(1) through (4) of this section.

(1) The test must have been conducted using the same methods specified in this subpart, and these methods must have been 

followed correctly.

(2) The test must not be older than 2 years.

(3) The test must be reviewed and accepted by the Administrator.

(4) Either no process or equipment changes must have been made since the test was performed, or the owner or operator must 

be able to demonstrate that the results of the performance test, with or without adjustments, reliably demonstrate compliance 

despite process or equipment changes.

[75 FR 9676, Mar. 3, 2010, as amended at 75 FR 51589, Aug. 20, 2010]

§ 63.6615 When must I conduct subsequent performance tests?

If you must comply with the emission limitations and operating limitations, you must conduct subsequent performance tests as 

specified in Table 3 of this subpart.

§ 63.6620 What performance tests and other procedures must I use?

(a) You must conduct each performance test in Tables 3 and 4 of this subpart that applies to you.

(b) Each performance test must be conducted according to the requirements that this subpart specifies in Table 4 to this subpart. 

If you own or operate a non-operational stationary RICE that is subject to performance testing, you do not need to start up the 

engine solely to conduct the performance test. Owners and operators of a non-operational engine can conduct the performance 

test when the engine is started up again.

(c) [Reserved]

(d) You must conduct three separate test runs for each performance test required in this section, as specified in §63.7(e)(3). Each 

test run must last at least 1 hour.

(e)(1) You must use Equation 1 of this section to determine compliance with the percent reduction requirement:

Where:
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Ci= concentration of CO or formaldehyde at the control device inlet,

Co= concentration of CO or formaldehyde at the control device outlet, and

R = percent reduction of CO or formaldehyde emissions.

(2) You must normalize the carbon monoxide (CO) or formaldehyde concentrations at the inlet and outlet of the control device to a 

dry basis and to 15 percent oxygen, or an equivalent percent carbon dioxide (CO2). If pollutant concentrations are to be corrected 

to 15 percent oxygen and CO2concentration is measured in lieu of oxygen concentration measurement, a CO2correction factor is 

needed. Calculate the CO2correction factor as described in paragraphs (e)(2)(i) through (iii) of this section.

(i) Calculate the fuel-specific Fovalue for the fuel burned during the test using values obtained from Method 19, section 5.2, and 

the following equation:

Where:

Fo= Fuel factor based on the ratio of oxygen volume to the ultimate CO2volume produced by the fuel at zero percent 

excess air.

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

Fd= Ratio of the volume of dry effluent gas to the gross calorific value of the fuel from Method 19, dsm3 /J (dscf/106

Btu).

Fc= Ratio of the volume of CO2produced to the gross calorific value of the fuel from Method 19, dsm3 /J (dscf/106

Btu).

(ii) Calculate the CO2correction factor for correcting measurement data to 15 percent oxygen, as follows:

Where:

Xco2= CO2correction factor, percent.

5.9 = 20.9 percent O2−15 percent O2, the defined O2correction value, percent.

(iii) Calculate the NOXand SO2gas concentrations adjusted to 15 percent O2using CO2as follows:

Where:

%CO2= Measured CO2concentration measured, dry basis, percent.
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(f) If you comply with the emission limitation to reduce CO and you are not using an oxidation catalyst, if you comply with the 

emission limitation to reduce formaldehyde and you are not using NSCR, or if you comply with the emission limitation to limit the 

concentration of formaldehyde in the stationary RICE exhaust and you are not using an oxidation catalyst or NSCR, you must 

petition the Administrator for operating limitations to be established during the initial performance test and continuously monitored 

thereafter; or for approval of no operating limitations. You must not conduct the initial performance test until after the petition has 

been approved by the Administrator.

(g) If you petition the Administrator for approval of operating limitations, your petition must include the information described in 

paragraphs (g)(1) through (5) of this section.

(1) Identification of the specific parameters you propose to use as operating limitations;

(2) A discussion of the relationship between these parameters and HAP emissions, identifying how HAP emissions change with 

changes in these parameters, and how limitations on these parameters will serve to limit HAP emissions;

(3) A discussion of how you will establish the upper and/or lower values for these parameters which will establish the limits on 

these parameters in the operating limitations;

(4) A discussion identifying the methods you will use to measure and the instruments you will use to monitor these parameters, as 

well as the relative accuracy and precision of these methods and instruments; and

(5) A discussion identifying the frequency and methods for recalibrating the instruments you will use for monitoring these 

parameters.

(h) If you petition the Administrator for approval of no operating limitations, your petition must include the information described in 

paragraphs (h)(1) through (7) of this section.

(1) Identification of the parameters associated with operation of the stationary RICE and any emission control device which could 

change intentionally ( e.g., operator adjustment, automatic controller adjustment, etc.) or unintentionally ( e.g., wear and tear, 

error, etc.) on a routine basis or over time;

(2) A discussion of the relationship, if any, between changes in the parameters and changes in HAP emissions;

(3) For the parameters which could change in such a way as to increase HAP emissions, a discussion of whether establishing 

limitations on the parameters would serve to limit HAP emissions;

(4) For the parameters which could change in such a way as to increase HAP emissions, a discussion of how you could establish 

upper and/or lower values for the parameters which would establish limits on the parameters in operating limitations;

(5) For the parameters, a discussion identifying the methods you could use to measure them and the instruments you could use to 

monitor them, as well as the relative accuracy and precision of the methods and instruments;

(6) For the parameters, a discussion identifying the frequency and methods for recalibrating the instruments you could use to 

monitor them; and

(7) A discussion of why, from your point of view, it is infeasible or unreasonable to adopt the parameters as operating limitations.

(i) The engine percent load during a performance test must be determined by documenting the calculations, assumptions, and 

measurement devices used to measure or estimate the percent load in a specific application. A written report of the average 

percent load determination must be included in the notification of compliance status. The following information must be included in 

the written report: the engine model number, the engine manufacturer, the year of purchase, the manufacturer's site-rated brake 

horsepower, the ambient temperature, pressure, and humidity during the performance test, and all assumptions that were made 

to estimate or calculate percent load during the performance test must be clearly explained. If measurement devices such as flow 

meters, kilowatt meters, beta analyzers, stain gauges, etc. are used, the model number of the measurement device, and an 

estimate of its accurate in percentage of true value must be provided.
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[69 FR 33506, June 15, 2004, as amended at 75 FR 9676, Mar. 3, 2010]

§ 63.6625 What are my monitoring, installation, collection, operation, and 

maintenance requirements?

(a) If you elect to install a CEMS as specified in Table 5 of this subpart, you must install, operate, and maintain a CEMS to monitor 

CO and either oxygen or CO2at both the inlet and the outlet of the control device according to the requirements in paragraphs 

(a)(1) through (4) of this section.

(1) Each CEMS must be installed, operated, and maintained according to the applicable performance specifications of 40 CFR 

part 60, appendix B.

(2) You must conduct an initial performance evaluation and an annual relative accuracy test audit (RATA) of each CEMS 

according to the requirements in §63.8 and according to the applicable performance specifications of 40 CFR part 60, appendix B 

as well as daily and periodic data quality checks in accordance with 40 CFR part 60, appendix F, procedure 1.

(3) As specified in §63.8(c)(4)(ii), each CEMS must complete a minimum of one cycle of operation (sampling, analyzing, and data 

recording) for each successive 15-minute period. You must have at least two data points, with each representing a different 15-

minute period, to have a valid hour of data.

(4) The CEMS data must be reduced as specified in §63.8(g)(2) and recorded in parts per million or parts per billion (as 

appropriate for the applicable limitation) at 15 percent oxygen or the equivalent CO2concentration.

(b) If you are required to install a continuous parameter monitoring system (CPMS) as specified in Table 5 of this subpart, you 

must install, operate, and maintain each CPMS according to the requirements in paragraphs (b)(1) through (5) of this section. For 

an affected source that is complying with the emission limitations and operating limitations on March 9, 2011, the requirements in 

paragraph (b) of this section are applicable September 6, 2011.

(1) You must prepare a site-specific monitoring plan that addresses the monitoring system design, data collection, and the quality 

assurance and quality control elements outlined in paragraphs (b)(1)(i) through (v) of this section and in §63.8(d). As specified in 

§63.8(f)(4), you may request approval of monitoring system quality assurance and quality control procedures alternative to those 

specified in paragraphs (b)(1) through (5) of this section in your site-specific monitoring plan.

(i) The performance criteria and design specifications for the monitoring system equipment, including the sample interface, 

detector signal analyzer, and data acquisition and calculations;

(ii) Sampling interface ( e.g., thermocouple) location such that the monitoring system will provide representative measurements;

(iii) Equipment performance evaluations, system accuracy audits, or other audit procedures;

(iv) Ongoing operation and maintenance procedures in accordance with provisions in §63.8(c)(1) and (c)(3); and

(v) Ongoing reporting and recordkeeping procedures in accordance with provisions in §63.10(c), (e)(1), and (e)(2)(i).

(2) You must install, operate, and maintain each CPMS in continuous operation according to the procedures in your site-specific 

monitoring plan.

(3) The CPMS must collect data at least once every 15 minutes (see also §63.6635).

(4) For a CPMS for measuring temperature range, the temperature sensor must have a minimum tolerance of 2.8 degrees Celsius 

(5 degrees Fahrenheit) or 1 percent of the measurement range, whichever is larger.

(5) You must conduct the CPMS equipment performance evaluation, system accuracy audits, or other audit procedures specified 

in your site-specific monitoring plan at least annually.
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(6) You must conduct a performance evaluation of each CPMS in accordance with your site-specific monitoring plan.

(c) If you are operating a new or reconstructed stationary RICE which fires landfill gas or digester gas equivalent to 10 percent or 

more of the gross heat input on an annual basis, you must monitor and record your fuel usage daily with separate fuel meters to 

measure the volumetric flow rate of each fuel. In addition, you must operate your stationary RICE in a manner which reasonably 

minimizes HAP emissions.

(d) If you are operating a new or reconstructed emergency 4SLB stationary RICE with a site rating of greater than or equal to 250 

and less than or equal to 500 brake HP located at a major source of HAP emissions, you must install a non-resettable hour meter 

prior to the startup of the engine.

(e) If you own or operate any of the following stationary RICE, you must operate and maintain the stationary RICE and aftertreatment control device (if any) according to the manufacturer's emission-related written instructions or develop your own 

maintenance plan which must provide to the extent practicable for the maintenance and operation of the engine in a manner 

consistent with good air pollution control practice for minimizing emissions:

(1) An existing stationary RICE with a site rating of less than 100 HP located at a major source of HAP emissions;

(2) An existing emergency or black start stationary RICE with a site rating of less than or equal to 500 HP located at a major 

source of HAP emissions;

(3) An existing emergency or black start stationary RICE located at an area source of HAP emissions;

(4) An existing non-emergency, non-black start stationary CI RICE with a site rating less than or equal to 300 HP located at an 

area source of HAP emissions;

(5) An existing non-emergency, non-black start 2SLB stationary RICE located at an area source of HAP emissions;

(6) An existing non-emergency, non-black start landfill or digester gas stationary RICE located at an area source of HAP 

emissions;

(7) An existing non-emergency, non-black start 4SLB stationary RICE with a site rating less than or equal to 500 HP located at an 

area source of HAP emissions;

(8) An existing non-emergency, non-black start 4SRB stationary RICE with a site rating less than or equal to 500 HP located at an 

area source of HAP emissions;

(9) An existing, non-emergency, non-black start 4SLB stationary RICE with a site rating greater than 500 HP located at an area 

source of HAP emissions that is operated 24 hours or less per calendar year; and

(10) An existing, non-emergency, non-black start 4SRB stationary RICE with a site rating greater than 500 HP located at an area 

source of HAP emissions that is operated 24 hours or less per calendar year.

(f) If you own or operate an existing emergency stationary RICE with a site rating of less than or equal to 500 brake HP located at 

a major source of HAP emissions or an existing emergency stationary RICE located at an area source of HAP emissions, you 

must install a non-resettable hour meter if one is not already installed.

(g) If you own or operate an existing non-emergency, non-black start CI engine greater than or equal to 300 HP that is not 

equipped with a closed crankcase ventilation system, you must comply with either paragraph (g)(1) or paragraph (g)(2) of this

section. Owners and operators must follow the manufacturer's specified maintenance requirements for operating and maintaining 

the open or closed crankcase ventilation systems and replacing the crankcase filters, or can request the Administrator to approve 

different maintenance requirements that are as protective as manufacturer requirements. Existing CI engines located at area 

sources in areas of Alaska not accessible by the FAHS do not have to meet the requirements of paragraph (g) of this section.

(1) Install a closed crankcase ventilation system that prevents crankcase emissions from being emitted to the atmosphere, or
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(2) Install an open crankcase filtration emission control system that reduces emissions from the crankcase by filtering the exhaust 

stream to remove oil mist, particulates, and metals.

(h) If you operate a new, reconstructed, or existing stationary engine, you must minimize the engine's time spent at idle during 

startup and minimize the engine's startup time to a period needed for appropriate and safe loading of the engine, not to exceed 30 

minutes, after which time the emission standards applicable to all times other than startup in Tables 1a, 2a, 2c, and 2d to this 

subpart apply.

(i) If you own or operate a stationary CI engine that is subject to the work, operation or management practices in items 1 or 2 of 

Table 2c to this subpart or in items 1 or 4 of Table 2d to this subpart, you have the option of utilizing an oil analysis program in 

order to extend the specified oil change requirement in Tables 2c and 2d to this subpart. The oil analysis must be performed at 

the same frequency specified for changing the oil in Table 2c or 2d to this subpart. The analysis program must at a minimum 

analyze the following three parameters: Total Base Number, viscosity, and percent water content. The condemning limits for 

these parameters are as follows: Total Base Number is less than 30 percent of the Total Base Number of the oil when new; 

viscosity of the oil has changed by more than 20 percent from the viscosity of the oil when new; or percent water content (by 

volume) is greater than 0.5. If all of these condemning limits are not exceeded, the engine owner or operator is not required to 

change the oil. If any of the limits are exceeded, the engine owner or operator must change the oil within 2 days of receiving the 

results of the analysis; if the engine is not in operation when the results of the analysis are received, the engine owner or operator 

must change the oil within 2 days or before commencing operation, whichever is later. The owner or operator must keep records 

of the parameters that are analyzed as part of the program, the results of the analysis, and the oil changes for the engine. The 

analysis program must be part of the maintenance plan for the engine.

(j) If you own or operate a stationary SI engine that is subject to the work, operation or management practices in items 6, 7, or 8 of 

Table 2c to this subpart or in items 5, 6, 7, 9, or 11 of Table 2d to this subpart, you have the option of utilizing an oil analysis 

program in order to extend the specified oil change requirement in Tables 2c and 2d to this subpart. The oil analysis must be 

performed at the same frequency specified for changing the oil in Table 2c or 2d to this subpart. The analysis program must at a 

minimum analyze the following three parameters: Total Acid Number, viscosity, and percent water content. The condemning limits 

for these parameters are as follows: Total Acid Number increases by more than 3.0 milligrams of potassium hydroxide (KOH) per

gram from Total Acid Number of the oil when new; viscosity of the oil has changed by more than 20 percent from the viscosity of 

the oil when new; or percent water content (by volume) is greater than 0.5. If all of these condemning limits are not exceeded, the 

engine owner or operator is not required to change the oil. If any of the limits are exceeded, the engine owner or operator must 

change the oil within 2 days of receiving the results of the analysis; if the engine is not in operation when the results of the 

analysis are received, the engine owner or operator must change the oil within 2 days or before commencing operation, 

whichever is later. The owner or operator must keep records of the parameters that are analyzed as part of the program, the 

results of the analysis, and the oil changes for the engine. The analysis program must be part of the maintenance plan for the 

engine.

[69 FR 33506, June 15, 2004, as amended at 73 FR 3606, Jan. 18, 2008; 75 FR 9676, Mar. 3, 2010; 75 FR 51589, Aug. 20, 

2010; 76 FR 12866, Mar. 9, 2011]

§ 63.6630 How do I demonstrate initial compliance with the emission limitations 

and operating limitations?

(a) You must demonstrate initial compliance with each emission and operating limitation that applies to you according to Table 5 

of this subpart.

(b) During the initial performance test, you must establish each operating limitation in Tables 1b and 2b of this subpart that applies 

to you.

(c) You must submit the Notification of Compliance Status containing the results of the initial compliance demonstration according 

to the requirements in §63.6645.

Continuous Compliance Requirements

§ 63.6635 How do I monitor and collect data to demonstrate continuous 
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compliance?

(a) If you must comply with emission and operating limitations, you must monitor and collect data according to this section.

(b) Except for monitor malfunctions, associated repairs, required performance evaluations, and required quality assurance or 

control activities, you must monitor continuously at all times that the stationary RICE is operating. A monitoring malfunction is any 

sudden, infrequent, not reasonably preventable failure of the monitoring to provide valid data. Monitoring failures that are caused 

in part by poor maintenance or careless operation are not malfunctions.

(c) You may not use data recorded during monitoring malfunctions, associated repairs, and required quality assurance or control 

activities in data averages and calculations used to report emission or operating levels. You must, however, use all the valid data 

collected during all other periods.

[69 FR 33506, June 15, 2004, as amended at 76 FR 12867, Mar. 9, 2011]

§ 63.6640 How do I demonstrate continuous compliance with the emission 

limitations and operating limitations?

(a) You must demonstrate continuous compliance with each emission limitation and operating limitation in Tables 1a and 1b, 

Tables 2a and 2b, Table 2c, and Table 2d to this subpart that apply to you according to methods specified in Table 6 to this 

subpart.

(b) You must report each instance in which you did not meet each emission limitation or operating limitation in Tables 1a and 1b, 

Tables 2a and 2b, Table 2c, and Table 2d to this subpart that apply to you. These instances are deviations from the emission and 

operating limitations in this subpart. These deviations must be reported according to the requirements in §63.6650. If you change 

your catalyst, you must reestablish the values of the operating parameters measured during the initial performance test. When

you reestablish the values of your operating parameters, you must also conduct a performance test to demonstrate that you are 

meeting the required emission limitation applicable to your stationary RICE.

(c) [Reserved]

(d) For new, reconstructed, and rebuilt stationary RICE, deviations from the emission or operating limitations that occur during the 

first 200 hours of operation from engine startup (engine burn-in period) are not violations. Rebuilt stationary RICE means a 

stationary RICE that has been rebuilt as that term is defined in 40 CFR 94.11(a).

(e) You must also report each instance in which you did not meet the requirements in Table 8 to this subpart that apply to you. If

you own or operate a new or reconstructed stationary RICE with a site rating of less than or equal to 500 brake HP located at a 

major source of HAP emissions (except new or reconstructed 4SLB engines greater than or equal to 250 and less than or equal to 

500 brake HP), a new or reconstructed stationary RICE located at an area source of HAP emissions, or any of the following RICE 

with a site rating of more than 500 brake HP located at a major source of HAP emissions, you do not need to comply with the 

requirements in Table 8 to this subpart: An existing 2SLB stationary RICE, an existing 4SLB stationary RICE, an existing 

emergency stationary RICE, an existing limited use stationary RICE, or an existing stationary RICE which fires landfill gas or 

digester gas equivalent to 10 percent or more of the gross heat input on an annual basis. If you own or operate any of the 

following RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions, you do not need to 

comply with the requirements in Table 8 to this subpart, except for the initial notification requirements: a new or reconstructed 

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

basis, a new or reconstructed emergency stationary RICE, or a new or reconstructed limited use stationary RICE.

(f) Requirements for emergency stationary RICE. (1) If you own or operate an existing emergency stationary RICE with a site 

rating of less than or equal to 500 brake HP located at a major source of HAP emissions, a new or reconstructed emergency 

stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions that was installed on or 

after June 12, 2006, or an existing emergency stationary RICE located at an area source of HAP emissions, you must operate the 

emergency stationary RICE according to the requirements in paragraphs (f)(1)(i) through (iii) of this section. Any operation other 

than emergency operation, maintenance and testing, and operation in non-emergency situations for 50 hours per year, as 

described in paragraphs (f)(1)(i) through (iii) of this section, is prohibited. If you do not operate the engine according to the 

requirements in paragraphs (f)(1)(i) through (iii) of this section, the engine will not be considered an emergency engine under this 
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subpart and will need to meet all requirements for non-emergency engines.

(i) There is no time limit on the use of emergency stationary RICE in emergency situations.

(ii) You may operate your emergency stationary RICE for the purpose of maintenance checks and readiness testing, provided that 

the tests are recommended by Federal, State or local government, the manufacturer, the vendor, or the insurance company 

associated with the engine. Maintenance checks and readiness testing of such units is limited to 100 hours per year. The owner 

or operator may petition the Administrator for approval of additional hours to be used for maintenance checks and readiness 

testing, but a petition is not required if the owner or operator maintains records indicating that Federal, State, or local standards 

require maintenance and testing of emergency RICE beyond 100 hours per year.

(iii) You may operate your emergency stationary RICE up to 50 hours per year in non-emergency situations, but those 50 hours 

are counted towards the 100 hours per year provided for maintenance and testing. The 50 hours per year for non-emergency 

situations cannot be used for peak shaving or to generate income for a facility to supply power to an electric grid or otherwise 

supply power as part of a financial arrangement with another entity; except that owners and operators may operate the 

emergency engine for a maximum of 15 hours per year as part of a demand response program if the regional transmission 

organization or equivalent balancing authority and transmission operator has determined there are emergency conditions that 

could lead to a potential electrical blackout, such as unusually low frequency, equipment overload, capacity or energy deficiency, 

or unacceptable voltage level. The engine may not be operated for more than 30 minutes prior to the time when the emergency 

condition is expected to occur, and the engine operation must be terminated immediately after the facility is notified that the 

emergency condition is no longer imminent. The 15 hours per year of demand response operation are counted as part of the 50 

hours of operation per year provided for non-emergency situations. The supply of emergency power to another entity or entities 

pursuant to financial arrangement is not limited by this paragraph (f)(1)(iii), as long as the power provided by the financial 

arrangement is limited to emergency power.

(2) If you own or operate an emergency stationary RICE with a site rating of more than 500 brake HP located at a major source of 

HAP emissions that was installed prior to June 12, 2006, you must operate the engine according to the conditions described in 

paragraphs (f)(2)(i) through (iii) of this section. If you do not operate the engine according to the requirements in paragraphs 

(f)(2)(i) through (iii) of this section, the engine will not be considered an emergency engine under this subpart and will need to 

meet all requirements for non-emergency engines.

(i) There is no time limit on the use of emergency stationary RICE in emergency situations.

(ii) You may operate your emergency stationary RICE for the purpose of maintenance checks and readiness testing, provided that 

the tests are recommended by the manufacturer, the vendor, or the insurance company associated with the engine. Required 

testing of such units should be minimized, but there is no time limit on the use of emergency stationary RICE in emergency 

situations and for routine testing and maintenance.

(iii) You may operate your emergency stationary RICE for an additional 50 hours per year in non-emergency situations. The 50 

hours per year for non-emergency situations cannot be used for peak shaving or to generate income for a facility to supply power 

to an electric grid or otherwise supply power as part of a financial arrangement with another entity.

[69 FR 33506, June 15, 2004, as amended at 71 FR 20467, Apr. 20, 2006; 73 FR 3606, Jan. 18, 2008; 75 FR 9676, Mar. 3, 2010; 

75 FR 51591, Aug. 20, 2010]

Notifications, Reports, and Records

§ 63.6645 What notifications must I submit and when?

(a) You must submit all of the notifications in §§63.7(b) and (c), 63.8(e), (f)(4) and (f)(6), 63.9(b) through (e), and (g) and (h) that 

apply to you by the dates specified if you own or operate any of the following;

(1) An existing stationary RICE with a site rating of less than or equal to 500 brake HP located at a major source of HAP 

emissions.

(2) An existing stationary RICE located at an area source of HAP emissions.
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(3) A stationary RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions.

(4) A new or reconstructed 4SLB stationary RICE with a site rating of greater than or equal to 250 HP located at a major source of 

HAP emissions.

(5) This requirement does not apply if you own or operate an existing stationary RICE less than 100 HP, an existing stationary 

emergency RICE, or an existing stationary RICE that is not subject to any numerical emission standards.

(b) As specified in §63.9(b)(2), if you start up your stationary RICE with a site rating of more than 500 brake HP located at a major 

source of HAP emissions before the effective date of this subpart, you must submit an Initial Notification not later than December 

13, 2004.

(c) If you start up your new or reconstructed stationary RICE with a site rating of more than 500 brake HP located at a major

source of HAP emissions on or after August 16, 2004, you must submit an Initial Notification not later than 120 days after you 

become subject to this subpart.

(d) As specified in §63.9(b)(2), if you start up your stationary RICE with a site rating of equal to or less than 500 brake HP located 

at a major source of HAP emissions before the effective date of this subpart and you are required to submit an initial notification, 

you must submit an Initial Notification not later than July 16, 2008.

(e) If you start up your new or reconstructed stationary RICE with a site rating of equal to or less than 500 brake HP located at a 

major source of HAP emissions on or after March 18, 2008 and you are required to submit an initial notification, you must submit 

an Initial Notification not later than 120 days after you become subject to this subpart.

(f) If you are required to submit an Initial Notification but are otherwise not affected by the requirements of this subpart, in 

accordance with §63.6590(b), your notification should include the information in §63.9(b)(2)(i) through (v), and a statement that 

your stationary RICE has no additional requirements and explain the basis of the exclusion (for example, that it operates 

exclusively as an emergency stationary RICE if it has a site rating of more than 500 brake HP located at a major source of HAP 

emissions).

(g) If you are required to conduct a performance test, you must submit a Notification of Intent to conduct a performance test at 

least 60 days before the performance test is scheduled to begin as required in §63.7(b)(1).

(h) If you are required to conduct a performance test or other initial compliance demonstration as specified in Tables 4 and 5 to 

this subpart, you must submit a Notification of Compliance Status according to §63.9(h)(2)(ii).

(1) For each initial compliance demonstration required in Table 5 to this subpart that does not include a performance test, you 

must submit the Notification of Compliance Status before the close of business on the 30th day following the completion of the 

initial compliance demonstration.

(2) For each initial compliance demonstration required in Table 5 to this subpart that includes a performance test conducted 

according to the requirements in Table 3 to this subpart, you must submit the Notification of Compliance Status, including the 

performance test results, before the close of business on the 60th day following the completion of the performance test according 

to §63.10(d)(2).

[73 FR 3606, Jan. 18, 2008, as amended at 75 FR 9677, Mar. 3, 2010; 75 FR 51591, Aug. 20, 2010]

§ 63.6650 What reports must I submit and when?

(a) You must submit each report in Table 7 of this subpart that applies to you.

(b) Unless the Administrator has approved a different schedule for submission of reports under §63.10(a), you must submit each 

report by the date in Table 7 of this subpart and according to the requirements in paragraphs (b)(1) through (b)(9) of this section.

(1) For semiannual Compliance reports, the first Compliance report must cover the period beginning on the compliance date that 
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is specified for your affected source in §63.6595 and ending on June 30 or December 31, whichever date is the first date following 

the end of the first calendar half after the compliance date that is specified for your source in §63.6595.

(2) For semiannual Compliance reports, the first Compliance report must be postmarked or delivered no later than July 31 or 

January 31, whichever date follows the end of the first calendar half after the compliance date that is specified for your affected 

source in §63.6595.

(3) For semiannual Compliance reports, each subsequent Compliance report must cover the semiannual reporting period from 

January 1 through June 30 or the semiannual reporting period from July 1 through December 31.

(4) For semiannual Compliance reports, each subsequent Compliance report must be postmarked or delivered no later than July 

31 or January 31, whichever date is the first date following the end of the semiannual reporting period.

(5) For each stationary RICE that is subject to permitting regulations pursuant to 40 CFR part 70 or 71, and if the permitting 

authority has established dates for submitting semiannual reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6 

(a)(3)(iii)(A), you may submit the first and subsequent Compliance reports according to the dates the permitting authority has 

established instead of according to the dates in paragraphs (b)(1) through (b)(4) of this section.

(6) For annual Compliance reports, the first Compliance report must cover the period beginning on the compliance date that is 

specified for your affected source in §63.6595 and ending on December 31.

(7) For annual Compliance reports, the first Compliance report must be postmarked or delivered no later than January 31 

following the end of the first calendar year after the compliance date that is specified for your affected source in §63.6595.

(8) For annual Compliance reports, each subsequent Compliance report must cover the annual reporting period from January 1 

through December 31.

(9) For annual Compliance reports, each subsequent Compliance report must be postmarked or delivered no later than January 

31.

(c) The Compliance report must contain the information in paragraphs (c)(1) through (6) of this section.

(1) Company name and address.

(2) Statement by a responsible official, with that official's name, title, and signature, certifying the accuracy of the content of the 

report.

(3) Date of report and beginning and ending dates of the reporting period.

(4) If you had a malfunction during the reporting period, the compliance report must include the number, duration, and a brief 

description for each type of malfunction which occurred during the reporting period and which caused or may have caused any 

applicable emission limitation to be exceeded. The report must also include a description of actions taken by an owner or operator 

during a malfunction of an 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-ofcontrol, as specified in §63.8(c)(7), a statement that there were no periods during which the CMS was out-of-control during the 

reporting period.

(d) For each deviation from an emission or operating limitation that occurs for a stationary RICE where you are not using a CMS 

to comply with the emission or operating limitations in this subpart, the Compliance report must contain the information in 

paragraphs (c)(1) through (4) of this section and the information in paragraphs (d)(1) and (2) of this section.
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(1) The total operating time of the stationary RICE at which the deviation occurred during the reporting period.

(2) Information on the number, duration, and cause of deviations (including unknown cause, if applicable), as applicable, and the 

corrective action taken.

(e) For each deviation from an emission or operating limitation occurring for a stationary RICE where you are using a CMS to 

comply with the emission and operating limitations in this subpart, you must include information in paragraphs (c)(1) through (4) 

and (e)(1) through (12) of this section.

(1) The date and time that each malfunction started and stopped.

(2) The date, time, and duration that each CMS was inoperative, except for zero (low-level) and high-level checks.

(3) The date, time, and duration that each CMS was out-of-control, including the information in §63.8(c)(8).

(4) The date and time that each deviation started and stopped, and whether each deviation occurred during a period of 

malfunction or during another period.

(5) A summary of the total duration of the deviation during the reporting period, and the total duration as a percent of the total 

source operating time during that reporting period.

(6) A breakdown of the total duration of the deviations during the reporting period into those that are due to control equipment 

problems, process problems, other known causes, and other unknown causes.

(7) A summary of the total duration of CMS downtime during the reporting period, and the total duration of CMS downtime as a 

percent of the total operating time of the stationary RICE at which the CMS downtime occurred during that reporting period.

(8) An identification of each parameter and pollutant (CO or formaldehyde) that was monitored at the stationary RICE.

(9) A brief description of the stationary RICE.

(10) A brief description of the CMS.

(11) The date of the latest CMS certification or audit.

(12) A description of any changes in CMS, processes, or controls since the last reporting period.

(f) Each affected source that has obtained a title V operating permit pursuant to 40 CFR part 70 or 71 must report all deviations as 

defined in this subpart in the semiannual monitoring report required by 40 CFR 70.6 (a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A). If an 

affected source submits a Compliance report pursuant to Table 7 of this subpart along with, or as part of, the semiannual 

monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A), and the Compliance report includes all 

required information concerning deviations from any emission or operating limitation in this subpart, submission of the Compliance 

report shall be deemed to satisfy any obligation to report the same deviations in the semiannual monitoring report. However, 

submission of a Compliance report shall not otherwise affect any obligation the affected source may have to report deviations

from permit requirements to the permit authority.

(g) If you are operating as a new or reconstructed stationary RICE which fires landfill gas or digester gas equivalent to 10 percent 

or more of the gross heat input on an annual basis, you must submit an annual report according to Table 7 of this subpart by the 

date specified unless the Administrator has approved a different schedule, according to the information described in paragraphs 

(b)(1) through (b)(5) of this section. You must report the data specified in (g)(1) through (g)(3) of this section.

(1) Fuel flow rate of each fuel and the heating values that were used in your calculations. You must also demonstrate that the 

percentage of heat input provided by landfill gas or digester gas is equivalent to 10 percent or more of the total fuel consumption 

on an annual basis.
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(2) The operating limits provided in your federally enforceable permit, and any deviations from these limits.

(3) Any problems or errors suspected with the meters.

[69 FR 33506, June 15, 2004, as amended at 75 FR 9677, Mar. 3, 2010]

§ 63.6655 What records must I keep?

(a) If you must comply with the emission and operating limitations, you must keep the records described in paragraphs (a)(1) 

through (a)(5), (b)(1) through (b)(3) and (c) of this section.

(1) A copy of each notification and report that you submitted to comply with this subpart, including all documentation supporting 

any Initial Notification or Notification of Compliance Status that you submitted, according to the requirement in §63.10(b)(2)(xiv).

(2) Records of the occurrence and duration of each malfunction of operation ( i.e., process equipment) or the air pollution control 

and monitoring equipment.

(3) Records of performance tests and performance evaluations as required in §63.10(b)(2)(viii).

(4) Records of all required maintenance performed on the air pollution control and monitoring equipment.

(5) Records of actions taken during periods of malfunction to minimize emissions in accordance with §63.6605(b), including 

corrective actions to restore malfunctioning process and air pollution control and monitoring equipment to its normal or usual 

manner of operation.

(b) For each CEMS or CPMS, you must keep the records listed in paragraphs (b)(1) through (3) of this section.

(1) Records described in §63.10(b)(2)(vi) through (xi).

(2) Previous ( i.e., superseded) versions of the performance evaluation plan as required in §63.8(d)(3).

(3) Requests for alternatives to the relative accuracy test for CEMS or CPMS as required in §63.8(f)(6)(i), if applicable.

(c) If you are operating a new or reconstructed stationary RICE which fires landfill gas or digester gas equivalent to 10 percent or 

more of the gross heat input on an annual basis, you must keep the records of your daily fuel usage monitors.

(d) You must keep the records required in Table 6 of this subpart to show continuous compliance with each emission or operating 

limitation that applies to you.

(e) You must keep records of the maintenance conducted on the stationary RICE in order to demonstrate that you operated and 

maintained the stationary RICE and after-treatment control device (if any) according to your own maintenance plan if you own or 

operate any of the following stationary RICE;

(1) An existing stationary RICE with a site rating of less than 100 brake HP located at a major source of HAP emissions.

(2) An existing stationary emergency RICE.

(3) An existing stationary RICE located at an area source of HAP emissions subject to management practices as shown in Table 

2d to this subpart.

(f) If you own or operate any of the stationary RICE in paragraphs (f)(1) or (2) of this section, you must keep records of the hours 

of operation of the engine that is recorded through the non-resettable hour meter. The owner or operator must document how 

many hours are spent for emergency operation, including what classified the operation as emergency and how many hours are 

spent for non-emergency operation. If the engines are used for demand response operation, the owner or operator must keep 
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records of the notification of the emergency situation, and the time the engine was operated as part of demand response.

(1) An existing emergency stationary RICE with a site rating of less than or equal to 500 brake HP located at a major source of 

HAP emissions that does not meet the standards applicable to non-emergency engines.

(2) An existing emergency stationary RICE located at an area source of HAP emissions that does not meet the standards 

applicable to non-emergency engines.

[69 FR 33506, June 15, 2004, as amended at 75 FR 9678, Mar. 3, 2010; 75 FR 51592, Aug. 20, 2010]

§ 63.6660 In what form and how long must I keep my records?

(a) Your records must be in a form suitable and readily available for expeditious review according to §63.10(b)(1).

(b) As specified in §63.10(b)(1), you must keep each record for 5 years following the date of each occurrence, measurement, 

maintenance, corrective action, report, or record.

(c) You must keep each record readily accessible in hard copy or electronic form for at least 5 years after the date of each 

occurrence, measurement, maintenance, corrective action, report, or record, according to §63.10(b)(1).

[69 FR 33506, June 15, 2004, as amended at 75 FR 9678, Mar. 3, 2010]

Other Requirements and Information

§ 63.6665 What parts of the General Provisions apply to me?

Table 8 to this subpart shows which parts of the General Provisions in §§63.1 through 63.15 apply to you. If you own or operate a 

new or reconstructed stationary RICE with a site rating of less than or equal to 500 brake HP located at a major source of HAP 

emissions (except new or reconstructed 4SLB engines greater than or equal to 250 and less than or equal to 500 brake HP), a 

new or reconstructed stationary RICE located at an area source of HAP emissions, or any of the following RICE with a site rating 

of more than 500 brake HP located at a major source of HAP emissions, you do not need to comply with any of the requirements 

of the General Provisions specified in Table 8: An existing 2SLB stationary RICE, an existing 4SLB stationary RICE, an existing 

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

an existing emergency stationary RICE, or an existing limited use stationary RICE. If you own or operate any of the following

RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions, you do not need to comply with 

the requirements in the General Provisions specified in Table 8 except for the initial notification requirements: A new stationary 

RICE that combusts landfill gas or digester gas equivalent to 10 percent or more of the gross heat input on an annual basis, a 

new emergency stationary RICE, or a new limited use stationary RICE.

[75 FR 9678, Mar. 3, 2010]

§ 63.6670 Who implements and enforces this subpart?

(a) This subpart is implemented and enforced by the U.S. EPA, or a delegated authority such as your State, local, or tribal 

agency. If the U.S. EPA Administrator has delegated authority to your State, local, or tribal agency, then that agency (as well as 

the U.S. EPA) has the authority to implement and enforce this subpart. You should contact your U.S. EPA Regional Office to find 

out whether this subpart is delegated to your State, local, or tribal agency.

(b) In delegating implementation and enforcement authority of this subpart to a State, local, or tribal agency under 40 CFR part 

63, subpart E, the authorities contained in paragraph (c) of this section are retained by the Administrator of the U.S. EPA and are 

not transferred to the State, local, or tribal agency.

(c) The authorities that will not be delegated to State, local, or tribal agencies are:
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(1) Approval of alternatives to the non-opacity emission limitations and operating limitations in §63.6600 under §63.6(g).

(2) Approval of major alternatives to test methods under §63.7(e)(2)(ii) and (f) and as defined in §63.90.

(3) Approval of major alternatives to monitoring under §63.8(f) and as defined in §63.90.

(4) Approval of major alternatives to recordkeeping and reporting under §63.10(f) and as defined in §63.90.

(5) Approval of a performance test which was conducted prior to the effective date of the rule, as specified in §63.6610(b).

§ 63.6675 What definitions apply to this subpart?

Terms used in this subpart are defined in the Clean Air Act (CAA); in 40 CFR 63.2, the General Provisions of this part; and in this 

section as follows:

Area source means any stationary source of HAP that is not a major source as defined in part 63.

Associated equipment as used in this subpart and as referred to in section 112(n)(4) of the CAA, means equipment associated 

with an oil or natural gas exploration or production well, and includes all equipment from the well bore to the point of custody 

transfer, except glycol dehydration units, storage vessels with potential for flash emissions, combustion turbines, and stationary 

RICE.

Black start engine means an engine whose only purpose is to start up a combustion turbine.

CAA means the Clean Air Act (42 U.S.C. 7401 et seq., as amended by Public Law 101–549, 104 Stat. 2399).

Commercial emergency stationary RICE means an emergency stationary RICE used in commercial establishments such as office 

buildings, hotels, stores, telecommunications facilities, restaurants, financial institutions such as banks, doctor's offices, and 

sports and performing arts facilities.

Compression ignition means relating to a type of stationary internal combustion engine that is not a spark ignition engine.

Custody transfer means the transfer of hydrocarbon liquids or natural gas: After processing and/or treatment in the producing 

operations, or from storage vessels or automatic transfer facilities or other such equipment, including product loading racks, to 

pipelines or any other forms of transportation. For the purposes of this subpart, the point at which such liquids or natural gas 

enters a natural gas processing plant is a point of custody transfer.

Deviation means any instance in which an affected source subject to this subpart, or an owner or operator of such a source:

(1) Fails to meet any requirement or obligation established by this subpart, including but not limited to any emission limitation or 

operating limitation;

(2) Fails to meet any term or condition that is adopted to implement an applicable requirement in this subpart and that is included 

in the operating permit for any affected source required to obtain such a permit; or

(3) Fails to meet any emission limitation or operating limitation in this subpart during malfunction, regardless or whether or not 

such failure is permitted by this subpart.

(4) Fails to satisfy the general duty to minimize emissions established by §63.6(e)(1)(i).

Diesel engine means any stationary RICE in which a high boiling point liquid fuel injected into the combustion chamber ignites 

when the air charge has been compressed to a temperature sufficiently high for auto-ignition. This process is also known as 

compression ignition.
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Diesel fuel means any liquid obtained from the distillation of petroleum with a boiling point of approximately 150 to 360 degrees 

Celsius. One commonly used form is fuel oil number 2. Diesel fuel also includes any non-distillate fuel with comparable physical 

and chemical properties ( e.g. biodiesel) that is suitable for use in compression ignition engines.

Digester gas means any gaseous by-product of wastewater treatment typically formed through the anaerobic decomposition of 

organic waste materials and composed principally of methane and CO2.

Dual-fuel engine means any stationary RICE in which a liquid fuel (typically diesel fuel) is used for compression ignition and 

gaseous fuel (typically natural gas) is used as the primary fuel.

Emergency stationary RICE means any stationary internal combustion engine whose operation is limited to emergency situations 

and required testing and maintenance. Examples include stationary RICE used to produce power for critical networks or 

equipment (including power supplied to portions of a facility) when electric power from the local utility (or the normal power 

source, if the facility runs on its own power production) is interrupted, or stationary RICE used to pump water in the case of fire or 

flood, etc. Stationary RICE used for peak shaving are not considered emergency stationary RICE. Stationary RICE used to supply 

power to an electric grid or that supply non-emergency power as part of a financial arrangement with another entity are not 

considered to be emergency engines, except as permitted under §63.6640(f). All emergency stationary RICE must comply with 

the requirements specified in §63.6640(f) in order to be considered emergency stationary RICE. If the engine does not comply 

with the requirements specified in §63.6640(f), then it is not considered to be an emergency stationary RICE under this subpart.

Engine startup means the time from initial start until applied load and engine and associated equipment reaches steady state or 

normal operation. For stationary engine with catalytic controls, engine startup means the time from initial start until applied load 

and engine and associated equipment, including the catalyst, reaches steady state or normal operation.

Four-stroke engine means any type of engine which completes the power cycle in two crankshaft revolutions, with intake and 

compression strokes in the first revolution and power and exhaust strokes in the second revolution.

Gaseous fuel means a material used for combustion which is in the gaseous state at standard atmospheric temperature and 

pressure conditions.

Gasoline means any fuel sold in any State for use in motor vehicles and motor vehicle engines, or nonroad or stationary engines, 

and commonly or commercially known or sold as gasoline.

Glycol dehydration unit means a device in which a liquid glycol (including, but not limited to, ethylene glycol, diethylene glycol, or 

triethylene glycol) absorbent directly contacts a natural gas stream and absorbs water in a contact tower or absorption column 

(absorber). The glycol contacts and absorbs water vapor and other gas stream constituents from the natural gas and becomes 

“rich” glycol. This glycol is then regenerated in the glycol dehydration unit reboiler. The “lean” glycol is then recycled.

Hazardous air pollutants (HAP) means any air pollutants listed in or pursuant to section 112(b) of the CAA.

Institutional emergency stationary RICE means an emergency stationary RICE used in institutional establishments such as 

medical centers, nursing homes, research centers, institutions of higher education, correctional facilities, elementary and 

secondary schools, libraries, religious establishments, police stations, and fire stations.

ISO standard day conditions means 288 degrees Kelvin (15 degrees Celsius), 60 percent relative humidity and 101.3 kilopascals 

pressure.

Landfill gas means a gaseous by-product of the land application of municipal refuse typically formed through the anaerobic 

decomposition of waste materials and composed principally of methane and CO2.

Lean burn engine means any two-stroke or four-stroke spark ignited engine that does not meet the definition of a rich burn engine.

Limited use stationary RICE means any stationary RICE that operates less than 100 hours per year.

Liquefied petroleum gas means any liquefied hydrocarbon gas obtained as a by-product in petroleum refining of natural gas 

production.
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Liquid fuel means any fuel in liquid form at standard temperature and pressure, including but not limited to diesel, residual/crude 

oil, kerosene/naphtha (jet fuel), and gasoline.

Major Source, as used in this subpart, shall have the same meaning as in §63.2, except that:

(1) Emissions from any oil or gas exploration or production well (with its associated equipment (as defined in this section)) and 

emissions from any pipeline compressor station or pump station shall not be aggregated with emissions from other similar units, 

to determine whether such emission points or stations are major sources, even when emission points are in a contiguous area or 

under common control;

(2) For oil and gas production facilities, emissions from processes, operations, or equipment that are not part of the same oil and 

gas production facility, as defined in §63.1271 of subpart HHH of this part, shall not be aggregated;

(3) For production field facilities, only HAP emissions from glycol dehydration units, storage vessel with the potential for flash 

emissions, combustion turbines and reciprocating internal combustion engines shall be aggregated for a major source 

determination; and

(4) Emissions from processes, operations, and equipment that are not part of the same natural gas transmission and storage 

facility, as defined in §63.1271 of subpart HHH of this part, shall not be aggregated.

Malfunction means any sudden, infrequent, and not reasonably preventable failure of air pollution control equipment, process 

equipment, or a process to operate in a normal or usual manner which causes, or has the potential to cause, the emission 

limitations in an applicable standard to be exceeded. Failures that are caused in part by poor maintenance or careless operation 

are not malfunctions.

Natural gas means a naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in geologic formations 

beneath the Earth's surface, of which the principal constituent is methane. Natural gas may be field or pipeline quality.

Non-selective catalytic reduction (NSCR) means an add-on catalytic nitrogen oxides (NOX) control device for rich burn engines 

that, in a two-step reaction, promotes the conversion of excess oxygen, NOX, CO, and volatile organic compounds (VOC) into 

CO2, nitrogen, and water.

Oil and gas production facility as used in this subpart means any grouping of equipment where hydrocarbon liquids are 

processed, upgraded ( i.e., remove impurities or other constituents to meet contract specifications), or stored prior to the point of 

custody transfer; or where natural gas is processed, upgraded, or stored prior to entering the natural gas transmission and 

storage source category. For purposes of a major source determination, facility (including a building, structure, or installation) 

means oil and natural gas production and processing equipment that is located within the boundaries of an individual surface site 

as defined in this section. Equipment that is part of a facility will typically be located within close proximity to other equipment 

located at the same facility. Pieces of production equipment or groupings of equipment located on different oil and gas leases, 

mineral fee tracts, lease tracts, subsurface or surface unit areas, surface fee tracts, surface lease tracts, or separate surface sites, 

whether or not connected by a road, waterway, power line or pipeline, shall not be considered part of the same facility. Examples 

of facilities in the oil and natural gas production source category include, but are not limited to, well sites, satellite tank batteries, 

central tank batteries, a compressor station that transports natural gas to a natural gas processing plant, and natural gas 

processing plants.

Oxidation catalyst means an add-on catalytic control device that controls CO and VOC by oxidation.

Peaking unit or engine means any standby engine intended for use during periods of high demand that are not emergencies.

Percent load means the fractional power of an engine compared to its maximum manufacturer's design capacity at engine site 

conditions. Percent load may range between 0 percent to above 100 percent.

Potential to emit means the maximum capacity of a stationary source to emit a pollutant under its physical and operational design. 

Any physical or operational limitation on the capacity of the stationary source to emit a pollutant, including air pollution control 

equipment and restrictions on hours of operation or on the type or amount of material combusted, stored, or processed, shall be 

treated as part of its design if the limitation or the effect it would have on emissions is federally enforceable. For oil and natural 
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gas production facilities subject to subpart HH of this part, the potential to emit provisions in §63.760(a) may be used. For natural 

gas transmission and storage facilities subject to subpart HHH of this part, the maximum annual facility gas throughput for storage 

facilities may be determined according to §63.1270(a)(1) and the maximum annual throughput for transmission facilities may be 

determined according to §63.1270(a)(2).

Production field facility means those oil and gas production facilities located prior to the point of custody transfer.

Production well means any hole drilled in the earth from which crude oil, condensate, or field natural gas is extracted.

Propane means a colorless gas derived from petroleum and natural gas, with the molecular structure C3H8.

Residential emergency stationary RICE means an emergency stationary RICE used in residential establishments such as homes 

or apartment buildings.

Responsible official means responsible official as defined in 40 CFR 70.2.

Rich burn engine means any four-stroke spark ignited engine where the manufacturer's recommended operating air/fuel ratio 

divided by the stoichiometric air/fuel ratio at full load conditions is less than or equal to 1.1. Engines originally manufactured as 

rich burn engines, but modified prior to December 19, 2002 with passive emission control technology for NOX(such as precombustion chambers) will be considered lean burn engines. Also, existing engines where there are no manufacturer's 

recommendations regarding air/fuel ratio will be considered a rich burn engine if the excess oxygen content of the exhaust at full 

load conditions is less than or equal to 2 percent.

Site-rated HP means the maximum manufacturer's design capacity at engine site conditions.

Spark ignition means relating to either: A gasoline-fueled engine; or any other type of engine with a spark plug (or other sparking 

device) and with operating characteristics significantly similar to the theoretical Otto combustion cycle. Spark ignition engines 

usually use a throttle to regulate intake air flow to control power during normal operation. Dual-fuel engines in which a liquid fuel 

(typically diesel fuel) is used for CI and gaseous fuel (typically natural gas) is used as the primary fuel at an annual average ratio 

of less than 2 parts diesel fuel to 100 parts total fuel on an energy equivalent basis are spark ignition engines.

Stationary reciprocating internal combustion engine (RICE) means any reciprocating internal combustion engine which uses 

reciprocating motion to convert heat energy into mechanical work and which is not mobile. Stationary RICE differ from mobile 

RICE in that a stationary RICE is not a non-road engine as defined at 40 CFR 1068.30, and is not used to propel a motor vehicle 

or a vehicle used solely for competition.

Stationary RICE test cell/stand means an engine test cell/stand, as defined in subpart PPPPP of this part, that tests stationary 

RICE.

Stoichiometric means the theoretical air-to-fuel ratio required for complete combustion.

Storage vessel with the potential for flash emissions means any storage vessel that contains a hydrocarbon liquid with a stock 

tank gas-to-oil ratio equal to or greater than 0.31 cubic meters per liter and an American Petroleum Institute gravity equal to or 

greater than 40 degrees and an actual annual average hydrocarbon liquid throughput equal to or greater than 79,500 liters per 

day. Flash emissions occur when dissolved hydrocarbons in the fluid evolve from solution when the fluid pressure is reduced.

Subpart means 40 CFR part 63, subpart ZZZZ.

Surface site means any combination of one or more graded pad sites, gravel pad sites, foundations, platforms, or the immediate 

physical location upon which equipment is physically affixed.

Two-stroke engine means a type of engine which completes the power cycle in single crankshaft revolution by combining the 

intake and compression operations into one stroke and the power and exhaust operations into a second stroke. This system 

requires auxiliary scavenging and inherently runs lean of stoichiometric.
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[69 FR 33506, June 15, 2004, as amended at 71 FR 20467, Apr. 20, 2006; 73 FR 3607, Jan. 18, 2008; 75 FR 9679, Mar. 3, 2010; 

75 FR 51592, Aug. 20, 2010; 76 FR 12867, Mar. 9, 2011]

Table 1ato Subpart ZZZZ of Part 63—Emission Limitations for Existing, New, and 

Reconstructed Spark Ignition, 4SRB Stationary RICE >500 HP Located at a Major 

Source of HAP Emissions

As stated in §§63.6600 and 63.6640, you must comply with the following emission limitations at 100 percent load plus or minus 10 

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

For each . . 

.

You must meet the following emission 

limitation, except during periods of startup . . 

. During periods of startup you must . . .

1. 4SRB 

stationary 

RICE

a. Reduce formaldehyde emissions by 76 

percent or more. If you commenced 

construction or reconstruction between 

December 19, 2002 and June 15, 2004, you may 

reduce formaldehyde emissions by 75 percent or 

more until June 15, 2007 or

Minimize the engine's time spent at idle and 

minimize the engine's startup time at startup 

to a period needed for appropriate and safe 

loading of the engine, not to exceed 30 

minutes, after which time the non-startup 

emission limitations apply.1

 b. Limit the concentration of formaldehyde in 

the stationary RICE exhaust to 350 ppbvd or 

less at 15 percent O2

1

Sources can petition the Administrator pursuant to the requirements of 40 CFR 63.6(g) for alternative work practices.

[75 FR 9679, Mar. 3, 2010, as amended at 75 FR 51592, Aug. 20, 2010]

Table 1bto Subpart ZZZZ of Part 63—Operating Limitations for Existing, New, and 

Reconstructed Spark Ignition 4SRB Stationary RICE >500 HP Located at a Major 

Source of HAP Emissions and Existing Spark Ignition 4SRB Stationary RICE >500 

HP Located at an Area Source of HAP Emissions

As stated in §§63.6600, 63.6603, 63.6630 and 63.6640, you must comply with the following operating limitations for existing, new 

and reconstructed 4SRB stationary RICE >500 HP located at a major source of HAP emissions and existing 4SRB stationary 

RICE >500 HP located at an area source of HAP emissions that operate more than 24 hours per calendar year:

For each . . . You must meet the following operating limitation . . .

1. 4SRB stationary RICE complying with the 

requirement to reduce formaldehyde emissions 

by 76 percent or more (or by 75 percent or 

more, if applicable) and using NSCR; or

4SRB stationary RICE complying with the 

requirement to limit the concentration of 

formaldehyde in the stationary RICE exhaust 

a. Maintain your catalyst so that the pressure drop across 

the catalyst does not change by more than 2 inches of 

water at 100 percent load plus or minus 10 percent from 

the pressure drop across the catalyst measured during the 

initial performance test; and

b. Maintain the temperature of your stationary RICE 

exhaust so that the catalyst inlet temperature is greater than 
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to 350 ppbvd or less at 15 percent O2 and 

using NSCR; or

4SRB stationary RICE complying with the 

requirement to limit the concentration of 

formaldehyde in the stationary RICE exhaust 

to 2.7 ppmvd or less at 15 percent O2 and 

using NSCR.

or equal to 750 °F and less than or equal to 1250 °F.

2. 4SRB stationary RICE complying with the 

requirement to reduce formaldehyde emissions 

by 76 percent or more (or by 75 percent or 

more, if applicable) and not using NSCR; or

4SRB stationary RICE complying with the 

requirement to limit the concentration of 

formaldehyde in the stationary RICE exhaust 

to 350 ppbvd or less at 15 percent O2 and not 

using NSCR; or

4SRB stationary RICE complying with the 

requirement to limit the concentration of 

formaldehyde in the stationary RICE exhaust 

to 2.7 ppmvd or less at 15 percent O2 and not 

using NSCR.

Comply with any operating limitations approved by the 

Administrator.

[76 FR 12867, Mar. 9, 2011]

Table 2ato Subpart ZZZZ of Part 63—Emission Limitations for New and 

Reconstructed 2SLB and Compression Ignition Stationary RICE >500 HP and New 

and Reconstructed 4SLB Stationary RICE ≥250 HP Located at a Major Source of 

HAP Emissions

As stated in §§63.6600 and 63.6640, you must comply with the following emission limitations for new and reconstructed lean burn 

and new and reconstructed compression ignition stationary RICE at 100 percent load plus or minus 10 percent:

For each . 

. .

You must meet the following emission limitation, 

except during periods of startup . . . During periods of startup you must . . .

1. 2SLB 

stationary 

RICE

a. Reduce CO emissions by 58 percent or more; or

b. Limit concentration of formaldehyde in the 

stationary RICE exhaust to 12 ppmvd or less at 15 

percent O2. If you commenced construction or 

reconstruction between December 19, 2002 and June 

15, 2004, you may limit concentration of 

formaldehyde to 17 ppmvd or less at 15 percent 

O2until June 15, 2007

Minimize the engine's time spent at idle 

and minimize the engine's startup time at 

startup to a period needed for appropriate 

and safe loading of the engine, not to 

exceed 30 minutes, after which time the 

non-startup emission limitations apply.1

2. 4SLB a. Reduce CO emissions by 93 percent or more; or
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stationary 

RICE

 b. Limit concentration of formaldehyde in the 

stationary RICE exhaust to 14 ppmvd or less at 15 

percent O2

3. CI 

stationary 

RICE

a. Reduce CO emissions by 70 percent or more; or

 b. Limit concentration of formaldehyde in the 

stationary RICE exhaust to 580 ppbvd or less at 15 

percent O2

1

Sources can petition the Administrator pursuant to the requirements of 40 CFR 63.6(g) for alternative work practices.

[75 FR 9680, Mar. 3, 2010]

Table 2bto Subpart ZZZZ of Part 63— Operating Limitations for New and 

Reconstructed 2SLB and Compression Ignition Stationary RICE >500 HP Located at 

a Major Source of HAP Emissions, New and Reconstructed 4SLB Stationary RICE 

≥250 HP Located at a Major Source of HAP Emissions, Existing Compression 

Ignition Stationary RICE >500 HP, and Existing 4SLB Stationary RICE >500 HP 

Located at an Area Source of HAP Emissions

As stated in §§63.6600, 63.6601, 63.6603, 63.6630, and 63.6640, you must comply with the following operating limitations for 

new and reconstructed 2SLB and compression ignition stationary RICE located at a major source of HAP emissions; new and 

reconstructed 4SLB stationary RICE ≥250 HP located at a major source of HAP emissions; existing compression ignition 

stationary RICE >500 HP; and existing 4SLB stationary RICE >500 HP located at an area source of HAP emissions that operate 

more than 24 hours per calendar year:

For each . . .

You must meet the following operating 

limitation . . .

1. 2SLB and 4SLB stationary RICE and CI stationary 

RICE complying with the requirement to reduce CO 

emissions and using an oxidation catalyst; or 2SLB and 

4SLB stationary RICE and CI stationary RICE 

complying with the requirement to limit the 

concentration of formaldehyde in the stationary RICE 

exhaust and using an oxidation catalyst; or 4SLB 

stationary RICE and CI stationary RICE complying with 

the requirement to limit the concentration of CO in the 

stationary RICE exhaust and using an oxidation catalyst

a. maintain your catalyst so that the pressure 

drop across the catalyst does not change by more 

than 2 inches of water at 100 percent load plus 

or minus 10 percent from the pressure drop 

across the catalyst that was measured during the 

initial performance test; and

b. maintain the temperature of your stationary 

RICE exhaust so that the catalyst inlet 

temperature is greater than or equal to 450 °F 

and less than or equal to 1350 °F.1

2. 2SLB and 4SLB stationary RICE and CI stationary 

RICE complying with the requirement to reduce CO 

Comply with any operating limitations approved 

by the Administrator.
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emissions and not using an oxidation catalyst; or 2SLB 

and 4SLB stationary RICE and CI stationary RICE 

complying with the requirement to limit the 

concentration of formaldehyde in the stationary RICE 

exhaust and not using an oxidation catalyst; or 4SLB 

stationary RICE and CI stationary RICE complying with 

the requirement to limit the concentration of CO in the 

stationary RICE exhaust and not using an oxidation 

catalyst

1

Sources can petition the Administrator pursuant to the requirements of 40 CFR 63.8(g) for a different temperature range.

[75 FR 51593, Aug. 20, 2010, as amended at 76 FR 12867, Mar. 9, 2011]

Table 2cto Subpart ZZZZ of Part 63—Requirements for Existing Compression 

Ignition Stationary RICE Located at a Major Source of HAP Emissions and Existing 

Spark Ignition Stationary RICE ≤500 HP Located at a Major Source of HAP 

Emissions

As stated in §§63.6600, 63.6602, and 63.6640, you must comply with the following requirements for existing compression ignition 

stationary RICE located at a major source of HAP emissions and existing spark ignition stationary RICE ≤500 HP located at a 

major source of HAP emissions:

For each . . .

You must meet the following 

requirement, except during 

periods of startup . . . During periods of startup you must . . .

1. Emergency stationary 

CI RICE and black start 

stationary CI RICE.1

a. Change oil and filter every 

500 hours of operation or 

annually, whichever comes 

first;2

b. Inspect air cleaner every 

1,000 hours of operation or 

annually, whichever comes 

first;

c. Inspect all hoses and belts 

every 500 hours of 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, nonblack start stationary CI 

RICE <100 HP

a. Change oil and filter every 

1,000 hours of operation or 

annually, whichever comes 

first;2

 b. Inspect air cleaner every 

1,000 hours of operation or 
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annually, whichever comes 

first;

 c. Inspect all hoses and belts 

every 500 hours of operation 

or annually, whichever comes 

first, and replace as necessary.3

3. Non-Emergency, nonblack start CI stationary 

RICE 100≤HP≤300 HP

Limit concentration of CO in 

the stationary RICE exhaust to 

230 ppmvd or less at 15 

percent O2

4. Non-Emergency, nonblack start CI stationary 

RICE 300<HP≤500

a. Limit concentration of CO

in the stationary RICE exhaust 

to 49 ppmvd or less at 15 

percent O2; or

 b. Reduce CO emissions by 70 

percent or more.

5. Non-Emergency, nonblack start stationary CI 

RICE >500 HP

a. Limit concentration of CO 

in the stationary RICE exhaust 

to 23 ppmvd or less at 15 

percent O2; or

 b. Reduce CO emissions by 70 

percent or more.

6. Emergency stationary SI 

RICE and black start 

stationary SI RICE.1

a. Change oil and filter every 

500 hours of operation or 

annually, whichever comes 

first;2

 b. Inspect spark plugs every 

1,000 hours of operation or 

annually, whichever comes 

first;

 c. Inspect all hoses and belts 

every 500 hours of operation 

or annually, whichever comes 

first, and replace as necessary.3

7. Non-Emergency, nonblack start stationary SI 

RICE <100 HP that are not 

2SLB stationary RICE

a. Change oil and filter every 

1,440 hours of operation or 

annually, whichever comes 

first;2

 b. Inspect spark plugs every 
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1,440 hours of operation or 

annually, whichever comes 

first;

 c. Inspect all hoses and belts 

every 1,440 hours of operation 

or annually, whichever comes 

first, and replace as necessary.3

8. Non-Emergency, nonblack start 2SLB 

stationary SI RICE <100 

HP

a. Change oil and filter every 

4,320 hours of operation or 

annually, whichever comes 

first;2

 b. Inspect spark plugs every 

4,320 hours of operation or 

annually, whichever comes 

first;

 c. Inspect all hoses and belts 

every 4,320 hours of operation 

or annually, whichever comes 

first, and replace as necessary.3

9. Non-emergency, nonblack start 2SLB 

stationary RICE 

100≤HP≤500

Limit concentration of CO in 

the stationary RICE exhaust to 

225 ppmvd or less at 15 

percent O2

10. Non-emergency, nonblack start 4SLB 

stationary RICE 

100≤HP≤500

Limit concentration of CO in 

the stationary RICE exhaust to 

47 ppmvd or less at 15 percent 

O2

11. Non-emergency, nonblack start 4SRB 

stationary RICE 

100≤HP≤500

Limit concentration of 

formaldehyde in the stationary 

RICE exhaust to 10.3 ppmvd 

or less at 15 percent O2

12. Non-emergency, nonblack start landfill or 

digester gas-fired 

stationary RICE 

100≤HP≤500

Limit concentration of CO in 

the stationary RICE exhaust to 

177 ppmvd or less at 15 

percent O2

1

If an emergency engine is operating during an emergency and it is not possible to shut down the engine in order to perform the 

work practice requirements on the schedule required in Table 2c of this subpart, or if performing the work practice on the required 

schedule would otherwise pose an unacceptable risk under Federal, State, or local law, the work practice can be delayed until the 

emergency is over or the unacceptable risk under Federal, State, or local law has abated. The work practice should be performed 

as soon as practicable after the emergency has ended or the unacceptable risk under Federal, State, or local law has abated. 
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Sources must report any failure to perform the work practice on the schedule required and the Federal, State or local law under 

which the risk was deemed unacceptable.

2

Sources have the option to utilize an oil analysis program as described in §63.6625(i) in order to extend the specified oil change 

requirement in Table 2c of this subpart.

3

Sources can petition the Administrator pursuant to the requirements of 40 CFR 63.6(g) for alternative work practices.

[75 FR 51593, Aug. 20, 2010]

Table 2dto Subpart ZZZZ of Part 63— Requirements for Existing Stationary RICE 

Located at Area Sources of HAP Emissions

As stated in §§63.6603 and 63.6640, you must comply with the following requirements for existing stationary RICE located at area 

sources of HAP emissions:

For each . . .

You must meet the 

following requirement,

except during periods 

of startup . . .

During periods of startup you 

must . . .

1. Non-Emergency, non-black start CI 

stationary RICE ≤300 HP

a. Change oil and filter 

every 1,000 hours of 

operation or annually, 

whichever comes first;1

Minimize the engine's time spent at 

idle and minimize the engine's 

startup time at startup to a period

needed for appropriate and safe 

loading of the engine, not to exceed 

30 minutes, after which time the 

non-startup emission limitations 

apply.

 b. Inspect air cleaner 

every 1,000 hours of 

operation or annually, 

whichever comes first;

c. Inspect all hoses and 

belts every 500 hours of 

operation or annually, 

whichever comes first, 

and replace as necessary.

2. Non-Emergency, non-black start CI 

stationary RICE 300<HP≤500

a. Limit concentration of 

CO in the stationary 

RICE exhaust to 49 

ppmvd at 15 percent O2; 

or

 b. Reduce CO emissions 

by 70 percent or more.
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3. Non-Emergency, non-black start CI 

stationary RICE >500 HP

a. Limit concentration of 

CO in the stationary 

RICE exhaust to 23 

ppmvd at 15 percent O2; 

or

 b. Reduce CO emissions 

by 70 percent or more.

4. Emergency stationary CI RICE and black 

start stationary CI RICE.2

a. Change oil and filter 

every 500 hours of 

operation or annually, 

whichever comes first;1

 b. Inspect air cleaner 

every 1,000 hours of 

operation or annually, 

whichever comes first; 

and

 c. Inspect all hoses and 

belts every 500 hours of 

operation or annually, 

whichever comes first, 

and replace as necessary.

5. Emergency stationary SI RICE; black 

start stationary SI RICE; non-emergency, 

non-black start 4SLB stationary RICE >500 

HP that operate 24 hours or less per 

calendar year; non-emergency, non-black 

start 4SRB stationary RICE >500 HP that 

operate 24 hours or less per calendar year.2

a. Change oil and filter 

every 500 hours of 

operation or annually, 

whichever comes first;1

b. Inspect spark plugs 

every 1,000 hours of 

operation or annually, 

whichever comes first; 

and

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 
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operation or annually, 

whichever comes first; 

and

 c. Inspect all hoses and 

belts every 4,320 hours 

of operation or annually, 

whichever comes first, 

and replace as necessary.

7. Non-emergency, non-black start 4SLB 

stationary RICE ≤500 HP

a. Change oil and filter 

every 1,440 hours of 

operation or annually, 

whichever comes first;1

 b. Inspect spark plugs 

every 1,440 hours of 

operation or annually, 

whichever comes first; 

and

 c. Inspect all hoses and 

belts every 1,440 hours 

of operation or annually, 

whichever comes first, 

and replace as necessary.

8. Non-emergency, non-black start 4SLB 

stationary RICE >500 HP

a. Limit concentration of 

CO in the stationary 

RICE exhaust to 47 

ppmvd at 15 percent O2; 

or

 b. Reduce CO emissions 

by 93 percent or more.

9. Non-emergency, non-black start 4SRB 

stationary RICE ≤500 HP

a. Change oil and filter 

every 1,440 hours of 

operation or annually, 

whichever comes first;1

 b. Inspect spark plugs 

every 1,440 hours of 

operation or annually, 

whichever comes first; 

and

 c. Inspect all hoses and 

belts every 1,440 hours 
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of operation or annually, 

whichever comes first, 

and replace as necessary.

10. Non-emergency, non-black start 4SRB 

stationary RICE >500 HP

a. Limit concentration of 

formaldehyde in the 

stationary RICE exhaust 

to 2.7 ppmvd at 15 

percent O2; or

 b. Reduce formaldehyde 

emissions by 76 percent 

or more.

11. Non-emergency, non-black start landfill 

or digester gas-fired stationary RICE

a. Change oil and filter 

every 1,440 hours of 

operation or annually, 

whichever comes first;1

 b. Inspect spark plugs 

every 1,440 hours of 

operation or annually, 

whichever comes first; 

and

 c. Inspect all hoses and 

belts every 1,440 hours 

of operation or annually, 

whichever comes first, 

and replace as necessary.

1

Sources have the option to utilize an oil analysis program as described in §63.6625(i) in order to extend the specified oil change 

requirement in Table 2d of this subpart.

2

If an emergency engine is operating during an emergency and it is not possible to shut down the engine in order to perform the 

management practice requirements on the schedule required in Table 2d of this subpart, or if performing the management 

practice on the required schedule would otherwise pose an unacceptable risk under Federal, State, or local law, the management 

practice can be delayed until the emergency is over or the unacceptable risk under Federal, State, or local law has abated. The 

management practice should be performed as soon as practicable after the emergency has ended or the unacceptable risk under 

Federal, State, or local law has abated. Sources must report any failure to perform the management practice on the schedule 

required and the Federal, State or local law under which the risk was deemed unacceptable.

[75 FR 51595, Aug. 20, 2010]

Table 3 to Subpart ZZZZ of Part 63—Subsequent Performance Tests

As stated in §§63.6615 and 63.6620, you must comply with the following subsequent performance test requirements:

For each . . . Complying with the You must . . .
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requirement to . . .

1. New or reconstructed 2SLB stationary RICE with a 

brake horsepower >500 located at major sources; new or 

reconstructed 4SLB stationary RICE with a brake 

horsepower ≥250 located at major sources; and new or 

reconstructed CI stationary RICE with a brake horsepower 

>500 located at major sources

Reduce CO emissions 

and not using a 

CEMS

Conduct subsequent 

performance tests 

semiannually.1

2. 4SRB stationary RICE with a brake horsepower ≥5,000 

located at major sources

Reduce formaldehyde 

emissions

Conduct subsequent 

performance tests 

semiannually.1

3. Stationary RICE with a brake horsepower >500 located 

at major sources and new or reconstructed 4SLB 

stationary RICE with a brake horsepower 250≤HP≤500 

located at major sources

Limit the 

concentration of 

formaldehyde in the 

stationary RICE 

exhaust

Conduct subsequent 

performance tests 

semiannually.1

4. Existing non-emergency, non-black start CI stationary 

RICE with a brake horsepower >500 that are not limited 

use stationary RICE; existing non-emergency, non-black 

start 4SLB and 4SRB stationary RICE located at an area 

source of HAP emissions with a brake horsepower >500 

that are operated more than 24 hours per calendar year that 

are not limited use stationary RICE

Limit or reduce CO 

or formaldehyde 

emissions

Conduct subsequent 

performance tests every 

8,760 hrs. or 3 years, 

whichever comes first.

5. Existing non-emergency, non-black start CI stationary 

RICE with a brake horsepower >500 that are limited use 

stationary RICE; existing non-emergency, non-black start 

4SLB and 4SRB stationary RICE located at an area source 

of HAP emissions with a brake horsepower >500 that are 

operated more than 24 hours per calendar year and are 

limited use stationary RICE

Limit or reduce CO 

or formaldehyde 

emissions

Conduct subsequent 

performance tests every 

8,760 hrs. or 5 years, 

whichever comes first.

1

After you have demonstrated compliance for two consecutive tests, you may reduce the frequency of subsequent performance 

tests to annually. If the results of any subsequent annual performance test indicate the stationary RICE is not in compliance with 

the CO or formaldehyde emission limitation, or you deviate from any of your operating limitations, you must resume semiannual

performance tests.

[75 FR 51596, Aug. 20, 2010]

Table 4 to Subpart ZZZZ of Part 63—Requirements for Performance Tests

As stated in §§63.6610, 63.6611, 63.6612, 63.6620, and 63.6640, you must comply with the following requirements for 

performance tests for stationary RICE:

For each . Complying with You must . . . Using . . . According to the following 
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. . the

requirement to 

. . .

requirements . . .

1. 2SLB, 

4SLB, and 

CI 

stationary 

RICE

a. Reduce CO 

emissions

i. Measure the O2at 

the inlet and outlet 

of the control 

device; and

(1) Portable CO and 

O2analyzer

(a) Using ASTM D6522–00 

(2005)a(incorporated by 

reference, see §63.14). 

Measurements to determine 

O2must be made at the same 

time as the measurements for 

CO concentration.

 ii. Measure the CO 

at the inlet and the 

outlet of the control 

device

(1) Portable CO and 

O2analyzer

(a) Using ASTM D6522–00 

(2005)ab(incorporated by 

reference, see §63.14) or 

Method 10 of 40 CFR 

appendix A. The CO 

concentration must be at 15 

percent O2, dry basis.

2. 4SRB 

stationary 

RICE

a. Reduce 

formaldehyde 

emissions

i. Select the 

sampling port 

location and the 

number of traverse 

points; and

(1) Method 1 or 1A of 40 

CFR part 60, appendix A 

§63.7(d)(1)(i)

(a) Sampling sites must be 

located at the inlet and outlet 

of the control device.

 ii. Measure O2at the 

inlet and outlet of 

the control device; 

and

(1) Method 3 or 3A or 3B 

of 40 CFR part 60, 

appendix A, or ASTM 

Method D6522–00m 

(2005)

(a) Measurements to 

determine O2concentration 

must be made at the same 

time as the measurements for 

formaldehyde concentration.

 iii. Measure 

moisture content at 

the inlet and outlet 

of the control 

device; and

(1) Method 4 of 40 CFR 

part 60, appendix A, or 

Test Method 320 of 40 

CFR part 63, appendix A, 

or ASTM D 6348–03

(a) Measurements to 

determine moisture content 

must be made at the same 

time and location as the 

measurements for 

formaldehyde concentration.

 iv. Measure 

formaldehyde at the 

inlet and the outlet 

of the control device

(1) Method 320 or 323 of 

40 CFR part 63, appendix 

A; or ASTM D6348–

03,cprovided in ASTM 

D6348–03 Annex A5 

(Analyte Spiking 

Technique), the percent R 

must be greater than or 

equal to 70 and less than 

(a) Formaldehyde 

concentration must be at 15 

percent O2, dry basis. Results 

of this test consist of the 

average of the three 1-hour or 

longer runs.
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or equal to 130

3. 

Stationary 

RICE

a. Limit the 

concentration of 

formaldehyde or 

CO in the 

stationary RICE 

exhaust

i. Select the 

sampling port 

location and the 

number of traverse 

points; and

(1) Method 1 or 1A of 40 

CFR part 60, appendix A 

§63.7(d)(1)(i)

(a) If using a control device, 

the sampling site must be 

located at the outlet of the 

control device.

 ii. Determine the 

O2concentration of 

the stationary RICE 

exhaust at the 

sampling port 

location; and

(1) Method 3 or 3A or 3B 

of 40 CFR part 60, 

appendix A, or ASTM 

Method D6522–00 (2005)

(a) Measurements to 

determine O2concentration 

must be made at the same 

time and location as the 

measurements for 

formaldehyde concentration.

 iii. Measure 

moisture content of 

the stationary RICE 

exhaust at the 

sampling port 

location; and

(1) Method 4 of 40 CFR 

part 60, appendix A, or 

Test Method 320 of 40 

CFR part 63, appendix A, 

or ASTM D 6348–03

(a) Measurements to 

determine moisture content 

must be made at the same 

time and location as the 

measurements for 

formaldehyde concentration.

 iv. Measure 

formaldehyde at the 

exhaust of the 

stationary RICE; or

(1) Method 320 or 323 of 

40 CFR part 63, appendix 

A; or ASTM D6348–

03,cprovided in ASTM 

D6348–03 Annex A5 

(Analyte Spiking 

Technique), the percent R 

must be greater than or 

equal to 70 and less than 

or equal to 130

(a) Formaldehyde 

concentration must be at 15 

percent O2, dry basis. Results 

of this test consist of the 

average of the three 1-hour or 

longer runs.

 v. Measure CO at 

the exhaust of the 

stationary RICE

(1) Method 10 of 40 CFR 

part 60, appendix A, 

ASTM Method D6522–

00 (2005),aMethod 320 of 

40 CFR part 63, appendix 

A, or ASTM D6348–03

(a) CO Concentration must 

be at 15 percent O2, dry 

basis. Results of this test 

consist of the average of the 

three 1-hour longer runs.

a

You may also use Methods 3A and 10 as options to ASTM–D6522–00 (2005). You may obtain a copy of ASTM–D6522–00 

(2005) from at least one of the following addresses: American Society for Testing and Materials, 100 Barr Harbor Drive, West 

Conshohocken, PA 19428–2959, or University Microfilms International, 300 North Zeeb Road, Ann Arbor, MI 48106. ASTM–

D6522–00 (2005) may be used to test both CI and SI stationary RICE.

b

You may also use Method 320 of 40 CFR part 63, appendix A, or ASTM D6348–03.

c

You may obtain a copy of ASTM–D6348–03 from at least one of the following addresses: American Society for Testing and 
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Materials, 100 Barr Harbor Drive, West Conshohocken, PA 19428–2959, or University Microfilms International, 300 North Zeeb 

Road, Ann Arbor, MI 48106.

[75 FR 51597, Aug. 20, 2010]

Table 5 to Subpart ZZZZ of Part 63—Initial Compliance With Emission Limitations 

and Operating Limitations

As stated in §§63.6612, 63.6625 and 63.6630, you must initially comply with the emission and operating limitations as required by 

the following:

For each . . .

Complying with the 

requirement to . . .

You have demonstrated initial 

compliance if. . .

1. New or reconstructed 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, existing nonemergency stationary CI RICE >500 HP 

located at an area source of HAP, and 

existing non-emergency 4SLB stationary 

RICE >500 HP located at an area source 

of HAP that are operated more than 24 

hours per calendar year

a. Reduce CO 

emissions and using 

oxidation catalyst, and 

using a CPMS

i. The average reduction of emissions of 

CO determined from the initial 

performance test achieves the required 

CO percent reduction; and

ii. You have installed a CPMS to 

continuously monitor catalyst inlet 

temperature according to the 

requirements in §63.6625(b); and

iii. You have recorded the catalyst 

pressure drop and catalyst inlet 

temperature during the initial 

performance test.

2. Non-emergency stationary CI RICE 

>500 HP located at a major source of 

HAP, existing non-emergency stationary 

CI RICE >500 HP located at an area 

source of HAP, and existing nonemergency 4SLB stationary RICE >500 

HP located at an area source of HAP that 

are operated more than 24 hours per 

calendar year

a. Limit the 

concentration of CO, 

using oxidation 

catalyst, and using a 

CPMS

i. The average CO concentration 

determined from the initial performance 

test is less than or equal to the CO 

emission limitation; and

ii. You have installed a CPMS to 

continuously monitor catalyst inlet 

temperature according to the 

requirements in §63.6625(b); and

iii. You have recorded the catalyst 

pressure drop and catalyst inlet 

temperature during the initial 

performance test.

3. New or reconstructed 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 

a. Reduce CO 

emissions and not 

using oxidation 

catalyst

i. The average reduction of emissions of 

CO determined from the initial 

performance test achieves the required 

CO percent reduction; and

ii. You have installed a CPMS to 
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major source of HAP, non-emergency 

stationary CI RICE >500 HP located at a 

major source of HAP, existing nonemergency stationary CI RICE >500 HP 

located at an area source of HAP, and 

existing non-emergency 4SLB stationary 

RICE >500 HP located at an area source 

of HAP that are operated more than 24 

hours per calendar year

continuously monitor operating 

parameters approved by the 

Administrator (if any) according to the 

requirements in §63.6625(b); and

iii. You have recorded the approved 

operating parameters (if any) during the 

initial performance test.

4. Non-emergency stationary CI RICE 

>500 HP located at a major source of 

HAP, existing non-emergency stationary 

CI RICE >500 HP located at an area 

source of HAP, and existing nonemergency 4SLB stationary RICE >500 

HP located at an area source of HAP that 

are operated more than 24 hours per 

calendar year

a. Limit the 

concentration of CO, 

and not using 

oxidation catalyst

i. The average CO concentration 

determined from the initial performance 

test is less than or equal to the CO 

emission limitation; and

ii. You have installed a CPMS to 

continuously monitor operating 

parameters approved by the 

Administrator (if any) according to the 

requirements in §63.6625(b); and

iii. You have recorded the approved 

operating parameters (if any) during the 

initial performance test.

5. New or reconstructed 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, existing nonemergency stationary CI RICE >500 HP 

located at an area source of HAP, and 

existing non-emergency 4SLB stationary 

RICE >500 HP located at an area source 

of HAP that are operated more than 24 

hours per calendar year

a. Reduce CO 

emissions, and using a 

CEMS

i. You have installed a CEMS to 

continuously monitor CO and either 

O2or CO2at both the inlet and outlet of 

the oxidation catalyst according to the 

requirements in §63.6625(a); and

ii. You have conducted a performance 

evaluation of your CEMS using PS 3 

and 4A of 40 CFR part 60, appendix B; 

and

iii. The average reduction of CO 

calculated using §63.6620 equals or 

exceeds the required percent reduction. 

The initial test comprises the first 4-

hour period after successful validation 

of the CEMS. Compliance is based on 

the average percent reduction achieved 

during the 4-hour period.

6. Non-emergency stationary CI RICE 

>500 HP located at a major source of 

HAP, existing non-emergency stationary 

CI RICE >500 HP located at an area 

source of HAP, and existing nona. Limit the 

concentration of CO, 

and using a CEMS

i. You have installed a CEMS to 

continuously monitor CO and either 

O2or CO2at the outlet of the oxidation 

catalyst according to the requirements 

in §63.6625(a); and
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060

Permit Reviewer: Josiah Balogun

emergency 4SLB stationary RICE >500 

HP located at an area source of HAP that 

are operated more than 24 hours per 

calendar year

ii. You have conducted a performance 

evaluation of your CEMS using PS 3 

and 4A of 40 CFR part 60, appendix B; 

and

 iii. The average concentration of CO 

calculated using §63.6620 is less than 

or equal to the CO emission limitation. 

The initial test comprises the first 4-

hour period after successful validation 

of the CEMS. Compliance is based on 

the average concentration measured 

during the 4-hour period.

7. Non-emergency 4SRB stationary RICE 

>500 HP located at a major source of 

HAP, and existing non-emergency 4SRB 

stationary RICE >500 HP located at an 

area source of HAP that are operated more 

than 24 hours per calendar year

a. Reduce 

formaldehyde 

emissions and using 

NSCR

i. The average reduction of emissions of 

formaldehyde determined from the 

initial performance test is equal to or 

greater than the required formaldehyde 

percent reduction; and

ii. You have installed a CPMS to 

continuously monitor catalyst inlet 

temperature according to the 

requirements in §63.6625(b); and

 iii. You have recorded the catalyst 

pressure drop and catalyst inlet 

temperature during the initial 

performance test.

8. Non-emergency 4SRB stationary RICE 

>500 HP located at a major source of 

HAP, and existing non-emergency 4SRB 

stationary RICE >500 HP located at an 

area source of HAP that are operated more 

than 24 hours per calendar year

a. Reduce 

formaldehyde 

emissions and not 

using NSCR

i. The average reduction of emissions of 

formaldehyde determined from the 

initial performance test is equal to or 

greater than the required formaldehyde 

percent reduction; and

ii. You have installed a CPMS to 

continuously monitor operating 

parameters approved by the 

Administrator (if any) according to the 

requirements in §63.6625(b); and

iii. You have recorded the approved 

operating parameters (if any) during the 

initial performance test.

9. Existing non-emergency 4SRB 

stationary RICE >500 HP located at an 

area source of HAP that are operated more 

than 24 hours per calendar year

a. Limit the 

concentration of 

formaldehyde and not 

using NSCR

i. The average formaldehyde 

concentration determined from the 

initial performance test is less than or 

equal to the formaldehyde emission 
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060

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limitation; and

 ii. You have installed a CPMS to 

continuously monitor operating 

parameters approved by the 

Administrator (if any) according to the 

requirements in §63.6625(b); and

 iii. You have recorded the approved 

operating parameters (if any) during the 

initial performance test.

10. New or reconstructed non-emergency 

stationary RICE >500 HP located at a 

major source of HAP, new or 

reconstructed non-emergency 4SLB 

stationary RICE 250≤HP≤500 located at a 

major source of HAP, and existing nonemergency 4SRB stationary RICE >500 

HP

a. Limit the 

concentration of 

formaldehyde in the 

stationary RICE 

exhaust and using 

oxidation catalyst or 

NSCR

i. The average formaldehyde 

concentration, corrected to 15 percent 

O2, dry basis, from the three test runs is 

less than or equal to the formaldehyde 

emission limitation; and

ii. You have installed a CPMS to 

continuously monitor catalyst inlet 

temperature according to the 

requirements in §63.6625(b); and

 iii. You have recorded the catalyst 

pressure drop and catalyst inlet 

temperature during the initial 

performance test.

11. New or reconstructed non-emergency 

stationary RICE >500 HP located at a

major source of HAP, new or 

reconstructed non-emergency 4SLB 

stationary RICE 250≤HP≤500 located at a 

major source of HAP, and existing nonemergency 4SRB stationary RICE >500 

HP

a. Limit the 

concentration of 

formaldehyde in the 

stationary RICE 

exhaust and not using 

oxidation catalyst or 

NSCR

i. The average formaldehyde 

concentration, corrected to 15 percent 

O2, dry basis, from the three test runs is 

less than or equal to the formaldehyde 

emission limitation; and

ii. You have installed a CPMS to 

continuously monitor operating 

parameters approved by the 

Administrator (if any) according to the 

requirements in §63.6625(b); and

 iii. You have recorded the approved 

operating parameters (if any) during the 

initial performance test.

12. Existing non-emergency stationary 

RICE 100≤HP≤500 located at a major 

source of HAP, and existing nonemergency stationary CI RICE 

300<HP≤500 located at an area source of 

HAP

a. Reduce CO or 

formaldehyde 

emissions

i. The average reduction of emissions of 

CO or formaldehyde, as applicable 

determined from the initial performance 

test is equal to or greater than the 

required CO or formaldehyde, as 

applicable, percent reduction.
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13. Existing non-emergency stationary 

RICE 100≤HP≤500 located at a major 

source of HAP, and existing nonemergency stationary CI RICE 

300<HP≤500 located at an area source of 

HAP

a. Limit the 

concentration of 

formaldehyde or CO in 

the stationary RICE 

exhaust

i. The average formaldehyde or CO 

concentration, as applicable, corrected 

to 15 percent O2, dry basis, from the 

three test runs is less than or equal to 

the formaldehyde or CO emission 

limitation, as applicable.

[76 FR 12867, Mar. 9, 2011]

Table 6 to Subpart ZZZZ of Part 63—Continuous Compliance With Emission 

Limitations, Operating Limitations, Work Practices, and Management Practices

As stated in §63.6640, you must continuously comply with the emissions and operating limitations and work or management 

practices as required by the following:

For each . . .

Complying with the 

requirement to . . .

You must demonstrate continuous 

compliance by . . .

1. New or reconstructed nonemergency 2SLB stationary RICE 

>500 HP located at a major source of 

HAP, new or reconstructed nonemergency 4SLB stationary RICE 

≥250 HP located at a major source of 

HAP, and new or reconstructed nonemergency CI stationary RICE >500 

HP located at a major source of HAP

a. Reduce CO emissions 

and using an oxidation 

catalyst, and using a 

CPMS

i. Conducting semiannual performance 

tests for CO to demonstrate that the 

required CO percent reduction is 

achieved;a

and

ii. Collecting the catalyst inlet 

temperature data according to 

§63.6625(b); and

iii. Reducing these data to 4-hour 

rolling averages; and

iv. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the catalyst inlet 

temperature; and

 v. Measuring the pressure drop across 

the catalyst once per month and 

demonstrating that the pressure drop 

across the catalyst is within the 

operating limitation established during 

the performance test.

2. New or reconstructed nonemergency 2SLB stationary RICE 

>500 HP located at a major source of 

HAP, new or reconstructed nonemergency 4SLB stationary RICE 

≥250 HP located at a major source of 

HAP, and new or reconstructed nona. 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;aand

ii. Collecting the approved operating 

parameter (if any) data according to 

§63.6625(b); and
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Permit Reviewer: Josiah Balogun

emergency CI stationary RICE >500 

HP located at a major source of HAP

iii. Reducing these data to 4-hour 

rolling averages; and

 iv. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the operating parameters 

established during the performance test.

3. New or reconstructed nonemergency 2SLB stationary RICE 

>500 HP located at a major source of 

HAP, new or reconstructed nonemergency 4SLB stationary RICE 

≥250 HP located at a major source of 

HAP, new or reconstructed nonemergency stationary CI RICE >500 

HP located at a major source of HAP, 

existing non-emergency stationary CI 

RICE >500 HP, existing nonemergency 4SLB stationary RICE 

>500 HP located at an area source of 

HAP that are operated more than 24 

hours per calendar year

a. Reduce CO emissions 

or limit the concentration 

of CO in the stationary 

RICE exhaust, and using a 

CEMS

i. Collecting the monitoring data 

according to §63.6625(a), reducing the 

measurements to 1-hour averages, 

calculating the percent reduction or 

concentration of CO emissions 

according to §63.6620; and

ii. Demonstrating that the catalyst 

achieves the required percent reduction 

of CO emissions over the 4-hour 

averaging period, or that the emission 

remain at or below the CO 

concentration limit; and

iii. Conducting an annual RATA of 

your CEMS using PS 3 and 4A of 40 

CFR part 60, appendix B, as well as 

daily and periodic data quality checks 

in accordance with 40 CFR part 60, 

appendix F, procedure 1.

4. Non-emergency 4SRB stationary 

RICE >500 HP located at a major 

source of HAP

a. Reduce formaldehyde 

emissions and using 

NSCR

i. Collecting the catalyst inlet 

temperature data according to 

§63.6625(b); and

 ii. Reducing these data to 4-hour rolling 

averages; and

 iii. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the catalyst inlet 

temperature; and

 iv. Measuring the pressure drop across 

the catalyst once per month and 

demonstrating that the pressure drop 

across the catalyst is within the 

operating limitation established during 

the performance test.

5. Non-emergency 4SRB stationary 

RICE >500 HP located at a major 

a. Reduce formaldehyde 

emissions and not using 

i. Collecting the approved operating 

parameter (if any) data according to 
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Permit Reviewer: Josiah Balogun

source of HAP NSCR §63.6625(b); and

ii. Reducing these data to 4-hour rolling 

averages; and

 iii. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the operating parameters 

established during the performance test.

6. Non-emergency 4SRB stationary 

RICE with a brake HP ≥5,000 located 

at a major source of HAP

a. Reduce formaldehyde 

emissions

Conducting semiannual performance 

tests for formaldehyde to demonstrate 

that the required formaldehyde percent 

reduction is achieved.a

7. New or reconstructed nonemergency stationary RICE >500 HP 

located at a major source of HAP and 

new or reconstructed non-emergency 

4SLB stationary RICE 250 ≤HP≤500 

located at a major source of HAP

a. Limit the concentration 

of formaldehyde in the

stationary RICE exhaust 

and using oxidation 

catalyst or NSCR

i. Conducting semiannual performance 

tests for formaldehyde to demonstrate 

that your emissions remain at or below 

the formaldehyde concentration 

limit;aand

ii. Collecting the catalyst inlet 

temperature data according to 

§63.6625(b); and

 iii. Reducing these data to 4-hour 

rolling averages; and

 iv. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the catalyst inlet 

temperature; and

 v. Measuring the pressure drop across 

the catalyst once per month and 

demonstrating that the pressure drop 

across the catalyst is within the 

operating limitation established during 

the performance test.

8. New or reconstructed nonemergency stationary RICE >500 HP 

located at a major source of HAP and 

new or reconstructed non-emergency 

4SLB stationary RICE 250 ≤HP≤500 

located at a major source of HAP

a. Limit the concentration 

of formaldehyde in the 

stationary RICE exhaust 

and not using oxidation 

catalyst or NSCR

i. Conducting semiannual performance 

tests for formaldehyde to demonstrate 

that your emissions remain at or below 

the formaldehyde concentration 

limit;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
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Permit Reviewer: Josiah Balogun

 iv. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the operating parameters 

established during the performance test.

9. Existing emergency and black start 

stationary RICE ≤500 HP located at a 

major source of HAP, existing nonemergency stationary RICE <100 HP 

located at a major source of HAP, 

existing emergency and black start 

stationary RICE located at an area 

source of HAP, existing nonemergency stationary CI RICE ≤300 

HP located at an area source of HAP, 

existing non-emergency 2SLB 

stationary RICE located at an area 

source of HAP, existing nonemergency landfill or digester gas 

stationary SI RICE located at an area 

source of HAP, existing nonemergency 4SLB and 4SRB stationary 

RICE ≤500 HP located at an area 

source of HAP, existing nonemergency 4SLB and 4SRB stationary 

RICE >500 HP located at an area 

source of HAP that operate 24 hours or 

less per calendar year

a. Work or Management 

practices

i. Operating and maintaining the 

stationary RICE according to the 

manufacturer's emission-related 

operation and maintenance instructions; 

or

ii. Develop and follow your own 

maintenance plan which must provide 

to the extent practicable for the 

maintenance and operation of the 

engine in a manner consistent with 

good air pollution control practice for 

minimizing emissions.

10. Existing stationary CI RICE >500 

HP that are not limited use stationary 

RICE, and existing 4SLB and 4SRB 

stationary RICE >500 HP located at an 

area source of HAP that operate more 

than 24 hours per calendar year and are 

not limited use stationary RICE

a. Reduce CO or 

formaldehyde emissions, 

or limit the concentration 

of formaldehyde or CO in 

the stationary RICE 

exhaust, and using 

oxidation catalyst or 

NSCR

i. Conducting performance tests every 

8,760 hours or 3 years, whichever 

comes first, for CO or formaldehyde, as 

appropriate, to demonstrate that the 

required CO or formaldehyde, as 

appropriate, percent reduction is 

achieved or that your emissions remain 

at or below the CO or formaldehyde 

concentration limit; and

 ii. Collecting the catalyst inlet 

temperature data according to 

§63.6625(b); and

 iii. Reducing these data to 4-hour 

rolling averages; and

 iv. Maintaining the 4-hour rolling 
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Permit Reviewer: Josiah Balogun

averages within the operating 

limitations for the catalyst inlet 

temperature; and

 v. Measuring the pressure drop across 

the catalyst once per month and 

demonstrating that the pressure drop 

across the catalyst is within the 

operating limitation established during 

the performance test.

11. Existing stationary CI RICE >500 

HP that are not limited use stationary 

RICE, and existing 4SLB and 4SRB 

stationary RICE >500 HP located at an 

area source of HAP that operate more 

than 24 hours per calendar year and are 

not limited use stationary RICE

a. Reduce CO or 

formaldehyde emissions, 

or limit the concentration 

of formaldehyde or CO in 

the stationary RICE 

exhaust, and not using 

oxidation catalyst or 

NSCR

i. Conducting performance tests every 

8,760 hours or 3 years, whichever 

comes first, for CO or formaldehyde, as 

appropriate, to demonstrate that the 

required CO or formaldehyde, as 

appropriate, percent reduction is 

achieved or that your emissions remain 

at or below the CO or formaldehyde 

concentration limit; and

 ii. Collecting the approved operating 

parameter (if any) data according to 

§63.6625(b); and

 iii. Reducing these data to 4-hour 

rolling averages; and

 iv. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the operating parameters 

established during the performance test.

12. Existing limited use CI stationary 

RICE >500 HP and existing limited use 

4SLB and 4SRB stationary RICE >500 

HP located at an area source of HAP 

that operate more than 24 hours per 

calendar year

a. Reduce CO or 

formaldehyde emissions 

or limit the concentration 

of formaldehyde or CO in 

the stationary RICE 

exhaust, and using an 

oxidation catalyst or 

NSCR

i. Conducting performance tests every 

8,760 hours or 5 years, whichever 

comes first, for CO or formaldehyde, as 

appropriate, to demonstrate that the 

required CO or formaldehyde, as 

appropriate, percent reduction is 

achieved or that your emissions remain 

at or below the CO or formaldehyde 

concentration limit; and

 ii. Collecting the catalyst inlet 

temperature data according to 

§63.6625(b); and

 iii. Reducing these data to 4-hour 

rolling averages; and
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Permit Reviewer: Josiah Balogun

 iv. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the catalyst inlet 

temperature; and

 v. Measuring the pressure drop across 

the catalyst once per month and 

demonstrating that the pressure drop 

across the catalyst is within the 

operating limitation established during 

the performance test.

13. Existing limited use CI stationary 

RICE >500 HP and existing limited use 

4SLB and 4SRB stationary RICE >500 

HP located at an area source of HAP 

that operate more than 24 hours per 

calendar year

a. Reduce CO or 

formaldehyde emissions 

or limit the concentration 

of formaldehyde or CO in 

the stationary RICE 

exhaust, and not using an 

oxidation catalyst or 

NSCR

i. Conducting performance tests every 

8,760 hours or 5 years, whichever 

comes first, for CO or formaldehyde, as 

appropriate, to demonstrate that the 

required CO or formaldehyde, as 

appropriate, percent reduction is 

achieved or that your emissions remain 

at or below the CO or formaldehyde 

concentration limit; and

 ii. Collecting the approved operating 

parameter (if any) data according to 

§63.6625(b); and

 iii. Reducing these data to 4-hour 

rolling averages; and

 iv. Maintaining the 4-hour rolling 

averages within the operating 

limitations for the operating parameters 

established during the performance test.

a

After you have demonstrated compliance for two consecutive tests, you may reduce the frequency of subsequent performance 

tests to annually. If the results of any subsequent annual performance test indicate the stationary RICE is not in compliance with 

the CO or formaldehyde emission limitation, or you deviate from any of your operating limitations, you must resume semiannual

performance tests.

[76 FR 12870, Mar. 9, 2011]

Table 7 to Subpart ZZZZ of Part 63—Requirements for Reports

As stated in §63.6650, you must comply with the following requirements for reports:

For each ...

You must 

submit a ... The report must contain ...

You 

must 

submit 
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Permit Reviewer: Josiah Balogun

the 

report ...

1. Existing non-emergency, non-black 

start stationary 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 nonemergency 4SRB stationary RICE >500 

HP located at a major source of HAP; 

existing non-emergency, non-black start 

stationary CI RICE >300 HP located at 

an area source of HAP; existing nonemergency, non-black start 4SLB and 

4SRB stationary RICE >500 HP located 

at an area source of HAP and operated 

more than 24 hours per calendar year; 

new or reconstructed non-emergency 

stationary RICE >500 HP located at a

major source of HAP; and new or 

reconstructed non-emergency 4SLB 

stationary RICE 250≤HP≤500 located at 

a major source of HAP

Compliance 

report

a. If there are no deviations from any 

emission limitations or operating 

limitations that apply to you, a statement 

that there were no deviations from the 

emission limitations or operating 

limitations during the reporting period. If 

there were no periods during which the 

CMS, including CEMS and CPMS, was 

out-of-control, as specified in §63.8(c)(7), 

a statement that there were not periods 

during which the CMS was out-of-control 

during the reporting period; or

b. If you had a deviation from any 

emission limitation or operating limitation 

during the reporting period, the 

information in §63.6650(d). If there were 

periods during which the CMS, including 

CEMS and CPMS, was out-of-control, as 

specified in §63.8(c)(7), the information in 

§63.6650(e); or

c. If you had a malfunction during the 

reporting period, the information in 

§63.6650(c)(4)

i. Semiannually according to the 

requirements in §63.6650(b)(1)–(5) for 

engines that are not limited use stationary 

RICE subject to numerical emission 

limitations; and

ii. Annually according to the requirements 

in §63.6650(b)(6)–(9) for engines that are 

limited use stationary RICE subject to 

numerical emission limitations.

i. Semiannually according to the 

requirements in §63.6650(b).

i. Semiannually according to the 

requirements in §63.6650(b).

2. New or reconstructed non-emergency 

stationary RICE that combusts landfill 

gas or digester gas equivalent to 10 

percent or more of the gross heat input 

on an annual basis

Report a. The fuel flow rate of each fuel and the 

heating values that were used in your 

calculations, and you must demonstrate 

that the percentage of heat input provided 

by landfill gas or digester gas, is 

equivalent to 10 percent or more of the 
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Permit Reviewer: Josiah Balogun

gross heat input on an annual basis; and

i. Annually, according to the requirements 

in §63.6650.

 b. The operating limits provided in your 

federally enforceable permit, and any 

deviations from these limits; and

i. See item 2.a.i.

 c. Any problems or errors suspected with 

the meters.

i. See item 2.a.i.

[75 FR 51603, Aug. 20, 2010]

Table 8 to Subpart ZZZZ of Part 63—Applicability of General Provisions to Subpart 

ZZZZ.

As stated in §63.6665, you must comply with the following applicable general provisions.

General 

provisions 

citation Subject of citation

Applies to 

subpart Explanation

§63.1 General applicability of the 

General Provisions

Yes.

§63.2 Definitions Yes Additional terms defined in 

§63.6675.

§63.3 Units and abbreviations Yes.

§63.4 Prohibited activities and 

circumvention

Yes.

§63.5 Construction and reconstruction Yes.

§63.6(a) Applicability Yes.

§63.6(b)(1)–(4) Compliance dates for new and 

reconstructed sources

Yes.

§63.6(b)(5) Notification Yes.

§63.6(b)(6) [Reserved]

§63.6(b)(7) Compliance dates for new and 

reconstructed area sources that 

become major sources

Yes.

§63.6(c)(1)–(2) Compliance dates for existing Yes.
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sources

§63.6(c)(3)–(4) [Reserved]

§63.6(c)(5) Compliance dates for existing 

area sources that become major 

sources

Yes.

§63.6(d) [Reserved]

§63.6(e) Operation and maintenance No.

§63.6(f)(1) Applicability of standards No.

§63.6(f)(2) Methods for determining 

compliance

Yes.

§63.6(f)(3) Finding of compliance Yes.

§63.6(g)(1)–(3) Use of alternate standard Yes.

§63.6(h) Opacity and visible emission 

standards

No Subpart ZZZZ does not contain 

opacity or visible emission 

standards.

§63.6(i) Compliance extension 

procedures and criteria

Yes.

§63.6(j) Presidential compliance 

exemption

Yes.

§63.7(a)(1)–(2) Performance test dates Yes Subpart ZZZZ contains 

performance test dates at 

§§63.6610, 63.6611, and 63.6612.

§63.7(a)(3) CAA section 114 authority Yes.

§63.7(b)(1) Notification of performance test Yes Except that §63.7(b)(1) only 

applies as specified in §63.6645.

§63.7(b)(2) Notification of rescheduling Yes Except that §63.7(b)(2) only 

applies as specified in §63.6645.

§63.7(c) Quality assurance/test plan Yes Except that §63.7(c) only applies 

as specified in §63.6645.

§63.7(d) Testing facilities Yes.

§63.7(e)(1) Conditions for conducting 

performance tests

No. Subpart ZZZZ specifies conditions 

for conducting performance tests 

at §63.6620.

§63.7(e)(2) Conduct of performance tests and 

reduction of data

Yes Subpart ZZZZ specifies test 

methods at §63.6620.
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§63.7(e)(3) Test run duration Yes.

§63.7(e)(4) Administrator may require other 

testing under section 114 of the 

CAA

Yes.

§63.7(f) Alternative test method 

provisions

Yes.

§63.7(g) Performance test data analysis, 

recordkeeping, and reporting

Yes.

§63.7(h) Waiver of tests Yes.

§63.8(a)(1) Applicability of monitoring 

requirements

Yes Subpart ZZZZ contains specific 

requirements for monitoring at 

§63.6625.

§63.8(a)(2) Performance specifications Yes.

§63.8(a)(3) [Reserved]

§63.8(a)(4) Monitoring for control devices No.

§63.8(b)(1) Monitoring Yes.

§63.8(b)(2)–(3) Multiple effluents and multiple 

monitoring systems

Yes.

§63.8(c)(1) Monitoring system operation and 

maintenance

Yes.

§63.8(c)(1)(i) Routine and predictable SSM Yes.

§63.8(c)(1)(ii) SSM not in Startup Shutdown 

Malfunction Plan

Yes.

§63.8(c)(1)(iii) Compliance with operation and 

maintenance requirements

Yes.

§63.8(c)(2)–(3) Monitoring system installation Yes.

§63.8(c)(4) Continuous monitoring system 

(CMS) requirements

Yes Except that subpart ZZZZ does not 

require Continuous Opacity 

Monitoring System (COMS).

§63.8(c)(5) COMS minimum procedures No Subpart ZZZZ does not require 

COMS.

§63.8(c)(6)–(8) CMS requirements Yes Except that subpart ZZZZ does not 

require COMS.

§63.8(d) CMS quality control Yes.
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060

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§63.8(e) CMS performance evaluation Yes Except for §63.8(e)(5)(ii), which 

applies to COMS.

 Except that 

§63.8(e) only 

applies as 

specified in 

§63.6645.

§63.8(f)(1)–(5) Alternative monitoring method Yes Except that §63.8(f)(4) only 

applies as specified in §63.6645.

§63.8(f)(6) Alternative to relative accuracy 

test

Yes Except that §63.8(f)(6) only 

applies as specified in §63.6645.

§63.8(g) Data reduction Yes Except that provisions for COMS 

are not applicable. Averaging 

periods for demonstrating 

compliance are specified at 

§§63.6635 and 63.6640.

§63.9(a) Applicability and State 

delegation of notification 

requirements

Yes.

§63.9(b)(1)–(5) Initial notifications Yes Except that §63.9(b)(3) is 

reserved.

 Except that 

§63.9(b) only 

applies as 

specified in 

§63.6645.

§63.9(c) Request for compliance 

extension

Yes Except that §63.9(c) only applies 

as specified in §63.6645.

§63.9(d) Notification of special 

compliance requirements for new 

sources

Yes Except that §63.9(d) only applies 

as specified in §63.6645.

§63.9(e) Notification of performance test Yes Except that §63.9(e) only applies 

as specified in §63.6645.

§63.9(f) Notification of visible emission 

(VE)/opacity test

No Subpart ZZZZ does not contain 

opacity or VE standards.

§63.9(g)(1) Notification of performance 

evaluation

Yes Except that §63.9(g) only applies 

as specified in §63.6645.

§63.9(g)(2) Notification of use of COMS No Subpart ZZZZ does not contain 
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data 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.

§63.10(b)(2)(i)–(v) Records related to SSM No.

§63.10(b)(2)(vi)–

(xi)

Records Yes.

§63.10(b)(2)(xii) Record when under waiver Yes.

§63.10(b)(2)(xiii) Records when using alternative 

to RATA

Yes For CO standard if using RATA 

alternative.

§63.10(b)(2)(xiv) Records of supporting 

documentation

Yes.

§63.10(b)(3) Records of applicability 

determination

Yes.

§63.10(c) Additional records for sources 

using CEMS

Yes Except that §63.10(c)(2)–(4) and 

(9) are reserved.

§63.10(d)(1) General reporting requirements Yes.

§63.10(d)(2) Report of performance test 

results

Yes.
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§63.10(d)(3) Reporting opacity or VE 

observations

No Subpart ZZZZ does not contain 

opacity or VE standards.

§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]
Attachment B to a PSD/Part 70 Operating Permit

Standards of Performance for Coal Preparation and Processing Plants

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

Source Name: Indiana Gasification LLC

Source Location: CR 200 N and Base Road, Rockport, IN 47635

County: Spencer

SIC Code: 4925, 2819

Operation Permit No.: T 147-30464-00060

Operation Permit Issuance Date: Yet to be Issued

Permit Reviewer: Josiah Balogun

Subpart Y—Standards of Performance for Coal Preparation and Processing 

Plants

Source: 74 FR 51977, Oct. 8, 2009, unless otherwise noted.

§ 60.250 Applicability and designation of affected facility.

(a) The provisions of this subpart apply to affected facilities in coal preparation and processing plants that process 

more than 181 megagrams (Mg) (200 tons) of coal per day.

(b) The provisions in §60.251, §60.252(a), §60.253(a), §60.254(a), §60.255(a), and §60.256(a) of this subpart are 

applicable to any of the following affected facilities that commenced construction, reconstruction or modification after 

October 27, 1974, and on or before April 28, 2008: Thermal dryers, pneumatic coal-cleaning equipment (air tables), 

coal processing and conveying equipment (including breakers and crushers), and coal storage systems, transfer and 

loading systems.

(c) The provisions in §60.251, §60.252(b)(1) and (c), §60.253(b), §60.254(b), §60.255(b) through (h), §60.256(b) and 

(c), §60.257, and §60.258 of this subpart are applicable to any of the following affected facilities that commenced 

construction, reconstruction or modification after April 28, 2008, and on or before May 27, 2009: Thermal dryers, 

pneumatic coal-cleaning equipment (air tables), coal processing and conveying equipment (including breakers and 

crushers), and coal storage systems, transfer and loading systems.

(d) The provisions in §60.251, §60.252(b)(1) through (3), and (c), §60.253(b), §60.254(b) and (c), §60.255(b) through 

(h), §60.256(b) and (c), §60.257, and §60.258 of this subpart are applicable to any of the following affected facilities 

that commenced construction, reconstruction or modification after May 27, 2009: Thermal dryers, pneumatic coalcleaning equipment (air tables), coal processing and conveying equipment (including breakers and crushers), coal 

storage systems, transfer and loading systems, and open storage piles.

§ 60.251 Definitions.

As used in this subpart, all terms not defined herein have the meaning given them in the Clean Air Act (Act) and in 

subpart A of this part.

(a) Anthracite means coal that is classified as anthracite according to the American Society of Testing and Materials 

in ASTM D388 (incorporated by reference, see §60.17).

(b) Bag leak detection system means a system that is capable of continuously monitoring relative particulate matter 

(dust loadings) in the exhaust of a fabric filter to detect bag leaks and other upset conditions. A bag leak detection 

system includes, but is not limited to, an instrument that operates on triboelectric, light scattering, light transmittance, 

or other effect to continuously monitor relative particulate matter loadings.
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(c) Bituminous coal means solid fossil fuel classified as bituminous coal by ASTM D388 (incorporated by reference—

see §60.17).

(d) Coal means:

(1) For units constructed, reconstructed, or modified on or before May 27, 2009, all solid fossil fuels classified as 

anthracite, bituminous, subbituminous, or lignite by ASTM D388 (incorporated by reference— see §60.17).

(2) For units constructed, reconstructed, or modified after May 27, 2009, all solid fossil fuels classified as anthracite, 

bituminous, subbituminous, or lignite by ASTM D388 (incorporated by reference— see §60.17), and coal refuse.

(e) Coal preparation and processing plant means any facility (excluding underground mining operations) which 

prepares coal by one or more of the following processes: breaking, crushing, screening, wet or dry cleaning, and 

thermal drying.

(f) Coal processing and conveying equipment means any machinery used to reduce the size of coal or to separate 

coal from refuse, and the equipment used to convey coal to or remove coal and refuse from the machinery. This 

includes, but is not limited to, breakers, crushers, screens, and conveyor belts. Equipment located at the mine face is 

not considered to be part of the coal preparation and processing plant.

(g) Coal refuse means waste products of coal mining, physical coal cleaning, and coal preparation operations ( e.g. 

culm, gob, etc. ) containing coal, matrix material, clay, and other organic and inorganic material.

(h) Coal storage system means any facility used to store coal except for open storage piles.

(i) Design controlled potential PM emissions rate means the theoretical particulate matter (PM) emissions (Mg) that 

would result from the operation of a control device at its design emissions rate (grams per dry standard cubic meter 

(g/dscm)), multiplied by the maximum design flow rate (dry standard cubic meter per minute (dscm/min)), multiplied 

by 60 (minutes per hour (min/hr)), multiplied by 8,760 (hours per year (hr/yr)), divided by 1,000,000 (megagrams per 

gram (Mg/g)).

(j) Indirect thermal dryer means a thermal dryer that reduces the moisture content of coal through indirect heating of 

the coal through contact with a heat transfer medium. If the source of heat (the source of combustion or furnace) is 

subject to another subpart of this part, then the furnace and the associated emissions are not part of the affected 

facility. However, if the source of heat is not subject to another subpart of this part, then the furnace and the 

associated emissions are part of the affected facility.

(k) Lignite means coal that is classified as lignite A or B according to the American Society of Testing and Materials in 

ASTM D388 (incorporated by reference, see §60.17).

(l) Mechanical vent means any vent that uses a powered mechanical drive (machine) to induce air flow.

(m) Open storage pile means any facility, including storage area, that is not enclosed that is used to store coal, 

including the equipment used in the loading, unloading, and conveying operations of the facility.

(n) Operating day means a 24-hour period between 12 midnight and the following midnight during which coal is 

prepared or processed at any time by the affected facility. It is not necessary that coal be prepared or processed the 

entire 24-hour period.

(o) Pneumatic coal-cleaning equipment means:

(1) For units constructed, reconstructed, or modified on or before May 27, 2009, any facility which classifies 

bituminous coal by size or separates bituminous coal from refuse by application of air stream(s).

(2) For units constructed, reconstructed, or modified after May 27, 2009, any facility which classifies coal by size or 

separates coal from refuse by application of air stream(s).
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(p) Potential combustion concentration means the theoretical emissions (nanograms per joule (ng/J) or pounds per 

million British thermal units (lb/MMBtu) heat input) that would result from combustion of a fuel in an uncleaned state 

without emission control systems, as determined using Method 19 of appendix A–7 of this part.

(q) Subbituminous coal means coal that is classified as subbituminous A, B, or C according to the American Society 

of Testing and Materials in ASTM D388 (incorporated by reference, see §60.17).

(r) Thermal dryer means:

(1) For units constructed, reconstructed, or modified on or before May 27, 2009, any facility in which the moisture 

content of bituminous coal is reduced by contact with a heated gas stream which is exhausted to the atmosphere.

(2) For units constructed, reconstructed, or modified after May 27, 2009, any facility in which the moisture content of 

coal is reduced by either contact with a heated gas stream which is exhausted to the atmosphere or through indirect 

heating of the coal through contact with a heated heat transfer medium.

(s) Transfer and loading system means any facility used to transfer and load coal for shipment.

§ 60.252 Standards for thermal dryers.

(a) On and after the date on which the performance test is conducted or required to be completed under §60.8, 

whichever date comes first, an owner or operator of a thermal dryer constructed, reconstructed, or modified on or 

before April 28, 2008, subject to the provisions of this subpart must meet the requirements in paragraphs (a)(1) and 

(a)(2) of this section.

(1) The owner or operator shall not cause to be discharged into the atmosphere from the thermal dryer any gases 

which contain PM in excess of 0.070 g/dscm (0.031 grains per dry standard cubic feet (gr/dscf)); and

(2) The owner or operator shall not cause to be discharged into the atmosphere from the thermal dryer any gases 

which exhibit 20 percent opacity or greater.

(b) Except as provided in paragraph (c) of this section, on and after the date on which the performance test is 

conducted or required to be completed under §60.8, whichever date comes first, an owner or operator of a thermal 

dryer constructed, reconstructed, or modified after April 28, 2008, subject to the provisions of this subpart must meet 

the applicable standards for PM and opacity, as specified in paragraph (b)(1) of this section. In addition, and except 

as provided in paragraph (c) of this section, on and after the date on which the performance test is conducted or 

required to be completed under §60.8, whichever date comes first, an owner or operator of a thermal dryer 

constructed, reconstructed, or modified after May 29, 2009, subject to the provisions of this subpart must also meet 

the applicable standards for sulfur dioxide (SO2), and combined nitrogen oxides (NOX) and carbon monoxide (CO) as 

specified in paragraphs (b)(2) and (b)(3) of this section.

(1) The owner or operator must meet the requirements for PM emissions in paragraphs (b)(1)(i) through (iii) of this 

section, as applicable to the affected facility.

(i) For each thermal dryer constructed or reconstructed after April 28, 2008, the owner or operator must meet the 

requirements of (b)(1)(i)(A) and (b)(1)(i)(B).

(A) The owner or operator must not cause to be discharged into the atmosphere from the thermal dryer any gases 

that contain PM in excess of 0.023 g/dscm (0.010 grains per dry standard cubic feet (gr/dscf)); and

(B) The owner or operator must not cause to be discharged into the atmosphere from the thermal dryer any gases 

that exhibit 10 percent opacity or greater.

(ii) For each thermal dryer modified after April 28, 2008, the owner or operator must meet the requirements of 

paragraphs (b)(1)(ii)(A) and (b)(1)(ii)(B) of this section.
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(A) The owner or operator must not cause to be discharged to the atmosphere from the affected facility any gases 

which contain PM in excess of 0.070 g/dscm (0.031 gr/dscf); and

(B) The owner or operator must not cause to be discharged into the atmosphere from the affected facility any gases 

which exhibit 20 percent opacity or greater.

(2) Except as provided in paragraph (b)(2)(iii) of this section, for each thermal dryer constructed, reconstructed, or 

modified after May 27, 2009, the owner or operator must meet the requirements for SO2emissions in either 

paragraph (b)(2)(i) or (b)(2)(ii) of this section.

(i) The owner or operator must not cause to be discharged into the atmosphere from the affected facility any gases 

that contain SO2in excess of 85 ng/J (0.20 lb/MMBtu) heat input; or

(ii) The owner or operator must not cause to be discharged into the atmosphere from the affected facility any gases 

that either contain SO2in excess of 520 ng/J (1.20 lb/MMBtu) heat input or contain SO2in excess of 10 percent of the 

potential combustion concentration ( i.e., the facility must achieve at least a 90 percent reduction of the potential 

combustion concentration and may not exceed a maximum emissions rate of 1.2 lb/MMBtu (520 ng/J)).

(iii) Thermal dryers that receive all of their thermal input from a source other than coal or residual oil, that receive all 

of their thermal input from a source subject to an SO2limit under another subpart of this part, or that use waste heat 

or residual from the combustion of coal or residual oil as their only thermal input are not subject to the SO2limits of 

this section.

(3) Except as provided in paragraph (b)(3)(iii) of this section, the owner or operator must meet the requirements for 

combined NOXand CO emissions in paragraph (b)(3)(i) or (b)(3)(ii) of this section, as applicable to the affected 

facility.

(i) For each thermal dryer constructed after May 27, 2009, the owner or operator must not cause to be discharged 

into the atmosphere from the affected facility any gases which contain a combined concentration of NOXand CO in 

excess of 280 ng/J (0.65 lb/MMBtu) heat input.

(ii) For each thermal dryer reconstructed or modified after May 27, 2009, the owner or operator must not cause to be 

discharged into the atmosphere from the affected facility any gases which contain combined concentration of 

NOXand CO in excess of 430 ng/J (1.0 lb/MMBtu) heat input.

(iii) Thermal dryers that receive all of their thermal input from a source other than coal or residual oil, that receive all 

of their thermal input from a source subject to a NOXlimit and/or CO limit under another subpart of this part, or that 

use waste heat or residual from the combustion of coal or residual oil as their only thermal input, are not subject to 

the combined NOXand CO limits of this section.

(c) Thermal dryers receiving all of their thermal input from an affected facility covered under another 40 CFR Part 60 

subpart must meet the applicable requirements in that subpart but are not subject to the requirements in this subpart.

§ 60.253 Standards for pneumatic coal-cleaning equipment.

(a) On and after the date on which the performance test is conducted or required to be completed under §60.8, 

whichever date comes first, an owner or operator of pneumatic coal-cleaning equipment constructed, reconstructed, 

or modified on or before April 28, 2008, must meet the requirements of paragraphs (a)(1) and (a)(2) of this section.

(1) The owner or operator must not cause to be discharged into the atmosphere from the pneumatic coal-cleaning 

equipment any gases that contain PM in excess of 0.040 g/dscm (0.017 gr/dscf); and

(2) The owner or operator must not cause to be discharged into the atmosphere from the pneumatic coal-cleaning 

equipment any gases that exhibit 10 percent opacity or greater.
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(b) On and after the date on which the performance test is conducted or required to be completed under §60.8, 

whichever date comes first, an owner or operator of pneumatic coal-cleaning equipment constructed, reconstructed, 

or modified after April 28, 2008, must meet the requirements in paragraphs (b)(1) and (b)(2) of this section.

(1) The owner of operator must not cause to be discharged into the atmosphere from the pneumatic coal-cleaning 

equipment any gases that contain PM in excess or 0.023 g/dscm (0.010 gr/dscf); and

(2) The owner or operator must not cause to be discharged into the atmosphere from the pneumatic coal-cleaning 

equipment any gases that exhibit greater than 5 percent opacity.

§ 60.254 Standards for coal processing and conveying equipment, coal 

storage systems, transfer and loading systems, and open storage piles.

(a) On and after the date on which the performance test is conducted or required to be completed under §60.8, 

whichever date comes first, an owner or operator shall not cause to be discharged into the atmosphere from any coal 

processing and conveying equipment, coal storage system, or coal transfer and loading system processing coal 

constructed, reconstructed, or modified on or before April 28, 2008, gases which exhibit 20 percent opacity or greater.

(b) On and after the date on which the performance test is conducted or required to be completed under §60.8, 

whichever date comes first, an owner or operator of any coal processing and conveying equipment, coal storage 

system, or coal transfer and loading system processing coal constructed, reconstructed, or modified after April 28, 

2008, must meet the requirements in paragraphs (b)(1) through (3) of this section, as applicable to the affected 

facility.

(1) Except as provided in paragraph (b)(3) of this section, the owner or operator must not cause to be discharged into 

the atmosphere from the affected facility any gases which exhibit 10 percent opacity or greater.

(2) The owner or operator must not cause to be discharged into the atmosphere from any mechanical vent on an 

affected facility gases which contain particulate matter in excess of 0.023 g/dscm (0.010 gr/dscf).

(3) Equipment used in the loading, unloading, and conveying operations of open storage piles are not subject to the 

opacity limitations of paragraph (b)(1) of this section.

(c) The owner or operator of an open storage pile, which includes the equipment used in the loading, unloading, and 

conveying operations of the affected facility, constructed, reconstructed, or modified after May 27, 2009, must 

prepare and operate in accordance with a submitted fugitive coal dust emissions control plan that is appropriate for 

the site conditions as specified in paragraphs (c)(1) through (6) of this section.

(1) The fugitive coal dust emissions control plan must identify and describe the control measures the owner or 

operator will use to minimize fugitive coal dust emissions from each open storage pile.

(2) For open coal storage piles, the fugitive coal dust emissions control plan must require that one or more of the 

following control measures be used to minimize to the greatest extent practicable fugitive coal dust: Locating the 

source inside a partial enclosure, installing and operating a water spray or fogging system, applying appropriate 

chemical dust suppression agents on the source (when the provisions of paragraph (c)(6) of this section are met), 

use of a wind barrier, compaction, or use of a vegetative cover. The owner or operator must select, for inclusion in the 

fugitive coal dust emissions control plan, the control measure or measures listed in this paragraph that are most 

appropriate for site conditions. The plan must also explain how the measure or measures selected are applicable and 

appropriate for site conditions. In addition, the plan must be revised as needed to reflect any changing conditions at 

the source.

(3) Any owner or operator of an affected facility that is required to have a fugitive coal dust emissions control plan 

may petition the Administrator to approve, for inclusion in the plan for the affected facility, alternative control 

measures other than those specified in paragraph (c)(2) of this section as specified in paragraphs (c)(3)(i) through (iv) 

of this section.
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(i) The petition must include a description of the alternative control measures, a copy of the fugitive coal dust 

emissions control plan for the affected facility that includes the alternative control measures, and information sufficient 

for EPA to evaluate the demonstrations required by paragraph (c)(3)(ii) of this section.

(ii) The owner or operator must either demonstrate that the fugitive coal dust emissions control plan that includes the 

alternate control measures will provide equivalent overall environmental protection or demonstrate that it is either 

economically or technically infeasible for the affected facility to use the control measures specifically identified in 

paragraph (c)(2).

(iii) While the petition is pending, the owner or operator must comply with the fugitive coal dust emissions control plan 

including the alternative control measures submitted with the petition. Operation in accordance with the plan 

submitted with the petition shall be deemed to constitute compliance with the requirement to operate in accordance 

with a fugitive coal dust emissions control plan that contains one of the control measures specifically identified in 

paragraph (c)(2) of this section while the petition is pending.

(iv) If the petition is approved by the Administrator, the alternative control measures will be approved for inclusion in 

the fugitive coal dust emissions control plan for the affected facility. In lieu of amending this subpart, a letter will be 

sent to the facility describing the specific control measures approved. The facility shall make any such letters and the 

applicable fugitive coal dust emissions control plan available to the public. If the Administrator determines it is

appropriate, the conditions and requirements of the letter can be reviewed and changed at any point.

(4) The owner or operator must submit the fugitive coal dust emissions control plan to the Administrator or delegated 

authority as specified in paragraphs (c)(4)(i) and (c)(4)(ii) of this section.

(i) The plan must be submitted to the Administrator or delegated authority prior to startup of the new, reconstructed, 

or modified affected facility, or 30 days after the effective date of this rule, whichever is later.

(ii) The plan must be revised as needed to reflect any changing conditions at the source. Such revisions must be 

dated and submitted to the Administrator or delegated authority before a source can operate pursuant to these 

revisions. The Administrator or delegated authority may also object to such revisions as specified in paragraph (c)(5) 

of this section.

(5) The Administrator or delegated authority may object to the fugitive coal dust emissions control plan as specified in 

paragraphs (c)(5)(i) and (c)(5)(ii) of this section.

(i) The Administrator or delegated authority may object to any fugitive coal dust emissions control plan that it has 

determined does not meet the requirements of paragraphs (c)(1) and (c)(2) of this section.

(ii) If an objection is raised, the owner or operator, within 30 days from receipt of the objection, must submit a revised 

fugitive coal dust emissions control plan to the Administrator or delegated authority. The owner or operator must 

operate in accordance with the revised fugitive coal dust emissions control plan. The Administrator or delegated 

authority retain the right, under paragraph (c)(5) of this section, to object to the revised control plan if it determines 

the plan does not meet the requirements of paragraphs (c)(1) and (c)(2) of this section.

(6) Where appropriate chemical dust suppression agents are selected by the owner or operator as a control measure 

to minimize fugitive coal dust emissions, (1) only chemical dust suppressants with Occupational Safety and Health 

Administration (OSHA)-compliant material safety data sheets (MSDS) are to be allowed; (2) the MSDS must be 

included in the fugitive coal dust emissions control plan; and (3) the owner or operator must consider and document 

in the fugitive coal dust emissions control plan the site-specific impacts associated with the use of such chemical dust 

suppressants.
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§ 60.255 Performance tests and other compliance requirements.

(a) An owner or operator of each affected facility that commenced construction, reconstruction, or modification on or 

before April 28, 2008, must conduct all performance tests required by §60.8 to demonstrate compliance with the 

applicable emission standards using the methods identified in §60.257.

(b) An owner or operator of each affected facility that commenced construction, reconstruction, or modification after 

April 28, 2008, must conduct performance tests according to the requirements of §60.8 and the methods identified in 

§60.257 to demonstrate compliance with the applicable emissions standards in this subpart as specified in 

paragraphs (b)(1) and (2) of this section.

(1) For each affected facility subject to a PM, SO2, or combined NOXand CO emissions standard, an initial 

performance test must be performed. Thereafter, a new performance test must be conducted according the 

requirements in paragraphs (b)(1)(i) through (iii) of this section, as applicable.

(i) If the results of the most recent performance test demonstrate that emissions from the affected facility are greater 

than 50 percent of the applicable emissions standard, a new performance test must be conducted within 12 calendar 

months of the date that the previous performance test was required to be completed.

(ii) If the results of the most recent performance test demonstrate that emissions from the affected facility are 50 

percent or less of the applicable emissions standard, a new performance test must be conducted within 24 calendar 

months of the date that the previous performance test was required to be completed.

(iii) An owner or operator of an affected facility that has not operated for the 60 calendar days prior to the due date of 

a performance test is not required to perform the subsequent performance test until 30 calendar days after the next 

operating day.

(2) For each affected facility subject to an opacity standard, an initial performance test must be performed. 

Thereafter, a new performance test must be conducted according to the requirements in paragraphs (b)(2)(i) through 

(iii) of this section, as applicable, except as provided for in paragraphs (e) and (f) of this section. Performance test 

and other compliance requirements for coal truck dump operations are specified in paragraph (h) of this section.

(i) If any 6-minute average opacity reading in the most recent performance test exceeds half the applicable opacity 

limit, a new performance test must be conducted within 90 operating days of the date that the previous performance 

test was required to be completed.

(ii) If all 6-minute average opacity readings in the most recent performance test are equal to or less than half the 

applicable opacity limit, a new performance test must be conducted within 12 calendar months of the date that the 

previous performance test was required to be completed.

(iii) An owner or operator of an affected facility continuously monitoring scrubber parameters as specified in 

§60.256(b)(2) is exempt from the requirements in paragraphs (b)(2)(i) and (ii) if opacity performance tests are 

conducted concurrently with (or within a 60-minute period of) PM performance tests.

(c) If any affected coal processing and conveying equipment ( e.g., breakers, crushers, screens, conveying systems), 

coal storage systems, or coal transfer and loading systems that commenced construction, reconstruction, or 

modification after April 28, 2008, are enclosed in a building, and emissions from the building do not exceed any of the 

standards in § 60.254 that apply to the affected facility, then the facility shall be deemed to be in compliance with 

such standards.

(d) An owner or operator of an affected facility (other than a thermal dryer) that commenced construction, 

reconstruction, or modification after April 28, 2008, is subject to a PM emission standard and uses a control device 

with a design controlled potential PM emissions rate of 1.0 Mg (1.1 tons) per year or less is exempted from the 

requirements of paragraphs (b)(1)(i) and (ii) of this section provided that the owner or operator meets all of the 

conditions specified in paragraphs (d)(1) through (3) of this section. This exemption does not apply to thermal dryers.

(1) PM emissions, as determined by the most recent performance test, are less than or equal to the applicable limit,
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(2) The control device manufacturer's recommended maintenance procedures are followed, and

(3) All 6-minute average opacity readings from the most recent performance test are equal to or less than half the 

applicable opacity limit or the monitoring requirements in paragraphs (e) or (f) of this section are followed.

(e) For an owner or operator of a group of up to five of the same type of affected facilities that commenced 

construction, reconstruction, or modification after April 28, 2008, that are subject to PM emissions standards and use 

identical control devices, the Administrator or delegated authority may allow the owner or operator to use a single PM 

performance test for one of the affected control devices to demonstrate that the group of affected facilities is in 

compliance with the applicable emissions standards provided that the owner or operator meets all of the conditions 

specified in paragraphs (e)(1) through (3) of this section.

(1) PM emissions from the most recent performance test for each individual affected facility are 90 percent or less of 

the applicable PM standard;

(2) The manufacturer's recommended maintenance procedures are followed for each control device; and

(3) A performance test is conducted on each affected facility at least once every 5 calendar years.

(f) As an alternative to meeting the requirements in paragraph (b)(2) of this section, an owner or operator of an 

affected facility that commenced construction, reconstruction, or modification after April 28, 2008, may elect to comply 

with the requirements in paragraph (f)(1) or (f)(2) of this section.

(1) Monitor visible emissions from each affected facility according to the requirements in paragraphs (f)(1)(i) through 

(iii) of this section.

(i) Conduct one daily 15-second observation each operating day for each affected facility (during normal operation) 

when the coal preparation and processing plant is in operation. Each observation must be recorded as either visible 

emissions observed or no visible emissions observed. Each observer determining the presence of visible emissions 

must meet the training requirements specified in §2.3 of Method 22 of appendix A–7 of this part. If visible emissions 

are observed during any 15-second observation, the owner or operator must adjust the operation of the affected 

facility and demonstrate within 24 hours that no visible emissions are observed from the affected facility. If visible 

emissions are observed, a Method 9, of appendix A–4 of this part, performance test must be conducted within 45 

operating days.

(ii) Conduct monthly visual observations of all process and control equipment. If any deficiencies are observed, the 

necessary maintenance must be performed as expeditiously as possible.

(iii) Conduct a performance test using Method 9 of appendix A–4 of this part at least once every 5 calendar years for 

each affected facility.

(2) Prepare a written site-specific monitoring plan for a digital opacity compliance system for approval by the 

Administrator or delegated authority. The plan shall require observations of at least one digital image every 15 

seconds for 10-minute periods (during normal operation) every operating day. An approvable monitoring plan must 

include a demonstration that the occurrences of visible emissions are not in excess of 5 percent of the observation 

period. For reference purposes in preparing the monitoring plan, see OAQPS “Determination of Visible Emission 

Opacity from Stationary Sources Using Computer-Based Photographic Analysis Systems.” This document is 

available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality and Planning Standards; 

Sector Policies and Programs Division; Measurement 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. The monitoring plan approved by the Administrator or delegated authority shall be implemented 

by the owner or operator.

(g) As an alternative to meeting the requirements in paragraph (b)(2) of this section, an owner or operator of an 

affected facility that commenced construction, reconstruction, or modification after April 28, 2008, subject to a visible 

emissions standard under this subpart may install, operate, and maintain a continuous opacity monitoring system 

(COMS). Each COMS used to comply with provisions of this subpart must be installed, calibrated, maintained, and 

continuously operated according to the requirements in paragraphs (g)(1) and (2) of this section.
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(1) The COMS must meet Performance Specification 1 in 40 CFR part 60, appendix B.

(2) The COMS must comply with the quality assurance requirements in paragraphs (g)(2)(i) through (v) of this 

section.

(i) The owner or operator must automatically (intrinsic to the opacity monitor) check the zero and upscale (span) 

calibration drifts at least once daily. For particular COMS, the acceptable range of zero and upscale calibration 

materials is as defined in the applicable version of Performance Specification 1 in 40 CFR part 60, appendix B.

(ii) The owner or operator must adjust the zero and span whenever the 24-hour zero drift or 24-hour span drift 

exceeds 4 percent opacity. The COMS must allow for the amount of excess zero and span drift measured at the 24-

hour interval checks to be recorded and quantified. The optical surfaces exposed to the effluent gases must be 

cleaned prior to performing the zero and span drift adjustments, except for systems using automatic zero 

adjustments. For systems using automatic zero adjustments, the optical surfaces must be cleaned when the 

cumulative automatic zero compensation exceeds 4 percent opacity.

(iii) The owner or operator must apply a method for producing a simulated zero opacity condition and an upscale 

(span) opacity condition using a certified neutral density filter or other related technique to produce a known 

obscuration of the light beam. All procedures applied must provide a system check of the analyzer internal optical 

surfaces and all electronic circuitry including the lamp and photodetector assembly.

(iv) Except during periods of system breakdowns, repairs, calibration checks, and zero and span adjustments, the 

COMS must be in continuous operation and must complete a minimum of one cycle of sampling and analyzing for 

each successive 10-second period and one cycle of data recording for each successive 6-minute period.

(v) The owner or operator must reduce all data from the COMS to 6-minute averages. Six-minute opacity averages 

must be calculated from 36 or more data points equally spaced over each 6-minute period. Data recorded during 

periods of system breakdowns, repairs, calibration checks, and zero and span adjustments must not be included in 

the data averages. An arithmetic or integrated average of all data may be used.

(h) The owner or operator of each affected coal truck dump operation that commenced construction, reconstruction, 

or modification after April 28, 2008, must meet the requirements specified in paragraphs (h)(1) through (3) of this 

section.

(1) Conduct an initial performance test using Method 9 of appendix A–4 of this part according to the requirements in 

paragraphs (h)(1)(i) and(ii).

(i) Opacity readings shall be taken during the duration of three separate truck dump events. Each truck dump event 

commences when the truck bed begins to elevate and concludes when the truck bed returns to a horizontal position.

(ii) Compliance with the applicable opacity limit is determined by averaging all 15-second opacity readings made 

during the duration of three separate truck dump events.

(2) Conduct monthly visual observations of all process and control equipment. If any deficiencies are observed, the 

necessary maintenance must be performed as expeditiously as possible.

(3) Conduct a performance test using Method 9 of appendix A–4 of this part at least once every 5 calendar years for 

each affected facility.

§ 60.256 Continuous monitoring requirements.
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(a) The owner or operator of each affected facility constructed, reconstructed, or modified on or before April 28, 2008, 

must meet the monitoring requirements specified in paragraphs (a)(1) and (2) of this section, as applicable to the 

affected facility.

(1) The owner or operator of any thermal dryer shall install, calibrate, maintain, and continuously operate monitoring 

devices as follows:

(i) A monitoring device for the measurement of the temperature of the gas stream at the exit of the thermal dryer on a 

continuous basis. The monitoring device is to be certified by the manufacturer to be accurate within ±1.7 °C (±3 °F).

(ii) For affected facilities that use wet scrubber emission control equipment:

(A) A monitoring device for the continuous measurement of the pressure loss through the venturi constriction of the 

control equipment. The monitoring device is to be certified by the manufacturer to be accurate within ±1 inch water 

gauge.

(B) A monitoring device for the continuous measurement of the water supply pressure to the control equipment. The 

monitoring device is to be certified by the manufacturer to be accurate within ±5 percent of design water supply 

pressure. The pressure sensor or tap must be located close to the water discharge point. The Administrator shall 

have discretion to grant requests for approval of alternative monitoring locations.

(2) All monitoring devices under paragraph (a) of this section are to be recalibrated annually in accordance with 

procedures under §60.13(b).

(b) The owner or operator of each affected facility constructed, reconstructed, or modified after April 28, 2008, that 

has one or more mechanical vents must install, calibrate, maintain, and continuously operate the monitoring devices 

specified in paragraphs (b)(1) through (3) of this section, as applicable to the mechanical vent and any control device 

installed on the vent.

(1) For mechanical vents with fabric filters (baghouses) with design controlled potential PM emissions rates of 25 Mg 

(28 tons) per year or more, a bag leak detection system according to the requirements in paragraph (c) of this 

section.

(2) For mechanical vents with wet scrubbers, monitoring devices according to the requirements in paragraphs (b)(2)(i) 

through (iv) of this section.

(i) A monitoring device for the continuous measurement of the pressure loss through the venturi constriction of the 

control equipment. The monitoring device is to be certified by the manufacturer to be accurate within ±1 inch water 

gauge.

(ii) A monitoring device for the continuous measurement of the water supply flow rate to the control equipment. The 

monitoring device is to be certified by the manufacturer to be accurate within ±5 percent of design water supply flow 

rate.

(iii) A monitoring device for the continuous measurement of the pH of the wet scrubber liquid. The monitoring device 

is to be certified by the manufacturer to be accurate within ±5 percent of design pH.

(iv) An average value for each monitoring parameter must be determined during each performance test. Each 

monitoring parameter must then be maintained within 10 percent of the value established during the most recent 

performance test on an operating day average basis.

(3) For mechanical vents with control equipment other than wet scrubbers, a monitoring device for the continuous 

measurement of the reagent injection flow rate to the control equipment, as applicable. The monitoring device is to be 

certified by the manufacturer to be accurate within ±5 percent of design injection flow rate. An average reagent 

injection flow rate value must be determined during each performance test. The reagent injection flow rate must then 

be maintained within 10 percent of the value established during the most recent performance test on an operating 

day average basis.
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(c) Each bag leak detection system used to comply with provisions of this subpart must be installed, calibrated, 

maintained, and continuously operated according to the requirements in paragraphs (c)(1) through (3) of this section.

(1) The bag leak detection system must meet the specifications and requirements in paragraphs (c)(1)(i) through (viii) 

of this section.

(i) The bag leak detection system must be certified by the manufacturer to be capable of detecting PM emissions at 

concentrations of 1 milligram per dry standard cubic meter (mg/dscm) (0.00044 grains per actual cubic foot (gr/acf)) 

or less.

(ii) The bag leak detection system sensor must provide output of relative PM loadings. The owner or operator shall 

continuously record the output from the bag leak detection system using electronic or other means ( e.g., using a strip 

chart recorder or a data logger).

(iii) The bag leak detection system must be equipped with an alarm system that will sound when the system detects 

an increase in relative particulate loading over the alarm set point established according to paragraph (c)(1)(iv) of this 

section, and the alarm must be located such that it can be heard by the appropriate plant personnel.

(iv) In the initial adjustment of the bag leak detection system, the owner or operator must establish, at a minimum, the 

baseline output by adjusting the sensitivity (range) and the averaging period of the device, the alarm set points, and 

the alarm delay time.

(v) Following initial adjustment, the owner or operator must not adjust the averaging period, alarm set point, or alarm 

delay time without approval from the Administrator or delegated authority except as provided in paragraph (c)(2)(vi) of 

this section.

(vi) Once per quarter, the owner or operator may adjust the sensitivity of the bag leak detection system to account for 

seasonal effects, including temperature and humidity, according to the procedures identified in the site-specific 

monitoring plan required by paragraph (c)(2) of this section.

(vii) The owner or operator must install the bag leak detection sensor downstream of the fabric filter.

(viii) Where multiple detectors are required, the system's instrumentation and alarm may be shared among detectors.

(2) The owner or operator must develop and submit to the Administrator or delegated authority for approval a sitespecific monitoring plan for each bag leak detection system. This plan must be submitted to the Administrator or 

delegated authority 30 days prior to startup of the affected facility. The owner or operator must operate and maintain 

the bag leak detection system according to the site-specific monitoring plan at all times. Each monitoring plan must 

describe the items in paragraphs (c)(2)(i) through (vi) of this section.

(i) Installation of the bag leak detection system;

(ii) Initial and periodic adjustment of the bag leak detection system, including how the alarm set-point will be 

established;

(iii) Operation of the bag leak detection system, including quality assurance procedures;

(iv) How the bag leak detection system will be maintained, including a routine maintenance schedule and spare parts 

inventory list;

(v) How the bag leak detection system output will be recorded and stored; and

(vi) Corrective action procedures as specified in paragraph (c)(3) of this section. In approving the site-specific 

monitoring plan, the Administrator or delegated authority may allow the owner and operator more than 3 hours to 

alleviate a specific condition that causes an alarm if the owner or operator identifies in the monitoring plan this 

specific condition as one that could lead to an alarm, adequately explains why it is not feasible to alleviate this 
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condition within 3 hours of the time the alarm occurs, and demonstrates that the requested time will ensure alleviation 

of this condition as expeditiously as practicable.

(3) For each bag leak detection system, the owner or operator must initiate procedures to determine the cause of 

every alarm within 1 hour of the alarm. Except as provided in paragraph (c)(2)(vi) of this section, the owner or 

operator must alleviate the cause of the alarm within 3 hours of the alarm by taking whatever corrective action(s) are 

necessary. Corrective actions may include, but are not limited to the following:

(i) Inspecting the fabric filter for air leaks, torn or broken bags or filter media, or any other condition that may cause an 

increase in PM emissions;

(ii) Sealing off defective bags or filter media;

(iii) Replacing defective bags or filter media or otherwise repairing the control device;

(iv) Sealing off a defective fabric filter compartment;

(v) Cleaning the bag leak detection system probe or otherwise repairing the bag leak detection system; or

(vi) Shutting down the process producing the PM emissions.

§ 60.257 Test methods and procedures.

(a) The owner or operator must determine compliance with the applicable opacity standards as specified in 

paragraphs (a)(1) through (3) of this section.

(1) Method 9 of appendix A–4 of this part and the procedures in §60.11 must be used to determine opacity, with the 

exceptions specified in paragraphs (a)(1)(i) and (ii).

(i) The duration of the Method 9 of appendix A–4 of this part performance test shall be 1 hour (ten 6-minute 

averages).

(ii) If, during the initial 30 minutes of the observation of a Method 9 of appendix A–4 of this part performance test, all 

of the 6-minute average opacity readings are less than or equal to half the applicable opacity limit, then the 

observation period may be reduced from 1 hour to 30 minutes.

(2) To determine opacity for fugitive coal dust emissions sources, the additional requirements specified in paragraphs 

(a)(2)(i) through (iii) must be used.

(i) The minimum distance between the observer and the emission source shall be 5.0 meters (16 feet), and the sun 

shall be oriented in the 140-degree sector of the back.

(ii) The observer shall select a position that minimizes interference from other fugitive coal dust emissions sources 

and make observations such that the line of vision is approximately perpendicular to the plume and wind direction.

(iii) The observer shall make opacity observations at the point of greatest opacity in that portion of the plume where 

condensed water vapor is not present. Water vapor is not considered a visible emission.

(3) A visible emissions observer may conduct visible emission observations for up to three fugitive, stack, or vent 

emission points within a 15-second interval if the following conditions specified in paragraphs (a)(3)(i) through (iii) of 

this section are met.

(i) No more than three emissions points may be read concurrently.
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(ii) All three emissions points must be within a 70 degree viewing sector or angle in front of the observer such that the 

proper sun position can be maintained for all three points.

(iii) If an opacity reading for any one of the three emissions points is within 5 percent opacity from the applicable 

standard (excluding readings of zero opacity), then the observer must stop taking readings for the other two points 

and continue reading just that single point.

(b) The owner or operator must conduct all performance tests required by §60.8 to demonstrate compliance with the 

applicable emissions standards specified in §60.252 according to the requirements in §60.8 using the applicable test 

methods and procedures in paragraphs (b)(1) through (8) of this section.

(1) Method 1 or 1A of appendix A–4 of this part shall be used to select sampling port locations and the number of 

traverse points in each stack or duct. Sampling sites must be located at the outlet of the control device (or at the 

outlet of the emissions source if no control device is present) prior to any releases to the atmosphere.

(2) Method 2, 2A, 2C, 2D, 2F, or 2G of appendix A–4 of this part shall be used to determine the volumetric flow rate 

of the stack gas.

(3) Method 3, 3A, or 3B of appendix A–4 of this part shall be used to determine the dry molecular weight of the stack 

gas. The owner or operator may use ANSI/ASME PTC 19.10–1981, “Flue and Exhaust Gas Analyses (incorporated 

by reference— see §60.17) as an alternative to Method 3B of appendix A–2 of this part.

(4) Method 4 of appendix A–4 of this part shall be used to determine the moisture content of the stack gas.

(5) Method 5, 5B or 5D of appendix A–4 of this part or Method 17 of appendix A–7 of this part shall be used to 

determine the PM concentration as follows:

(i) The sampling time and sample volume for each run shall be at least 60 minutes and 0.85 dscm (30 dscf). 

Sampling shall begin no less than 30 minutes after startup and shall terminate before shutdown procedures begin. A 

minimum of three valid test runs are needed to comprise a PM performance test.

(ii) Method 5 of appendix A of this part shall be used only to test emissions from affected facilities without wet flue gas 

desulfurization (FGD) systems.

(iii) Method 5B of appendix A of this part is to be used only after wet FGD systems.

(iv) Method 5D of appendix A–4 of this part shall be used for positive pressure fabric filters and other similar 

applications ( e.g., stub stacks and roof vents).

(v) Method 17 of appendix A–6 of this part may be used at 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–3 of this part may be used in Method 17 of appendix A–6 of this part only if it is used after 

a wet FGD system. Do not use Method 17 of appendix A–6 of this part after wet FGD systems if the effluent is 

saturated or laden with water droplets.

(6) Method 6, 6A, or 6C of appendix A–4 of this part shall be used to determine the SO2concentration. A minimum of 

three valid test runs are needed to comprise an SO2performance test.

(7) Method 7 or 7E of appendix A–4 of this part shall be used to determine the NOXconcentration. A minimum of 

three valid test runs are needed to comprise an NOXperformance test.

(8) Method 10 of appendix A–4 of this part shall be used to determine the CO concentration. A minimum of three valid 

test runs are needed to comprise a CO performance test. CO performance tests are conducted concurrently (or 

within a 60-minute period) with NOXperformance tests.

§ 60.258 Reporting and recordkeeping.
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(a) The owner or operator of a coal preparation and processing plant that commenced construction, reconstruction, or 

modification after April 28, 2008, shall maintain in a logbook (written or electronic) on-site and make it available upon 

request. The logbook shall record the following:

(1) The manufacturer's recommended maintenance procedures and the date and time of any maintenance and 

inspection activities and the results of those activities. Any variance from manufacturer recommendation, if any, shall 

be noted.

(2) The date and time of periodic coal preparation and processing plant visual observations, noting those sources 

with visible emissions along with corrective actions taken to reduce visible emissions. Results from the actions shall 

be noted.

(3) The amount and type of coal processed each calendar month.

(4) The amount of chemical stabilizer or water purchased for use in the coal preparation and processing plant.

(5) Monthly certification that the dust suppressant systems were operational when any coal was processed and that 

manufacturer's recommendations were followed for all control systems. Any variance from the manufacturer's 

recommendations, if any, shall be noted.

(6) Monthly certification that the fugitive coal dust emissions control plan was implemented as described. Any 

variance from the plan, if any, shall be noted. A copy of the applicable fugitive coal dust emissions control plan and 

any letters from the Administrator providing approval of any alternative control measures shall be maintained with the 

logbook. Any actions, e.g. objections, to the plan and any actions relative to the alternative control measures, e.g. 

approvals, shall be noted in the logbook as well.

(7) For each bag leak detection system, the owner or operator must keep the records specified in paragraphs (a)(7)(i) 

through (iii) of this section.

(i) Records of the bag leak detection system output;

(ii) Records of bag leak detection system adjustments, including the date and time of the adjustment, the initial bag 

leak detection system settings, and the final bag leak detection settings; and

(iii) The date and time of all bag leak detection system alarms, the time that procedures to determine the cause of the 

alarm were initiated, the cause of the alarm, an explanation of the actions taken, the date and time the cause of the 

alarm was alleviated, and whether the cause of the alarm was alleviated within 3 hours of the alarm.

(8) A copy of any applicable monitoring plan for a digital opacity compliance system and monthly certification that the 

plan was implemented as described. Any variance from plan, if any, shall be noted.

(9) During a performance test of a wet scrubber, and each operating day thereafter, the owner or operator shall 

record the measurements of the scrubber pressure loss, water supply flow rate, and pH of the wet scrubber liquid.

(10) During a performance test of control equipment other than a wet scrubber, and each operating day thereafter, 

the owner or operator shall record the measurements of the reagent injection flow rate, as applicable.

(b) For the purpose of reports required under section 60.7(c), any owner operator subject to the provisions of this 

subpart also shall report semiannually periods of excess emissions as follow:

(1) The owner or operator of an affected facility with a wet scrubber shall submit semiannual reports to the 

Administrator or delegated authority of occurrences when the measurements of the scrubber pressure loss, water 

supply flow rate, or pH of the wet scrubber liquid vary by more than 10 percent from the average determined during 

the most recent performance test.
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(2) The owner or operator of an affected facility with control equipment other than a wet scrubber shall submit 

semiannual reports to the Administrator or delegated authority of occurrences when the measurements of the reagent 

injection flow rate, as applicable, vary by more than 10 percent from the average determined during the most recent 

performance test.

(3) All 6-minute average opacities that exceed the applicable standard.

(c) The owner or operator of an affected facility shall submit the results of initial performance tests to the 

Administrator or delegated authority, consistent with the provisions of section 60.8. The owner or operator who elects 

to comply with the reduced performance testing provisions of sections 60.255(c) or (d) shall include in the 

performance test report identification of each affected facility that will be subject to the reduced testing. The owner or 

operator electing to comply with section 60.255(d) shall also include information which demonstrates that the control 

devices are identical.

(d) After July 1, 2011, within 60 days after the date of completing each performance evaluation conducted to 

demonstrate compliance with this subpart, the owner or operator of the affected facility must submit the test data to 

EPA by successfully entering the data electronically into EPA's WebFIRE data base available at 

http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main. For performance tests that cannot be entered into WebFIRE 

( i.e., Method 9 of appendix A–4 of this part opacity performance tests) the owner or operator of the affected facility 

must mail a summary copy to United States Environmental Protection Agency; Energy Strategies Group; 109 TW 

Alexander DR; mail code: D243–01; RTP, NC 27711.
Attachment C to a PSD/Part 70 Operating Permit

Standards of Performance for Industrial-Commercial-Institutional Steam 

Generating Units [40 CFR Part 60, Subpart Db] [326 IAC 12]

Source Name: Indiana Gasification LLC

Source Location: CR 200 N and Base Road, Rockport, IN 47635

County: Spencer

SIC Code: 4925, 2819

Operation Permit No.: T 147-30464-00060

Operation Permit Issuance Date: Yet to be Issued

Permit Reviewer: Josiah Balogun

Subpart Db—Standards of Performance for Industrial-CommercialInstitutional Steam Generating Units

Source: 72 FR 32742, June 13, 2007, unless otherwise noted.

§ 60.40b Applicability and delegation of authority.

(a) The affected facility to which this subpart applies is each steam generating unit that commences construction,

modification, or reconstruction after June 19, 1984, and that has a heat input capacity from fuels combusted in the 

steam generating unit of greater than 29 megawatts (MW) (100 million British thermal units per hour (MMBtu/hr)).

(b) Any affected facility meeting the applicability requirements under paragraph (a) of this section and commencing 

construction, modification, or reconstruction after June 19, 1984, but on or before June 19, 1986, is subject to the 

following standards:

(1) Coal-fired affected facilities having a heat input capacity between 29 and 73 MW (100 and 250 MMBtu/hr), 

inclusive, are subject to the particulate matter (PM) and nitrogen oxides (NOX) standards under this subpart.

(2) Coal-fired affected facilities having a heat input capacity greater than 73 MW (250 MMBtu/hr) and meeting the 

applicability requirements under subpart D (Standards of performance for fossil-fuel-fired steam generators; §60.40) 

are subject to the PM and NOXstandards under this subpart and to the sulfur dioxide (SO2) standards under subpart 

D (§60.43).

(3) Oil-fired affected facilities having a heat input capacity between 29 and 73 MW (100 and 250 MMBtu/hr), inclusive, 

are subject to the NOXstandards under this subpart.

(4) Oil-fired affected facilities having a heat input capacity greater than 73 MW (250 MMBtu/hr) and meeting the 

applicability requirements under subpart D (Standards of performance for fossil-fuel-fired steam generators; §60.40) 

are also subject to the NOXstandards under this subpart and the PM and SO2standards under subpart D (§60.42 and 

§60.43).

(c) Affected facilities that also meet the applicability requirements under subpart J (Standards of performance for 

petroleum refineries; §60.104) are subject to the PM and NOXstandards under this subpart and the SO2standards 

under subpart J (§60.104).

(d) Affected facilities that also meet the applicability requirements under subpart E (Standards of performance for 

incinerators; §60.50) are subject to the NOXand PM standards under this subpart.

(e) Steam generating units meeting the applicability requirements under subpart Da (Standards of performance for 

electric utility steam generating units; §60.40Da) are not subject to this subpart.
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(f) Any change to an existing steam generating unit for the sole purpose of combusting gases containing total 

reduced sulfur (TRS) as defined under §60.281 is not considered a modification under §60.14 and the steam 

generating unit is not subject to this subpart.

(g) In delegating implementation and enforcement authority to a State under section 111(c) of the Clean Air Act, the 

following authorities shall be retained by the Administrator and not transferred to a State.

(1) Section 60.44b(f).

(2) Section 60.44b(g).

(3) Section 60.49b(a)(4).

(h) Any affected facility that meets the applicability requirements and is subject to subpart Ea, subpart Eb, or subpart 

AAAA of this part is not covered by this subpart.

(i) Heat recovery steam generators that are associated with combined cycle gas turbines and that meet the 

applicability requirements of subpart KKKK of this part are not subject to this subpart. This subpart will continue to 

apply to all other heat recovery steam generators that are capable of combusting more than 29 MW (100 MMBtu/hr) 

heat input of fossil fuel. If the heat recovery steam generator is subject to this subpart, only emissions resulting from 

combustion of fuels in the steam generating unit are subject to this subpart. (The gas turbine emissions are subject to 

subpart GG or KKKK, as applicable, of this part.)

(j) Any affected facility meeting the applicability requirements under paragraph (a) of this section and commencing 

construction, modification, or reconstruction after June 19, 1986 is not subject to subpart D (Standards of 

Performance for Fossil-Fuel-Fired Steam Generators, §60.40).

(k) Any affected facility that meets the applicability requirements and is subject to an EPA approved State or Federal 

section 111(d)/129 plan implementing subpart Cb or subpart BBBB of this part is not covered by this subpart.

[72 FR 32742, June 13, 2007, as amended at 74 FR 5084, Jan. 28, 2009]

§ 60.41b Definitions.

As used in this subpart, all terms not defined herein shall have the meaning given them in the Clean Air Act and in 

subpart A of this part.

Annual capacity factor means the ratio between the actual heat input to a steam generating unit from the fuels listed 

in §60.42b(a), §60.43b(a), or §60.44b(a), as applicable, during a calendar year and the potential heat input to the 

steam generating unit had it been operated for 8,760 hours during a calendar year at the maximum steady state 

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 in a calendar year.

Byproduct/waste means any liquid or gaseous substance produced at chemical manufacturing plants, petroleum 

refineries, or pulp and paper mills (except natural gas, distillate oil, or residual oil) and combusted in a steam

generating unit for heat recovery or for disposal. Gaseous substances with carbon dioxide (CO2) levels greater than 

50 percent or carbon monoxide levels greater than 10 percent are not byproduct/waste for the purpose of this 

subpart.

Chemical manufacturing plants mean industrial plants that are classified by the Department of Commerce under 

Standard Industrial Classification (SIC) Code 28.

Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of 

Testing and Materials in ASTM D388 (incorporated by reference, see §60.17), coal refuse, and petroleum coke. Coalderived synthetic fuels, including but not limited to solvent refined coal, gasified coal not meeting the definition of 
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natural gas, coal-oil mixtures, coke oven gas, and coal-water mixtures, are also included in this definition for the 

purposes of this subpart.

Coal refuse means any byproduct 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 kJ/kg (6,000 Btu/lb) on a dry basis.

Cogeneration , also known as combined heat and power, means a facility that simultaneously produces both electric 

(or mechanical) and useful thermal energy from the same primary energy source.

Coke oven gas means the volatile constituents generated in the gaseous exhaust during the carbonization of 

bituminous coal to form coke.

Combined cycle system means a system in which a separate source, such as a gas turbine, internal combustion 

engine, kiln, etc., provides exhaust gas to a steam generating unit.

Conventional technology means wet flue gas desulfurization (FGD) technology, dry FGD technology, atmospheric 

fluidized bed combustion technology, and oil hydrodesulfurization technology.

Distillate oil means fuel oils that contain 0.05 weight percent nitrogen or less and comply with the specifications for 

fuel oil numbers 1 and 2, as defined by the American Society of Testing and Materials in ASTM D396 (incorporated 

by reference, see §60.17) or diesel fuel oil numbers 1 and 2, as defined by the American Society for Testing and 

Materials in ASTM D975 (incorporated by reference, see §60.17).

Dry flue gas desulfurization technology means a SO2control system that is located downstream of the steam 

generating unit and removes sulfur oxides from the combustion gases of the steam generating unit by contacting the 

combustion gases with an alkaline reagent and water, whether introduced separately or as a premixed slurry or 

solution and forming a dry powder material. This definition includes devices where the dry powder material is 

subsequently converted to another form. Alkaline slurries or solutions used in dry flue gas desulfurization technology 

include but are not limited to lime and sodium.

Duct burner means a device that combusts fuel and that is placed in the exhaust duct from another source, such as a 

stationary gas turbine, internal combustion engine, kiln, etc., to allow the firing of additional fuel to heat the exhaust 

gases before the exhaust gases enter a steam generating unit.

Emerging technology means any SO2control system that is not defined as a conventional technology under this 

section, and for which the owner or operator of the facility has applied to the Administrator and received approval to 

operate as an emerging technology under §60.49b(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 combustion of fuel in a bed or series of beds (including but not limited to 

bubbling bed units and circulating bed units) of limestone aggregate (or other sorbent materials) in which these 

materials are forced upward by the flow of combustion air and the gaseous products of combustion.

Fuel pretreatment means a process that removes a portion of the sulfur in a fuel before combustion of the fuel in a 

steam generating unit.

Full capacity means operation of the steam generating unit at 90 percent or more of the maximum steady-state 

design heat input capacity.

Gaseous fuel means any fuel that is a gas at ISO conditions. This includes, but is not limited to, natural gas and 

gasified coal (including coke oven gas).

Gross output means the gross useful work performed by the steam generated. For units generating only electricity, 

the gross useful work performed is the gross electrical output from the turbine/generator set. For cogeneration units, 
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the gross useful work performed is the gross electrical or mechanical output plus 75 percent of the useful thermal 

output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to 

enhance the performance of the unit ( i.e. , steam delivered to an industrial process).

Heat input means heat derived from combustion of fuel in a steam generating unit and does not include the heat 

derived from preheated combustion air, recirculated flue gases, or exhaust gases from other sources, such as gas 

turbines, internal combustion engines, kilns, etc.

Heat release rate means the steam generating unit design heat input capacity (in MW or Btu/hr) divided by the 

furnace volume (in cubic meters or cubic feet); the furnace volume is that volume bounded by the front furnace wall 

where the burner is located, the furnace side waterwall, and extending to the level just below or in front of the first row 

of convection pass tubes.

Heat transfer medium means any material that is used to transfer heat from one point to another point.

High heat release rate means a heat release rate greater than 730,000 J/sec-m3 (70,000 Btu/hr-ft3 ).

ISO Conditions means a temperature of 288 Kelvin, a relative humidity of 60 percent, and a pressure of 101.3 

kilopascals.

Lignite means a type of coal classified as lignite A or lignite B by the American Society of Testing and Materials in 

ASTM D388 (incorporated by reference, see §60.17).

Low heat release rate means a heat release rate of 730,000 J/sec-m3 (70,000 Btu/hr-ft3 ) or less.

Mass-feed stoker steam generating unit means a steam generating unit where solid fuel is introduced directly into a 

retort or is fed directly onto a grate where it is combusted.

Maximum heat input capacity means the ability of a steam generating unit to combust a stated maximum amount of 

fuel on a steady state basis, as determined by the physical design and characteristics of the steam generating unit.

Municipal-type solid waste means refuse, more than 50 percent of which is waste consisting of a mixture of paper, 

wood, yard wastes, food wastes, plastics, leather, rubber, and other combustible materials, and noncombustible 

materials such as glass and rock.

Natural gas means:

(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the 

earth's surface, of which the principal constituent is methane; or

(2) Liquefied petroleum gas, as defined by the American Society for Testing and Materials in ASTM D1835 

(incorporated by reference, see §60.17); or

(3) A mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additionally, natural gas must either 

be composed of at least 70 percent methane by volume or have a gross calorific value between 34 and 43 

megajoules (MJ) per dry standard cubic meter (910 and 1,150 Btu per dry standard cubic foot).

Noncontinental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of 

Puerto Rico, or the Northern Mariana Islands.

Oil means crude oil or petroleum or a liquid fuel derived from crude oil or petroleum, including distillate and residual 

oil.

Petroleum refinery means industrial plants as classified by the Department of Commerce under Standard Industrial 

Classification (SIC) Code 29.
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Potential sulfur dioxide emission rate means the theoretical SO2emissions (nanograms per joule (ng/J) or lb/MMBtu 

heat input) that would result from combusting fuel in an uncleaned state and without using emission control systems. 

For gasified coal or oil that is desulfurized prior to combustion, the Potential sulfur dioxide emission rate is the 

theoretical SO2emissions (ng/J or lb/MMBtu heat input) that would result from combusting fuel in a cleaned state 

without using any post combustion emission control systems.

Process heater means a device that is primarily used to heat a material to initiate or promote a chemical reaction in 

which the material participates as a reactant or catalyst.

Pulp and paper mills means industrial plants that are classified by the Department of Commerce under North 

American Industry Classification System (NAICS) Code 322 or Standard Industrial Classification (SIC) Code 26.

Pulverized coal-fired steam generating unit means a steam generating unit in which pulverized coal is introduced into 

an air stream that carries the coal to the combustion chamber of the steam generating unit where it is fired in 

suspension. This includes both conventional pulverized coal-fired and micropulverized coal-fired steam generating 

units. Residual oil means crude oil, fuel oil numbers 1 and 2 that have a nitrogen content greater than 0.05 weight 

percent, and all fuel oil numbers 4, 5 and 6, as defined by the American Society of Testing and Materials in ASTM 

D396 (incorporated by reference, see §60.17).

Spreader stoker steam generating unit means a steam generating unit in which solid fuel is introduced to the 

combustion zone by a mechanism that throws the fuel onto a grate from above. Combustion takes place both in 

suspension and on the grate.

Steam generating unit means a device that combusts any fuel or byproduct/waste and produces steam or heats 

water or heats any heat transfer medium. This term includes any municipal-type solid waste incinerator with a heat 

recovery steam generating unit or any steam generating unit that combusts fuel and is part of a cogeneration system 

or a combined cycle system. This term does not include process heaters as they are defined in this subpart.

Steam generating unit operating day means a 24-hour period between 12:00 midnight and the following midnight 

during which any fuel is combusted at any time in the steam generating unit. It is not necessary for fuel to be 

combusted continuously for the entire 24-hour period.

Very low sulfur oil means for units constructed, reconstructed, or modified on or before February 28, 2005, oil that 

contains no more than 0.5 weight percent sulfur or that, when combusted without SO2emission control, has a 

SO2emission rate equal to or less than 215 ng/J (0.5 lb/MMBtu) heat input. For units constructed, reconstructed, or 

modified after February 28, 2005 and not located in a noncontinental area, very low sulfur oil means oil that contains 

no more than 0.30 weight percent sulfur or that, when combusted without SO2emission control, has a SO2emission 

rate equal to or less than 140 ng/J (0.32 lb/MMBtu) heat input. For units constructed, reconstructed, or modified after 

February 28, 2005 and located in a noncontinental area, very low sulfur oil means oil that contains no more than 0.5 

weight percent sulfur or that, when combusted without SO2emission control, has a SO2emission rate equal to or less 

than 215 ng/J (0.50 lb/MMBtu) heat input.

Wet flue gas desulfurization technology means a SO2control system that is located downstream of the steam 

generating unit and removes sulfur oxides from the combustion gases of the steam generating unit by contacting the 

combustion gas with an alkaline slurry or solution and forming a liquid material. This definition applies to devices 

where the aqueous liquid material product of this contact is subsequently converted to other forms. Alkaline reagents 

used in wet flue gas desulfurization technology include, but are not limited to, lime, limestone, and sodium.

Wet scrubber system means any emission control device that mixes an aqueous stream or slurry with the exhaust 

gases from a steam generating unit to control emissions of PM or SO2.

Wood means wood, wood residue, bark, or any derivative fuel or residue thereof, in any form, including, but not 

limited to, sawdust, sanderdust, wood chips, scraps, slabs, millings, shavings, and processed pellets made from 

wood or other forest residues.

[72 FR 32742, June 13, 2007, as amended at 74 FR 5084, Jan. 28, 2009]
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§ 60.42b Standard for sulfur dioxide (SO2).

(a) Except as provided in paragraphs (b), (c), (d), or (j) of this section, on and after the date on which the performance 

test is completed or required to be completed under §60.8, whichever 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 oil shall cause to be discharged into the atmosphere any gases that contain SO2in excess of 87 ng/J (0.20 

lb/MMBtu) or 10 percent (0.10) of the potential SO2emission rate (90 percent reduction) and the emission limit 

determined according to the following formula:

Where:

Es= SO2emission limit, in ng/J or lb/MMBtu heat input;

Ka= 520 ng/J (or 1.2 lb/MMBtu);

Kb= 340 ng/J (or 0.80 lb/MMBtu);

Ha= Heat input from the combustion of coal, in J (MMBtu); and

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

For 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 in this paragraph. No credit is provided for the heat input to the affected 

facility from the combustion of natural gas, wood, municipal-type solid waste, or other fuels or heat derived from 

exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc.

(b) On and after the date on which the 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 refuse alone in a fluidized bed combustion steam 

generating unit shall cause to be discharged into the atmosphere any gases that contain SO2in excess of 87 ng/J 

(0.20 lb/MMBtu) or 20 percent (0.20) of the potential SO2emission rate (80 percent reduction) and 520 ng/J (1.2 

lb/MMBtu) heat input. If coal or oil is fired with coal refuse, the affected facility is subject to paragraph (a) or (d) of this 

section, as applicable. For 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 in this paragraph. No credit is provided for the heat 

input to the affected facility from the combustion of natural gas, wood, municipal-type solid waste, or other fuels or 

heat derived from exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc.

(c) On and after the date on which the performance test is completed or is required to be completed under §60.8, 

whichever comes first, no owner or operator of an affected facility that combusts coal or oil, either alone or in 

combination with any other fuel, and that uses an emerging technology for the control of SO2emissions, shall cause 

to be discharged into the atmosphere any gases that contain SO2in excess of 50 percent of the potential 

SO2emission rate (50 percent reduction) and that contain SO2in excess of the emission limit determined according to 

the following formula:

Where:

Es= SO2 emission limit, in ng/J or lb/MM Btu heat input;
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Kc= 260 ng/J (or 0.60 lb/MMBtu);

Kd= 170 ng/J (or 0.40 lb/MMBtu);

Hc= Heat input from the combustion of coal, in J (MMBtu); and

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

For 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 in this paragraph. No credit is provided for the heat input to the affected 

facility from the combustion of natural gas, wood, municipal-type solid waste, or other fuels, or from the heat input 

derived from exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc.

(d) On and after the date on which the performance test is completed or required to be completed under §60.8, 

whichever comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or 

modification on or before February 28, 2005 and listed in paragraphs (d)(1), (2), (3), or (4) of this section shall cause 

to be discharged into the atmosphere any gases that contain SO2in excess of 520 ng/J (1.2 lb/MMBtu) heat input if 

the affected facility combusts coal, or 215 ng/J (0.5 lb/MMBtu) heat input if the affected facility combusts oil other than 

very low sulfur oil. Percent reduction requirements are not applicable to affected facilities under paragraphs (d)(1), 

(2), (3) or (4) of this section. For facilities complying with paragraphs (d)(1), (2), or (3) of this section, only the heat 

input supplied to the affected facility from the combustion of coal and oil is counted in this paragraph. No credit is 

provided for the heat input to the affected facility from the combustion of natural gas, wood, municipal-type solid 

waste, or other fuels or heat derived from exhaust gases from other sources, such as gas turbines, internal 

combustion engines, kilns, etc.

(1) Affected facilities that have an annual capacity factor for coal and oil of 30 percent (0.30) or less and are subject 

to a federally enforceable permit limiting the operation of the affected facility to an annual capacity factor for coal and 

oil of 30 percent (0.30) or less;

(2) Affected facilities located in a noncontinental area; or

(3) Affected facilities combusting coal or oil, alone or in combination with any fuel, in a duct burner as part of a 

combined cycle system where 30 percent (0.30) or less of the heat entering the steam generating unit is from 

combustion of coal and oil in the duct burner and 70 percent (0.70) or more of the heat entering the steam generating 

unit is from the exhaust gases entering the duct burner; or

(4) The affected facility burns coke oven gas alone or in combination with natural gas or very low sulfur distillate oil.

(e) Except as provided in paragraph (f) of this section, compliance with the emission limits, fuel oil sulfur limits, and/or 

percent reduction requirements under this section are determined on a 30-day rolling average basis.

(f) Except as provided in paragraph (j)(2) of this section, compliance with the emission limits or fuel oil sulfur limits 

under this section is determined on a 24-hour average basis for affected facilities that (1) have a federally enforceable 

permit limiting the annual capacity factor for oil to 10 percent or less, (2) combust only very low sulfur oil, and (3) do 

not combust any other fuel.

(g) Except as provided in paragraph (i) of this section and §60.45b(a), the SO2emission limits and percent reduction 

requirements under this section apply at all times, including periods of startup, shutdown, and malfunction.

(h) Reductions in the potential SO2emission rate through fuel pretreatment are not credited toward the percent 

reduction requirement under paragraph (c) of this section unless:

(1) Fuel pretreatment results in a 50 percent or greater reduction in potential SO2emissions and

(2) Emissions from the pretreated fuel (without combustion or post-combustion SO2control) are equal to or less than 

the emission limits specified in paragraph (c) of this section.
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(i) An affected facility subject to paragraph (a), (b), or (c) of this section may combust very low sulfur oil or natural gas 

when the SO2control system is not being operated because of malfunction or maintenance of the SO2control system.

(j) Percent reduction requirements are not applicable to affected facilities combusting only very low sulfur oil. The 

owner or operator of an affected facility combusting very low sulfur oil shall demonstrate that the oil meets the 

definition of very low sulfur oil by: (1) Following the performance testing procedures as described in §60.45b(c) or 

§60.45b(d), and following the monitoring procedures as described in §60.47b(a) or §60.47b(b) to determine 

SO2emission rate or fuel oil sulfur content; or (2) maintaining fuel records as described in §60.49b(r).

(k)(1) Except as provided in paragraphs (k)(2), (k)(3), and (k)(4) of this section, on and after the date on which the 

initial performance test is completed or is required to be completed under §60.8, whichever date comes first, no 

owner or operator of an affected facility that commences construction, reconstruction, or modification after February 

28, 2005, and that combusts coal, oil, natural gas, a mixture of these fuels, or a mixture of these fuels with any other 

fuels shall cause to be discharged into the atmosphere any gases that contain SO2in excess of 87 ng/J (0.20 

lb/MMBtu) heat input or 8 percent (0.08) of the potential SO2emission rate (92 percent reduction) and 520 ng/J (1.2 

lb/MMBtu) heat input. For facilities complying with the percent reduction standard and paragraph (k)(3) of this section, 

only the heat input supplied to the affected facility from the combustion of coal and oil is counted in paragraph (k) of 

this section. No credit is provided for the heat input to the affected facility from the combustion of natural gas, wood, 

municipal-type solid waste, or other fuels or heat derived from exhaust gases from other sources, such as gas 

turbines, internal combustion engines, kilns, etc.

(2) Units firing only very low sulfur oil, gaseous fuel, a mixture of these fuels, or a mixture of these fuels with any other 

fuels with a potential SO2emission rate of 140 ng/J (0.32 lb/MMBtu) heat input or less are exempt from the 

SO2emissions limit in paragraph (k)(1) of this section.

(3) Units that are located in a noncontinental area and that combust coal, oil, or natural gas shall not discharge any 

gases that contain SO2in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the affected facility combusts coal, or 215 

ng/J (0.50 lb/MMBtu) heat input if the affected facility combusts oil or natural gas.

(4) As an alternative to meeting the requirements under paragraph (k)(1) of this section, modified facilities that 

combust coal or a mixture of coal with other fuels shall not cause to be discharged into the atmosphere any gases 

that contain SO2in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO2emission 

rate (90 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input.

[72 FR 32742, June 13, 2007, as amended at 74 FR 5084, Jan. 28, 2009; 76 FR 3523, Jan. 20, 2011]

§ 60.43b Standard for particulate matter (PM).

(a) On and after the date on which the initial performance test is completed or is required to be completed under 

§60.8, whichever 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, shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in 

excess of the following emission limits:

(1) 22 ng/J (0.051 lb/MMBtu) heat input, (i) If the affected facility combusts only coal, or

(ii) If the affected facility combusts coal and other fuels and has an annual capacity factor for the other fuels of 10 

percent (0.10) or less.

(2) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility combusts coal and other fuels and has an annual 

capacity factor for the other fuels greater than 10 percent (0.10) and is subject to a federally enforceable requirement 

limiting operation of the affected facility to an annual capacity factor greater than 10 percent (0.10) for fuels other than 

coal.

(3) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility combusts coal or coal and other fuels and

(i) Has an annual capacity factor for coal or coal and other fuels of 30 percent (0.30) or less,
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(ii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or less,

(iii) Has a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor of 30 

percent (0.30) or less for coal or coal and other solid fuels, and

(iv) Construction of the affected facility commenced after June 19, 1984, and before November 25, 1986.

(4) An affected facility burning coke oven gas alone or in combination with other fuels not subject to a PM standard 

under §60.43b and not using a post-combustion technology (except a wet scrubber) for reducing PM or 

SO2emissions is not subject to the PM limits under §60.43b(a).

(b) On and after the date on which the performance test is completed or required to be completed under §60.8, 

whichever comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or 

modification on or before February 28, 2005, and that combusts oil (or mixtures of oil with other fuels) and uses a 

conventional or emerging technology to reduce SO2emissions shall cause to be discharged into the atmosphere from 

that affected facility any gases that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.

(c) On and after the date on which the initial performance test is completed or is required to be completed under 

§60.8, whichever comes first, no owner or operator of an affected facility that commenced construction, 

reconstruction, or modification on or before February 28, 2005, and that combusts wood, or wood with other fuels, 

except coal, shall cause to be discharged from that affected facility any gases that contain PM in excess of the 

following emission limits:

(1) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has an annual capacity factor greater than 30 percent 

(0.30) for wood.

(2) 86 ng/J (0.20 lb/MMBtu) heat input if (i) The affected facility has an annual capacity factor of 30 percent (0.30) or 

less for wood;

(ii) Is subject to a federally enforceable requirement limiting operation of the affected facility to an annual capacity 

factor of 30 percent (0.30) or less for wood; and

(iii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or less.

(d) 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 combusts municipal-type solid 

waste or mixtures of municipal-type solid waste with other fuels, shall cause to be discharged into the atmosphere 

from that affected facility any gases that contain PM in excess of the following emission limits:

(1) 43 ng/J (0.10 lb/MMBtu) heat input;

(i) If the affected facility combusts only municipal-type solid waste; or

(ii) If the affected facility combusts municipal-type solid waste and other fuels and has an annual capacity factor for 

the other fuels of 10 percent (0.10) or less.

(2) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility combusts municipal-type solid waste or municipal-type 

solid waste and other fuels; and

(i) Has an annual capacity factor for municipal-type solid waste and other fuels of 30 percent (0.30) or less;

(ii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or less;

(iii) Has a federally enforceable requirement limiting operation of the affected facility to an annual capacity factor of 30 

percent (0.30) or less for municipal-type solid waste, or municipal-type solid waste and other fuels; and
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(iv) Construction of the affected facility commenced after June 19, 1984, but on or before November 25, 1986.

(e) For the purposes of this section, the annual capacity factor is determined by dividing the actual heat input to the 

steam generating unit during the calendar year from the combustion of coal, wood, or municipal-type solid waste, and 

other fuels, as applicable, by the potential heat input to the steam generating unit if the steam generating unit had 

been operated for 8,760 hours at the maximum heat input capacity.

(f) 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 can combust coal, oil, wood, or 

mixtures of these fuels with any other fuels shall cause to be discharged into the atmosphere any gases that exhibit 

greater than 20 percent opacity (6-minute average), except for one 6-minute period per hour of not more than 27 

percent opacity. Owners and operators of an affected facility that elect to install, calibrate, maintain, and operate a 

continuous emissions monitoring system (CEMS) for measuring PM emissions according to the requirements of this 

subpart and are subject to a federally enforceable PM limit of 0.030 lb/MMBtu or less are exempt from the opacity 

standard specified in this paragraph.

(g) The PM and opacity standards apply at all times, except during periods of startup, shutdown, or malfunction.

(h)(1) Except as provided in paragraphs (h)(2), (h)(3), (h)(4), (h)(5), and (h)(6) of this section, 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 commenced 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 shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in 

excess of 13 ng/J (0.030 lb/MMBtu) heat input,

(2) As an alternative to meeting the requirements of paragraph (h)(1) of this section, the owner or operator of an 

affected facility for which modification commenced after February 28, 2005, may elect to meet the requirements of 

this paragraph. On and after the date on which the initial performance test is completed or required to be completed 

under §60.8, no owner or operator of an affected facility that commences modification after February 28, 2005 shall 

cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of both:

(i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion of coal, oil, wood, a mixture of these fuels, or a 

mixture of these fuels with any other fuels; and

(ii) 0.2 percent of the combustion concentration (99.8 percent reduction) when combusting coal, oil, wood, a mixture 

of these fuels, or a mixture of these fuels with any other fuels.

(3) On and after the date on which the initial performance test is completed or is required to be completed under 

§60.8, whichever date comes first, no owner or operator of an affected facility that commences modification after 

February 28, 2005, and that combusts over 30 percent wood (by heat input) on an annual basis and has a maximum 

heat input capacity of 73 MW (250 MMBtu/h) or less shall cause to be discharged into the atmosphere from that 

affected facility any gases that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input.

(4) On and after the date on which the initial performance test is completed or is required to be completed under 

§60.8, whichever date comes first, no owner or operator of an affected facility that commences modification after 

February 28, 2005, and that combusts over 30 percent wood (by heat input) on an annual basis and has a maximum 

heat input capacity greater than 73 MW (250 MMBtu/h) shall cause to be discharged into the atmosphere from that 

affected facility any gases that contain PM in excess of 37 ng/J (0.085 lb/MMBtu) heat input.

(5) On and after the date on which the initial performance test is completed or is required to be completed under 

§60.8, whichever date comes first, an owner or operator of an affected facility not located in a noncontinental area 

that commences construction, reconstruction, or modification after February 28, 2005, and that combusts only oil that 

contains no more than 0.30 weight percent sulfur, coke oven gas, a mixture of these fuels, or either fuel (or a mixture 

of these fuels) in combination with other fuels not subject to a PM standard in §60.43b and not using a postcombustion technology (except a wet scrubber) to reduce SO2or PM emissions is not subject to the PM limits in 

(h)(1) of this section.
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(6) On and after the date on which the initial performance test is completed or is required to be completed under 

§60.8, whichever date comes first, an owner or operator of an affected facility located in a noncontinental area that 

commences construction, reconstruction, or modification after February 28, 2005, and that combusts only oil that 

contains no more than 0.5 weight percent sulfur, coke oven gas, a mixture of these fuels, or either fuel (or a mixture 

of these fuels) in combination with other fuels not subject to a PM standard in §60.43b and not using a postcombustion technology (except a wet scrubber) to reduce SO2or PM emissions is not subject to the PM limits in 

(h)(1) of this section.

[72 FR 32742, June 13, 2007, as amended at 74 FR 5084, Jan. 28, 2009]

§ 60.44b Standard for nitrogen oxides (NOX).

(a) Except as provided under paragraphs (k) and (l) of this section, 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 is subject to the provisions of this section and that combusts only coal, oil, or 

natural gas shall cause to be discharged into the atmosphere from that affected facility any gases that contain 

NOX(expressed as NO2) in excess of the following emission limits:

Fuel/steam generating unit type

Nitrogen oxide emission limits 

(expressed as NO2) heat input

ng/J lb/MMBTu

(1) Natural gas and distillate oil, except (4):

(i) Low heat release rate 43 0.10

(ii) High heat release rate 86 0.20

(2) Residual oil:

(i) Low heat release rate 130 0.30

(ii) High heat release rate 170 0.40

(3) Coal:

(i) Mass-feed stoker 210 0.50

(ii) Spreader stoker and fluidized bed 

combustion

260 0.60

(iii) Pulverized coal 300 0.70

(iv) Lignite, except (v) 260 0.60

(v) Lignite mined in North Dakota, South 

Dakota, or Montana and combusted in a slag tap 

furnace

340 0.80

(vi) Coal-derived synthetic fuels 210 0.50

(4) Duct burner used in a combined cycle system:

(i) Natural gas and distillate oil 86 0.20

(ii) Residual oil 170 0.40
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(b) Except as provided under paragraphs (k) and (l) of this section, 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 simultaneously combusts mixtures of coal, oil, or natural gas shall cause to be 

discharged into the atmosphere from that affected facility any gases that contain NOXin excess of a limit determined 

by the use of the following formula:

Where:

En= NOXemission limit (expressed as NO2), ng/J (lb/MMBtu);

ELgo= Appropriate emission limit from paragraph (a)(1) for combustion of natural gas or distillate oil, ng/J 

(lb/MMBtu);

Hgo= Heat input from combustion of natural gas or distillate oil, J (MMBtu);

ELro= Appropriate emission limit from paragraph (a)(2) for combustion of residual oil, ng/J (lb/MMBtu);

Hro= Heat input from combustion of residual oil, J (MMBtu);

ELc= Appropriate emission limit from paragraph (a)(3) for combustion of coal, ng/J (lb/MMBtu); and

Hc= Heat input from combustion of coal, J (MMBtu).

(c) Except as provided under paragraph (l) of this section, 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 simultaneously combusts coal or oil, or a mixture of these fuels with natural gas, and wood, 

municipal-type solid waste, or any other fuel shall cause to be discharged into the atmosphere any gases that contain 

NOXin excess of the emission limit for the coal or oil, or mixtures of these fuels with natural gas combusted in the 

affected facility, as determined pursuant to paragraph (a) or (b) of this section, unless the affected facility has an 

annual capacity factor for coal or oil, or mixture of these fuels with natural gas of 10 percent (0.10) or less and is 

subject to a federally enforceable requirement that limits operation of the affected facility to an annual capacity factor 

of 10 percent (0.10) or less for coal, oil, or a mixture of these fuels with natural gas.

(d) 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 simultaneously combusts natural 

gas with wood, municipal-type solid waste, or other solid fuel, except coal, shall cause to be discharged into the 

atmosphere from that affected facility any gases that contain NOXin excess of 130 ng/J (0.30 lb/MMBtu) heat input 

unless the affected facility has an annual capacity factor for natural gas of 10 percent (0.10) or less and is subject to a 

federally enforceable requirement that limits operation of the affected facility to an annual capacity factor of 10 

percent (0.10) or less for natural gas.

(e) Except as provided under paragraph (l) of this section, 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 simultaneously combusts coal, oil, or natural gas with byproduct/waste shall cause to be 

discharged into the atmosphere any gases that contain NOXin excess of the emission limit determined by the 

following formula unless the affected facility has an annual capacity factor for coal, oil, and natural gas of 10 percent 

(0.10) or less and is subject to a federally enforceable requirement that limits operation of the affected facility to an 

annual capacity factor of 10 percent (0.10) or less:
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Where:

En= NOXemission limit (expressed as NO2), ng/J (lb/MMBtu);

ELgo= Appropriate emission limit from paragraph (a)(1) for combustion of natural gas or distillate oil, ng/J 

(lb/MMBtu);

Hgo= Heat input from combustion of natural gas, distillate oil and gaseous byproduct/waste, J (MMBtu);

ELro= Appropriate emission limit from paragraph (a)(2) for combustion of residual oil and/or 

byproduct/waste, ng/J (lb/MMBtu);

Hro= Heat input from combustion of residual oil, J (MMBtu);

ELc= Appropriate emission limit from paragraph (a)(3) for combustion of coal, ng/J (lb/MMBtu); and

Hc= Heat input from combustion of coal, J (MMBtu).

(f) Any owner or operator of an affected facility that combusts byproduct/waste with either natural gas or oil may 

petition the Administrator within 180 days of the initial startup of the affected facility to establish a NOXemission limit 

that shall apply specifically to that affected facility when the byproduct/waste is combusted. The petition shall include 

sufficient and appropriate data, as determined by the Administrator, such as NOXemissions from the affected facility, 

waste composition (including nitrogen content), and combustion conditions to allow the Administrator to confirm that 

the affected facility is unable to comply with the emission limits in paragraph (e) of this section and to determine the 

appropriate emission limit for the affected facility.

(1) Any owner or operator of an affected facility petitioning for a facility-specific NOXemission limit under this section 

shall:

(i) Demonstrate compliance with the emission limits for natural gas and distillate oil in paragraph (a)(1) of this section 

or for residual oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, by conducting a 30-day performance test 

as provided in §60.46b(e). During the performance test only natural gas, distillate oil, or residual oil shall be 

combusted in the affected facility; and

(ii) Demonstrate that the affected facility is unable to comply with the emission limits for natural gas and distillate oil in 

paragraph (a)(1) of this section or for residual oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, when 

gaseous or liquid byproduct/waste is combusted in the affected facility under the same conditions and using the same 

technological system of emission reduction applied when demonstrating compliance under paragraph (f)(1)(i) of this 

section.

(2) The NOXemission limits for natural gas or distillate oil in paragraph (a)(1) of this section or for residual oil in 

paragraph (a)(2) or (l)(1) of this section, as appropriate, shall be applicable to the affected facility until and unless the 

petition is approved by the Administrator. If the petition is approved by the Administrator, a facility-specific 

NOXemission limit will be established at the NOXemission level achievable when the affected facility is combusting oil 

or natural gas and byproduct/waste in a manner that the Administrator determines to be consistent with minimizing 

NOXemissions. In lieu of amending this subpart, a letter will be sent to the facility describing the facility-specific 

NOXlimit. The facility shall use the compliance procedures detailed in the letter and make the letter available to the 

public. If the Administrator determines it is appropriate, the conditions and requirements of the letter can be reviewed 

and changed at any point.

(g) Any owner or operator of an affected facility that combusts hazardous waste (as defined by 40 CFR part 261 or 40 

CFR part 761) with natural gas or oil may petition the Administrator within 180 days of the initial startup of the 
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affected facility for a waiver from compliance with the NOXemission limit that applies specifically to that affected 

facility. The petition must include sufficient and appropriate data, as determined by the Administrator, on 

NOXemissions from the affected facility, waste destruction efficiencies, waste composition (including nitrogen 

content), the quantity of specific wastes to be combusted and combustion conditions to allow the Administrator to 

determine if the affected facility is able to comply with the NOXemission limits required by this section. The owner or 

operator of the affected facility shall demonstrate that when hazardous waste is combusted in the affected facility, 

thermal destruction efficiency requirements for hazardous waste specified in an applicable federally enforceable 

requirement preclude compliance with the NOXemission limits of this section. The NOXemission limits for natural gas 

or distillate oil in paragraph (a)(1) of this section or for residual oil in paragraph (a)(2) or (l)(1) of this section, as 

appropriate, are applicable to the affected facility until and unless the petition is approved by the Administrator. (See 

40 CFR 761.70 for regulations applicable to the incineration of materials containing polychlorinated biphenyls 

(PCB's).) In lieu of amending this subpart, a letter will be sent to the facility describing the facility-specific NOXlimit. 

The facility shall use the compliance procedures detailed in the letter and make the letter available to the public. If the 

Administrator determines it is appropriate, the conditions and requirements of the letter can be reviewed and changed 

at any point.

(h) For purposes of paragraph (i) of this section, the NOXstandards under this section apply at all times including 

periods of startup, shutdown, or malfunction.

(i) Except as provided under paragraph (j) of this section, compliance with the emission limits under this section is 

determined on a 30-day rolling average basis.

(j) Compliance with the emission limits under this section is determined on a 24-hour average basis for the initial 

performance test and on a 3-hour average basis for subsequent performance tests for any affected facilities that:

(1) Combust, alone or in combination, only natural gas, distillate oil, or residual oil with a nitrogen content of 0.30 

weight percent or less;

(2) Have a combined annual capacity factor of 10 percent or less for natural gas, distillate oil, and residual oil with a 

nitrogen content of 0.30 weight percent or less; and

(3) Are subject to a federally enforceable requirement limiting operation of the affected facility to the firing of natural 

gas, distillate oil, and/or residual oil with a nitrogen content of 0.30 weight percent or less and limiting operation of the 

affected facility to a combined annual capacity factor of 10 percent or less for natural gas, distillate oil, and residual oil 

with a nitrogen content of 0.30 weight percent or less.

(k) Affected facilities that meet the criteria described in paragraphs (j)(1), (2), and (3) of this section, and that have a 

heat input capacity of 73 MW (250 MMBtu/hr) or less, are not subject to the NOXemission limits under this section.

(l) 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 commenced construction or 

reconstruction after July 9, 1997 shall cause to be discharged into the atmosphere from that affected facility any 

gases that contain NOX(expressed as NO2) in excess of the following limits:

(1) If the affected facility combusts coal, oil, natural gas, a mixture of these fuels, or a mixture of these fuels with any 

other fuels: A limit of 86 ng/J (0.20 lb/MMBtu) heat input unless the affected facility has an annual capacity factor for 

coal, oil, and natural gas of 10 percent (0.10) or less and is subject to a federally enforceable requirement that limits 

operation of the facility to an annual capacity factor of 10 percent (0.10) or less for coal, oil, and natural gas; or

(2) If the affected facility has a low heat release rate and combusts natural gas or distillate oil in excess of 30 percent 

of the heat input on a 30-day rolling average from the combustion of all fuels, a limit determined by use of the 

following formula:
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Where:

En= NOXemission limit, (lb/MMBtu);

Hgo= 30-day heat input from combustion of natural gas or distillate oil; and

Hr= 30-day heat input from combustion of any other fuel.

(3) After February 27, 2006, units where more than 10 percent of total annual output is electrical or mechanical may 

comply with an optional limit of 270 ng/J (2.1 lb/MWh) gross energy output, based on a 30-day rolling average. Units 

complying with this output-based limit must demonstrate compliance according to the procedures of §60.48Da(i) of 

subpart Da of this part, and must monitor emissions according to §60.49Da(c), (k), through (n) of subpart Da of this 

part.

[72 FR 32742, June 13, 2007, as amended at 74 FR 5086, Jan. 28, 2009]

§ 60.45b Compliance and performance test methods and procedures for 

sulfur dioxide.

(a) The SO2emission standards in §60.42b apply at all times. Facilities burning coke oven gas alone or in 

combination with any other gaseous fuels or distillate oil are allowed to exceed the limit 30 operating days per 

calendar year for SO2control system maintenance.

(b) In conducting the performance tests required under §60.8, the owner or operator shall use the methods and 

procedures in appendix A (including fuel certification and sampling) of this part or the methods and procedures as 

specified in this section, except as provided in §60.8(b). Section 60.8(f) does not apply to this section. The 30-day 

notice required in §60.8(d) applies only to the initial performance test unless otherwise specified by the Administrator.

(c) The owner or operator of an affected facility shall conduct performance tests to determine compliance with the 

percent of potential SO2emission rate (% Ps) and the SO2emission rate (Es) pursuant to §60.42b following the 

procedures listed below, except as provided under paragraph (d) and (k) of this section.

(1) The initial performance test shall be conducted over 30 consecutive operating days of the steam generating unit. 

Compliance with the SO2standards 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 affected facility will be operated, but not later than 180 days after initial startup of the facility.

(2) If only coal, only oil, or a mixture of coal and oil is combusted, the following procedures are used:

(i) The procedures in Method 19 of appendix A–7 of this part are used to determine the hourly SO2emission rate 

(Eho) and the 30-day average emission rate (Eao). The hourly averages used to compute the 30-day averages are 

obtained from the CEMS of §60.47b(a) or (b).

(ii) The percent of potential SO2emission rate (%Ps) emitted to the atmosphere is computed using the following 

formula:

Where:

%Ps= Potential SO2emission rate, percent;
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%Rg= SO2removal efficiency of the control device as determined by Method 19 of appendix A of this part, 

in percent; and

%Rf= SO2removal efficiency of fuel pretreatment as determined by Method 19 of appendix A of this part, 

in percent.

(3) If coal or oil is combusted with other fuels, the same procedures required in paragraph (c)(2) of this section are 

used, except as provided in the following:

(i) An adjusted hourly SO2emission rate (Ehoo ) is used in Equation 19–19 of Method 19 of appendix A of this part to 

compute an adjusted 30-day average emission rate (Eaoo ). The Eho° is computed using the following formula:

Where:

Eho

o = Adjusted hourly SO2emission rate, ng/J (lb/MMBtu);

Eho= Hourly SO2emission rate, ng/J (lb/MMBtu);

Ew= SO2concentration in fuels other than coal and oil combusted in the affected facility, as determined by 

the fuel sampling and analysis procedures in Method 19 of appendix A of this part, ng/J (lb/MMBtu). The 

value Ewfor each fuel lot is used for each hourly average during the time that the lot is being combusted; 

and

Xk= Fraction of total heat input from fuel combustion derived from coal, oil, or coal and oil, as determined 

by applicable procedures in Method 19 of appendix A of this part.

(ii) To compute the percent of potential SO2emission rate (%Ps), an adjusted %Rg(%Rg

o ) is computed from the 

adjusted Eaoo from paragraph (b)(3)(i) of this section and an adjusted average SO2inlet rate (Eai

o ) using the following 

formula:

To compute Eai

o , an adjusted hourly SO2inlet rate (Ehio ) is used. The Ehio is computed using the following formula:

Where:

Ehi

o = Adjusted hourly SO2inlet rate, ng/J (lb/MMBtu); and

Ehi= Hourly SO2inlet rate, ng/J (lb/MMBtu).

(4) The owner or operator of an affected facility subject to paragraph (c)(3) of this section does not have to measure 

parameters Ewor Xkif the owner or operator elects to assume that Xk= 1.0. Owners or operators of affected facilities 

who assume Xk= 1.0 shall:
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(i) Determine %Psfollowing the procedures in paragraph (c)(2) of this section; and

(ii) Sulfur dioxide emissions (Es) are considered to be in compliance with SO2emission limits under §60.42b.

(5) The owner or operator of an affected facility that qualifies under the provisions of §60.42b(d) does not have to 

measure parameters Ewor Xkin paragraph (c)(3) of this section if the owner or operator of the affected facility elects 

to measure SO2emission rates of the coal or oil following the fuel sampling and analysis procedures in Method 19 of 

appendix A–7 of this part.

(d) Except as provided in paragraph (j) of this section, the owner or operator of an affected facility that combusts only 

very low sulfur oil, natural gas, or a mixture of these fuels, has an annual capacity factor for oil of 10 percent (0.10) or 

less, and is subject to a federally enforceable requirement limiting operation of the affected facility to an annual 

capacity factor for oil of 10 percent (0.10) or less shall:

(1) Conduct the initial performance test over 24 consecutive steam generating unit operating hours at full load;

(2) Determine compliance with the standards after the initial performance test based on the arithmetic average of the 

hourly emissions data during each steam generating unit operating day if a CEMS is used, or based on a daily 

average if Method 6B of appendix A of this part or fuel sampling and analysis procedures under Method 19 of 

appendix A of this part are used.

(e) The owner or operator of an affected facility subject to §60.42b(d)(1) shall demonstrate the maximum design 

capacity of the steam generating unit by operating the facility at maximum capacity for 24 hours. This demonstration 

will be made during the initial performance test and a subsequent demonstration may be requested at any other time. 

If the 24-hour average firing rate for the affected facility is less than the maximum design capacity provided by the 

manufacturer of the affected facility, the 24-hour average firing rate shall be used to determine the capacity utilization 

rate for the affected facility, otherwise the maximum design capacity provided by the manufacturer is used.

(f) For the initial performance test required under §60.8, compliance with the SO2emission limits and percent 

reduction requirements under §60.42b is based on the average emission rates and the average percent reduction for 

SO2for the first 30 consecutive steam generating unit operating days, except as provided under paragraph (d) of this 

section. The initial performance test is the only test for which at least 30 days prior notice is required unless otherwise 

specified by the Administrator. The initial performance test is to be scheduled so that the first steam generating unit 

operating day of the 30 successive steam generating unit operating days is completed within 30 days after achieving 

the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial 

startup of the facility. The boiler load during the 30-day period does not have to be the maximum design load, but 

must be representative of future operating conditions and include at least one 24-hour period at full load.

(g) After the initial performance test required under §60.8, compliance with the SO2emission limits and percent 

reduction requirements under §60.42b is based on the average emission rates and the average percent reduction for 

SO2for 30 successive steam generating unit operating days, except as provided under paragraph (d). A separate 

performance test is completed at the end of each steam generating unit operating day after the initial performance 

test, and a new 30-day average emission rate and percent reduction for SO2are calculated to show compliance with 

the standard.

(h) Except as provided under paragraph (i) of this section, the owner or operator of an affected facility shall use all 

valid SO2emissions data in calculating %Psand Ehounder paragraph (c), of this section whether or not the minimum 

emissions data requirements under §60.46b are achieved. All valid emissions data, including valid SO2emission data 

collected during periods of startup, shutdown and malfunction, shall be used in calculating %Psand Ehopursuant to 

paragraph (c) of this section.

(i) During periods of malfunction or maintenance of the SO2control systems when oil is combusted as provided under 

§60.42b(i), emission data are not used to calculate %Psor Esunder §60.42b(a), (b) or (c), however, the emissions 

data are used to determine compliance with the emission limit under §60.42b(i).

(j) The owner or operator of an affected facility that only combusts very low sulfur oil, natural gas, or a mixture of 

these fuels with any other fuels not subject to an SO2standard is not subject to the compliance and performance 

testing requirements of this section if the owner or operator obtains fuel receipts as described in §60.49b(r).
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(k) The owner or operator of an affected facility seeking to demonstrate compliance in §§60.42b(d)(4), 60.42b(j), 

60.42b(k)(2), and 60.42b(k)(3) (when not burning coal) shall follow the applicable procedures in §60.49b(r).

[72 FR 32742, June 13, 2007, as amended at 74 FR 5086, Jan. 28, 2009]

§ 60.46b Compliance and performance test methods and procedures for 

particulate matter and nitrogen oxides.

(a) The PM emission standards and opacity limits under §60.43b apply at all times except during periods of startup, 

shutdown, or malfunction. The NOXemission standards under §60.44b apply at all times.

(b) Compliance with the PM emission standards under §60.43b shall be determined through performance testing as 

described in paragraph (d) of this section, except as provided in paragraph (i) of this section.

(c) Compliance with the NOXemission standards under §60.44b shall be determined through performance testing 

under paragraph (e) or (f), or under paragraphs (g) and (h) of this section, as applicable.

(d) To determine compliance with the PM emission limits and opacity limits under §60.43b, the owner or operator of 

an affected facility shall conduct an initial performance test as required under §60.8, and shall conduct subsequent 

performance tests as requested by the Administrator, using the following procedures and reference methods:

(1) Method 3A or 3B of appendix A–2 of this part is used for gas analysis when applying Method 5 of appendix A–3 of 

this part or Method 17 of appendix A–6 of this part.

(2) Method 5, 5B, or 17 of appendix A of this part shall be used to measure the concentration of PM as follows:

(i) Method 5 of appendix A of this part shall be used at affected facilities without wet flue gas desulfurization (FGD) 

systems; and

(ii) Method 17 of appendix A–6 of this part may be used at 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–3 of this part may be used in Method 17 of appendix A–6 of this part only if it is used after 

a wet FGD system. Do not use Method 17 of appendix A–6 of this part after wet FGD systems if the effluent is 

saturated or laden with water droplets.

(iii) Method 5B of appendix A of this part is to be used only after wet FGD systems.

(3) Method 1 of appendix A of this part is used to select the sampling site and the number of traverse sampling 

points. The sampling time for each run is at least 120 minutes and the minimum sampling volume is 1.7 dscm (60 

dscf) except that smaller sampling times or volumes may be approved by the Administrator when necessitated by 

process variables or other factors.

(4) For Method 5 of appendix A of this part, the temperature of the sample gas in the probe and filter holder is 

monitored and is maintained at 160±14 °C (320±25 °F).

(5) For determination of PM emissions, the oxygen (O2) or CO2sample is obtained simultaneously with each run of 

Method 5, 5B, or 17 of appendix A of this part by traversing the duct at the same sampling location.

(6) For each run using Method 5, 5B, or 17 of appendix A of this part, the emission rate expressed in ng/J heat input 

is determined using:

(i) The O2or CO2measurements and PM measurements obtained under this section;

(ii) The dry basis F factor; and
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Permit Reviewer: Josiah Balogun

(iii) The dry basis emission rate calculation procedure contained in Method 19 of appendix A of this part.

(7) Method 9 of appendix A of this part is used for determining the opacity of stack emissions.

(e) To determine compliance with the emission limits for NOXrequired under §60.44b, the owner or operator of an 

affected facility shall conduct the performance test as required under §60.8 using the continuous system for 

monitoring NOXunder §60.48(b).

(1) For the initial compliance test, NOXfrom the steam generating unit are monitored for 30 successive steam 

generating unit operating days and the 30-day average emission rate is used to determine compliance with the 

NOXemission standards under §60.44b. The 30-day average emission rate is calculated as the average of all hourly 

emissions data recorded by the monitoring system during the 30-day test period.

(2) Following the date on which the initial performance test is completed or is required to be completed in §60.8, 

whichever date comes first, the owner or operator of an affected facility which combusts coal (except as specified 

under §60.46b(e)(4)) or which combusts residual oil having a nitrogen content greater than 0.30 weight percent shall 

determine compliance with the NOXemission standards in §60.44b on a continuous basis through the use of a 30-day 

rolling average emission rate. A new 30-day rolling average emission rate is calculated for each steam generating 

unit operating day as the average of all of the hourly NOXemission data for the preceding 30 steam generating unit 

operating days.

(3) Following the date on which the initial performance test is completed or is required to be completed under §60.8, 

whichever date comes first, the owner or operator of an affected facility that has a heat input capacity greater than 73 

MW (250 MMBtu/hr) and that combusts natural gas, distillate oil, or residual oil having a nitrogen content of 0.30 

weight percent or less shall determine compliance with the NOXstandards under §60.44b on a continuous basis 

through the use of a 30-day rolling average emission rate. A new 30-day rolling average emission rate is calculated 

each steam generating unit operating day as the average of all of the hourly NOXemission data for the preceding 30 

steam generating unit operating days.

(4) Following the date on which the initial 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 has a heat input capacity of 73 MW (250 

MMBtu/hr) or less and that combusts natural gas, distillate oil, gasified coal, or residual oil having a nitrogen content 

of 0.30 weight percent or less shall upon request determine compliance with the NOXstandards in §60.44b through 

the use of a 30-day performance test. During periods when performance tests are not requested, NOXemissions data 

collected pursuant to §60.48b(g)(1) or §60.48b(g)(2) are used to calculate a 30-day rolling average emission rate on 

a daily basis and used to prepare excess emission reports, but will not be used to determine compliance with the 

NOXemission standards. A new 30-day rolling average emission rate is calculated each steam generating unit 

operating day as the average of all of the hourly NOXemission data for the preceding 30 steam generating unit 

operating days.

(5) If the owner or operator of an affected facility that combusts residual oil does not sample and analyze the residual 

oil for nitrogen content, as specified in §60.49b(e), the requirements of §60.48b(g)(1) apply and the provisions of 

§60.48b(g)(2) are inapplicable.

(f) To determine compliance with the emissions limits for NOXrequired by §60.44b(a)(4) or §60.44b(l) for duct burners 

used in combined cycle systems, either of the procedures described in paragraph (f)(1) or (2) of this section may be 

used:

(1) The owner or operator of an affected facility shall conduct the performance test required under §60.8 as follows:

(i) The emissions rate (E) of NOXshall be computed using Equation 1 in this section:

Where:
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E = Emissions rate of NOXfrom the duct burner, ng/J (lb/MMBtu) heat input;

Esg= Combined effluent emissions rate, in ng/J (lb/MMBtu) heat input using appropriate F factor as 

described in Method 19 of appendix A of this part;

Hg= Heat input rate to the combustion turbine, in J/hr (MMBtu/hr);

Hb= Heat input rate to the duct burner, in J/hr (MMBtu/hr); and

Eg= Emissions rate from the combustion turbine, in ng/J (lb/MMBtu) heat input calculated using 

appropriate F factor as described in Method 19 of appendix A of this part.

(ii) Method 7E of appendix A of this part shall be used to determine the NOXconcentrations. Method 3A or 3B of 

appendix A of this part shall be used to determine O2concentration.

(iii) The owner or operator shall identify and demonstrate to the Administrator's satisfaction suitable methods to 

determine the average hourly heat input rate to the combustion turbine and the average hourly heat input rate to the 

affected duct burner.

(iv) Compliance with the emissions limits under §60.44b(a)(4) or §60.44b(l) is determined by the three-run average 

(nominal 1-hour runs) for the initial and subsequent performance tests; or

(2) The owner or operator of an affected facility may elect to determine compliance on a 30-day rolling average basis 

by using the CEMS specified under §60.48b for measuring NOXand O2and meet the requirements of §60.48b. The 

sampling site shall be located at the outlet from the steam generating unit. The NOXemissions rate at the outlet from 

the steam generating unit shall constitute the NOXemissions rate from the duct burner of the combined cycle system.

(g) The owner or operator of an affected facility described in §60.44b(j) or §60.44b(k) shall demonstrate the maximum 

heat input capacity of the steam generating unit by operating the facility at maximum capacity for 24 hours. The 

owner or operator of an affected facility shall determine the maximum heat input capacity using the heat loss method 

or the heat input method described in sections 5 and 7.3 of the ASME Power Test Codes 4.1 (incorporated by 

reference, see §60.17). This demonstration of maximum heat input capacity shall be made during the initial 

performance test for affected facilities that meet the criteria of §60.44b(j). It shall be made within 60 days after 

achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after 

initial start-up of each facility, for affected facilities meeting the criteria of §60.44b(k). Subsequent demonstrations 

may be required by the Administrator at any other time. If this demonstration indicates that the maximum heat input 

capacity of the affected facility is less than that stated by the manufacturer of the affected facility, the maximum heat 

input capacity determined during this demonstration shall be used to determine the capacity utilization rate for the 

affected facility. Otherwise, the maximum heat input capacity provided by the manufacturer is used.

(h) The owner or operator of an affected facility described in §60.44b(j) that has a heat input capacity greater than 73 

MW (250 MMBtu/hr) shall:

(1) Conduct an initial performance test as required under §60.8 over a minimum of 24 consecutive steam generating 

unit operating hours at maximum heat input capacity to demonstrate compliance with the NOXemission standards 

under §60.44b using Method 7, 7A, 7E of appendix A of this part, or other approved reference methods; and

(2) Conduct subsequent performance tests once per calendar year or every 400 hours of operation (whichever comes 

first) to demonstrate compliance with the NOXemission standards under §60.44b over a minimum of 3 consecutive 

steam generating unit operating hours at maximum heat input capacity using Method 7, 7A, 7E of appendix A of this 

part, or other approved reference methods.

(i) The owner or operator of an affected facility seeking to demonstrate compliance with the PM limit in paragraphs 

§60.43b(a)(4) or §60.43b(h)(5) shall follow the applicable procedures in §60.49b(r).
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(j) In place of PM testing with Method 5 or 5B of appendix A–3 of this part, or Method 17 of appendix A–6 of this part, 

an owner or operator may elect to install, calibrate, maintain, and operate a CEMS for monitoring PM emissions 

discharged to the atmosphere and record the output of the system. The owner or operator of an affected facility who 

elects to continuously monitor PM emissions instead of conducting performance testing using Method 5 or 5B of 

appendix A–3 of this part or Method 17 of appendix A–6 of this part shall comply with the requirements specified in 

paragraphs (j)(1) through (j)(14) of this section.

(1) Notify the Administrator one month before starting use of the system.

(2) Notify the Administrator one month before stopping use of the system.

(3) The monitor shall be installed, evaluated, and operated in accordance with §60.13 of subpart A of this part.

(4) The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the 

affected facility, as specified under §60.8 of subpart A of this part or within 180 days of notification to the 

Administrator of use of the CEMS if the owner or operator was previously determining compliance by Method 5, 5B, 

or 17 of appendix A of this part performance tests, whichever is later.

(5) The owner or operator of an affected facility shall conduct an initial performance test for PM emissions as required 

under §60.8 of subpart A of this part. Compliance with the PM emission limit shall be determined by using the CEMS 

specified in paragraph (j) of this section to measure PM and calculating a 24-hour block arithmetic average emission 

concentration using EPA Reference Method 19 of appendix A of this part, section 4.1.

(6) Compliance with the PM emission limit shall be determined based on the 24-hour daily (block) average of the 

hourly arithmetic average emission concentrations using CEMS outlet data.

(7) At a minimum, valid CEMS hourly averages shall be obtained as specified in paragraphs (j)(7)(i) of this section for 

75 percent of the total operating hours per 30-day rolling average.

(i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average.

(ii) [Reserved]

(8) The 1-hour arithmetic averages required under paragraph (j)(7) of this section shall be expressed in ng/J or 

lb/MMBtu heat input and shall be used to calculate the boiler operating day daily arithmetic average emission 

concentrations. The 1-hour arithmetic averages shall be calculated using the data points required under §60.13(e)(2) 

of subpart A of this part.

(9) All valid CEMS data shall be used in calculating average emission concentrations even if the minimum CEMS 

data requirements of paragraph (j)(7) of this section are not met.

(10) The CEMS shall be operated according to Performance Specification 11 in appendix B of this part.

(11) During the correlation testing runs of the CEMS required by Performance Specification 11 in appendix B of this 

part, PM and O2(or CO2) data shall be collected concurrently (or within a 30-to 60-minute period) by both the 

continuous emission monitors and performance tests conducted using the following test methods.

(i) For PM, Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part shall be used; and

(ii) For O2(or CO2), Method 3A or 3B of appendix A–2 of this part, as applicable shall be used.

(12) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with 

procedure 2 in appendix F of this part. Relative Response Audit's must be performed annually and Response 

Correlation Audits must be performed every 3 years.
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(13) When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibration checks, and zero 

and span adjustments, emissions data shall be obtained by using other monitoring systems as approved by the 

Administrator or EPA Reference Method 19 of appendix A of this part to provide, as necessary, valid emissions data 

for a minimum of 75 percent of total operating hours per 30-day rolling average.

(14) After July 1, 2011, within 90 days after completing a correlation testing run, the owner or operator of an affected 

facility shall either successfully enter the test data into EPA's WebFIRE data base located at 

http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main or mail a copy to: United States Environmental Protection 

Agency; Energy Strategies Group; 109 TW Alexander DR; Mail Code: D243–01; RTP, NC 27711.

[72 FR 32742, June 13, 2007, as amended at 74 FR 5086, Jan. 28, 2009; 76 FR 3523, Jan. 20, 2011]

§ 60.47b Emission monitoring for sulfur dioxide.

(a) Except as provided in paragraphs (b) and (f) of this section, the owner or operator of an affected facility subject to 

the SO2standards in §60.42b shall install, calibrate, maintain, and operate CEMS for measuring SO2concentrations 

and either O2or CO2concentrations and shall record the output of the systems. For units complying with the percent 

reduction standard, the SO2and either O2or CO2concentrations shall both be monitored at the inlet and outlet of the 

SO2control device. If the owner or operator has installed and certified SO2and O2or CO2CEMS according to the 

requirements of §75.20(c)(1) of this chapter and appendix A to part 75 of this chapter, and is continuing to meet the 

ongoing quality assurance requirements of §75.21 of this chapter and appendix B to part 75 of this chapter, those 

CEMS may be used to meet the requirements of this section, provided that:

(1) When relative accuracy testing is conducted, SO2concentration data and CO2(or O2) data are collected 

simultaneously; and

(2) In addition to meeting the applicable SO2and CO2(or O2) relative accuracy specifications in Figure 2 of appendix 

B to part 75 of this chapter, the relative accuracy (RA) standard in section 13.2 of Performance Specification 2 in 

appendix B to this part is met when the RA is calculated on a lb/MMBtu basis; and

(3) The reporting requirements of §60.49b are met. SO2and CO2(or O2) data used to meet the requirements of 

§60.49b shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of 

this chapter, nor shall the SO2data have been bias adjusted according to the procedures of part 75 of this chapter.

(b) As an alternative to operating CEMS as required under paragraph (a) of this section, an owner or operator may 

elect to determine the average SO2emissions and percent reduction by:

(1) Collecting coal or oil samples in an as-fired condition at the inlet to the steam generating unit and analyzing them 

for sulfur and heat content according to Method 19 of appendix A of this part. Method 19 of appendix A of this part 

provides procedures for converting these measurements into the format to be used in calculating the average 

SO2input rate, or

(2) Measuring SO2according to Method 6B of appendix A of this part at the inlet or outlet to the SO2control system. 

An initial stratification test is required to verify the adequacy of the Method 6B of appendix A of this part sampling 

location. The stratification test shall consist of three paired runs of a suitable SO2and CO2measurement train 

operated at the candidate location and a second similar train operated according to the procedures in section 3.2 and 

the applicable procedures in section 7 of Performance Specification 2. Method 6B of appendix A of this part, Method 

6A of appendix A of this part, or a combination of Methods 6 and 3 or 3B 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.

(3) A daily SO2emission rate, ED, shall be determined using the procedure described in Method 6A of appendix A of 

this part, section 7.6.2 (Equation 6A–8) and stated in ng/J (lb/MMBtu) heat input.
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(4) The mean 30-day emission rate is calculated using the daily measured values in ng/J (lb/MMBtu) for 30 

successive steam generating unit operating days using equation 19–20 of Method 19 of appendix A of this part.

(c) The owner or operator of an affected facility shall obtain emission data for at least 75 percent of the operating 

hours in at least 22 out of 30 successive boiler 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 or the reference methods and procedures 

as described in paragraph (b) of this section.

(d) The 1-hour average SO2emission rates measured by the CEMS required by paragraph (a) of this section and 

required under §60.13(h) is expressed in ng/J or lb/MMBtu heat input and is used to calculate the average emission 

rates under §60.42(b). Each 1-hour average SO2emission rate must be based on 30 or more minutes of steam 

generating unit operation. The hourly averages shall be calculated according to §60.13(h)(2). Hourly SO2emission 

rates are not calculated if the affected facility is operated less than 30 minutes in a given clock hour and are not 

counted toward determination of a steam generating unit operating day.

(e) The procedures under §60.13 shall be followed for installation, evaluation, and operation of the CEMS.

(1) Except as provided for in paragraph (e)(4) of this section, 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) Except as provided for in paragraph (e)(4) of this section, quarterly accuracy determinations and daily calibration 

drift tests shall be performed in accordance with Procedure 1 of appendix F of this part.

(3) For affected facilities combusting coal or oil, alone or in combination with other fuels, the span value of the 

SO2CEMS at the inlet to the SO2control device is 125 percent of the maximum estimated hourly potential 

SO2emissions of the fuel combusted, and the span value of the CEMS at the outlet to the SO2control device is 50 

percent of the maximum estimated hourly potential SO2emissions of the fuel combusted. Alternatively, SO2span 

values determined according to section 2.1.1 in appendix A to part 75 of this chapter may be used.

(4) As an alternative to meeting the requirements of requirements of paragraphs (e)(1) and (e)(2) of this section, the 

owner or operator may elect to implement the following alternative data accuracy assessment procedures:

(i) For all required CO2and O2monitors and for SO2and NOXmonitors with span values greater than or equal to 100 

ppm, the daily calibration error test and calibration adjustment procedures described in sections 2.1.1 and 2.1.3 of 

appendix B to part 75 of this chapter may be followed instead of the CD assessment procedures in Procedure 1, 

section 4.1 of appendix F to this part.

(ii) For all required CO2and O2monitors and for SO2and NOXmonitors with span values greater than 30 ppm, 

quarterly linearity checks may be performed in accordance with section 2.2.1 of appendix B to part 75 of this chapter, 

instead of performing the cylinder gas audits (CGAs) described in Procedure 1, section 5.1.2 of appendix F to this 

part. If this option is selected: The frequency of the linearity checks shall be as specified in section 2.2.1 of appendix 

B to part 75 of this chapter; the applicable linearity specifications in section 3.2 of appendix A to part 75 of this 

chapter shall be met; the data validation and out-of-control criteria in section 2.2.3 of appendix B to part 75 of this 

chapter shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, section 

5.2 of appendix F to this part; and the grace period provisions in section 2.2.4 of appendix B to part 75 of this chapter 

shall apply. For the purposes of data validation under this subpart, the cylinder gas audits described in Procedure 1, 

section 5.1.2 of appendix F to this part shall be performed for SO2and NOXspan values less than or equal to 30 ppm; 

and

(iii) For SO2, CO2, and O2monitoring systems and for NOXemission rate monitoring systems, RATAs may be 

performed in accordance with section 2.3 of appendix B to part 75 of this chapter instead of following the procedures 

described in Procedure 1, section 5.1.1 of appendix F to this part. If this option is selected: The frequency of each 

RATA shall be as specified in section 2.3.1 of appendix B to part 75 of this chapter; the applicable relative accuracy 

specifications shown in Figure 2 in appendix B to part 75 of this chapter shall be met; the data validation and out-ofcontrol criteria in section 2.3.2 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit 

inaccuracy and out-of-control criteria in Procedure 1, section 5.2 of appendix F to this part; and the grace period 

provisions in section 2.3.3 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation 

under this subpart, the relative accuracy specification in section 13.2 of Performance Specification 2 in appendix B to 
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this part shall be met on a lb/MMBtu basis for SO2(regardless of the SO2emission level during the RATA), and for 

NOXwhen the average NOXemission rate measured by the reference method during the RATA is less than 0.100

lb/MMBtu.

(f) The owner or operator of an affected facility that combusts very low sulfur oil or is demonstrating compliance under 

§60.45b(k) is not subject to the emission monitoring requirements under paragraph (a) of this section if the owner or 

operator maintains fuel records as described in §60.49b(r).

[72 FR 32742, June 13, 2007, as amended at 74 FR 5087, Jan. 28, 2009]

§ 60.48b Emission monitoring for particulate matter and nitrogen oxides.

(a) Except as provided in paragraph (j) of this section, the owner or operator of an affected facility subject to the 

opacity standard under §60.43b shall install, calibrate, maintain, and operate a continuous opacity monitoring system 

(COMS) for measuring the opacity of 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 under §60.43b and meeting the conditions 

under paragraphs (j)(1), (2), (3), (4), or (5) of this section who elects not to use a COMS shall conduct a performance 

test using Method 9 of appendix A–4 of this part and the procedures in §60.11 to demonstrate compliance with the 

applicable limit in §60.43b by April 29, 2011, within 45 days of stopping use of an existing COMS, or 180 days after 

initial startup of the facility, whichever is later, and shall comply with either paragraphs (a)(1), (a)(2), or (a)(3) of this 

section. The observation period for Method 9 of appendix A–4 of this part performance tests may be reduced from 3 

hours to 60 minutes if all 6-minute averages are less than 10 percent and all individual 15-second observations are 

less than or equal to 20 percent during the initial 60 minutes of observation.

(1) Except as provided in paragraph (a)(2) and (a)(3) of this section, the owner or operator shall conduct subsequent 

Method 9 of appendix A–4 of this part performance tests using the procedures in paragraph (a) of this section 

according to the applicable schedule in paragraphs (a)(1)(i) through (a)(1)(iv) of this section, as determined by the 

most recent Method 9 of appendix A–4 of this part performance test results.

(i) If no visible emissions are observed, a subsequent Method 9 of appendix A–4 of this part performance test must 

be completed within 12 calendar months from the date that the most recent performance test was conducted;

(ii) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal to 5 percent, a 

subsequent Method 9 of appendix A–4 of this part performance test must be completed within 6 calendar months 

from the date that the most recent performance test was conducted;

(iii) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a 

subsequent Method 9 of appendix A–4 of this part performance test must be completed within 3 calendar months 

from the date that the most recent performance test was conducted; or

(iv) If the maximum 6-minute average opacity is greater than 10 percent, a subsequent Method 9 of appendix A–4 of 

this part performance test must be completed within 45 calendar days from the date that the most recent performance 

test was conducted.

(2) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A–4 of this 

part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix 

A–4 of this part performance tests, elect to perform subsequent monitoring using Method 22 of appendix A–7 of this 

part according to the procedures specified in paragraphs (a)(2)(i) and (ii) of this section.

(i) The owner or operator shall conduct 10 minute observations (during normal operation) each operating day the 

affected facility fires fuel for which an opacity standard is applicable using Method 22 of appendix A–7 of this part and 

demonstrate that the sum of the occurrences of any visible emissions is not in excess of 5 percent of the observation 

period ( i.e. , 30 seconds per 10 minute period). If the sum of the occurrence of any visible emissions is greater than 

30 seconds during the initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the 

occurrence of visible emissions is greater than 5 percent of the observation period ( i.e., 90 seconds per 30 minute 

period), the owner or operator shall either document and adjust the operation of the facility and demonstrate within 24 

hours that the sum of the occurrence of visible emissions is equal to or less than 5 percent during a 30 minute 
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observation ( i.e., 90 seconds) or conduct a new Method 9 of appendix A–4 of this part performance test using the 

procedures in paragraph (a) of this section within 45 calendar days according to the requirements in §60.46d(d)(7).

(ii) If no visible emissions are observed for 30 operating days during which an opacity standard is applicable, 

observations can be reduced to once every 7 operating days during which an opacity standard is applicable. If any 

visible emissions are observed, daily observations shall be resumed.

(3) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A–4 of this 

part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix 

A–4 performance tests, elect to perform subsequent monitoring using a digital opacity compliance system according 

to a site-specific monitoring plan approved by the Administrator. The observations shall be similar, but not necessarily 

identical, to the requirements in paragraph (a)(2) of this section. For reference purposes in preparing the monitoring 

plan, see OAQPS “Determination of Visible Emission Opacity from Stationary Sources Using Computer-Based 

Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection Agency (U.S. 

EPA); Office of Air Quality and Planning Standards; Sector Policies and Programs Division; Measurement Policy 

Group (D243–02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer 

Network (TTN) under Emission Measurement Center Preliminary Methods.

(b) Except as provided under paragraphs (g), (h), and (i) of this section, the owner or operator of an affected facility 

subject to a NOXstandard under §60.44b shall comply with either paragraphs (b)(1) or (b)(2) of this section.

(1) Install, calibrate, maintain, and operate CEMS for measuring NOXand O2(or CO2) emissions discharged to the 

atmosphere, and shall record the output of the system; or

(2) If the owner or operator has installed a NOXemission rate CEMS to meet the requirements of part 75 of this 

chapter and is continuing to meet the ongoing requirements of part 75 of this chapter, that CEMS may be used to 

meet the requirements of this section, except that the owner or operator shall also meet the requirements of §60.49b.

Data reported to meet the requirements of §60.49b shall not include data substituted using the missing data 

procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the 

procedures of part 75 of this chapter.

(c) The CEMS required under paragraph (b) of this section shall be operated and data recorded during all periods of 

operation of the affected facility except for CEMS breakdowns and repairs. Data is recorded during calibration 

checks, and zero and span adjustments.

(d) The 1-hour average NOXemission rates measured by the continuous NOXmonitor required by paragraph (b) of 

this section and required under §60.13(h) shall be expressed in ng/J or lb/MMBtu heat input and shall be used to 

calculate the average emission rates under §60.44b. The 1-hour averages shall be calculated using the data points 

required under §60.13(h)(2).

(e) The procedures under §60.13 shall be followed for installation, evaluation, and operation of the continuous 

monitoring systems.

(1) For affected facilities combusting coal, wood or municipal-type solid waste, the span value for a COMS shall be 

between 60 and 80 percent.

(2) For affected facilities combusting coal, oil, or natural gas, the span value for NOXis determined using one of the 

following procedures:

(i) Except as provided under paragraph (e)(2)(ii) of this section, NOXspan values shall be determined as follows:

Fuel

Span values for NOX

(ppm)

Natural gas 500.
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Oil 500.

Coal 1,000.

Mixtures 500 (x + y) + 1,000z.

Where:

x = Fraction of total heat input derived from natural gas;

y = Fraction of total heat input derived from oil; and

z = Fraction of total heat input derived from coal.

(ii) As an alternative to meeting the requirements of paragraph (e)(2)(i) of this section, the owner or operator of an 

affected facility may elect to use the NOXspan values determined according to section 2.1.2 in appendix A to part 75 

of this chapter.

(3) All span values computed under paragraph (e)(2)(i) of this section for combusting mixtures of regulated fuels are 

rounded to the nearest 500 ppm. Span values computed under paragraph (e)(2)(ii) of this section shall be rounded off 

according to section 2.1.2 in appendix A to part 75 of this chapter.

(f) When NOXemission data are not obtained because of CEMS breakdowns, repairs, calibration checks and zero 

and span adjustments, emission data will be obtained by using standby monitoring systems, Method 7 of appendix A 

of this part, Method 7A of appendix A of this part, or other approved reference methods to provide emission data for a 

minimum of 75 percent of the operating hours in each steam generating unit operating day, in at least 22 out of 30 

successive steam generating unit operating days.

(g) The owner or operator of an affected facility that has a heat input capacity of 73 MW (250 MMBtu/hr) or less, and 

that has an annual capacity factor for residual oil having a nitrogen content of 0.30 weight percent or less, natural 

gas, distillate oil, gasified coal, or any mixture of these fuels, greater than 10 percent (0.10) shall:

(1) Comply with the provisions of paragraphs (b), (c), (d), (e)(2), (e)(3), and (f) of this section; or

(2) Monitor steam generating unit operating conditions and predict NOXemission rates as specified in a plan 

submitted pursuant to §60.49b(c).

(h) The owner or operator of a duct burner, as described in §60.41b, that is subject to the NOXstandards in 

§60.44b(a)(4), §60.44b(e), or §60.44b(l) is not required to install or operate a continuous emissions monitoring 

system to measure NOXemissions.

(i) The owner or operator of an affected facility described in §60.44b(j) or §60.44b(k) is not required to install or 

operate a CEMS for measuring NOXemissions.

(j) The owner or operator of an affected facility that meets the conditions in either paragraph (j)(1), (2), (3), (4), (5), or 

(6) of this section is not required to install or operate a COMS if:

(1) The affected facility uses a PM CEMS to monitor PM emissions; or

(2) The affected facility burns only liquid (excluding residual oil) or gaseous fuels with potential SO2emissions rates of 

26 ng/J (0.060 lb/MMBtu) or less and does not use a post-combustion technology to reduce SO2or PM emissions. 

The owner or operator must maintain fuel records of the sulfur content of the fuels burned, as described under 

§60.49b(r); or
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(3) The affected facility burns coke oven gas alone or in combination with fuels meeting the criteria in paragraph (j)(2) 

of this section and does not use a post-combustion technology to reduce SO2or PM emissions; or

(4) The affected facility does not use post-combustion technology (except a wet scrubber) for reducing PM, SO2, or 

carbon monoxide (CO) emissions, burns only gaseous fuels or fuel oils that contain less than or equal to 0.30 weight 

percent sulfur, and is operated such that emissions of CO to the atmosphere from the affected facility are maintained 

at levels less than or equal to 0.15 lb/MMBtu on a steam generating unit operating day average basis. Owners and 

operators of affected facilities electing to comply with this paragraph must demonstrate compliance according to the 

procedures specified in paragraphs (j)(4)(i) through (iv) of this section; or

(i) You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs (j)(4)(i)(A) 

through (D) of this section.

(A) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in §60.58b(i)(3) 

of subpart Eb of this part.

(B) Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS expressed in 

parts per million by volume corrected to 3 percent oxygen (dry basis).

(C) At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the operating 

hours on a 30-day rolling average basis. The 1-hour averages are calculated using the data points required in 

§60.13(h)(2).

(D) 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.

(ii) You must calculate the 1-hour average CO emissions levels for each steam generating unit operating day by 

multiplying the average hourly CO output concentration measured by the CO CEMS times the corresponding average 

hourly flue gas flow rate and divided by the corresponding average hourly heat input to the affected source. The 24-

hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission levels 

computed for each steam generating unit operating day.

(iii) You must evaluate the preceding 24-hour average CO emission level each steam generating unit operating day 

excluding periods of affected source startup, shutdown, or malfunction. If the 24-hour average CO emission level is 

greater than 0.15 lb/MMBtu, you must initiate investigation of the relevant equipment and control systems within 24 

hours of the first discovery of the high emission incident and, take the appropriate corrective action as soon as 

practicable to adjust control settings or repair equipment to reduce the 24-hour average CO emission level to 0.15 

lb/MMBtu or less.

(iv) You must record the CO measurements and calculations performed according to paragraph (j)(4) of this section 

and any corrective actions taken. The record of corrective action taken must include the date and time during which 

the 24-hour average CO emission level was greater than 0.15 lb/MMBtu, and the date, time, and description of the 

corrective action.

(5) The affected facility uses a bag leak detection system to monitor the performance of a fabric filter (baghouse) 

according to the most recent requirements in section §60.48Da of this part; or

(6) The affected facility burns only gaseous fuels or fuel oils that contain less than or equal to 0.30 weight percent 

sulfur and operates according to a written site-specific monitoring plan approved by the permitting authority. This 

monitoring plan must include procedures and criteria for establishing and monitoring specific parameters for the 

affected facility indicative of compliance with the opacity standard.

(k) Owners or operators complying with the PM emission limit by using a PM CEMS must calibrate, maintain, operate, 

and record the output of the system for PM emissions discharged to the atmosphere as specified in §60.46b(j). The 

CEMS specified in paragraph §60.46b(j) shall be operated and data recorded during all periods of operation of the 

affected facility except for CEMS breakdowns and repairs. Data is recorded during calibration checks, and zero and 

span adjustments.
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[72 FR 32742, June 13, 2007, as amended at 74 FR 5087, Jan. 28, 2009; 76 FR 3523, Jan. 20, 2011]

§ 60.49b Reporting and recordkeeping requirements.

(a) The owner or operator of each affected facility shall submit notification of the date of initial startup, as provided by 

§60.7. This notification shall include:

(1) The design heat input capacity of the affected facility and identification of the fuels to be combusted in the affected 

facility;

(2) If applicable, a copy of any federally enforceable requirement that limits the annual capacity factor for any fuel or 

mixture of fuels under §§60.42b(d)(1), 60.43b(a)(2), (a)(3)(iii), (c)(2)(ii), (d)(2)(iii), 60.44b(c), (d), (e), (i), (j), (k), 

60.45b(d), (g), 60.46b(h), or 60.48b(i);

(3) The annual capacity factor at which the owner or operator anticipates operating the facility based on all fuels fired 

and based on each individual fuel fired; and

(4) Notification that an emerging technology will be used for controlling emissions of SO2. The Administrator will 

examine the description of the emerging technology and will determine whether the technology qualifies as an 

emerging technology. In making this determination, the Administrator may require the owner or operator of the 

affected facility to submit additional information concerning the control device. The affected facility is subject to the 

provisions of §60.42b(a) unless and until this determination is made by the Administrator.

(b) The owner or operator of each affected facility subject to the SO2, PM, and/or NOXemission limits under 

§§60.42b, 60.43b, and 60.44b shall submit to the Administrator the performance test data from the initial performance 

test and the performance evaluation of the CEMS using the applicable performance specifications in appendix B of 

this part. The owner or operator of each affected facility described in §60.44b(j) or §60.44b(k) shall submit to the 

Administrator the maximum heat input capacity data from the demonstration of the maximum heat input capacity of 

the affected facility.

(c) The owner or operator of each affected facility subject to the NOXstandard in §60.44b who seeks to demonstrate 

compliance with those standards through the monitoring of steam generating unit operating conditions in the 

provisions of §60.48b(g)(2) shall submit to the Administrator for approval a plan that identifies the operating 

conditions to be monitored in §60.48b(g)(2) and the records to be maintained in §60.49b(g). This plan shall be 

submitted to the Administrator for approval within 360 days of the initial startup of the affected facility. An affected 

facility burning coke oven gas alone or in combination with other gaseous fuels or distillate oil shall submit this plan to 

the Administrator for approval within 360 days of the initial startup of the affected facility or by November 30, 2009, 

whichever date comes later. If the plan is approved, the owner or operator shall maintain records of predicted 

nitrogen oxide emission rates and the monitored operating conditions, including steam generating unit load, identified 

in the plan. The plan shall:

(1) Identify the specific operating conditions to be monitored and the relationship between these operating conditions 

and NOXemission rates ( i.e. , ng/J or lbs/MMBtu heat input). Steam generating unit operating conditions include, but 

are not limited to, the degree of staged combustion ( i.e. , the ratio of primary air to secondary and/or tertiary air) and 

the level of excess air ( i.e. , flue gas O2level);

(2) Include the data and information that the owner or operator used to identify the relationship between NOXemission 

rates and these operating conditions; and

(3) Identify how these operating conditions, including steam generating unit load, will be monitored under §60.48b(g) 

on an hourly basis by the owner or operator during the period of operation of the affected facility; the quality 

assurance procedures or practices that will be employed to ensure that the data generated by monitoring these 

operating conditions will be representative and accurate; and the type and format of the records of these operating 

conditions, including steam generating unit load, that will be maintained by the owner or operator under §60.49b(g).

(d) Except as provided in paragraph (d)(2) of this section, the owner or operator of an affected facility shall record and 

maintain records as specified in paragraph (d)(1) of this section.
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(1) The owner or operator of an affected facility shall record and maintain records of the amounts of each fuel 

combusted during each day and calculate the annual capacity factor individually for coal, distillate oil, residual oil, 

natural gas, wood, and municipal-type solid waste for the reporting period. The annual capacity factor is determined 

on a 12-month rolling average basis with a new annual capacity factor calculated at the end of each calendar month.

(2) As an alternative to meeting the requirements of paragraph (d)(1) of this section, the owner or operator of an 

affected facility that is subject to a federally enforceable permit restricting fuel use to a single fuel such that the facility 

is not required to continuously monitor any emissions (excluding opacity) or parameters indicative of emissions may 

elect to record and maintain records of the amount of each fuel combusted during each calendar month.

(e) For an affected facility that combusts residual oil and meets the criteria under §§60.46b(e)(4), 60.44b(j), or (k), the 

owner or operator shall maintain records of the nitrogen content of the residual oil combusted in the affected facility 

and calculate the average fuel nitrogen content for the reporting period. The nitrogen content shall be determined 

using ASTM Method D4629 (incorporated by reference, see §60.17), or fuel suppliers. If residual oil blends are being 

combusted, fuel nitrogen specifications may be prorated based on the ratio of residual oils of different nitrogen 

content in the fuel blend.

(f) For an affected facility subject to the opacity standard in §60.43b, the owner or operator shall maintain records of 

opacity. In addition, an owner or operator that elects to monitor emissions according to the requirements in 

§60.48b(a) shall maintain records according to the requirements specified in paragraphs (f)(1) through (3) of this 

section, as applicable to the visible emissions monitoring method used.

(1) For each performance test conducted using Method 9 of appendix A–4 of this part, the owner or operator shall 

keep the records including the information specified in paragraphs (f)(1)(i) through (iii) of this section.

(i) Dates and time intervals of all opacity observation periods;

(ii) Name, affiliation, and copy of current visible emission reading certification for each visible emission observer 

participating in the performance test; and

(iii) Copies of all visible emission observer opacity field data sheets;

(2) For each performance test conducted using Method 22 of appendix A–4 of this part, the owner or operator shall 

keep the records including the information specified in paragraphs (f)(2)(i) through (iv) of this section.

(i) Dates and time intervals of all visible emissions observation periods;

(ii) Name and affiliation for each visible emission observer participating in the performance test;

(iii) Copies of all visible emission observer opacity field data sheets; and

(iv) Documentation of any adjustments made and the time the adjustments were completed to the affected facility 

operation by the owner or operator to demonstrate compliance with the applicable monitoring requirements.

(3) For each digital opacity compliance system, the owner or operator shall maintain records and submit reports 

according to the requirements specified in the site-specific monitoring plan approved by the Administrator.

(g) Except as provided under paragraph (p) of this section, the owner or operator of an affected facility subject to the

NOXstandards under §60.44b shall maintain records of the following information for each steam generating unit 

operating day:

(1) Calendar date;

(2) The average hourly NOXemission rates (expressed as NO2) (ng/J or lb/MMBtu heat input) measured or predicted;
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(3) The 30-day average NOXemission rates (ng/J or lb/MMBtu heat input) calculated at the end of each steam 

generating unit operating day from the measured or predicted hourly nitrogen oxide emission rates for the preceding 

30 steam generating unit operating days;

(4) Identification of the steam generating unit operating days when the calculated 30-day average NOXemission rates 

are in excess of the NOXemissions standards under §60.44b, with the reasons for such excess emissions as well as 

a description of corrective actions taken;

(5) Identification of the steam generating unit operating days for which pollutant data have not been obtained, 

including reasons for not obtaining sufficient data and a description of corrective actions taken;

(6) Identification of the times when emission data have been excluded from the calculation of average emission rates 

and the reasons for excluding data;

(7) Identification of “F” factor used for calculations, method of determination, and type of fuel combusted;

(8) Identification of the times when the pollutant concentration exceeded full span of the CEMS;

(9) Description of any modifications to the CEMS that could affect the ability of the CEMS to comply with Performance 

Specification 2 or 3; and

(10) Results of daily CEMS drift tests and quarterly accuracy assessments as required under appendix F, Procedure 

1 of this part.

(h) The owner or operator of any affected facility in any category listed in paragraphs (h)(1) or (2) of this section is 

required to submit excess emission reports for any excess emissions that occurred during the reporting period.

(1) Any affected facility subject to the opacity standards in §60.43b(f) or to the operating parameter monitoring 

requirements in §60.13(i)(1).

(2) Any affected facility that is subject to the NOXstandard of §60.44b, and that:

(i) Combusts natural gas, distillate oil, gasified coal, or residual oil with a nitrogen content of 0.3 weight percent or 

less; or

(ii) Has a heat input capacity of 73 MW (250 MMBtu/hr) or less and is required to monitor NOXemissions on a 

continuous basis under §60.48b(g)(1) or steam generating unit operating conditions under §60.48b(g)(2).

(3) For the purpose of §60.43b, excess emissions are defined as all 6-minute periods during which the average 

opacity exceeds the opacity standards under §60.43b(f).

(4) For purposes of §60.48b(g)(1), excess emissions are defined as any calculated 30-day rolling average 

NOXemission rate, as determined under §60.46b(e), that exceeds the applicable emission limits in §60.44b.

(i) The owner or operator of any affected facility subject to the continuous monitoring requirements for NOXunder 

§60.48(b) shall submit reports containing the information recorded under paragraph (g) of this section.

(j) The owner or operator of any affected facility subject to the SO2standards under §60.42b shall submit reports.

(k) For each affected facility subject to the compliance and performance testing requirements of §60.45b and the 

reporting requirement in paragraph (j) of this section, the following information shall be reported to the Administrator:

(1) Calendar dates covered in the reporting period;
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(2) Each 30-day average SO2emission rate (ng/J or lb/MMBtu heat input) measured during the reporting period, 

ending with the last 30-day period; reasons for noncompliance with the emission standards; and a description of 

corrective actions taken; For an exceedance due to maintenance of the SO2control system covered in paragraph 

60.45b(a), the report shall identify the days on which the maintenance was performed and a description of the 

maintenance;

(3) Each 30-day average percent reduction in SO2emissions calculated during the reporting period, ending with the 

last 30-day period; reasons for noncompliance with the emission standards; and a description of corrective actions 

taken;

(4) Identification of the steam generating unit operating days that coal or oil was combusted and for which SO2or 

diluent (O2or CO2) data have not been obtained by an approved method for at least 75 percent of the operating 

hours in the steam generating unit operating day; justification for not obtaining sufficient data; and description of 

corrective action taken;

(5) Identification of the times when emissions data have been excluded from the calculation of average emission 

rates; justification for excluding data; and description of corrective action 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 “F” factor used for calculations, method of determination, and type of fuel combusted;

(7) Identification of times when hourly averages have been obtained based on manual sampling methods;

(8) Identification of the times when the pollutant concentration exceeded full span of the CEMS;

(9) Description of any modifications to the CEMS that could affect the ability of the CEMS to comply with Performance 

Specification 2 or 3;

(10) Results of daily CEMS drift tests and quarterly accuracy assessments as required under appendix F, Procedure 

1 of this part; and

(11) The annual capacity factor of each fired as provided under paragraph (d) of this section.

(l) For each affected facility subject to the compliance and performance testing requirements of §60.45b(d) and the 

reporting requirements of paragraph (j) of this section, the following information shall be reported to the Administrator:

(1) Calendar dates when the facility was in operation during the reporting period;

(2) The 24-hour average SO2emission rate measured for each steam generating unit operating day during the 

reporting period that coal or oil was combusted, ending in the last 24-hour period in the quarter; reasons for 

noncompliance with the emission standards; and a description of corrective actions taken;

(3) Identification of the steam generating unit operating days that coal or oil was combusted for which S02or diluent 

(O2or CO2) data have not been obtained by an approved method for at least 75 percent of the operating hours; 

justification for not obtaining sufficient data; and description of corrective action taken;

(4) Identification of the times when emissions data have been excluded from the calculation of average emission 

rates; justification for excluding data; and description of corrective action taken if data have been excluded for periods 

other than those during which coal or oil were not combusted in the steam generating unit;

(5) Identification of “F” factor used for calculations, method of determination, and type of fuel combusted;

(6) Identification of times when hourly averages have been obtained based on manual sampling methods;

(7) Identification of the times when the pollutant concentration exceeded full span of the CEMS;
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(8) Description of any modifications to the CEMS that could affect the ability of the CEMS to comply with Performance 

Specification 2 or 3; and

(9) Results of daily CEMS drift tests and quarterly accuracy assessments as required under Procedure 1 of appendix 

F 1 of this part. If the owner or operator elects to implement the alternative data assessment procedures described in 

§§60.47b(e)(4)(i) through (e)(4)(iii), each data assessment report shall include a summary of the results of all of the 

RATAs, linearity checks, CGAs, and calibration error or drift assessments required by §§60.47b(e)(4)(i) through 

(e)(4)(iii).

(m) For each affected facility subject to the SO2standards in §60.42(b) for which the minimum amount of data 

required in §60.47b(c) were not obtained during the reporting period, the following information is reported to the 

Administrator in addition to that required under paragraph (k) of this section:

(1) The number of hourly averages available for outlet emission rates and inlet emission rates;

(2) The standard deviation of hourly averages for outlet emission rates and inlet emission rates, as determined in 

Method 19 of appendix A of this part, section 7;

(3) The lower confidence limit for the mean outlet emission rate and the upper confidence limit for the mean inlet 

emission rate, as calculated in Method 19 of appendix A of this part, section 7; and

(4) The ratio of the lower confidence limit for the mean outlet emission rate and the allowable emission rate, as 

determined in Method 19 of appendix A of this part, section 7.

(n) If a percent removal efficiency by fuel pretreatment ( i.e. , %Rf) is used to determine the overall percent reduction 

( i.e. , %Ro) under §60.45b, the owner or operator of the affected facility shall submit a signed statement with the 

report.

(1) Indicating what removal efficiency by fuel pretreatment ( i.e. , %Rf) was credited during the reporting period;

(2) Listing the quantity, heat content, and date each pre-treated fuel shipment was received during the reporting 

period, the name and location of the fuel pretreatment facility; and the total quantity and total heat content of all fuels 

received at the affected facility during the reporting period;

(3) Documenting the transport of the fuel from the fuel pretreatment facility to the steam generating unit; and

(4) Including a signed statement from the owner or operator of the fuel pretreatment facility certifying that the percent 

removal efficiency achieved by fuel pretreatment was determined in accordance with the provisions of Method 19 of 

appendix A of this part and listing the heat content and sulfur content of each fuel before and after fuel pretreatment.

(o) All records required under this section shall be maintained by the owner or operator of the affected facility for a 

period of 2 years following the date of such record.

(p) The owner or operator of an affected facility described in §60.44b(j) or (k) shall maintain records of the following 

information for each steam generating unit operating day:

(1) Calendar date;

(2) The number of hours of operation; and

(3) A record of the hourly steam load.

(q) The owner or operator of an affected facility described in §60.44b(j) or §60.44b(k) shall submit to the Administrator 

a report containing:

(1) The annual capacity factor over the previous 12 months;
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(2) The average fuel nitrogen content during the reporting period, if residual oil was fired; and

(3) If the affected facility meets the criteria described in §60.44b(j), the results of any NOXemission tests required 

during the reporting period, the hours of operation during the reporting period, and the hours of operation since the 

last NOXemission test.

(r) The owner or operator of an affected facility who elects to use the fuel based compliance alternatives in §60.42b or 

§60.43b shall either:

(1) The owner or operator of an affected facility who elects to demonstrate that the affected facility combusts only 

very low sulfur oil, natural gas, wood, a mixture of these fuels, or any of these fuels (or a mixture of these fuels) in 

combination with other fuels that are known to contain an insignificant amount of sulfur in §60.42b(j) or §60.42b(k) 

shall obtain and maintain at the affected facility fuel receipts from the fuel supplier that certify that the oil meets the 

definition of distillate oil and gaseous fuel meets the definition of natural gas as defined in §60.41b and the applicable 

sulfur limit. For the purposes of this section, the distillate oil need not meet the fuel nitrogen content specification in 

the definition of distillate oil. Reports shall be submitted to the Administrator certifying that only very low sulfur oil 

meeting this definition, natural gas, wood, and/or other fuels that are known to contain insignificant amounts of sulfur 

were combusted in the affected facility during the reporting period; or

(2) The owner or operator of an affected facility who elects to demonstrate compliance based on fuel analysis in 

§60.42b or §60.43b shall develop and submit a site-specific fuel analysis plan to the Administrator for review and 

approval no later than 60 days before the date you intend to demonstrate compliance. Each fuel analysis plan shall 

include a minimum initial requirement of weekly testing and each analysis report shall contain, at a minimum, the 

following information:

(i) The potential sulfur emissions rate of the representative fuel mixture in ng/J heat input;

(ii) The method used to determine the potential sulfur emissions rate of each constituent of the mixture. For distillate 

oil and natural gas a fuel receipt or tariff sheet is acceptable;

(iii) The ratio of different fuels in the mixture; and

(iv) The owner or operator can petition the Administrator to approve monthly or quarterly sampling in place of weekly 

sampling.

(s) Facility specific NOXstandard for Cytec Industries Fortier Plant's C.AOG incinerator located in Westwego, 

Louisiana:

(1) Definitions .

Oxidation zone is defined as the portion of the C.AOG incinerator that extends from the inlet of the oxidizing zone 

combustion air to the outlet gas stack.

Reducing zone is defined as the portion of the C.AOG incinerator that extends from the burner section to the inlet of 

the oxidizing zone combustion air.

Total inlet air is defined as the total amount of air introduced into the C.AOG incinerator for combustion of natural gas 

and chemical by-product waste and is equal to the sum of the air flow into the reducing zone and the air flow into the 

oxidation zone.

(2) Standard for nitrogen oxides . (i) When fossil fuel alone is combusted, the NOXemission limit for fossil fuel in 

§60.44b(a) applies.

(ii) When natural gas and chemical by-product waste are simultaneously combusted, the NOXemission limit is 289 

ng/J (0.67 lb/MMBtu) and a maximum of 81 percent of the total inlet air provided for combustion shall be provided to 

the reducing zone of the C.AOG incinerator.
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(3) Emission monitoring . (i) The percent of total inlet air provided to the reducing zone shall be determined at least 

every 15 minutes by measuring the air flow of all the air entering the reducing zone and the air flow of all the air 

entering the oxidation zone, and compliance with the percentage of total inlet air that is provided to the reducing zone 

shall be determined on a 3-hour average basis.

(ii) The NOXemission limit shall be determined by the compliance and performance test methods and procedures for 

NOXin §60.46b(i).

(iii) The monitoring of the NOXemission limit shall be performed in accordance with §60.48b.

(4) Reporting and recordkeeping requirements . (i) The owner or operator of the C.AOG incinerator shall submit a 

report on any excursions from the limits required by paragraph (a)(2) of this section to the Administrator with the 

quarterly report required by paragraph (i) of this section.

(ii) The owner or operator of the C.AOG incinerator shall keep records of the monitoring required by paragraph (a)(3) 

of this section for a period of 2 years following the date of such record.

(iii) The owner of operator of the C.AOG incinerator shall perform all the applicable reporting and recordkeeping 

requirements of this section.

(t) Facility-specific NOXstandard for Rohm and Haas Kentucky Incorporated's Boiler No. 100 located in Louisville, 

Kentucky:

(1) Definitions .

Air ratio control damper is defined as the part of the low NOXburner that is adjusted to control the split of total 

combustion air delivered to the reducing and oxidation portions of the combustion flame.

Flue gas recirculation line is defined as the part of Boiler No. 100 that recirculates a portion of the boiler flue gas back 

into the combustion air.

(2) Standard for nitrogen oxides . (i) When fossil fuel alone is combusted, the NOXemission limit for fossil fuel in 

§60.44b(a) applies.

(ii) When fossil fuel and chemical by-product waste are simultaneously combusted, the NOXemission limit is 473 ng/J 

(1.1 lb/MMBtu), and the air ratio control damper tee handle shall be at a minimum of 5 inches (12.7 centimeters) out 

of the boiler, and the flue gas recirculation line shall be operated at a minimum of 10 percent open as indicated by its 

valve opening position indicator.

(3) Emission monitoring for nitrogen oxides . (i) The air ratio control damper tee handle setting and the flue gas 

recirculation line valve opening position indicator setting shall be recorded during each 8-hour operating shift.

(ii) The NOXemission limit shall be determined by the compliance and performance test methods and procedures for 

NOXin §60.46b.

(iii) The monitoring of the NOXemission limit shall be performed in accordance with §60.48b.

(4) Reporting and recordkeeping requirements . (i) The owner or operator of Boiler No. 100 shall submit a report on 

any excursions from the limits required by paragraph (b)(2) of this section to the Administrator with the quarterly 

report required by §60.49b(i).

(ii) The owner or operator of Boiler No. 100 shall keep records of the monitoring required by paragraph (b)(3) of this 

section for a period of 2 years following the date of such record.

(iii) The owner of operator of Boiler No. 100 shall perform all the applicable reporting and recordkeeping requirements 

of §60.49b.
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(u) Site-specific standard for Merck & Co., Inc.'s Stonewall Plant in Elkton, Virginia . (1) This paragraph (u) applies 

only to the pharmaceutical manufacturing facility, commonly referred to as the Stonewall Plant, located at Route 340 

South, in Elkton, Virginia (“site”) and only to the natural gas-fired boilers installed as part of the powerhouse 

conversion required pursuant to 40 CFR 52.2454(g). The requirements of this paragraph shall apply, and the 

requirements of §§60.40b through 60.49b(t) shall not apply, to the natural gas-fired boilers installed pursuant to 40 

CFR 52.2454(g).

(i) The site shall equip the natural gas-fired boilers with low NOXtechnology.

(ii) The site shall install, calibrate, maintain, and operate a continuous monitoring and recording system for measuring 

NOXemissions discharged to the atmosphere and opacity using a continuous emissions monitoring system or a 

predictive emissions monitoring system.

(iii) Within 180 days of the completion of the powerhouse conversion, as required by 40 CFR 52.2454, the site shall 

perform a performance test to quantify criteria pollutant emissions.

(2) [Reserved]

(v) The owner or operator of an affected facility may submit electronic quarterly reports for SO2and/or NOXand/or 

opacity in lieu of submitting the written reports required under paragraphs (h), (i), (j), (k) or (l) of this section. The 

format of each quarterly electronic report shall be coordinated with the permitting authority. The electronic report(s) 

shall be submitted no later than 30 days after the end of the calendar quarter and shall be accompanied by a

certification statement from the owner or operator, indicating whether compliance with the applicable emission 

standards and minimum data requirements of this subpart was achieved during the reporting period. Before 

submitting reports in the electronic format, the owner or operator shall coordinate with the permitting authority to 

obtain their agreement to submit reports in this alternative format.

(w) The reporting period for the reports required under this subpart is each 6 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.

(x) Facility-specific NOXstandard for Weyerhaeuser Company's No. 2 Power Boiler located in New Bern, North 

Carolina:

(1) Standard for nitrogen oxides . (i) When fossil fuel alone is combusted, the NOXemission limit for fossil fuel in 

§60.44b(a) applies.

(ii) When fossil fuel and chemical by-product waste are simultaneously combusted, the NOXemission limit is 215 ng/J 

(0.5 lb/MMBtu).

(2) Emission monitoring for nitrogen oxides . (i) The NOXemissions shall be determined by the compliance and 

performance test methods and procedures for NOXin §60.46b.

(ii) The monitoring of the NOXemissions shall be performed in accordance with §60.48b.

(3) Reporting and recordkeeping requirements . (i) The owner or operator of the No. 2 Power Boiler shall submit a 

report on any excursions from the limits required by paragraph (x)(2) of this section to the Administrator with the 

quarterly report required by §60.49b(i).

(ii) The owner or operator of the No. 2 Power Boiler shall keep records of the monitoring required by paragraph (x)(3) 

of this section for a period of 2 years following the date of such record.

(iii) The owner or operator of the No. 2 Power Boiler shall perform all the applicable reporting and recordkeeping 

requirements of §60.49b.

(y) Facility-specific NOXstandard for INEOS USA's AOGI located in Lima, Ohio:
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Permit Reviewer: Josiah Balogun

(1) Standard for NO X. (i) When fossil fuel alone is combusted, the NOXemission limit for fossil fuel in §60.44b(a) 

applies.

(ii) When fossil fuel and chemical byproduct/waste are simultaneously combusted, the NOXemission limit is 645 ng/J 

(1.5 lb/MMBtu).

(2) Emission monitoring for NO X. (i) The NOXemissions shall be determined by the compliance and performance test 

methods and procedures for NOXin §60.46b.

(ii) The monitoring of the NOXemissions shall be performed in accordance with §60.48b.

(3) Reporting and recordkeeping requirements . (i) The owner or operator of the AOGI shall submit a report on any 

excursions from the limits required by paragraph (y)(2) of this section to the Administrator with the quarterly report 

required by paragraph (i) of this section.

(ii) The owner or operator of the AOGI shall keep records of the monitoring required by paragraph (y)(3) of this 

section for a period of 2 years following the date of such record.

(iii) The owner or operator of the AOGI shall perform all the applicable reporting and recordkeeping requirements of 

this section.

[72 FR 32742, June 13, 2007, as amended at 74 FR 5089, Jan. 28, 2009]
Attachment D to a PSD/Part 70 Operating Permit

Subpart Kb—Standards of Performance for Volatile Organic Liquid Storage 

Vessels (Including Petroleum Liquid Storage Vessels) for Which 

Construction, Reconstruction, or Modification Commenced After July 23, 

1984 [40 CFR Part 60, Subpart Kb] [326 IAC 12]

Source Name: Indiana Gasification LLC

Source Location: CR 200 N and Base Road, Rockport, IN 47635

County: Spencer

SIC Code: 4925, 2819

Operation Permit No.: T 147-30464-00060

Operation Permit Issuance Date: Yet to be Issued

Permit Reviewer: Josiah Balogun

Subpart Kb—Standards of Performance for Volatile Organic Liquid Storage 

Vessels (Including Petroleum Liquid Storage Vessels) for Which 

Construction, Reconstruction, or Modification Commenced After July 23, 

1984

Source: 52 FR 11429, Apr. 8, 1987, unless otherwise noted.

§ 60.110b Applicability and designation of affected facility.

(a) Except as provided in paragraph (b) of this section, the affected facility to which this subpart applies is each 

storage vessel with a capacity greater than or equal to 75 cubic meters (m3 ) that is used to store volatile organic 

liquids (VOL) for which construction, reconstruction, or modification is commenced after July 23, 1984.

(b) This subpart does not apply to storage vessels with a capacity greater than or equal to 151 m3 storing a liquid with 

a maximum true vapor pressure less than 3.5 kilopascals (kPa) or with a capacity greater than or equal to 75 m3 but 

less than 151 m3 storing a liquid with a maximum true vapor pressure less than 15.0 kPa.

(c) [Reserved]

(d) This subpart does not apply to the following:

(1) Vessels at coke oven by-product plants.

(2) Pressure vessels designed to operate in excess of 204.9 kPa and without emissions to the atmosphere.

(3) Vessels permanently attached to mobile vehicles such as trucks, railcars, barges, or ships.

(4) Vessels with a design capacity less than or equal to 1,589.874 m3 used for petroleum or condensate stored, 

processed, or treated prior to custody transfer.

(5) Vessels located at bulk gasoline plants.

(6) Storage vessels located at gasoline service stations.

(7) Vessels used to store beverage alcohol.
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(8) Vessels subject to subpart GGGG of 40 CFR part 63.

(e) Alternative means of compliance —(1) Option to comply with part 65. Owners or operators may choose to comply 

with 40 CFR part 65, subpart C, to satisfy the requirements of §§60.112b through 60.117b for storage vessels that 

are subject to this subpart that meet the specifications in paragraphs (e)(1)(i) and (ii) of this section. When choosing 

to comply with 40 CFR part 65, subpart C, the monitoring requirements of §60.116b(c), (e), (f)(1), and (g) still apply. 

Other provisions applying to owners or operators who choose to comply with 40 CFR part 65 are provided in 40 CFR 

65.1.

(i) A storage vessel with a design capacity greater than or equal to 151 m3 containing a VOL that, as stored, has a 

maximum true vapor pressure equal to or greater than 5.2 kPa; or

(ii) A storage vessel with a design capacity greater than 75 m3 but less than 151 m3 containing a VOL that, as stored, 

has a maximum true vapor pressure equal to or greater than 27.6 kPa.

(2) Part 60, subpart A. Owners or operators who choose to comply with 40 CFR part 65, subpart C, must also comply 

with §§60.1, 60.2, 60.5, 60.6, 60.7(a)(1) and (4), 60.14, 60.15, and 60.16 for those storage vessels. All sections and 

paragraphs of subpart A of this part that are not mentioned in this paragraph (e)(2) do not apply to owners or 

operators of storage vessels complying with 40 CFR part 65, subpart C, except that provisions required to be met 

prior to implementing 40 CFR part 65 still apply. Owners and operators who choose to comply with 40 CFR part 65, 

subpart C, must comply with 40 CFR part 65, subpart A.

(3) Internal floating roof report. If an owner or operator installs an internal floating roof and, at initial startup, chooses 

to comply with 40 CFR part 65, subpart C, a report shall be furnished to the Administrator stating that the control 

equipment meets the specifications of 40 CFR 65.43. This report shall be an attachment to the notification required 

by 40 CFR 65.5(b).

(4) External floating roof report. If an owner or operator installs an external floating roof and, at initial startup, chooses 

to comply with 40 CFR part 65, subpart C, a report shall be furnished to the Administrator stating that the control 

equipment meets the specifications of 40 CFR 65.44. This report shall be an attachment to the notification required 

by 40 CFR 65.5(b).

[52 FR 11429, Apr. 8, 1987, as amended at 54 FR 32973, Aug. 11, 1989; 65 FR 78275, Dec. 14, 2000; 68 FR 59332, 

Oct. 15, 2003]

§ 60.111b Definitions.

Terms used in this subpart are defined in the Act, in subpart A of this part, or in this subpart as follows:

Bulk gasoline plant means any gasoline distribution facility that has a gasoline throughput less than or equal to 

75,700 liters per day. Gasoline throughput shall be the maximum calculated design throughput as may be limited by 

compliance with an enforceable condition under Federal requirement or Federal, State or local law, and discoverable 

by the Administrator and any other person.

Condensate means hydrocarbon liquid separated from natural gas that condenses due to changes in the temperature 

or pressure, or both, and remains liquid at standard conditions.

Custody transfer means the transfer of produced petroleum and/or condensate, after processing and/or treatment in 

the producing operations, from storage vessels or automatic transfer facilities to pipelines or any other forms of 

transportation.

Fill means the introduction of VOL into a storage vessel but not necessarily to complete capacity.

Gasoline service station means any site where gasoline is dispensed to motor vehicle fuel tanks from stationary 

storage tanks.
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Maximum true vapor pressure means the equilibrium partial pressure exerted by the volatile organic compounds (as 

defined in 40 CFR 51.100) in the stored VOL at the temperature equal to the highest calendar-month average of the 

VOL storage temperature for VOL's stored above or below the ambient temperature or at the local maximum monthly 

average temperature as reported by the National Weather Service for VOL's stored at the ambient temperature, as 

determined:

(1) In accordance with methods described in American Petroleum institute Bulletin 2517, Evaporation Loss From 

External Floating Roof Tanks, (incorporated by reference—see §60.17); or

(2) As obtained from standard reference texts; or

(3) As determined by ASTM D2879–83, 96, or 97 (incorporated by reference—see §60.17);

(4) Any other method approved by the Administrator.

Petroleum means the crude oil removed from the earth and the oils derived from tar sands, shale, and coal.

Petroleum liquids means petroleum, condensate, and any finished or intermediate products manufactured in a 

petroleum refinery.

Process tank means a tank that is used within a process (including a solvent or raw material recovery process) to 

collect material discharged from a feedstock storage vessel or equipment within the process before the material is 

transferred to other equipment within the process, to a product or by-product storage vessel, or to a vessel used to 

store recovered solvent or raw material. In many process tanks, unit operations such as reactions and blending are 

conducted. Other process tanks, such as surge control vessels and bottoms receivers, however, may not involve unit 

operations.

Reid vapor pressure means the absolute vapor pressure of volatile crude oil and volatile nonviscous petroleum liquids 

except liquified petroleum gases, as determined by ASTM D323–82 or 94 (incorporated by reference—see §60.17).

Storage vessel means each tank, reservoir, or container used for the storage of volatile organic liquids but does not 

include:

(1) Frames, housing, auxiliary supports, or other components that are not directly involved in the containment of 

liquids or vapors;

(2) Subsurface caverns or porous rock reservoirs; or

(3) Process tanks.

Volatile organic liquid (VOL) means any organic liquid which can emit volatile organic compounds (as defined in 40 

CFR 51.100) into the atmosphere.

Waste means any liquid resulting from industrial, commercial, mining or agricultural operations, or from community 

activities that is discarded or is being accumulated, stored, or physically, chemically, or biologically treated prior to 

being discarded or recycled.

[52 FR 11429, Apr. 8, 1987, as amended at 54 FR 32973, Aug. 11, 1989; 65 FR 61756, Oct. 17, 2000; 68 FR 59333, 

Oct. 15, 2003]

§ 60.112b Standard for volatile organic compounds (VOC).

(a) The owner or operator of each storage vessel either with a design capacity greater than or equal to 151 m3

containing a VOL that, as stored, has a maximum true vapor pressure equal to or greater than 5.2 kPa but less than 

76.6 kPa or with a design capacity greater than or equal to 75 m3 but less than 151 m3 containing a VOL that, as 
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060

Permit Reviewer: Josiah Balogun

stored, has a maximum true vapor pressure equal to or greater than 27.6 kPa but less than 76.6 kPa, shall equip 

each storage vessel with one of the following:

(1) A fixed roof in combination with an internal floating roof meeting the following specifications:

(i) The internal floating roof shall rest or float on the liquid surface (but not necessarily in complete contact with it) 

inside a storage vessel that has a fixed roof. The internal floating roof shall be floating on the liquid surface at all 

times, except during initial fill and during those intervals when the storage vessel is completely emptied or 

subsequently emptied and refilled. When the roof is resting on the leg supports, the process of filling, emptying, or 

refilling shall be continuous and shall be accomplished as rapidly as possible.

(ii) Each internal floating roof shall be equipped with one of the following closure devices between the wall of the 

storage vessel and the edge of the internal floating roof:

(A) A foam- or liquid-filled seal mounted in contact with the liquid (liquid-mounted seal). A liquid-mounted seal means 

a foam- or liquid-filled seal mounted in contact with the liquid between the wall of the storage vessel and the floating 

roof continuously around the circumference of the tank.

(B) Two seals mounted one above the other so that each forms a continuous closure that completely covers the 

space between the wall of the storage vessel and the edge of the internal floating roof. The lower seal may be vapormounted, but both must be continuous.

(C) A mechanical shoe seal. A mechanical shoe seal is a metal sheet held vertically against the wall of the storage 

vessel by springs or weighted levers and is connected by braces to the floating roof. A flexible coated fabric 

(envelope) spans the annular space between the metal sheet and the floating roof.

(iii) Each opening in a noncontact internal floating roof except for automatic bleeder vents (vacuum breaker vents) 

and the rim space vents is to provide a projection below the liquid surface.

(iv) Each opening in the internal floating roof except for leg sleeves, automatic bleeder vents, rim space vents, 

column wells, ladder wells, sample wells, and stub drains is to be equipped with a cover or lid which is to be 

maintained in a closed position at all times (i.e., no visible gap) except when the device is in actual use. The cover or 

lid shall be equipped with a gasket. Covers on each access hatch and automatic gauge float well shall be bolted 

except when they are in use.

(v) Automatic bleeder vents shall be equipped with a gasket and are to be closed at all times when the roof is floating 

except when the roof is being floated off or is being landed on the roof leg supports.

(vi) Rim space vents shall be equipped with a gasket and are to be set to open only when the internal floating roof is 

not floating or at the manufacturer's recommended setting.

(vii) Each penetration of the internal floating roof for the purpose of sampling shall be a sample well. The sample well 

shall have a slit fabric cover that covers at least 90 percent of the opening.

(viii) Each penetration of the internal floating roof that allows for passage of a column supporting the fixed roof shall 

have a flexible fabric sleeve seal or a gasketed sliding cover.

(ix) Each penetration of the internal floating roof that allows for passage of a ladder shall have a gasketed sliding 

cover.

(2) An external floating roof. An external floating roof means a pontoon-type or double-deck type cover that rests on 

the liquid surface in a vessel with no fixed roof. Each external floating roof must meet the following specifications:

(i) Each external floating roof shall be equipped with a closure device between the wall of the storage vessel and the 

roof edge. The closure device is to consist of two seals, one above the other. The lower seal is referred to as the 

primary seal, and the upper seal is referred to as the secondary seal.
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(A) The primary seal shall be either a mechanical shoe seal or a liquid-mounted seal. Except as provided in 

§60.113b(b)(4), the seal shall completely cover the annular space between the edge of the floating roof and tank wall.

(B) The secondary seal shall completely cover the annular space between the external floating roof and the wall of 

the storage vessel in a continuous fashion except as allowed in §60.113b(b)(4).

(ii) Except for automatic bleeder vents and rim space vents, each opening in a noncontact external floating roof shall 

provide a projection below the liquid surface. Except for automatic bleeder vents, rim space vents, roof drains, and 

leg sleeves, each opening in the roof is to be equipped with a gasketed cover, seal, or lid that is to be maintained in a 

closed position at all times (i.e., no visible gap) except when the device is in actual use. Automatic bleeder vents are 

to be closed at all times when the roof is floating except when the roof is being floated off or is being landed on the 

roof leg supports. Rim vents are to be set to open when the roof is being floated off the roof legs supports or at the 

manufacturer's recommended setting. Automatic bleeder vents and rim space vents are to be gasketed. Each 

emergency roof drain is to be provided with a slotted membrane fabric cover that covers at least 90 percent of the 

area of the opening.

(iii) The roof shall be floating on the liquid at all times (i.e., off the roof leg supports) except during initial fill until the 

roof is lifted off leg supports and when the tank is completely emptied and subsequently refilled. The process of filling, 

emptying, or refilling when the roof is resting on the leg supports shall be continuous and shall be accomplished as 

rapidly as possible.

(3) A closed vent system and control device meeting the following specifications:

(i) The closed vent system shall be designed to collect all VOC vapors and gases discharged from the storage vessel 

and operated with no detectable emissions as indicated by an instrument reading of less than 500 ppm above 

background and visual inspections, as determined in part 60, subpart VV, §60.485(b).

(ii) The control device shall be designed and operated to reduce inlet VOC emissions by 95 percent or greater. If a 

flare is used as the control device, it shall meet the specifications described in the general control device 

requirements (§60.18) of the General Provisions.

(4) A system equivalent to those described in paragraphs (a)(1), (a)(2), or (a)(3) of this section as provided in 

§60.114b of this subpart.

(b) The owner or operator of each storage vessel with a design capacity greater than or equal to 75 m3 which 

contains a VOL that, as stored, has a maximum true vapor pressure greater than or equal to 76.6 kPa shall equip 

each storage vessel with one of the following:

(1) A closed vent system and control device as specified in §60.112b(a)(3).

(2) A system equivalent to that described in paragraph (b)(1) as provided in §60.114b of this subpart.

(c) Site-specific standard for Merck & Co., Inc.'s Stonewall Plant in Elkton, Virginia. This paragraph applies only to the 

pharmaceutical manufacturing facility, commonly referred to as the Stonewall Plant, located at Route 340 South, in 

Elkton, Virginia (“site”).

(1) For any storage vessel that otherwise would be subject to the control technology requirements of paragraphs (a) 

or (b) of this section, the site shall have the option of either complying directly with the requirements of this subpart, or

reducing the site-wide total criteria pollutant emissions cap (total emissions cap) in accordance with the procedures 

set forth in a permit issued pursuant to 40 CFR 52.2454. If the site chooses the option of reducing the total emissions 

cap in accordance with the procedures set forth in such permit, the requirements of such permit shall apply in lieu of 

the otherwise applicable requirements of this subpart for such storage vessel.

(2) For any storage vessel at the site not subject to the requirements of 40 CFR 60.112b (a) or (b), the requirements 

of 40 CFR 60.116b (b) and (c) and the General Provisions (subpart A of this part) shall not apply.

[52 FR 11429, Apr. 8, 1987, as amended at 62 FR 52641, Oct. 8, 1997]
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§ 60.113b Testing and procedures.

The owner or operator of each storage vessel as specified in §60.112b(a) shall meet the requirements of paragraph 

(a), (b), or (c) of this section. The applicable paragraph for a particular storage vessel depends on the control 

equipment installed to meet the requirements of §60.112b.

(a) After installing the control equipment required to meet §60.112b(a)(1) (permanently affixed roof and internal 

floating roof), each owner or operator shall:

(1) Visually inspect the internal floating roof, the primary seal, and the secondary seal (if one is in service), prior to 

filling the storage vessel with VOL. If there are holes, tears, or other openings in the primary seal, the secondary seal, 

or the seal fabric or defects in the internal floating roof, or both, the owner or operator shall repair the items before 

filling the storage vessel.

(2) For Vessels equipped with a liquid-mounted or mechanical shoe primary seal, visually inspect the internal floating 

roof and the primary seal or the secondary seal (if one is in service) through manholes and roof hatches on the fixed 

roof at least once every 12 months after initial fill. If the internal floating roof is not resting on the surface of the VOL 

inside the storage vessel, or there is liquid accumulated on the roof, or the seal is detached, or there are holes or 

tears in the seal fabric, the owner or operator shall repair the items or empty and remove the storage vessel from 

service within 45 days. If a failure that is detected during inspections required in this paragraph cannot be repaired 

within 45 days and if the vessel cannot be emptied within 45 days, a 30-day extension may be requested from the 

Administrator in the inspection report required in §60.115b(a)(3). Such a request for an extension must document that 

alternate storage capacity is unavailable and specify a schedule of actions the company will take that will assure that 

the control equipment will be repaired or the vessel will be emptied as soon as possible.

(3) For vessels equipped with a double-seal system as specified in §60.112b(a)(1)(ii)(B):

(i) Visually inspect the vessel as specified in paragraph (a)(4) of this section at least every 5 years; or

(ii) Visually inspect the vessel as specified in paragraph (a)(2) of this section.

(4) Visually inspect the internal floating roof, the primary seal, the secondary seal (if one is in service), gaskets, 

slotted membranes and sleeve seals (if any) each time the storage vessel is emptied and degassed. If the internal 

floating roof has defects, the primary seal has holes, tears, or other openings in the seal or the seal fabric, or the 

secondary seal has holes, tears, or other openings in the seal or the seal fabric, or the gaskets no longer close off the 

liquid surfaces from the atmosphere, or the slotted membrane has more than 10 percent open area, the owner or 

operator shall repair the items as necessary so that none of the conditions specified in this paragraph exist before 

refilling the storage vessel with VOL. In no event shall inspections conducted in accordance with this provision occur 

at intervals greater than 10 years in the case of vessels conducting the annual visual inspection as specified in 

paragraphs (a)(2) and (a)(3)(ii) of this section and at intervals no greater than 5 years in the case of vessels specified 

in paragraph (a)(3)(i) of this section.

(5) Notify the Administrator in writing at least 30 days prior to the filling or refilling of each storage vessel for which an 

inspection is required by paragraphs (a)(1) and (a)(4) of this section to afford the Administrator the opportunity to 

have an observer present. If the inspection required by paragraph (a)(4) of this section is not planned and the owner 

or operator could not have known about the inspection 30 days in advance or refilling the tank, the owner or operator 

shall notify the Administrator at least 7 days prior to the refilling of the storage vessel. Notification shall be made by 

telephone immediately followed by written documentation demonstrating why the inspection was unplanned. 

Alternatively, this notification including the written documentation may be made in writing and sent by express mail so 

that it is received by the Administrator at least 7 days prior to the refilling.

(b) After installing the control equipment required to meet §60.112b(a)(2) (external floating roof), the owner or 

operator shall:

(1) Determine the gap areas and maximum gap widths, between the primary seal and the wall of the storage vessel 

and between the secondary seal and the wall of the storage vessel according to the following frequency.
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(i) Measurements of gaps between the tank wall and the primary seal (seal gaps) shall be performed during the 

hydrostatic testing of the vessel or within 60 days of the initial fill with VOL and at least once every 5 years thereafter.

(ii) Measurements of gaps between the tank wall and the secondary seal shall be performed within 60 days of the 

initial fill with VOL and at least once per year thereafter.

(iii) If any source ceases to store VOL for a period of 1 year or more, subsequent introduction of VOL into the vessel 

shall be considered an initial fill for the purposes of paragraphs (b)(1)(i) and (b)(1)(ii) of this section.

(2) Determine gap widths and areas in the primary and secondary seals individually by the following procedures:

(i) Measure seal gaps, if any, at one or more floating roof levels when the roof is floating off the roof leg supports.

(ii) Measure seal gaps around the entire circumference of the tank in each place where a 0.32-cm diameter uniform 

probe passes freely (without forcing or binding against seal) between the seal and the wall of the storage vessel and 

measure the circumferential distance of each such location.

(iii) The total surface area of each gap described in paragraph (b)(2)(ii) of this section shall be determined by using 

probes of various widths to measure accurately the actual distance from the tank wall to the seal and multiplying each 

such width by its respective circumferential distance.

(3) Add the gap surface area of each gap location for the primary seal and the secondary seal individually and divide 

the sum for each seal by the nominal diameter of the tank and compare each ratio to the respective standards in 

paragraph (b)(4) of this section.

(4) Make necessary repairs or empty the storage vessel within 45 days of identification in any inspection for seals not 

meeting the requirements listed in (b)(4) (i) and (ii) of this section:

(i) The accumulated area of gaps between the tank wall and the mechanical shoe or liquid-mounted primary seal 

shall not exceed 212 Cm2 per meter of tank diameter, and the width of any portion of any gap shall not exceed 3.81 

cm.

(A) One end of the mechanical shoe is to extend into the stored liquid, and the other end is to extend a minimum 

vertical distance of 61 cm above the stored liquid surface.

(B) There are to be no holes, tears, or other openings in the shoe, seal fabric, or seal envelope.

(ii) The secondary seal is to meet the following requirements:

(A) The secondary seal is to be installed above the primary seal so that it completely covers the space between the 

roof edge and the tank wall except as provided in paragraph (b)(2)(iii) of this section.

(B) The accumulated area of gaps between the tank wall and the secondary seal shall not exceed 21.2 cm2 per meter 

of tank diameter, and the width of any portion of any gap shall not exceed 1.27 cm.

(C) There are to be no holes, tears, or other openings in the seal or seal fabric.

(iii) If a failure that is detected during inspections required in paragraph (b)(1) of §60.113b(b) cannot be repaired 

within 45 days and if the vessel cannot be emptied within 45 days, a 30-day extension may be requested from the 

Administrator in the inspection report required in §60.115b(b)(4). Such extension request must include a 

demonstration of unavailability of alternate storage capacity and a specification of a schedule that will assure that the 

control equipment will be repaired or the vessel will be emptied as soon as possible.

(5) Notify the Administrator 30 days in advance of any gap measurements required by paragraph (b)(1) of this section 

to afford the Administrator the opportunity to have an observer present.
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(6) Visually inspect the external floating roof, the primary seal, secondary seal, and fittings each time the vessel is 

emptied and degassed.

(i) If the external floating roof has defects, the primary seal has holes, tears, or other openings in the seal or the seal 

fabric, or the secondary seal has holes, tears, or other openings in the seal or the seal fabric, the owner or operator 

shall repair the items as necessary so that none of the conditions specified in this paragraph exist before filling or 

refilling the storage vessel with VOL.

(ii) For all the inspections required by paragraph (b)(6) of this section, the owner or operator shall notify the 

Administrator in writing at least 30 days prior to the filling or refilling of each storage vessel to afford the Administrator 

the opportunity to inspect the storage vessel prior to refilling. If the inspection required by paragraph (b)(6) of this 

section is not planned and the owner or operator could not have known about the inspection 30 days in advance of 

refilling the tank, the owner or operator shall notify the Administrator at least 7 days prior to the refilling of the storage 

vessel. Notification shall be made by telephone immediately followed by written documentation demonstrating why 

the inspection was unplanned. Alternatively, this notification including the written documentation may be made in 

writing and sent by express mail so that it is received by the Administrator at least 7 days prior to the refilling.

(c) The owner or operator of each source that is equipped with a closed vent system and control device as required in 

§60.112b (a)(3) or (b)(2) (other than a flare) is exempt from §60.8 of the General Provisions and shall meet the 

following requirements.

(1) Submit for approval by the Administrator as an attachment to the notification required by §60.7(a)(1) or, if the 

facility is exempt from §60.7(a)(1), as an attachment to the notification required by §60.7(a)(2), an operating plan 

containing the information listed below.

(i) Documentation demonstrating that the control device will achieve the required control efficiency during maximum 

loading conditions. This documentation is to include a description of the gas stream which enters the control device, 

including flow and VOC content under varying liquid level conditions (dynamic and static) and manufacturer's design 

specifications for the control device. If the control device or the closed vent capture system receives vapors, gases, or 

liquids other than fuels from sources that are not designated sources under this subpart, the efficiency demonstration 

is to include consideration of all vapors, gases, and liquids received by the closed vent capture system and control 

device. If an enclosed combustion device with a minimum residence time of 0.75 seconds and a minimum 

temperature of 816 °C is used to meet the 95 percent requirement, documentation that those conditions will exist is 

sufficient to meet the requirements of this paragraph.

(ii) A description of the parameter or parameters to be monitored to ensure that the control device will be operated in 

conformance with its design and an explanation of the criteria used for selection of that parameter (or parameters).

(2) Operate the closed vent system and control device and monitor the parameters of the closed vent system and 

control device in accordance with the operating plan submitted to the Administrator in accordance with paragraph 

(c)(1) of this section, unless the plan was modified by the Administrator during the review process. In this case, the 

modified plan applies.

(d) The owner or operator of each source that is equipped with a closed vent system and a flare to meet the 

requirements in §60.112b (a)(3) or (b)(2) shall meet the requirements as specified in the general control device 

requirements, §60.18 (e) and (f).

[52 FR 11429, Apr. 8, 1987, as amended at 54 FR 32973, Aug. 11, 1989]

§ 60.114b Alternative means of emission limitation.

(a) If, in the Administrator's judgment, an alternative means of emission limitation will achieve a reduction in 

emissions at least equivalent to the reduction in emissions achieved by any requirement in §60.112b, the 

Administrator will publish in the Federal Register a notice permitting the use of the alternative means for purposes of 

compliance with that requirement.

(b) Any notice under paragraph (a) of this section will be published only after notice and an opportunity for a hearing.
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(c) Any person seeking permission under this section shall submit to the Administrator a written application including:

(1) An actual emissions test that uses a full-sized or scale-model storage vessel that accurately collects and 

measures all VOC emissions from a given control device and that accurately simulates wind and accounts for other 

emission variables such as temperature and barometric pressure.

(2) An engineering evaluation that the Administrator determines is an accurate method of determining equivalence.

(d) The Administrator may condition the permission on requirements that may be necessary to ensure operation and 

maintenance to achieve the same emissions reduction as specified in §60.112b.

§ 60.115b Reporting and recordkeeping requirements.

The owner or operator of each storage vessel as specified in §60.112b(a) shall keep records and furnish reports as 

required by paragraphs (a), (b), or (c) of this section depending upon the control equipment installed to meet the 

requirements of §60.112b. The owner or operator shall keep copies of all reports and records required by this section, 

except for the record required by (c)(1), for at least 2 years. The record required by (c)(1) will be kept for the life of the 

control equipment.

(a) After installing control equipment in accordance with §60.112b(a)(1) (fixed roof and internal floating roof), the 

owner or operator shall meet the following requirements.

(1) Furnish the Administrator with a report that describes the control equipment and certifies that the control 

equipment meets the specifications of §60.112b(a)(1) and §60.113b(a)(1). This report shall be an attachment to the 

notification required by §60.7(a)(3).

(2) Keep a record of each inspection performed as required by §60.113b (a)(1), (a)(2), (a)(3), and (a)(4). Each record 

shall identify the storage vessel on which the inspection was performed and shall contain the date the vessel was 

inspected and the observed condition of each component of the control equipment (seals, internal floating roof, and 

fittings).

(3) If any of the conditions described in §60.113b(a)(2) are detected during the annual visual inspection required by 

§60.113b(a)(2), a report shall be furnished to the Administrator within 30 days of the inspection. Each report shall 

identify the storage vessel, the nature of the defects, and the date the storage vessel was emptied or the nature of 

and date the repair was made.

(4) After each inspection required by §60.113b(a)(3) that finds holes or tears in the seal or seal fabric, or defects in 

the internal floating roof, or other control equipment defects listed in §60.113b(a)(3)(ii), a report shall be furnished to 

the Administrator within 30 days of the inspection. The report shall identify the storage vessel and the reason it did 

not meet the specifications of §61.112b(a)(1) or §60.113b(a)(3) and list each repair made.

(b) After installing control equipment in accordance with §61.112b(a)(2) (external floating roof), the owner or operator 

shall meet the following requirements.

(1) Furnish the Administrator with a report that describes the control equipment and certifies that the control 

equipment meets the specifications of §60.112b(a)(2) and §60.113b(b)(2), (b)(3), and (b)(4). This report shall be an 

attachment to the notification required by §60.7(a)(3).

(2) Within 60 days of performing the seal gap measurements required by §60.113b(b)(1), furnish the Administrator 

with a report that contains:

(i) The date of measurement.

(ii) The raw data obtained in the measurement.

(iii) The calculations described in §60.113b (b)(2) and (b)(3).
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(3) Keep a record of each gap measurement performed as required by §60.113b(b). Each record shall identify the 

storage vessel in which the measurement was performed and shall contain:

(i) The date of measurement.

(ii) The raw data obtained in the measurement.

(iii) The calculations described in §60.113b (b)(2) and (b)(3).

(4) After each seal gap measurement that detects gaps exceeding the limitations specified by §60.113b(b)(4), submit 

a report to the Administrator within 30 days of the inspection. The report will identify the vessel and contain the 

information specified in paragraph (b)(2) of this section and the date the vessel was emptied or the repairs made and 

date of repair.

(c) After installing control equipment in accordance with §60.112b (a)(3) or (b)(1) (closed vent system and control 

device other than a flare), the owner or operator shall keep the following records.

(1) A copy of the operating plan.

(2) A record of the measured values of the parameters monitored in accordance with §60.113b(c)(2).

(d) After installing a closed vent system and flare to comply with §60.112b, the owner or operator shall meet the 

following requirements.

(1) A report containing the measurements required by §60.18(f) (1), (2), (3), (4), (5), and (6) shall be furnished to the 

Administrator as required by §60.8 of the General Provisions. This report shall be submitted within 6 months of the 

initial start-up date.

(2) Records shall be kept of all periods of operation during which the flare pilot flame is absent.

(3) Semiannual reports of all periods recorded under §60.115b(d)(2) in which the pilot flame was absent shall be 

furnished to the Administrator.

§ 60.116b Monitoring of operations.

(a) The owner or operator shall keep copies of all records required by this section, except for the record required by 

paragraph (b) of this section, for at least 2 years. The record required by paragraph (b) of this section will be kept for 

the life of the source.

(b) The owner or operator of each storage vessel as specified in §60.110b(a) shall keep readily accessible records 

showing the dimension of the storage vessel and an analysis showing the capacity of the storage vessel.

(c) Except as provided in paragraphs (f) and (g) of this section, the owner or operator of each storage vessel either 

with a design capacity greater than or equal to 151 m3 storing a liquid with a maximum true vapor pressure greater 

than or equal to 3.5 kPa or with a design capacity greater than or equal to 75 m3 but less than 151 m3 storing a liquid 

with a maximum true vapor pressure greater than or equal to 15.0 kPa shall maintain a record of the VOL stored, the 

period of storage, and the maximum true vapor pressure of that VOL during the respective storage period.

(d) Except as provided in paragraph (g) of this section, the owner or operator of each storage vessel either with a 

design capacity greater than or equal to 151 m3 storing a liquid with a maximum true vapor pressure that is normally 

less than 5.2 kPa or with a design capacity greater than or equal to 75 m3 but less than 151 m3 storing a liquid with a 

maximum true vapor pressure that is normally less than 27.6 kPa shall notify the Administrator within 30 days when 

the maximum true vapor pressure of the liquid exceeds the respective maximum true vapor vapor pressure values for 

each volume range.
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(e) Available data on the storage temperature may be used to determine the maximum true vapor pressure as 

determined below.

(1) For vessels operated above or below ambient temperatures, the maximum true vapor pressure is calculated 

based upon the highest expected calendar-month average of the storage temperature. For vessels operated at 

ambient temperatures, the maximum true vapor pressure is calculated based upon the maximum local monthly 

average ambient temperature as reported by the National Weather Service.

(2) For crude oil or refined petroleum products the vapor pressure may be obtained by the following:

(i) Available data on the Reid vapor pressure and the maximum expected storage temperature based on the highest 

expected calendar-month average temperature of the stored product may be used to determine the maximum true 

vapor pressure from nomographs contained in API Bulletin 2517 (incorporated by reference—see §60.17), unless the 

Administrator specifically requests that the liquid be sampled, the actual storage temperature determined, and the 

Reid vapor pressure determined from the sample(s).

(ii) The true vapor pressure of each type of crude oil with a Reid vapor pressure less than 13.8 kPa or with physical 

properties that preclude determination by the recommended method is to be determined from available data and 

recorded if the estimated maximum true vapor pressure is greater than 3.5 kPa.

(3) For other liquids, the vapor pressure:

(i) May be obtained from standard reference texts, or

(ii) Determined by ASTM D2879–83, 96, or 97 (incorporated by reference—see §60.17); or

(iii) Measured by an appropriate method approved by the Administrator; or

(iv) Calculated by an appropriate method approved by the Administrator.

(f) The owner or operator of each vessel storing a waste mixture of indeterminate or variable composition shall be 

subject to the following requirements.

(1) Prior to the initial filling of the vessel, the highest maximum true vapor pressure for the range of anticipated liquid 

compositions to be stored will be determined using the methods described in paragraph (e) of this section.

(2) For vessels in which the vapor pressure of the anticipated liquid composition is above the cutoff for monitoring but 

below the cutoff for controls as defined in §60.112b(a), an initial physical test of the vapor pressure is required; and a 

physical test at least once every 6 months thereafter is required as determined by the following methods:

(i) ASTM D2879–83, 96, or 97 (incorporated by reference—see §60.17); or

(ii) ASTM D323–82 or 94 (incorporated by reference—see §60.17); or

(iii) As measured by an appropriate method as approved by the Administrator.

(g) The owner or operator of each vessel equipped with a closed vent system and control device meeting the 

specification of §60.112b or with emissions reductions equipment as specified in 40 CFR 65.42(b)(4), (b)(5), (b)(6), or 

(c) is exempt from the requirements of paragraphs (c) and (d) of this section.

[52 FR 11429, Apr. 8, 1987, as amended at 65 FR 61756, Oct. 17, 2000; 65 FR 78276, Dec. 14, 2000; 68 FR 59333, 

Oct. 15, 2003]

§ 60.117b Delegation of authority.
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(a) In delegating implementation and enforcement authority to a State under section 111(c) of the Act, the authorities 

contained in paragraph (b) of this section shall be retained by the Administrator and not transferred to a State.

(b) Authorities which will not be delegated to States: §§60.111b(f)(4), 60.114b, 60.116b(e)(3)(iii), 60.116b(e)(3)(iv), 

and 60.116b(f)(2)(iii).

[52 FR 11429, Apr. 8, 1987, as amended at 52 FR 22780, June 16, 1987]
Attachment E to a PSD/Part 70 Operating Permit

Subpart IIII—Standards of Performance for Stationary Compression 

Ignition Internal Combustion Engines [40 CFR Part 60, Subpart IIII] 

[326 IAC 12]

Source Name: Indiana Gasification LLC

Source Location: CR 200 N and Base Road, Rockport, IN 47635

County: Spencer

SIC Code: 4925, 2819

Operation Permit No.: T 147-30464-00060

Operation Permit Issuance Date: Yet to be Issued

Permit Reviewer: Josiah Balogun

Subpart IIII—Standards of Performance for Stationary Compression 

Ignition Internal Combustion Engines

Source: 71 FR 39172, July 11, 2006, unless otherwise noted.

What This Subpart Covers

§ 60.4200 Am I subject to this subpart?

(a) The provisions of this subpart are applicable to manufacturers, owners, and operators of stationary compression 

ignition (CI) internal combustion engines (ICE) and other persons as specified in paragraphs (a)(1) through (4) of this 

section. For the purposes of this subpart, the date that construction commences is the date the engine is ordered by 

the owner or operator.

(1) Manufacturers of stationary CI ICE with a displacement of less than 30 liters per cylinder where the model year is:

(i) 2007 or later, for engines that are not fire pump engines;

(ii) The model year listed in Table 3 to this subpart or later model year, for fire pump engines.

(2) Owners and operators of stationary CI ICE that commence construction after July 11, 2005, where the stationary 

CI ICE are:

(i) Manufactured after April 1, 2006, and are not fire pump engines, or

(ii) Manufactured as a certified National Fire Protection Association (NFPA) fire pump engine after July 1, 2006.

(3) Owners and operators of any stationary CI ICE that are modified or reconstructed after July 11, 2005 and any 

person that modifies or reconstructs any stationary CI ICE after July 11, 2005.

(4) The provisions of §60.4208 of this subpart are applicable to all owners and operators of stationary CI ICE that 

commence construction 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.
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(c) If you are an owner or operator of an area source subject to this subpart, you are exempt from the obligation to 

obtain a permit under 40 CFR part 70 or 40 CFR part 71, provided you are not required to obtain a permit under 40 

CFR 70.3(a) or 40 CFR 71.3(a) for a reason other than your status as an area source under this subpart. 

Notwithstanding the previous sentence, you must continue to comply with the provisions of this subpart applicable to 

area sources.

(d) Stationary CI ICE may be eligible for exemption from the requirements of this subpart as described in 40 CFR part 

1068, subpart C (or the exemptions described in 40 CFR part 89, subpart J and 40 CFR part 94, subpart J, for 

engines that would need to be certified to standards in those parts), except that owners and operators, as well as 

manufacturers, may be eligible to request an exemption for national security.

(e) Owners and operators of facilities with CI ICE that are acting as temporary replacement units and that are located 

at a stationary source for less than 1 year and that have been properly certified as meeting the standards that would 

be applicable to such engine under the appropriate nonroad engine provisions, are not required to meet any other 

provisions under this subpart with regard to such engines.

[71 FR 39172, July 11, 2006, as amended at 76 FR 37967, June 28, 2011]

Emission Standards for Manufacturers

§ 60.4201 What emission standards must I meet for non-emergency 

engines if I am a stationary CI internal combustion engine manufacturer?

(a) Stationary CI internal combustion engine manufacturers must certify their 2007 model year and later nonemergency stationary CI ICE with a maximum engine power less than or equal to 2,237 kilowatt (KW) (3,000 

horsepower (HP)) and a displacement of less than 10 liters per cylinder to the certification emission standards for 

new nonroad CI engines in 40 CFR 89.112, 40 CFR 89.113, 40 CFR 1039.101, 40 CFR 1039.102, 40 CFR 1039.104, 

40 CFR 1039.105, 40 CFR 1039.107, and 40 CFR 1039.115, as applicable, for all pollutants, for the same model 

year and maximum engine power.

(b) Stationary CI internal combustion engine manufacturers must certify their 2007 through 2010 model year nonemergency stationary CI ICE with a maximum engine power greater than 2,237 KW (3,000 HP) and a displacement 

of less than 10 liters per cylinder to the emission standards in table 1 to this subpart, for all pollutants, for the same 

maximum engine power.

(c) Stationary CI internal combustion engine manufacturers must certify their 2011 model year and later nonemergency stationary CI ICE with a maximum engine power greater than 2,237 KW (3,000 HP) and a displacement 

of less than 10 liters per cylinder to the certification emission standards for new nonroad CI engines in 40 CFR 

1039.101, 40 CFR 1039.102, 40 CFR 1039.104, 40 CFR 1039.105, 40 CFR 1039.107, and 40 CFR 1039.115, as 

applicable, for all pollutants, for the same maximum engine power.

(d) Stationary CI internal combustion engine manufacturers must certify the following non-emergency stationary CI 

ICE 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:

(1) Their 2007 model year through 2012 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;

(2) Their 2013 model year non-emergency stationary CI ICE with a maximum engine power greater than or equal to 

3,700 KW (4,958 HP) and a displacement of greater than or equal to 10 liters per cylinder and less than 15 liters per 

cylinder; and

(3) Their 2013 model year non-emergency stationary CI ICE with a displacement of greater than or equal to 15 liters 

per cylinder and less than 30 liters per cylinder.
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(e) Stationary CI internal combustion engine manufacturers must certify the following non-emergency stationary CI 

ICE to the certification emission standards and other requirements for new marine CI engines in 40 CFR 1042.101, 

40 CFR 1042.107, 40 CFR 1042.110, 40 CFR 1042.115, 40 CFR 1042.120, and 40 CFR 1042.145, as applicable, for 

all pollutants, for the same displacement and maximum engine power:

(1) Their 2013 model year non-emergency stationary CI ICE with a maximum engine power less than 3,700 KW 

(4,958 HP) and a displacement of greater than or equal to 10 liters per cylinder and less than 15 liters per cylinder; 

and

(2) Their 2014 model year and later 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.

(f) Notwithstanding the requirements in paragraphs (a) through (c) of this section, stationary non-emergency CI ICE 

identified in paragraphs (a) and (c) may be certified to the provisions of 40 CFR part 94 or, if Table 1 to 40 CFR 

1042.1 identifies 40 CFR part 1042 as being applicable, 40 CFR part 1042, if the engines will be used solely in either 

or both of the following locations:

(1) Areas of Alaska not accessible by the Federal Aid Highway System (FAHS); and

(2) Marine offshore installations.

(g) Notwithstanding the requirements in paragraphs (a) through (f) of this section, stationary CI internal combustion 

engine manufacturers are not required to certify reconstructed engines; however manufacturers may elect to do so. 

The reconstructed engine must be certified to the emission standards specified in paragraphs (a) through (e) of this 

section that are applicable to the model year, maximum engine power, and displacement of the reconstructed 

stationary CI ICE.

[71 FR 39172, July 11, 2006, as amended at 76 FR 37967, June 28, 2011]

§ 60.4202 What emission standards must I meet for emergency engines if I 

am a stationary CI internal combustion engine manufacturer?

(a) Stationary CI internal combustion engine manufacturers must certify their 2007 model year and later emergency 

stationary CI ICE with a maximum engine power less than or equal to 2,237 KW (3,000 HP) and a displacement of 

less than 10 liters per cylinder that are not fire pump engines to the emission standards specified in paragraphs (a)(1) 

through (2) of this section.

(1) For engines with a maximum engine power less than 37 KW (50 HP):

(i) The certification emission standards for new nonroad CI engines for the same model year and maximum engine 

power in 40 CFR 89.112 and 40 CFR 89.113 for all pollutants for model year 2007 engines, and

(ii) The certification emission standards for new nonroad CI engines in 40 CFR 1039.104, 40 CFR 1039.105, 40 CFR 

1039.107, 40 CFR 1039.115, and table 2 to this subpart, for 2008 model year and later engines.

(2) For engines with a maximum engine power greater than or equal to 37 KW (50 HP), the certification emission 

standards for new nonroad CI engines for the same model year and maximum engine power in 40 CFR 89.112 and 

40 CFR 89.113 for all pollutants beginning in model year 2007.

(b) Stationary CI internal combustion engine manufacturers must certify their 2007 model year and later emergency 

stationary CI ICE with a maximum engine power greater than 2,237 KW (3,000 HP) and a displacement of less than 

10 liters per cylinder that are not fire pump engines to the emission standards specified in paragraphs (b)(1) through 

(2) of this section.

(1) For 2007 through 2010 model years, the emission standards in table 1 to this subpart, for all pollutants, for the 

same maximum engine power.
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(2) For 2011 model year and later, the certification emission standards for new nonroad CI engines for engines of the 

same model year and maximum engine power in 40 CFR 89.112 and 40 CFR 89.113 for all pollutants.

(c) [Reserved]

(d) Beginning with the model years in table 3 to this subpart, stationary CI internal combustion engine manufacturers 

must certify their fire pump stationary CI ICE to the emission standards in table 4 to this subpart, for all pollutants, for 

the same model year and NFPA nameplate power.

(e) Stationary CI internal combustion engine manufacturers must certify the following emergency stationary CI ICE 

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:

(1) Their 2007 model year through 2012 emergency stationary CI ICE with a displacement of greater than or equal to 

10 liters per cylinder and less than 30 liters per cylinder;

(2) Their 2013 model year and later emergency stationary CI ICE with a maximum engine power greater than or 

equal to 3,700 KW (4,958 HP) and a displacement of greater than or equal to 10 liters per cylinder and less than 15 

liters per cylinder;

(3) Their 2013 model year emergency stationary CI ICE with a displacement of greater than or equal to 15 liters per 

cylinder and less than 30 liters per cylinder; and

(4) Their 2014 model year and later emergency stationary CI ICE with a maximum engine power greater than or 

equal to 2,000 KW (2,682 HP) and a displacement of greater than or equal to 15 liters per cylinder and less than 30 

liters per cylinder.

(f) Stationary CI internal combustion engine manufacturers must certify the following emergency stationary CI ICE to 

the certification emission standards and other requirements applicable to Tier 3 new marine CI engines in 40 CFR 

1042.101, 40 CFR 1042.107, 40 CFR 1042.115, 40 CFR 1042.120, and 40 CFR 1042.145, for all pollutants, for the 

same displacement and maximum engine power:

(1) Their 2013 model year and later emergency stationary CI ICE with a maximum engine power less than 3,700 KW 

(4,958 HP) and a displacement of greater than or equal to 10 liters per cylinder and less than 15 liters per cylinder; 

and

(2) Their 2014 model year and later emergency stationary CI ICE with a maximum engine power less than 2,000 KW 

(2,682 HP) and a displacement of greater than or equal to 15 liters per cylinder and less than 30 liters per cylinder.

(g) Notwithstanding the requirements in paragraphs (a) through (d) of this section, stationary emergency CI internal 

combustion engines identified in paragraphs (a) and (c) may be certified to the provisions of 40 CFR part 94 or, if 

Table 2 to 40 CFR 1042.101 identifies Tier 3 standards as being applicable, the requirements applicable to Tier 3 

engines in 40 CFR part 1042, if the engines will be used solely in either or both of the following locations:

(1) Areas of Alaska not accessible by the FAHS; and

(2) Marine offshore installations.

(h) Notwithstanding the requirements in paragraphs (a) through (f) of this section, stationary CI internal combustion 

engine manufacturers are not required to certify reconstructed engines; however manufacturers may elect to do so. 

The reconstructed engine must be certified to the emission standards specified in paragraphs (a) through (f) of this 

section that are applicable to the model year, maximum engine power and displacement of the reconstructed 

emergency stationary CI ICE.

[71 FR 39172, July 11, 2006, as amended at 76 FR 37968, June 28, 2011]
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§ 60.4203 How long must my engines meet the emission standards if I am 

a manufacturer of stationary CI internal combustion engines?

Engines manufactured by stationary CI internal combustion engine manufacturers must meet the emission standards 

as required in §§60.4201 and 60.4202 during the certified emissions life of the engines.

[76 FR 37968, June 28, 2011]

Emission Standards for Owners and Operators

§ 60.4204 What emission standards must I meet for non-emergency 

engines if I am an owner or operator of a stationary CI internal combustion 

engine?

(a) Owners and operators of pre-2007 model year non-emergency stationary CI ICE with a displacement of less than 

10 liters per cylinder must comply with the emission standards in table 1 to this subpart. Owners and operators of pre2007 model year non-emergency stationary CI ICE with a displacement of greater than or equal to 10 liters per 

cylinder and less than 30 liters per cylinder must comply with the emission standards in 40 CFR 94.8(a)(1).

(b) Owners and operators of 2007 model year and later non-emergency stationary CI ICE with a displacement of less 

than 30 liters per cylinder must comply with the emission standards for new CI engines in §60.4201 for their 2007 

model year and later stationary CI ICE, as applicable.

(c) Owners and operators of non-emergency stationary CI engines with a displacement of greater than or equal to 30 

liters per cylinder must meet the following requirements:

(1) For engines installed prior to January 1, 2012, limit the emissions of NOXin the stationary CI internal combustion 

engine exhaust to the following:

(i) 17.0 grams per kilowatt-hour (g/KW-hr) (12.7 grams per horsepower-hr (g/HP-hr)) when maximum engine speed is 

less than 130 revolutions per minute (rpm);

(ii) 45 · n−0.2g/KW-hr (34 · n−0.2g/HP-hr) when maximum engine speed is 130 or more but less than 2,000 rpm, where 

n is maximum engine speed; and

(iii) 9.8 g/KW-hr (7.3 g/HP-hr) when maximum engine speed is 2,000 rpm or more.

(2) For engines installed on or after January 1, 2012 and before January 1, 2016, limit the emissions of NOXin the 

stationary CI internal combustion engine exhaust to the following:

(i) 14.4 g/KW-hr (10.7 g/HP-hr) when maximum engine speed is less than 130 rpm;

(ii) 44 · n−0.23g/KW-hr (33 · n−0.23g/HP-hr) when maximum engine speed is greater than or equal to 130 but less than 

2,000 rpm and where n is maximum engine speed; and

(iii) 7.7 g/KW-hr (5.7 g/HP-hr) when maximum engine speed is greater than or equal to 2,000 rpm.

(3) For engines installed on or after January 1, 2016, limit the emissions of NOXin the stationary CI internal 

combustion engine exhaust to the following:

(i) 3.4 g/KW-hr (2.5 g/HP-hr) when maximum engine speed is less than 130 rpm;
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(ii) 9.0 · n−0.20g/KW-hr (6.7 · n−0.20g/HP-hr) where n (maximum engine speed) is 130 or more but less than 2,000 rpm; 

and

(iii) 2.0 g/KW-hr (1.5 g/HP-hr) where maximum engine speed is greater than or equal to 2,000 rpm.

(4) 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).

(d) Owners and operators of non-emergency stationary CI ICE with a displacement of less than 30 liters per cylinder 

who conduct performance tests in-use must meet the not-to-exceed (NTE) standards as indicated in §60.4212.

(e) Owners and operators of any modified or reconstructed non-emergency stationary CI ICE subject to this subpart 

must meet the emission standards applicable to the model year, maximum engine power, and displacement of the 

modified or reconstructed non-emergency stationary CI ICE that are specified in paragraphs (a) through (d) of this 

section.

[71 FR 39172, July 11, 2006, as amended at 76 FR 37968, June 28, 2011]

§ 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 emergency stationary CI ICE with a displacement of greater than or 

equal to 10 liters per cylinder and less than 30 liters per cylinder that are not fire pump engines must comply with the 

emission standards in 40 CFR 94.8(a)(1).

(b) Owners and operators of 2007 model year and later emergency stationary CI ICE with a displacement of less than 

30 liters per cylinder that are not fire pump engines must comply with the emission standards for new nonroad CI 

engines in §60.4202, for all pollutants, for the same model year and maximum engine power for their 2007 model 

year and later emergency stationary CI ICE.

(c) Owners and operators of fire pump engines with a displacement of less than 30 liters per cylinder must comply 

with the emission standards in table 4 to this subpart, for all pollutants.

(d) Owners and operators of emergency stationary CI engines with a displacement of greater than or equal to 30 

liters per cylinder must meet the requirements in this section.

(1) For engines installed prior to January 1, 2012, limit the emissions of NOXin the stationary CI internal combustion 

engine exhaust to the following:

(i) 17.0 g/KW-hr (12.7 g/HP-hr) when maximum engine speed is less than 130 rpm;

(ii) 45 · n−0.2g/KW-hr (34 · n−0.2g/HP-hr) when maximum engine speed is 130 or more but less than 2,000 rpm, where 

n is maximum engine speed; and

(iii) 9.8 g/kW-hr (7.3 g/HP-hr) when maximum engine speed is 2,000 rpm or more.

(2) For engines installed on or after January 1, 2012, limit the emissions of NOXin the stationary CI internal 

combustion engine exhaust to the following:

(i) 14.4 g/KW-hr (10.7 g/HP-hr) when maximum engine speed is less than 130 rpm;

(ii) 44 · n−0.23g/KW-hr (33 · n−0.23g/HP-hr) when maximum engine speed is greater than or equal to 130 but less than 

2,000 rpm and where n is maximum engine speed; and
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(iii) 7.7 g/KW-hr (5.7 g/HP-hr) when maximum engine speed is greater than or equal to 2,000 rpm.

(3) Limit the emissions of PM in the stationary CI internal combustion engine exhaust to 0.40 g/KW-hr (0.30 g/HP-hr).

(e) Owners and operators of emergency stationary CI ICE with a displacement of less than 30 liters per cylinder who 

conduct performance tests in-use must meet the NTE standards as indicated in §60.4212.

(f) Owners and operators of any modified or reconstructed emergency stationary CI ICE subject to this subpart must 

meet the emission standards applicable to the model year, maximum engine power, and displacement of the modified 

or reconstructed CI ICE that are specified in paragraphs (a) through (e) of this section.

[71 FR 39172, July 11, 2006, as amended at 76 FR 37969, June 28, 2011]

§ 60.4206 How long must I meet the emission standards if I am an owner 

or operator of a stationary CI internal combustion engine?

Owners and operators of stationary CI ICE must operate and maintain stationary CI ICE that achieve the emission 

standards as required in §§60.4204 and 60.4205 over the entire life of the engine.

[76 FR 37969, June 28, 2011]

Fuel Requirements for Owners and Operators

§ 60.4207 What fuel requirements must I meet if I am an owner or operator 

of a stationary CI internal combustion engine subject to this subpart?

(a) Beginning October 1, 2007, owners and operators of stationary CI ICE subject to this subpart that use diesel fuel 

must use diesel fuel that meets the requirements of 40 CFR 80.510(a).

(b) Beginning October 1, 2010, owners and operators of stationary CI ICE subject to this subpart with a displacement 

of less than 30 liters per cylinder that use diesel fuel must purchase diesel fuel that meets the requirements of 40 

CFR 80.510(b) for nonroad diesel fuel.

(c) [Reserved]

(d) Beginning June 1, 2012, owners and operators of stationary CI ICE subject to this subpart with a displacement of 

greater than or equal to 30 liters per cylinder are no longer subject to the requirements of paragraph (a) of this 

section, and must use fuel that meets a maximum per-gallon sulfur content of 1,000 parts per million (ppm).

(e) Stationary CI ICE that have a national security exemption under §60.4200(d) are also exempt from the fuel 

requirements in this section.

[71 FR 39172, July 11, 2006, as amended at 76 FR 37969, June 28, 2011]

Other Requirements for Owners and Operators

§ 60.4208 What is the deadline for importing or installing stationary CI ICE 

produced in previous model years?

(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.
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(b) After December 31, 2009, owners and operators may not install stationary CI ICE with a maximum engine power 

of less than 19 KW (25 HP) (excluding fire pump engines) that do not meet the applicable requirements for 2008 

model year engines.

(c) After December 31, 2014, owners and operators may not install non-emergency stationary CI ICE with a 

maximum engine power of greater than or equal to 19 KW (25 HP) and less than 56 KW (75 HP) that do not meet the 

applicable requirements for 2013 model year non-emergency engines.

(d) After December 31, 2013, owners and operators may not install non-emergency stationary CI ICE with a 

maximum engine power of greater than or equal to 56 KW (75 HP) and less than 130 KW (175 HP) that do not meet 

the applicable requirements for 2012 model year non-emergency engines.

(e) After December 31, 2012, owners and operators may not install non-emergency stationary CI ICE with a 

maximum engine power of greater than or equal to 130 KW (175 HP), including those above 560 KW (750 HP), that 

do not meet the applicable requirements for 2011 model year non-emergency engines.

(f) After December 31, 2016, owners and operators may not install non-emergency stationary CI ICE with a maximum 

engine power of greater than or equal to 560 KW (750 HP) that do not meet the applicable requirements for 2015 

model year non-emergency engines.

(g) After December 31, 2018, owners and operators may not install non-emergency stationary CI ICE with a 

maximum engine power greater than or equal to 600 KW (804 HP) and less than 2,000 KW (2,680 HP) and a 

displacement of greater than or equal to 10 liters per cylinder and less than 30 liters per cylinder that do not meet the 

applicable requirements for 2017 model year non-emergency engines.

(h) In addition to the requirements specified in §§60.4201, 60.4202, 60.4204, and 60.4205, it is prohibited to import 

stationary CI ICE with a displacement of less than 30 liters per cylinder that do not meet the applicable requirements 

specified in paragraphs (a) through (g) of this section after the dates specified in paragraphs (a) through (g) of this 

section.

(i) The requirements of this section do not apply to owners or operators of stationary CI ICE that have been modified, 

reconstructed, and do not apply to engines that were removed from one existing location and reinstalled at a new 

location.

[71 FR 39172, July 11, 2006, as amended at 76 FR 37969, June 28, 2011]

§ 60.4209 What are the monitoring requirements if I am an owner or 

operator of a stationary CI internal combustion engine?

If you are an owner or operator, you must meet the monitoring requirements of this section. In addition, you must also 

meet the monitoring requirements specified in §60.4211.

(a) If you are an owner or operator of an emergency stationary CI internal combustion engine that does not meet the 

standards applicable to non-emergency engines, 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 a 

backpressure monitor that notifies the owner or operator when the high backpressure limit of the engine is 

approached.

[71 FR 39172, July 11, 2006, as amended at 76 FR 37969, June 28, 2011]

Compliance Requirements
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§ 60.4210 What are my compliance requirements if I am a stationary CI 

internal combustion engine manufacturer?

(a) Stationary CI internal combustion engine manufacturers must certify their stationary CI ICE with a displacement of 

less than 10 liters per cylinder to the emission standards specified in §60.4201(a) through (c) and §60.4202(a), (b) 

and (d) using the certification procedures required in 40 CFR part 89, subpart B, or 40 CFR part 1039, subpart C, as 

applicable, and must test their engines as specified in those parts. For the purposes of this subpart, engines certified 

to the standards in table 1 to this subpart shall be subject to the same requirements as engines certified to the 

standards in 40 CFR part 89. For the purposes of this subpart, engines certified to the standards in table 4 to this 

subpart shall be subject to the same requirements as engines certified to the standards in 40 CFR part 89, except 

that engines with NFPA nameplate power of less than 37 KW (50 HP) certified to model year 2011 or later standards 

shall be subject to the same requirements as engines certified to the standards in 40 CFR part 1039.

(b) Stationary CI internal combustion engine manufacturers must certify their stationary CI ICE with a displacement of 

greater than or equal to 10 liters per cylinder and less than 30 liters per cylinder to the emission standards specified 

in §60.4201(d) and (e) and §60.4202(e) and (f) using the certification procedures required in 40 CFR part 94, subpart 

C, or 40 CFR part 1042, subpart C, as applicable, and must test their engines as specified in 40 CFR part 94 or 1042, 

as applicable.

(c) Stationary CI internal combustion engine manufacturers must meet the requirements of 40 CFR 1039.120, 

1039.125, 1039.130, and 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, 40 CFR part 94 or 40 CFR part 1042 for engines that would be covered by that part if they were 

nonroad (including marine) engines. Labels on such engines must refer to stationary engines, rather than or in 

addition to nonroad or marine engines, as appropriate. Stationary CI internal combustion engine manufacturers must 

label their engines according to paragraphs (c)(1) through (3) of this section.

(1) Stationary CI internal combustion engines manufactured from January 1, 2006 to March 31, 2006 (January 1, 

2006 to June 30, 2006 for fire pump engines), other than those that are part of certified engine families under the 

nonroad CI engine regulations, must be labeled according to 40 CFR 1039.20.

(2) Stationary CI internal combustion engines manufactured from April 1, 2006 to December 31, 2006 (or, for fire 

pump engines, July 1, 2006 to December 31 of the year preceding the year listed in table 3 to this subpart) must be 

labeled according to paragraphs (c)(2)(i) through (iii) of this section:

(i) Stationary CI internal combustion engines that are part of certified engine families under the nonroad regulations 

must meet the labeling requirements for nonroad CI engines, but do not have to meet the labeling requirements in 40 

CFR 1039.20.

(ii) Stationary CI internal combustion engines that meet Tier 1 requirements (or requirements for fire pumps) under 

this subpart, but do not meet the requirements applicable to nonroad CI engines must be labeled according to 40 

CFR 1039.20. The engine manufacturer may add language to the label clarifying that the engine meets Tier 1 

requirements (or requirements for fire pumps) of this subpart.

(iii) Stationary CI internal combustion engines manufactured after April 1, 2006 that do not meet Tier 1 requirements 

of this subpart, or fire pumps engines manufactured after July 1, 2006 that do not meet the requirements for fire 

pumps under this subpart, may not be used in the U.S. If any such engines are manufactured in the U.S. after April 1, 

2006 (July 1, 2006 for fire pump engines), they must be exported or must be brought into compliance with the 

appropriate standards prior to initial operation. The export provisions of 40 CFR 1068.230 would apply to engines for 

export and the manufacturers must label such engines according to 40 CFR 1068.230.

(3) Stationary CI internal combustion engines manufactured after January 1, 2007 (for fire pump engines, after 

January 1 of the year listed in table 3 to this subpart, as applicable) must be labeled according to paragraphs (c)(3)(i) 

through (iii) of this section.

(i) Stationary CI internal combustion engines that meet the requirements of this subpart and the corresponding 

requirements for nonroad (including marine) engines of the same model year and HP must be labeled according to 

the provisions in 40 CFR parts 89, 94, 1039 or 1042, as appropriate.
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(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 40 CFR parts 89, 94, 1039 or 1042, as appropriate, but the words “stationary” must be 

included instead of “nonroad” or “marine” on the label. In addition, such engines must be labeled according to 40 CFR 

1039.20.

(iii) Stationary CI internal combustion engines that do not meet the requirements of this subpart must be labeled 

according to 40 CFR 1068.230 and must be exported under the provisions of 40 CFR 1068.230.

(d) An engine manufacturer certifying an engine family or families to standards under this subpart that are identical to 

standards applicable under 40 CFR parts 89, 94, 1039 or 1042 for that model year may certify any such family that 

contains both nonroad (including marine) and stationary engines as a single engine family and/or may include any 

such family containing stationary engines in the averaging, banking and trading provisions applicable for such 

engines under those parts.

(e) Manufacturers of engine families discussed in paragraph (d) of this section may meet the labeling requirements 

referred to in paragraph (c) of this section for stationary CI ICE by either adding a separate label containing the 

information required in paragraph (c) of this section or by adding the words “and stationary” after the word “nonroad” 

or “marine,” as appropriate, to the label.

(f) Starting with the model years shown in table 5 to this subpart, stationary CI internal combustion engine 

manufacturers must add a permanent label stating that the engine is for stationary emergency use only to each new 

emergency stationary CI internal combustion engine greater than or equal to 19 KW (25 HP) that meets all the 

emission standards for emergency engines in §60.4202 but does not meet all the emission standards for nonemergency engines in §60.4201. The label must be added according to the labeling requirements specified in 40 

CFR 1039.135(b). Engine manufacturers must specify in the owner's manual that operation of emergency engines is 

limited to emergency operations and required maintenance and testing.

(g) Manufacturers of fire pump engines may use the test cycle in table 6 to this subpart for testing fire pump engines 

and may test at the NFPA certified nameplate HP, provided that the engine is labeled as “Fire Pump Applications 

Only”.

(h) Engine manufacturers, including importers, may introduce into commerce uncertified engines or engines certified 

to earlier standards that were manufactured before the new or changed standards took effect until inventories are 

depleted, as long as such engines are part of normal inventory. For example, if the engine manufacturers' normal 

industry practice is to keep on hand a one-month supply of engines based on its projected sales, and a new tier of 

standards starts to apply for the 2009 model year, the engine manufacturer may manufacture engines based on the 

normal inventory requirements late in the 2008 model year, and sell those engines for installation. The engine 

manufacturer may not circumvent the provisions of §§60.4201 or 60.4202 by stockpiling engines that are built before 

new or changed standards take effect. Stockpiling of such engines beyond normal industry practice is a violation of 

this subpart.

(i) The replacement engine provisions of 40 CFR 89.1003(b)(7), 40 CFR 94.1103(b)(3), 40 CFR 94.1103(b)(4) and 40 

CFR 1068.240 are applicable to stationary CI engines replacing existing equipment that is less than 15 years old.

[71 FR 39172, July 11, 2006, as amended at 76 FR 37969, June 28, 2011]

§ 60.4211 What are my compliance requirements if I am an owner or 

operator of a stationary CI internal combustion engine?

(a) If you are an owner or operator and must comply with the emission standards specified in this subpart, you must 

do all of the following, except as permitted under paragraph (g) of this section:

(1) Operate and maintain the stationary CI internal combustion engine and control device according to the 

manufacturer's emission-related written instructions;

(2) Change only those emission-related settings that are permitted by the manufacturer; and
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(3) Meet the requirements of 40 CFR parts 89, 94 and/or 1068, as they apply to you.

(b) If you are an owner or operator of a pre-2007 model year stationary CI internal combustion engine and must 

comply with the emission standards specified in §§60.4204(a) or 60.4205(a), or if you are an owner or operator of a 

CI fire pump engine that is manufactured prior to the model years in table 3 to this subpart and must comply with the 

emission standards specified in §60.4205(c), you must demonstrate compliance according to one of the methods 

specified in paragraphs (b)(1) through (5) of this section.

(1) Purchasing an engine certified according to 40 CFR part 89 or 40 CFR part 94, as applicable, for the same model 

year and maximum engine power. The engine must be installed and configured according to the manufacturer's 

specifications.

(2) Keeping records of performance test results for each pollutant for a test conducted on a similar engine. The test 

must have been conducted using the same methods specified in this subpart and these methods must have been 

followed correctly.

(3) Keeping records of engine manufacturer data indicating compliance with the standards.

(4) Keeping records of control device vendor data indicating compliance with the standards.

(5) Conducting an initial performance test to demonstrate compliance with the emission standards according to the 

requirements specified in §60.4212, as applicable.

(c) If you are an owner or operator of a 2007 model year and later stationary CI internal combustion engine and must 

comply with the emission standards specified in §60.4204(b) or §60.4205(b), or if you are an owner or operator of a 

CI fire pump engine that is manufactured during or after the model year that applies to your fire pump engine power 

rating in table 3 to this subpart and must comply with the emission standards specified in §60.4205(c), you must 

comply by purchasing an engine certified to the emission standards in §60.4204(b), or §60.4205(b) or (c), as 

applicable, for the same model year and maximum (or in the case of fire pumps, NFPA nameplate) engine power. 

The engine must be installed and configured according to the manufacturer's emission-related specifications, except 

as permitted in paragraph (g) of this section.

(d) If you are an owner or operator and must comply with the emission standards specified in §60.4204(c) or 

§60.4205(d), you must demonstrate compliance according to the requirements specified in paragraphs (d)(1) through 

(3) of this section.

(1) Conducting an initial performance test to demonstrate initial compliance with the emission standards as specified 

in §60.4213.

(2) Establishing operating parameters to be monitored continuously to ensure the stationary internal combustion 

engine continues to meet the emission standards. The owner or operator must petition the Administrator for approval 

of operating parameters to be monitored continuously. The petition must include the information described in 

paragraphs (d)(2)(i) through (v) of this section.

(i) Identification of the specific parameters you propose to monitor continuously;

(ii) A discussion of the relationship between these parameters and NOXand PM emissions, identifying how the 

emissions of these pollutants change with changes in these parameters, and how limitations on these parameters will 

serve to limit NOXand PM emissions;

(iii) A discussion of how you will establish the upper and/or lower values for these parameters which will establish the 

limits on these parameters in the operating limitations;

(iv) A discussion identifying the methods and the instruments you will use to monitor these parameters, as well as the 

relative accuracy and precision of these methods and instruments; and
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(v) A discussion identifying the frequency and methods for recalibrating the instruments you will use for monitoring 

these parameters.

(3) For non-emergency engines with a displacement of greater than or equal to 30 liters per cylinder, conducting 

annual performance tests to demonstrate continuous compliance with the emission standards as specified in 

§60.4213.

(e) If you are an owner or operator of a modified or reconstructed stationary CI internal combustion engine and must 

comply with the emission standards specified in §60.4204(e) or §60.4205(f), you must demonstrate compliance 

according to one of the methods specified in paragraphs (e)(1) or (2) of this section.

(1) Purchasing, or otherwise owning or operating, an engine certified to the emission standards in §60.4204(e) or 

§60.4205(f), as applicable.

(2) Conducting a performance test to demonstrate initial compliance with the emission standards according to the 

requirements specified in §60.4212 or §60.4213, as appropriate. The test must be conducted within 60 days after the

engine commences operation after the modification or reconstruction.

(f) Emergency stationary ICE may be operated for the purpose of maintenance checks and readiness testing, 

provided that the tests are recommended by Federal, State or local government, the manufacturer, the vendor, or the 

insurance company associated with the engine. Maintenance checks and readiness testing of such units is limited to 

100 hours per year. There is no time limit on the use of emergency stationary ICE in emergency situations. The 

owner or operator may petition the Administrator for approval of additional hours to be used for maintenance checks 

and readiness testing, but a petition is not required if the owner or operator maintains records indicating that Federal, 

State, or local standards require maintenance and testing of emergency ICE beyond 100 hours per year. Emergency 

stationary ICE may operate up to 50 hours per year in non-emergency situations, but those 50 hours are counted 

towards the 100 hours per year provided for maintenance and testing. The 50 hours per year for non-emergency 

situations cannot be used for peak shaving or to generate income for a facility to supply power to an electric grid or 

otherwise supply non-emergency power as part of a financial arrangement with another entity. For owners and 

operators of emergency engines, any operation other than emergency operation, maintenance and testing, and 

operation in non-emergency situations for 50 hours per year, as permitted in this section, is prohibited.

(g) If you do not install, configure, operate, and maintain your engine and control device according to the 

manufacturer's emission-related written instructions, or you change emission-related settings in a way that is not 

permitted by the manufacturer, you must demonstrate compliance as follows:

(1) If you are an owner or operator of a stationary CI internal combustion engine with maximum engine power less 

than 100 HP, you must keep a maintenance plan and records of conducted maintenance to demonstrate compliance 

and must, to the extent practicable, maintain and operate the engine in a manner consistent with good air pollution 

control practice for minimizing emissions. In addition, if you do not install and configure the engine and control device 

according to the manufacturer's emission-related written instructions, or you change the emission-related settings in a 

way that is not permitted by the manufacturer, you must conduct an initial performance test to demonstrate 

compliance with the applicable emission standards within 1 year of such action.

(2) If you are an owner or operator of a stationary CI internal combustion engine greater than or equal to 100 HP and 

less than or equal to 500 HP, you must keep a maintenance plan and records of conducted maintenance and must, 

to the extent practicable, maintain and operate the engine in a manner consistent with good air pollution control 

practice for minimizing emissions. In addition, you must conduct an initial performance test to demonstrate 

compliance with the applicable emission standards within 1 year of startup, or within 1 year after an engine and 

control device is no longer installed, configured, operated, and maintained in accordance with the manufacturer's 

emission-related written instructions, or within 1 year after you change emission-related settings in a way that is not 

permitted by the manufacturer.

(3) If you are an owner or operator of a stationary CI internal combustion engine greater than 500 HP, you must keep 

a maintenance plan and records of conducted maintenance and must, to the extent practicable, maintain and operate 

the engine in a manner consistent with good air pollution control practice for minimizing emissions. In addition, you 

must conduct an initial performance test to demonstrate compliance with the applicable emission standards within 1 

year of startup, or within 1 year after an engine and control device is no longer installed, configured, operated, and 

maintained in accordance with the manufacturer's emission-related written instructions, or within 1 year after you 
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change emission-related settings in a way that is not permitted by the manufacturer. You must conduct subsequent 

performance testing every 8,760 hours of engine operation or 3 years, whichever comes first, thereafter to 

demonstrate compliance with the applicable emission standards.

[71 FR 39172, July 11, 2006, as amended at 76 FR 37970, June 28, 2011]

Testing Requirements for Owners and Operators

§ 60.4212 What test methods and other procedures must I use if I am an 

owner or operator of a stationary CI internal combustion engine with a 

displacement of less than 30 liters per cylinder?

Owners and operators of stationary CI ICE with a displacement of less than 30 liters per cylinder who conduct 

performance tests pursuant to this subpart must do so according to paragraphs (a) through (e) of this section.

(a) The performance test must be conducted according to the in-use testing procedures in 40 CFR part 1039, subpart 

F, for stationary CI ICE with a displacement of less than 10 liters per cylinder, and according to 40 CFR part 1042, 

subpart F, for stationary CI ICE with a displacement of greater than or equal to 10 liters per cylinder and less than 30 

liters per cylinder.

(b) Exhaust emissions from stationary CI ICE that are complying with the emission standards for new CI engines in 

40 CFR part 1039 must not exceed the not-to-exceed (NTE) standards for the same model year and maximum 

engine power as required in 40 CFR 1039.101(e) and 40 CFR 1039.102(g)(1), except as specified in 40 CFR 

1039.104(d). This requirement starts when NTE requirements take effect for nonroad diesel engines under 40 CFR 

part 1039.

(c) Exhaust emissions from stationary CI ICE that are complying with the emission standards for new CI engines in 

40 CFR 89.112 or 40 CFR 94.8, as applicable, must not exceed the NTE numerical requirements, rounded to the 

same number of decimal places as the applicable standard in 40 CFR 89.112 or 40 CFR 94.8, as applicable, 

determined from the following equation:

Where:

STD = The standard specified for that pollutant in 40 CFR 89.112 or 40 CFR 94.8, as applicable.

Alternatively, stationary CI ICE that are complying with the emission standards for new CI engines in 40 CFR 89.112 

or 40 CFR 94.8 may follow the testing procedures specified in §60.4213 of this subpart, as appropriate.

(d) Exhaust emissions from stationary CI ICE that are complying with the emission standards for pre-2007 model year 

engines in §60.4204(a), §60.4205(a), or §60.4205(c) must not exceed the NTE numerical requirements, rounded to 

the same number of decimal places as the applicable standard in §60.4204(a), §60.4205(a), or §60.4205(c), 

determined from the equation in paragraph (c) of this section.

Where:

STD = The standard specified for that pollutant in §60.4204(a), §60.4205(a), or §60.4205(c).

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.
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(e) Exhaust emissions from stationary CI ICE that are complying with the emission standards for new CI engines in 

40 CFR part 1042 must not exceed the NTE standards for the same model year and maximum engine power as 

required in 40 CFR 1042.101(c).

[71 FR 39172, July 11, 2006, as amended at 76 FR 37971, June 28, 2011]

§ 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 (f) of this section.

(a) Each performance test must be conducted according to the requirements in §60.8 and under the specific 

conditions that this subpart specifies in table 7. The test must be conducted within 10 percent of 100 percent peak (or 

the highest achievable) load.

(b) You may not conduct performance tests during periods of startup, shutdown, or malfunction, as specified in 

§60.8(c).

(c) You must conduct three separate test runs for each performance test required in this section, as specified in 

§60.8(f). Each test run must last at least 1 hour.

(d) To determine compliance with the percent reduction requirement, you must follow the requirements as specified in 

paragraphs (d)(1) through (3) of this section.

(1) You must use Equation 2 of this section to determine compliance with the percent reduction requirement:

Where:

Ci= concentration of NOXor PM at the control device inlet,

Co= concentration of NOXor PM at the control device outlet, and

R = percent reduction of NOXor PM emissions.

(2) You must normalize the NOXor PM concentrations at the inlet and outlet of the control device to a dry basis and to 

15 percent oxygen (O2) using Equation 3 of this section, or an equivalent percent carbon dioxide (CO2) using the 

procedures described in paragraph (d)(3) of this section.

Where:

Cadj= Calculated NOXor PM concentration adjusted to 15 percent O2.

Cd= Measured concentration of NOXor PM, uncorrected.
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5.9 = 20.9 percent O2−15 percent O2, the defined O2correction value, percent.

%O2= Measured O2concentration, dry basis, percent.

(3) If pollutant concentrations are to be corrected to 15 percent O2and CO2concentration is measured in lieu of 

O2concentration measurement, a CO2correction factor is needed. Calculate the CO2correction factor as described in 

paragraphs (d)(3)(i) through (iii) of this section.

(i) Calculate the fuel-specific Fovalue for the fuel burned during the test using values obtained from Method 19, 

Section 5.2, and the following equation:

Where:

Fo= Fuel factor based on the ratio of O2volume to the ultimate CO2volume produced by the fuel at zero 

percent excess air.

0.209 = Fraction of air that is O2, percent/100.

Fd= Ratio of the volume of dry effluent gas to the gross calorific value of the fuel from Method 19, dsm3 /J 

(dscf/106 Btu).

Fc= Ratio of the volume of CO2produced to the gross calorific value of the fuel from Method 19, dsm3 /J 

(dscf/106 Btu).

(ii) Calculate the CO2correction factor for correcting measurement data to 15 percent O2, as follows:

Where:

XCO2= CO2correction factor, percent.

5.9 = 20.9 percent O2−15 percent O2, the defined O2correction value, percent.

(iii) Calculate the NOXand PM gas concentrations adjusted to 15 percent O2using CO2as follows:

Where:

Cadj= Calculated NOXor PM concentration adjusted to 15 percent O2.

Cd= Measured concentration of NOXor PM, uncorrected.

%CO2= Measured CO2concentration, dry basis, percent.
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(e) To determine compliance with the NOXmass per unit output emission limitation, convert the concentration of 

NOXin the engine exhaust using Equation 7 of this section:

Where:

ER = Emission rate in grams per KW-hour.

Cd= Measured NOXconcentration in ppm.

1.912x10−3= Conversion constant for ppm NOXto grams per standard cubic meter at 25 degrees Celsius.

Q = Stack gas volumetric flow rate, in standard cubic meter per hour.

T = Time of test run, in hours.

KW-hour = Brake work of the engine, in KW-hour.

(f) To determine compliance with the PM mass per unit output emission limitation, convert the concentration of PM in 

the engine exhaust using Equation 8 of this section:

Where:

ER = Emission rate in grams per KW-hour.

Cadj= Calculated PM concentration in grams per standard cubic meter.

Q = Stack gas volumetric flow rate, in standard cubic meter per hour.

T = Time of test run, in hours.

KW-hour = Energy output of the engine, in KW.

[71 FR 39172, July 11, 2006, as amended at 76 FR 37971, June 28, 2011]

Notification, Reports, and Records for Owners and Operators

§ 60.4214 What are my notification, reporting, and recordkeeping 

requirements if I am an owner or operator of a stationary CI internal 

combustion engine?

(a) Owners and operators of non-emergency stationary CI ICE that are greater than 2,237 KW (3,000 HP), or have a 

displacement of greater than or equal to 10 liters per cylinder, or are pre-2007 model year engines that are greater 

than 130 KW (175 HP) and not certified, must meet the requirements of paragraphs (a)(1) and (2) of this section.
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(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.

(i) Name and address of the owner or operator;

(ii) The address of the affected source;

(iii) Engine information including make, model, engine family, serial number, model year, maximum engine power, 

and engine displacement;

(iv) Emission control equipment; and

(v) Fuel used.

(2) Keep records of the information in paragraphs (a)(2)(i) through (iv) of this section.

(i) All notifications submitted to comply with this subpart and all documentation supporting any notification.

(ii) Maintenance conducted on the engine.

(iii) If the stationary CI internal combustion is a certified engine, documentation from the manufacturer that the engine 

is certified to meet the emission standards.

(iv) If the stationary CI internal combustion is not a certified engine, documentation that the engine meets the 

emission standards.

(b) If the stationary CI internal combustion engine is an emergency stationary internal combustion engine, the owner 

or operator is not required to submit an initial notification. Starting with the model years in table 5 to this subpart, if the 

emergency engine does not meet the standards applicable to non-emergency engines in the applicable model year, 

the owner or operator must keep records of the operation of the engine in emergency and non-emergency service 

that are recorded through the non-resettable hour meter. The owner must record the time of operation of the engine 

and the reason the engine was in operation during that time.

(c) If the stationary CI internal combustion engine is equipped with a diesel particulate filter, the owner or operator 

must keep records of any corrective action taken after the backpressure monitor has notified the owner or operator 

that the high backpressure limit of the engine is approached.

Special Requirements

§ 60.4215 What requirements must I meet for engines used in Guam, 

American Samoa, or the Commonwealth of the Northern Mariana Islands?

(a) Stationary CI ICE with a displacement of less than 30 liters per cylinder that are used in Guam, American Samoa, 

or the Commonwealth of the Northern Mariana Islands are required to meet the applicable emission standards in 

§§60.4202 and 60.4205.

(b) Stationary CI ICE that are used in Guam, American Samoa, or the Commonwealth of the Northern Mariana 

Islands are not required to meet the fuel requirements in §60.4207.

(c) Stationary CI ICE with a displacement of greater than or equal to 30 liters per cylinder that are used in Guam, 

American Samoa, or the Commonwealth of the Northern Mariana Islands are required to meet the following emission 

standards:

(1) For engines installed prior to January 1, 2012, limit the emissions of NOXin the stationary CI internal combustion 

engine exhaust to the following:
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(i) 17.0 g/KW-hr (12.7 g/HP-hr) when maximum engine speed is less than 130 rpm;

(ii) 45 · n−0.2g/KW-hr (34 · n−0.2g/HP-hr) when maximum engine speed is 130 or more but less than 2,000 rpm, where 

n is maximum engine speed; and

(iii) 9.8 g/KW-hr (7.3 g/HP-hr) when maximum engine speed is 2,000 rpm or more.

(2) For engines installed on or after January 1, 2012, limit the emissions of NOXin the stationary CI internal 

combustion engine exhaust to the following:

(i) 14.4 g/KW-hr (10.7 g/HP-hr) when maximum engine speed is less than 130 rpm;

(ii) 44 · n−0.23g/KW-hr (33 · n−0.23g/HP-hr) when maximum engine speed is greater than or equal to 130 but less than 

2,000 rpm and where n is maximum engine speed; and

(iii) 7.7 g/KW-hr (5.7 g/HP-hr) when maximum engine speed is greater than or equal to 2,000 rpm.

(3) Limit the emissions of PM in the stationary CI internal combustion engine exhaust to 0.40 g/KW-hr (0.30 g/HP-hr).

[71 FR 39172, July 11, 2006, as amended at 76 FR 37971, June 28, 2011]

§ 60.4216 What requirements must I meet for engines used in Alaska?

(a) Prior to December 1, 2010, owners and operators of stationary CI ICE with a displacement of less than 30 liters 

per cylinder located in areas of Alaska not accessible by the FAHS should refer to 40 CFR part 69 to determine the 

diesel fuel requirements applicable to such engines.

(b) Except as indicated in paragraph (c) of this section, manufacturers, owners and operators of stationary CI ICE 

with a displacement of less than 10 liters per cylinder located in areas of Alaska not accessible by the FAHS may 

meet the requirements of this subpart by manufacturing and installing engines meeting the requirements of 40 CFR 

parts 94 or 1042, as appropriate, rather than the otherwise applicable requirements of 40 CFR parts 89 and 1039, as 

indicated in sections §§60.4201(f) and 60.4202(g) of this subpart.

(c) Manufacturers, owners and operators of stationary CI ICE that are located in areas of Alaska not accessible by 

the FAHS may choose to meet the applicable emission standards for emergency engines in §60.4202 and §60.4205, 

and not those for non-emergency engines in §60.4201 and §60.4204, except that for 2014 model year and later nonemergency CI ICE, the owner or operator of any such engine that was not certified as meeting Tier 4 PM standards, 

must meet the applicable requirements for PM in §60.4201 and §60.4204 or install a PM emission control device that 

achieves PM emission reductions of 85 percent, or 60 percent for engines with a displacement of greater than or 

equal to 30 liters per cylinder, compared to engine-out emissions.

(d) The provisions of §60.4207 do not apply to owners and operators of pre-2014 model year stationary CI ICE 

subject to this subpart that are located in areas of Alaska not accessible by the FAHS.

(e) The provisions of §60.4208(a) do not apply to owners and operators of stationary CI ICE subject to this subpart 

that are located in areas of Alaska not accessible by the FAHS until after December 31, 2009.

(f) The provisions of this section and §60.4207 do not prevent owners and operators of stationary CI ICE subject to 

this subpart that are located in areas of Alaska not accessible by the FAHS from using fuels mixed with used 

lubricating oil, in volumes of up to 1.75 percent of the total fuel. The sulfur content of the used lubricating oil must be 

less than 200 parts per million. The used lubricating oil must meet the on-specification levels and properties for used 

oil in 40 CFR 279.11.

[76 FR 37971, June 28, 2011]
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§ 60.4217 What emission standards must I meet if I am an owner or 

operator of a stationary internal combustion engine using special fuels?

Owners and operators of stationary CI ICE that do not use diesel fuel 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 

§60.4204 or §60.4205 using such fuels and that use of such fuel is appropriate and reasonably necessary,

considering cost, energy, technical feasibility, human health and environmental, and other factors, for the operation of 

the engine.

[76 FR 37972, June 28, 2011]

General Provisions

§ 60.4218 What parts of the General Provisions apply to me?

Table 8 to this subpart shows which parts of the General Provisions in §§60.1 through 60.19 apply to you.

Definitions

§ 60.4219 What definitions apply to this subpart?

As used in this subpart, all terms not defined herein shall have the meaning given them in the CAA and in subpart A 

of this part.

Certified emissions 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 certified emissions 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 certified emissions 

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).

Combustion turbine means all equipment, including but not limited to the turbine, the fuel, air, lubrication and exhaust 

gas systems, control systems (except emissions control equipment), and any ancillary components and subcomponents comprising any simple cycle combustion turbine, any regenerative/recuperative cycle combustion 

turbine, the combustion turbine portion of any cogeneration cycle combustion system, or the combustion turbine 

portion of any combined cycle steam/electric generating system.

Compression ignition means relating to a type of stationary internal combustion engine that is not a spark ignition 

engine.

Date of manufacture means one of the following things:

(1) For freshly manufactured engines and modified engines, date of manufacture means the date the engine is 

originally produced.

(2) For reconstructed engines, date of manufacture means the date the engine was originally produced, except as 

specified in paragraph (3) of this definition.

(3) Reconstructed engines are assigned a new date of manufacture if the fixed capital cost of the new and 

refurbished components exceeds 75 percent of the fixed capital cost of a comparable entirely new facility. An engine 

that is produced from a previously used engine block does not retain the date of manufacture of the engine in which 

the engine block was previously used if the engine is produced using all new components except for the engine 

block. In these cases, the date of manufacture is the date of reconstruction or the date the new engine is produced.
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Diesel fuel means any liquid obtained from the distillation of petroleum with a boiling point of approximately 150 to 

360 degrees Celsius. One commonly used form is number 2 distillate oil.

Diesel particulate filter means an emission control technology that reduces PM emissions by trapping the particles in 

a flow filter substrate and periodically removes the collected particles by either physical action or by oxidizing (burning 

off) the particles in a process called regeneration.

Emergency stationary internal combustion engine means any stationary internal combustion engine whose operation 

is limited to emergency situations and required testing and maintenance. Examples include stationary ICE used to 

produce power for critical networks or equipment (including power supplied to portions of a facility) when electric 

power from the local utility (or the normal power source, if the facility runs on its own power production) is interrupted, 

or stationary ICE used to pump water in the case of fire or flood, etc. Stationary CI ICE used to supply power to an 

electric grid or that supply power as part of a financial arrangement with another entity are not considered to be 

emergency engines.

Engine manufacturer means the manufacturer of the engine. See the definition of “manufacturer” in this section.

Fire pump engine means an emergency stationary internal combustion engine certified to NFPA requirements that is 

used to provide power to pump water for fire suppression or protection.

Freshly manufactured engine means an engine that has not been placed into service. An engine becomes freshly 

manufactured when it is originally produced.

Installed means the engine is placed and secured at the location where it is intended to be operated.

Manufacturer has the meaning given in section 216(1) of the Act. In general, this term includes any person who 

manufactures a stationary engine for sale in the United States or otherwise introduces a new stationary engine into 

commerce in the United States. This includes importers who import stationary engines for sale or resale.

Maximum engine power means maximum engine power as defined in 40 CFR 1039.801.

Model year means the calendar year in which an engine is manufactured (see “date of manufacture”), except as 

follows:

(1) Model year means the annual new model production period of the engine manufacturer in which an engine is 

manufactured (see “date of manufacture”), if the annual new model production period is different than the calendar 

year and includes 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.

(2) For an engine that is converted to a stationary engine after being placed into service as a nonroad or other nonstationary engine, model year means the calendar year or new model production period in which the engine was 

manufactured (see “date of manufacture”).

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 
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gaseous fuel (typically natural gas) is used as the primary fuel at an annual average ratio of less than 2 parts diesel 

fuel to 100 parts total fuel on an energy equivalent basis are spark ignition engines.

Stationary internal combustion engine means any internal combustion engine, except combustion turbines, that 

converts heat energy into mechanical work and is not mobile. Stationary ICE differ from mobile ICE in that a 

stationary internal combustion engine is not a nonroad engine as defined at 40 CFR 1068.30 (excluding paragraph 

(2)(ii) of that definition), and is not used to propel a motor vehicle, aircraft, or a vehicle used solely for competition. 

Stationary ICE include reciprocating ICE, rotary ICE, and other ICE, except combustion turbines.

Subpart means 40 CFR part 60, subpart IIII.

[71 FR 39172, July 11, 2006, as amended at 76 FR 37972, June 28, 2011]

Table 1 to Subpart IIII of Part 60—Emission Standards for Stationary Pre2007 Model Year Engines With a Displacement of <10 Liters per Cylinder 

and 2007–2010 Model Year Engines >2,237 KW (3,000 HP) and With a 

Displacement of <10 Liters per Cylinder

[As stated in §§60.4201(b), 60.4202(b), 60.4204(a), and 60.4205(a), you must comply with the following emission 

standards]

Maximum 

engine power

Emission standards for stationary pre-2007 model year engines with a 

displacement of <10 liters per cylinder and 2007–2010 model year engines 

>2,237 KW (3,000 HP) and with a displacement of <10 liters per cylinder 

in g/KW-hr (g/HP-hr)

NMHC + NOX HC NOX CO PM

KW<8 (HP<11) 10.5 (7.8) 8.0 (6.0) 1.0 (0.75)

8≤KW<19 

(11≤HP<25)

9.5 (7.1) 6.6 (4.9) 0.80 (0.60)

19≤KW<37 

(25≤HP<50)

9.5 (7.1) 5.5 (4.1) 0.80 (0.60)

37≤KW<56 

(50≤HP<75)

9.2 (6.9)

56≤KW<75 

(75≤HP<100)

9.2 (6.9)

75≤KW<130 

(100≤HP<175)

9.2 (6.9)

130≤KW<225 

(175≤HP<300)

1.3 (1.0) 9.2 (6.9) 11.4 (8.5) 0.54 (0.40)

225≤KW<450 

(300≤HP<600)

1.3 (1.0) 9.2 (6.9) 11.4 (8.5) 0.54 (0.40)

450≤KW≤560 

(600≤HP≤750)

1.3 (1.0) 9.2 (6.9) 11.4 (8.5) 0.54 (0.40)
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KW>560 

(HP>750)

1.3 (1.0) 9.2 (6.9) 11.4 (8.5) 0.54 (0.40)

Table 2 to Subpart IIII of Part 60—Emission Standards for 2008 Model Year 

and Later Emergency Stationary CI ICE <37 KW (50 HP) With a 

Displacement of <10 Liters per Cylinder

[As stated in §60.4202(a)(1), you must comply with the following emission standards]

Engine power

Emission standards for 2008 model year and later emergency stationary 

CI ICE <37 KW (50 HP) with a displacement of <10 liters per cylinder in 

g/KW-hr (g/HP-hr)

Model year(s) NOX+ NMHC CO PM

KW<8 (HP<11) 2008+ 7.5 (5.6) 8.0 (6.0) 0.40 (0.30)

8≤KW<19 

(11≤HP<25)

2008+ 7.5 (5.6) 6.6 (4.9) 0.40 (0.30)

19≤KW<37 

(25≤HP<50)

2008+ 7.5 (5.6) 5.5 (4.1) 0.30 (0.22)

Table 3 to Subpart IIII of Part 60—Certification Requirements for Stationary 

Fire Pump Engines

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)1

KW<75

(HP<100)

2011

75≤KW<130

(100≤HP<175)

2010

130≤KW≤560

(175≤HP≤750)

2009

KW>560

(HP>750)

2008
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1

Manufacturers of fire pump stationary CI ICE with a maximum engine power greater than or equal to 37 kW (50 HP) 

and less than 450 KW (600 HP) and a rated speed of greater than 2,650 revolutions per minute (rpm) are not 

required to certify such engines until three model years following the model year indicated in this Table 3 for engines 

in the applicable engine power category.

[71 FR 39172, July 11, 2006, as amended at 76 FR 37972, June 28, 2011]

Table 4 to Subpart IIII of Part 60—Emission Standards for Stationary Fire 

Pump Engines

[As stated in §§60.4202(d) and 60.4205(c), you must comply with the following emission standards for stationary fire 

pump engines]

Maximum engine power Model year(s) NMHC + NOX CO PM

KW<8 (HP<11) 2010 and earlier 10.5 (7.8) 8.0 (6.0) 1.0 (0.75)

 2011+ 7.5 (5.6) 0.40 (0.30)

8≤KW<19 (11≤HP<25) 2010 and earlier 9.5 (7.1) 6.6 (4.9) 0.80 (0.60)

 2011+ 7.5 (5.6) 0.40 (0.30)

19≤KW<37 (25≤HP<50) 2010 and earlier 9.5 (7.1) 5.5 (4.1) 0.80 (0.60)

 2011+ 7.5 (5.6) 0.30 (0.22)

37≤KW<56 (50≤HP<75) 2010 and earlier 10.5 (7.8) 5.0 (3.7) 0.80 (0.60)

 2011+1 4.7 (3.5) 0.40 (0.30)

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)
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1

For model years 2011–2013, manufacturers, owners and operators of fire pump stationary CI ICE in this engine 

power category with a rated speed of greater than 2,650 revolutions per minute (rpm) may comply with the emission 

limitations for 2010 model year engines.

2

For model years 2010–2012, manufacturers, owners and operators of fire pump stationary CI ICE in this engine 

power category with a rated speed of greater than 2,650 rpm may comply with the emission limitations for 2009 

model year engines.

3

In model years 2009–2011, manufacturers of fire pump stationary CI ICE in this engine power category with a rated 

speed of greater than 2,650 rpm may comply with the emission limitations for 2008 model year engines.

Table 5 to Subpart IIII of Part 60—Labeling and Recordkeeping 

Requirements for New Stationary Emergency Engines

[You must comply with the labeling requirements in §60.4210(f) and the recordkeeping requirements in §60.4214(b) 

for new emergency stationary CI ICE beginning in the following model years:]

Engine power Starting model year

19≤KW<56 (25≤HP<75) 2013

56≤KW<130 (75≤HP<175) 2012

KW≥130 (HP≥175) 2011

Table 6 to Subpart IIII of Part 60—Optional 3-Mode Test Cycle for Stationary 

Fire Pump Engines

[As stated in §60.4210(g), manufacturers of fire pump engines may use the following test cycle for testing fire pump 

engines:]

Mode No. Engine speed1

Torque

(percent)2

Weighting

factors

1 Rated 100 0.30

2 Rated 75 0.50

3 Rated 50 0.20

1

Engine speed: ±2 percent of point.

2

Torque: NFPA certified nameplate HP for 100 percent point. All points should be ±2 percent of engine percent load 

value.

Table 7 to Subpart IIII of Part 60—Requirements for Performance Tests for 

Stationary CI ICE With a Displacement of ≥30 Liters per Cylinder

[As stated in §60.4213, you must comply with the following requirements for performance tests for stationary CI ICE 

with a displacement of ≥30 liters per cylinder:]
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For each

Complying with 

the

requirement to You must Using

According to the 

following 

requirements

1. Stationary CI 

internal 

combustion 

engine with a 

displacement of 

≥30 liters per 

cylinder

a. Reduce 

NOXemissions 

by 90 percent or 

more

i. Select the 

sampling port 

location and the 

number of traverse 

points;

(1) Method 1 or 

1A of 40 CFR 

part 60, appendix 

A

(a) Sampling sites 

must be located at the 

inlet and outlet of the 

control device.

 ii. Measure O2at the 

inlet and outlet of 

the control device;

(2) Method 3, 3A, 

or 3B of 40 CFR 

part 60, appendix 

A

(b) Measurements to 

determine 

O2concentration must 

be made at the same 

time as the 

measurements for 

NOXconcentration.

 iii. If necessary, 

measure moisture 

content at the inlet 

and outlet of the 

control device; and,

(3) Method 4 of 

40 CFR part 60, 

appendix A, 

Method 320 of 40 

CFR part 63, 

appendix A, or 

ASTM D 6348–

03 (incorporated 

by reference, see 

§60.17)

(c) Measurements to 

determine moisture 

content must be made 

at the same time as the 

measurements for 

NOXconcentration.

 iv. Measure NOXat 

the inlet and outlet 

of the control 

device

(4) Method 7E of 

40 CFR part 60, 

appendix A, 

Method 320 of 40 

CFR part 63, 

appendix A, or 

ASTM D 6348–

03 (incorporated 

by reference, see 

§60.17)

(d) NOXconcentration 

must be at 15 percent 

O2, dry basis. Results 

of this test consist of 

the average of the three 

1-hour or longer runs.

 b. Limit the 

concentration of 

NOXin the 

stationary CI 

internal 

combustion 

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.
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engine exhaust.

 ii. Determine the 

O2concentration of 

the stationary 

internal combustion 

engine exhaust at 

the sampling port 

location; and,

(2) Method 3, 3A, 

or 3B of 40 CFR 

part 60, appendix 

A

(b) Measurements to 

determine 

O2concentration must 

be made at the same 

time as the 

measurement for 

NOXconcentration.

 iii. If necessary, 

measure moisture 

content of the 

stationary internal 

combustion engine 

exhaust at the 

sampling port 

location; and,

(3) Method 4 of 

40 CFR part 60, 

appendix A, 

Method 320 of 40 

CFR part 63, 

appendix A, or 

ASTM D 6348–

03 (incorporated 

by reference, see 

§60.17)

(c) Measurements to 

determine moisture 

content must be made 

at the same time as the 

measurement for 

NOXconcentration.

 iv. Measure NOXat 

the exhaust of the 

stationary internal 

combustion engine

(4) Method 7E of 

40 CFR part 60, 

appendix A, 

Method 320 of 40 

CFR part 63, 

appendix A, or 

ASTM D 6348–

03 (incorporated 

by reference, see 

§60.17)

(d) NOXconcentration 

must be at 15 percent 

O2, dry basis. Results 

of this test consist of 

the average of the three 

1-hour or longer runs.

 c. Reduce PM 

emissions by 60 

percent or more

i. Select the 

sampling port 

location and the 

number of traverse 

points;

(1) Method 1 or 

1A of 40 CFR 

part 60, appendix 

A

(a) Sampling sites 

must be located at the 

inlet and outlet of the 

control device.

 ii. Measure O2at the 

inlet and outlet of 

the control device;

(2) Method 3, 3A, 

or 3B of 40 CFR 

part 60, appendix 

A

(b) Measurements to 

determine 

O2concentration must 

be made at the same 

time as the 

measurements for PM 

concentration.

 iii. If necessary, 

measure moisture 

content at the inlet 

(3) Method 4 of 

40 CFR part 60, 

appendix A

(c) Measurements to 

determine and 

moisture content must 
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060

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and outlet of the

control device; and

be made at the same 

time as the 

measurements for PM 

concentration.

 iv. Measure PM at 

the inlet and outlet 

of the control 

device

(4) Method 5 of 

40 CFR part 60, 

appendix A

(d) PM concentration 

must be at 15 percent 

O2, dry basis. Results 

of this test consist of 

the average of the three 

1-hour or longer runs.

 d. Limit the 

concentration of 

PM in the 

stationary CI 

internal 

combustion 

engine exhaust

i. Select the 

sampling port 

location and the 

number of traverse 

points;

(1) Method 1 or 

1A of 40 CFR 

part 60, appendix 

A

(a) If using a control 

device, the sampling 

site must be located at 

the outlet of the control 

device.

 ii. Determine the 

O2concentration of 

the stationary 

internal combustion 

engine exhaust at 

the sampling port 

location; and

(2) Method 3, 3A, 

or 3B of 40 CFR 

part 60, appendix 

A

(b) Measurements to 

determine 

O2concentration must 

be made at the same 

time as the 

measurements for PM 

concentration.

 iii. If necessary, 

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

(c) Measurements to 

determine moisture 

content must be made 

at the same time as the 

measurements for PM 

concentration.

 iv. Measure PM at 

the exhaust of the 

stationary internal 

combustion engine

(4) Method 5 of 

40 CFR part 60, 

appendix A

(d) PM concentration 

must be at 15 percent 

O2, dry basis. Results

of this test consist of 

the average of the three 

1-hour or longer runs.

Table 8 to Subpart IIII of Part 60—Applicability of General Provisions to 

Subpart IIII

[As stated in §60.4218, you must comply with the following applicable General Provisions:]
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060

Permit Reviewer: Josiah Balogun

General 

Provisions

citation Subject of citation

Applies

to

subpart Explanation

§60.1 General applicability of 

the General Provisions

Yes

§60.2 Definitions Yes Additional terms defined in §60.4219.

§60.3 Units and abbreviations Yes

§60.4 Address Yes

§60.5 Determination of 

construction or 

modification

Yes

§60.6 Review of plans Yes

§60.7 Notification and 

Recordkeeping

Yes Except that §60.7 only applies as specified in 

§60.4214(a).

§60.8 Performance tests Yes Except that §60.8 only applies to stationary CI 

ICE with a displacement of (≥30 liters per 

cylinder and engines that are not certified.

§60.9 Availability of information Yes

§60.10 State Authority Yes

§60.11 Compliance with standards 

and maintenance 

requirements

No Requirements are specified in subpart IIII.

§60.12 Circumvention Yes

§60.13 Monitoring requirements Yes Except that §60.13 only applies to stationary 

CI ICE with a displacement of (≥30 liters per 

cylinder.

§60.14 Modification Yes

§60.15 Reconstruction Yes

§60.16 Priority list Yes

§60.17 Incorporations by 

reference

Yes

§60.18 General control device 

requirements

No

§60.19 General notification and 

reporting requirements

Yes
Indiana Gasification LLC Page 29 of 29

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060

Permit Reviewer: Josiah Balogun

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Attachment F to a PSD/Part 70 Operating Permit

Leak detection and Repair (LDAR) Conditions for All Fugitive Sources 

-Subpart H— National Emission Standards for Organic Hazardous Air 

Pollutants for Equipment Leaks [40 CFR Part 63, Subpart H] 

[326 IAC 20]

Source Name: Indiana Gasification LLC

Source Location: CR 200 N and Base Road, Rockport, IN 47635

County: Spencer

SIC Code: 4925, 2819

Operation Permit No.: T 147-30464-00060

Operation Permit Issuance Date: Yet to be Issued

Permit Reviewer: Josiah Balogun

Subpart H—National Emission Standards for Organic Hazardous Air 

Pollutants for Equipment Leaks

Source: 59 FR 19568, Apr. 22, 1994, unless otherwise noted.

§ 63.160 Applicability and designation of source.

(a) The provisions of this subpart apply to pumps, compressors, agitators, pressure relief devices, sampling 

connection systems, open-ended valves or lines, valves, connectors, surge control vessels, bottoms receivers, 

instrumentation systems, and control devices or closed vent systems required by this subpart that are intended to 

operate in organic hazardous air pollutant service 300 hours or more during the calendar year within a source subject 

to the provisions of a specific subpart in 40 CFR part 63 that references this subpart.

(b) After the compliance date for a process unit, equipment to which this subpart applies that are also subject to the 

provisions of:

(1) 40 CFR part 60 will be required to comply only with the provisions of this subpart.

(2) 40 CFR part 61 will be required to comply only with the provisions of this subpart.

(c) If a process unit subject to the provisions of this subpart has equipment to which this subpart does not apply, but 

which is subject to a standard identified in paragraph (c)(1), (c)(2), or (c)(3) of this section, the owner or operator may 

elect to apply this subpart to all such equipment in the process unit. If the owner or operator elects this method of 

compliance, all VOC in such equipment shall be considered, for purposes of applicability and compliance with this 

subpart, as if it were organic hazardous air pollutant (HAP). Compliance with the provisions of this subpart, in the 

manner described in this paragraph, shall be deemed to constitute compliance with the standard identified in 

paragraph (c)(1), (c)(2), or (c)(3) of this section.

(1) 40 CFR part 60, subpart VV, GGG, or KKK; (2) 40 CFR part 61, subpart F or J; or (3) 40 CFR part 264, subpart 

BB or 40 CFR part 265, subpart BB.

(2) [Reserved]

(d) The provisions in §63.1(a)(3) of subpart A of this part do not alter the provisions in paragraph (b) of this section.
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060

Permit Reviewer: Josiah Balogun

(e) Except as provided in any subpart that references this subpart, lines and equipment not containing process fluids 

are not subject to the provisions of this subpart. Utilities, and other non-process lines, such as heating and cooling 

systems which do not combine their materials with those in the processes they serve, are not considered to be part of 

a process unit.

(f) The provisions of this subpart do not apply to research and development facilities or to bench-scale batch 

processes, regardless of whether the facilities or processes are located at the same plant site as a process subject to 

the provisions of this subpart.

(g) Alternative means of compliance —(1) Option to comply with part 65. Owners or operators of CMPU that are 

subject to §63.100 may choose to comply with the provisions of 40 CFR part 65 for all Group 1 and Group 2 process 

vents, Group 1 storage vessels, Group 1 transfer operations, and equipment that are subject to §63.100, that are part 

of the CMPU. Other provisions applying to an owner or operator who chooses to comply with 40 CFR part 65 are 

provided in 40 CFR 65.1.

(i) For equipment, 40 CFR part 65 satisfies the requirements of §§63.102, 63.103, and 63.162 through 63.182. When 

choosing to comply with 40 CFR part 65, the requirements of §63.180(d) continue to apply.

(ii) For Group 1 and Group 2 process vents, Group 1 storage vessels, and Group 1 transfer operations, comply with 

§63.110(i)(1).

(2) Part 65, subpart C or F. For owners or operators choosing to comply with 40 CFR part 65, each surge control 

vessel and bottoms receiver subject to §63.100 that meets the conditions specified in table 2 or table 3 of this subpart 

shall meet the requirements for storage vessels in 40 CFR part 65, subpart C; all other equipment subject to §63.100 

shall meet the requirements in 40 CFR part 65, subpart F.

(3) Part 63, subpart A. Owners or operators who choose to comply with 40 CFR part 65, subpart C or F, for 

equipment subject to §63.100 must also comply with the applicable general provisions of this part 63 listed in table 4 

of this subpart. All sections and paragraphs of subpart A of this part that are not mentioned in table 4 of this subpart 

do not apply to owners or operators of equipment subject to §63.100 of subpart F complying with 40 CFR part 65, 

subpart C or F, except that provisions required to be met prior to implementing 40 CFR part 65 still apply. Owners 

and operators who choose to comply with 40 CFR part 65, subpart C or F, must comply with 40 CFR part 65, subpart 

A.

[59 FR 19568, Apr. 22, 1994, as amended at 59 FR 48176, Sept. 20, 1994; 59 FR 53360, Oct. 24, 1994; 60 FR 

18029, Apr. 10, 1995; 61 FR 31439, June 20, 1996; 64 FR 20198, Apr. 26, 1999; 65 FR 78285, Dec. 14, 2000]

§ 63.161 Definitions.

All terms used in this subpart shall have the meaning given them in the Act and in this section as follows, except as 

provided in any subpart that references this subpart.

Batch process means a process in which the equipment is fed intermittently or discontinuously. Processing then 

occurs in this equipment after which the equipment is generally emptied. Examples of industries that use batch 

processes include pharmaceutical production and pesticide production.

Batch product-process equipment train means the collection of equipment (e.g., connectors, reactors, valves, pumps, 

etc.) configured to produce a specific product or intermediate by a batch process.

Bench-scale batch process means a batch process (other than a research and development facility) that is operated 

on a small scale, such as one capable of being located on a laboratory bench top. This bench-scale equipment will 

typically include reagent feed vessels, a small reactor and associated product separator, recovery and holding 

equipment. These processes are only capable of producing small quantities of product.

Bottoms receiver means a tank that collects distillation bottoms before the stream is sent for storage or for further 

downstream processing.
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060

Permit Reviewer: Josiah Balogun

Closed-loop system means an enclosed system that returns process fluid to the process and is not vented to the 

atmosphere except through a closed-vent system.

Closed-purge system means a system or combination of system and portable containers, to capture purged liquids. 

Containers must be covered or closed when not being filled or emptied.

Closed-vent system means a system that is not open to the atmosphere and that is composed of hard-piping, 

ductwork, connections and, if necessary, flow-inducing devices that transport gas or vapor from a piece or pieces of 

equipment to a control device or back into a process.

Combustion device means an individual unit of equipment, such as a flare, incinerator, process heater, or boiler, used 

for the combustion of organic hazardous air pollutant emissions.

Compliance date means the dates specified in §63.100(k) or §63.100(l)(3) of subpart F of this part for process units 

subject to subpart F of this part; the dates specified in §63.190(e) of subpart I of this part for process units subject to 

subpart I of this part. For sources subject to other subparts in 40 CFR part 63 that reference this subpart, compliance 

date will be defined in those subparts. However, the compliance date for §63.170 shall be no later than 3 years after 

the effective date of those subparts unless otherwise specified in such other subparts.

Connector means flanged, screwed, or other joined fittings used to connect two pipe lines or a pipe line and a piece 

of equipment. A common connector is a flange. Joined fittings welded completely around the circumference of the 

interface are not considered connectors for the purpose of this regulation. For the purpose of reporting and 

recordkeeping, connector means joined fittings that are not inaccessible, glass, or glass-lined as described in 

§63.174(h) of this subpart.

Control device means any equipment used for recovering, recapturing, or oxidizing organic hazardous air pollutant 

vapors. Such equipment includes, but is not limited to, absorbers, carbon adsorbers, condensers, flares, boilers, and 

process heaters.

Double block and bleed system means two block valves connected in series with a bleed valve or line that can vent 

the line between the two block valves.

Duct work means a conveyance system such as those commonly used for heating and ventilation systems. It is often 

made of sheet metal and often has sections connected by screws or crimping. Hard-piping is not ductwork.

Equipment means each pump, compressor, agitator, pressure relief device, sampling connection system, openended valve or line, valve, connector, surge control vessel, bottoms receiver, and instrumentation system in organic 

hazardous air pollutant service; and any control devices or systems required by this subpart.

First attempt at repair means to take action for the purpose of stopping or reducing leakage of organic material to the 

atmosphere, followed by monitoring as specified in §63.180 (b) and (c), as appropriate, to verify whether the leak is 

repaired, unless the owner or operator determines by other means that the leak is not repaired.

Flow indicator means a device which indicates whether gas flow is, or whether the valve position would allow gas flow 

to be, present in a line.

Fuel gas means gases that are combusted to derive useful work or heat.

Fuel gas system means the offsite and onsite piping and control system that gathers gaseous stream(s) generated by 

onsite operations, may blend them with other sources of gas, and transports the gaseous stream for use as fuel gas 

in combustion devices or in in-process combustion equipment such as furnaces and gas turbines, either singly or in 

combination.

Hard-piping means pipe or tubing that is manufactured and properly installed using good engineering judgement and 

standards, such as ANSI B31–3.
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060

Permit Reviewer: Josiah Balogun

In food/medical service means that a piece of equipment in organic hazardous air pollutant service contacts a 

process stream used to manufacture a Food and Drug Administration regulated product where leakage of a barrier 

fluid into the process stream would cause any of the following:

(1) A dilution of product quality so that the product would not meet written specifications,

(2) An exothermic reaction which is a safety hazard,

(3) The intended reaction to be slowed down or stopped, or

(4) An undesired side reaction to occur.

In gas/vapor service means that a piece of equipment in organic hazardous air pollutant service contains a gas or 

vapor at operating conditions.

In heavy liquid service means that a piece of equipment in organic hazardous air pollutant service is not in gas/vapor 

service or in light liquid service.

In light liquid service means that a piece of equipment in organic hazardous air pollutant service contains a liquid that 

meets the following conditions:

(1) The vapor pressure of one or more of the organic compounds is greater than 0.3 kilopascals at 20 °C,

(2) The total concentration of the pure organic compounds constituents having a vapor pressure greater than 0.3 

kilopascals at 20 °C is equal to or greater than 20 percent by weight of the total process stream, and

(3) The fluid is a liquid at operating conditions.

Note: Vapor pressures may be determined by the methods described in 40 CFR 60.485(e)(1).

In liquid service means that a piece of equipment in organic hazardous air pollutant service is not in gas/vapor 

service.

In organic hazardous air pollutant or in organic HAP service means that a piece of equipment either contains or 

contacts a fluid (liquid or gas) that is at least 5 percent by weight of total organic HAP's as determined according to 

the provisions of §63.180(d) of this subpart. The provisions of §63.180(d) of this subpart also specify how to 

determine that a piece of equipment is not in organic HAP service.

In vacuum service means that equipment is operating at an internal pressure which is at least 5 kilopascals below 

ambient pressure.

In volatile organic compound or in VOC service means, for the purposes of this subpart, that:

(1) The piece of equipment contains or contacts a process fluid that is at least 10 percent VOC by weight (see 40 

CFR 60.2 for the definition of VOC, and 40 CFR 60.485(d) to determine whether a piece of equipment is not in VOC 

service); and

(2) The piece of equipment is not in heavy liquid service as defined in 40 CFR 60.481.

In-situ sampling systems means nonextractive samplers or in-line samplers.

Initial start-up means the first time a new or reconstructed source begins production. Initial start-up does not include 

operation solely for testing equipment. Initial start-up does not include subsequent start-ups (as defined in this 

section) of process units following malfunctions or process unit shutdowns.
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060

Permit Reviewer: Josiah Balogun

Instrumentation system means a group of equipment components used to condition and convey a sample of the 

process fluid to analyzers and instruments for the purpose of determining process operating conditions (e.g., 

composition, pressure, flow, etc.). Valves and connectors are the predominant type of equipment used in 

instrumentation systems; however, other types of equipment may also be included in these systems. Only valves 

nominally 0.5 inches and smaller, and connectors nominally 0.75 inches and smaller in diameter are considered 

instrumentation systems for the purposes of this subpart. Valves greater than nominally 0.5 inches and connectors 

greater than nominally 0.75 inches associated with instrumentation systems are not considered part of 

instrumentation systems and must be monitored individually.

Liquids dripping means any visible leakage from the seal including dripping, spraying, misting, clouding, and ice 

formation. Indications of liquid dripping include puddling or new stains that are indicative of an existing evaporated 

drip.

Nonrepairable means that it is technically infeasible to repair a piece of equipment from which a leak has been 

detected without a process unit shutdown.

On-site or On site means, with respect to records required to be maintained by this subpart, that the records are 

stored at a location within a major source which encompasses the affected source. On-site includes, but is not limited 

to, storage at the chemical manufacturing process unit to which the records pertain, or storage in central files 

elsewhere at the major source.

Open-ended valve or line means any valve, except pressure relief valves, having one side of the valve seat in contact 

with process fluid and one side open to atmosphere, either directly or through open piping.

Plant site means all contiguous or adjoining property that is under common control, including properties that are 

separated only by a road or other public right-of-way. Common control includes properties that are owned, leased, or 

operated by the same entity, parent entity, subsidiary, or any combination thereof.

Polymerizing monomer means a molecule or compound usually containing carbon and of relatively low molecular 

weight and simple structure (e.g., hydrogen cyanide, acrylonitrile, styrene), which is capable of conversion to 

polymers, synthetic resins, or elastomers by combination with itself due to heat generation caused by a pump 

mechanical seal surface, contamination by a seal fluid (e.g., organic peroxides or chemicals that will form organic 

peroxides), or a combination of both with the resultant polymer buildup causing rapid mechanical seal failure.

Pressure release means the emission of materials resulting from the system pressure being greater than the set 

pressure of the pressure relief device. This release can be one release or a series of releases over a short time 

period due to a malfunction in the process.

Pressure relief device or valve means a safety device used to prevent operating pressures from exceeding the 

maximum allowable working pressure of the process equipment. A common pressure relief device is a spring-loaded 

pressure relief valve. Devices that are actuated either by a pressure of less than or equal to 2.5 psig or by a vacuum 

are not pressure relief devices.

Process unit means a chemical manufacturing process unit as defined in subpart F of this part, a process subject to 

the provisions of subpart I of this part, or a process subject to another subpart in 40 CFR part 63 that references this 

subpart.

Process unit shutdown means a work practice or operational procedure that stops production from a process unit or 

part of a process unit during which it is technically feasible to clear process material from a process unit or part of a 

process unit consistent with safety constraints and during which repairs can be effected. An unscheduled work 

practice or operational procedure that stops production from a process unit or part of a process unit for less than 24 

hours is not a process unit shutdown. An unscheduled work practice or operational procedure that would stop 

production from a process unit or part of a process unit for a shorter period of time than would be required to clear the 

process unit or part of the process unit of materials and start up the unit, and would result in greater emissions than 

delay of repair of leaking components until the next scheduled process unit shutdown, is not a process unit shutdown. 

The use of spare equipment and technically feasible bypassing of equipment without stopping production are not 

process unit shutdowns.
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Permit Reviewer: Josiah Balogun

Recapture device means an individual unit of equipment capable of and used for the purpose of recovering 

chemicals, but not normally for use, reuse, or sale. Recapture devices include, but are not limited to, absorbers, 

carbon absorbers, and condensers.

Recovery device means an individual unit of equipment capable of and normally used for the purpose of recovering 

chemicals for fuel value (i.e., net positive heating value), use, reuse, or for sale for fuel value, use or reuse. Recovery 

devices include, but are not limited to, absorbers, carbon absorbers, and condensers. For purposes of the monitoring, 

recordkeeping, and reporting requirements of this subpart, recapture devices are considered recovery devices.

Repaired means that equipment:

(1) Is adjusted, or otherwise altered, to eliminate a leak as defined in the applicable sections of this subpart, and

(2) Unless otherwise specified in applicable provisions of this subpart, is monitored as specified in §63.180 (b) and 

(c), as appropriate, to verify that emissions from the equipment are below the applicable leak definition.

Routed to a process or route to a process means the emissions are conveyed by hard-piping or a closed vent system 

to any enclosed portion of a process unit where the emissions are predominately recycled and/or consumed in the 

same manner as a material that fulfills the same function in the process; and/or transformed by chemical reaction into 

materials that are not organic hazardous air pollutants; and/or incorporated into a product; and/or recovered.

Sampling connection system means an assembly of equipment within a process unit used during periods of 

representative operation to take samples of the process fluid. Equipment used to take non-routine grab samples is 

not considered a sampling connection system.

Screwed connector means a threaded pipe fitting where the threads are cut on the pipe wall and the fitting requires 

only two pieces to make the connection (i.e., the pipe and the fitting).

Sensor means a device that measures a physical quantity or the change in a physical quantity, such as temperature, 

pressure, flow rate, pH, or liquid level.

Set pressure means the pressure at which a properly operating pressure relief device begins to open to relieve 

atypical process system operating pressure.

Start-up means the setting in operation of a piece of equipment or a control device that is subject to this subpart.

Surge control vessel means feed drums, recycle drums, and intermediate vessels. Surge control vessels are used 

within a process unit (as defined in the specific subpart that references this subpart) when in-process storage, mixing, 

or management of flow rates or volumes is needed to assist in production of a product.

[59 FR 19568, Apr. 22, 1994, as amended at 59 FR 48176, Sept. 20, 1994; 60 FR 18024, 18029, Apr. 10, 1995; 61 

FR 31439, June 20, 1996; 62 FR 2788, Jan. 17, 1997]

§ 63.162 Standards: General.

(a) Compliance with this subpart will be determined by review of the records required by §63.181 of this subpart and 

the reports required by §63.182 of this subpart, review of performance test results, and by inspections.

(b)(1) An owner or operator may request a determination of alternative means of emission limitation to the 

requirements of §§63.163 through 63.170, and §§63.172 through 63.174 of this subpart as provided in §63.177.

(2) If the Administrator makes a determination that a means of emission limitation is a permissible alternative to the 

requirements of §§63.163 through 63.170, and §§63.172 through 63.174 of this subpart, the owner or operator shall 

comply with the alternative.
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Permit Reviewer: Josiah Balogun

(c) Each piece of equipment in a process unit to which this subpart applies shall be identified such that it can be 

distinguished readily from equipment that is not subject to this subpart. Identification of the equipment does not 

require physical tagging of the equipment. For example, the equipment may be identified on a plant site plan, in log 

entries, or by designation of process unit boundaries by some form of weatherproof identification.

(d) Equipment that is in vacuum service is excluded from the requirements of this subpart.

(e) Equipment that is in organic HAP service less than 300 hours per calendar year is excluded from the 

requirements of §§63.163 through 63.174 of this subpart and §63.178 of this subpart if it is identified as required in 

§63.181(j) of this subpart.

(f) When each leak is detected as specified in §§63.163 and 63.164; §§63.168 and 63.169; and §§63.172 through 

63.174 of this subpart, the following requirements apply:

(1) Clearly identify the leaking equipment.

(2) The identification on a valve may be removed after it has been monitored as specified in §§63.168(f)(3), and 

63.175(e)(7)(i)(D) of this subpart, and no leak has been detected during the follow-up monitoring. If the owner or 

operator elects to comply using the provisions of §63.174(c)(1)(i) of this subpart, the identification on a connector may 

be removed after it is monitored as specified in §63.174(c)(1)(i) and no leak is detected during that monitoring.

(3) The identification which has been placed on equipment determined to have a leak, except for a valve or for a 

connector that is subject to the provisions of §63.174(c)(1)(i), may be removed after it is repaired.

(g) Except as provided in paragraph (g)(1) of this section, all terms in this subpart that define a period of time for 

completion of required tasks (e.g., weekly, monthly, quarterly, annual), refer to the standard calendar periods unless 

specified otherwise in the section or subsection that imposes the requirement.

(1) If the initial compliance date does not coincide with the beginning of the standard calendar period, an owner or 

operator may elect to utilize a period beginning on the compliance date, or may elect to comply in accordance with 

the provisions of paragraphs (g)(2) or (g)(3) of this section.

(2) Time periods specified in this subpart for completion of required tasks may be changed by mutual agreement 

between the owner or operator and the Administrator, as specified in subpart A of this part. For each time period that 

is changed by agreement, the revised period shall remain in effect until it is changed. A new request is not necessary 

for each recurring period.

(3) Except as provided in paragraph (g)(1) or (g)(2) of this section, where the period specified for compliance is a 

standard calendar period, if the initial compliance date does not coincide with the beginning of the calendar period, 

compliance shall be required according to the schedule specified in paragraphs (g)(3)(i) or (g)(3)(ii) of this section, as 

appropriate.

(i) Compliance shall be required before the end of the standard calendar period within which the compliance deadline 

occurs, if there remain at least 3 days for tasks that must be performed weekly, at least 2 weeks for tasks that must 

be performed monthly, at least 1 month for tasks that must be performed each quarter, or at least 3 months for tasks 

that must be performed annually; or

(ii) In all other cases, compliance shall be required before the end of the first full standard calendar period after the 

period within which the initial compliance deadline occurs.

(4) In all instances where a provision of this subpart requires completion of a task during each of multiple successive 

periods, an owner or operator may perform the required task at any time during each period, provided the task is 

conducted at a reasonable interval after completion of the task during the previous period.

(h) In all cases where the provisions of this subpart require an owner or operator to repair leaks by a specified time 

after the leak is detected, it is a violation of this subpart to fail to take action to repair the leaks within the specified

time. If action is taken to repair the leaks within the specified time, failure of that action to successfully repair the leak 
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is not a violation of this subpart. However, if the repairs are unsuccessful, a leak is detected and the owner or 

operator shall take further action as required by applicable provisions of this subpart.

[59 FR 19568, Apr. 22, 1994, as amended at 59 FR 48176, Sept. 20, 1994; 62 FR 2789, Jan. 17, 1997; 68 FR 37345, 

June 23, 2003]

§ 63.163 Standards: Pumps in light liquid service.

(a) The provisions of this section apply to each pump that is in light liquid service.

(1) The provisions are to be implemented on the dates specified in the specific subpart in 40 CFR part 63 that 

references this subpart in the phases specified below:

(i) For each group of existing process units at existing sources subject to the provisions of subparts F or I of this part, 

the phases of the standard are:

(A) Phase I, beginning on the compliance date;

(B) Phase II, beginning no later than 1 year after the compliance date; and

(C) Phase III, beginning no later than 21/2years after the compliance date.

(ii) For new sources subject to the provisions of subparts F or I of this part, the applicable phases of the standard are:

(A) After initial start-up, comply with the Phase II requirements; and

(B) Beginning no later than 1 year after initial start-up, comply with the Phase III requirements.

(2) The owner or operator of a source subject to the provisions of subparts F or I of this part may elect to meet the 

requirements of a later phase during the time period specified for an earlier phase.

(3) Sources subject to other subparts in 40 CFR part 63 that reference this subpart shall comply on the dates 

specified in the applicable subpart.

(b)(1) The owner or operator of a process unit subject to this subpart shall monitor each pump monthly to detect leaks 

by the method specified in §63.180(b) of this subpart and shall comply with the requirements of paragraphs (a) 

through (d) of this section, except as provided in §63.162(b) of this subpart and paragraphs (e) through (j) of this 

section.

(2) The instrument reading, as determined by the method as specified in §63.180(b) of this subpart, that defines a 

leak in each phase of the standard is:

(i) For Phase I, an instrument reading of 10,000 parts per million or greater.

(ii) For Phase II, an instrument reading of 5,000 parts per million or greater.

(iii) For Phase III, an instrument reading of:

(A) 5,000 parts per million or greater for pumps handling polymerizing monomers;

(B) 2,000 parts per million or greater for pumps in food/medical service; and

(C) 1,000 parts per million or greater for all other pumps.
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(3) Each pump shall be checked by visual inspection each calendar week for indications of liquids dripping from the 

pump seal. If there are indications of liquids dripping from the pump seal, a leak is detected.

(c)(1) When a leak is detected, it shall be repaired as soon as practicable, but not later than 15 calendar days after it 

is detected, except as provided in paragraph (c)(3) of this section or §63.171 of this subpart.

(2) A first attempt at repair shall be made no later than 5 calendar days after the leak is detected. First attempts at 

repair include, but are not limited to, the following practices where practicable:

(i) Tightening of packing gland nuts.

(ii) Ensuring that the seal flush is operating at design pressure and temperature.

(3) For pumps in Phase III to which a 1,000 parts per million leak definition applies, repair is not required unless an 

instrument reading of 2,000 parts per million or greater is detected.

(d)(1) The owner or operator shall decide no later than the first monitoring period whether to calculate percent leaking 

pumps on a process unit basis or on a source-wide basis. Once the owner or operator has decided, all subsequent 

percent calculations shall be made on the same basis.

(2) If, in Phase III, calculated on a 6-month rolling average, the greater of either 10 percent of the pumps in a process 

unit or three pumps in a process unit leak, the owner or operator shall implement a quality improvement program for 

pumps that complies with the requirements of §63.176 of this subpart.

(3) The number of pumps at a process unit shall be the sum of all the pumps in organic HAP service, except that 

pumps found leaking in a continuous process unit within 1 month after start-up of the pump shall not count in the 

percent leaking pumps calculation for that one monitoring period only.

(4) Percent leaking pumps shall be determined by the following equation:

%PL=((PL−PS)/(PT−PS))×100

where:

%PL=Percent leaking pumps

PL=Number of pumps found leaking as determined through monthly monitoring as required in paragraphs 

(b)(1) and (b)(2) of this section.

PT=Total pumps in organic HAP service, including those meeting the criteria in paragraphs (e) and (f) of

this section.

PS=Number of pumps leaking within 1 month of start-up during the current monitoring period.

(e) Each pump equipped with a dual mechanical seal system that includes a barrier fluid system is exempt from the 

requirements of paragraphs (a) through (d) of this section, provided the following requirements are met:

(1) Each dual mechanical seal system is:

(i) Operated with the barrier fluid at a pressure that is at all times greater than the pump stuffing box pressure; or

(ii) Equipped with a barrier fluid degassing reservoir that is routed to a process or fuel gas system or connected by a 

closed-vent system to a control device that complies with the requirements of §63.172 of this subpart; or
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(iii) Equipped with a closed-loop system that purges the barrier fluid into a process stream.

(2) The barrier fluid is not in light liquid service.

(3) Each barrier fluid system is equipped with a sensor that will detect failure of the seal system, the barrier fluid 

system, or both.

(4) Each pump is checked by visual inspection each calendar week for indications of liquids dripping from the pump 

seal.

(i) If there are indications of liquids dripping from the pump seal at the time of the weekly inspection, the pump shall 

be monitored as specified in §63.180(b) of this subpart to determine if there is a leak of organic HAP in the barrier 

fluid.

(ii) If an instrument reading of 1,000 parts per million or greater is measured, a leak is detected.

(5) Each sensor as described in paragraph (e)(3) of this section is observed daily or is equipped with an alarm unless 

the pump is located within the boundary of an unmanned plant site.

(6)(i) The owner or operator determines, based on design considerations and operating experience, criteria 

applicable to the presence and frequency of drips and to the sensor that indicates failure of the seal system, the 

barrier fluid system, or both.

(ii) If indications of liquids dripping from the pump seal exceed the criteria established in paragraph (e)(6)(i) of this 

section, or if, based on the criteria established in paragraph (e)(6)(i) of this section, the sensor indicates failure of the 

seal system, the barrier fluid system, or both, a leak is detected.

(iii) When a leak is detected, it shall be repaired as soon as practicable, but not later than 15 calendar days after it is 

detected, except as provided in §63.171 of this subpart.

(iv) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected.

(f) Any pump that is designed with no externally actuated shaft penetrating the pump housing is exempt from the 

requirements of paragraphs (a) through (c) of this section.

(g) Any pump equipped with a closed-vent system capable of capturing and transporting any leakage from the seal or 

seals to a process or to a fuel gas system or to a control device that complies with the requirements of §63.172 of this 

subpart is exempt from the requirements of paragraphs (b) through (e) of this section.

(h) Any pump that is located within the boundary of an unmanned plant site is exempt from the weekly visual 

inspection requirement of paragraphs (b)(3) and (e)(4) of this section, and the daily requirements of paragraph (e)(5) 

of this section, provided that each pump is visually inspected as often as practicable and at least monthly.

(i) If more than 90 percent of the pumps at a process unit meet the criteria in either paragraph (e) or (f) of this section, 

the process unit is exempt from the requirements of paragraph (d) of this section.

(j) Any pump that is designated, as described in §63.181(b)(7)(i) of this subpart, as an unsafe-to-monitor pump is 

exempt from the requirements of paragraphs (b) through (e) of this section if:

(1) The owner or operator of the pump determines that the pump is unsafe to monitor because monitoring personnel 

would be exposed to an immediate danger as a consequence of complying with paragraphs (b) through (d) of this 

section; and

(2) The owner or operator of the pump has a written plan that requires monitoring of the pump as frequently as 

practical during safe-to-monitor times, but not more frequently than the periodic monitoring schedule otherwise 

applicable.
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[59 FR 19568, Apr. 22, 1994, as amended at 59 FR 48176, Sept. 20, 1994; 61 FR 31439, June 20, 1996; 62 FR 

2789, Jan. 17, 1997; 64 FR 20198, Apr. 26, 1999]

§ 63.164 Standards: Compressors.

(a) Each compressor shall be equipped with a seal system that includes a barrier fluid system and that prevents 

leakage of process fluid to the atmosphere, except as provided in §63.162(b) of this subpart and paragraphs (h) and 

(i) of this section.

(b) Each compressor seal system as required in paragraph (a) of this section shall be:

(1) Operated with the barrier fluid at a pressure that is greater than the compressor stuffing box pressure; or

(2) Equipped with a barrier fluid system degassing reservoir that is routed to a process or fuel gas system or 

connected by a closed-vent system to a control device that complies with the requirements of §63.172 of this subpart; 

or

(3) Equipped with a closed-loop system that purges the barrier fluid directly into a process stream.

(c) The barrier fluid shall not be in light liquid service.

(d) Each barrier fluid system as described in paragraphs (a) through (c) of this section shall be equipped with a 

sensor that will detect failure of the seal system, barrier fluid system, or both.

(e)(1) Each sensor as required in paragraph (d) of this section shall be observed daily or shall be equipped with an 

alarm unless the compressor is located within the boundary of an unmanned plant site.

(2) The owner or operator shall determine, based on design considerations and operating experience, a criterion that 

indicates failure of the seal system, the barrier fluid system, or both.

(f) If the sensor indicates failure of the seal system, the barrier fluid system, or both based on the criterion determined 

under paragraph (e)(2) of this section, a leak is detected.

(g)(1) When a leak is detected, it shall be repaired as soon as practicable, but not later than 15 calendar days after it 

is detected, except as provided in §63.171 of this subpart.

(2) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected.

(h) A compressor is exempt from the requirements of paragraphs (a) through (g) of this section if it is equipped with a 

closed-vent system to capture and transport leakage from the compressor drive shaft seal back to a process or a fuel 

gas system or to a control device that complies with the requirements of §63.172 of this subpart.

(i) Any compressor that is designated, as described in §63.181(b)(2)(ii) of this subpart, to operate with an instrument 

reading of less than 500 parts per million above background, is exempt from the requirements of paragraphs (a) 

through (h) of this section if the compressor:

(1) Is demonstrated to be operating with an instrument reading of less than 500 parts per million above background, 

as measured by the method specified in §63.180(c) of this subpart; and

(2) Is tested for compliance with paragraph (i)(1) of this section initially upon designation, annually, and at other times 

requested by the Administrator.

[59 FR 19568, Apr. 22, 1994, as amended at 59 FR 48176, Sept. 20, 1994; 62 FR 2790, Jan. 17, 1997; 64 FR 20198, 

Apr. 26, 1999]
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§ 63.165 Standards: Pressure relief devices in gas/vapor service.

(a) Except during pressure releases, each pressure relief device in gas/vapor service shall be operated with an 

instrument reading of less than 500 parts per million above background except as provided in paragraph (b) of this 

section, as measured by the method specified in §63.180(c) of this subpart.

(b)(1) After each pressure release, the pressure relief device shall be returned to a condition indicated by an 

instrument reading of less than 500 parts per million above background, as soon as practicable, but no later than 5 

calendar days after each pressure release, except as provided in §63.171 of this subpart.

(2) No later than 5 calendar days after the pressure release and being returned to organic HAP service, the pressure 

relief device shall be monitored to confirm the condition indicated by an instrument reading of less than 500 parts per 

million above background, as measured by the method specified in §63.180(c) of this subpart.

(c) Any pressure relief device that is routed to a process or fuel gas system or equipped with a closed-vent system 

capable of capturing and transporting leakage from the pressure relief device to a control device as described in 

§63.172 of this subpart is exempt from the requirements of paragraphs (a) and (b) of this section.

(d)(1) Any pressure relief device that is equipped with a rupture disk upstream of the pressure relief device is exempt 

from the requirements of paragraphs (a) and (b) of this section, provided the owner or operator complies with the 

requirements in paragraph (d)(2) of this section.

(2) After each pressure release, a rupture disk shall be installed upstream of the pressure relief device as soon as 

practicable, but no later than 5 calendar days after each pressure release, except as provided in §63.171 of this 

subpart.

[59 FR 19568, Apr. 22, 1994, as amended at 59 FR 48176, Sept. 20, 1994; 62 FR 2790, Jan. 17, 1997]

§ 63.166 Standards: Sampling connection systems.

(a) Each sampling connection system shall be equipped with a closed-purge, closed-loop, or closed-vent system, 

except as provided in §63.162(b) of this subpart. Gases displaced during filling of the sample container are not 

required to be collected or captured.

(b) Each closed-purge, closed-loop, or closed-vent system as required in paragraph (a) of this section shall:

(1) Return the purged process fluid directly to the process line; or

(2) Collect and recycle the purged process fluid to a process; or

(3) Be designed and operated to capture and transport the purged process fluid to a control device that complies with 

the requirements of §63.172 of this subpart; or

(4) Collect, store, and transport the purged process fluid to a system or facility identified in paragraph (b)(4)(i), (ii), or 

(iii) of this section.

(i) A waste management unit as defined in §63.111 of subpart G of this part, if the waste management unit is subject 

to, and operated in compliance with the provisions of subpart G of this part applicable to group 1 wastewater streams. 

If the purged process fluid does not contain any organic HAP listed in Table 9 of subpart G of part 63, the waste 

management unit need not be subject to, and operated in compliance with the requirements of 40 CFR part 63, 

subpart G applicable to group 1 wastewater streams provided the facility has an NPDES permit or sends the 

wastewater to an NPDES permitted facility.

(ii) A treatment, storage, or disposal facility subject to regulation under 40 CFR part 262, 264, 265, or 266; or
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(iii) A facility permitted, licensed, or registered by a State to manage municipal or industrial solid waste, if the process 

fluids are not hazardous waste as defined in 40 CFR part 261.

(c) In-situ sampling systems and sampling systems without purges are exempt from the requirements of paragraphs 

(a) and (b) of this section.

[59 FR 19568, Apr. 22, 1994, as amended at 61 FR 31439, June 20, 1996]

§ 63.167 Standards: Open-ended valves or lines.

(a)(1) Each open-ended valve or line shall be equipped with a cap, blind flange, plug, or a second valve, except as 

provided in §63.162(b) of this subpart and paragraphs (d) and (e) of this section.

(2) The cap, blind flange, plug, or second valve shall seal the open end at all times except during operations requiring 

process fluid flow through the open-ended valve or line, or during maintenance or repair.

(b) Each open-ended valve or line equipped with a second valve shall be operated in a manner such that the valve on 

the process fluid end is closed before the second valve is closed.

(c) When a double block and bleed system is being used, the bleed valve or line may remain open during operations 

that require venting the line between the block valves but shall comply with paragraph (a) of this section at all other 

times.

(d) Open-ended valves or lines in an emergency shutdown system which are designed to open automatically in the 

event of a process upset are exempt from the requirements of paragraphs (a), (b) and (c) of this section.

(e) Open-ended valves or lines containing materials which would autocatalytically polymerize or, would present an 

explosion, serious overpressure, or other safety hazard if capped or equipped with a double block and bleed system 

as specified in paragraphs (a) through (c) of this section are exempt from the requirements of paragraph (a) through 

(c) of this section.

[59 FR 19568, Apr. 22, 1994, as amended at 61 FR 31440, June 20, 1996]

§ 63.168 Standards: Valves in gas/vapor service and in light liquid service.

(a) The provisions of this section apply to valves that are either in gas service or in light liquid service.

(1) The provisions are to be implemented on the dates set forth in the specific subpart in 40 CFR part 63 that 

references this subpart as specified in paragraph (a)(1)(i), (a)(1)(ii), or (a)(1)(iii) of this section.

(i) For each group of existing process units at existing sources subject to the provisions of subpart F or I of this part, 

the phases of the standard are:

(A) Phase I, beginning on the compliance date;

(B) Phase II, beginning no later than 1 year after the compliance date; and

(C) Phase III, beginning no later than 21/2years after the compliance date.

(ii) For new sources subject to the provisions of subpart F or I of this part, the applicable phases of the standard are:

(A) After initial start-up, comply with the Phase II requirements; and

(B) Beginning no later than 1 year after initial start-up, comply with the Phase III requirements.
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(iii) Sources subject to other subparts in 40 CFR part 63 that reference this subpart shall comply on the dates 

specified in the applicable subpart.

(2) The owner or operator of a source subject to this subpart may elect to meet the requirements of a later phase 

during the time period specified for an earlier phase.

(3) The use of monitoring data generated before April 22, 1994 to qualify for less frequent monitoring is governed by 

the provisions of §63.180(b)(6) of this subpart.

(b) The owner or operator of a source subject to this subpart shall monitor all valves, except as provided in 

§63.162(b) of this subpart and paragraphs (h) and (i) of this section, at the intervals specified in paragraphs (c) and 

(d) of this section and shall comply with all other provisions of this section, except as provided in §63.171, §63.177, 

§63.178, and §63.179 of this subpart.

(1) The valves shall be monitored to detect leaks by the method specified in §63.180(b) of this subpart.

(2) The instrument reading that defines a leak in each phase of the standard is:

(i) For Phase I, an instrument reading of 10,000 parts per million or greater.

(ii) For Phase II, an instrument reading of 500 parts per million or greater.

(iii) For Phase III, an instrument reading of 500 parts per million or greater.

(c) In Phases I and II, each valve shall be monitored quarterly.

(d) In Phase III, the owner or operator shall monitor valves for leaks at the intervals specified below:

(1) At process units with 2 percent or greater leaking valves, calculated according to paragraph (e) of this section, the 

owner or operator shall either:

(i) Monitor each valve once per month; or

(ii) Within the first year after the onset of Phase III, implement a quality improvement program for valves that complies 

with the requirements of §63.175 (d) or (e) of this subpart and monitor quarterly.

(2) At process units with less than 2 percent leaking valves, the owner or operator shall monitor each valve once each 

quarter, except as provided in paragraphs (d)(3) and (d)(4) of this section.

(3) At process units with less than 1 percent leaking valves, the owner or operator may elect to monitor each valve 

once every 2 quarters.

(4) At process units with less than 0.5 percent leaking valves, the owner or operator may elect to monitor each valve 

once every 4 quarters.

(e)(1) Percent leaking valves at a process unit shall be determined by the following equation:

%VL=(VL/(VT+VC))×100

where:

%VL=Percent leaking valves as determined through periodic monitoring required in paragraphs (b) 

through (d) of this section.
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VL=Number of valves found leaking excluding nonrepairables as provided in paragraph (e)(3)(i) of this 

section.

VT=Total valves monitored, in a monitoring period excluding valves monitored as required by (f)(3) of this 

section.

VC=Optional credit for removed valves=0.67 × net number (i.e., total removed−total added) of valves in 

organic HAP service removed from process unit after the date set forth in §63.100(k) of subpart F for 

existing process units, and after the date of initial start-up for new sources. If credits are not taken, then 

VC=0.

(2) For use in determining monitoring frequency, as specified in paragraph (d) of this section, the percent leaking 

valves shall be calculated as a rolling average of two consecutive monitoring periods for monthly, quarterly, or 

semiannual monitoring programs; and as an average of any three out of four consecutive monitoring periods for 

annual monitoring programs.

(3)(i) Nonrepairable valves shall be included in the calculation of percent leaking valves the first time the valve is 

identified as leaking and nonrepairable and as required to comply with paragraph (e)(3)(ii) of this section. Otherwise, 

a number of nonrepairable valves (identified and included in the percent leaking calculation in a previous period) up 

to a maximum of 1 percent of the total number of valves in organic HAP service at a process unit may be excluded 

from calculation of percent leaking valves for subsequent monitoring periods.

(ii) If the number of nonrepairable valves exceeds 1 percent of the total number of valves in organic HAP service at a 

process unit, the number of nonrepairable valves exceeding 1 percent of the total number of valves in organic HAP 

service shall be included in the calculation of percent leaking valves.

(f)(1) When a leak is detected, it shall be repaired as soon as practicable, but no later than 15 calendar days after the 

leak is detected, except as provided in §63.171 of this subpart.

(2) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected.

(3) When a leak has been repaired, the valve shall be monitored at least once within the first 3 months after its repair.

(i) The monitoring shall be conducted as specified in §63.180 (b) and (c), as appropriate, to determine whether the 

valve has resumed leaking.

(ii) Periodic monitoring required by paragraphs (b) through (d) of this section may be used to satisfy the requirements 

of this paragraph (f)(3), if the timing of the monitoring period coincides with the time specified in this paragraph (f)(3). 

Alternatively, other monitoring may be performed to satisfy the requirements of this paragraph (f)(3), regardless of 

whether the timing of the monitoring period for periodic monitoring coincides with the time specified in this paragraph 

(f)(3).

(iii) If a leak is detected by monitoring that is conducted pursuant to paragraph (f)(3) of this section, the owner or 

operator shall follow the provisions of paragraphs (f)(3)(iii)(A) and (f)(3)(iii)(B) of this section, to determine whether 

that valve must be counted as a leaking valve for purposes of §63.168(e) of this subpart.

(A) If the owner or operator elected to use periodic monitoring required by paragraphs (b) through (d) of this section 

to satisfy the requirements of paragraph (f)(3) of this section, then the valve shall be counted as a leaking valve.

(B) If the owner or operator elected to use other monitoring, prior to the periodic monitoring required by paragraphs 

(b) through (d) of this section, to satisfy the requirements of paragraph (f)(3) of this section, then the valve shall be 

counted as a leaking valve unless it is repaired and shown by periodic monitoring not to be leaking.

(g) First attempts at repair include, but are not limited to, the following practices where practicable:

(1) Tightening of bonnet bolts,
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(2) Replacement of bonnet bolts,

(3) Tightening of packing gland nuts, and

(4) Injection of lubricant into lubricated packing.

(h) Any valve that is designated, as described in §63.181(b)(7)(i) of this subpart, as an unsafe-to-monitor valve is 

exempt from the requirements of paragraphs (b) through (f) of this section if:

(1) The owner or operator of the valve determines that the valve is unsafe to monitor because monitoring personnel 

would be exposed to an immediate danger as a consequence of complying with paragraphs (b) through (d) of this 

section; and

(2) The owner or operator of the valve has a written plan that requires monitoring of the valve as frequently as 

practicable during safe-to-monitor times, but not more frequently than the periodic monitoring schedule otherwise 

applicable.

(i) Any valve that is designated, as described in §63.181(b)(7)(ii) of this subpart, as a difficult-to-monitor valve is 

exempt from the requirements of paragraphs (b) through (d) of this section if:

(1) The owner or operator of the valve determines that the valve cannot be monitored without elevating the monitoring 

personnel more than 2 meters above a support surface or it is not accessible at anytime in a safe manner;

(2) The process unit within which the valve is located is an existing source or the owner or operator designates less 

than 3 percent of the total number of valves in a new source as difficult-to-monitor; and

(3) The owner or operator of the valve follows a written plan that requires monitoring of the valve at least once per 

calendar year.

(j) Any equipment located at a plant site with fewer than 250 valves in organic HAP service is exempt from the 

requirements for monthly monitoring and a quality improvement program specified in paragraph (d)(1) of this section. 

Instead, the owner or operator shall monitor each valve in organic HAP service for leaks once each quarter, or 

comply with paragraph (d)(3) or (d)(4) of this section except as provided in paragraphs (h) and (i) of this section.

[59 FR 19568, Apr. 22, 1994, as amended at 59 FR 48176, Sept. 20, 1994; 61 FR 31440, June 20, 1996; 62 FR 

2790, Jan. 17, 1997]

§ 63.169 Standards: Pumps, valves, connectors, and agitators in heavy 

liquid service; instrumentation systems; and pressure relief devices in 

liquid service.

(a) Pumps, valves, connectors, and agitators in heavy liquid service, pressure relief devices in light liquid or heavy 

liquid service, and instrumentation systems shall be monitored within 5 calendar days by the method specified in 

§63.180(b) of this subpart if evidence of a potential leak to the atmosphere is found by visual, audible, olfactory, or 

any other detection method. If such a potential leak is repaired as required in paragraphs (c) and (d) of this section, it 

is not necessary to monitor the system for leaks by the method specified in §63.180(b) of this subpart.

(b) If an instrument reading of 10,000 parts per million or greater for agitators, 5,000 parts per million or greater for 

pumps handling polymerizing monomers, 2,000 parts per million or greater for all other pumps (including pumps in 

food/medical service), or 500 parts per million or greater for valves, connectors, instrumentation systems, and 

pressure relief devices is measured, a leak is detected.

(c)(1) When a leak is detected, it shall be repaired as soon as practicable, but not later than 15 calendar days after it 

is detected, except as provided in §63.171 of this subpart.
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(2) The first attempt at repair shall be made no later than 5 calendar days after each leak is detected.

(3) For equipment identified in paragraph (a) of this section that is not monitored by the method specified in 

§63.180(b), repaired shall mean that the visual, audible, olfactory, or other indications of a leak to the atmosphere 

have been eliminated; that no bubbles are observed at potential leak sites during a leak check using soap solution; or 

that the system will hold a test pressure.

(d) First attempts at repair include, but are not limited to, the practices described under §§63.163(c)(2) and 63.168(g) 

of this subpart, for pumps and valves, respectively.

[59 FR 19568, Apr. 22, 1994, as amended at 59 FR 48177, Sept. 20, 1994; 60 FR 18029, Apr. 10, 1995; 62 FR 2790, 

Jan. 17, 1997; 65 FR 78285, Dec. 14, 2000]

§ 63.170 Standards: Surge control vessels and bottoms receivers.

Each surge control vessel or bottoms receiver that is not routed back to the process and that meets the conditions 

specified in table 2 or table 3 of this subpart shall be equipped with a closed-vent system that routes the organic 

vapors vented from the surge control vessel or bottoms receiver back to the process or to a control device that 

complies with the requirements in §63.172 of this subpart, except as provided in §63.162(b) of this subpart, or comply 

with the requirements of §63.119(b) or (c) of subpart G of this part.

[60 FR 18024, Apr. 10, 1995]

§ 63.171 Standards: Delay of repair.

(a) Delay of repair of equipment for which leaks have been detected is allowed if repair within 15 days is technically 

infeasible without a process unit shutdown. Repair of this equipment shall occur by the end of the next process unit 

shutdown.

(b) Delay of repair of equipment for which leaks have been detected is allowed for equipment that is isolated from the 

process and that does not remain in organic HAP service.

(c) Delay of repair for valves, connectors, and agitators is also allowed if:

(1) The owner or operator determines that emissions of purged material resulting from immediate repair would be 

greater than the fugitive emissions likely to result from delay of repair, and

(2) When repair procedures are effected, the purged material is collected and destroyed or recovered in a control 

device complying with §63.172 of this subpart.

(d) Delay of repair for pumps is also allowed if:

(1) Repair requires replacing the existing seal design with a new system that the owner or operator has determined 

under the provisions of §63.176(d) of this subpart will provide better performance or:

(i) A dual mechanical seal system that meets the requirements of §63.163(e) of this subpart,

(ii) A pump that meets the requirements of §63.163(f) of this subpart, or

(iii) A closed-vent system and control device that meets the requirements of §63.163(g) of this subpart; and

(2) Repair is completed as soon as practicable, but not later than 6 months after the leak was detected.

(e) Delay of repair beyond a process unit shutdown will be allowed for a valve if valve assembly replacement is 

necessary during the process unit shutdown, valve assembly supplies have been depleted, and valve assembly 
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supplies had been sufficiently stocked before the supplies were depleted. Delay of repair beyond the second process 

unit shutdown will not be allowed unless the third process unit shutdown occurs sooner than 6 months after the first 

process unit shutdown.

[59 FR 19568, Apr. 22, 1994, as amended at 59 FR 48177, Sept. 20, 1994; 65 FR 78285, Dec. 14, 2000]

§ 63.172 Standards: Closed-vent systems and control devices.

(a) Owners or operators of closed-vent systems and control devices used to comply with provisions of this subpart 

shall comply with the provisions of this section, except as provided in §63.162(b) of this subpart.

(b) Recovery or recapture devices (e.g., condensers and absorbers) shall be designed and operated to recover the 

organic hazardous air pollutant emissions or volatile organic compounds emissions vented to them with an efficiency 

of 95 percent or greater, or to an exit concentration of 20 parts par million by volume, whichever is less stringent. The 

20 parts per million by volume performance standard is not applicable to the provisions of §63.179.

(c) Enclosed combustion devices shall be designed and operated to reduce the organic hazardous air pollutant 

emissions or volatile organic compounds emissions vented to them with an efficiency of 95 percent or greater, or to 

an exit concentration of 20 parts per million by volume, on a dry basis, corrected to 3 percent oxygen, whichever is 

less stringent, or to provide a minimum residence time of 0.50 seconds at a minimum temperature of 760 °C.

(d) Flares used to comply with this subpart shall comply with the requirements of §63.11(b) of subpart A of this part.

(e) Owners or operators of control devices that are used to comply with the provisions of this subpart shall monitor 

these control devices to ensure that they are operated and maintained in conformance with their design.

Note: The intent of this provision is to ensure proper operation and maintenance of the control device.

(f) Except as provided in paragraphs (k) and (l) of this section, each closed-vent system shall be inspected according 

to the procedures and schedule specified in paragraphs (f)(1) and (f)(2) of this section.

(1) If the closed-vent system is constructed of hard-piping, the owner or operator shall:

(i) Conduct an initial inspection according to the procedures in paragraph (g) of this section, and

(ii) Conduct annual visual inspections for visible, audible, or olfactory indications of leaks.

(2) If the vapor collection system or closed-vent system is constructed of duct work, the owner or operator shall:

(i) Conduct an initial inspection according to the procedures in paragraph (g) of this section, and

(ii) Conduct annual inspections according to the procedures in paragraph (g) of this section.

(g) Each closed-vent system shall be inspected according to the procedures in §63.180(b) of this subpart.

(h) Leaks, as indicated by an instrument reading greater than 500 parts per million above background or by visual 

inspections, shall be repaired as soon as practicable, except as provided in paragraph (i) of this section.

(1) A first attempt at repair shall be made no later than 5 calendar days after the leak is detected.

(2) Repair shall be completed no later than 15 calendar days after the leak is detected, except as provided in 

paragraph (i) of this section.

(i) Delay of repair of a closed-vent system for which leaks have been detected is allowed if the repair is technically 

infeasible without a process unit shutdown or if the owner or operator determines that emissions resulting from 
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immediate repair would be greater than the fugitive emissions likely to result from delay of repair. Repair of such 

equipment shall be complete by the end of the next process unit shutdown.

(j) For each closed-vent system that contains bypass lines that could divert a vent stream away from the control 

device and to the atmosphere, the owner or operator shall comply with the provisions of either paragraph (j)(1) or 

(j)(2) of this section, except as provided in paragraph (j)(3) of this section.

(1) Install, set or adjust, maintain, and operate a flow indicator that takes a reading at least once every 15 minutes. 

Records shall be generated as specified in §63.118(a)(3) of subpart G of this part. The flow indicator shall be installed 

at the entrance to any bypass line; or

(2) Secure the bypass line valve in the non-diverting position with a car-seal or a lock-and-key type configuration. A 

visual inspection of the seal or closure mechanism shall be performed at least once every month to ensure the valve 

is maintained in the non-diverting position and the vent stream is not diverted through the bypass line.

(3) Equipment such as low leg drains, high point bleeds, analyzer vents, open-ended valves or lines, and pressure 

relief valves needed for safety purposes are not subject to this paragraph.

(k) Any parts of the closed-vent system that are designated, as described in paragraph 63.181(b)(7)(i), as unsafe to 

inspect are exempt from the inspection requirements of paragraphs (f)(1) and (f)(2) of this section if:

(1) The owner or operator determines that the equipment is unsafe to inspect because inspecting personnel would be 

exposed to an imminent or potential danger as a consequence of complying with paragraph (f)(1) or (f)(2) of this 

section; and

(2) The owner or operator has a written plan that requires inspection of the equipment as frequently as practicable 

during safe-to-inspect times, but not more frequently than annually.

(l) Any parts of the closed-vent system that are designated, as described in §63.181 (b)(7)(i) of this subpart, as 

difficult to inspect are exempt from the inspection requirements of paragraphs (f)(1) and (f)(2) of this section if:

(1) The owner or operator determines that the equipment cannot be inspected without elevating the inspecting 

personnel more than 2 meters above a support surface; and

(2) The owner or operator has a written plan that requires inspection of the equipment at least once every 5 years.

(m) Whenever organic HAP emissions are vented to a closed-vent system or control device used to comply with the 

provisions of this subpart, such system or control device shall be operating.

(n) After the compliance dates specified in §63.100 of subpart F of this part, the owner or operator of any control 

device subject to this subpart that is also subject to monitoring, recordkeeping, and reporting requirements in 40 CFR 

part 264, subpart BB, or is subject to monitoring and recordkeeping requirements in 40 CFR part 265, subpart BB, 

may elect to comply either with the monitoring, recordkeeping, and reporting requirements of this subpart, or with the 

monitoring, recordkeeping, and reporting requirements in 40 CFR parts 264 and/or 265, as described in this 

paragraph, which shall constitute compliance with the monitoring, recordkeeping and reporting requirements of this 

subpart. The owner or operator shall identify which option has been chosen, in the next periodic report required by 

§63.182(d).

[59 FR 19568, Apr. 22, 1994, as amended at 59 FR 48177, Sept. 20, 1994; 61 FR 31440, June 20, 1996; 62 FR 

2790, Jan. 17, 1997]

§ 63.173 Standards: Agitators in gas/vapor service and in light liquid 

service.

(a)(1) Each agitator shall be monitored monthly to detect leaks by the methods specified in §63.180(b) of this subpart, 

except as provided in §63.162(b) of this subpart.
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(2) If an instrument reading of 10,000 parts per million or greater is measured, a leak is detected.

(b)(1) Each agitator shall be checked by visual inspection each calendar week for indications of liquids dripping from 

the agitator.

(2) If there are indications of liquids dripping from the agitator, a leak is detected.

(c)(1) When a leak is detected, it shall be repaired as soon as practicable, but not later than 15 calendar days after it 

is detected, except as provided in §63.171 of this subpart.

(2) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected.

(d) Each agitator equipped with a dual mechanical seal system that includes a barrier fluid system is exempt from the 

requirements of paragraph (a) of this section, provided the requirements specified in paragraphs (d)(1) through (d)(6) 

of this section are met:

(1) Each dual mechanical seal system is:

(i) Operated with the barrier fluid at a pressure that is at all times greater than the agitator stuffing box pressure; or

(ii) Equipped with a barrier fluid degassing reservoir that is routed to a process or fuel gas system or connected by a 

closed-vent system to a control device that complies with the requirements of §63.172 of this subpart; or

(iii) Equipped with a closed-loop system that purges the barrier fluid into a process stream.

(2) The barrier fluid is not in light liquid organic HAP service.

(3) Each barrier fluid system is equipped with a sensor that will detect failure of the seal system, the barrier fluid 

system, or both.

(4) Each agitator is checked by visual inspection each calendar week for indications of liquids dripping from the 

agitator seal.

(i) If there are indications of liquids dripping from the agitator seal at the time of the weekly inspection, the agitator 

shall be monitored as specified in §63.180(b) of this subpart to determine the presence of organic HAP in the barrier 

fluid.

(ii) If an instrument reading of 10,000 parts per million or greater is measured, a leak is detected.

(5) Each sensor as described in paragraph (d)(3) of this section is observed daily or is equipped with an alarm unless 

the agitator is located within the boundary of an unmanned plant site.

(6)(i) The owner or operator determines, based on design considerations and operating experience, criteria 

applicable to the presence and frequency of drips and to the sensor that indicates failure of the seal system, the 

barrier fluid system, or both.

(ii) If indications of liquids dripping from the agitator seal exceed the criteria established in paragraph (d)(6)(i) of this

section, or if, based on the criteria established in paragraph (d)(6)(i) of this section, the sensor indicates failure of the 

seal system, the barrier fluid system, or both, a leak is detected.

(iii) When a leak is detected, it shall be repaired as soon as practicable, but not later than 15 calendar days after it is 

detected, except as provided in §63.171 of this subpart.

(iv) A first attempt at repair shall be made no later than 5 calendar days after each leak is detected.
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(e) Any agitator that is designed with no externally actuated shaft penetrating the agitator housing is exempt from 

paragraphs (a) through (c) of this section.

(f) Any agitator equipped with a closed-vent system capable of capturing and transporting any leakage from the seal 

or seals to a process or fuel gas system or to a control device that complies with the requirements of §63.172 of this 

subpart is exempt from the requirements of paragraphs (a) through (c) of the section.

(g) Any agitator that is located within the boundary of an unmanned plant site is exempt from the weekly visual 

inspection requirement of paragraphs (b)(1) and (d)(4) of this section, and the daily requirements of paragraph (d)(5) 

of this section, provided that each agitator is visually inspected as often as practical and at least monthly.

(h) Any agitator that is difficult-to-monitor is exempt from the requirements of paragraphs (a) through (d) of this 

section if:

(1) The owner or operator determines that the agitator cannot be monitored without elevating the monitoring 

personnel more than two meters above a support surface or it is not accessible at anytime in a safe manner;

(2) The process unit within which the agitator is located is an existing source or the owner or operator designates less 

than three percent of the total number of agitators in a new source as difficult-to-monitor; and

(3) The owner or operator follows a written plan that requires monitoring of the agitator at least once per calendar 

year.

(i) Any agitator that is obstructed by equipment or piping that prevents access to the agitator by a monitor probe is 

exempt from the monitoring requirements of paragraphs (a) through (d) of this section.

(j) Any agitator that is designated, as described in §63.181(b)(7)(i) of this subpart, as an unsafe-to-monitor agitator is 

exempt from the requirements of paragraphs (a) through (d) of this section if:

(1) The owner or operator of the agitator determines that the agitator is unsafe to monitor because monitoring 

personnel would be exposed to an immediate danger as a consequence of complying with paragraphs (a) through (d) 

of this section; and

(2) The owner or operator of the agitator has a written plan that requires monitoring of the agitator as frequently as 

practical during safe-to-monitor times, but not more frequently than the periodic monitoring schedule otherwise 

applicable.

[59 FR 19568, Apr. 22, 1994, as amended at 61 FR 31440, June 20, 1996; 62 FR 2791, Jan. 17, 1997; 64 FR 20198, 

Apr. 26, 1999]

§ 63.174 Standards: Connectors in gas/vapor service and in light liquid 

service.

(a) The owner or operator of a process unit subject to this subpart shall monitor all connectors in gas/vapor and light 

liquid service, except as provided in §63.162(b) of this subpart, and in paragraphs (f) through (h) of this section, at the 

intervals specified in paragraph (b) of this section.

(1) The connectors shall be monitored to detect leaks by the method specified in §63.180(b) of this subpart.

(2) If an instrument reading greater than or equal to 500 parts per million is measured, a leak is detected.

(b) The owner or operator shall monitor for leaks at the intervals specified in either paragraph (b)(1) or (b)(2) of this 

section and in paragraph (b)(3) of this section.
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(1) For each group of existing process units within an existing source, by no later than 12 months after the 

compliance date, the owner or operator shall monitor all connectors, except as provided in paragraphs (f) through (h) 

of this section.

(2) For new sources, within the first 12 months after initial start-up or by no later than 12 months after the date of 

promulgation of a specific subpart that references this subpart, whichever is later, the owner or operator shall monitor 

all connectors, except as provided in paragraphs (f) through (h) of this section.

(3) After conducting the initial survey required in paragraph (b)(1) or (b)(2) of this section, the owner or operator shall 

perform all subsequent monitoring of connectors at the frequencies specified in paragraphs (b)(3)(i) through (b)(3)(v) 

of this section, except as provided in paragraph (c)(2) of this section:

(i) Once per year (i.e., 12-month period), if the percent leaking connectors in the process unit was 0.5 percent or 

greater during the last required annual or biennial monitoring period.

(ii) Once every 2 years, if the percent leaking connectors was less than 0.5 percent during the last required 

monitoring period. An owner or operator may comply with this paragraph by monitoring at least 40 percent of the 

connectors in the first year and the remainder of the connectors in the second year. The percent leaking connectors 

will be calculated for the total of all monitoring performed during the 2-year period.

(iii) If the owner or operator of a process unit in a biennial leak detection and repair program calculates less than 0.5 

percent leaking connectors from the 2-year monitoring period, the owner or operator may monitor the connectors one 

time every 4 years. An owner or operator may comply with the requirements of this paragraph by monitoring at least 

20 percent of the connectors each year until all connectors have been monitored within 4 years.

(iv) If a process unit complying with the requirements of paragraph (b) of this section using a 4-year monitoring 

interval program has greater than or equal to 0.5 percent but less than 1 percent leaking connectors, the owner or 

operator shall increase the monitoring frequency to one time every 2 years. An owner or operator may comply with 

the requirements of this paragraph by monitoring at least 40 percent of the connectors in the first year and the 

remainder of the connectors in the second year. The owner or operator may again elect to use the provisions of 

paragraph (b)(3)(iii) of this section when the percent leaking connectors decreases to less than 0.5 percent.

(v) If a process unit complying with requirements of paragraph (b)(3)(iii) of this section using a 4-year monitoring 

interval program has 1 percent or greater leaking connectors, the owner or operator shall increase the monitoring 

frequency to one time per year. The owner or operator may again elect to use the provisions of paragraph (b)(3)(iii) of 

this section when the percent leaking connectors decreases to less than 0.5 percent.

(4) The use of monitoring data generated before April 22, 1994 to qualify for less frequent monitoring is governed by 

the provisions of §63.180(b)(6).

(c)(1)(i) Except as provided in paragraph (c)(1)(ii) of this section, each connector that has been opened or has 

otherwise had the seal broken shall be monitored for leaks when it is reconnected or within the first 3 months after 

being returned to organic hazardous air pollutants service. If the monitoring detects a leak, it shall be repaired 

according to the provisions of paragraph (d) of this section, unless it is determined to be nonrepairable, in which case 

it is counted as a nonrepairable connector for the purposes of paragraph (i)(2) of this section.

(ii) As an alternative to the requirements in paragraph (c)(1)(i) of this section, an owner or operator may choose not to 

monitor connectors that have been opened or otherwise had the seal broken. In this case, the owner or operator may 

not count nonrepairable connectors for the purposes of paragraph (i)(2) of this section. The owner or operator shall 

calculate the percent leaking connectors for the monitoring periods described in paragraph (b) of this section, by 

setting the nonrepairable component, CAN, in the equation in paragraph (i)(2) of this section to zero for all monitoring 

periods.

(iii) An owner or operator may switch alternatives described in paragraphs (c)(1) (i) and (ii) of this section at the end 

of the current monitoring period he is in, provided that it is reported as required in §63.182 of this subpart and begin 

the new alternative in annual monitoring. The initial monitoring in the new alternative shall be completed no later than 

12 months after reporting the switch.
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(2) As an alternative to the requirements of paragraph (b)(3) of this section, each screwed connector 2 inches or less 

in nominal inside diameter installed in a process unit before the dates specified in paragraph (c)(2)(iii) or (c)(2)(iv) of 

this section may:

(i) Comply with the requirements of §63.169 of this subpart, and

(ii) Be monitored for leaks within the first 3 months after being returned to organic hazardous air pollutants service 

after having been opened or otherwise had the seal broken. If that monitoring detects a leak, it shall be repaired 

according to the provisions of paragraph (d) of this section.

(iii) For sources subject to subparts F and I of this part, the provisions of paragraph (c)(2) of this section apply to 

screwed connectors installed before December 31, 1992.

(iv) For sources not identified in paragraph (c)(2)(iii) of this section, the provisions of paragraph (c)(2) of this section 

apply to screwed connectors installed before the date of proposal of the applicable subpart of this part that references 

this subpart.

(d) When a leak is detected, it shall be repaired as soon as practicable, but no later than 15 calendar days after the 

leak is detected, except as provided in paragraph (g) of this section and in §63.171 of this subpart. A first attempt at 

repair shall be made no later than 5 calendar days after the leak is detected.

(e) [Reserved]

(f) Any connector that is designated, as described in §63.181(b)(7)(i) of this subpart, as an unsafe-to-monitor 

connector is exempt from the requirements of paragraph (a) of this section if:

(1) The owner or operator determines that the connector is unsafe to monitor because personnel would be exposed 

to an immediate danger as a result of complying with paragraphs (a) through (e) of this section; and

(2) The owner or operator has a written plan that requires monitoring of the connector as frequently as practicable 

during safe to monitor periods, but not more frequently than the periodic schedule otherwise applicable.

(g) Any connector that is designated, as described in §63.181(b)(7)(iii) of this subpart, as an unsafe-to-repair 

connector is exempt from the requirements of paragraphs (a), (d), and (e) of this section if:

(1) The owner or operator determines that repair personnel would be exposed to an immediate danger as a 

consequence of complying with paragraph (d) of this section; and

(2) The connector will be repaired before the end of the next scheduled process unit shutdown.

(h)(1) Any connector that is inaccessible or is ceramic or ceramic-lined (e.g., porcelain, glass, or glass-lined), is 

exempt from the monitoring requirements of paragraphs (a) and (c) of this section and from the recordkeeping and 

reporting requirements of §63.181 and §63.182 of this subpart. An inaccessible connector is one that is:

(i) Buried;

(ii) Insulated in a manner that prevents access to the connector by a monitor probe;

(iii) Obstructed by equipment or piping that prevents access to the connector by a monitor probe;

(iv) Unable to be reached from a wheeled scissor-lift or hydraulic-type scaffold which would allow access to 

connectors up to 7.6 meters (25 feet) above the ground;

(v) Inaccessible because it would require elevating the monitoring personnel more than 2 meters above a permanent 

support surface or would require the erection of scaffold; or
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(vi) Not able to be accessed at any time in a safe manner to perform monitoring. Unsafe access includes, but is not 

limited to, the use of a wheeled scissor-lift on unstable or uneven terrain, the use of a motorized man-lift basket in 

areas where an ignition potential exists, or access would require near proximity to hazards such as electrical lines, or 

would risk damage to equipment.

(2) If any inaccessible or ceramic or ceramic-lined connector is observed by visual, audible, olfactory, or other means 

to be leaking, the leak shall be repaired as soon as practicable, but no later than 15 calendar days after the leak is 

detected, except as provided in §63.171 of this subpart and paragraph (g) of this section.

(3) A first attempt at repair shall be made no later than 5 calendar days after the leak is detected.

(i) For use in determining the monitoring frequency, as specified in paragraph (b) of this section, the percent leaking 

connectors shall be calculated as specified in paragraphs (i)(1) and (i)(2) of this section.

(1) For the first monitoring period, use the following equation:

% CL= CL/(Ct+ CC) × 100

where:

% CL= Percent leaking connectors as determined through periodic monitoring required in paragraphs (a) 

and (b) of this section.

CL= Number of connectors measured at 500 parts per million or greater, by the method specified in 

§63.180(b) of this subpart.

Ct= Total number of monitored connectors in the process unit.

CC= Optional credit for removed connectors = 0.67 × net (i.e., total removed—total added) number of 

connectors in organic hazardous air pollutants service removed from the process unit after the 

compliance date set forth in the applicable subpart for existing process units, and after the date of initial 

start-up for new process units. If credits are not taken, then CC= 0.

(2) For subsequent monitoring periods, use the following equation:

% CL= [(CL− CAN)/(Ct+ CC)] × 100

where:

% CL= Percent leaking connectors as determined through periodic monitoring required in paragraphs (a) 

and (b) of this section.

CL= Number of connectors, including nonrepairables, measured at 500 parts per million or greater, by the 

method specified in §63.180(b) of this subpart.

CAN= Number of allowable nonrepairable connectors, as determined by monitoring required in paragraphs 

(b)(3) and (c) of this section, not to exceed 2 percent of the total connector population, Ct.

Ct= Total number of monitored connectors, including nonrepairables, in the process unit.

CC= Optional credit for removed connectors = 0.67 × net number (i.e., total removed—total added) of 

connectors in organic hazardous air pollutants service removed from the process unit after the 
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compliance date set forth in the applicable subpart for existing process units, and after the date of initial 

start-up for new process units. If credits are not taken, then CC= 0.

(j) Optional credit for removed connectors. If an owner or operator eliminates a connector subject to monitoring under 

paragraph (b) of this section, the owner or operator may receive credit for elimination of the connector, as described 

in paragraph (i) of this section, provided the requirements in paragraphs (j)(1) through (j)(4) are met.

(1) The connector was welded after the date of proposal of the specific subpart that references this subpart.

(2) The integrity of the weld is demonstrated by monitoring it according to the procedures in §63.180(b) of this subpart 

or by testing using X-ray, acoustic monitoring, hydrotesting, or other applicable method.

(3) Welds created after the date of proposal but before the date of promulgation of a specific subpart that references 

this subpart are monitored or tested by 3 months after the compliance date specified in the applicable subpart.

(4) Welds created after promulgation of the subpart that references this subpart are monitored or tested within 3 

months after being welded.

(5) If an inadequate weld is found or the connector is not welded completely around the circumference, the connector 

is not considered a welded connector and is therefore not exempt from the provisions of this subpart.

[59 FR 19568, Apr. 22, 1994, as amended at 59 FR 48177, Sept. 20, 1994; 61 FR 31440, June 20, 1996; 62 FR 

2791, Jan. 17, 1997]

§ 63.175 Quality improvement program for valves.

(a) In Phase III, an owner or operator may elect to comply with one of the alternative quality improvement programs 

specified in paragraphs (d) and (e) of this section. The decision to use one of these alternative provisions to comply 

with the requirements of §63.168(d)(1)(ii) of this subpart must be made during the first year of Phase III for existing 

process units and for new process units.

(b) An owner or operator of a process unit subject to the requirements of paragraph (d) or (e) of this section shall 

comply with those requirements until the process unit has fewer than 2 percent leaking valves, calculated as a rolling 

average of 2 consecutive quarters, as specified in §63.168(e) of this subpart.

(c) After the process unit has fewer than 2 percent leaking valves, the owner or operator may elect to comply with the 

requirements in §63.168 of this subpart, to continue to comply with the requirements in paragraph (e) (or (d), if 

appropriate) of this section, or comply with both the requirements in §63.168 and §63.175.

(1) If the owner or operator elects to continue the quality improvement program, the owner or operator is exempt from 

the requirements for performance trials as specified in paragraph (e)(6) of this section, or further progress as 

specified in paragraph (d)(4) of this section, as long as the process unit has fewer than 2 percent leaking valves 

calculated according to §63.168(e).

(2) If the owner or operator elects to comply with both paragraph (e) of this section and §63.168 of this subpart, he 

may also take advantage of the lower monitoring frequencies associated with lower leak rates in §63.168 (d)(2), 

(d)(3), and (d)(4) of this subpart.

(3) If the owner or operator elects not to continue the quality improvement program, the program is no longer an 

option if the process unit again exceeds 2 percent leaking valves, and in such case, monthly monitoring will be 

required.

(d) The following requirements shall be met if an owner or operator elects to use a quality improvement program to 

demonstrate further progress:
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(1) The owner or operator shall continue to comply with the requirements in §63.168 of this subpart except each valve 

shall be monitored quarterly.

(2) The owner or operator shall collect the following data, and maintain records as required in §63.181(h)(1) of this 

subpart, for each valve in each process unit subject to the quality improvement program:

(i) The maximum instrument reading observed in each monitoring observation before repair, the response factor for 

the stream if appropriate, the instrument model number, and date of the observation.

(ii) Whether the valve is in gas or light liquid service.

(iii) If a leak is detected, the repair methods used and the instrument readings after repair.

(3) The owner or operator shall continue to collect data on the valves as long as the process unit remains in the 

quality improvement program.

(4) The owner or operator must demonstrate progress in reducing the percent leaking valves each quarter the 

process unit is subject to the requirements of paragraph (d) of this section, except as provided in paragraphs (d)(4)(ii) 

and (d)(4)(iii) of this section.

(i) Demonstration of progress shall mean that for each quarter there is at least a 10-percent reduction in the percent 

leaking valves from the percent leaking valves determined for the preceding monitoring period. The percent leaking 

valves shall be calculated as a rolling average of two consecutive quarters of monitoring data. The percent reduction 

shall be calculated using the rolling average percent leaking valves, according to the following:

%LVR= (%LVAVG1− %LVAVG2/ %LVAVG1× 100

where:

%LVR=Percent leaking valve reduction.

%LVAVG1=(%VLi+ %VLi=1)/2.

%LVAVG2=(%VLi=1+ %VLi=2)/2.

where:

%VLi, %VLi=1, %VLi=2are percent leaking valves calculated for subsequent monitoring periods, i, i+1, 

i+2.

(ii) An owner or operator who fails for two consecutive rolling averages to demonstrate at least a 10-percent reduction 

per quarter in percent leaking valves, and whose overall average percent reduction based on two or more rolling 

averages is less than 10 percent per quarter, shall either comply with the requirements in §63.168(d)(1)(i) of this 

subpart using monthly monitoring or shall comply using a quality improvement program for technology review as 

specified in paragraph (e) of this section. If the owner or operator elects to comply with the requirements of paragraph 

(e) of this section, the schedule for performance trials and valve replacements remains as specified in paragraph (e) 

of this section.

(iii) As an alternative to the provisions in paragraph (d)(4)(i), an owner or operator may use the procedure specified in 

paragraphs (d)(4)(iii)(A) and (d)(4)(iii)(B) of this section to demonstrate progress in reducing the percent leaking 

valves.

(A) The percent reduction that must be achieved each quarter shall be calculated as follows:
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%RR = percent reduction required each quarter, as calculated according to §63.168(e)

%VL= percent leaking valves, calculated according to §63.168(e), at the time elected to use provisions of 

§63.168(d)(1)(ii)

(B) The owner or operator shall achieve less than 2 percent leaking valves no later than 2 years after electing to use 

the demonstration of progress provisions in §63.175(d) of this subpart.

(e) The following requirements shall be met if an owner or operator elects to use a quality improvement program of 

technology review and improvement:

(1) The owner or operator shall comply with the requirements in §63.168 of this subpart except the requirement for 

monthly monitoring in §63.168(d)(1)(i) of this subpart does not apply.

(2) The owner or operator shall collect the data specified below, and maintain records as required in §63.181(h)(2), 

for each valve in each process unit subject to the quality improvement program. The data may be collected and the 

records may be maintained on a process unit or group of process units basis. The data shall include the following:

(i) Valve type (e.g., ball, gate, check); valve manufacturer; valve design (e.g., external stem or actuating mechanism, 

flanged body); materials of construction; packing material; and year installed.

(ii) Service characteristics of the stream such as operating pressure, temperature, line diameter, and corrosivity.

(iii) Whether the valve is in gas or light liquid service.

(iv) The maximum instrument readings observed in each monitoring observation before repair, response factor for the 

stream if adjusted, instrument model number, and date of the observation.

(v) If a leak is detected, the repair methods used and the instrument readings after repair.

(vi) If the data will be analyzed as part of a larger analysis program involving data from other plants or other types of 

process units, a description of any maintenance or quality assurance programs used in the process unit that are 

intended to improve emission performance.

(3) The owner or operator shall continue to collect data on the valves as long as the process unit remains in the 

quality improvement program.

(4) The owner or operator shall inspect all valves removed from the process unit due to leaks. The inspection shall 

determine which parts of the valve have failed and shall include recommendations, as appropriate, for design 

changes or changes in specifications to reduce leak potential.

(5)(i) The owner or operator shall analyze the data collected to comply with the requirements of paragraph (e)(2) of 

this section to determine the services, operating or maintenance practices, and valve designs or technologies that 

have poorer than average emission performance and those that have better than average emission performance. The 

analysis shall determine if specific trouble areas can be identified on the basis of service, operating conditions or 

maintenance practices, equipment design, or other process specific factors.

(ii) The analysis shall also be used to identify any superior performing valve technologies that are applicable to the 

service(s), operating conditions, or valve designs associated with poorer than average emission performance. A 

superior performing valve technology is one for which a group of such valves has a leak frequency of less than 2 

percent for specific applications in such a process unit. A candidate superior performing valve technology is one 
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demonstrated or reported in the available literature or through a group study as having low emission performance and 

as being capable of achieving less than 2 percent leaking valves in the process unit.

(iii) The analysis shall include consideration of:

(A) The data obtained from the inspections of valves removed from the process unit due to leaks,

(B) Information from the available literature and from the experience of other plant sites that will identify valve designs 

or technologies and operating conditions associated with low emission performance for specific services, and

(C) Information on limitations on the service conditions for the valve design and operating conditions as well as 

information on maintenance procedures to ensure continued low emission performance.

(iv) The data analysis may be conducted through an inter- or intra-company program (or through some combination 

of the two approaches) and may be for a single process unit, a company, or a group of process units.

(v) The first analysis of the data shall be completed no later than 18 months after the start of Phase III. The first 

analysis shall be performed using a minimum of two quarters of data. An analysis of the data shall be done each year 

the process unit is in the quality improvement program.

(6) A trial evaluation program shall be conducted at each plant site for which the data analysis does not identify 

superior performing valve designs or technologies that can be applied to the operating conditions and services 

identified as having poorer than average performance, except as provided in paragraph (e)(6)(v) of this section. The 

trial program shall be used to evaluate the feasibility of using in the process unit the valve designs or technologies 

that have been identified by others as having low emission performance.

(i) The trial program shall include on-line trials of valves or operating and maintenance practices that have been 

identified in the available literature or in analysis by others as having the ability to perform with leak rates below 2 

percent in similar services, as having low probability of failure, or as having no external actuating mechanism in 

contact with the process fluid. If any of the candidate superior performing valve technologies is not included in the 

performance trials, the reasons for rejecting specific technologies from consideration shall be documented as 

required in §63.181(h)(5)(ii) of this subpart.

(ii) The number of valves in the trial evaluation program shall be the lesser of 1 percent or 20 valves for programs 

involving single process units and the lesser of 1 percent or 50 valves for programs involving groups of process units.

(iii) The trial evaluation program shall specify and include documentation of:

(A) The candidate superior performing valve designs or technologies to be evaluated, the stages for evaluating the 

identified candidate valve designs or technologies, including the estimated time period necessary to test the 

applicability;

(B) The frequency of monitoring or inspection of the equipment;

(C) The range of operating conditions over which the component will be evaluated; and

(D) Conclusions regarding the emission performance and the appropriate operating conditions and services for the 

trial valves.

(iv) The performance trials shall initially be conducted for, at least, a 6-month period beginning not later than 18 

months after the start of Phase III. Not later than 24 months after the start of Phase III, the owner or operator shall 

have identified valve designs or technologies that, combined with appropriate process, operating, and maintenance 

practices, operate with low emission performance for specific applications in the process unit. The owner or operator 

shall continue to conduct performance trials as long as no superior performing design or technology has been 

identified, except as provided in paragraph (e)(6)(vi) of this section. The compilation of candidate and demonstrated 

superior emission performance valve designs or technologies shall be amended in the future, as appropriate, as 

additional information and experience is obtained.
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(v) Any plant site with fewer than 400 valves and owned by a corporation with fewer than 100 total employees shall 

be exempt from trial evaluations of valves. Plant sites exempt from the trial evaluations of valves shall begin the 

program at the start of the fourth year of Phase III.

(vi) An owner or operator who has conducted performance trials on all candidate superior emission performance 

technologies suitable for the required applications in the process unit may stop conducting performance trials 

provided that a superior performing design or technology has been demonstrated or there are no technically feasible 

candidate superior technologies remaining. The owner or operator shall prepare an engineering evaluation 

documenting the physical, chemical, or engineering basis for the judgment that the superior emission performance 

technology is technically infeasible or demonstrating that it would not reduce emissions.

(7) Each owner or operator who elects to use a quality improvement program for technology review and improvement 

shall prepare and implement a valve quality assurance program that details purchasing specifications and 

maintenance procedures for all valves in the process unit. The quality assurance program may establish any number 

of categories, or classes, of valves as needed to distinguish among operating conditions and services associated with 

poorer than average emission performance as well as those associated with better than average emission 

performance. The quality assurance program shall be developed considering the findings of the data analysis 

required under paragraph (e)(5) of this section, if applicable, the findings of the trial evaluation required in paragraph 

(e)(6) of this section, and the operating conditions in the process unit. The quality assurance program shall be 

reviewed and, as appropriate, updated each year as long as the process unit has 2 percent or more leaking valves.

(i) The quality assurance program shall:

(A) Establish minimum design standards for each category of valves. The design standards shall specify known 

critical parameters such as tolerance, manufacturer, materials of construction, previous usage, or other applicable 

identified critical parameters;

(B) Require that all equipment orders specify the design standard (or minimum tolerances) for the valve;

(C) Include a written procedure for bench testing of valves that specifies performance criteria for acceptance of valves 

and specifies criteria for the precision and accuracy of the test apparatus. All valves repaired off-line after preparation 

of the quality assurance plan shall be bench-tested for leaks. This testing may be conducted by the owner or operator 

of the process unit, by the vendor, or by a designated representative. The owner or operator shall install only those 

valves that have been documented through bench-testing to be nonleaking.

(D) Require that all valves repaired on-line be monitored using the method specified in §63.180(b) of this subpart for 

leaks for 2 successive months, after repair.

(E) Provide for an audit procedure for quality control of purchased equipment to ensure conformance with purchase 

specifications. The audit program may be conducted by the owner or operator of the process unit or by a designated 

representative.

(F) Detail off-line valve maintenance and repair procedures. These procedures shall include provisions to ensure that 

rebuilt or refurbished valves will meet the design specifications for the valve type and will operate such that emissions 

are minimized.

(ii) The quality assurance program shall be established no later than the start of the third year of Phase III for plant 

sites with 400 or more valves or owned by a corporation with 100 or more employees; and no later than the start of 

the fourth year of Phase III for plant sites with less than 400 valves and owned by a corporation with less than 100 

employees.

(8) Beginning at the start of the third year of Phase III for plant sites with 400 or more valves or owned by a 

corporation with 100 or more employees and at the start of the fourth year of Phase III for plant sites with less than 

400 valves and owned by a corporation with less than 100 employees, each valve that is replaced for any reason 

shall be replaced with a new or modified valve that complies with the quality assurance standards for the valve 

category and that is identified as superior emission performance technology. Superior emission performance 

technology means valves or valve technologies identified with emission performance that, combined with appropriate 
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process, operating, and maintenance practices, will result in less than 2 percent leaking valves for specific 

applications in a large population, except as provided in paragraph (e)(8)(ii) of this section.

(i) The valves shall be maintained as specified in the quality assurance program.

(ii) If a superior emission performance technology cannot be identified, then valve replacement shall be with one of (if 

several) the lowest emission performance technologies that has been identified for the specific application.

[59 FR 19568, Apr. 22, 1994, as amended at 60 FR 63631, Dec. 12, 1995]

§ 63.176 Quality improvement program for pumps.

(a) In Phase III, if, on a 6-month rolling average, the greater of either 10 percent of the pumps in a process unit (or 

plant site) or three pumps in a process unit (or plant site) leak, the owner or operator shall comply with the 

requirements of this section as specified below:

(1) Pumps that are in food/medical service or in polymerizing monomer service shall comply with all requirements 

except for those specified in paragraph (d)(8) of this section.

(2) Pumps that are not in food/medical or polymerizing monomer service shall comply with all requirements of this 

section.

(b) The owner or operator shall comply with the requirements of this section until the number of leaking pumps is less 

than the greater of either 10 percent of the pumps or three pumps, calculated as a 6-month rolling average, in the 

process unit (or plant site). Once the performance level is achieved, the owner or operator shall comply with the 

requirements in §63.163 of this subpart.

(c) If in a subsequent monitoring period, the process unit (or plant site) has greater than 10 percent of the pumps 

leaking or three pumps leaking (calculated as a 6-month rolling average), the owner or operator shall resume the 

quality improvement program starting at performance trials.

(d) The quality improvement program shall include the following:

(1) The owner or operator shall comply with the requirements in §63.163 of this subpart.

(2) The owner or operator shall collect the following data, and maintain records as required in §63.181(h)(3), for each 

pump in each process unit (or plant site) subject to the quality improvement program. The data may be collected and 

the records may be maintained on a process unit or plant site basis.

(i) Pump type (e.g., piston, horizontal or vertical centrifugal, gear, bellows); pump manufacturer; seal type and 

manufacturer; pump design (e.g., external shaft, flanged body); materials of construction; if applicable, barrier fluid or 

packing material; and year installed.

(ii) Service characteristics of the stream such as discharge pressure, temperature, flow rate, corrosivity, and annual 

operating hours.

(iii) The maximum instrument readings observed in each monitoring observation before repair, response factor for the 

stream if appropriate, instrument model number, and date of the observation.

(iv) If a leak is detected, the repair methods used and the instrument readings after repair.

(v) If the data will be analyzed as part of a larger analysis program involving data from other plants or other types of 

process units, a description of any maintenance or quality assurance programs used in the process unit that are 

intended to improve emission performance.
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(3) The owner or operator shall continue to collect data on the pumps as long as the process unit (or plant site) 

remains in the quality improvement program.

(4) The owner or operator shall inspect all pumps or pump seals which exhibited frequent seal failures and were 

removed from the process unit due to leaks. The inspection shall determine the probable cause of the pump seal 

failure or of the pump leak and shall include recommendations, as appropriate, for design changes or changes in 

specifications to reduce leak potential.

(5)(i) The owner or operator shall analyze the data collected to comply with the requirements of paragraph (d)(2) of 

this section to determine the services, operating or maintenance practices, and pump or pump seal designs or 

technologies that have poorer than average emission performance and those that have better than average emission 

performance. The analysis shall determine if specific trouble areas can be identified on the basis of service, operating 

conditions or maintenance practices, equipment design, or other process specific factors.

(ii) The analysis shall also be used to determine if there are superior performing pump or pump seal technologies that 

are applicable to the service(s), operating conditions, or pump or pump seal designs associated with poorer than 

average emission performance. A superior performing pump or pump seal technology is one with a leak frequency of 

less than 10 percent for specific applications in the process unit or plant site. A candidate superior performing pump 

or pump seal technology is one demonstrated or reported in the available literature or through a group study as 

having low emission performance and as being capable of achieving less than 10 percent leaking pumps in the 

process unit (or plant site).

(iii) The analysis shall include consideration of:

(A) The data obtained from the inspections of pumps and pump seals removed from the process unit due to leaks;

(B) Information from the available literature and from the experience of other plant sites that will identify pump 

designs or technologies and operating conditions associated with low emission performance for specific services; and

(C) Information on limitations on the service conditions for the pump seal technology operating conditions as well as 

information on maintenance procedures to ensure continued low emission performance.

(iv) The data analysis may be conducted through an inter- or intra-company program (or through some combination 

of the two approaches) and may be for a single process unit, a plant site, a company, or a group of process units.

(v) The first analysis of the data shall be completed no later than 18 months after the start of the quality improvement 

program. The first analysis shall be performed using a minimum of 6 months of data. An analysis of the data shall be 

done each year the process unit is in the quality improvement program.

(6) A trial evaluation program shall be conducted at each plant site for which the data analysis does not identify use of 

superior performing pump seal technology or pumps that can be applied to the areas identified as having poorer than 

average performance, except as provided in paragraph (d)(6)(v) of this section. The trial program shall be used to 

evaluate the feasibility of using in the process unit (or plant site) the pump designs or seal technologies, and 

operating and maintenance practices that have been identified by others as having low emission performance.

(i) The trial program shall include on-line trials of pump seal technologies or pump designs and operating and 

maintenance practices that have been identified in the available literature or in analysis by others as having the ability 

to perform with leak rates below 10 percent in similar services, as having low probability of failure, or as having no 

external actuating mechanism in contact with the process fluid. If any of the candidate superior performing pump seal 

technologies or pumps is not included in the performance trials, the reasons for rejecting specific technologies from 

consideration shall be documented as required in §63.181(h)(5)(ii).

(ii) The number of pump seal technologies or pumps in the trial evaluation program shall be the lesser of 1 percent or 

two pumps for programs involving single process units and the lesser of 1 percent or five pumps for programs 

involving a plant site or groups of process units. The minimum number of pumps or pump seal technologies in a trial 

program shall be one.

(iii) The trial evaluation program shall specify and include documentation of:
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(A) The candidate superior performing pump seal designs or technologies to be evaluated, the stages for evaluating 

the identified candidate pump designs or pump seal technologies, including the time period necessary to test the 

applicability;

(B) The frequency of monitoring or inspection of the equipment;

(C) The range of operating conditions over which the component will be evaluated; and

(D) Conclusions regarding the emission performance and the appropriate operating conditions and services for the 

trial pump seal technologies or pumps.

(iv) The performance trials shall initially be conducted, at least, for a 6-month period beginning not later than 18 

months after the start of the quality improvement program. No later than 24 months after the start of the quality 

improvement program, the owner or operator shall have identified pump seal technologies or pump designs that, 

combined with appropriate process, operating, and maintenance practices, operate with low emission performance 

for specific applications in the process unit. The owner or operator shall continue to conduct performance trials as 

long as no superior performing design or technology has been identified, except as provided in paragraph (d)(6)(vi) of 

this section. The initial list of superior emission performance pump designs or pump seal technologies shall be 

amended in the future, as appropriate, as additional information and experience is obtained.

(v) Any plant site with fewer than 400 valves and owned by a corporation with fewer than 100 employees shall be 

exempt from trial evaluations of pump seals or pump designs. Plant sites exempt from the trial evaluations of pumps 

shall begin the pump seal or pump replacement program at the start of the fourth year of the quality improvement 

program.

(vi) An owner or operator who has conducted performance trials on all alternative superior emission performance 

technologies suitable for the required applications in the process unit may stop conducting performance trials 

provided that a superior performing design or technology has been demonstrated or there are no technically feasible 

alternative superior technologies remaining. The owner or operator shall prepare an engineering evaluation 

documenting the physical, chemical, or engineering basis for the judgment that the superior emission performance 

technology is technically infeasible or demonstrating that it would not reduce emissions.

(7) Each owner or operator shall prepare and implement a pump quality assurance program that details purchasing 

specifications and maintenance procedures for all pumps and pump seals in the process unit. The quality assurance 

program may establish any number of categories, or classes, of pumps as needed to distinguish among operating 

conditions and services associated with poorer than average emission performance as well as those associated with 

better than average emission performance. The quality assurance program shall be developed considering the 

findings of the data analysis required under paragraph (d)(5) of this section, if applicable, the findings of the trial 

evaluation required in paragraph (d)(6) of this section, and the operating conditions in the process unit. The quality 

assurance program shall be updated each year as long as the process unit has the greater of either 10 percent or 

more leaking pumps or has three leaking pumps.

(i) The quality assurance program shall:

(A) Establish minimum design standards for each category of pumps or pump seal technology. The design standards 

shall specify known critical parameters such as tolerance, manufacturer, materials of construction, previous usage, or 

other applicable identified critical parameters;

(B) Require that all equipment orders specify the design standard (or minimum tolerances) for the pump or the pump 

seal;

(C) Provide for an audit procedure for quality control of purchased equipment to ensure conformance with purchase 

specifications. The audit program may be conducted by the owner or operator of the plant site or process unit or by a 

designated representative; and

(D) Detail off-line pump maintenance and repair procedures. These procedures shall include provisions to ensure that 

rebuilt or refurbished pumps and pump seals will meet the design specifications for the pump category and will 

operate such that emissions are minimized.
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(ii) The quality assurance program shall be established no later than the start of the third year of the quality 

improvement program for plant sites with 400 or more valves or 100 or more employees; and no later than the start of 

the fourth year of the quality improvement program for plant sites with less than 400 valves and less than 100 

employees.

(8) Beginning at the start of the third year of the quality improvement program for plant sites with 400 or more valves 

or 100 or more employees and at the start of the fourth year of the quality improvement program for plant sites with 

less than 400 valves and less than 100 employees, the owner or operator shall replace, as described in paragraphs 

(d)(8)(i) and (d)(8)(ii) of this section, the pumps or pump seals that are not superior emission performance technology 

with pumps or pump seals that have been identified as superior emission performance technology and that comply 

with the quality assurance standards for the pump category. Superior emission performance technology is that 

category or design of pumps or pump seals with emission performance which, when combined with appropriate 

process, operating, and maintenance practices, will result in less than 10 percent leaking pumps for specific 

applications in the process unit or plant site. Superior emission performance technology includes material or design 

changes to the existing pump, pump seal, seal support system, installation of multiple mechanical seals or equivalent, 

or pump replacement.

(i) Pumps or pump seals shall be replaced at the rate of 20 percent per year based on the total number of pumps in 

light liquid service. The calculated value shall be rounded to the nearest nonzero integer value. The minimum number 

of pumps or pump seals shall be one. Pump replacement shall continue until all pumps subject to the requirements of 

§63.163 of this subpart are pumps determined to be superior performance technology.

(ii) The owner or operator may delay replacement of pump seals or pumps with superior technology until the next 

planned process unit shutdown, provided the number of pump seals and pumps replaced is equivalent to the 20 

percent or greater annual replacement rate.

(iii) The pumps shall be maintained as specified in the quality assurance program.

§ 63.177 Alternative means of emission limitation: General.

(a) Permission to use an alternative means of emission limitation under section 112(h)(3) of the Act shall be governed 

by the following procedures in paragraphs (b) through (e) of this section.

(b) Where the standard is an equipment, design, or operational requirement:

(1) Each owner or operator applying for permission to use an alternative means of emission limitation under §63.6(g) 

of subpart A of this part shall be responsible for collecting and verifying emission performance test data for an 

alternative means of emission limitation.

(2) The Administrator will compare test data for the means of emission limitation to test data for the equipment, 

design, and operational requirements.

(3) The Administrator may condition the permission on requirements that may be necessary to ensure operation and 

maintenance to achieve the same emission reduction as the equipment, design, and operational requirements.

(c) Where the standard is a work practice:

(1) Each owner or operator applying for permission shall be responsible for collecting and verifying test data for an 

alternative means of emission limitation.

(2) For each kind of equipment for which permission is requested, the emission reduction achieved by the required 

work practices shall be demonstrated for a minimum period of 12 months.

(3) For each kind of equipment for which permission is requested, the emission reduction achieved by the alternative 

means of emission limitation shall be demonstrated.
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(4) Each owner or operator applying for permission shall commit, in writing, for each kind of equipment to work 

practices that provide for emission reductions equal to or greater than the emission reductions achieved by the 

required work practices.

(5) The Administrator will compare the demonstrated emission reduction for the alternative means of emission 

limitation to the demonstrated emission reduction for the required work practices and will consider the commitment in 

paragraph (c)(4) of this section.

(6) The Administrator may condition the permission on requirements that may be necessary to ensure operation and 

maintenance to achieve the same or greater emission reduction as the required work practices of this subpart.

(d) An owner or operator may offer a unique approach to demonstrate the alternative means of emission limitation.

(e)(1) Manufacturers of equipment used to control equipment leaks of an organic HAP may apply to the Administrator 

for permission for an alternative means of emission limitation that achieves a reduction in emissions of the organic 

HAP achieved by the equipment, design, and operational requirements of this subpart.

(2) The Administrator will grant permission according to the provisions of paragraphs (b), (c), and (d) of this section.

§ 63.178 Alternative means of emission limitation: Batch processes.

(a) As an alternative to complying with the requirements of §§63.163 through 63.171 and §§63.173 through 63.176, 

an owner or operator of a batch process that operates in organic HAP service during the calendar year may comply 

with one of the standards specified in paragraphs (b) and (c) of this section, or the owner or operator may petition for 

approval of an alternative standard under the provisions of §63.177 of this subpart. The alternative standards of this 

section provide the options of pressure testing or monitoring the equipment for leaks. The owner or operator may 

switch among the alternatives provided the change is documented as specified in §63.181.

(b) The following requirements shall be met if an owner or operator elects to use pressure testing of batch productprocess equipment to demonstrate compliance with this subpart. An owner or operator who complies with the 

provisions of this paragraph is exempt from the monitoring provisions of §63.163, §§63.168 and 63.169, and 

§§63.173 through 63.176 of this subpart.

(1) Each time equipment is reconfigured for production of a different product or intermediate, the batch productprocess equipment train shall be pressure-tested for leaks before organic HAP is first fed to the equipment and the 

equipment is placed in organic HAP service.

(i) When the batch product-process train is reconfigured to produce a different product, pressure testing is required 

only for the new or disturbed equipment.

(ii) Each batch product process that operates in organic HAP service during a calendar year shall be pressure tested 

at least once during that calendar year.

(iii) Pressure testing is not required for routine seal breaks, such as changing hoses or filters, which are not part of 

the reconfiguration to produce a different product or intermediate.

(2) The batch product process equipment shall be tested either using the procedures specified in §63.180(f) of this 

subpart for pressure or vacuum loss or with a liquid using the procedures specified in §63.180(g) of this subpart.

(3)(i) For pressure or vacuum tests, a leak is detected if the rate of change in pressure is greater than 6.9 kilopascals 

(1 psig) in 1 hour or if there is visible, audible, or olfactory evidence of fluid loss.

(ii) For pressure tests using a liquid, a leak is detected if there are indications of liquids dripping or if there is other 

evidence of fluid loss.
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(4)(i) If a leak is detected, it shall be repaired and the batch product-process equipment shall be retested before startup of the process.

(ii) If a batch product-process fails the retest or the second of two consecutive pressure tests, it shall be repaired as 

soon as practicable, but not later than 30 calendar days after the second pressure test, provided the conditions 

specified in paragraph (d) of this section are met.

(c) The following requirements shall be met if an owner or operator elects to monitor the equipment to detect leaks by 

the method specified in §63.180(b) of this subpart to demonstrate compliance with this subpart.

(1) The owner or operator shall comply with the requirements of §§63.163 through 63.170, and §§63.172 through 

63.176 of this subpart.

(2) The equipment shall be monitored for leaks by the method specified in §63.180(b) of this subpart when the 

equipment is in organic HAP service, in use with an acceptable surrogate volatile organic compound which is not an 

organic HAP, or is in use with any other detectable gas or vapor.

(3) The equipment shall be monitored for leaks as specified below:

(i) Each time the equipment is reconfigured for the production of a new product, the reconfigured equipment shall be 

monitored for leaks within 30 days of start-up of the process. This initial monitoring of reconfigured equipment shall 

not be included in determining percent leaking equipment in the process unit.

(ii) Connectors shall be monitored in accordance with the requirements in §63.174 of this subpart.

(iii) Equipment other than connectors shall be monitored at the frequencies specified in table 1 of this subpart. The 

operating time shall be determined as the proportion of the year the batch product-process that is subject to the 

provisions of this subpart is operating.

(iv) The monitoring frequencies specified in table 1 of this subpart are not requirements for monitoring at specific 

intervals and can be adjusted to accommodate process operations. An owner or operator may monitor anytime during 

the specified monitoring period (e.g., month, quarter, year), provided the monitoring is conducted at a reasonable 

interval after completion of the last monitoring campaign. For example, if the equipment is not operating during the 

scheduled monitoring period, the monitoring can be done during the next period when the process is operating.

(4) If a leak is detected, it shall be repaired as soon as practicable but not later than 15 calendar days after it is 

detected, except as provided in paragraph (d) of this section.

(d) Delay of repair of equipment for which leaks have been detected is allowed if the replacement equipment is not 

available providing the following conditions are met:

(1) Equipment supplies have been depleted and supplies had been sufficiently stocked before the supplies were 

depleted.

(2) The repair is made no later than 10 calendar days after delivery of the replacement equipment.

§ 63.179 Alternative means of emission limitation: Enclosed-vented 

process units.

Process units enclosed in such a manner that all emissions from equipment leaks are vented through a closed-vent 

system to a control device meeting the requirements of §63.172 of this subpart are exempt from the requirements of 

§63.163, through 63.171, and §§63.173 and 63.174 of this subpart. The enclosure shall be maintained under a 

negative pressure at all times while the process unit is in operation to ensure that all emissions are routed to a control 

device.
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§ 63.180 Test methods and procedures.

(a) Each owner or operator subject to the provisions of this subpart shall comply with the test methods and 

procedures requirements provided in this section.

(b) Monitoring, as required under this subpart, shall comply with the following requirements:

(1) Monitoring shall comply with Method 21 of 40 CFR part 60, appendix A.

(2)(i) Except as provided for in paragraph (b)(2)(ii) of this section, the detection instrument shall meet the 

performance criteria of Method 21 of 40 CFR part 60, appendix A, except the instrument response factor criteria in 

Section 3.1.2(a) of Method 21 shall be for the average composition of the process fluid not each individual VOC in the 

stream. For process streams that contain nitrogen, water, air, or other inerts which are not organic HAP's or VOC's, 

the average stream response factor may be calculated on an inert-free basis. The response factor may be 

determined at any concentration for which monitoring for leaks will be conducted.

(ii) If no instrument is available at the plant site that will meet the performance criteria specified in paragraph (b)(2)(i)

of this section, the instrument readings may be adjusted by multiplying by the average response factor of the process 

fluid, calculated on an inert-free basis as described in paragraph (b)(2)(i) of this section.

(3) The instrument shall be calibrated before use on each day of its use by the procedures specified in Method 21 of 

40 CFR part 60, appendix A.

(4) Calibration gases shall be:

(i) Zero air (less than 10 parts per million of hydrocarbon in air); and

(ii) Mixtures of methane in air at the concentrations specified in paragraphs (b)(4)(ii)(A) through (b)(4)(ii)(C) of this 

section. A calibration gas other than methane in air may be used if the instrument does not respond to methane or if 

the instrument does not meet the performance criteria specified in paragraph (b)(2)(i) of this section. In such cases, 

the calibration gas may be a mixture of one or more of the compounds to be measured in air.

(A) For Phase I, a mixture of methane or other compounds, as applicable, in air at a concentration of approximately, 

but less than, 10,000 parts per million.

(B) For Phase II, a mixture of methane or other compounds, as applicable, and air at a concentration of 

approximately, but less than, 10,000 parts per million for agitators, 5,000 parts per million for pumps, and 500 parts 

per million for all other equipment, except as provided in paragraph (b)(4)(iii) of this section.

(C) For Phase III, a mixture of methane or other compounds, as applicable, and air at a concentration of 

approximately, but less than, 10,000 parts per million methane for agitators; 2,000 parts per million for pumps in 

food/medical service; 5,000 parts per million for pumps in polymerizing monomer service; 1,000 parts per million for 

all other pumps; and 500 parts per million for all other equipment, except as provided in paragraph (b)(4)(iii) of this 

section.

(iii) The instrument may be calibrated at a higher methane concentration than the concentration specified for that 

piece of equipment. The concentration of the calibration gas may exceed the concentration specified as a leak by no 

more than 2,000 parts per million. If the monitoring instrument's design allows for multiple calibration scales, then the 

lower scale shall be calibrated with a calibration gas that is no higher than 2,000 parts per million above the 

concentration specified as a leak and the highest scale shall be calibrated with a calibration gas that is approximately 

equal to 10,000 parts per million. If only one scale on an instrument will be used during monitoring, the owner or 

operator need not calibrate the scales that will not be used during that day's monitoring.

(5) Monitoring shall be performed when the equipment is in organic HAP service, in use with an acceptable surrogate 

volatile organic compound which is not an organic HAP, or is in use with any other detectable gas or vapor.
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(6) Monitoring data that do not meet the criteria specified in paragraphs (b)(1) through (b)(5) of this section may be 

used to qualify for less frequent monitoring under the provisions in §63.168(d)(2) and (d)(3) or §63.174(b)(3)(ii) or 

(b)(3)(iii) of this subpart provided the data meet the conditions specified in paragraphs (b)(6)(i) and (b)(6)(ii) of this 

section.

(i) The data were obtained before April 22, 1994.

(ii) The departures from the criteria specified in paragraphs (b)(1) through (b)(5) of this section or from the specified 

monitoring frequency of §63.168(c) are minor and do not significantly affect the quality of the data. Examples of minor 

departures are monitoring at a slightly different frequency (such as every six weeks instead of monthly or quarterly), 

following the performance criteria of section 3.1.2(a) of Method 21 of appendix A of 40 CFR part 60 instead of 

paragraph (b)(2) of this section, or monitoring at a different leak definition if the data would indicate the presence or 

absence of a leak at the concentration specified in this subpart. Failure to use a calibrated instrument is not 

considered a minor departure.

(c) When equipment is monitored for compliance as required in §§63.164(i), 63.165(a), and 63.172(f) or when 

equipment subject to a leak definition of 500 ppm is monitored for leaks as required by this subpart, the owner or 

operator may elect to adjust or not to adjust the instrument readings for background. If an owner or operator elects to 

not adjust instrument readings for background, the owner or operator shall monitor the equipment according to the 

procedures specified in paragraphs (b)(1) through (b)(4) of this section. In such case, all instrument readings shall be 

compared directly to the applicable leak definition to determine whether there is a leak. If an owner or operator elects 

to adjust instrument readings for background, the owner or operator shall monitor the equipment according to the 

procedures specified in paragraphs (c)(1) through (c)(4) of this section.

(1) The requirements of paragraphs (b) (1) through (4) of this section shall apply.

(2) The background level shall be determined, using the same procedures that will be used to determine whether the 

equipment is leaking.

(3) The instrument probe shall be traversed around all potential leak interfaces as close to the interface as possible 

as described in Method 21 of 40 CFR part 60, appendix A.

(4) The arithmetic difference between the maximum concentration indicated by the instrument and the background 

level is compared with 500 parts per million for determining compliance.

(d)(1) Each piece of equipment within a process unit that can reasonably be expected to contain equipment in organic 

HAP service is presumed to be in organic HAP service unless an owner or operator demonstrates that the piece of 

equipment is not in organic HAP service. For a piece of equipment to be considered not in organic HAP service, it 

must be determined that the percent organic HAP content can be reasonably expected not to exceed 5 percent by 

weight on an annual average basis. For purposes of determining the percent organic HAP content of the process fluid 

that is contained in or contacts equipment, Method 18 of 40 CFR part 60, appendix A shall be used.

(2)(i) An owner or operator may use good engineering judgment rather than the procedures in paragraph (d)(1) of this 

section to determine that the percent organic HAP content does not exceed 5 percent by weight. When an owner or 

operator and the Administrator do not agree on whether a piece of equipment is not in organic HAP service, however, 

the procedures in paragraph (d)(1) of this section shall be used to resolve the disagreement.

(ii) Conversely, the owner or operator may determine that the organic HAP content of the process fluid does not 

exceed 5 percent by weight by, for example, accounting for 98 percent of the content and showing that organic HAP 

is less than 3 percent.

(3) If an owner or operator determines that a piece of equipment is in organic HAP service, the determination can be 

revised after following the procedures in paragraph (d)(1) of this section, or by documenting that a change in the 

process or raw materials no longer causes the equipment to be in organic HAP service.

(4) Samples used in determining the percent organic HAP content shall be representative of the process fluid that is 

contained in or contacts the equipment.
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(e) When a flare is used to comply with §63.172(d), the owner or operator shall comply with paragraphs (e)(1) 

through (3) of this section. The owner or operator is not required to conduct a performance test to determine percent 

emission reduction or outlet organic HAP or TOC concentration.

(1) Conduct a visible emission test using the techniques specified in §63.11(b)(4).

(2) Determine the net heating value of the gas being combusted using the techniques specified in §63.11(b)(6).

(3) Determine the exit velocity using the techniques specified in either §63.11(b)(7)(i) (and §63.11(b)(7)(iii), where 

applicable) or §63.11(b)(8), as appropriate.

(f) The following procedures shall be used to pressure test batch product-process equipment for pressure or vacuum 

loss to demonstrate compliance with the requirements of §63.178(b)(3)(i) of this subpart.

(1) The batch product-process equipment train shall be pressurized with a gas to a pressure less than the set 

pressure of any safety relief devices or valves or to a pressure slightly above the operating pressure of the 

equipment, or alternatively, the equipment shall be placed under a vacuum.

(2) Once the test pressure is obtained, the gas source or vacuum source shall be shut off.

(3) The test shall continue for not less than 15 minutes unless it can be determined in a shorter period of time that the 

allowable rate of pressure drop or of pressure rise was exceeded. The pressure in the batch product-process 

equipment shall be measured after the gas or vacuum source is shut off and at the end of the test period. The rate of 

change in pressure in the batch product-process equipment shall be calculated using the following equation:

where:

Δ P/t=Change in pressure, psig/hr.

Pf=Final pressure, psig.

Pi=Initial pressure, psig.

tf−ti=Elapsed time, hours.

(4) The pressure shall be measured using a pressure measurement device (gauge, manometer, or equivalent) which 

has a precision of ±2.5 millimeter mercury in the range of test pressure and is capable of measuring pressures up to 

the relief set pressure of the pressure relief device. If such a pressure measurement device is not reasonably 

available, the owner or operator shall use a pressure measurement device with a precision of at least +10 percent of 

the test pressure of the equipment and shall extend the duration of the test for the time necessary to detect a 

pressure loss or rise that equals a rate of one psig per hour.

(5) An alternative procedure may be used for leak testing the equipment if the owner or operator demonstrates the 

alternative procedure is capable of detecting a pressure loss or rise.

(g) The following procedures shall be used to pressure-test batch product-process equipment using a liquid to 

demonstrate compliance with the requirements of §63.178(b)(3)(ii) of this subpart.

(1) The batch product-process equipment train, or section of the train, shall be filled with the test liquid (e.g., water, 

alcohol) until normal operating pressure is obtained. Once the equipment is filled, the liquid source shall be shut off.
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(2) The test shall be conducted for a period of at least 60 minutes, unless it can be determined in a shorter period of 

time that the test is a failure.

(3) Each seal in the equipment being tested shall be inspected for indications of liquid dripping or other indications of 

fluid loss. If there are any indications of liquids dripping or of fluid loss, a leak is detected.

(4) An alternative procedure may be used for leak testing the equipment, if the owner or operator demonstrates the 

alternative procedure is capable of detecting losses of fluid.

[59 FR 19568, Apr. 22, 1994, as amended at 59 FR 48177, Sept. 20, 1994; 61 FR 31440, June 20, 1996; 62 FR 

2792, Jan. 17, 1997; 66 FR 6936, Jan. 22, 2001]

§ 63.181 Recordkeeping requirements.

(a) An owner or operator of more than one process unit subject to the provisions of this subpart may comply with the 

recordkeeping requirements for these process units in one recordkeeping system if the system identifies each record 

by process unit and the program being implemented (e.g., quarterly monitoring, quality improvement) for each type of 

equipment. All records and information required by this section shall be maintained in a manner that can be readily 

accessed at the plant site. This could include physically locating the records at the plant site or accessing the records 

from a central location by computer at the plant site.

(b) Except as provided in paragraph (e) of this section, the following information pertaining to all equipment in each 

process unit subject to the requirements in §§63.162 through 63.174 of this subpart shall be recorded:

(1)(i) A list of identification numbers for equipment (except connectors exempt from monitoring and recordkeeping 

identified in §63.174 of this subpart and instrumentation systems) subject to the requirements of this subpart. 

Connectors need not be individually identified if all connectors in a designated area or length of pipe subject to the 

provisions of this subpart are identified as a group, and the number of connectors subject is indicated. With respect to 

connectors, the list shall be complete no later than the completion of the initial survey required by §63.174 (b)(1) or 

(b)(2) of this subpart.

(ii) A schedule by process unit for monitoring connectors subject to the provisions of §63.174(a) of this subpart and 

valves subject to the provisions of §63.168(d) of this subpart.

(iii) Physical tagging of the equipment to indicate that it is in organic HAP service is not required. Equipment subject 

to the provisions of this subpart may be identified on a plant site plan, in log entries, or by other appropriate methods.

(2)(i) A list of identification numbers for equipment that the owner or operator elects to equip with a closed-vent 

system and control device, under the provisions of §63.163(g), §63.164(h), §63.165(c), or §63.173(f) of this subpart.

(ii) A list of identification numbers for compressors that the owner or operator elects to designate as operating with an 

instrument reading of less than 500 parts per million above background, under the provisions of §63.164(i) of this 

subpart.

(iii) Identification of surge control vessels or bottoms receivers subject to the provisions of this subpart that the owner 

or operator elects to equip with a closed-vent system and control device, under the provisions of §63.170 of this 

subpart.

(3)(i) A list of identification numbers for pressure relief devices subject to the provisions in §63.165(a) of this subpart.

(ii) A list of identification numbers for pressure relief devices equipped with rupture disks, under the provisions of 

§63.165(d) of this subpart.

(4) Identification of instrumentation systems subject to the provisions of this subpart. Individual components in an 

instrumentation system need not be identified.
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(5) Identification of screwed connectors subject to the requirements of §63.174(c)(2) of this subpart. Identification can 

be by area or grouping as long as the total number within each group or area is recorded.

(6) The following information shall be recorded for each dual mechanical seal system:

(i) Design criteria required in §§63.163(e)(6)(i), 63.164(e)(2), and 63.173(d)(6)(i) of this subpart and an explanation of 

the design criteria; and

(ii) Any changes to these criteria and the reasons for the changes.

(7) The following information pertaining to all pumps subject to the provisions of §63.163(j), valves subject to the 

provisions of §63.168(h) and (i) of this subpart, agitators subject to the provisions of §63.173(h) through (j), and 

connectors subject to the provisions of §63.174(f) and (g) of this subpart shall be recorded:

(i) Identification of equipment designated as unsafe to monitor, difficult to monitor, or unsafe to inspect and the plan 

for monitoring or inspecting this equipment.

(ii) A list of identification numbers for the equipment that is designated as difficult to monitor, an explanation of why 

the equipment is difficult to monitor, and the planned schedule for monitoring this equipment.

(iii) A list of identification numbers for connectors that are designated as unsafe to repair and an explanation why the 

connector is unsafe to repair.

(8)(i) A list of valves removed from and added to the process unit, as described in §63.168(e)(1) of this subpart, if the 

net credits for removed valves is expected to be used.

(ii) A list of connectors removed from and added to the process unit, as described in §63.174(i)(1) of this subpart, and 

documentation of the integrity of the weld for any removed connectors, as required in §63.174(j) of this subpart. This 

is not required unless the net credits for removed connectors is expected to be used.

(9)(i) For batch process units that the owner or operator elects to monitor as provided under §63.178(c) of this 

subpart, a list of equipment added to batch product process units since the last monitoring period required in 

§63.178(c)(3)(ii) and (3)(iii) of this subpart.

(ii) Records demonstrating the proportion of the time during the calendar year the equipment is in use in a batch 

process that is subject to the provisions of this subpart. Examples of suitable documentation are records of time in 

use for individual pieces of equipment or average time in use for the process unit. These records are not required if 

the owner or operator does not adjust monitoring frequency by the time in use, as provided in §63.178(c)(3)(iii) of this 

subpart.

(10) For any leaks detected as specified in §§63.163 and 63.164; §§63.168 and 63.169; and §§63.172 through 

63.174 of this subpart, a weatherproof and readily visible identification, marked with the equipment identification 

number, shall be attached to the leaking equipment.

(c) For visual inspections of equipment subject to the provisions of this subpart (e.g., §63.163(b)(3), §63.163(e)(4)(i)), 

the owner or operator shall document that the inspection was conducted and the date of the inspection. The owner or 

operator shall maintain records as specified in paragraph (d) of this section for leaking equipment identified in this 

inspection, except as provided in paragraph (e) of this section. These records shall be retained for 2 years.

(d) When each leak is detected as specified in §§63.163 and 63.164; §§63.168 and 63.169; and §§63.172 through 

63.174 of this subpart, the following information shall be recorded and kept for 2 years:

(1) The instrument and the equipment identification number and the operator name, initials, or identification number.

(2) The date the leak was detected and the date of first attempt to repair the leak.
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(3) The date of successful repair of the leak.

(4) Maximum instrument reading measured by Method 21 of 40 CFR part 60, appendix A after it is successfully 

repaired or determined to be nonrepairable.

(5) “Repair delayed” and the reason for the delay if a leak is not repaired within 15 calendar days after discovery of 

the leak.

(i) The owner or operator may develop a written procedure that identifies the conditions that justify a delay of repair. 

The written procedures may be included as part of the startup/shutdown/malfunction plan, required by §63.6(e)(3), for 

the source or may be part of a separate document that is maintained at the plant site. In such cases, reasons for 

delay of repair may be documented by citing the relevant sections of the written procedure.

(ii) If delay of repair was caused by depletion of stocked parts, there must be documentation that the spare parts were 

sufficiently stocked on-site before depletion and the reason for depletion.

(6) Dates of process unit shutdowns that occur while the equipment is unrepaired.

(7)(i) Identification, either by list, location (area or grouping), or tagging of connectors that have been opened or 

otherwise had the seal broken since the last monitoring period required in §63.174(b) of this subpart, as described in 

§63.174(c)(1) of this subpart, unless the owner or operator elects to comply with the provisions of §63.174(c)(1)(ii) of 

this subpart.

(ii) The date and results of monitoring as required in §63.174(c) of this subpart. If identification of connectors that 

have been opened or otherwise had the seal broken is made by location under paragraph (d)(7)(i) of this section, 

then all connectors within the designated location shall be monitored.

(8) The date and results of the monitoring required in §63.178(c)(3)(i) of this subpart for equipment added to a batch 

process unit since the last monitoring period required in §63.178 (c)(3)(ii) and (c)(3)(iii) of this subpart. If no leaking 

equipment is found in this monitoring, the owner or operator shall record that the inspection was performed. Records 

of the actual monitoring results are not required.

(9) Copies of the periodic reports as specified in §63.182(d) of this subpart, if records are not maintained on a 

computerized database capable of generating summary reports from the records.

(e) The owner or operator of a batch product process who elects to pressure test the batch product process 

equipment train to demonstrate compliance with this subpart is exempt from the requirements of paragraphs (b), (c), 

(d), and (f) of this section. Instead, the owner or operator shall maintain records of the following information:

(1) The identification of each product, or product code, produced during the calendar year. It is not necessary to 

identify individual items of equipment in a batch product process equipment train.

(2) [Reserved]

(3) Physical tagging of the equipment to identify that it is in organic HAP service and subject to the provisions of this 

subpart is not required. Equipment in a batch product process subject to the provisions of this subpart may be 

identified on a plant site plan, in log entries, or by other appropriate methods.

(4) The dates of each pressure test required in §63.178(b) of this subpart, the test pressure, and the pressure drop 

observed during the test.

(5) Records of any visible, audible, or olfactory evidence of fluid loss.

(6) When a batch product process equipment train does not pass two consecutive pressure tests, the following 

information shall be recorded in a log and kept for 2 years:
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(i) The date of each pressure test and the date of each leak repair attempt.

(ii) Repair methods applied in each attempt to repair the leak.

(iii) The reason for the delay of repair.

(iv) The expected date for delivery of the replacement equipment and the actual date of delivery of the replacement 

equipment.

(v) The date of successful repair.

(f) The dates and results of each compliance test required for compressors subject to the provisions in §63.164(i) and 

the dates and results of the monitoring following a pressure release for each pressure relief device subject to the 

provisions in §§63.165 (a) and (b) of this subpart. The results shall include:

(1) The background level measured during each compliance test.

(2) The maximum instrument reading measured at each piece of equipment during each compliance test.

(g) The owner or operator shall maintain records of the information specified in paragraphs (g)(1) through (g)(3) of 

this section for closed-vent systems and control devices subject to the provisions of §63.172 of this subpart. The 

records specified in paragraph (g)(1) of this section shall be retained for the life of the equipment. The records 

specified in paragraphs (g)(2) and (g)(3) of this section shall be retained for 2 years.

(1) The design specifications and performance demonstrations specified in paragraphs (g)(1)(i) through (g)(1)(iv) of 

this section.

(i) Detailed schematics, design specifications of the control device, and piping and instrumentation diagrams.

(ii) The dates and descriptions of any changes in the design specifications.

(iii) The flare design (i.e., steam-assisted, air-assisted, or non-assisted) and the results of the compliance 

demonstration required by §63.11(b) of subpart A of this part.

(iv) A description of the parameter or parameters monitored, as required in §63.172(e) of this subpart, to ensure that 

control devices are operated and maintained in conformance with their design and an explanation of why that 

parameter (or parameters) was selected for the monitoring.

(2) Records of operation of closed-vent systems and control devices, as specified in paragraphs (g)(2)(i) through 

(g)(2)(iii) of this section.

(i) Dates and durations when the closed-vent systems and control devices required in §§63.163 through 63.166, and 

§63.170 of this subpart are not operated as designed as indicated by the monitored parameters, including periods 

when a flare pilot light system does not have a flame.

(ii) Dates and durations during which the monitoring system or monitoring device is inoperative.

(iii) Dates and durations of start-ups and shutdowns of control devices required in §§63.163 through 63.166, and 

§63.170 of this subpart.

(3) Records of inspections of closed-vent systems subject to the provisions of §63.172 of this subpart, as specified in 

paragraphs (g)(3)(i) and (g)(3)(ii) of this section.
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(i) For each inspection conducted in accordance with the provisions of §63.172(f)(1) or (f)(2) of this subpart during 

which no leaks were detected, a record that the inspection was performed, the date of the inspection, and a 

statement that no leaks were detected.

(ii) For each inspection conducted in accordance with the provisions of §63.172(f)(1) or (f)(2) of this subpart during 

which leaks were detected, the information specified in paragraph (d) of this section shall be recorded.

(h) Each owner or operator of a process unit subject to the requirements of §§63.175 and 63.176 of this subpart shall 

maintain the records specified in paragraphs (h)(1) through (h)(9) of this section for the period of the quality 

improvement program for the process unit.

(1) For owners or operators who elect to use a reasonable further progress quality improvement program, as 

specified in §63.175(d) of this subpart:

(i) All data required in §63.175(d)(2) of this subpart.

(ii) The percent leaking valves observed each quarter and the rolling average percent reduction observed in each 

quarter.

(iii) The beginning and ending dates while meeting the requirements of §63.175(d) of this subpart.

(2) For owners or operators who elect to use a quality improvement program of technology review and improvement, 

as specified in §63.175(e) of this subpart:

(i) All data required in §63.175(e)(2) of this subpart.

(ii) The percent leaking valves observed each quarter.

(iii) Documentation of all inspections conducted under the requirements of §63.175(e)(4) of this subpart, and any 

recommendations for design or specification changes to reduce leak frequency.

(iv) The beginning and ending dates while meeting the requirements of §63.175(e) of this subpart.

(3) For owners or operators subject to the requirements of the pump quality improvement program as specified in 

§63.176 of this subpart:

(i) All data required in §63.176(d)(2) of this subpart.

(ii) The rolling average percent leaking pumps.

(iii) Documentation of all inspections conducted under the requirements of §63.176(d)(4) of this subpart, and any 

recommendations for design or specification changes to reduce leak frequency.

(iv) The beginning and ending dates while meeting the requirements of §63.176(d) of this subpart.

(4) If a leak is not repaired within 15 calendar days after discovery of the leak, the reason for the delay and the 

expected date of successful repair.

(5) Records of all analyses required in §§63.175(e) and 63.176(d) of this subpart. The records will include the 

following:

(i) A list identifying areas associated with poorer than average performance and the associated service characteristics 

of the stream, the operating conditions and maintenance practices.
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(ii) The reasons for rejecting specific candidate superior emission performing valve or pump technology from 

performance trials.

(iii) The list of candidate superior emission performing valve or pump technologies, and documentation of the 

performance trial program items required under §§63.175(e)(6)(iii) and 63.176(d)(6)(iii) of this subpart.

(iv) The beginning date and duration of performance trials of each candidate superior emission performing 

technology.

(6) All records documenting the quality assurance program for valves or pumps as specified in §§63.175(e)(7) and 

63.176(d)(7) of this subpart.

(7) Records indicating that all valves or pumps replaced or modified during the period of the quality improvement 

program are in compliance with the quality assurance requirements in §63.175(e)(7) and §63.176(d)(7) of this 

subpart.

(8) Records documenting compliance with the 20 percent or greater annual replacement rate for pumps as specified 

in §63.176(d)(8) of this subpart.

(9) Information and data to show the corporation has fewer than 100 employees, including employees providing 

professional and technical contracted services.

(i) The owner or operator of equipment in heavy liquid service shall comply with the requirements of either paragraph 

(i)(1) or (i)(2) of this section, as provided in paragraph (i)(3) of this section.

(1) Retain information, data, and analyses used to determine that a piece of equipment is in heavy liquid service.

(2) When requested by the Administrator, demonstrate that the piece of equipment or process is in heavy liquid 

service.

(3) A determination or demonstration that a piece of equipment or process is in heavy liquid service shall include an 

analysis or demonstration that the process fluids do not meet the definition of “in light liquid service.” Examples of 

information that could document this include, but are not limited to, records of chemicals purchased for the process, 

analyses of process stream composition, engineering calculations, or process knowledge.

(j) Identification, either by list, location (area or group) of equipment in organic HAP service less than 300 hours per 

year within a process unit subject to the provisions of this subpart under §63.160 of this subpart.

(k) Owners and operators choosing to comply with the requirements of §63.179 of this subpart shall maintain the 

following records:

(1) Identification of the process unit(s) and the organic HAP's they handle.

(2) A schematic of the process unit, enclosure, and closed-vent system.

(3) A description of the system used to create a negative pressure in the enclosure to ensure that all emissions are 

routed to the control device.

[59 FR 19568, Apr. 22, 1994, as amended at 59 FR 48177, Sept. 20, 1994; 60 FR 18030, Apr. 10, 1995; 61 FR 

31441, June 20, 1996; 62 FR 2792, Jan. 17, 1997; 64 FR 20198, Apr. 26, 1999; 68 FR 37344, June 23, 2003]

§ 63.182 Reporting requirements.
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(a) Each owner or operator of a source subject to this subpart shall submit the reports listed in paragraphs (a)(1) 

through (a)(5) of this section. Owners or operators requesting an extension of compliance shall also submit the report 

listed in paragraph (a)(6) of this section.

(1) An Initial Notification described in paragraph (b) of this section, and

(2) A Notification of Compliance Status described in paragraph (c) of this section,

(3) Periodic Reports described in paragraph (d) of this section, and

(4)–(5) [Reserved]

(6) Pursuant to section 112(i)(3)(B) of the Act, an owner or operator may request an extension allowing an existing 

source up to 1 additional year beyond the compliance date specified in the subpart that references this subpart.

(i) For purposes of this subpart, a request for an extension shall be submitted to the operating permit authority as part 

of the operating permit application. If the State in which the source is located does not have an approved operating 

permit program, a request for an extension shall be submitted to the Administrator as a separate submittal. The dates 

specified in §63.6(i) of subpart A of this part for submittal of requests for extensions shall not apply to sources subject 

to this subpart.

(ii) A request for an extension of compliance must include the data described in §63.6(i)(6)(i) (A), (B), and (D) of 

subpart A of this part.

(iii) The requirements in §63.6(i)(8) through (i)(14) of subpart A of this part will govern the review and approval of 

requests for extensions of compliance with this subpart.

(b) Each owner or operator of an existing or new source subject to the provisions of this subpart shall submit a written 

Initial Notification to the Administrator, containing the information described in paragraph (b)(1), according to the 

schedule in paragraph (b)(2) of this section. The Initial Notification provisions in §63.9(b)(1) through (b)(3) of subpart 

A of this part shall not apply to owners or operators of sources subject to this subpart.

(1) The Initial Notification shall include the following information:

(i) The name and address of the owner or operator;

(ii) The address (physical location) of the affected source;

(iii) An identification of the chemical manufacturing processes subject to this subpart; and

(iv) A statement of whether the source can achieve compliance by the applicable compliance date specified in the 

subpart in 40 CFR part 63 that references this subpart.

(2) The Initial Notification shall be submitted according to the schedule in paragraph (b)(2)(i), (b)(2)(ii), or (b)(2)(iii) of 

this section, as applicable.

(i) For an existing source, the Initial Notification shall be submitted within 120 days after the date of promulgation of 

the subpart that references this subpart.

(ii) For a new source that has an initial start-up 90 days after the date of promulgation of this subpart or later, the 

application for approval of construction or reconstruction required by §63.5(d) of subpart A of this part shall be 

submitted in lieu of the Initial Notification. The application shall be submitted as soon as practicable before the 

construction or reconstruction is planned to commence (but it need not be sooner than 90 days after the date of 

promulgation of the subpart that references this subpart).
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(iii) For a new source that has an initial start-up prior to 90 days after the date of promulgation of the applicable 

subpart, the Initial Notification shall be submitted within 90 days after the date of promulgation of the subpart that 

references this subpart.

(c) Each owner or operator of a source subject to this subpart shall submit a Notification of Compliance Status within 

90 days after the compliance dates specified in the subpart in 40 CFR part 63 that references this subpart, except as 

provided in paragraph (c)(4) of this section.

(1) The notification shall provide the information listed in paragraphs (c)(1)(i) through (c)(1)(iv) of this section for each

process unit subject to the requirements of §63.163 through §63.174 of this subpart.

(i) Process unit identification.

(ii) Number of each equipment type (e.g., valves, pumps) excluding equipment in vacuum service.

(iii) Method of compliance with the standard (for example, “monthly leak detection and repair” or “equipped with dual 

mechanical seals”).

(iv) Planned schedule for each phase of the requirements in §63.163 and §63.168 of this subpart.

(2) The notification shall provide the information listed in paragraphs (c)(2)(i) and (c)(2)(ii) of this section for each 

process unit subject to the requirements of §63.178(b) of this subpart.

(i) Batch products or product codes subject to the provisions of this subpart, and

(ii) Planned schedule for pressure testing when equipment is configured for production of products subject to the 

provisions of this subpart.

(3) The notification shall provide the information listed in paragraphs (c)(3)(i) and (c)(3)(ii) of this section for each 

process unit subject to the requirements in §63.179 of this subpart.

(i) Process unit identification.

(ii) A description of the system used to create a negative pressure in the enclosure and the control device used to 

comply with the requirements of §63.172 of this subpart.

(4) For existing sources subject to subpart F of this part, the Notification of Compliance Status shall be submitted for 

the group of process units with the earliest compliance date specified in §63.100(k) of subpart F of this part, by no 

later than 90 days after the compliance date for that group. The Notification of Compliance Status for each 

subsequent group shall be submitted as part of the first periodic report that is due not less than 90 days after the 

compliance date for that group.

(d) The owner or operator of a source subject to this subpart shall submit Periodic Reports.

(1) A report containing the information in paragraphs (d)(2), (d)(3), and (d)(4) of this section shall be submitted 

semiannually starting 6 months after the Notification of Compliance Status, as required in paragraph (c) of this 

section. The first periodic report shall cover the first 6 months after the compliance date specified in §63.100(k)(3) of 

subpart F. Each subsequent periodic report shall cover the 6 month period following the preceding period.

(2) For each process unit complying with the provisions of §63.163 through §63.174 of this subpart, the summary 

information listed in paragraphs (i) through (xvi) of this paragraph for each monitoring period during the 6-month 

period.

(i) The number of valves for which leaks were detected as described in §63.168(b) of this subpart, the percent 

leakers, and the total number of valves monitored;
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(ii) The number of valves for which leaks were not repaired as required in §63.168(f) of this subpart, identifying the 

number of those that are determined nonrepairable;

(iii) The number of pumps for which leaks were detected as described in §63.163(b) of this subpart, the percent 

leakers, and the total number of pumps monitored;

(iv) The number of pumps for which leaks were not repaired as required in §63.163(c) of this subpart;

(v) The number of compressors for which leaks were detected as described in §63.164(f) of this subpart;

(vi) The number of compressors for which leaks were not repaired as required in §63.164(g) of this subpart;

(vii) The number of agitators for which leaks were detected as described in §63.173(a) and (b) of this subpart;

(viii) The number of agitators for which leaks were not repaired as required in §63.173(c) of this subpart;

(ix) The number of connectors for which leaks were detected as described in §63.174(a) of this subpart, the percent 

of connectors leaking, and the total number of connectors monitored;

(x) [Reserved]

(xi) The number of connectors for which leaks were not repaired as required in §63.174(d) of this subpart, identifying 

the number of those that are determined nonrepairable;

(xii) [Reserved]

(xiii) The facts that explain any delay of repairs and, where appropriate, why a process unit shutdown was technically 

infeasible.

(xiv) The results of all monitoring to show compliance with §§63.164(i), 63.165(a), and 63.172(f) of this subpart 

conducted within the semiannual reporting period.

(xv) If applicable, the initiation of a monthly monitoring program under §63.168(d)(1)(i) of this subpart, or a quality 

improvement program under either §§63.175 or 63.176 of this subpart.

(xvi) If applicable, notification of a change in connector monitoring alternatives as described in §63.174(c)(1) of this 

subpart.

(xvii) If applicable, the compliance option that has been selected under §63.172(n).

(3) For owners or operators electing to meet the requirements of §63.178(b) of this subpart, the report shall include 

the information listed in paragraphs (i) through (v) of this paragraph for each process unit.

(i) Batch product process equipment train identification;

(ii) The number of pressure tests conducted;

(iii) The number of pressure tests where the equipment train failed the pressure test;

(iv) The facts that explain any delay of repairs; and

(v) The results of all monitoring to determine compliance with §63.172(f) of this subpart.
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(4) The information listed in paragraph (c) of this section for the Notification of Compliance Status for process units 

with later compliance dates. Any revisions to items reported in earlier Notification of Compliance Status, if the method 

of compliance has changed since the last report.

[59 FR 19568, Apr. 22, 1994, as amended at 59 FR 48178, Sept. 20, 1994; 60 FR 18030, Apr. 10, 1995; 60 FR 

63631, Dec. 12, 1995; 62 FR 2792, Jan. 17, 1997]

§ 63.183 Implementation and enforcement.

(a) This subpart can be implemented and enforced by the U.S. EPA, or a delegated authority such as the applicable 

State, local, or Tribal agency. If the U.S. EPA Administrator has delegated authority to a State, local, or Tribal agency, 

then that agency, in addition to the U.S. EPA, has the authority to implement and enforce this subpart. Contact the 

applicable U.S. EPA Regional Office to find out if implementation and enforcement of this subpart is delegated to a 

State, local, or Tribal agency.

(b) In delegating implementation and enforcement authority of this subpart to a State, local, or Tribal agency under 

subpart E of this part, the authorities contained in paragraph (c) of this section are retained by the Administrator of 

U.S. EPA and cannot be transferred to the State, local, or Tribal agency.

(c) The authorities that cannot be delegated to State, local, or Tribal agencies are as specified in paragraphs (c)(1) 

through (4) of this section.

(1) Approval of alternatives to the requirements in §§63.160, 63.162 through 63.176, 63.178 through 63.179. Follow 

the applicable procedures of §63.177 to request an alternative means of emission limitation for batch processes and 

enclosed-vented process units. Where these standards reference another subpart, the cited provisions will be 

delegated according to the delegation provisions of the referenced subpart. Where these standards reference another 

subpart and modify the requirements, the requirements shall be modified as described in this subpart. Delegation of 

the modified requirements will also occur according to the delegation provisions of the referenced subpart.

(2) Approval of major alternatives to test methods under §63.7(e)(2)(ii) and (f), as defined in §63.90, and as required 

in this subpart.

(3) Approval of major alternatives to monitoring under §63.8(f), as defined in §63.90, and as required in this subpart.

(4) Approval of major alternatives to recordkeeping and reporting under §63.10(f), as defined in §63.90, and as 

required in this subpart.

[68 FR 37345, June 23, 2003]

Table 1 to Subpart H of Part 63—Batch Processes

Monitoring Frequency for Equipment Other than Connectors

Operating time (% of 

year)

Equivalent continuous process monitoring frequency time in 

use

Monthly Quarterly Semiannually

0 to <25 Quarterly Annually Annually.

25 to <50 Quarterly Semiannually Annually.

50 to <75 Bimonthly Three times Semiannually.

75 to 100 Monthly Quarterly Semiannually.
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Table 2 to Subpart H of Part 63—Surge Control Vessels and Bottoms 

Receivers at Existing Sources

Vessel capacity (cubic meters) Vapor pressure1(kilopascals)

75 ≤ capacity < 151 ≥13.1

151 ≤ capacity ≥ 5.2a

1

Maximum true vapor pressure of total organic HAP at operating temperature as defined in subpart G of this part.

[60 FR 18025, Apr. 10, 1995]

Table 3 to Subpart H of Part 63—Surge Control Vessels and Bottoms 

Receivers at New Sources

Vessel capacity (cubic meters) Vapor pressure1(kilopascals)

38 ≤ capacity < 151 ≥ 13.1

151 ≤ capacity ≥ 0.7

1

Maximum true vapor pressure of total organic HAP at operating temperature as defined in subpart G of this part.

[60 FR 18025, Apr. 10, 1995]

Table 4 to Subpart H of Part 63—Applicable 40 CFR Part 63 General 

Provisions

40 CFR part 63, subpart A, provisions applicable to subpart H

§63.1(a)(1), (a)(2), (a)(3), (a)(13), (a)(14), (b)(2) and (c)(4)

§63.2

§63.5(a)(1), (a)(2), (b), (d)(1)(ii), (d)(4), (e), (f)(1) and (f)(2)

§63.6(a), (b)(3), (c)(5), (i)(1), (i)(2), (i)(4)(i)(A), (i)(5) through (i)(14), (i)(16) and (j)

§63.9(a)(2), (b)(4)(i)a, (b)(4)(ii), (b)(4)(iii), (b)(5)a, (c) and (d)

§63.10(d)(4)

§63.11 (c), (d), and (e)

§63.12(b)

a

The notifications specified in §63.9(b)(4)(i) and (b)(5) shall be submitted at the times specified in 40 CFR part 65.

[65 FR 78285, Dec. 14, 2000, as amended at 73 FR 78213, Dec. 22, 2008]


Indiana Department of Environmental Management

Office of Air Quality

Addendum to the Technical Support Document (ATSD) for a PSD/New Source 

Construction and Part 70 Operating Permit (Title V)

Source Description and Location

Source Name: Indiana Gasification, LLC

Source Location: CR 200 N and Base Road, Rockport, IN 47635

County: Spencer

SIC Code: 4925, 2819

Operation Permit No.: T 147-30464-00060

Permit Reviewer: Josiah Balogun

Public Notice Information

On December 15, 2011, the Office of Air Quality (OAQ) had a notice published in the Journal Democrat in 

Rockport, Indiana, stating that Indiana Gasification, LLC had applied for a PSD/New Source Construction 

and Part 70 Operating Permit (TITLE V) to operate a natural gas (SNG) and liquefied carbon dioxide (CO2) 

production plant. The notice also stated that OAQ proposed to issue a Title V permit for this operation and 

provided information on how the public could review the proposed Title V permit and other documentation. 

Finally, the notice informed interested parties that there was a period of forty - seven (47) days to provide 

comments on whether or not this Title V permit should be issued as proposed.

On January 25, 2012, the Office of Air Quality (OAQ) held a public meeting and hearing at the 

South Spencer High School Auditorium in Rockport, Indiana, for citizens and interested parties to discuss 

questions and concerns related to the project.

No changes have been made to the TSD because the OAQ prefers that the Technical Support 

Document reflects the permit that was on public notice. Changes that occur after the public 

notice are documented in this Addendum to the Technical Support Document. This 

 accomplishes the desired result, ensuring that these types of concerns are documented and 

part of the record regarding this permit decision.

Comments Received from USEPA

On February 2, 2012, Sam Portanova of USEPA submitted comments on the proposed Title V 

Operating Permit. The comments are summarized in the subsequent pages, with IDEM’s corresponding 

responses.

Comment 1: The permit record does not appear to include any air quality analysis to show that this 

source will not cause a violation of the ozone national ambient air quality standards. 40 

C.F.R. 51.166(k); 40 C.F.R. 51.166(m). EPA's 8-hour ozone implementation phase 2 rule 

(November 29, 2005; 70 FR 71612) requires that NOx be considered as an ozone 

precursor under PSD. One of the elements of that rule is a requirement that the PSD 

program regulations define the term “significant” for ozone to include 40 tons per year 

(tpy) of NOx. See 40 CFR 51.166(b)(23)(i). In accordance with 40 CFR 51.166(m)(1)(a), 

a permit application must contain an air quality analysis for each pollutant that a new 

source would have the potential to emit in significant amounts. Since the proposed 

Indiana Gasification permit has NOx emissions above this significance threshold for 

ozone, EPA regulations require that the record contain an ozone impact analysis for this 

source. A quantitative modeling analysis is not necessarily required, but IDEM should 
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consult with EPA Region 5 regarding the appropriate form for such an analysis in this 

case. 40 CFR Part 51, Appendix W, §5.2.1.c. Although IDEM is in the process of 

adopting the requirements of the Phase 2 rule into the Indiana state implementation plan, 

even before those rules are finalized, EPA’s expectation is that IDEM will conduct a 

source impact analysis on ozone for sources emitting NOx over the 40 tpy significance 

level for ozone to ensure that its permits are consistent with the Clean Air Act and the 

minimum requirements described in 40 CFR 51.166 for state PSD permitting programs.

Response 1: U.S. EPA explains in its letter responding to the Sierra Club’s July 28, 2010, rulemaking 

petition to designate air quality models for ozone and PM2.5 for use by all major sources 

applying for a PSD permit that, because “[t]he complex chemistry of ozone and secondary 

formation of PM2.5 are well-documented and have historically presented significant 

challenges to the designation of particular models for assessing the impacts of individual 

stationary sources on the formation of these air pollutants,” the Agency’s position has 

been that it “was not technically sound to designate with particularity specific models that 

must be used to assess the impacts of a single source on ozone concentrations.” Letter 

from Gina McCarthy, U.S. EPA Office of Air and Radiation, to Robert Ukeiley, 2 (Jan. 4, 

2012). Instead, to comply with the requirements of CAA § 165(e)(3)(D), the Agency’s 

practice has been to have its regional offices consult with state/local agencies on a caseby-case basis regarding the appropriate models or other analytical techniques that should 

be used. U.S. EPA Jan. 4, 2012, letter at 2; see 40 C.F.R. Part 51, Appendix W, Sec. 

5.2.1.c (“Estimating the Impact of Individual Sources. Choice of methods used to assess 

the impact of an individual source depends on the nature of the source and its emissions. 

Thus, model users should consult with the regional office to determine the most suitable 

approach on a case-by-case basis.”) 

IDEM has consulted with U.S. EPA Region 5 and explains below its analysis.

Ozone is a photochemical pollutant that is not generally emitted directly from sources, but 

is a secondary pollutant created through complex reactions, primarily from volatile organic 

compounds (VOCs) and oxides of nitrogen (NOx). This complex chemistry is well 

understood but has historically presented significant challenges to the designation of 

particular models for assessing the impacts of individual stationary sources for the 

formation of this pollutant. Since formation of ozone takes place over 10’s to 100’s of 

kilometers downwind from sources, regional models have been developed to simulate 

ozone levels over large areas. These models have worked well and have been used to 

develop strategies for reducing VOCs and NOx in order to attain the ozone ambient air 

quality standards. However, changes from additions of individual sources have not 

shown any impact in these regional models.

Given the limited significance of Indiana Gasification’s emissions, 16 tons per year for 

VOCs and 127 tons per year for NOx, the analysis set forth below demonstrates that the 

IG project would not have an effect on the attainment status. Examining the point source 

emissions for Spencer County for 2010, VOCs and NOx account for 27,978 tons per year. 

Most of those emissions are coming from the AEP Rockport power plant. Indiana 

Gasification’s potential emissions for VOCs and NOx are 143 tons per year for both 

pollutants, and would represent only 0.5% of the total of NOx and VOC point source 

emissions for the county. If other potential ozone precursor emitting sources are 

included, such as biogenics, area, and on/off road mobile source emissions for this 

county, this would decrease the percentage of IG’s overall potential contribution for ozone 

formation. While production of ozone is not a linear relationship to emissions, analysis of 

IG’s emissions demonstrates the impacts of this project will be below detectable levels. 

As described below, because it will only be emitting less than 0.5% of the emissions for 

that county, its ozone contribution would be insignificant and immeasurable. 

. 
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Since ozone is a regional pollutant as explained above and not just county specific, IDEM 

further evaluated the ozone formation in that area using the modeling analysis used in the 

Cross State Air Pollution Rule (CSAPR).

Ozone Analysis for Indiana Gasification – U. S. EPA’s CSAPR Modeling

Because of the well established relationship between nitrogen oxides (NOx) and volatile 

organic compounds (VOCs), regional transport, and the formation of ozone, U.S. EPA 

recently finalized the CSAPR to assist states in meeting the ozone NAAQS. This rule 

included extensive modeling to support the emissions reductions necessary in each state 

to achieve the ozone NAAQS in the eastern U.S. The source category responsible for 

these reductions is Electric Generating Units (EGUs). 

U.S. EPA used a regional model, Comprehensive Air Quality Model with extensions 

(CAMx), and the Air Quality Assessment Tool (AQAT), to determine levels of reduction 

from EGUs necessary to achieve the NAAQS at every site. The documentation includes 

extensive tables showing impacts at all ozone monitors in the eastern U.S. and emission 

reduction levels necessary to achieve those results. To examine the possible impact of 

Indiana Gasification (IG), IDEM used the U.S. EPA modeling conducted to establish the 

final 2014 budgets in CSAPR. The CSAPR website is located at 

http://www.epa.gov/crossstaterule/techinfo.html.

Information regarding the NOx emission reductions necessary to achieve the future year 

modeled design values can be found in the “EmissionsSummaries.xlsx spreadsheet 

under the Emissions Inventory Final Rule TSD section at EPA’s CSAPR website for 

technical information, http://www.epa.gov/crossstaterule/techinfo.html. The spreadsheet 

shows the base case annual NOx emissions for Indiana by 2014 at 431,342 tons and 

remedy control scenario annual NOx emissions by 2014 at 424,250 tons. Indiana’s total 

NOx emission reduction between these scenarios is 7,092 tons. All surrounding states 

make similar significant reductions. IG emissions will be 127 tons per year of NOx and 

15.9 tons per year of VOCs. For purposes of this analysis, the IG emissions will be 

analyzed at 143 tons per year.

8-Hour Ozone Modeling Results

The nearest ozone monitor to Spencer County is the Leopold ozone monitor in Perry 

County. Leopold’s current design value for 2009-2011 is 70 parts per billion (ppb), below 

the 8-hour NAAQS of 75 ppb. The maximum 8-hour ozone modeled concentrations for 

Perry County are 73.1 ppb for the 2014 base case and 72.6 ppb for the 2014 control 

scenario. This is a reduction of 0.5 ppb as a result of NOx emission reductions from 

CSAPR. In order for this modeled annual concentration reduction from CSAPR to occur, 

Indiana’s 2014 NOx emissions were reduced by 7,092 tons of NOx. This particular 

monitoring site is not necessarily impacted by every EGU in Indiana, but in the 

surrounding states, thousands of tons of annual NOx emission reductions also will have 

occurred by 2014, many of which would impact this site. Therefore, to estimate the 

impact of IG on modeled concentrations, the ratio of IG NOx and VOC emissions to the 

NOx emission reductions from CSAPR are compared to the ratio of IG ozone impact by 

the difference between the base case and remedy control modeling results. 

IG’s impact on ozone is estimated as: 

143 tons NOx and VOC/7,092 tons NOx = 0.02 *0.5 ppb = 0.01 ppb of IG ozone

impact.

This equates to only about 0.01% of the projected regional ozone level (2014 

modeled Remedy results shown in the table below).

Table 1, below, shows the CSAPR modeling results for nearby ozone monitors and the 

impact that IG would have on ozone concentrations in the area. Base case and remedy 
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concentrations come from tables located in CSAPR_AQModeling.pdf, Appendix B, pages 

B-10 and B-12 for 8-hour ozone design values that show the projected base case 2014 

ozone concentrations at surrounding monitoring sites versus control strategy ozone

concentrations. 2014 Base represents modeled results taken from the anticipated 2014 

emissions. 2014 Remedy represents the 2014 Base emissions with emission reductions 

from CSAPR factored into the modeling. 

Table 1: EPA’s Cross-State Air Pollution Rule 8-Hour Ozone Modeling Results

Monitor ID County

2014

Base

(ppb)

2014

Remedy

(ppb)

2014

BaseRemedy

(ppb)

Anticipated 

Source Impact

(ppb)

Source 

(IG)

Impact of 

2014 

Remedy

(%)

181230009 Perry 73.1 72.6 0.5 0.01 0.0138%

180710001 Jackson 66.2 65.8 0.4 0.008 0.0122%

181730008 Warrick 71.6 71.3 0.3 0.006 0.0084%

181730009 Warrick 65.7 65.3 0.4 0.008 0.0123%

181730011 Warrick 69.0 68.7 0.3 0.006 0.0087%

Based on this analysis, IG’s impact to regional ozone is expected to be only about 1/100th

of one percent. To further show the impact this increase would have upon monitoring 

results, the method detection limit for ozone monitors used in Indiana ozone monitoring 

network is 0.5 ppb. Values contained in Table 1 (0.01 ppb or less) would not be 

measurable.

Summary

Indiana Gasification’s NOx and VOC emissions were compared with U.S. EPA CSAPR 

modeling for 8-hour ozone to determine what impacts on ozone may occur as a result of 

ozone formation. When the IG emissions were compared with the amount of NOx 

emission reductions realized from CSAPR and compared with CSAPR modeling results 

for 8-hour ozone, the impacts from IG on nearby ozone monitors in Perry, Warrick and 

Jackson Counties are anticipated to be below detectable levels and would not have an 

effect on the attainment status of those counties.

Comment 2: The draft permit does not show the potential to emit (PTE) for total GHG emissions. 

Please add the GHG PTE to the permit, either on a mass basis for the individual GHG 

gases or on a CO2 equivalent (CO2e) basis. The GHG PTE should account for CO2

emissions and any other GHG emitted from the facility (e.g., methane, nitrous oxide).

Response 2: The PTE for total GHG—expressed as CO2e—is fully documented in the TSD for each 

emissions unit and for the facility as a whole (see TSD pages 7 and 9–11, as well as 

emissions tables at end of TSD document, starting on page 398 of the 880-page PDF). 

Comment 3: The draft permit contains emission limits for CO2, but does not contain limits for other 

GHG pollutants. Please clarify, in the permit record, how compliance will be 

demonstrated for any non-CO2 GHG emitted from the facility.
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Response 3: CO2 was selected as a surrogate for point source CO2e emissions for three reasons. 

First, the other point source GHG emissions are incidental to combustion and have a 

direct relationship to and are proportionate to fuel use and the associated CO2 emissions. 

Thus, limitations on CO2 will directly and proportionately limit non-CO2, point source GHG 

emissions. Second, point source GHG emissions at the proposed facility total 2.18 tons 

per year CH4 and 0.34 tons per year N2O, for a total of 151.18 tons per year CO2e. Point 

source CO2 emissions from this proposed facility total 1,875,000 tons per year. The 

relative contribution of CH4 and N2O to total point source CO2e (0.0081%) is insignificant 

and does not warrant separate limits. Third, the principal source of CH4 and N2O is fuel 

combustion in the auxiliary boiler and engines, and there are no known supplemental 

controls for such units that could support rational separate emission limits for those 

GHGs. Consequently, CO2 was selected as the surrogate for all point source GHG 

emissions at the proposed facility. Compliance for GHGs other than CO2 from such 

sources can and will be demonstrated through the emission limits for CO2. The 

explanation of this approach is in the current record at several points. (For example, see 

TSD BACT Analysis text at page 149 of 181).

The only instances where CO2 is not an adequate surrogate are in the case of fugitive 

SF6 emissions from circuit breakers (FUG-SF6), and fugitive CH4 emissions from 

equipment (FUG). For this reason, emissions of these GHG pollutants are addressed with 

appropriate permit conditions for those pollutants and the processes from which they are 

emitted (see BACT analysis in TSD for emissions units FUG and FUG-SF6).

Comment 4: Please clarify, in the permit record, whether there are any GHG emissions from the 

gasifier.

Response 4: No. The gasifier is not an emission source except for small amounts of fugitive emissions,

which are included in the emission calculations together with other fugitive emissions and 

described as FUG emissions. There are GHG emissions associated with the pre-heat 

burners, identified as EU-008A-E. IDEM wrote a GHG BACT analysis for these emission 

units and also established a limit for them in the permit.

Comment 5: The flare minimization plan requirement (permit conditions D.2.4(1)(D), D.2.4(2)(C), 

D.2.4(3)(B), and D.2.4(B)) for this unit applies during startups, shutdowns, and other 

flaring events. The best available control technology (BACT) emissions limits for 

PM/PM10/PM2.5, CO, SO2, and NOx apply to startup and shutdown, but does not mention 

limits for other flaring events. Since BACT applies at all times, the permit should include 

BACT limits that apply during other flaring events. The permit may specify different BACT 

limits that apply during other flaring events but cannot exclude BACT limits during those 

events.

Response 5: US EPA is correct that the numeric emissions limits in the permit for flaring events are 

applicable only to startup and shutdown events (e.g., Condition D.2.4(1)(D)). This is 

because startups and shutdowns are the only operating scenarios in which flaring is 

expected in normal operation. Outside of startups or shutdowns, in normal operation the 

only emissions from the flare will be the combustion emissions from the pilot. The term 

“other flaring events” referenced in the permit condition regarding requirements of a flare 

minimization plan (e.g., Condition D.2.4(1)(A)) is referring to upsets or malfunctions. For 

this facility, upset flaring is anticipated to be very infrequent. However, as explained more 

fully in response to Sierra Club Comments 5 and 78, due to the inherently unpredictable 

nature of malfunction events, IDEM is requiring IG to implement extensive BACT work 

practice requirements which apply during malfunction flaring, instead of numeric limits. 

These work practices are required at all times and include use of flare best practices 

(e.g., Condition D.2.4(1)(B)) and a requirement to follow the flare minimization plan (e.g.; 

Condition D.2.4(1)(A)) which includes, among other requirements, a requirement to 
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investigate the “root cause” of malfunction events that cause gases to be sent to a flare, 

and implementation of preventative measures to minimize re-occurrence of these events.

Thus, the permit contains numeric BACT emission limits which apply to planned flaring 

(startups and shutdowns), and BACT design/work practice requirements which apply at all 

times. 

Comment 6: Permit condition D.2.4(3)(B) limits SO2 emissions during a shutdown event to 85.21 

pounds per hour (lb/hr) or 255.6 lb per 24-hour period. The technical support document 

lists SO2 emissions from this flare as 1.97 tpy. However, the 255.6 lb per 24-hour limit 

could result in maximum SO2 emissions of 46.65 tpy. Given the disparity between the 

projected limits and the maximum potential limits, please explain how the source expects 

to limit the total frequency and duration of shutdown events.

Response 6: The annual flare SO2 emissions estimate of 1.97 tpy is based on a conservative estimate 

of the number of startups and shutdowns per year. It is comprised of an estimated 0.05 

tpy startup flaring and 1.92 tpy of shutdown flaring. To ensure that the frequency and 

duration of these events are consistent with this permit evaluation, annual limits of these 

amounts for startup and shutdown will be added to the permit. The same monitoring and 

recordkeeping required to comply with the daily limit will support demonstration of 

compliance with these annual limits. The quarterly reports form for the SO2 emissions 

have been added to the permit.

D.2.4 PM, PM10 and PM2.5, CO, SO2, NOx and GHGs PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the 

Syngas Hydrocarbon Flare, identified as EU-001 shall be as follows:

..........................................................................................................................................

(3) The SO2 emissions from the Syngas Hydrocarbon Flare, identified as (EU-001) 

shall be limited as follows:

.............................................................................................................................

The SO2 emissions from the Syngas Hydrocarbon Flare during a shutdown event 

shall not exceed 85.21 lb/hr based on a 3-hour average and shall not exceed 

255.6 lbs per 24 hours and shall not exceed 1.92 tons per twelve (12) 

consecutive month period with compliance determined at the end of each 

month. The SO2 emissions from the Syngas Hydrocarbon Flare shall not exceed 

0.35 lb/hour during startup, based on a 3-hour average and shall not exceed 

0.05 tons per twelve (12) consecutive month period with compliance 

determined at the end of each month.

Comment 7: Permit conditions D.4.9(c) and D.4.9(d) list a CO2 BACT emission limit of 1,290,000 tpy 

for the AGR units that represents a significant reduction in emissions compared to the 

first two years of operation. This CO2 reduction is to be achieved by the production of 

liquified CO2 that will be sold to third parties for use in enhanced oil recovery. Permit 

condition D.4.16 includes a compliance determination method for CO2 emissions; 

however, this condition does not appear to account for monitoring CO2 emissions from 

the liquefaction process. The permit should include a monitoring requirement that 

accounts for the removal of CO2 from the AGR emission stream in order to demonstrate 

compliance with the 1,290,000 tpy limit for emissions of CO2 from the facility. 

Response 7: With respect to monitoring the CO2 from the AGR vent, the AGR will isolate CO2 to 

produce a 98% pure CO2 stream. (See IG Permit Application Section 2.0). That CO2 is 

either compressed and liquefied for sale or routed to one of the RTOs prior to venting. 

Flow to the RTOs is to be monitored continuously as anticipated by Draft Permit 

Conditions D.4.11 and D.4.24(d). CO2 emitted through the AGR vent (outlet of the RTO) is 

determined using the method set forth in Draft Permit Condition D.4.16, which takes into 
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account the flow and the CO2 concentration of flow to the RTOs. 

While monitoring and recordkeeping of the vent flow from the AGR to the RTOs is required 

in the proposed permit, a permit language amendment in Section D.4 will make clear the 

requirement to calibrate, maintain and operate those flow meters.

With respect to the monitoring of CO2 emissions from the liquefaction process, liquefaction 

is performed through electric-power compressors that do not themselves emit combustionrelated CO2. The fugitive CO2 emissions from the compressors are addressed in the leak 

detection and repair requirements of permit condition D.15.4. The CO2 emissions from the 

compressors are estimated as no more than 4 tons per year (see TSD at page 11).

The following changes have been made in the permit.

D.4.22 Vent Flow Monitoring 

In order to demonstrate the compliance status with Conditions D.4.6 – SO2 PSD BACT, 

D.4.9 - GHGs PSD BACT, D.4.11 – HAPs Minor Limit, D.4.15 – Sulfur Dioxide Control, and 

D.4.16 - Greenhouse Gases (GHGs) Calculations, a continuous monitoring system shall be 

calibrated, maintained, and operated on AGR vent flow to continuously monitor the vent 

flow from the AGR to the thermal oxidizers. For the purposes of this condition, continuous 

monitoring shall mean no less often than once per fifteen (15) minutes. The output from 

this monitoring system shall be recorded whenever the AGRs are in operation. 

.......................................................................................................................................................

D.4.234 Record Keeping Requirements

..............................................................................................................................................

(d) To document the compliance status with condition D.4.11, the Permittee shall maintain 

records in accordance with (1) through (4) below. Records maintained for (1) through (4) 

shall be taken monthly when the unit is in operation and shall be complete and sufficient 

to establish compliance with the HAP emission limits established in condition D.4.11.

(1) The monthly records of the flow rate of gas vented to the thermal oxidizer

methanol, carbonyl sulfide, and total HAPs emissions.

(2) The temperature of the Monthly records of when the RTO is in standby 

mode.

(3) The water flow rate of the water wash tower (if used).

(4) The results of the most recent stack test showing setting the emission factors 

for thermal oxidizer destruction efficiency for VOC and methanol, carbonyl 

sulfide, and total HAPs emissions and inlet and outlet methanol and VOC 

concentrations during the test. 

(e) In order to document the compliance status with Conditions D.4.6 – SO2 PSD BACT and 

D.4.15 – Sulfur Dioxide Control, the Permittee shall maintain monthly records of the sulfur 

content in the AGR vent stream. 

(f) In order to document the compliance status with Conditions D.4.22 - Vent Flow 

Monitoring, D.4.6 – SO2 PSD BACT, D.4.9 - GHGs PSD BACT, D.4.15 – Sulfur Dioxide 

Control, and D.4.16 - Greenhouse Gases (GHGs) Calculations, the Permittee shall 

maintain monthly records of the vent flow from the AGRs into the RTOs.

......................................................................................................................................................
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Comment 8: A continuous emission monitoring system (CEMS) for NOx, SO2, and CO2 is being 

proposed for the wet sulfuric acid (WSA) plant but not the AGR system vent. Since the 

AGR vent is the largest source of GHG emissions from the facility, please clarify whether 

a CO2 CEMS was considered for the AGR vent and, if so, why a CO2 CEMS was not 

included in the draft permit.

Response 8: There are three substantial differences between the WSA and the AGR relevant to 

whether a CO2 CEMS is appropriate: 

First, in contrast to the AGR stream described below, the concentration of the CO2 in the 

WSA can vary based on composition of the feedstock and the relative portions of coal 

versus coke feed. The composition of the gas being emitted from the AGRs will not vary 

significantly. The AGR stream for pipeline quality requirements will be nearly pure CO2, 

with the rest being mostly CO which combusts in the RTO to CO2. The compliance 

demonstration calculation for the AGR/RTO emissions of CO2 accounts for the CO2 in 

the exhaust, as well as the CO and organics that are converted to CO2. Due to 

conservative default factors, the equation in the permit at Section D.4.16 results in all the 

flow being treated as CO2. Any variability that would occur would be within the 1% relative 

accuracy of CO2 concentration in a CEMS. Accordingly, a CEMS will offer no 

improvement in the CO2 tracking of this source. 

Second, the WSA will already have NOx and SO2 CEMs and, therefore, the incremental 

cost to add and maintain a CO2 CEM is less for the WSA. In contrast, no other CEMS is 

required for the AGR vent. 

Third, the AGR vent will operate only intermittently, whereas the WSA will be operated 

continuously.

Therefore, monitoring AGR vent flow to the RTO is the appropriate monitoring requirement 

and provides a continuous and accurate method of quantifying and tracking emissions of 

CO2 from this source. 

Comment 9: Permit condition D.4.11 limits methanol emissions at the AGR units to 9.0 tons per 12-

month period and combined hazardous air pollutant (HAP) emissions to 22.5 tons per 12-

month period so that the source remains below the major source threshold for HAPs. 

The permit includes monitoring, reporting, and recordkeeping requirements for the 

methanol limit; however, the permit does not include monitoring requirements to assure 

compliance with the combined HAP limit. Furthermore, we note that the calculations 

attached to the draft permit document show potential HAP emissions above the 25 tpy 

major source threshold. Please include monitoring requirements in the permit to assure 

compliance with the combined HAP emissions limit.

Response 9: The requirements for HAPs associated with the AGR units are being revised in response 

to this comment. In particular, a limit on COS is being added, the total HAPs limit for the 

AGR is being reduced, the stack testing of the RTOs is being expanded to include a 

broader spectrum of organic HAPs, and a requirement to use that testing to set emissions 

factors for HAPs for the AGR is being added. In addition, the method for demonstrating 

compliance with the methanol limit on the AGR units is being revised to simplify the 

equation, and the method for demonstrating compliance with the COS and total HAP 

limits on the AGR units are being added.

Below is the revised language for conditions D.4.11 and D.4.19 that address compliance 

with the HAP limits on the AGR units.
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D.4.11 Hazardous Air Pollutants (HAPs) Minor Limits

(a) The Acid Gas Recovery Units, identified as EU-007A/B, Methanol and Carbonyl 

Sulfide (COS) emissions shall, each 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 Acid Gas Recovery Units, identified as EU-007A/B, combined Hazardous Air 

Pollutants (HAPs) emissions shall be limited to less than 22.5 17.0 tons per 

twelve (12) consecutive month period, with compliance determined at the end of 

each month.

(c) The methanol emissions from the AGRs shall be calculated by the following 

equation:

Methanol emissions = Vent Flow x Methanol Conc. x (1 – Control Effic.)

Emissions Factor

Where:

Vent Flow = Total AGR vent flow to the thermal oxidizers (million SCF/period) 

to be monitored continuously by the Permittee.

Methanol Conc. Emissions Factor = Methanol Concentration emitted per 

million standard cubic feet of vent gas of the inlet to the thermal oxidizer (lbs

methanol/million MMSCF of vent gas) as determined in the most recent 

compliance stack test of the oxidizer. Until the initial compliance stack testing is 

performed, the engineering estimate of 12.70.127 lbs methanol emitted/million 

SCF of vent flow shall be used.

Control Effic. = The control efficiency of the Regenerative Thermal Oxidizer as 

 determined by stack test. Until the initial stack test is performed, 

the engineering estimate of 99% control shall be used.

(d) The carbonyl sulfide emissions from the AGRs shall be calculated by the 

following equation:

Carbonyl Sulfide emissions = Vent Flow x Carbonyl Sulfide Emissions 

Factor 

Where:

Vent Flow = Total AGR vent flow to the thermal oxidizers (million 

SCF/period) 

to be monitored continuously by the Permittee.

Carbonyl Sulfide Emissions Factor = Pounds of Carbonyl Sulfide emitted 

per million standard cubic feet of vent gas to the thermal oxidizer (lbs. 

COS/MMSCF of vent gas) as determined in the most recent compliance 

stack test of the oxidizer. Until the initial compliance stack testing is 

performed, the engineering estimate of 0.0062 lbs. carbonyl sulfide 

emitted/million SCF vent gas shall be used.

(e) Total HAP emissions from the AGRs shall be calculated by the following 

equations:
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When there is no AGR vent flow and RTO is in Standby Mode: 

Total HAPs Emissions = RTO Fuel Flow in MMBtu/hr. x HAP Emission 

Factor of 0.00185 lb HAP/MMBtu

When there is AGR vent flow to the RTO:

Total HAP emissions = Methanol Emissions + Carbonyl Sulfide Emissions + 

Other HAPs Emissions

Where:

Methanol Emissions = Methanol Emissions as quantified in D.4.11(c)

Carbonyl Sulfide Emissions = Carbonyl Sulfide Emissions as quantified in 

D.4.11(d) 

Other HAPs Emissions are calculated by the following formula:

Other HAPs Emissions (with AGR vent flow) = Vent Flow x (Hexane 

Emissions Factor + Formaldehyde Emissions Factor + Additional HAPs 

emissions factor)

Where:

Vent Flow = Total AGR vent flow to the thermal oxidizers (million 

SCF/period) to be monitored continuously by the Permittee.

Hexane Emissions factor = Pounds of Hexane emitted per million standard 

cubic feet of vent gas to the thermal oxidizer (lbs. hexane/MMSCF of vent 

gas) as determined in the most recent compliance stack test of the oxidizer. 

If no compliance stack test has been performed, the emission factor of 

0.0054 lbs. hexane emitted/million SCF vent gas shall be used.

Formaldehyde Emissions factor = Pounds of Formaldehyde emitted per 

million standard cubic feet of vent gas to the thermal oxidizer (lbs. 

formaldehyde/MMSCF of vent gas) as determined in the most recent 

compliance stack test of the oxidizer. If no compliance stack test has been 

performed, the emission factor of 0.00023 lbs. formaldehyde 

emitted/million SCF vent gas shall be used. 

Additional HAPS Emissions factor = Pounds of any other HAP besides 

methanol, carbonyl sulfide, hexane, or formaldehyde emitted per million 

standard cubic feet of vent gas to the thermal oxidizer (lbs. HAP/MMSCF of 

vent gas) as determined in the most recent compliance stack test of the 

oxidizer. If no compliance stack test has been performed, the emission 

factor of 0.00004 lbs. additional HAPs emitted/million SCF vent gas shall be 

used.

Compliance with the above limits 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 any individual HAP and twenty-five (25) tons per year of any 

combination of HAPs and make the source an area source of HAPs.
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........................................................................................................................................................

D.4.19 Testing Requirements [326 IAC 2-1.1-11]

...........................................................................................................................................................

(d) In order to demonstrate compliance with Condition D.4.11 – Hazardous Air Pollutants

Minor Limit, not later than 180 days after initial startup of the second gasifier, but not later 

than 365 days after the initial startup of the first gasifier, the Permittee shall conduct 

methanol, carbonyl sulfide and other HAPs (as determined by IDEM, using the 

results of the screening test required by Condition D.4.19(e)) emissions stack testing 

of the emissions from the first of the Acid Gas Removal (AGR) units EU-007A or EU007B that has been started up. Not later than 180 days after initial startup of the fourth 

gasifier, the Permittee shall conduct methanol carbonyl sulfide and other HAPs

emissions stack testing of the emissions from the other of the Acid Gas Removal (AGR) 

units EU-007A or EU-007B. These tests shall utilize methods as approved by the 

Commissioner. These tests shall be repeated at least once every five years from the date 

of the most recent valid compliance demonstration. Testing shall be conducted in 

accordance with the provisions of 326 IAC 3-6 (Source Sampling Procedures). Section C 

- Performance Testing contains the Permittee's obligation with regard to the performance 

testing required by this condition.

(e) Not later than 60 days prior to the emissions stack testing required by Condition 

D.4.19(d), the Permittee shall conduct a screening test for other HAPs present in 

first of the Acid Gas Removal (AGR) units EU-007A or EU-007B that has started up. 

These tests shall utilize methods as approved by the Commissioner. This 

requirement shall also apply to the repeat testing required by Condition D.4.19(d). 

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.

Comment 10: Section D.5 lists permit conditions for two WSA plant trains (EU-015A-B). In permit 

condition D.5.8, NOx is limited to 10.2 lb/hr based on a 24-hour block daily average when 

the flow to the selective catalytic reduction (SCR) is operating above its optimal 

temperature of 750 degrees F. However, there is no limit established for when the flow to 

the SCR is below 750 degrees F. Since BACT must apply at all times, the permit should 

include a limit for these units when the flow to the SCR is below 750 degrees F.

Response 10: The BACT limit of 10.2 lbs/hr, block 24-hr average NOx from the WSA is intended to apply 

at all times. The facility is capable of maintaining the minimum SCR operating temperature 

of 750 F at all times acid gases are being fed to the unit. The only period when 

temperatures will be below this temperature is during initial WSA startup/warmup phase, 

before the introduction of acid gas feed. During the unit's warmup phase, the unit will use 

natural gas-fired preheat burners to get the unit up to this operating temperature. 

Uncontrolled emissions of the preheat burners, without any SCR effectiveness, are

estimated to be only 2.45 lbs/hr (see draft permit TSD pdf document, page 444 of the 880 

pdf). Therefore, even during this brief period of operation below 750F, the facility will 

comply with the proposed 10.2 lb/hr BACT limit. Consequently, there is no need for the 

qualifier in the BACT permit limit related to operating temperature. Instead, the NOx BACT 

permit limit for the WSAs will be amended to apply at all times, dropping the exception for 

temperatures below 750 F, with SCR required when acid gases are being fed to the unit.

This will require the following changes to the permit:
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D.5.8 NOx PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Wet 

Sulfuric Acid (WSA) plant, identified as EU-015A and B shall be as follows:

The NOx emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall be limited by the use of a 

selective catalytic reduction (SCR) when the flow to the SCR is at or above a temperature of 750 

degrees F and the. The NOx emissions shall not exceed 10.2 pounds per hour NOx based on a 

24-hour block daily average for each Wet Sulfuric Acid unit. and, when acid gases are being fed 

to the unit, the NOx emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall be 

controlled by the use of selective catalytic reduction (SCR).

D.5.12 Nitrogen Oxide Control

In order to ensure compliance with Condition D.5.8, the selective catalytic reduction (SCR) shall 

be in operation and control emissions from each Wet Sulfuric Acid (WSA) unit at all times that the 

WSA is in operation and the flow to the SCR is at or above 750 degrees F acid gases are being 

fed to the unit.

D.5.19 WSA Temperature Monitoring

In order to demonstrate the compliance status with Conditions D.5.8, the Permittee shall 

continuously monitor the temperature of the flow to the SCR whenever the WSA is operating and 

the SCR is not operating. 

D.5.201Record Keeping Requirements

...........................................................................................................................................................

(e) To demonstrate compliance with Condition D.5.19, the Permittee shall record the output 

of the continuous temperature monitoring system on the flow to the SCR.

(fe) Section C - General Record Keeping Requirements, contains the Permittee's obligation 

with regard to the records required by this condition.

Comment 11: Section D.7 includes PM, PM10, PM2.5, CO, SO2, and NOx BACT emission limits for the 

five gasifier preheat burners (EU-008A-E). However, the limits themselves are based on 

the emissions for only one gasifier preheat burner operating under normal conditions of 

18 MMBTU/hr, not all five gasifiers operating at the site. It is unclear whether this 

condition is meant to apply individually to each gasifier or collectively to all five gasifiers 

operating at once. We note that the calculations attached to the draft permit (pages 417-

426 and 508-517 of the electronic file) contain emission factors and equations necessary 

for obtaining the BACT limits. The limits listed are for an individual gasifier preheat burner 

as opposed to all five preheat burners. Please clarify in the permit the BACT limit(s) that 

applies to the five gasifier preheat burners. 

Response 11: IDEM has revised these conditions to clarify that the limits apply to each of the Gasifier 

Preheat Burners in the permit accordingly. 

D.7.4 PM, PM10 and PM2.5 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Gasifier 

Preheat Burners, identified as EU-008A - E shall be as follows:

The PM, PM10 and PM2.5 emissions from the Gasifier Preheat Burners (EU-008A-E) operation 

shall not exceed 0.0007 lb /MMBtu, each and only natural gas or SNG shall be used. 
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D.7.5 CO PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Gasifier 

Preheat Burners, identified as EU-008A - E shall be as follows:

The CO emissions from the Gasifier Preheat Burners (EU-008A-E) operation shall not exceed

0.056 lb CO/MMBtu, each and shall use good combustion practices. 

D.7.6 SO2 PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Gasifier 

Preheat Burners, identified as EU-008A - E shall be as follows:

The SO2 emissions from the Gasifier Preheat Burners (EU-008A-E) operation shall be not exceed

0.0006 lb SO2/MMBtu, each and natural gas or SNG shall be used.

D.7.7 NOx PSD BACT [326 IAC 2-2-3]

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Gasifier 

Preheat Burners, identified as EU-008A - E shall be as follows:

The NOx emissions from the Gasifier Preheat Burners (EU-008A-E) operation shall not exceed 

0.10 lb NOx /MMBtu, each and good combustion practices shall be used.

Comment 12: Section D.18 lists permit conditions for the zero liquid discharge (ZLD) inert gas vent (EU033). Permit condition D.18.4 says that operation of the carbon adsorber (for mercury 

emissions) will allow the source to limit source-wide HAP emissions to less than 10 tpy of 

a single HAP and to less than 25 tpy of all HAPs. However, the condition does not 

provide a specific HAP limit for this unit. If use of this control device is necessary to limit 

source-wide HAPs to less than 10/25 tpy, then the permit should include an emission limit 

for this unit in order to demonstrate that the source is not a major source for HAPs. 

According to the calculations attached to the draft permit, a limit on mercury emissions 

from this unit is not necessary to limit source-wide HAP emissions below the 10/25 tpy 

threshold. If these calculations are correct, the permit should clarify that this control 

option is not required to keep HAP emissions below 10/25 tpy. 

Response 12: Besides the requirement to apply GHG BACT, there are no other states or federal 

regulations specifically applicable to this small process vent. However, IG intends to route 

this vent through a carbon adsorber control device to assure minimal mercury emissions 

and, as such, the carbon adsorber device will serve to reduce a hazardous air pollutant 

(HAP) to the extent such HAP does exist in the stream. Because a limit on mercury 

emissions from this unit is not necessary to limit source-wide HAP emissions below the 

10/25 tpy threshold, this condition will be revised as follows:

D.18.4 Hazardous Air Pollutants (HAPs) Control

............................................................................................................................................................

Compliance with this condition 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 any individual HAP and twenty-five (25) tons per year of any combination of HAPs and 

make the source an area source of HAPs.

Comment 13: We have identified the following typographical errors in the permit:

In permit condition D.5.22, 326 IAC 3-5-7(5) should be 326 IAC 3-5-7(c)(4).

Response 13: IDEM has corrected the typo in Condition D.5.22 in the permit accordingly.
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D.5.221Reporting Requirements

(a) Pursuant to 326 IAC 3-5-7(5) 326 IAC 3-5-7(c)(4), reporting of continuous monitoring 

system instrument downtime, except for zero (0) and span checks, which shall be 

reported separately, shall include the following:

............................................................................................................................................

Comment 14: We have identified the following typographical errors in the permit:

In permit condition D.6.17, 326 IAC 3-5-7(5) should be 326 IAC 3-5-7(c)(4). 

Response 14: IDEM has corrected the typo in Condition D.6.17 in the permit accordingly.

D.6.178Reporting Requirements

(a) Pursuant to 326 IAC 3-5-7(5) 326 IAC 3-5-7(c)(4), reporting of continuous monitoring 

system instrument downtime, except for zero (0) and span checks, which shall be 

reported separately, shall include the following:

............................................................................................................................................................

Comments Received from the Public 

IDEM also received comments from a substantial number of citizens which are all addressed in 

this document. Not all of these commenters are identified specifically by name in this document, but all 

comments received during the public comment period are available for review as part of the public file.

The summary of the comments and IDEM, OAQ responses, including changes to permit No

T147-30464-00060 (language deleted is shown in strikeout and language added is shown in bold) are as 

follows:

Section C Comments: 

Comment 1: Section C.4 - Incineration allows incineration of refuse; it does so by restricting such to 

that allowed by cited statutes, which allow incineration of a limited amount of waste. No 

incineration should be permitted as it is unnecessary and unlikely to be closely monitored 

as to content. Why is incineration permitted at all at this facility?

Response 1: This permit condition is included in all Indiana Title V permits. It does not allow the source 

to incinerate refuse or any refuse burning. Any such incineration or burning of refuse would 

violate Indiana’s air rules unless the source first obtains the proper air permitting approval. 

This permit condition emphasizes these legal requirements. There is no such approval in 

this permit. The permit condition states:

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

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

permit. The Permittee shall not operate a refuse incinerator or refuse burning equipment 

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

Comment 2: Section C.11 specifies that monitoring of emissions may begin as long as 90 days after 

start of operations. It could and should begin when operations begin; why isn’t this 

required?

Response 2: Sources that are constructing new emission units are allowed 90 days after those units 

begin operation to get monitoring equipment and processes running correctly. New 

monitoring equipment for new units require analysis and evaluation to confirm that they are 

running correctly and that the data they collect is being recorded properly. This provision 

gives the source 90 days to complete these evaluations before they are in violation of the 
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monitoring requirements. The source must still comply with all of its emission limits and 

standards once it begins operation. IDEM does not have to have emission monitoring data 

to cite a source for an emission violation or require the source to test its equipment if IDEM 

feels it is not operating properly. 

Comment 3: Section C.13 (a) grants up to 180 days from the commencement of operations for the 

operator to file its Emergency Reduction Plan. This plan should exist the day operations 

begin, unless the operator can prove no emergency will arise for the first 180 days of 

operation: an impossibility due to the definition of emergency. What specific actions will 

be required to be taken, and which taken in the event of an emergency prior to the 

emergency Reduction Plan existing? What is the worst case scenario of such an 

emergency and what would be the potential injuries from it? Who will monitor emissions 

during such an emergency and who compensate the public and individuals for damages 

caused by the emergency?

Response 3: The Emergency Reduction Plan requirement for this source is based on the Indiana rule 

found at 326 Indiana Administrative Code (IAC) 1-5-2. All of the Indiana Administrative 

Code can be found at http://www.in.gov/legislative/iac/ on the Internet. The rule provides 

that the source has one-hundred eighty days from the date it commences operation to 

submit its emergency reduction plan. IDEM cannot shorten this time period as it is set out 

in the rule. 

The Episode Alert Levels rule, 326 IAC 1-5 establishes air pollution episode levels based 

on concentrations of criteria pollutants in the ambient air. If these levels are reached, the 

Commissioner of IDEM will activate an Air Pollution Alert that will state the appropriate 

episode level. At that time the source must take the steps in its emergency reduction plan 

to reduce its emissions, pursuant to the episode level that has been declared. 

IDEM monitors the level of air pollutants in the ambient air at established locations 

throughout Indiana. The actual monitoring data collected is available at 

http://www.in.gov/idem/4652.htm on IDEM’s website. The air concentrations of each 

pollutant that would cause an air episode alert are set out in 326 Indiana Administrative 

Code 1-5-4. In the twenty-four years that this rule has been in place, ambient air levels 

have never been high enough to trigger an alert. If an alert were to occur, IDEM would 

continue to monitor the ambient air levels and would verify that all sources have reduced 

their emissions in compliance with their Emergency Reduction Plan. The rule does not set 

out any provision for compensation to the public or individuals for damages caused by the 

air pollution episode.

The emergency reduction plan does not govern what the source does if it has an 

emergency that affects its operation, such as a fire. If a source has an emergency it still 

must comply with all federal and state health-based emission standards. An emergency 

may constitute an affirmative defense to an action brought for noncompliance with a 

technology-based emission standard if the source meets all the requirements of 326 IAC 

2-7-16. These requirements are set out in the Emergency Provisions condition in section 

B of the permit, including that the source must take all reasonable steps to correct the 

emergency.

IDEM has an Emergency Response team that responds to environmental emergencies 

around the state. These team members will evaluate any threat to the public and assist in 

determining what steps are necessary to protect the public. Any environmental 

emergency should be reported to IDEM immediately at (888) 233-7745. This number is 

answered 24 hours-a-day, 7 days-a-week.
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Comment 4: Section C.16 allows an infinite number of days to retest after a failed stack test. The 

follow up stack test should immediately follow corrective action. What justifies not 

requiring immediate retesting?

Response 4: The permit condition, Actions Related to Noncompliance Demonstrated by a Stack Test,

does not give the source an infinite number of days to retest after a failed stack test. The 

condition requires that the source retest no later than 180 days after the date of the 

noncompliant test. Should the Permittee demonstrate to IDEM, OAQ that retesting in one 

hundred eighty (180) days is not practicable, IDEM, OAQ has the power to extend the 

retesting deadline further.

Immediate retesting is not usually possible. Emission tests procedures can take days to 

run and require extensive preparation of testing equipment. The testing must be done 

pursuant to a testing protocol that must be submitted to IDEM in advance for approval. 

IDEM staff have to schedule time to observe the testing process. The source’s plant 

operation staff and the testing personnel need time to evaluate why the operation failed 

the test and take corrective action before retesting can be carried out. 

Please note that this condition does not excuse the source from failing its stack test. As 

stated in subpart (C) IDEM may take any action allowed under law in response to the 

noncompliant test, which could include taking an enforcement action against the source. 

This permit condition states:

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

IAC 2-7-6]

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

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

permit, the Permittee shall submit a description of its response actions to IDEM, OAQ, no 

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

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

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

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

extend the retesting deadline

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

to noncompliant stack tests.

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

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

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

Comment 5: Section C.18 (d) (2) requires calculation of emissions. Emissions should be required to 

be measured because calculations are not based upon continuous nor even frequent, in 

most cases, monitoring of actual emissions. Actual emissions are measured, not 

calculated. What justifies not requiring reporting of actual measured emissions?

Response 5: This permit condition, the General Record Keeping Requirements condition in section C,

sets out the general record keeping requirements for the source. This condition is used to 

make sure that there are a set of record keeping requirements that cover all the 

applicable requirements that apply to the source. Please note that all of the specific 

record keeping requirements for the source’s emission units are set out in each of the D 

sections of the permit.

Part (d) of the General Record Keeping Requirements condition in section C applies to a 

particular circumstance under the air permitting rules. The requirements of provision (d) 

come directly from the applicable requirement at 326 IAC 2-2. The rule requirements are 

being incorporated into the permit. 
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Regarding the specific applicability and requirements of this rule, at some point in 

the future, after it begins operation, the source may make a change in the way 

that it operates an emission unit that does not require an air permit change under 

326 Indiana Administrative Code 2-2 or 2-3, because there is no increase in 

emissions that would trigger new air permitting review under those rules. 

However, the source must monitor the emissions from the unit as required in 

(d)(1) of this condition and, using this monitoring information, calculate its annual 

emissions in a tons per year units as required in (d)(2) of this condition. So, the 

actual emissions from the unit would be monitored, not calculated. The monitored 

emissions would then be converted to units of “tons per year” through a 

calculation and recorded.

Greenhouse Gases (GHGs) Comments:

Comment 6: Page 12 of 43 of the UPTE charts, Note 2, shows a serious amount and increase of CO2

emissions in the first two years of operation. This indicates that unnecessary emissions 

will occur, that or the CO2 capture process is not perfected. What is the cause of these 

variations in CO2 emissions over time? How will the capture of CO2 be accomplished? 

Where will the CO2 be stored or how will it be removed from the site?

Response 6: With respect to the commenter’s use of the phrases “CO2 capture process,” “capture of 

CO2” or “CO2 be stored or removed from the site” to describe the manufacture of CO2 as 

a product for sale, it should be clarified that the CO2 is produced in the gasification and 

purification process and is not “captured” from an emission unit. (See Response to Public 

Comment 9). Furthermore it is not stored at the Indiana Gasification site. The cause of 

the variations in CO2 emissions from the AGR vent in the first two years of operation are 

described on page 155 of 181 of the TSD BACT Analysis, and the variations are reflected 

in the enforceable permit conditions in Draft Permit Condition D.4.9.

Comment 7: The plan calls for a pipeline to Louisiana for transporting liquid CO2 captured by the plant,

so that CO2 can be used to enhance oil recovery from old wells. There is no assurance 

that this pipeline will ever be built. The plant proposes to operate the first two years 

without CCS. I predict that at the end of two years the plant owners will say, no pipeline, I 

guess we will have to continue dumping millions of tons of CO2 into the atmosphere. 

Otherwise, we would have to shut-down the plant and layoff 200 plant workers." 

Enhanced oil recovery is an established means of sequestering CO2. CCS is the object 

of intense current research, and it is by no means clear that a safe and economic solution 

will be found. Even with 80 percent CCS, the plant will unnecessarily increase CO2

emissions above those entailed with burning natural gas. In addition the plant will 

subsidize destructive coal mining, which itself releases significant amounts of climate 

altering methane, even before it gets to the plant.

Response 7: Draft Permit Condition D.4.9 expressly prohibits what this commenter speculates will occur 

by providing enforceable limits on CO2 emissions from the AGR vents. With respect to the 

comments on the emissions associated with the use of natural gas and “subsidization” of 

coal mining, they are beyond the scope of the permitting action being taken here 

consistent with the Clean Air Act PSD permitting process and the state air permitting rules.

Comment 8: This project has shown a lot of progress in reducing CO2 emissions but despite the 

progress shown by the CO2 emission limit in the Draft Permit, it simply does not include 

sufficient limits on future CO2 emissions from the Project, given the record available 

below. 

The Indiana Air Pollution Control Board has adopted this rule into its PSD program. See 
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326 I A C 2-2-1(zz)(1) (including facilities that emit 75,000 CO2e, or 100,000 CO2e if the 

project is built after July 1, 2011, in the definition of “subject to regulation”). The Project 

will exceed this applicability threshold, and thus IG was required to perform a greenhouse 

gas BACT analysis. The inclusion of a CO2 emission limit is therefore required for this 

facility. See Draft Permit Condition D.4.9 (establishing CO2 emission limit of 1.29 million 

tpy during and after the third 12 months of operation).

The Project’s CO2 emission limit is based – at least in part – on IG’s intent to use the 

AGR unit to capture and sell more than 90% of the CO2 produced at the facility. See

Application, Appx. F at 2-7. However, IG believes that operational constraints, including 

potential downtime of the CO2 pipeline and downstream offtakers, as well as 

maintenance and other issues within the facility itself, may result in the amount of CO2

actually placed into the pipeline to be only about 80% of the potential CO2 emissions from 

the AGR. Thus, the CO2 emission limit represents the balance of the potential AGR 

emissions that can be vented, 1.29 million tpy during the third 12-month period of 

operation and each year thereafter.

The 1.29 million tpy limit is the third of a three-phase CO2 BACT emission limitation. We 

support the use of such a limitation, and note that similar limitations have been upheld by 

the Environmental Appeals Board (“EAB”) when a “permitting authority [is] faced with 

some uncertainty as to what emission limit [is] achievable.” In re AES Puerto Rico L.P., 8 

E.A.D. 324, 349 (E.A.B. 1999). For example, EAB upheld a BACT emission limits for 

nitrogen oxides by using both a design limit and a worst-case limit. In re Hadson Power 

14 – Buena Vista, 4 E.A.D. 258, 288-90 (E.A.B. 1992). This was the first application of 

that particular control technology to that particular unit in this country. Id. The permit in 

Hadson Power allowed the state agency to revise the emission limit downward toward the 

design limit after operation commenced to reflect an emission rate that the facility 

demonstrated was consistently achievable. Id. at 291. Similarly, EAB upheld an 

adjustable BACT emission limit for particulate matter with a diameter of ten microns or 

less (“PM10”) that allowed the permitting authority to adjust the initial limit upward if the 

facility was unable to meet it due to certain conditions. AES Puerto Rico L.P., 8 E.A.D. at 

347. Both of these cases show that a BACT emission limit can change over time, and 

thus provide support for IDEM’s CO2 emission limit, (Draft Permit, condition D.4.9), 

although as explained below, the record in this case shows that more can be done here to 

limit potential future CO2 emissions. 

As an initial matter, CATF agrees with IG’s conservative explanation that the “combination 

of technologies and the operational constraints required for the technologies...are new 

and complex” and that the “experience on lifetime operations for a plant of this scale is 

limited.” Application, Appx. F at 2-8. Based on these circumstances, an allowance for 
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some CO2 venting at the AGR is warranted. Just as surely, however, IG will learn over 

time how to best optimize the operation of the Project to capture and sell CO2 from it. For 

example, the coordination of maintenance outages across the facility and with 

downstream CO2 customers is likely to improve with experience. So, too, should 

knowledge of the operation of such other key equipment as CO2 compressors. 

We recognize that IG views CO2 as a sales product of the Project, and thus has 

incentives to minimize the vented volume of CO2 in order to maximize the CO2 sales 

volume. The record therefore supports an additional CO2 emission limit to be effective 

beginning in the eighth operational year at a level equal to the actual CO2 emissions in 

operational years four, five and six, plus a small margin (for example, ten percent of that 

average) for uncertainty unless IG demonstrates to the satisfaction of IDEM that special 

and unique circumstances during this averaging period make it unlikely that a new limit 

would be achievable in practice in subsequent years. This adaptable limit would be 

imposed based on the actual operations of the facility, expressed in tons of CO2 emitted 

per unit SNG produced, see EPA, PSD and Title V Permitting Guidance for Greenhouse 

Gases, at p.46 (March 2011) (“EPA encourages permitting authorities to consider 

establishing an output-based BACT emissions limit, or a combination of output- and inputbased limits, wherever feasible and appropriate to ensure that BACT is complied with at 

all levels of operation”), and must not be higher than the 1.29 million tpy that begins in the 

third year of plant operation. Such an adjustable, declining CO2 emission limit is more 

protective of the environment than the limit in the Draft Permit, is consistent with the 

interests of IG and the State of Indiana, and is supported under relevant law and practice, 

and by the facts present here.

Response 8: It is standard practice under PSD to establish in the pre-construction permit a fixed BACT 

emission limitation, based on the best technical information available at the time of permit 

issuance. That BACT limitation applies to the operation of that emission unit until that unit 

later makes a change that triggers another PSD review. Occasionally, a permitting 

authority may devise a flexible approach to BACT emission limitations, but such an 

approach is not required and is the exception to the general rule. Based on the technical 

information available at this time (see for example Permit Application Appendix F on 

pages 3-2 and 3-3), IDEM has determined that the use of fixed BACT emission limitations 

for the AGR vents is appropriate. To the extent that additional technical information 

becomes available in the future, the PSD regulations provide opportunities for permit 

modifications at the request of the permittee or at the initiative of the permitting authority 

in appropriate situations. The best technical information available at those times would be 

used to inform any future BACT determination.

It should be noted that the CO2 manufactured in the AGR is a valuable product, and the 

permittee has significant incentives to minimize the emission of CO2 at the AGR vent. A 

permit condition that would change the limit based on operating history might be 

construed to encourage additional emissions from the AGR vent so as to preserve 

compliance headroom, would be inconsistent with the overall purpose of selling as much 

CO2 as product as feasible, and is therefore also inappropriate.
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Comment 9: The Act defines BACT as an emission limitation based on the maximum degree of 

reduction of each pollutant subject to regulation under this chapter emitted from or which 

results from any major emitting facility, which the permitting authority, on a case-by-case 

basis, taking into account energy, environmental, and economic impacts and other costs, 

determines is achievable for such facility through application of production processes and 

available methods, systems, and techniques, including fuel cleaning, clean fuels, or 

treatment or innovative fuel combustion techniques for control of each such pollutant.

42 U.S.C. § 7479(3) (emphasis added). Importantly for present purposes, the plain text 

“which results from” in this provision defines both (a) “each pollutant” that must be 

reduced and (b) the object of the maximum degree of reduction requirement. In other 

words, the BACT limit must reflect the maximum degree of reduction of a pollutant 

covering both direct emissions onsite and emissions of the same pollutant that “result 

from” the facility. BACT thus does not allow a facility to supposedly reduce pollution, only 

for that pollution to be emitted to the atmosphere later down the road. Such a loophole 

would severely weaken the Act’s stringent control requirements.

Ensuring that a permittee actually achieves the maximum degree of reduction is of 

particular concern with CO2. CO2 is widely distributed pollutant that produces impacts as 

a result of increasing global average concentrations of the gas in the atmosphere. Thus, 

imposing a constraint on the amount of CO2 that may be released at one point without 

requiring a demonstration that the captured CO2 is not simply being released at an off-site 

location would be ineffective as an method to reduce the harms to public health and 

welfare associated with the stream of emissions. It follows that, as taken up in more detail 

below, the BACT limit for CO2 must contain conditions sufficient to demonstrate that 

captured CO2 will be handled in a manner providing a high degree of assurance that the 

CO2 will not be released to the air, either during transport of the CO2 or from the 

location(s) to which it is transported.

Response 9: EPA’s long-standing interpretation of the “which results from” language cited by the 

commenter does not require BACT analyses for off-site sources. To the extent that the 

off-site emissions to which the commenter refers should be considered “secondary 

emissions” at all under EPA’s regulations and guidance, such emissions are also not 

subject to BACT. EPA’s March 2011 PSD and Title V Permitting Guidance for 

Greenhouse Gases has this to say about the consideration of secondary emissions in a 

BACT analysis: “EPA has historically interpreted the BACT requirement to be inapplicable 

to secondary emissions, which are defined to include emissions that may occur as a 

result of the construction or operation of a major stationary source but do not come from 

the source itself.” GHG Guidance at 24 (emphases added). The 1990 NSR Workshop 

Manual, further, states: “Secondary emissions are not considered in the potential 

emissions accounting procedure. . . . Secondary emissions occur from any facility that is 

not a part of the source being reviewed, but which would not be constructed or increase 

its emissions except as a result of the construction or operation of the major stationary 

source or major modification.” 1990 Manual at A.16. 

In this case, the “source being reviewed” is the collection of emission units within the 

fence-line of the Indiana Gasification facility. EPA’s guidance is plain that emissions from 

off-site sources—even if they would not have occurred but for the construction of the 

Indiana Gasification facility—are not included in the BACT analysis. See also 40 C.F.R. § 

52.21(b)(18) (definition of “secondary emissions”) (“Secondary emissions means 

emissions which would occur as a result of the construction or operation of a major 

stationary source or major modification, but do not come from the major stationary source 

or major modification itself.”). EPA’s Environmental Appeals Board has consistently 

focused the attention of permitting authorities on the stationary source itself: “As the 

Board has explained many times, BACT is a ‘site-specific determination and * * * the 
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combined results of the considerations that form the BACT analysis are the selection of 

an emission limitation and a control technology that are specific to a particular facility.’” In 

re: Mississippi Lime Co., PSD App. No. 11-01, 2011 WL 3557194 at Section VI.A (Envtl. 

App. Bd. Aug. 9, 2011) (emphasis added). In the context of an attempt to include vessel 

emissions as a part of the BACT analysis at an Outer Continental Shelf facility, the EAB 

observed—quoting the very statutory language cited by NRDC in its comment here—that 

the permit challengers “fail to acknowledge that the statutory BACT definition does not 

address emissions disconnected from the emissions’ source, but instead directs that the 

emissions limitation is established, on a ‘case-by-case basis,’ by determining what is 

‘achievable for the facility’ through ‘application’ of various control methods.” In re: Shell 

Gulf of Mexico, Inc., OCS Appeal No. 10-01 at Section VI.A (Envtl. App. Bd. Dec. 30, 

2010) (emphasis added). The BACT analysis does not include air pollution sources not at 

the facility under review.

The PSD program does, however, assess the impacts of secondary emissions on 

NAAQS and PSD increments in the ambient air quality impacts analysis. 1990 Manual at 

C.1. However, because there is no NAAQS or PSD increment for GHGs, EPA has 

directed that secondary emissions of CO2 need not be included in the ambient air quality 

impacts analysis. See GHG Guidance at 47–48. Secondary emissions of CO2 have no 

place in a review of the proposed facility.

Consequently, comments that relate to the control of CO2 downstream of the proposed 

facility (e.g., control of CO2 during transportation, storage, use, and re-use in EOR 

operations) are not relevant to this permitting action.

Comment 10: IDEM’s alleged GHG BACT determination is procedurally flawed.

As an initial matter, we note significant concern that the agency’s supposed GHG BACT 

determination for the AGR Vent consists of a verbatim cut-and-paste of the applicant’s 

(exceedingly thin) BACT analysis submitted in its application. Compare TSD Appendix B –

“BACT Analyses” at 150-153 (concluding that sequestration is not technically feasible 

under BACT Step 2) and Application Appendix F at 3-3 to 3-8. Indeed, it appears that the 

agency simply substituted “IDEM” for “IG,” absurdly leading it to conclude that the agency 

itself “cannot even begin the process of trying to engineer or build [pipeline 

infrastructure].” TSD Appendix B at 153 of 181. This blatant failure to conduct an 

independent assessment of the application and come to its own determination flies in the 

face of the agency’s BACT duties. See supra at 3-5. For this reason alone, IDEM cannot 

move forward on the proposed permit without first doing the required analysis, coming to 

its own conclusion, and going through another public comment period.

In addition, the agency errs in even this thin attempt to apply the top-down analysis. IDEM 

provides an exceedingly short list of “potential control technologies” at Step 1 that 

inexplicably fails to even list use of captured CO2 for EOR – relied upon later in selecting 

the proposed CO2 BACT limit on the AGR vents themselves. Nor does IDEM determine 

whether sequestration of the AGR Vent CO2 is an “available” technology under Step 1, 

but mis-categorizes this inquiry as a Step 2 question. See TSD Appendix B at 150; EPA 

GHG BACT Guidance at 33-34 (discussing availability of CCS as a Step 1 inquiry). It then 

punts on the availability question in general by claiming that sequestration is “technically 

infeasible” for this project under Step 2. To correct these errors, IDEM must include a 

complete list of the available control technologies and determine on the record whether it 

believes sequestration is available or not as a Step 1 matter. It must then make its own 

independent determination whether sequestration is, or is not, technically infeasible. 

Not only does IDEM omit use of captured CO2 for EOR as a control technology in Step 1, 

but it then discusses in Step 4 potential constraints on the project’s ability to control CO2

via EOR based on uncertainty around construction of the pipeline for EOR shipments of 
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CO2. Assuming for argument’s sake that these considerations are properly Step 4 factors,

and that they go to issues particular to the startup of the facility, IDEM once again failed 

entirely to evaluate whether these separate BACT limits represent the maximum degree 

of reduction in CO2 over the first two years of the facility’s operation. It instead simply 

adopted the applicant’s discussion and numbers without question. 

Response 10: Independent review. It is the permit applicant’s responsibility to prepare a complete and 

thorough application, including a detailed BACT analysis. The alternative—a situation in 

which state permitting agencies are required to prepare detailed supporting documents, 

including a BACT analysis—would result in complete paralysis of the state’s permitting 

program. The permitting record contains approximately eighty documents that 

demonstrate arm’s length communications between IDEM and the permit applicant, 

prompted in many cases by the agency’s challenges to aspects of the original permit 

application and detailed responses. The fact that after this significant transparent and 

iterative process the final documents offered by the permittee in support of the application 

were sufficiently thorough that the permitting authority’s decision was predicated on them 

does not show a lack of analysis or independence, but rather the opposite. The permitting 

authority pressed the permittee to ensure a robust permit application and supporting 

analysis; this is precisely what the permitting authority was required to do.

EOR omitted from top-down analysis. Enhanced oil recovery was not in Step 1 

because this is a case of a product sale not regulated under the Clean Air Act. In addition, 

EPA has not even identified EOR as "available" for purposes of BACT if a party was not 

selling a product but attempting to comply with an emissions standard. It is important to 

distinguish between high-purity CO2 produced by the AGR and delivered to the pipeline, 

and the high-purity CO2 produced by the AGR but routed to the AGR vent. As explained 

on page one of the TSD, CO2 produced by the AGR, compressed, and delivered to the 

pipeline is a product of the Indiana Gasification facility. That the delivered CO2 has value 

as a product is evident by the fact that revenues from CO2 sales are shared with 

ratepayers under the IFA contract, see Indiana Finance Authority contract Section 5.4(c), 

and the IURC considered the sale of CO2 as a product as an important commercial term 

for the project. IURC Nov. 22, 2011, Order at 94 (commenting on allocation of “profits on 

the sale of CO2”). As a product, that CO2 is not an “air pollutant” as that term is defined 

by the Clean Air Act, and therefore no BACT analysis is required for the product CO2. 

Conversely, CO2 produced by the AGR that is vented is an “air pollutant” as that term is 

defined by the Clean Air Act, and for which a BACT determination is required. The CO2

from the AGR vent—along with all other GHG emissions from the facility—are the GHGs 

for which a BACT determination was made.

By way of analogy, the AGR vented CO2 is similar to gasoline fumes that may be emitted 

from a gasoline storage tank at a refinery. Had the gasoline been delivered for sale, it 

would be a product. Only because the gasoline was emitted into the ambient air did it lose 

its identity as a product, and become air pollution to which the Clean Air Act would apply. 

By way of further analogy, once delivered as a product to the fence line of the proposed 

facility, subsequent potential emissions of the product CO2 are not the responsibility of the

permit applicant any more than a carbonated beverage manufacturer is responsible for 

the ultimate release of CO2 when the beverage container is opened. Or similarly, 

refineries producing gasoline as a product are not responsible for the air emissions from 

automobile refueling or the combustion of the gasoline in automobiles. The Clean Air Act 

places compliance obligations on the emitter of air pollution, not the manufacturer of 

products that may later through their use result in air pollution.

Sequestration excluded from list of available technologies. The commenter is 

mistaken in asserting that sequestration for AGR vent CO2 was excluded from the list of 

available technologies in Step 1 of the top-down approach. For CO2 emitted from the 

AGR vent, the BACT analysis explicitly included carbon sequestration in Step 1 of the top-
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down analysis. See TSD BACT Analysis at page 150. And while the TSD BACT Analysis 

does challenge in Step 2 EPA’s assertion that CCS is “available,” the TSD BACT Analysis 

very clearly states “this analysis will presume sequestration to meet the criteria as an 

‘available’ technology.” Id.

Sequestration properly excluded under Step 2. The commenter’s suggestion that 

IDEM failed to address the question of availability is erroneous. The TSD BACT Analysis 

very clearly listed sequestration of AGR vent CO2 as an “available” technology, and then 

in detail explained why the technology is nevertheless technically infeasible. See TSD 

BACT Analysis at 150–153.

Comment 11: IDEM erroneously eliminated sequestration as technically infeasible.

The analysis of sequestration that IDEM copied from the applicant is cursory at best, and 

erroneously concludes that this option is infeasible. In addition, IDEM relies on factors that 

are questionably legitimate Step 2 inquiries.

First, as to availability in Step 1, a number of successful sequestration projects are, and 

have been, operating successfully worldwide at full commercial scale. These projects 

have clearly demonstrated the availability of sequestration as a technology.

With respect to technical feasibility, IDEM concludes that “[t]he source has neither access 

to, nor can develop, a suitable sequestration site for the volume of CO2 that may be 

vented from the AGR vents” See TSD Appendix B at 151 of 181. IDEM further asserts 

that “[w]hile sequestration is being studied for use in the region where the plant will be 

located, there is presently no practical option” (Id.) and that the results of the nearby 

sequestration project by Archer Daniels Midland (ADM) in collaboration with the Midwest 

Geological Sequestration Consortium (“MGSC”) will not be known for some time. These 

conclusions are in error. 

The work that has been carried out by the MGSC and its partners for the purposes of the 

ADM sequestration project in Decatur is of particular relevance to the Indiana Gasification 

plant. This project is currently injecting carbon dioxide underground. Schlumberger 

Carbon Services (“Schlumberger”) produced a sequestration feasibility study for Tenaska 

evaluating in significant detail the possibility of sequestration of captured CO2 at the 

nearby Mt. Simon sandstone formation in Illinois, for a site that is approximately 200 miles 

away from the proposed Rockport site. That analysis considered all of the appropriate 

technical feasibility issues such as geologic suitability of the Mt. Simon sandstone, 

injection well plume modeling, seismic data, etc., and concluded that use of the site was 

entirely feasible for the Facility:

A geological study was completed to develop an assessment of the suitability of 

the site for storage of carbon dioxide. The work is the first phase in developing a 

geologic carbon dioxide (CO2) storage site in the Mt. Simon formation. The goal 

of the study was to evaluate:

1. Whether the site has capacity to store the expected volume of CO2 from 

the plant;

2. Containment of the storage reservoir;

3. Infrastructure requirements for storage (number and dimensions of 

injection wells, operational strategies)

The results of the study indicate that the Mt. Simon sandstone has sufficient 

porosity (open space between the sand grains in the rock) and permeability (the 

degree to which the pore spaces are interconnected, allowing fluid to move 

through the rocks) and therefore provides a storage reservoir target capable of 
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accommodating all of the CO2 produced by the plant over a planned operational 

life of 30 years. The Eau Claire formation, which overlies the Mt. Simon 

sandstone, will provide the vertical containment needed to prevent movement of 

CO2 out of the Mt. Simon formation and into shallower geologic formations, 

ground water, and the atmosphere. There are also several other low permeability 

layers that provide secondary containment. The Mt. Simon formation and the 

containment layers are laterally extensive and available information, including the 

results of a subsurface (seismic) survey, confirm that there are no faults or 

breaks in the lateral continuity.

The Schlumberger Cost Study further concludes:

The geologic setting is favorable. The target formation of the Mt. Simon is 

estimated to be very thick at 1100-1300 feet with a high estimated porosity and 

permeability in the area selected. The thickness combined with the porosity and 

permeability allows for a high capacity injection field to be developed using a 

minimal number of wells. The field is estimated to only require 3 to 4 wells with a 

well spacing of only 2 miles. The thickness also reduces the area required for the 

CO2 resulting in reduced right of way. Also, the target area is under and adjacent 

to the plant resulting in minimal pipeline cost.

None of this specific technical information was even referenced, much less considered, in 

IDEM’s rejection of CCS as technically infeasible. 

The overwhelmingly positive results from a nearby site should be considered evidence 

that sequestration may be technically feasible for Indiana Gasification as well. At the very 

least, they demonstrate the complete lack of diligence on Indiana Gasification’s and 

IDEM’s part in analyzing with any credibility whether sequestration is indeed feasible. The 

Schlumberger study highlights a number of the factors that have to be considered before 

opining on its technical feasibility. We see no evidence of such an examination in this 

case. Moreover, the worked carried out by MGSC and its partners could be directly 

applicable to Indiana Gasification if they decided to transport CO2 to Illinois: the geology 

near Decatur has been extensively studied and characterized, which amounts to taking 

away the most significant source of uncertainty regarding the feasibility of sequestration. 

IDEM’s assertion that the results from the ADM project will not be known for years is both 

misleading and false: even though monitoring will need to take place during the course of 

that project, no formal “verdict” is expected. There is considerable certainty already about 

the feasibility of the injection and the safety of the storage. At the very least, the wealth of 

current knowledge and data should lead IDEM to require further analysis of sequestration 

as a feasible option.

IDEM goes on to argue that logistical challenges related to the acquisition of rights of way 

for a CO2 pipeline render sequestration technically infeasible. See TSD Appendix B at 

153 of 181. This argument is wholly inadequate. Indiana Gasification would only need to 

follow the same steps as any other company (including Enhanced Oil Recovery 

companies) to build a pipeline. These steps are well defined and have been followed 

routinely for decades by all parties wishing to construct pipelines. Tardiness in beginning 

such a process cannot be used as an argument against the technical feasibility, especially 

when the construction of a pipeline by a third party is used as an option to transport CO2

away from the plant site.

Finally, the ongoing nature of sequestration research sponsored by the U.S. Department 

of Energy (DOE), as well as any uncertainty surrounding the fate of other government 

sponsored sequestration projects (such as FutureGen 2.0) cannot be used as an 

argument against the technical feasibility of sequestration (See TSD Appendix B at 152 of 

181): research efforts are indeed ongoing but are part of a long term program and not 
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necessarily indicative of the feasibility of sequestration, and project uncertainty could be 

due to an assortment of logistical or other reasons. Only a detailed, site-specific analysis 

can be used to examine the technical feasibility of sequestration.

Response 11: The commenter questions the determination that sequestration is technically infeasible as 

BACT for CO2 emissions from the AGR vent. Accordingly, this response will address that 

comment. The technical infeasibility of capturing CO2 from other emission sources at the 

proposed facility was addressed thoroughly in the TSD BACT Analysis at pages 148, 156, 

158, 167, 169, 171, 174, 176, and 177. These sources will not be addressed further.

The commenter points out several activities related to the research and development of 

sequestration. One of those is addressed on Page 151 of the BACT determination. The 

work underway by the MGSC was considered as a part of the AGR vent GHG BACT 

analysis for the Indiana Gasification project. The BACT determination indicates that 

MGSC was beginning a large-scale CO2 injection project (1 million tons) over a three year 

period, but concludes that this Department of Energy funded demonstration project has 

not proven that sequestration is a technically feasible option for Indiana Gasification 

today. 

The commenter’s inclusion of the Schlumberger materials, which have been reviewed, 

does not change this conclusion. The commenter’s claim that sequestration of CO2 from 

the AGR is feasible in light of these recent studies is incorrect for three reasons.

First, the studies referenced by the commenter include a preliminary feasibility analysis of 

sequestration at the proposed Taylorville Energy Center. The Schlumberger studies were 

conducted on behalf of a proposed IGCC plant in Illinois, which IDEM understands does 

not have a CO2 BACT limit as part of its State of Illinois issued air permit. The study 

describes its objectives as follows: 

A geological study was completed to develop an assessment of the suitability of the site 

for storage of carbon dioxide. The work is the first phase in developing a geologic carbon 

dioxide (CO2) storage site in the Mt. Simon formation. The goal of the study was to

evaluate:

1. Whether the site has capacity to store the expected volume of CO2 from the 

plant;

2. Containment of the storage reservoir;

3. Infrastructure requirements for storage (number and dimensions of injection 

wells, operational strategies).

(NRDC Exhibit 1, pg. 1). The Schlumberger studies concluded that the nearby Mt. Simon 

sandstone had sufficient porosity and permeability to provide a storage reservoir 

potentially capable of accommodating all of the CO2 produced by the Taylorville Energy 

Center over a planned operational life of 30 years. That study, however, is not evidence of 

the current technical feasibility of sequestration at the Taylorville site, but is simply an 

initial estimate of the potential suitability of the site for possible future sequestration 

development. While the study does characterize the geology of this location in Illinois and 

indicates that the geology appears suitable for geologic sequestration based on seismic 

data and modeling analysis, these results do not render geologic sequestration technically 

feasible for Indiana Gasification. Importantly, the study itself indicates that its work is the 

“first phase” in developing a storage site. The study does not include drilling of injection 

wells or actual injection of CO2. Moreover, the cost study indicates the following 

uncertainty:

It should also be noted the estimate was completed without a test well. 

When the first injection well is drilled, actual conditions are likely to vary 
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from those assumptions and could therefore result in the need for 

alternate designs, additional infrastructure, and revised operating 

assumptions.

(NRDC Exhibit 2, pg. 1).

The Schlumberger feasibility study does not indicate that geologic sequestration is 

technically feasible; it only indicates the geologic conditions appear to be favorable. 

Second, the first phase activity at the Taylorville facility can most fairly be described as a 

pilot test. As of February 2012, the MGSC Decatur demonstration project had injected 

about 70,000 tons of CO2, and plans to continue to inject CO2 for up to three years. The 

amount injected to date represents an amount equal to about six percent of the potential 

annual volumes from the Indiana Gasification AGR vent. During the MGSC demonstration 

project, measurement, monitoring and verification activities will be ongoing to evaluate 

how the injection proceeds, where the underground CO2 plume forms, and whether 

permanent storage has been accomplished. The results of these evaluations are not 

known today. Importantly, Chuck McConnell, Chief Operating Officer for the U.S. 

Department of Energy (DOE) Office of Fossil Energy (FE) is quoted as saying: 

“This injection test project by MGSC, as well as those undertaken by 

other FE regional partnerships, are helping confirm the great potential 

and viability of permanent geologic storage as an important option in 

climate change mitigation strategies.”

(http://sequestration.org/resources/topStories.html accessed February 9, 2012) 

(emphasis added).

It is hoped that these demonstration test projects are developing important scientific data 

and understanding, but that understanding does not exist at a level that makes geologic 

sequestration technically feasible today. This position is further confirmed by a statement 

on the MGSC website regarding its mission: 

While the industrial processes required to make carbon sequestration 

possible have been known for quite some time, they have never been 

applied at the scale required to significantly reduce the atmospheric buildup of CO2. Our challenge is to show the value of these technologies 

within our region, using geological resources to demonstrate that carbon 

dioxide can be stored safely and economically, deep underground. 

(http://sequestration.org/challenge/index.html, accessed February 9, 2012) (emphasis 

added)

MGSC and the other DOE-funded regional partnerships are in the process of 

demonstrating geologic sequestration technologies. They have not completed their work. 

The work to date does not verify that geologic sequestration is technically feasible today 

at the scale that Indiana Gasification would need to sequester.

EPA’s October 1990 Draft PSD Workshop Manual says that in the context of a technical 

feasibility review, “technologies in the pilot scale testing stages of development would not 

be considered available for BACT review.” Workshop Manual at B.17. In the case of 

Taylorville, the facility is not even testing a technology, but is examining whether a facility 

is even appropriate for the installation of a technology. But even if the Taylorville facility is 

considered to be testing a “technology,” because the Taylorville facility is in the “test” or 

“demonstration” mode, it cannot be considered an “available” technology for purposes of 
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a BACT review. 

Third, Illinois EPA has decided that sequestration was not technically feasible for the 

Taylorville facility (though a final permit has not yet been issued). EPA’s recent PSD and 

Title V Permitting Guidance for Greenhouse Gases notes that it is important for permitting 

authorities to pay “particular attention to the most recent information from the commercial 

sector and other recently-issued permits.” Office of Air Quality Planning and Standards, 

U.S. EPA, PSD and Title V Permitting Guidance for Greenhouse Gases, at 35 (March 

2011) (“EPA GHG Guidance”). The PSD permit application for the Taylorville Energy 

Center was submitted in April 2010. The draft permit was noticed for public comment on 

October 17, 2011. In the summary accompanying the draft permit, IEPA explained 

“[a]lthough the results of [the Schlumberger studies] were favorable, many other technical 

issues associated with geologic CO2 sequestration still need to be resolved. In addition, 

there are unresolved issues involving the regulatory requirements for sequestration and 

liability associated with sequestration. Further development of sequestration is needed 

before a BACT emission limit could be set for the proposed plant that is predicated upon 

implementation of CCS.”

The public comment period on the draft Taylorville Energy Center PSD permit closed on 

December 30, 2011. In their comments on the draft permit, some parties have asserted 

that IEPA’s finding that CCS is technically infeasible at the Taylorville Energy Center is in 

conflict with the Schlumberger studies. As detailed above, the Schlumberger studies do 

not establish technical feasibility of CCS at the Taylorville facility. In addition, some 

commenters have asserted that IEPA’s finding is in conflict with Christian County 

Generation’s application for a Class VI geologic sequestration permit from EPA under the 

Safe Drinking Water Act’s Underground Injection Control program, submitted in 

September 2011. Christian County Generation’s application for a Class VI UIC permit 

merely reflects its intention to sequester CO2 in the future, however, and does not conflict 

with IEPA’s finding that geologic sequestration is currently technically infeasible. 

EPA, in its comments, requested that the project summary be updated to reflect the fact 

that Christian County Generation applied for a Class VI geologic sequestration permit. 

EPA did not conclude, however, that sequestration was feasible for the project but, 

instead, requested that IEPA revisit this determination in light of Christian County 

Generation’s Class VI permit application. 

In sum, because the Schlumberger studies do not point to the present availability of the 

Taylorville site to accept millions of tons of CO2 from the Indiana Gasification facility, 

because the Taylorville site is still in a pilot or demonstration phase, and because IEPA 

has concluded that sequestration is not technically feasible at the Taylorville site, the 

assessment of sequestration as presented in the BACT determination remains valid.

Comment 12: The proposed limit fails to ensure the maximum degree of reduction achievable. 

IDEM failed by omitting any requirement that the facility demonstrate that the captured 

CO2 emissions will not re-enter the atmosphere. Without such a demonstration, the 

emission limitation does not reflect the maximum degree of reduction in greenhouse 

gases resulting from the facility and the permit does not ensure compliance with the 

BACT limit. See supra,2-6. Due to its composition as a compressed gas, the potential for 

release of captured CO2 is extremely high unless specific steps are taken to ensure that it 

will not escape from pipelines or other means of transport and will not escape from the 

site(s) to which it is delivered. Accordingly, a permit provision that simply measures 

releases from on-site CO2 vents and ignores the fate of the captured CO2 that is diverted 

to a location past the fenceline clearly would not meet the statutory definition of "emission 

limitation" because it would not be effective in limiting the amount of captured CO2 that 

was emitted to the air or resulted from the facility. Such a permit structure would allow the 

captured CO2 to be released at any time and any point. For example, captured CO2
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could be piped to facility that used the CO2 to make carbonated beverages, resulting in 

only a slight delay in the release of this pollutant. Similarly, a permit authorizing a system 

that sends captured CO2 to an enhanced oil recovery operation cannot be recognized as 

establishing an emission limitation for CO2 unless the enhanced oil recovery facility is 

required to operate pursuant to an approved regime that demonstrates permanent 

retention of the injected CO2. Thus, the permit for any source that captures CO2 must 

require a demonstration that the captured CO2 is delivered to a facility that is subject to 

design and operational requirements adequate to assure the permanent isolation of the 

delivered CO2 from the atmosphere.

Current federal and state regulations for pipelines and enhanced oil recovery sites do not 

provide any assurance that CO2 from the source will not be vented to the atmosphere or 

that any leaks will be remedied or quantified. Underground injection of carbon dioxide 

(CO2) is regulated under EPA’s Underground Injection Control Program (UIC). The UIC 

rules have been promulgated under the authority of the Safe Drinking Water Act (with the 

exception of Class I hazardous wells which implement RCRA requirements) in order to 

protect Underground Sources of Drinking Water (USDWs).

Under UIC, injection is permitted through wells or area permits. There are six injection 

well classes, two of which are most relevant to commercial scale CO2 injection: Class VI 

and Class II. Class II dates back several decades and is used for injecting brines, CO2

and other fluids associated with oil and gas production, and hydrocarbons for storage. 

This would almost certainly be the class under which Indiana Gasification’s CO2 offtakers 

would operate. Class VI is a new injection well class, which applies to wells that inject 

CO2 for geologic sequestration. Class VI rules were proposed by EPA in July, 2008 and 

were promulgated in December, 2010, specifically the purpose of CO2 sequestration. 

Regulatory requirements for Class VI are more comprehensive than for Class II on many 

counts:

• The information than needs to be submitted at the time of a permit application is 

more extensive under Class VI. 

• Class VI siting requirements include an injection zone with sufficient properties to 

receive the total anticipated volume of CO2 injectate, a confining zone big enough 

to contain injected and displaced fluids, and with sufficient integrity to allow 

injection without initiating or propagating fractures. Class II only requires a 

confining zone that is free of transmissive faults and fractures.

• Monitoring requirements for Class II are limited to analyzing injected fluids with 

sufficient frequency to yield data representative of its chemical and physical 

characteristics, as well as injection rate, pressure and volume measurements. 

Class VI requirements include an extensive testing and monitoring plan that 

covers operational parameters for the well, direct and indirect methods to track 

the extent of the CO2 plume and the area of elevated pressure, water quality 

measurements, as well as surface monitoring if required by the Director.

• Class requirements for a well plugging plan are tailored to individual situations 

rather than requiring off-the-shelf methods to be used.

• Class II lacks any post-injection site care and site closure requirements. Class VI 

requires post-injection monitoring for fifty years, or an alternative period if it can 

be shown that it is sufficient, in order to establish the evolution of the injected 

CO2 and displaced fluids, and that no USDWs are being endangered. Once no 

endangerment established, then the Director may authorize site closure, at which 

point financial responsibility obligations cease.

• The area of review and corrective action requirements for Class VI are broader. 

The actual area of review does not rely on default distances, needs to be updated 

at least every five years, requires modeling of certain specifications to determine 

the extent of the CO2 plume and displaced fluids, and more extensive 
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identification of penetrations within the area of review. A revision of the area of 

review also may require revision of other required plans. 

• Financial responsibility obligations under Class VI go further than Class II.

• Class VI emergency and remedial response provisions require actions by the 

owner or operator to address movement of the injection or formation fluids that 

may cause an endangerment to a USDW during construction, operation, and 

post-injection site care periods. Class II has no such requirements.

• Construction requirements, as well as requirements for logging, sampling and 

testing, go further in Class VI than they do in Class II.

• The standard for granting primacy to states for the implementation of the program 

is weaker for Class II wells, and consists of a general effectiveness 

demonstration as opposed to meeting individual stringency and adequacy criteria.

Although Class VI requirements have been promulgated with the express purpose of 

protecting USDWs and not necessarily ensuring the safe and effective sequestration of 

CO2 and preventing any releases to the atmosphere, they go a long way towards doing 

so. This is because of the site characterization and screening requirements, the need to 

establish and maintain a confinement zone, and act when confinement is breached. 

However, select cases such as well blowouts or vents directly to the atmosphere, or areas 

without USDWs may not be covered.

EPA’s regulations do not require all CO2 injection sites to be permitted as Class VI wells. 

Only owners or operators that are injecting carbon dioxide for the primary purpose of 

long-term storage into an oil and gas reservoir must apply for and obtain a Class VI 

geologic sequestration permit when there is an increased risk to USDWs compared to 

Class II operations. The Director must consider a number of relevant factors when 

making such a determination. However, there is no definition or “primary purpose”, and 

guidance is pending regarding the transition from Class II to Class VI. This loophole 

allows EOR projects that wish to demonstrate sequestration to remain in Class II rather 

than transition to Class VI.

In terms or reporting any leaks, the Clean Air Act (CAA) provides EPA with the authority to 

require data reporting that will inform and are relevant to EPA’s implementation of a wide 

variety of CAA provisions. Subpart RR of the reporting rule applies to wells that inject a 

CO2 stream for long-term containment in subsurface geologic formations. Subpart UU 

applies to wells that inject a CO2 stream into the subsurface (without the objective of longterm containment. 

Under subpart RR (which, alongside subpart UU was promulgated in December, 2011), 

there is no reporting threshold, and basic mass flows of CO2 received, produced, leaked 

and sequestered must be reported. In addition, a Monitoring, Reporting and Verification 

(MRV) plan is required to be submitted by the owner/operator that includes:

a. Identification of CO2 leakage pathways in MMA, incl. likelihood, magnitude and 

timing, and 

b. Delineation of the monitoring area

c. A strategy for detecting and quantifying any surface leakage of CO2

d. A strategy for establishing expected baselines for monitoring CO2 surface 

leakage

There are no specific requirements for these actions and strategies analogous to the 

Class VI requirements. MRV plans are reviewed on an individual basis. Subpart UU 

requires reporting only of the mass of CO2 received, and does not require any MRV.

All Class VI wells must report under subpart RR, but Class II wells must report under 

subpart UU and may choose to report under subpart RR. Therefore, it is at the discretion 
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of an EOR operator whether to conduct any MRV needed to demonstrate sequestration 

and whether to quantify and report any leakage. This is wholly inadequate for the 

purposes of demonstrating that CO2 from Indiana Gasification’s facility has not eventually 

been vented. Even if operators voluntarily report under subpart RR, there is no guarantee 

that the scope of the MRV will be adequate. Worse none of the reporting rule subparts 

require any mitigation in the event of leakage – they simply require that the leakage be 

estimated and reported.

Thus, the permit for any source that captures CO2 must require a demonstration that the 

captured CO2 is delivered to a facility subject to design, maintenance and operational 

requirements adequate to assure the permanent isolation of the delivered CO2 from the 

atmosphere. EPA’s current regulatory infrastructure as it applies to Enhanced Oil 

Recovery operations is not adequate in ensuring the non-emission of transported and 

injected CO2, nor does is require quantification and reporting of any such leaks.

IDEM may structure such a requirement by, at a minimum, mandating that the applicant 

submit as part of its permit application a CO2 plan under which the applicant certifies that 

the entities to which it transfers captured CO2 are subject to a regulatory program that 

requires them to follow design, operational and maintenance requirements sufficient to 

assure permanent isolation of the CO2 from the atmosphere. This could be achieved if 

enhanced oil recovery operations took place under UIC Class VI and subpart RR CAA 

reporting requirements. The plan must be made part of the initial permit record and 

subject to public comment; thus, IDEM must renotice the proposed permit for public 

comment once the applicant submits the CO2 plan. 

In advance of comprehensive regulations from EPA that ensure the permanent 

sequestration of CO2 during enhanced oil recovery, a CO2 plan that does not rely on 

Class VI regulation under UIC should contain but not be limited to the following:

• A demonstration that sites are capable of long-term containment of carbon 

dioxide;

• Identification and characterization of potential natural and man-made leakage 

pathways, and appropriate risk management and corrective actions;

• Design, construction and operation parameters to prevent, mitigate and 

remediate the creation or activation of leakage pathways, or and the migration of 

CO2 or fluids into any zone in a manner not authorized by the Administrator (or 

pursuant to a State program approved by the Administrator as meeting the 

requirements of this section);

• Minimizing fugitive CO2 emissions from project operations;

• Monitoring and modeling to predict and confirm the position and behavior of the 

CO2 and other fluids in the subsurface during and after injection;

• Accounting and reporting of CO2 quantities sequestered, injected, recycled, 

leaked, vented, and any other categories as appropriate; and,

• Post-injection site closure and financial responsibility requirements that ensure 

the long-term containment of injected CO2.

Response 12: The commenter suggests that the entire regulatory program for managing the 

transportation, storage, and injection of CO2 in geologic formations and any consequent 

“leakage” of CO2 must be analyzed in the proposed facility’s BACT analysis. See 

Response to Public Comment 9 for a description of the emissions that must be 

considered in the BACT analysis. As discussed in Response to Public Comment 10, 

which includes a description of the CO2 sources that must be analyzed for BACT 

purposes, secondary emissions (if any) associated with CO2 delivered as product are not 

air emissions associated with this facility, and therefore not subject to BACT. 
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Consequently, the commenter’s detailed discussion of preventing CO2 from entering the 

air from EOR use of CO2 is not relevant to this permit proceeding.

Comment 13: Higher carbon dioxide emissions for two years should not be allowed, use the lower limit 

from the start of the permit.

Response 13: See Response to Public Comment 8.

Comment 14: Indiana is one of the worst states for CO2 emissions.

Response 14: Indiana’s current economy is based on energy intensive industry and electrical power 

generation. This leads to relatively high CO2 emissions at the state level. Indiana 

regulates CO2 emissions from all new plants that emit large amounts of CO2 through the 

Prevent of Significant Deterioration (PSD) program. 

This permitting action deals with a new source and this new source is subject to a PSD 

review and the application of Best Achievable Control Technology (BACT) requirements for 

greenhouse gases, including CO2. The GHG BACT Analysis for this source is set out in 

Appendix B-BACT Analyses, to the Technical Support Document. 

Comment 15: What happens if the pipeline isn’t built?

Response 15: See Response to Public Comment 7.

Comment 16: CO2 sequestration is too costly and dangerous. Will this CO2 be sequestered? 

Response 16: The permitting authority has concluded that geologic sequestration of emitted CO2 is 

technically infeasible for this project, and has accordingly not required CO2 sequestration.

Hazardous Air Pollutants (HAPs) Comments:

Comment 17: The Permit Must Provide Practically Enforceable Conditions Restricting the Project 

from Being a Major Source of HAP Emissions.

Review of the File shows the Draft Permit is premised upon the Project not being a major 

source of hazardous air pollutant (HAP) emissions.

File review shows the Project has an unrestricted PTE for a single HAP (methanol) of 

greater than 10 tons/year and an unrestricted PTE for all HAPs of greater than 25 

tons/year. Specifically, Appendix A: Emissions Calculations Emission Summary 

(Uncontrolled Potential to Emit) shows the combined Potential to Emit for all emission 

sources totals 17.98 tons/year methanol and 53.26 tons/year Total HAPs. Therefore, the 

Project would be a major source subject to additional requirements, unless there are 

sufficient practically enforceable permit restrictions in the Permit to limit the HAP 

emissions to less than 10 tons/year methanol and 25 tons/year Total HAP. 

The Draft Permit apparently intends to limit methanol emissions such that the Project is 

not a major source (i.e., it would be an “area source” as defined in 40 CFR 63.2; 

sometimes referred to as a “minor source”). Appendix A: Emissions Calculations 

Emission Summary shows the Limited Potential to Emit for emission sources totals 9.66 

tons/year methanol and 24.79 tons/year Total HAPs. However, the restrictions to achieve

the limited Potential to Emit are insufficient. The Commenter believes the Permit can 

appropriately restrict HAP emissions to less than 10 tons/year methanol and 25 tons/year 

Total HAP by addressing the comments below.
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Review of Appendix A data summaries shows the following emission units whose PTE 

either of methanol emissions or Total HAP emissions are limited in some fashion (i.e., 

emission units with no reduction of HAP emissions are not included):

Emission Unit

Uncontrolled PTE 

(tons/year)

Limited PTE

(tons/year)

Methanol Total HAPs Methanol Total HAPs

Auxiliary Boiler (005A/B) 0 6.69 0 1.4

Acid Gas Recovery Unit 

(007A/B)

10.54 37.83 9 22.5

Gasifier Preheat Burners 

(008A-E)

0 0.75 0 0.1

Fugitive Emissions 7.15 7.58 0.38 0.38

The Commenter reviewed the Draft Permit for requirements that practically limit the 

emission of HAP such that the source would be an area source.

Review of the Draft Permit shows Condition D.6.9 Operational Limit practically restricts 

the Auxiliary Boiler (005A/B) emissions via a fuel throughput restriction. However, it is not 

clear from the face of the permit whether this restriction is a necessary requirement for 

restricting HAP emissions to create an area source. If the fuel throughput restriction has 

as part of its purpose the limitation of HAP emissions, IDEM should, clarify that purpose in 

an Addendum to the TSD and add clarification to Condition D.6.9 as follows (new text 

italicized): “The total throughput of fuel to the two (2) natural gas-fired auxiliary boilers, 

identified as EU-005A/B, shall not exceed a total firing rate of 1430 billion Btu per twelve 

(12) consecutive month period, with compliance determined at the end of each month. 

Compliance with the above limit 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 any individual HAP and twenty-five (25) tons per year of any 

combination of HAPs and make the source an area source of HAPs.”

Response 17: As stated above the two (2) natural gas-fired auxiliary boilers were limited to a total firing 

rate of 1430 billion Btu per twelve (12) consecutive month period, which is part of the 

process to limit all the emissions from the boilers including the HAPs emissions. The 

above statement from the commenter has been included in new Condition D.6.9 -

Hazardous Air Pollutants (HAPs) Minor Limits of the permit.

D.6.9 Hazardous Air Pollutants (HAPs) Minor Limits

The single HAP and total HAP from the natural gas-fired auxiliary boilers identified as EU005A and EU-005B shall be limited by compliance with Condition D.6.10 - Operational Limit 

and, combined with the potential to emit HAP emissions from all other emission units, this 

requirement will limit the potential to emit from this source to less than ten (10) tons per 

year of any individual HAP and twenty-five (25) tons per year of any combination of HAPs 

and make the source an area source of HAPs.
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 Comment 18: Draft Permit Condition D.4.11 Hazardous Air Pollutants (HAPs) Minor Limits expressly 

limits HAP emission from the Acid Gas Recovery Unit (007A/B) for the purpose of making 

the source an area source of HAPs. Therefore, the relevance of the restriction with 

respect to area source status is clearly set forth. With regard to these emission units 

(007A/B), it is noted that the File record (i.e., Draft Permit and TSD documents) is not 

consistent in describing what the Commenter has presumed are the same emission units. 

For example, the emission unit description in Draft Permit D.4(E) describes Acid Gas 

Removal (AGR) Unit vents, identified as EU-007A and EU-007B; Conditions D.4.5, D.4.7, 

D.4.18 and D.4.19 use the D.4(E) description. However, Conditions D.4.8 and D.4.11 

describe Acid Gas Recovery Unit vents (EU-007A/B), Conditions D.4.9 describes both 

Acid Gas Recovery (AGR) vents and Acid Gas Removal (AGR/RTO) Unit vents, and 

Condition D.4.10 describes AGR units. Other such differences may appear elsewhere in 

the Draft Permit and TSD. IDEM should clarify whether these descriptions are the same 

or different emission units. Additionally, the Permit should reflect editing such that it uses 

consistent emission unit descriptions.

Response 18: IDEM has revised the emission unit description for the two (2) Acid Gas Removal (AGR) 

Unit vents, as EU-007A and EU-007B to be consistent as set forth by the file record

throughout the permit. IDEM conducted a BACT analysis for the regenerative thermal 

oxidizer controlling the AGR which is the AGR/RTO. This is the identification for the AGR

regenerative thermal oxidizer not the identification for the AGR itself. As stated above the 

identification for the AGR Unit vents are EU-007A and EU-007B.

Comment 19: The Commenter was not able to determine the mechanism (e.g., a restriction on fuel 

usage, hours of operation, or something else) that restricts HAP emissions from Gasifier 

Preheat Burners (008A-E). However, it may be practically achieved via the CO2

emissions limit in Condition D.7.8 GHGs PSD BACT [326 IAC 2-2-3]. IDEM should, at a 

minimum, clarify in an Addendum to the TSD the requirement(s) by which HAP emissions 

for these units are limited for the purpose of area source status. For clarity, IDEM should 

add the following to Permit Condition D.7.8: “Compliance with the above limit 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 any individual 

HAP and twenty-five (25) tons per year of any combination of HAPs and make the source 

an area source of HAPs.”

Response 19: While the commenter is correct that the CO2 emissions limit operates as a practical 

limitation on overall HAPs, because uncontrolled HAPs PTE from the pre-heat burners 

would not result in overall HAPs PTE exceeding the major source thresholds, no HAPs 

limitation is necessary for the preheat burners.

In addition, the HAPs emissions from the preheat burners are very small but the source 

will be restricting their fuel usage to comply with the CO2 emission limit, which will have 

the effect of restricting the HAPs emissions. Condition D.7.12(a) - Record Keeping and 

Requirement clearly specifies that the source shall maintain monthly records of the type 

and amount of fuel combusted in the Gasifier Preheat Burners.

Comment 20: Control of Fugitive Emissions is a significant element in limiting HAP emissions. Draft 

Permit Section D.15 and Condition E.6.1 CO, H2SO4, SO2, and GHG PSD BACT [326 

IAC 2-2-3] establish Leak Detection and Repair (LDAR) requirements; however, it is not 

clear that LDAR requirements are established to limit source HAP emissions such that the

source is an area source for HAP emissions. The basis for Project HAP fugitive emissions

is included in TSD Appendix A. The TSD data shows fugitive emissions are controlled by 

applying published reduction factors achieved via implementation of an LDAR program. 

IDEM should specifically clarify, in both the Permit and an Addendum to the TSD, that 

implementation of an LDAR program is one of the requirements for achieving area source 

status. For clarity, IDEM should add the following to Permit Condition D.15.4:
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“Compliance with the LDAR program incorporated in Section E.6 for equipment in 

methanol service 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 any individual HAP and twenty-five (25) tons per year of any combination of HAPs 

and make the source an area source of HAPs.”

Response 20: IDEM has included the above language in a new Condition D.15.5 - Hazardous Air 

Pollutants (HAPs) Minor Limits to clarify that, the implementation of an LDAR program is 

one of the requirements for achieving area source status for this source.

D.15.5 Hazardous Air Pollutants (HAPs) Minor Limits

The single HAP and total HAPs from the Fugitive Equipment Leaks from the gasification, 

shift conversion, gas cooling, AGR, CO2 compression, WSA, and methanation identified as 

FUG & FUG-WSA shall be limited by compliance with the LDAR program incorporated in 

Section E.6 for equipment in methanol service and, combined with the potential to emit 

HAP emissions from all other emission units, this requirement will limit the potential to 

emit from this source to less than ten (10) tons per year of any individual HAP and twentyfive (25) tons per year of any combination of HAPs and make the source an area source of 

HAPs.

BACT Analysis Comments:

Comment 21: Sections D.7.4 and D. 6.4 show that particulate emissions from burning the same amount 

of the same fuel are about 10 1⁄2 times more from the large, 408 MMBtu/hr boilers as from 

the much smaller 35MMBtu/hr burners. The larger should be held to a lower not a larger 

amount, as it should be possible for larger combustion to be more cleanly accomplished 

and emissions from it controlled more thoroughly than from the smaller combustions. 

Why are the larger combustors allowed to produce more emissions per unit of heat?

Response 22: Particulate emissions from any clean gas fired source are very small. Particulate emissions 

from the Auxiliary Boilers have been estimating using the standard EPA AP42 emissions 

factors for particulate emissions from natural gas combustion (permit condition D.6.4). This 

is the standard methodology for conventional external combustion sources. The particulate 

emissions for the unique gasifier preheat burners (permit condition D.7.4) include the 

additional consideration that the combustion exhaust from these preheat burners pass 

through the gasifier quench water system which is expected to remove a significant 

amount of the already low particulate emissions. An explanation of the selection of these 

emissions factors is presented in IG’s application on page 3-4. 

LDAR Comments:

Comment 22: LDAR Comments:

The LDAR provisions in Condition E.6.1 are ambiguous and should be 

revised.

Draft Permit Condition E.6.1 states, in part that:

The source is not a major source of HAPs and is not subject to any of the MACT 

standards under 40 CFR Part 63. However, in the context of the BACT 

determination for this source, the substantive requirements of 40 CFR 63 

Subpart H, addressing equipment leaks, apply to the components listed under 

40 CFR 63.160(a) that are in service at the facility for the following process 
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streams: methanol streams, propylene streams, and product SNG streams. The 

same Subpart H requirements apply to any leaks of SO2 in the Wet Sulfuric Acid 

unit piping between the combustor and oxidation reactor, beginning with the 

connector at the combustor and ending with the connector at the oxidation 

reactor, except that references in the regulations to methane or VOCs will instead 

be applied to the pollutant SO2.

The condition’s reference to the “substantive requirements” is ambiguous. If only 

the requirements of Subpart H identified throughout E.6.1 are deemed the 

substantive portions, then the condition should be modified to clearly state those 

are the substantive requirements. If it means all of Subpart H except specific 

requirements, IDEM should specify those that are excepted. If it means 

interpreting Subpart H requirements with different definitions, then those 

definitions should be specified in E.6.1.

LDAR implementation can be challenging to even the most experienced 

professionals. Lack of clarity and consistency in terminology would further 

complicate compliance efforts. For example, Subpart H regulates leaks from 

“equipment” (as that term is defined in 40 CFR 63.161); it does not specify 

requirements in terms of “components” (as referenced in E.6.1). Under Subpart 

H, regulated equipment must be “in organic hazardous air pollutant service” (as 

that term is defined in 40 CFR 63.161). Unless the Project propylene and product 

SNG streams contain 5 percent by weight of organic HAP they would not qualify 

as streams “in organic hazardous air pollutant service” under Subpart H; thereby 

creating uncertainty as to what requirements are intended by E.6.1. Therefore, it 

is unclear what practically enforceable requirements E.6.1 actually creates for the 

process streams listed. If IDEM intends the Permittee to only implement particular 

Subpart H requirements, then the Permit needs to be more specific. Accordingly, 

for the purpose of applicability and compliance with Subpart H requirements 

under Condition E.6.1, it should appropriately specify those substances (e.g., 

VOC, HAP, SO2, etc.) that are to be considered as if they were organic 

hazardous air pollutants (OHAP). 

Regardless of the approach developed to incorporate LDAR requirements, the 

Permit should clearly specify whether the requirements are necessary with 

respect to limiting HAP emissions to area source thresholds. In addition, LDAR 

compliance obligations should be clear, complete, and practically enforceable.

Response 22: The applicable permit conditions are being edited to clarify the role of LDAR in limiting 

HAP emissions and the components to which these requirements apply. The following 

edits are being implemented to condition E.6.1.

E.6.1 CO, H2SO4, SO2, and GHG PSD BACT [326 IAC 2-2-3] and Hazardous 

Air Pollutants (HAPs) Minor Limits

The source is not a major source of HAPs and is not subject to any of the MACT 

standards under 40 CFR Part 63. However, in the context of the BACT 

determination for this source and the limitation of HAP emissions, the 

requirements of 40 CFR 63 Subpart H, addressing equipment leaks, that are 

listed below, apply to the pumps, compressors, pressure relief devices, 

sampling connection systems, open-ended valves or lines, valves, 

connectors, instrumentation systems, and control devices or systems that 

are in service at the facility for the following process streams: methanol streams, 

propylene streams, and product SNG streams. The same Subpart H 

requirements apply to any leaks of SO2 in the Wet Sulfuric Acid unit piping 

between the combustor and oxidation reactor, beginning with the connector at the 

combustor and ending with the connector at the oxidation reactor, except that 
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references in the regulations to methane or VOCs will instead be applied to the 

pollutant SO2. These requirements apply to the above listed streams 

irrespective of the HAP content of the specified streams.

...............................................................................................................................................

Comment 23: What about leaks in pipes caused by acidic waste streams?

Response 23: The LDAR provisions of this permit are applicable to appropriate piping and components 

with the potential to leak air pollution. As such, leaks of any origin will be detected and 

addressed through maintenance and repair requirements of the permit. It should be 

noted that sulfuric acid is used commonly in manufacturing and there is extensive 

experience in the specification of metallurgy and the selection of materials for 

components and piping that are resistant to acid corrosion.

Compliance Assurance Monitoring (CAM) Comments (Testing, CEMs 

and Monitoring)

Comment 24: Section A.3 (c) - Specifically Regulated Insignificant Activities calls four rod mill operations 

insignificant and indicates no emissions controls will be required. These would be mills 

that crush coal. There will be coal dust made and apparently vented to the atmosphere. I 

call this significant activity. What justifies not requiring pollution controls on this operation?

Response 24: All emissions units in Section A.3 are specifically regulated insignificant activities in 

accordance with 326 IAC 2-7-1(21). The four (4) rod mills, identified as EU-013A through 

EU-013D have low emissions because they are a wet process in which a high volume of 

water is mixed with the coal/coke feedstock at the inlet of the rod mill and the combined 

mixture ground into a high solids aqueous slurry. This aqueous slurry is then fed to the 

slurry holding tanks from which it is pumped into the gasifiers. Because the rod mill coal 

grinding occurs in an aqueous solution, even without add-on controls, the rod mill 

particulate emissions are extremely small (e.g.; 0.1 lb/hr and 0.44 tons/yr PM10). 

Accordingly, the rod mill vents are considered an insignificant activity in accordance with 

326 IAC 2-7-1(21)(B) because the uncontrolled emission of PM10 is less than five 

pounds per hour or twenty-five pounds per day. The classifications of these emission 

units in this draft permit are strictly related to air pollution emissions. 

Comment 25: Section D.1.4 (a) (1) controls PM 2.5 via a baghouse, which filters allow a great 

percentage of uncontrolled PM 2.5 to be emitted. What justifies use of less than the 

maximally effective (this is not MACT and please do not confuse it with MACT or BACT) 

pollution controls of PM and PM2.5?

Response 25: A baghouse (also known as a fabric filter) does provide the greatest level of control for 

PM, PM10 and PM2.5. IDEM conducted a top-down BACT analysis of PM, PM10, and 

PM2.5 control technologies as part of its review and included it as Appendix B to the 

Technical Support Document. This source has no condensable PM emissions, and, in 

this review, IDEM concluded that the same control technologies were applicable to all 

three forms of PM. The control technologies evaluated included a wet scrubber, wet 

suppression, a cyclone and a fabric filter. IDEM made a final determination that a fabric 

filter was the top ranked control technology for all three forms of PM (PM, PM10 and

PM2.5) and that BACT for the emission units under evaluation was a fabric filter achieving 

a maximum loading from the control device of 0.003 grains per dry standard cubic foot 

(dscf) for PM and PM10 and 0.0015 grains per dry standard cubic foot (dscf) for PM2.5. 

This level of control is more stringent than any BACT limit reviewed for permits for other 

sources with similar emission units. Therefore, the baghouse control devices provide the 

highest effective control for PM, PM10, and PM2.5.
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Comment 26: Section D. 1.6 (d) allows operation, when temperature is below 32 degrees with no 

suppression of coal dust Particulate Matter. It is not specified if this is 32 degrees 

Celsius, which, if it is, would mean no suppression most of the time, i.e., when air 

temperature is below approximately 89 degrees Fahrenheit. Why does this oversight 

exist and how will you correct it; which 32 degrees is it?

Response 26: The temperature is in Fahrenheit. IDEM has made the appropriate clarification in 

Condition D.1.6 - PM, PM10 and PM2.5 Control in the permit accordingly. See response to 

Sierra Club Comment 69.

Comment 27: Section D. 1.7 (a) allows excessive time to perform tests. Testing should be done at or 

shortly after operation inception, not up to 180 days after, as the permit allows. What 

justifies not requiring testing sooner after operations begin?

Section D. 5.16 (b) allows up to 365 days to expire following start up of operations for 

testing to be performed and results filed with IDEM. This is far too long a period. What 

justifies allowing this much time to elapse and what will the emissions be during this 

period?

Response 27: Section D.1.7 (a) applies to the testing of the emissions of the baghouse on the feedstock 

conveying systems. While the operator is given 180 days to demonstrate the emissions 

levels through testing, the obligation to install, operate and maintain the baghouse applies 

from initial operation of the conveying system. See Section D.1.5 and D.1.6. The 180 

days are provided to allow time to develop and submit a test protocol, line up a testing 

contractor and achieve a condition representative of normal operation. Earlier testing 

might represent conditions not representative of normal loading on the control system. 

Section D.5.16 applies to the demonstration of particulate emissions from the Wet 

Sulfuric Acid unit. The timing of that test is also keyed to the startup of gasifiers to ensure 

that there will be representative throughput in the WSA at the time of test. As with the 

feed stock conveyor baghouse, the timing of the testing does not alter the obligation to 

start up and operate the units with emissions controls functioning correctly. In summary, 

IDEM believes all permit terms and conditions are correct and require sufficient testing to 

ensure compliance. 

Some sources need time to build up a supply of raw materials to be able to run 

emission units at representative conditions. If the source cannot operate at a 

representative capacity, the test may not be considered valid and must be repeated as 

production increases. If the test is not completed within the time allotted, IDEM may 

initiate an enforcement action. 

Because this large facility has many interrelated operations, full load and 

representative operating conditions on some units cannot be achieved until multiple 

upstream units are operating, which may take up to 365 days to occur. Therefore, 

IDEM determined it was appropriate to extend the testing of some of the emission 

units to 365 days after start up of the first gasifier unit. No revisions to the draft permit 

are required as a result of this comment.

Comment 28: The syn gas flare is extremely dirty for its fuel consumption. Can the emissions from the 

flare be controlled?

Response 28: The project incorporates a number of measures to reduce emissions from the syngas flare 

and those measures are reflected in operational and emissions limits in the permit. First, 

the flare pilot will operate on clean natural gas or SNG. Second, the gasifiers will be 

started on a clean feedstock, methanol, so that the gasified material going to the flare 

during startup will have negligible SO2. Also, during gasifier shutdowns, most of the 

residual gas in the gasifier will be sent to downstream treatment systems and only a small 
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residual will be sent to the flare. IDEM conducted a top-down BACT analysis for flare 

emissions, which is included in the TSD, that provides an evaluation of potentially available 

control technologies.

Comment 29: Section D.6.13 specifies that only one test of CO emissions will take place and that can 

be up to 180 days after startup. Conditions at a facility change over time and emissions 

can change with those. This testing is inadequate to protect the public. Will these test 

results be used as a surrogate for other emissions? If so, what justifies such use? If the 

test is to measure combustion efficiency, what justifies only one test, as combustion 

characteristics change over time?

Response 29: The two (2) natural gas-fired auxiliary boilers have no add-on control device for CO 

emissions, and the CO combustion characteristics are inherent in the design of the 

burners. Therefore, the CO emissions from the natural gas-fired auxiliary boilers are 

expected to remain essentially the same throughout the life time of the emission unit. The 

one time testing will be performed to verify compliance with the CO BACT limit given to 

the source. However, IDEM may require compliance testing at any specific time when 

necessary to determine if these facilities are in compliance. If testing is required by IDEM, 

compliance shall be determined by a performance test conducted in accordance with 

Section C - Performance Testing. No revisions to the draft permit are required as a result 

of this comment.

Comment 30: Inspections (Compliance monitoring): IDEM inspections are rare and will be with this 

plant. Maybe IDEM will inspect once per year, what happens the rest of the time? 

Response 30: See Response to Public Comment 50.

Potential to Emit Comments:

Comment 31: What are the PTEs for dioxins/furans of individual combustors and gasifiers proposed to 

be operated at this site? Why are dioxins/furans not listed in the PTE lists in this permit? 

What justifies not listing them?

Response 31: The combustion of natural gas, SNG, syngas and diesel fuel do not produce dioxin/furans.

Dioxin/furans are associated with the direct combustion of more complex organic materials 

such as coal and plastics. With regard to natural gas used in the boilers and preheaters, 

and diesel fuel used in the emergency engines, EPA emissions factors for HAPs from 

these fuels list no dioxins or furans. The SNG combusts in the same manner as natural 

gas and has no dioxins or furans or their precursors. With regard to the syngas, according 

to the United States Department of Energy, dioxin and furan compounds are not expected 

to be present in the syngas from gasification systems for two reasons. First, the high 

temperatures in the gasification process effectively destroy any dioxin/furan compounds or 

precursors in the coal or coke feed. Second, the lack of oxygen in the reduced gas 

environment would preclude the formation of the free chlorine from HCl, thus limiting 

chlorination of any dioxin/furan precursors. If the syngas is combusted, one would not 

expect formation of dioxin/furan compounds because very little of the particulate matter 

required for post combustion formation is present in the clean syngas or in the downstream 

combustion gases. Measurements of dioxin/furan compounds in existing gasification 

systems confirm these expectations. (Source: A Comparison of Gasification and 

Incineration of Hazardous Wastes Final Report, March 30, 2000, 

(http://www.netl.doe.gov/publications/others/techrpts/igcc_wp.pdf).

Comment 32: This permit is based upon the EPA’s AP-42, Compilation of Air Emission Factors, 

demonstrated by the material in the support documents. The introduction to AP-42 clearly 

states that emission factors contained in it are not reliably accurate for a specific source. 
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(EPA, January 1995, “Introduction to AP-42, Volume 1, Fifth Edition, January 1995, 

pp.2,3). The EPA clearly indicates that their PM 10 factor does not, in this permit 

application, include condensable PM. (ibid, p6, paragraph 2). The PM 10 PTE in this 

permit is most likely to be inaccurate. How much condensable PM will this facility’s 

individual components emit and what are the health and environmental dangers of these 

condensable PM emissions? 

This permit fails to specify if the PM amounts include or do not include condensable

particulate matter, a significant form of pollution. Condensable must be included in an 

accurate listing of emissions and appears not to be. What justifies not listing PTEs of 

condensable particulate matter in this permit?

Response 32: Because there is no separate applicability threshold for the condensable fraction of 

particulate, IDEM is not required to separately list out the PTE for this subset of total 

particulate. However, in its review of emissions estimates, IDEM has considered 

condensable particulate for all emission sources for which condensable particulate is 

expected, as discussed below.

The largest particulate emission sources at the facility are the Wet Sulfuric Acid (WSA) 

units. The particulate from the WSA units is primarily sulfuric acid mist, which is 

presumed to be a condensable particulate formed from acid which starts out as a gas and 

then condenses. The emissions estimate for these WSA emissions is based on 

information provided by the WSA process licenser. 

Particulate emission from combustion sources (e.g.; auxiliary boiler, preheat burners, 

flares, AGR vent, etc.) are based on AP-42 factors for natural gas combustion, which 

include both filterable and condensable particulate.

Particulate emissions from non-contact cooling towers are expected to result only from 

dissolved solids in the cooling water, in which is considered filterable particulate. 

Particulate emissions from this source are estimated using AP-42 specified methodology.

Particulate emissions from the ZLD spray dryer, ASU Regeneration Vents, and 

Emergency Engines are based on vendor estimates which include, if applicable, 

condensable particulate.

Plant haul road dust is all filterable particulate. There fugitive emissions are not 

exhausted at an elevated temperature, so there is no condensable particulate associated 

with roadway dust. The filterable particulate is estimated using the appropriate AP-42 

methodology.

Likewise, the particulate matter emissions from the Incoming solid feedstock materials 

handling system, transferring material from the barge unloading facility and railcar 

unloading facility to storage piles, day bins, and other feedstock handling steps are all 

filterable PM; there are no condensable PM emissions from these units. 

IDEM believes that the Permittee has adequately documented the source of the emission 

factors used in the calculations submitted.

Comment 33: Section D.6.15 is based upon emission factors without specifying where those are from. 

Most likely, they are AP-42 factors; the emissions figures stand a two out of three chance 

of being incorrect and the degree of their inaccuracy cannot be determined. Where are 

these factors from, and what is their degree of inaccuracy?
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Response 33: Permit condition D.6.15 is the permit condition limiting total CO2 emission from the 

Auxiliary Boilers. The CO2 emissions factor specified (116.89 lb CO2/MMBtu) is taken 

from the methodology in US EPA’s 2009 Greenhouse Gas Mandatory Report Rule 40 CFR 

Part 98, Subpart C – General Stationary Fuel Combustion Sources. Specifically, it is the 

factor in that Subpart in Table C-1 (Default CO2 Emissions factors and High Heat Values 

for Various Types of Fuels) for “Natural Gas, Pipeline (weighted U.S average)” which is 

53.02 kg CO2/MMBtu (converted to lbs./MMBtu). This value is similar to, but about 1⁄2% 

lower than the older AP42 factor for CO2 from natural gas external combustion in AP42 

Chapter 1.4 (most recent update was July 1998). The factor specified is provided for use 

by all facilities for this type of source in EPA’s Mandatory GHG Reporting Rule and is 

considered to be appropriate for use in permitting.

Comment 34: AP-42 clearly states the degree of inaccuracy cannot be determined: “Because 

insufficient data exist to determine the accuracy or validity of the emission factors...no 

estimates can be made of the error that results from using these factors to calculate toxic 

air emissions from any given facility.” (Pope, Anne A., et al, October 1990, EPA-450/2-

90-011, Toxic Air Pollutant Emission Factors- A Compilation for Selected Air Toxic 

Compounds and Sources, Second Edition, [AP42], p. 7; and, with the exception of the 

words, “in this compilation,” in document EPA-450/2-91-028, EPA, 1991, Crosswalk 

[XATEF] Air Toxic Emission Factor Data Base Management System User’s Manual, 

Version 1.2, p. 7)

Response 34: The permit contains enforceable limits on the operation of sources and the emissions of 

sources that serve as the controlled potential to emit (“PTE”) for those units. For 

information related to the use of emission factors, see Responses to Public Comment 42 

and Sierra Club Comments 29, 33, and 36.

Comment 35: Section D. 2.7 requires calculation of emissions using an emissions factor; the EPA states 

factors do not accurately indicate actual emissions. How inaccurate, expressed in a 

percentage of the calculated quantity, will these calculations be?

Response 35: Because this emission unit is subject to BACT, the emission limits imposed are based 

upon the maximum degree of pollution reduction that is achievable on a case-by-case 

basis. Part of the BACT process for developing emission limits involves reviewing the 

limits imposed at other similar sources in order to determine whether the proposed limits 

are at least as stringent as those being met at other facilities. In part because this BACT 

review requires comparison to other facilities, both the methods used to develop the limits 

and the resulting limits are comparable to what is used at other facilities. The techniques 

used to estimate emissions are consistent with standard practice for this type of source 

and consistent with the compliance methodology commonly utilized by comparable 

facilities, and are therefore considered to be accurate and appropriate for the source. 

The NOx and CO emissions factors specified for the flare are design specifications from 

the equipment vendor. The particulate emissions factors are based on AP-42 Chapter 1.4 

for natural gas combustion, which although small, are actually larger than those provided 

in the AP-42 section for industrial flares (Chapter 13.5), which lists particulate (soot) 

emissions from non-smoking flares as zero (0). A detailed explanation of the basis of the 

SO2 emission factor for the hydrocarbon flare is provided in the response to Sierra Club 

Comment 44.
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Environmental Justice Comment:

Comment 36: Environmental Justice Comment:

(a) Rockport, a community of slightly greater than 2,000 people has Toxic Releases 

from two existing industries on the edge of town that measure more than thirty 

million pounds of releases each year. That is more toxic releases than the 

combined total of the industrial (TRI reported) emissions of Atlanta, New York 

City, Pittsburgh, Philadelphia, Indianapolis, Chicago, Seattle, Los Angeles and 

San Diego COMBINED (representing a combined population of 34 million 

people).

As a result, the area is impoverished, having an average per capita income that is 

only about 2/3 of the national average. Sadly it also translates into higher levels of 

cancer, respiratory, and cardio vascular death and disease than the rest of the 

United States. 

Valley Watch has followed the issue of environmental justice due to this problem 

for years and we assert that it is precisely places like Rockport that Plan EJ 2014 

was designed to ameliorate. However, IDEM, in issuing this draft permit has 

completely ignored the issue in direct contradiction of the current protocol.

(b) Environmental Justice. This area has more pollution that several major cities but 

Rockport has only 2,000 people, but IDEM doesn’t care. EJ is not mentioned in 

the permit.

Response 36: IDEM is committed to its Environmental Justice Policy, which can be viewed at 

http://www.in.gov/idem/files/A-008-OEA-08-P-R2.pdf on IDEM’s website. 

Environmental Justice is the fair treatment and meaningful involvement of all people 

regardless of race, color, national origin, geographic location or income with respect to the 

development, implementation, and enforcement of environmental laws, regulations, and 

policies. The Policy requires that IDEM ensure all members of the public have: (1) equal 

access to public information pertinent to Agency policies and procedures; (2) adequate 

notice regarding all Agency program information and decision-making processes; and (3) 

the opportunity to provide public comments and pertinent information to Agency program 

staff.

IDEM has followed this Policy throughout the permitting process. IDEM published a notice 

of this permitting action in the local newspaper. IDEM also posted a copy of the draft 

permit on its website and provided a copy to the local library. On January 25, 2012, IDEM 

held a public meeting and a public hearing at the South Spencer High School Auditorium in 

Rockport, IN, for citizens and interested parties to discuss questions and concerns related 

to the project. 

Furthermore, the proposed facility is not located in an “area of concern” for environmental 

justice issues. Using 2000 U.S. Census data, IDEM has created a map to identify potential 

areas of environmental justice concern in Indiana based on racial minority, Hispanic/Latino 

minority, and income. Rockport, IN, and the downwind areas are not among them. The 

proposed project, therefore, will not have disproportionately high and adverse 

environmental effects on minority and/or low income populations.

As the relevant permitting agency, IDEM’s environmental justice policy applies in this 

instance. Nevertheless, Valley Watch cites to recent U.S. EPA guidance designed to 

increase U.S. EPA’s efforts to address environmental justice concerns. In 1994, President 
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Clinton issued Executive Order (EO) 12898, “Federal Actions to Address Environmental 

Justice in Minority Populations and Low-Income Populations” directing all federal agencies 

to participate in a government-wide effort to address environmental justice issues. EO 

12898 also established an Interagency Working Group to assist the covered agencies by 

providing guidance and serving as a clearinghouse.

More recently, in August 2011, the covered federal agencies signed a “Memorandum of 

Understanding on Environmental Justice and Executive Order 12898.” The purposes of 

this memorandum were to (1) declare the continued importance of identifying and 

addressing environmental justice considerations, (2) renew the process under EO 12898 

for agencies to provide environmental justice strategies and implementation progress 

reports, (3) establish structures and procedures to ensure that the Interagency Working 

Group operates effectively and efficiently, and (4) identify particular areas of focus to be 

included in agency environmental justice efforts. The memorandum of understanding 

requires, among other things, that each agency prepare an “Environmental Justice 

Strategy” to be posted on its public webpage. 

Consistent with this mandate, U.S. EPA published “Plan EJ 2014” in September 2011. 

Plan EJ 2014 is a four-year roadmap to help U.S. EPA develop stronger community 

relationships and increase U.S. EPA’s efforts to improve environmental and health 

conditions in overburdened communities. Plan EJ 2014 is not a rule or regulation, but 

instead a strategy to help integrate environmental justice in U.S. EPA’s day-to-day 

activities. 

With regard to public participation, IDEM complied with several of the recommended best 

practices in the Plan EJ 2014 Guidance, including:

● Public notifications outside of newspapers 

● Direct and targeted outreach to community organizations and institutions

● Making documents physically accessible and free to communities 

● Scheduling meetings during non-working hours 

● Permit process descriptions of when, where, and how the public can get involved

See U.S. EPA, “Plan EJ 2014: Considering Environmental Justice in Permitting,” at 10-11 

(September 2011). U.S. EPA’s Plan EJ 2014 guidance regarding public participation, 

therefore, overlaps with and is consistent with IDEM’s Environmental Justice Policy, which 

was followed throughout the permitting process.

Comment 37: Meetings on permit should be held when elderly are more likely to attend, at mid day, at a 

more centrally located site. 

Response 37: IDEM held a public meeting and a public hearing at the South Spencer High School 

Auditorium in Rockport, IN, on January 25, 2012. The public meeting began at 5:30 p.m., 

during which IDEM staff made an opening statement and took questions and comments 

regarding the permits for the construction and operation of the proposed state-of-the-art 

SNG and liquefied CO2 production plant. At 6:30 p.m., IDEM conducted a formal public 

hearing on the draft permits. Citizens had the opportunity to submit written comments and 

make formal statements concerning the draft permits during that time. 

IDEM held the public meeting and hearing during non-working hours to maximize 

attendance. Indeed, holding meetings during non-working hours is recommended by U.S. 

EPA in its environmental justice guidance. See U.S. EPA, “Plan EJ 2014: Considering 

Environmental Justice in Permitting,” at 10-11 (September 2011). Although IDEM 

scheduled a meeting during non-working hours to maximize attendance, those unable to 

attend the meeting were permitted to submit written comments on the draft permits.
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Finally, the South Spencer High School Auditorium is located in Rockport, IN, and 

therefore an appropriate location for the public meeting and hearing.

National Ambient Air Quality Standard Comment:

Comment 38: The Clean Air Act requires that new major sources of pollutants demonstrate that they will 

not cause or contribute to a violation of any ambient air quality standards. The current 

ambient air quality for ozone is 75 ppb. For example there are no ozone monitors in 

Spencer County, we do not know how severe our problem is. Since pollution has no 

boundaries, we know of several neighboring counties already near or above the 

acceptable amount of 75 ppb. For example, in 2011 a new monitor in Knox County at the 

Southwest Purdue Agricultural Center registered 77 ppb, Perry County monitor registered 

74 ppb, Posey County monitor registered 76 ppb, Warrick County Boonville High School 

75 ppb and Evansville 77 ppb. 

On page 37 of IDEM's technical support document, IDEM admits it did conduct a computer 

modeling analysis of the levels of fine particulate matter that would be released when the 

facility is built and that the additional particulate matter would be in violation of the 

National Ambient Air Quality Standard for fine particulate matter.

Response 38: The following spreadsheets show ozone values in southwestern Indiana since 1995. Note 

that not all sites were operating until after that time. The National Ambient Air Quality 

Standard (NAAQS) for ozone for each monitoring location is the fourth highest daily value 

for a year, averaged over a three-year period. As shown in the righthand column (“3 year 

Average of 4th High”) in each table, all sites are currently in attainment of the 0.076 ppm 

(76 ppb) standard based on the ozone monitoring in the area.

It should also be noted that IDEM did not operate an ozone monitor in Knox County in 

2011, nor does it now.
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Rockport, Indiana T 147-30464-00060

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Southwest Indiana Region

EIGHT HOUR OZONE AVERAGES (PPM)

Greene County

Year 1st Date 2nd Date 3rd Date 4th Date Days => 0.085 ppm 3 Year Period Site Design Value

2000 0.095 6/1 0.093 6/9 0.091 6/8 0.090 5/31 4 (00 avg) 0.090

Plummer 2001 0.092 6/13 0.091 6/18 0.087 6/19 0.085 5/4 5 (00-01 avg) 0.087

18 055 0001 2002 0.097 8/10 0.095 7/8 0.095 9/8 0.093 7/15 14 (00-02 avg) 0.089

2003 0.097 6/18 0.092 6/24 0.092 6/25 0.088 8/25 4 (01-03 avg) 0.088

2004 0.076 4/16 0.075 4/29 0.075 9/23 0.073 8/19 0 (02-04 avg) 0.084

2005 0.084 6/25 0.082 6/24 0.079 6/29 0.079 7/10 0 (03-05 avg) 0.080

2006 0.081 6/17 0.077 8/25 0.076 6/6 0.076 6/16 0 (04-06 avg) 0.076

2007 0.090 6/17 0.086 8/2 0.085 5/21 0.084 5/23 3 (05-07 avg) 0.079

Days => 0.076 ppm

 2008 0.075 4/23 0.075 7/18 0.072 4/22 0.072 7/16 0 (06-08 avg) 0.077

2009 0.071 6/25 0.070 6/24 0.070 6/7 0.068 6/27 0 (07-09 avg) 0.074

2010 0.076 4/12 0.075 4/13 0.074 5/5 0.074 4/14 1 (08-10 avg) 0.071

2011 0.089 6/7 0.082 8/2 0.080 9/3 0.080 8/1 7 (09-11 avg) 0.074

Perry County

Year 1st Date 2nd Date 3rd Date 4th Date Days => 0.085 ppm 3 Year Period Site Design Value

2004 0.081 8/19 0.080 4/16 0.080 5/7 0.078 4/29 0 (04 avg) 0.078

Leopold 2005 0.088 7/10 0.086 6/30 0.086 8/1 0.086 8/11 4 (04-05 avg) 0.082

18 123 0009 2006 0.084 6/15 0.082 6/17 0.080 7/1 0.079 7/2 0 (04-06 avg) 0.081

2007 0.092 9/20 0.086 7/25 0.085 8/15 0.080 9/22 3 (05-07 avg) 0.081

Days => 0.076 ppm

 2008 0.080 7/18 0.078 8/20 0.075 7/28 0.073 7/29 2 (06-08 avg) 0.077

2009 0.076 6/25 0.067 6/2 0.067 6/1 0.065 6/6 1 (07-09 avg) 0.072

2010 0.077 8/9 0.077 6/21 0.075 7/14 0.072 8/13 2 (08-10 avg) 0.070

2011 0.080 6/6 0.079 6/9 0.076 9/1 0.074 7/11 3 (09-11 avg) 0.070

Posey County

Year 1st Date 2nd Date 3rd Date 4th Date Days => 0.085 ppm 3 Year Period Site Design Value

1996 0.061 0.059 0.057 0.054 0 (96 avg) 0.054

St Philips 1997 0.096 7/12 0.090 6/23 0.089 7/18 0.087 6/27 4 (96-97 avg) 0.070

18 129 0003 1998 0.111 9/13 0.096 8/17 0.095 9/12 0.092 5/14 11 (96-98 avg) 0.077

1999 0.105 9/4 0.104 9/2 0.098 9/3 0.096 9/5 15 (97-99 avg) 0.091

2000 0.093 8/29 0.086 7/9 0.086 7/27 0.085 6/8 5 (98-00 avg) 0.091

2001 0.080 6/18 0.080 6/19 0.079 5/10 0.079 6/12 0 (99-01 avg) 0.086

2002 0.106 8/3 0.099 8/9 0.098 9/8 0.097 6/20 13 (00-02 avg) 0.087

2003 0.092 6/24 0.082 6/23 0.080 6/18 0.077 6/29 1 (01-03 avg) 0.084

2004 0.077 9/23 0.073 4/16 0.073 6/30 0.071 8/18 0 (02-04 avg) 0.081

2005 0.085 8/1 0.080 6/23 0.080 7/10 0.077 7/9 1 (03-05 avg) 0.075

2006 0.079 7/19 0.066 6/15 0.063 7/18 0.058 6/16 0 (04-06 avg) 0.068

2007 0.086 8/1 0.084 7/25 0.081 5/22 0.080 6/12 1 (05-07 avg) 0.071

Days => 0.076 ppm

 2008 0.080 4/23 0.073 8/20 0.070 7/17 0.069 7/16 1 (06-08 avg) 0.069

2009 0.076 6/24 0.070 5/20 0.069 6/6 0.067 5/23 1 (07-09 avg) 0.072

2010 0.072 8/7 0.071 9/20 0.071 8/19 0.069 9/21 0 (08-10 avg) 0.068

2011 0.079 6/2 0.076 6/30 0.076 6/29 0.076 6/7 4 (09-11 avg) 0.070

*Site started 7-01-96

3 Year Average of 4th High

3 Year Average of 4th High

3 Year Average of 4th High
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Vanderburgh County

Year 1st Date 2nd Date 3rd Date 4th Date Days => 0.085ppm 3 Year Period Site Design Value

1995 0.101 0.096 0.095 0.094 18 (95 avg) 0.094

Evansville - Mill Rd. 1996 0.100 0.097 0.092 0.090 8 (95-96 avg) 0.092

18 163 0012 1997 0.105 7/12 0.101 7/17 0.094 7/25 0.093 6/23 6 (95-97 avg) 0.092

1998 0.111 9/13 0.102 9/12 0.099 5/14 0.092 5/18 8 (96-98 avg) 0.091

1999 0.101 9/5 0.100 9/4 0.098 8/12 0.098 9/2 18 (97-99 avg) 0.094

2000 0.085 8/29 0.083 7/9 0.083 7/27 0.081 8/17 1 (98-00 avg) 0.090

2001 0.077 6/18 0.074 7/21 0.073 6/12 0.073 7/16 0 (99-01 avg) 0.084

2002 0.105 8/13 0.102 7/8 0.096 8/9 0.095 7/15 16 (00-02 avg) 0.083

2003 0.089 6/24 0.086 8/27 0.082 6/29 0.081 6/23 2 (01-03 avg) 0.083

2004 0.078 9/23 0.074 6/30 0.073 4/16 0.072 8/18 0 (02-04 avg) 0.082

2005 0.090 6/23 0.081 6/22 0.081 8/1 0.080 8/9 1 (03-05 avg) 0.077

2006 0.092 7/19 0.083 7/18 0.079 8/17 0.075 6/9 1 (04-06 avg) 0.075

2007 0.089 8/28 0.088 8/1 0.086 8/14 0.085 8/12 4 (05-07 avg) 0.080

Days => 0.076 ppm

 2008 0.083 7/16 0.079 7/17 0.074 7/18 0.074 5/29 2 (06-08 avg) 0.078

Evansville - Buena Vista *2009 0.064 6/24 0.062 5/20 0.061 6/25 0.061 6/6 0 (07-09 avg) 0.073

18 163 0021 2010 0.067 6/25 0.067 6/3 0.064 6/21 0.064 5/29 0 (08-10 avg) 0.066

2011 0.085 7/1 0.078 6/7 0.077 7/2 0.077 6/2 5 (09-11 avg) 0.067

*Site was moved to new location on 7/10/2009

Vanderburgh County

Year 1st Date 2nd Date 3rd Date 4th Date Days => 0.085 ppm 3 Year Period Site Design Value

Inglefield 1995 0.099 0.097 0.096 0.096 20 (95 avg) 0.096

18 163 0013 1996 0.103 0.098 0.095 0.094 12 (95-96 avg) 0.095

1997 0.105 7/12 0.102 7/17 0.093 7/18 0.089 7/7 8 (95-97 avg) 0.093

1998 0.107 9/13 0.099 5/14 0.098 8/17 0.094 9/12 10 (96-98 avg) 0.092

1999 0.098 6/21 0.095 9/4 0.094 9/5 0.091 9/2 9 (97-99 avg) 0.091

2000 0.077 6/1 0.076 7/27 0.075 6/4 0.075 7/9 0 (98-00 avg) 0.086

2001 0.079 6/12 0.076 6/18 0.073 5/10 0.072 5/4 0 (99-01 avg) 0.079

2002 0.097 7/8 0.095 8/3 0.089 7/15 0.086 6/21 5 (00-02 avg) 0.077

2003 0.085 6/24 0.081 6/23 0.075 6/29 0.075 7/17 1 (01-03 avg) 0.077

2004 0.065 4/16 0.061 4/29 0.058 4/17 0.058 8/18 0 (02-04 avg) 0.073

2005 0.058 7/10 0.057 6/23 0.056 5/7 0.056 5/18 0 (03-05 avg) 0.063

2006 0.095 7/19 0.088 7/18 0.082 7/17 0.081 6/15 2 (04-06 avg) 0.065

2007 0.091 8/28 0.089 8/14 0.088 6/17 0.088 7/25 8 (05-07 avg) 0.075

Days => 0.076 ppm

 2008 0.077 8/20 0.075 7/17 0.075 7/16 0.072 4/23 1 (06-08 avg) 0.080

2009 0.076 6/24 0.069 6/6 0.069 5/20 0.068 6/27 1 (07-09 avg) 0.076

2010 0.077 4/14 0.073 4/12 0.071 8/10 0.071 8/8 1 (08-10 avg) 0.070

2011 0.080 6/7 0.074 7/7 0.073 6/30 0.072 9/3 1 (09-11 avg) 0.070

3 Year Average of 4th High

3 Year Average of 4th High
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Warrick County

Year 1st Date 2nd Date 3rd Date 4th Date Days => 0.076 ppm 3 Year Period Site Design Value

1995 0.104 0.089 0.088 0.087 7 (95 avg) 0.087

Yankeetown 1996 0.102 0.098 0.097 0.093 14 (95-96 avg) 0.090

18 173 0002 1997 0.095 8/1 0.094 7/18 0.091 7/12 0.091 8/2 7 (95-97 avg) 0.090

1998 0.119 9/13 0.113 9/12 0.099 5/14 0.096 5/18 10 (96-98 avg) 0.093

1999 0.101 9/5 0.098 9/4 0.096 6/22 0.095 8/12 5 (97-99 avg) 0.094

2000 0.081 7/26 0.080 7/9 0.077 7/27 0.077 8/15 0 (98-00 avg) 0.089

2001 0.087 6/12 0.082 6/18 0.081 6/19 0.081 9/13 1 (99-01 avg) 0.084

2002 0.113 7/8 0.097 8/9 0.094 6/21 0.094 9/6 17 (00-02 avg) 0.084

2003 0.101 6/24 0.090 7/17 0.082 6/7 0.082 8/27 2 (01-03 avg) 0.085

2004 0.075 8/18 0.074 4/29 0.074 6/30 0.074 8/3 0 (02-04 avg) 0.083

Site discontinued September 30, 2004

Warrick County

Year 1st Date 2nd Date 3rd Date 4th Date Days => 0.085 ppm 3 Year Period Site Design Value

1995 0.106 0.098 0.090 0.090 9 (95 avg) 0.090

Boonville 1996 0.094 0.093 0.090 0.090 10 (95-96 avg) 0.090

18 173 0008 1997 0.109 7/17 0.097 7/12 0.097 7/18 0.095 8/2 9 (95-97 avg) 0.091

1998 0.114 9/13 0.105 9/12 0.100 8/22 0.091 5/13 9 (96-98 avg) 0.092

1999 0.092 6/21 0.091 9/5 0.088 6/22 0.087 9/2 5 (97-99 avg) 0.091

2000 0.078 6/1 0.075 7/27 0.074 6/9 0.073 6/8 0 (98-00 avg) 0.083

2001 0.091 6/12 0.081 6/19 0.079 6/18 0.078 9/13 1 (99-01 avg) 0.079

2002 0.107 7/8 0.093 9/6 0.092 6/21 0.091 7/16 13 (00-02 avg) 0.080

2003 0.087 6/24 0.087 8/27 0.083 7/17 0.076 6/7 2 (01-03 avg) 0.081

2004 0.084 8/3 0.076 6/30 0.075 8/18 0.073 4/29 0 (02-04 avg) 0.080

2005 0.096 6/25 0.085 6/29 0.081 8/4 0.080 6/22 2 (03-05 avg) 0.076

2006 0.087 7/19 0.086 7/18 0.083 8/17 0.078 7/17 2 (04-06 avg) 0.077

2007 0.086 8/28 0.084 8/15 0.083 6/17 0.083 9/4 1 (05-07 avg) 0.080

Days => 0.076 ppm

 2008 0.073 8/20 0.072 7/29 0.072 7/16 0.071 7/18 0 (06-08 avg) 0.077

2009 0.071 6/25 0.066 6/2 0.066 5/20 0.064 7/9 0 (07-09 avg) 0.072

2010 0.077 8/2 0.076 8/8 0.072 4/13 0.071 6/3 2 (08-10 avg) 0.068

2011 0.089 7/1 0.085 6/7 0.076 8/1 0.075 7/2 3 (09-11 avg) 0.070

Warrick County

Year 1st Date 2nd Date 3rd Date 4th Date Days => 0.085 ppm 3 Year Period Site Design Value

2005 0.083 6/25 0.078 6/22 0.077 5/6 0.077 8/5 0 (2005 avg) 0.077

Dayville 2006 0.080 6/9 0.078 6/10 0.078 7/18 0.078 7/19 0 (05-06 avg) 0.077

18 173 0011 2007 0.078 6/13 0.078 8/28 0.077 6/16 0.076 6/12 0 (05-07 avg) 0.077

Days => 0.076 ppm

 2008 0.067 4/23 0.063 7/16 0.061 4/22 0.060 8/20 0 (06-08 avg) 0.071

2009 0.068 6/27 0.059 7/9 0.059 6/29 0.057 8/14 0 (07-09 avg) 0.064

2010 0.077 6/25 0.074 8/8 0.073 9/15 0.070 9/14 1 (08-10 avg) 0.062

2011 0.079 6/7 0.077 7/1 0.074 6/2 0.072 6/6 2 (09-11 avg) 0.066

3 Year Average of 4th High

3 Year Average of 4th High

3 Year Average of 4th High
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Rockport, Indiana T 147-30464-00060

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Regarding particulate, IDEM performed a modeling analysis for PM2.5 and showed IG is not culpable for 

any violations of the National Ambient Air Quality Standard (NAAQS). As explained in response to Sierra 

Club Comment 23, even though the model predicted a NAAQS violation, U.S. EPA guidance states that 

“the source will not be considered to cause or contribute to the violation if its own impact is not significant 

at any violating receptor at the time of each predicted violation.” U.S. EPA Workshop NSR Manual (Draft 

1990) at C.52. Because IG was not significant at the same receptor and time period, it does not cause or 

contribute to a violation of the NAAQS. The analysis and results of the evaluation of PM2.5 impacts can be 

found at pages 6-9 of 49 of the Air Quality Analysis for the permit. 

Modeling Comments:

Comment 39: It should be noted that the region in the air shed of this plant is already saturated with a 

variety of air pollutants and just recently met the 1997 standards for ambient air quality for 

both fine particles and ozone, an improvement Valley Watch would contend did not occur 

as a result of any Federally enforceable action to reduce, but instead the air quality 

improvement that occurred resulted from the reduced level of economic activity that 

accompanied the serious recession experienced since 2007. That recession saw a 

reduction of electrical generation across the board of approximately 25% from the years 

2007 through 2010. 

Interestingly, monitored data in 2011, a time of increased economic activity, showed 

increased levels of air pollutants across the board as more electricity was generated in 

the area. In fact, had new ozone and fine particle standards been implemented as EPA’s 

Scientific Advisors had recommended, the region would have been found in nonattainment of the National Ambient Air Quality Standards for both ozone and fine particles 

if 2011 was the only year considered.

That is important since the pollution released from the Indiana Gasification proposal 

would have had to be offset if the region was considered non-attainment. Since the Cross 

State Air Pollution Rule has now been deferred by the US Court of Appeals and there is 

no real certainty as to its ultimate fate and thus the reliance of both IDEM and EPA that 

the area will remain in attainment and there is no way that it can call any of the provisions 

for pollution reductions “Federally Enforceable.”

IDEM failed to look at this possibility in issuing a permit in an area that is depending on 

Warrick County

Year 1st Date 2nd Date 3rd Date 4th Date Days => 0.085 ppm 3 Year Period Site Design Value

1995 0.108 0.107 0.096 0.093 10 (95 avg) 0.093

Lynnville 1996 0.103 0.102 0.095 0.094 8 (95-96 avg) 0.093

18 173 0009 1997 0.108 7/17 0.097 7/18 0.095 8/1 0.094 7/12 10 (95-97 avg) 0.093

1998 0.109 9/13 0.098 9/12 0.095 8/17 0.093 8/21 9 (96-98 avg) 0.093

1999 0.098 6/21 0.096 9/5 0.094 9/2 0.092 6/22 11 (97-99 avg) 0.093

2000 0.080 6/1 0.079 6/8 0.078 7/27 0.077 6/9 0 (98-00 avg) 0.087

2001 0.087 6/12 0.077 6/18 0.076 9/13 0.075 6/10 1 (99-01 avg) 0.081

2002 0.094 9/6 0.091 6/21 0.091 7/15 0.090 7/16 12 (00-02 avg) 0.080

2003 0.089 6/24 0.086 8/27 0.082 7/17 0.078 6/29 2 (01-03 avg) 0.081

2004 0.070 4/16 0.066 4/29 0.066 8/18 0.066 9/23 0 (02-04 avg) 0.078

2005 0.082 6/25 0.078 8/9 0.077 6/29 0.076 7/23 0 (03-05 avg) 0.073

2006 0.076 6/9 0.074 7/19 0.074 8/17 0.070 6/17 0 (04-06 avg) 0.070

2007 0.084 7/3 0.084 8/3 0.081 6/16 0.080 5/21 0 (05-07 avg) 0.075

Days => 0.076 ppm

 2008 0.076 8/20 0.068 4/23 0.064 9/24 0.064 7/29 1 (06-08 avg) 0.071

2009 0.068 6/24 0.066 6/27 0.066 5/20 0.064 6/25 0 (07-09 avg) 0.069

2010 0.073 8/8 0.070 8/13 0.070 8/9 0.070 4/13 0 (08-10 avg) 0.066

2011 0.079 6/7 0.076 7/1 0.072 6/30 0.072 6/6 2 (09-11 avg) 0.068

3 Year Average of 4th High
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significant reductions of fine particle precursors in making their designation of the region 

as an attainment area. As a result, the analysis on which the re-designation was made is 

seriously flawed. Therefore, it is questionable whether this permit should have been 

treated as a PSD permit instead of an NSR permit, requiring offsets from existing 

polluters in order to construct a new major source.

Further, IDEM chose not to include any modeling of this plant’s impact on downwind 

ozone or fine particles to determine just how emissions from this plant would impact 

regions with chronic air pollution problem downwind both east and west.

Response 39: In July 2008, IDEM submitted a request for redesignation and a maintenance plan for fine 

particles for the Southwestern Indiana area. 

The Southwestern Indiana area has attained the annual NAAQS for fine particles. IDEM 

prepared a State Implementation and Maintenance Plan that meets the requirement of 

Section 110(a)(1) of the 1990 Clean Air Act.

Section 107 of the Clean Air Act (CAA) establishes specific requirements to be met in 

order for an area to be considered for redesignation, including:

(a) A determination that the area has attained the annual standard for fine particles. 

(b) An approved State Implementation Plan (SIP) for the area under Section 110(k).

(c) A determination that the improvement in air quality is due to permanent and 

enforceable reductions in emissions resulting from implementation of the SIP and 

other federal requirements.

(d) A fully approved maintenance plan under Section 175A.

(e) A determination that all Section 110 and Part D requirements have been met. 

Indiana has met all the above-requirements and has submitted an approved maintenance 

plan.

A maintenance plan provides for the continued attainment of the air quality standard by an 

area for a period of ten years after the U.S. EPA has formally redesignated the area to 

attainment. The plan also provides assurances that even if there is a subsequent 

exceedance of the air quality standard that measures in the maintenance plan will prevent 

any future occurrences through contingency measures that would be triggered. 

The redesignation requests for ozone and PM2.5 did not include reliance upon federal 

programs such as the Clean Air Interstate Rule (CAIR) to show continued attainment. In 

fact, the ozone redesignation request, dated June 2, 2005, page 25 stated specifically 

“U.S. EPA has modeled base case future years with existing emission controls only and 

shown that Warrick and Vanderburgh Counties will attain the 8-hour ozone NAAQS 

without proposed additional national emission control strategies.” At that time, CAIR had 

not yet been implemented. For the PM2.5 redesignation request, IDEM used modeling 

that included scenarios both with and without reductions from CAIR or the proposed 

Transport Rule. See Section 7.1, “REQUEST FOR REDESIGNATION AND 

MAINTENANCE PLAN UNDER THE ANNUAL NATIONAL AMBIENT AIR QUALITY 

STANDARD FOR FINE PARTICLES, Southwestern Indiana Area”, January 2011, page 

36. Indiana found that in either situation, “and the future year design values were 

determined without the emission reductions associated with CAIR”.

To read more about the redesignation and maintenance plan go to 

http://www.in.gov/idem/files/evv_fine_redesignation.doc.

Also, see the response to U.S. EPA Comment 1 for a description of the ozone analysis. 

See Response 44 under comments received by the public for a discussion of PM2.5. 
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Rockport, Indiana T 147-30464-00060

Permit Reviewer: Josiah Balogun

Comment 40: IDEM needs to model Particulate Emissions to show the effect of construction and 

operation of the plant. 

Response 40: IDEM has conducted the Air Quality Analysis in accordance with U.S. EPA and Indiana 

requirements. That analysis, which is included in the draft permit documentation, 

included an evaluation of PM10 and PM2.5. 

Comment 41: IDEM needs to model ozone. Ozone is a problem in Green and Clark Counties, we need 

modeling to see if it is a problem in Spencer County. 

Response 41: For a description of the ozone analysis, see the Response to U.S. EPA Comment 1.

Health Concern Comments

Comment 42: The calculated Potential to Emit of the emissions in this permit may be wildly inaccurate, 

posing serious potential harm to the public and the environment. As of January 2011, the 

EPA claimed only unpublished, laboratory confirmation of the use of surrogate emissions 

in determining coal combustion emissions; the only way to know the actual emissions is to 

constantly monitor each and every pollutant, and this permit does not require that. How, in 

light of the preceding, does this permit adequately protect the public health and 

environment from pollution? The data which is being presented by the Gasification 

proponents needs to be verified by research that is conducted by investigators who are 

absolutely independent. Is this permit doing the best job it can in preventing pollution?

Response 42: As an initial matter, this project does not combust any coal, and so IDEM has not used 

coal combustion emission factors. The coal and petroleum coke feedstocks are instead 

chemically converted through a fully enclosed gasification process. Gasification is a

process by which a solid fuel source is subjected to very high temperature and pressures 

to create a chemical reaction that leads to the creation of synthesis gas or “syngas”. The 

proposed IG facility will further clean and convert the produced syngas to create a 

substitute natural gas or “SNG.” 

The permit contains enforceable limits on the operation of sources and the emissions of 

sources that serve as the controlled potential to emit (“PTE”) for those units. For sources 

where the PTE is not subject to such a limit, IDEM estimated the PTE using the best 

available emission information, including emission factors collected by U.S. EPA and 

published under the AP-42, which is available at http://www.epa.gov/ttnchie1/ap42/ on the 

Internet. Other estimates underlying this permit are based on the company’s extensive 

knowledge of the processes that will be used, equipment vendor data and many years of 

experience with similar sources of emissions. For an explanation of why the BACT review

process promotes accurate development of emissions estimates, see the response to 

Public Comment 35. The bases for many of the emission factors used in this permitting 

action are explained in more detail in responses to other comments. See, for example, 

responses to Sierra Club Comments 28, 29, 31, 34, 36, 38, and 44. 

The permit contains emission limits that the source must meet. Each D section of the 

permit also contains a subsection with all the applicable compliance determination 

requirements, which show how the source will comply with its emission limits and 

standards. Each D section also sets out the applicable compliance monitoring, record 

keeping and reporting requirements that will create additional emission information to 

ensure that the process is always in compliance with its emission limits. In cases where 

the potential magnitude or variability of the emissions justifies it, the permit requires 

continuous pollutant emissions monitors and or stack testing.
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Comment 43: IDEM received a substantial number of comments regarding the health impact of the 

ambient air pollution levels in Spencer County, both now and what they will be after this 

source begins operation. These concerns included the many possible effects the 

emissions may have on them, such as human health effects, including increased cases of 

cancer and asthma. IDEM has set forth some of these comments verbatim below:

We are way too polluted now. Has anyone ever done a study on how much greater the 

cancer threat is here than in other places? I've read that we are the 16th most polluted 

county in the nation.

The people in Spencer County and the surrounding Counties have a tough decision to 

make concerning the many factors that weigh into this permit. Some of these factors 

include, increase medical problems such as asthma, premature death, cardiovascular 

disease and decrease lung function. 

As a resident of Rockport, I am very concerned about the added pollution a coal 

gasification plant will bring to our community. Approval of permit number 147-30464-

00060 would expose the residents to greater heath risks. Spencer County already is high 

on the pollution levels. It's not fair to our younger generation to have them grow up in an 

unhealthy environment. I am not willing to trade my grand children's well-being for 

economic growth. Please don't approve this permit. Let rural America breathe.

The city is already exposed 24/7 to toxic pollutants that are producing deteriorating effects 

on the health of our County people. The effect on the public health must be considered. 

Indiana Gasification’s emissions, when added to emissions from AEP Power Plant and 

AK Steel are an unnecessary and undesirable addition to air pollution load in Spencer 

County and surrounding counties. Cumulative load affects air quality and health.

My family members have cancer. People who live here their whole lives aren’t susceptible 

to cancer right away, while those who move to Spencer County get cancer in just a few 

years. I don’t think people realize how many people are dying in this county from cancer. 

This area has one of the highest cancer rates in the United States

Air Quality is important.

On site releases of toxics to air, water and land in Indiana according to TRI, increase 18 

percent in 2010. Carcinogen releases were up 16% with a 21% increase in 

Bioaccumulative toxics (BT).

According to scorecard.org, Spencer County has 26,507,023 pounds of chemicals 

released to the atmosphere. Vanderburgh County has 1,185,000. Spencer County is the 

top polluted county in Indiana. AK Steel emits 22,707, 000 and 812,000 according to 

scorecard.org, while the Rockport Power plant emits just 3,731,543.

Indiana is the worst state in the nation for chromium and nickel pollutants. 

Indiana is one of the worst states for chromium, nickel as well as arsenic, lead, mercury, 

selenium, and acid emissions.

We already have so many entities that are polluting the immediate area that it is hard to 

believe that they are considering another one?

I don’t want to live here if it gets so bad that you can’t breathe without getting a respiratory 

problem.
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Asthma: Children in Evansville are five times more likely to be hospitalized with Asthma 

than their counterpart in Fort Wayne.

Response 43: After the public comment period IDEM performed further information gathering and 

analyses. A screening analysis was conducted for air toxics in Spencer County, Indiana. 

This screening was performed to help address questions and concerns that the public 

raised during a public meeting pertaining to the permitting of the Indiana Gasification 

facility. The review consisted of reviewing current heath information, reviewing the existing

2005 National Air Toxics Assessment (NATA) (released in early 2011), and performing air 

dispersion modeling for major sources in the area. 

The analysis shows that there is no increased asthma or cancer incidence in Spencer 

County and that the county is rated as one of the best in the state for low chronic illness. 

The 2005 National Air Toxics Assessment (NATA) showed that air toxics emissions and 

estimated concentrations in Spencer County are below State and National averages. Air 

dispersion modeling indicates that cancer risk and non-cancer hazard are below or within 

the expected risk range and that a majority of the risk from toxics would fall on the 

property of major sources, not in areas where the public lives or would have access. 

Current Health Information – Asthma and Cancer rates

Review of the current data available to the ISDH and IDEM demonstrated that residents in Spencer County 

have not been at increased risk for exacerbation of asthma (measured by emergency department and 

hospitalization encounters). Table 1 shows the age adjusted rate for asthma and the state ranking for that 

rate. Figure 1 shows the ranking of each county in Indiana for age-adjusted emergency department visits 

for Asthma in 2009.

Table 1 - Age-adjusted Emergency Department (ED) and Inpatient (IP) Asthma-related Encounter 

Rates and Ranks, Spencer County, 2006–2010 

Age-adjusted 

Rate~

Rank in State 

(Out of 92; lower is 

better)

SPENCER CO ASTHMA-RELATED 

EMERGENCY DEPARTMENT VISITS* 46.2 15

SPENCER CO ASTHMA-RELATED 

INPATIENT ADMITS* 17.0 7

*Based on ICD-9 code of 493 (asthma) within first three diagnoses codes

~Age-adjusted rate per 10,000 population

Source: Indiana Hospital Association’s Hospital Discharge Database Figure 1 is a map generated for the 

2011 Burden of Asthma in Indiana Report (http://www.in.gov/isdh/files/BR_Asthma_5-11-11gw.pdf). This 

map depicts asthma-related emergency department rates based on patients having a primary diagnosis of 

asthma. Spencer County is in the “white” zone, showing that it had a rate during 2009 that was in the 

lowest (best) quartile in the state. 

Figure 1 – Age-Adjusted Asthma Emergency Department Visits in Indiana 2009
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Source: Indiana Hospital Association’s Hospital Discharge Database 

Table 2 below shows the cancer rate compared to the rest of Indiana for overall and receptor specific 

cancers. Spencer County is not at an increased risk for cancer incidents. In fact, Spencer County’s overall 

age-adjusted cancer incidence rate (425.3 cases per 100,000 people) during 2004–2008 was statistically 

lower than the Indiana rate (475.6 cases per 100,000 people). There were no increased statistical 

differences between Spencer County’s rates and the state’s rates for the leading cancer types (Table 2).
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Table 2. Cancer Incidence Rates, Indiana and Spencer County, 2004–2008*

All Cancers

Prostate

(Male-only disease) Female Breast Lung Colon and Rectum

County Count Rate* Count Rate* Count Rate* Count Rate* Count Rate*

Spencer 493 425.3 ↓ 59 104.1 62 104 84 71.2 69 60.2

Indiana 154,990 475.6 19,770 136 20,511 116 25,914 80 16,739 51.4

*Rates are per 100,000 people and age-adjusted to the 2000 U.S. Standard Population

†“↑↓” symbols denote whether the county’s rate is significantly different than the Indiana rate based on the 95% 

confidence interval overlap method (see Page 4 for description). Because of limitations of this method, some of the counties 

without ↑↓ symbols could still have significantly different rates than the state.

“x” Rate and comparison to state rate is suppressed if fewer than 20 cases occurred because rate is considered unstable. 

Source: Indiana State Cancer Registry (http://www.in.gov/isdh/24360.htm) 

National Air Toxics Assessment

The United States Environmental Protection Agency (U.S. EPA) conducted the most recent National Air 

Toxics Assessment (NATA) in 2005. The NATA is a large scale evaluation of air toxics that examines 

many sources of air toxics. The evaluation looks at not only major sources of air toxics, such as factories, 

but also emissions from vehicles, small sources, and background air toxics. The NATA estimates what 

level of pollution people will be exposed to and the potential risk of developing health effects over a life 

time (70 years) when breathing those toxics. The NATA reports risk estimates based on the average 

concentrations over a census tract. There are five census tracts in Spencer County and 1,412 census 

tracts in the State of Indiana. The NATA looks at both cancer and non-cancer health effects. 

For cancer risk, the highest tract in Spencer County was ranked 979th in the state of Indiana. The highest 

cancer risk for that census tract from major sources in the NATA was 0.67 excess cancer cases in a 

million people. That means that if one million people inhaled the same air for 24 hours a day, 7 days a 

week, 52 weeks a year for 70 years, there would be at most 0.67 extra cancer cases per million people. 

The average for Spencer County from point sources is 0.48. This is well below the average calculated for 

Indiana of 2.2 and the national average of 1.6. When considering the risk from all sources, including 

background, Spencer County’s risk is estimated at 2.9 excess cancer cases per million people. This is 

also less than the Indiana average of 3.6 and the national average of 5.0 excess cancer cases per million 

people. 

For non-cancer hazard, NATA calculated respiratory and neurological hazards. This screening analysis 

combined the two different health endpoints to get one non-cancer hazard quotient which is an extremely 

health protective approach. For all census tracts in Spencer County the non-cancer hazard was less than 

1. The highest tract was 0.76. For non-cancer hazards any result of less than 1 indicates that adverse 

health effects from the pollutant are extremely unlikely to occur.

http://www.epa.gov/ttn/atw/nata2005/tables.html

Air Toxics Emissions 

Emissions estimates used in the Spencer County air toxics analyses were based on 2008 information for 

the three major sources in Spencer County. These sources are: AEP-Rockport, AK Steel Corporation and 

American Iron Oxide Company. These emission estimates were based on reported fuel process rates, 

EPA emission factors and existing control equipment. The 2008 inventory estimates were then updated 

with 2010 state reported and Toxic Release Inventory data where possible. These emissions were 

combined for each source to come up with a combined source air toxic total. For the screening analysis, 

the emissions were estimated at 1,259.1 tons. 1,239 tons of the total emissions were from AEP-Rockport. 
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For the 2005 NATA there were a total of 5,221 tons of air toxics in Spencer County, with hydrochloric acid 

estimated at 4,582 tons. Indiana’s 2010 inventory for emissions is more current and takes into account 

recent control equipment installation at the AEP-Rockport facility. 

Air Toxics Dispersion Modeling Evaluation 

An AERMOD modeling analysis was conducted using existing modeling parameters for the four major 

point sources in Spencer County (the three large existing facilities mentioned above and the new 

proposed Indiana Gasification facility). Indiana Gasification parameters were based on available 

technological information and permit application data. The other three major sources’ stack locations and 

release parameters were retrieved from the IDEM modeling database and analyzed at the emissions point 

level. Only these major point sources were considered for this analysis. The AERMOD run used 

meteorological data from Evansville, Indiana surface station and mixing heights from the Peoria, IL upper 

air station. The data was preprocessed minute by minute for 2006-2010. Terrain data was factored in for 

all sources and receptors. Building data was available for Indiana Gasification and the downwash for 

those buildings were used in the analysis. The screening analysis contained 1804 receptors in a 20 km by 

20 km grid around the Indiana Gasification facility. Boundary data for Indiana Gasification was available 

and no receptors were placed on that source’s property. Boundary data was not used for the other 

sources and receptors were located on their properties. 

The annual estimated concentration for 2006 to 2010 was averaged into a single concentration for each 

receptor. For each facility, the estimated concentration for each air toxic was calculated based on the 

source’s modeled impact and the estimated emissions. The concentration was then used to calculate 

cancer risk and non-cancer hazards for each source. The cancer Unit Risk Factor (URF) and non-cancer 

Reference Concentration (RfC) were taken from the most recent version of U.S. EPA’s Chronic doseresponse Table 1 (http://www.epa.gov/ttn/atw/toxsource/summary.html). 

The highest modeled cancer risk based on the receptor grid was 1.2 excess cancer cases in a million. 

This was the only receptor over one in a million. The average for all the receptors was 0.15 excess cancer 

cases. Indiana Gasification highest excess cancer case receptor was 0.006. The average cancer risk for 

Indiana Gasification over all receptors was 0.0026 excess cancer cases. The pollutants driving the risk 

were arsenic, chromium VI, methylhydrazine, and formaldehyde. U.S. EPA uses a range between one in a 

million to one hundred in a million excess cancer cases when evaluating whether the estimated risk is at a 

level where action should be taken. Generally, U.S. EPA considers risk estimates over one hundred in a 

million to be at levels where action or more investigation is required. Risks that fall between one in a 

million and 100 in a million level generate decisions and actions taking into account the assumptions used 

to determine the estimate. Risk estimates below one in a million are usually considered as not requiring 

further action. 

For non-cancer hazard quotient, the highest receptor in the study area is 0.21. Non-cancer drivers were 

hydrogen sulfide, acrolein, hydrochloric acid, manganese, cadmium and arsenic. A non-cancer hazard 

quotient under 1.0 is commonly recognized to be health-protective. Hazard quotients over 1.0 indicate that 

further investigation may be necessary but does not necessarily mean that health effects are expected. 

The average for the study area was 0.025. For Indiana Gasification, the highest receptor hazard quotient 

was 0.21 and the average was 0.02. These are health protective scenarios and are very likely to be 

greater than the actual non-cancer hazard quotient.

Comment 44: Several commenters expressed concerns over the effect of the source's emissions on 

wildlife, water, farm ground, and crop yield and the quality of life.

Response 44: The permit documents include an Additional Impact Analysis in which IDEM concluded 

that “the operation of the facility will have no significant impact on economic growth, soils,

vegetation, or visibility in the immediate vicinity or on any Class I area (see Air Quality 

Analysis, pp. 12-13 of 49). 

The federal Clean Air Act requires the U.S. EPA to set National Ambient Air Quality 
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Standards (NAAQS) for six criteria pollutants. These standards are set by U.S. EPA at 

levels that protect human health, including the health of sensitive persons, such as 

asthmatics, children and the elderly. The NAAQS are often referred to as the federal 

health standards for outdoor air. The secondary NAAQS standards provide public 

welfare protection, including protection against decreased visibility and damage to 

animals, crops, vegetation, and buildings. Spencer County is currently in attainment 

status for all criteria pollutants.

More information about these pollutants is available at www.epa.gov/air/airpollutants.html

on U.S. EPA’s website. The complete table of the NAAQS can be found at the 

www.epa.gov/air/criteria.html website. Detailed information about the effects of these 

common pollutants is available at www.epa.gov/air/urbanair/. IDEM conducts sampling of 

the ambient air at monitoring stations around Indiana. This air monitoring is conducted to 

measure whether the NAAQS are being met. Information about Indiana’s air monitoring 

system and monitoring results is available at www.idem.IN.gov/4116.htm. Information 

about current and expected air pollution levels throughout Indiana is on IDEM’s 

SmogWatch site at www.smogwatch.IN.gov on the Internet.

IDEM’s Office of Water Quality (OWQ) manages waste water permitting. If the source 

needs a water permit it will have to apply to OWQ. Information about water permitting is 

available at http://www.in.gov/idem/4869.htm on the Internet.

Comment 45: One commenter was concerned over the effect of increased truck traffic on area roads.

Response 45: The permit includes air quality-related requirements that apply to fugitive dust emissions 

from plant roadways. IDEM has no authority to consider the effect of increased truck 

traffic on public area roads. Issues of traffic safety are left to local government agencies 

that set and enforce traffic controls.

Fugitive Emission Comments

Comment 46: IDEM barely addressed the very real issue of fugitive emissions from the plant except to 

require dubious Best Management Practices for operation and maintenance of this 

experimental plant. The problem is that converting coal into other hydrocarbons creates 

waste streams that are known to be extremely acidic and caustic as the coal is refined. 

Those high and low Ph wastes are known to quickly consume the many seals that are 

part of such a sophisticated chemical conversion that is required to gasify coal. Usually 

Best Management Practice is the accepted way to deal with keeping fugitive emissions 

from escaping a plant. However, this plant has other obstacles that might well keep these 

emissions from being adequately kept in check. 

Response 46: The water quench system in the gasifier readily captures and dilutes the acid compounds 

formed when the coal and coke are gasified. This water is then removed from the gasifier 

and managed as a conventional wastewater stream. Later in the process, sulfur 

compounds that remain in the syngas are intentionally converted to sulfuric acid which is 

a useful product that will be sold for commercial use. As noted in response to public 

comment 23, the LDAR provisions of this permit, where appropriate are required for

piping and components with the potential to leak air pollution. As such, leaks of any origin 

will be detected and addressed through maintenance and repair requirements of the 

permit. It should be noted that sulfuric acid is used commonly in manufacturing and there 

is extensive experience in the specification of metallurgy and the selection of materials for 

components and piping that are resistant to acid corrosion.
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Global Warming Comments:

Comment 47: Global warming is a significant event that will have many dangerous, deadly and costly 

impacts. The use of syngas as a fuel produces more CO2 thus, providing a second dose 

of potential effect on global weather patterns.

Response 47: In response to concerns over climate change, U.S. EPA promulgated new regulations 

under the PSD program requiring facilities that emit greenhouse gases (GHG) above 

certain thresholds to apply Best Available Control Technology (BACT) to GHG emissions. 

IDEM has applied these regulatory requirements in this permit, as set out in the GHG 

BACT analysis in the draft permit documents. BACT requirements have been applied to 

the syngas flare, which is the only emission point at the facility where syngas is combusted,

and to fugitive emissions of syngas. Syngas is not used as a fuel at the facility. 

General Comments:

Comment 48: How is the coal to be gasified? Is this a proven technique and industrial technology, with 

known, demonstrated, and measured emissions? How does this differ from processes 

used to produce utility gas or city gas at or about the year 1900? Where can be found 

reports of emissions from operating industrial scale coal gasification plants?

Response 48: A brief description of the gasification process is summarized in the applicant’s permit 

application page 2-1 which explains that gasification is the process by which a solid fuel 

source is subjected to very high temperature and pressures to create a chemical reaction 

that leads to the creation of synthesis gas or “syngas”. The proposed IG facility further 

cleans and converts the produced syngas to create a substitute natural gas or “SNG.”

The modern gasification process is different than the turn of the century “city gas” 

generation process, which was used to thermally and destructively distill gases from coal 

for use as a gaseous fuel. The modern gasification process is a proven technology with a 

number of US and world wide applications. The following five plants are operating in the 

United States today:

• Wabash River in Indiana for power generation, 

• Tampa Electric Polk Power in Florida for power generation, 

• Great Plains Synfuels in North Dakota making SNG, 

• Eastman Chemicals in Tennessee making chemicals, and 

• Coffeyville Resources in Kansas making fertilizer.

In the permit review of best available control technologies (BACT), each emissions unit 

was compared to the most relevant recent permitting of a similar emission unit. For the 

equipment unique to gasification facilities, comparisons were made in the BACT analysis 

to recently proposed and permitted facilities such as the Duke Edwardsport IGCC in 

Indiana, Power Holdings SNG plant in Illinois, Lake Charles Cogeneration in Louisiana, 

and Cash Creek Generation in Kentucky. These gasification facilities have not yet begun 

operation, but they have all been permitted within the last 5 years and their proposed limits 

represent an appropriate comparison in establishing expectations for the IG facility. 

Discussion of the required emissions performance of these proposed similar facilities are 

presented in the BACT section of the TSD document beginning on page 638.
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Comment 49: IDEM did not address the overall economics of the facility. Indiana Gasification is bound 

by a contract with the State of Indiana (which obviously creates a distinct conflict of 

interest in IDEM granting this permit) that requires it to sell its output to the State of 

Indiana for a price that is considerably higher than the price of its primary competitor, 

natural gas. Because the price is higher but not really high enough to adequately cover 

their cost of production, there will be tremendous pressure on the operator to keep 

operating and maintenance cost to a minimum. As a result, those pressures will impact 

the operator’s ability to adequately implement Best Management Practices designed to 

hold down fugitive emissions. 

Plant should be put in a county with a lower level of air pollution. We want a tourist based 

economy.

Natural gas supplies are plentiful, this plant is not needed. Electric rates will go up.

Coal is the bane of economic development.

Government should not be loaning money to company. State law will make residents pay 

a premium for natural gas.

Response 49: IDEM is not authorized by Indiana law to consider the economics of an industry or 

economic planning when issuing an air permit decision. 

Comment 50: The significant budget cuts at IDEM have resulted in IDEM having an increasingly poor 

inspection record for facilities like this and it is clear that the conditions for sometimes 

high levels of fugitive emissions that would go unchecked until the next, infrequent IDEM 

inspection, might take place. If that happened and those emissions were added to the 

existing level of toxic emissions in the immediate vicinity, a dangerously toxic situation 

could rapidly develop and IDEM would be in the dark until their next inspection.

Response 50: IDEM monitors the levels of harmful emissions in the ambient air at locations around 

Indiana. The monitoring results from these stations are available at 

http://www.in.gov/idem/4652.htm on the Internet. In addition, IDEM projects daily ambient 

air concentrations, based on current weather patterns, at its SmogWatch site at

http://www.in.gov/apps/idem/smog/ on IDEM’s website.

Under this permit, IG will have an obligation to submit quarterly deviation reports reporting 

any deviations from the requirements of the permit. Not doing so can result in IDEM 

bringing an enforcement action. Separate from inspections, IDEM will receive test 

reports and emissions information that will allow IDEM to determine when violations have 

occurred. 

IDEM response time to violations depends on the severity of the reported violation. IDEM 

responds to all reports of violations. Responses to violations vary depending on the 

severity of the violation and can be a warning letter, a fine or even criminal prosecution. 

IDEM has sufficient compliance inspectors. IDEM has inspection tools and practices to 

determine noncompliance, even if a source is not reporting deviations. 

IDEM will enforce the permit as issued. IDEM will review the severity of any violation 

and the source’s history of violations in determining what enforcement action is 

necessary and what are appropriate penalties.

IDEM inspects sources like IG on the average of once per year. IDEM will make more 

frequent inspections if the source has a history of violations or is the subject of complaints 

from the public. Any person may report any suspected violation by contacting IDEM. You 

can file a complaint with IDEM three different ways:

1. Submit a complaint online at http://www.in.gov/idem/5275.htm on IDEM’s 
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website,

2. Call the Complaint Coordinator toll free at (800) 451-6027 ext. 24464, or

3. Print, complete, and mail a paper-based Complaint Submission Form (now 

available on the IDEM Forms page at http://www.in.gov/idem/5157.htm#agency

IDEM handles all inspection, compliance and enforcement issues on a case-by-case 

basis. The current air inspector for this area is:

Inspector Name: Andrea Alltop

Phone No: 812-380-2315

Email Address: aalltop@idem.in.gov

Address: IDEM, Southwest Regional Office, P.O. Box, 1120 N. Vincennes 

Avenue, Petersburg, Indiana 47567.

Comment 51: I beg you not to issue the noted Air Permit for Indiana Gasification. This project is an 

example of the misuse of the powers of government to 1) harm the environment, 2) 

hasten the depletion of a natural resource, and 3) impose a rate increase on residential 

Indiana rate-payers to the benefit powerful corporations.

Response 51: Detailed information providing an evaluation of the environmental impact of the source is 

included in the draft permit documentation, and IDEM has determined that the source, as 

permitted, meets the requirements of the Prevention of Significant Deterioration and other 

Clean Air Act programs. IDEM has no authority to consider concerns over rate increases 

when issuing a decision for an air permit.

Comment 52: The people in Spencer County and the surrounding Counties have a tough decision to 

make concerning the many factors that weigh into this permit. Some of these factors 

include increase medical problems such as autism.

Response 52: IDEM has set out information and analysis regarding air pollution and health in response 

to Comment 43, above. The source’s permit reflects all of the applicable air pollution 

controls and limitations for its emission equipment. The Center for Disease Control is 

studying autism. More information about those studies, including a summary of last year’s 

workshop with Autism Speaks, is available at 

http://www.cdc.gov/ncbddd/autism/index.html on the internet.

Comment 53: The area in which Indiana Gasification is proposing to build the synthetic gasification plant 

is in the 100 year flood plane of south Spencer County. Not only is all of the area in the 

flood plane but there are also natural wetlands within the area. We oppose the building of 

this project for many reasons; among them is the fact that the construction of this plant, in 

this location, would cause future flood waters to adversely affect other properties. 

Response 53: The applicable air permitting laws and rules do not address floodway or wetlands issues. 

The Indiana Department of Natural Resources-Division of Water, (317) 232-4160, 

water_inquiry@dnr.IN.gov has jurisdiction over construction in the floodway. If applicable, 

the owners of the proposed gasification plan would need to go through the Construction in 

the Floodway permitting process. 

If applicable, the applicant would be required to obtain proper permits for proposed 

wetland impacts. Specifically, the IDEM-Section 401 Wetlands program requires

applicants to obtain a State certification for jurisdictional impacts. In addition, an applicant 

would be required to obtain a Section 404 permit from the US Army Corps of Engineers 

for wetland impacts. Finally, the IDNR-Division of Water also regulates wetlands and has 

similar requirements. However, its jurisdiction would only fall within the floodway. 
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Comment 54: The President rejected to build a pipeline to carry oil from Canada to Texas. Why would 

he approve this pipeline for CO2?

Response 54: There are a number of interstate permits in the US that support the transport of fuels and 

products such as CO2. In fact, there are a number of CO2 pipelines already permitted and 

in place. IDEM does not have authority over interstate pipeline approvals and cannot 

address that process in the context of this permit review. IDEM can and will enforce the 

emissions limits in the permit. If the pipeline is not constructed the source may have to 

apply to IDEM to revise its limits on carbon dioxide emissions. If that occurs there will be a 

new public notice process and a new opportunity for the public to comment on any 

proposed permit changes to the Best Achievable Control Technology requirements for 

Green House Gases (GHG BACT).

Comment 55: What is the current status concerning the clean air permits for the coal gasification plant 

being proposed for Spencer County?

Response 55: IDEM has now issued the final permit decision, as set out in the Notice of Decision 

document.

Comment 56: Big Plains Gasification Project in North Dakota: Why is there no TRI data available for this 

plant?

Response 56: IDEM has not been able to locate a source named “Big Plains Gasification” in North 

Dakota. The North Dakota Department of Health, which handles air permits in North 

Dakota, can be contacted at 701-328-5188 or contact Lew Dendy at NDDH at 

ldendy@nd.gov by e-mail.

Comment 57: IDEM needs to assess and limit pollution, not just rubber stamp the application. This is a 

done deal by politicians in the coal industry to show us who is in control of the power 

structure of the State of Indiana. The Governor is enamored of clean coal. When was the 

last time IDEM denied an application or modified one?

Response 57: IDEM’s air permit process determines the air permit regulations that apply to each 

emission unit at a source and the source overall, using information in the application 

materials. If an applicant has provided adequate information to allow IDEM to determine 

the applicable air quality regulations and draft a permit with appropriate requirements, 

IDEM is required to draft and issue the permit. In applying the applicable regulations to the 

permitting process, IDEM very often requires controls or requirements beyond what was 

initially proposed by the applicant. When a source determines that it cannot go forward 

with a project due to the emission limitations or other condition in a draft air permit, it may 

withdraw its application. 

Using information in IG’s permit application and supplemental materials, IDEM drafted the 

proposed permit documents for public notice and comment. The public has commented on 

the proposed permit, including specific comments on permit conditions and permit 

limitations. IDEM has responded to those comments in this Addendum, making changes 

to permit terms as necessary.

Comment 58: Syngas could be used in cars, have other good effects but this project is not a good thing. 

We should use wind, solar and mass transportation. We should focus on Renewable 

Energy. 

Response 58: Determining national or state energy policies, relative to such things as power generation 

and mass transit, is not within the scope of the IDEM review. IDEM has no authority to 

direct the focus of energy generation or use.
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Comment 59: No one commented on FESOP 087-27799-03302 which has 3,850 tons of emissions and 

is 4000 feet from this proposed plant.

Response 59: The amount of public comment on an air permit for another plant does not affect IDEM’s 

consideration of the public comments on this plant.

Comment 60: What will the effect of sequestration be on our local area?

Response 60: There is no provision for sequestration in this permit. Carbon Capture and Sequestration 

was evaluated but it was determined to be technically infeasible for this project. Therefore 

the source will not be required to perform sequestration.

Comment 61: What effect will transportation of coal by rail and barge have on community?

Response 61: IDEM is not authorized to consider the effect of rail or barge traffic moving through the 

community outside of the source’s property. The permit review addresses the air 

emissions associated with coal and coke handling at the facility and imposes Best 

Available Control Technology requirements to minimize emissions associated with those 

handling activities at the site.

Comment 62: Surface Mining’s destructive practices will increase. Mining releases methane, a GHG.

Response 62: IDEM is not authorized to consider the effect of mining activities that may increase as a 

result of issuing the permit.

Comment 63: Jobs are not worth pollution.

Response 63: IDEM is not authorized to consider the number of jobs that may be created by a source 

when issuing an air pollution permit. 

In support of the Project

Comment 64: In support of the Project:

(a) I believe this permit should be approved. A few local and a large number of out of 

town (and state for that matter) have voiced some concerns about this permit and 

this plant in general, mainly because of the word coal. I have a copy of IDEM 

permit #147-29070-03302 for a asphault plant that is located at 1021 N. ST. RD. 

66 Rockport, IN. That permit had an allowable emission rate of 385 tons per year 

for a ten year period. To my knowledge not a single comment against that permit 

was submitted. Now why would a group of people be against one source of 

pollution and not another that emits more? I believe IDEM did an outstanding job 

on this draft and should approve it as soon as possible.

(b) The Clean Air Task Force (CATF) support IDEM’s inclusion of a greenhouse gas 

best available control technology (“BACT”) emission limit for the acid gas removal 

(“AGR”) system at the facility as mandated under both the Clean Air Act and 

State of Indiana requirements, also we support IG’s efforts to further the use of 

CCS technology in achieving this limit. The Project stands to be an important 

step towards more widespread use of CCS generally, and in the central US in 

particular, especially through development of a CO2 pipeline to injection sites in 

the Gulf Coast states and we support the selection of a phased-in limit for CO2

over the initial three years of the facility’s operation. 
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(c) The Coal conveyor system will be enclosed with dust collectors, therefore the 

fugitive dust will not be a problem. I am in support of the project.

(d) Toxic and carcinogen releases in Indiana have gone down, therefore I am in 

support of the project.

(e) Mercury release rate is decreasing in Indiana, therefore I am in support of the 

project.

(f) This plant will have lowest mercury emissions of any coal plant operating in 

Indiana.

(g) Rockport Power plant will scrub its emissions, maybe as soon as 2013.Therefore 

I am in support of the plant.

(h) Permit should be granted because CO2 is going to be captured. 

(i) This will be cleanest coal plant in the world.

(j) I appreciate IDEM and what they are trying to do for Spencer County.

(k) I support this permit and the project

(l) This is good public policy, Ind. Reg. Comm. Approved. 

(m) Oil Recovery use of captured CO2 will reduce dependence on foreign oil. I am in 

support of the project.

(n) We need jobs so that people can pay their bills and to support our local tax base. 

I am in support of the project.

Response 64: IDEM acknowledges that these comments are important to the commenters. However, 

these comments do not have any direct impact on how IDEM reviews and make decisions 

on air permit applications.

SIERRA Club Comments

Modeling Comments

Comment 1: IDEM FAILED TO FOLLOW THE REQUIRED PUBLIC PARTICIPATION 

REQUIREMENTS

IDEM did not follow the required public participation procedures. IDEM made some of the 

AERMOD files available at the public library but not all of them. In particular, the SO2 and 

NOx modeling files were not available at the public library. We went to the public library 

and obtained 4 computer disks which we were told were all of the computer disks 

available. These contained PM2.5 and PM10 modeling but not the SO2 and NOx files. 

There was one excel file submitted under a September 29, 2011 cover letter but this only 

had some of the inputs listed and we do not even know if the inputs in the spreadsheet 

were the inputs actually used in the modeling. This is particularly problematic because as 

explained below, the SO2 and NOx modeling claims to have predicted impacts very close 

to the significant impact level and contained numerous flaws. Therefore, IDEM should 

hold make these computer files available at the public library and then hold a new public 

comment period. 
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Response 1: A copy of the permit application was placed at the Spencer County Public Library 

within ten days after the application was filed with IDEM. IDEM placed all the draft 

permit documents at the library and also made them available at IDEM’s offices and 

on IDEM’s website. IDEM is not aware of the specific records request referenced in 

this comment, but the Library staff on February 8, 2012 also confirmed that these files, 

on a DVD, are available at the Library. IDEM is not aware of the commenter having 

contacted IDEM in order to obtain the modeling files at any time during this permitting 

action. No revisions to the draft permit are required as a result of this comment.

In addition, IDEM has no specific information to indicate Indiana Gasification, LLC 

did not comply with the public notification requirements. If specific evidence was 

provided to IDEM of a failure to comply with the requirements of 326 IAC 2-7-17(b) 

or 326 IAC 2-1.1-6 prior to issuance, IDEM would consider this information in its 

permit decision. 

Comment 2: IDEM IMPROPERLY USED A SIL

To begin with, the 1-hour SO2 SIL is not in Indiana’s SIP. Therefore, IDEM cannot rely on 

it to issue a Title V permit. Furthermore, IDEM has offered nothing in the record to 

support the use of a SIL in general or a 7.80 ug/m3 1-hour SO2. Thus, IDEM cannot rely 

on this SIL. 

Response 2: Under the PSD program a new major source or major modification must complete an air 

quality analysis to demonstrate compliance with the National Ambient Air Quality 

Standards (NAAQS). This analysis involves several steps and U.S. EPA has provided a 

screening tool known as the Significant Impact Level (SIL). The use of SILs are rooted in 

the de minimis exception observed in Alabama Power v. Costle, 636 F.2d 323, 360 (D.C. 

Cir. 1979). Historically, “EPA has allowed the use of several types of screening tools to 

facilitate implementation of the preconstruction review process to reduce the permit 

applicant’s burden and streamline the permitting process for de minimis circumstances. 

These tools include ...SILs....” 75 Fed. Reg. 64,864, 64,866 (Oct. 20, 2010) (final rule 

establishing SILs for PM2.5). SILs are used to determine whether emissions from a 

proposed major new stationary source or modification will have a “significant” impact on 

air quality in the area. If an individual source projects an increase in air quality impacts 

less than the corresponding SIL, its impact is considered to be de minimis and the permit 

applicant would not be required to perform a more comprehensive, cumulative modeling 

analysis. A cumulative analysis involves measuring the impact of the new source in 

addition to impacts from other existing sources in the area. If a cumulative modeling 

analysis indicates a violation of the NAAQS, the SILs may also be used to determine 

whether the proposed source's impact on a modeled violation is significant enough that it 

is considered to “cause or contribute to” the modeled violation of the NAAQS or 

increment.

For the 1-hour SO2 and the 1-hour NO2 standards, U.S. EPA provided an interim SIL. 

The interim SIL for SO2 is 3 ppb (7.86 μg/m3

). See Memorandum from Anna Marie 

Wood, Acting Director, U.S. EPA Air Quality Policy Division, to Regional Air Division 

Directors, “Guidance Concerning the Implementation of the 1-hour SO2 NAAQS for the 

Prevention of Significant Deterioration Program,” at 6 (Aug. 23, 2010) (“SO2 SIL 

Guidance”). U.S. EPA derived this value by using an impact equal to 4% of the 1-hour 

SO2 NAAQS. Id. at 6. In so doing, U.S. EPA explained that it believes it is reasonable to 

base the interim 1-hour SIL directly on consideration of impacts relative to the 

corresponding 1-hour NAAQS. Id. See response to Sierra Club Comment 16 for 

additional discussion of considerations in setting an appropriate de minimis level. U.S. 

EPA stated that it was making the SIL “available to States with EPA-approved 

implementation plans containing a PSD program to use at their discretion.” Id. at 5. 
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IDEM agrees with U.S. EPA’s basis for this interim SIL value of 3 ppb, and the SIL was 

implemented in accordance with the SO2 SIL Guidance. Thus, although the SIL for SO2

is not incorporated into Indiana’s SIP, it does not need to be in order for IDEM to utilize 

this screening tool.

Consistent with U.S. EPA’s guidance, IDEM used the maximum 1st highest 1-hour 

concentration averaged over 5 years for comparison to the 1-hour SO2 SIL of 3 ppb (7.86 

μg/m3

).

Comment 3: Also, even if the use of the SIL was permissible, IDEM averaged five years of impacts and 

compared the average to the SIL. The proper analysis would be whether any one year 

exceeded the SIL. While, as explained above, we do not have the modeling files because 

IDEM failed to make them available at the library, we believe, based on the average being 

so close to the SIL, that at least one year was above the SIL. Therefore, a cumulative 

impact analysis is required followed by an additional public comment period.

Response 3: IDEM modeled SO2 in accordance with U.S. EPA guidance. See Memorandum from Anna 

Marie Wood, Acting Director, U.S. EPA Air Quality Policy Division, to Regional Air Division 

Directors, “Guidance Concerning the Implementation of the 1-hour SO2 NAAQS for the 

Prevention of Significant Deterioration Program,” at 6 (August 23, 2010) (“SO2 SIL 

Guidance”). Specifically, the SO2 SIL Guidance provides:

[W]e are providing an interim 1-hour SO2 SIL value of 3 ppb to implement the federal 

PSD program. To determine initially whether a proposed project’s emission increase will 

have a significant impact (resulting in the need for a cumulative air quality analysis), this 

interim SIL should be compared to either the following:

• The highest of the 5-year averages of the maximum modeled 1-hour SO2

concentrations predicted each year at each receptor, based on 5 years of 

National Weather Service data; or

• The highest modeled 1-hour SO2 concentration predicted across all receptors

based on 1 year of site-specific meteorological data, or the highest of the multiyear averages of the maximum modeled 1-hour SO2 concentrations predicted 

each year at each receptor, based on 2 or more, up to 5 complete years of 

available site-specific meteorological data.

Id. (emphasis added). Because representative nearby National Weather Service data 

was available, IG used the first option listed above rather than collect 1 year of sitespecific meterological data. Consistent with this guidance, IDEM used the maximum 1st

highest 1-hour concentration at each receptor averaged over 5 years for comparison to 

the 1-hour SO2 SIL of 3 ppb (7.86 μg/m3

). 

Comment 4: THE MODELING USES IMPROPER EMISSION RATES

IDEM claims that the maximum emissions from the syngas flare startup, EU 001, is 0.70 

lb/hr. TSD App A, pdf page 400, 491. IDEM claims the maximum emissions from 

shutdown flaring is 255.62 lb/event which IDEM coverts to 85.21 lb/hr. TSD at pdf page 

492. IDEM provides no information on where it obtained these figures. The BACT limit is 

0.35 lb/hr (3 hr ave) startup on sulfur free fuel, 85.21 lb/hr (3 hr ave) for shut down. TSD 

at pdf page 646. In contrast, the Illinois Environmental Protection Agency’s (“IEPA”) draft 

Construction Permit (“Draft Permit”), ID No. 021060ACB, for Christian County Generation 

LLC’s proposed Taylorville Energy Center (“TEC”) states that its highest SO2 emissions 

from its flare during startup is 9,036 lb/hr. AAF has a limit of 9510 lb/SSM event. TSD at 

pdf page 646. Duke Energy Edwardsport has a limit of 1396.7 lb/hr during peak of startup 
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and this facility is approximately half the size of IG, that is 5000 T per day versus IG’s 

10,400 T per day. TSD at pdf page 646. 

Response 4: The disparity for these limits for startups is based on the kind of fuel used for start up. 

Christian County Generation LLC’s proposed Taylorville Energy Center and Duke Energy 

Edwardsport use coal as a start up fuel. IG uses methanol for its start up fuel. Methanol 

combustion has very little SO2 emissions as compared to coal. IG has committed to using 

methanol as a start up fuel which gives lower lb/hr values for SO2. 

IG has also committed to slightly lower shutdown SO2 emissions limits than these other 

facilities. This is due to IG’s plan to initially depressure shutdown gasification process 

equipment through the wet sulfuric acid (WSA) plant to recover the sulfur rather than vent 

all vessel depressuration gases to the flare. 

See Conditions D.2.4(3) and D.2.9.

Comment 5: The SO2 modeling fails to consider SO2 emissions when the flares are doing what they 

are designed to do, flare products, except the modeling does consider the hydrocarbon 

flare during startup on methanol. See spreadsheet submitted to IDEM under a 

September 29, 2011 cover letter, SO2 tab. The modeling must model SO2 impacts when 

the flares are flaring substances during upsets or malfunctions, which again, is how they 

are designed to do, so it is a completely reasonable worst case scenario. 

Response 5: The federal Prevention of Significant Deterioration (PSD) and Nonattainment New Source 

Review (NNSR) pre-construction permitting programs are two of the major ways that EPA 

and the states can regulate air quality. New major sources and major modifications to 

sources must be properly permitted under the PSD or NNSR program.

The startup and shutdown emissions for this facility have been calculated and included in 

the facility PTE, permit limits, and air dispersion modeling. The hydrocarbon flare is the 

only emissions point that has higher emissions during startup or shutdown than in normal 

operation – for the hydrocarbon flare, normal operation is operation with the pilot flame. 

For the criteria pollutants besides SO2, startups represent the operating scenario resulting 

in the highest flared emissions. This comes from the use of the flare to control/combust 

vented syngas generated by the starting up gasifier before it reaches sufficient pressure 

to be routed to downstream processing. However, SO2 emission from startup flaring is 

relatively small because the facility will be permitted to startup on methanol, which is 

essentially sulfur free. Instead, the maximum flare SO2 emissions are from shutdown 

flaring. Although the gasification processes can be stopped without any flaring, a small 

amount of flaring will be needed to depressurize the equipment to allow it to be taken out 

of service for maintenance. Prior to depressurization, this shutdown equipment will 

contain coal/coke generated syngas which will have some sulfur content. As a result, as 

this gas is vented to the flare following a shutdown, SO2 will be generated. Again, the 

modeling analysis for SO2 included shutdown flaring.

No other facility equipment would require flaring due to startup or shutdown, or have 

higher emissions during such a period versus their normal emissions. Besides the 

gasifiers, the other facility equipment is designed and expected to startup, shutdown, and 

be maintained without requiring flaring or any excess emissions. 

United States v. Louisiana-Pacific Corp., 682 F. Supp. 1141, 1158 (D. Colo. 1988) 

establishes that PTE includes only emissions that occur during normal operations:

Any analysis of the definition of “potential to emit” must include a reference to the 

case of Alabama Power Co. v. Costle, 204 U.S. App. D.C. 51, 636 F.2d 323 

(D.C.Cir. 1979) because the current definition above was promulgated in 
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response to the D.C. Circuit’s holding in that case. . . .

The broad holding of Alabama Power is that potential to emit does not refer to the 

maximum emissions that can be generated by a source hypothesizing the worst 

conceivable operation. Rather, the concept contemplates the maximum 

emissions that can be generated while operating the source as it is intended to be 

operated and as it is normally operated. . . . Alabama Power stands for the 

proposition that hypothesizing the worst possible emissions from the worst 

possible operation is the wrong way to calculate potential to emit.

Louisiana-Pacific, 682 F. Supp. at 1157-58. Malfunction emissions are the result of 

events beyond the control of the owner/operator and are not reflective of a source 

operating under its physical or operational design. See 326 IAC 1-2-39 (Malfunction 

is“[a]ny sudden, unavoidable failure of any air pollution control equipment, process, or 

combustion or process equipment to operate in a normal and usual manner.”)

Malfunctions do not represent the way the facility is intended to operate or the way it will 

normally operate. The Commenter suggests that malfunction emissions should be 

included in modeling because the flares are “doing what they are designed to do.” 

However, a flare is a safety device that is not an independent operation from the process 

it serves. The facility has been designed in such a way as to prevent the need for flaring 

in normal operation, outside of startups and shutdowns, to minimize the possibility of 

malfunction flaring, and to minimize the amount of emissions that must be flared when 

flaring does occur. The permit contains limits on startup and shutdown flaring as well as 

several other requirements that apply to all flaring events, including malfunctions. 

However, not every possible scenario can be covered in a design. Malfunction of 

equipment requiring use of the flare may still happen. The flare is the control and not an 

independent operation, and it is not appropriate to include malfunction emissions in 

modeling merely because the malfunction emissions pass through a flare. 

EPA’s Guideline on Air Quality Models found in Appendix W to 40 C.F.R. Part 51, fully 

supports the view that malfunctions are not considered to be part of normal operating 

conditions for purposes of modeling a source’s potential impact. The Guideline explains 

that “the source should be modeled using the design capacity . . . .” 40 C.F.R. Part 51, 

Appendix W, Sec. 8.1.2. The Guidelines further provide: “Malfunctions which may result 

in excess emissions are not considered to be a normal operating condition. They 

generally should not be considered in determining allowable emissions.” 40 C.F.R. Part 

51, Appendix W, Sec. 8.1.2 fn.a. 

More recent EPA modeling guidance supports the approach adopted by EPA in the 

Guidelines. In connection with modeling for the 1-hour NO2 NAAQS, EPA recommends 

that the reviewing authority may consider operating scenarios that are relatively 

continuous and may exclude certain types of intermittent emissions. See March 1, 2011 

Memorandum from Tyler Fox, Leader, EPA Air Modeling Group at 2. 

Malfunction events that may result in excess emissions are not reflective of the source 

operating as designed. Accordingly, IDEM was not required to include such events in its 

modeling calculations.

Comment 6: Similarly, the TSD acknowledges that during an upset, acid gases can be routed to the 

acid gas flare. TSD at pdf page 403, 494. However, the emission rates used for ambient 

impacts analysis as well as for PTE completely ignored emissions when acid gases are 

routed to the acid gas flare. Id. Thus, not only is the ambient impacts analysis for SO2 

inadequate, the ambient impact analysis for NOx, PM10, PM2.5 and the synthetic minor 

HAPs determination are also invalid. 
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Response 6: The Acid Gas Flare is used only for relief protection during upsets or malfunctions of the 

Wet Sulfuric Acid (WSA) plant. See Response 5 under the Sierra Club comments 

regarding consideration of upsets and malfunctions in calculating PTE and modeling 

impacts. 

Comment 7: The draft permit contains no emission limits for the flares during upsets or malfunctions. 

Therefore, the potential to emit (PTE) must be used in the modeling. The SO2 PTE is 400 

tons per hour of coal * 3.66% S coal * 64/32 = 29.28 tons per hour SO2. Assuming that 

all the sulfur is converted into SO2 is appropriate because IDEM admits that “SO2 

emissions are merely a function of the amount of sulfur compounds in the gases vented 

to the flare and are unrelated to flare design.” TSD at pdf page 645. 

Response 7: See Response 5 under the Sierra Club comments regarding consideration of upsets and 

malfunctions in calculating PTE and modeling impacts. Also, regarding permit limits, the 

draft permit contains several operating requirements regarding flare minimization and flare 

best practices which are applicable at all times, including upsets and malfunctions. 

Comment 8: As to emissions during shutdown, the PTE used in modeling is based on assumption of 

only 15 shutdowns using the flare per year. However, there is no permit requirement 

limiting IG to 15 shutdowns per year. Therefore, the PTE is actually 373.2 based on 8760 

hours per year. 

Response 8: See Response to U.S. EPA Comment 6.

Comment 9: In addition, the draft permit does not contain any enforceable 1-hour averaging time 

emission limits for any other emission units. Therefore, the modeling must use 1-hour 

averaging time PTE. In the SO2 modeling, according to the shreadsheet submitted to 

IDEM under a September 29, 2011 cover letter, the modeling used a SO2 emission rate of 

0.00009 lb/hr for the emergency diesel engines in the normal operations with engines 

scenario, 0.005 in the normal operations / black start combo and 0.0006 in the normal ops

combo scenario. The modeling appears to have included no emissions from the engines 

for the worst case black start combo scenario. We do not know where these emission 

rates came from and do not know why different values where used in the three scenarios 

with emission rates. IDEM needs to explain why three different values were used and 

also explain why the black start combo scenario assumes no emissions but the normal 

operations / black start combo includes emissions from the diesel engines. However, 

IDEM lists the permitted PTE of the emergency generator diesel engines as 0.015 lb/hr. 

TSD at pdf page 427, 363. Thus, the modeling must use 0.015 lb/hr in all scenarios.

The same is true for the firewater diesel pumps. In the SO2 modeling, according to the 

shreadsheet submitted to IDEM under a September 29, 2011 cover letter, the modeling 

used a SO2 emission rate of 0.00004 lb/hr for one scenario, 0.002 for another, 0.00025 

for a third and no emissions for the “worst case black start” scenario. We do not know 

where these values came from, why different values were used in different scenarios and 

why no emissions were assumed for the “worst case black start” scenario. However, 

IDEM lists the permitted PTE of the firewater diesel pumps as 0.0061 lb/hr. TSD at pdf 

page 431, 363. Thus, the modeling must use 0.0061 lb/hr in all scenarios.

Response 9: The emissions rates listed by the commenter are for emergency generators and 

emergency fire water pumps which will only be operated in non-emergency use for 

readiness testing and maintenance. This will occur for 1 hour per week for each engine, 

and is limited by permit condition D.9.4 (e) which restricts each engine’s operation to 52 

hours per year of non-emergency operation. Because these sources operate 

intermittently and only briefly, their emissions rates for modeling purposes vary depending 
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on the averaging time of the standard being modeled: 

• Modeling for a 3 hr standard assumed each engine was tested for 1 hr resulting 

in an average emissions rate for the period 1/3rd the single hourly emission rate (1 

hr of emissions divided by 3 hours of the standard). 

• Modeling for a 24 hr standard used 1/24th the single hourly emissions rate.

• Annual modeling emissions rate assumed 52 hours of operations divided by 8760 

hrs per year.

Regarding startups, no emergency engine testing was assumed for modeling scenarios 

covering only startups. Therefore, permit condition D.9.5 prohibits testing of these units 

during startups. However, for some pollutant modeling runs, IG modeled the combined 

worse case emissions of multiple operating modes to help limit the total number of 

modeling runs needed. For example, for modeling scenarios such as “normal 

operations/black start” emissions rates for emergency engines were included as part of 

normal operations, although they were excluded in a modeling run that only addresses 

startup.

The 1 hour NAAQS modeling (SO2 and NOx) was treated slightly differently than the 

other averaging periods and according to guidance in a U.S. EPA OAQPS March 1, 2011 

memorandum from Tyler Fox (“Additional Clarification Regarding Application of Appendix 

W Modeling Guidance for the 1-hour NO2 National Ambient Air Quality Standard”). The 

memorandum provides additional clarification regarding application of Appendix W 

modeling which applies to both NO2 and SO2 1-hour standards. The memo addresses 

emission scenarios concerning intermittent emissions from emergency generators or 

startup/shutdown operations. Page 8 of the memo starts the discussion on the 

“Treatment of Intermittent Emissions”. Below are some excerpts from that memo:

Page 8 -

EPA’s guidance in Table 8-2 of Appendix W involves a degree of conservatism in 

the modeling assumptions for demonstrating compliance with the NAAQS by 

recommending the use of maximum allowable emissions, which represents 

emission levels that the facility could, and might reasonably be expected to, 

achieve if a PSD permit is granted. However, the intermittent nature of the actual 

emissions associated with emergency generators and startup/shutdown in many 

cases, when coupled with the probabilistic form of the standard, could result in 

modeled impacts being significantly higher than actual impacts would realistically 

be expected to be for these emission scenarios. The potential overestimation in 

these cases results from the implicit assumption that worst-case emissions will 

coincide with worst-case meteorological conditions based on the specific hours 

on specific days of each of the years associated with the modeled design value 

based on the form of the hourly standard. In fact, the probabilistic form of the 

standard is explicitly intended to provide a more stable metric for characterizing 

ambient air quality levels by mitigating the impact that outliers in the distribution 

might have on the design value. The February 9, 2010, preamble to the rule 

promulgating the new 1-hour NO2 standard stated that “it is desirable from a 

public health perspective to have a form that is reasonably stable and insulated 

from the impacts of extreme meteorological events.” 75 FR 6492. Also, the Clean 

Air Science Advisory Committee (CASAC) “recommended a 98th-percentile form 

averaged over 3 years for such a standard, given the potential for instability in the 

higher percentile concentrations around major roadways.” 75 FR 6493.
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Page 9 -

Given the implications of the probabilistic form of the 1-hour NO2 NAAQS 

discussed above, we are concerned that assuming continuous operations for 

intermittent emissions would effectively impose an additional level of stringency 

beyond that intended by the level of the standard itself. As a result, we feel that it 

would be inappropriate to implement the 1-hour NO2 standard in such a manner 

and recommend that compliance demonstrations for the 1-hour NO2 NAAQS be 

based on emission scenarios that can logically be assumed to be relatively 

continuous or which occur frequently enough to contribute significantly to the 

annual distribution of daily maximum 1-hour concentrations. EPA believes that 

existing modeling guidelines provide sufficient discretion for reviewing authorities 

to exclude certain types of intermittent emissions from compliance 

demonstrations for the 1-hour NO2 standard under these circumstances.

Page 11 –

Another approach that may be considered in cases where there is more 

uncertainty regarding the applicability of this guidance would be to model impacts 

from intermittent emissions based on an average hourly rate, rather than the 

maximum hourly emission. For example, if a proposed permit includes a limit of 

500 hours/year or less for an emergency generator, a modeling analysis could be 

based on assuming continuous operation at the average hourly rate, i.e., the 

maximum hourly rate times 500/8760. This approach would account for potential 

worst-case meteorological conditions associated with emergency generator 

emissions by assuming continuous operation, while use of the average hourly 

emission represents a simple approach to account for the probability of the 

emergency generator actually operating for a given hour. Also note that the 

contribution of intermittent emissions to annual impacts should continue to be 

addressed as in the past to demonstrate compliance with the annual NO2

standard.

Memorandum from Tyler Fox, Leader, EPA Air Quality Modeling Group, to Regional Air 

Division Directors, “Additional Clarification Regarding Application of Appendix W Modeling 

Guidance for the 1-hour NO2 National Ambient Air Quality Standard” (March 1, 2011). 

Thus, consistent with the guidance outlined above, for emergency engines permitted with 

an operating limit of 52 hours per year, the 1-hr SO2 and NOx modeling used an average 

annual emissions rate (ie: 52 hrs of emissions divided by 8760 hrs/year).

Comment 10: Furthermore, the PTE and emissions used for the annual averaging time modeling for the 

emergency diesel generators and firewater pumps is limited to 52 hours based on the 

permit condition limiting these emission units to 52 hours of non-emergency operations 

per year. However, there is no exemption to PSD prohibition on violations of NAAQS to 

“emergency.” This is because air pollution is very dangerous and even deadly so IG’s 

understanding of an emergency does not permit it to release pollution that can injury or 

even kill innocent people. Thus, unless the permit contains a permit condition that 

absolutely limits operations of the emergency diesel generators and fire water pumps, the

modeling has to be based on 8760 hours per year rather than 52 hours per year. 

Response 10: The emergency diesel generators and firewater pumps will only be in operation on an 

intermittent basis. The March 01, 2011, Tyler Fox, U.S. EPA memorandum addresses 

this issue. See Response 9 under Sierra Club comments. In addition, U.S. EPA has 

offered guidance on how to calculate PTE for emergency generators used to provide 

back-up power when electric power from the local utility is interrupted. See Sept. 6, 1995 

Memorandum from John S. Seitz, Director, Office of Air Quality Planning and Standards 
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on Calculating Potential to Emit (PTE) for Emergency Generators at 2-3. 

Among other things, the Seitz Memo explains that “EPA has determined that a 

reasonable and realistic “worst-case” estimate of the number of hours that power would 

be expected to be unavailable from the local utility may be considered in identifying the 

“maximum capacity” of such generators for the purpose of estimating such generators 

PTE. Consequently, EPA does not recommend the use of 8760 hours per year (i.e., fullyear operation) for calculating the PTE for emergency generators. Instead, EPA 

recommends that the potential to emit be determined based upon an estimate of the 

maximum amount of hours the generator could operate, taking into account (1) the 

number of hours power would be expected to be unavailable and (2) the number of hours 

for maintenance activities.” Seitz Memo at 3. EPA’s guidance provides for estimates 

“made on a case-by-case basis where justified by the source owner or permitting authority 

(for example, if historical data on local power outages indicate that a larger or smaller 

number would be appropriate).” Id. Thus, EPA’s guidance makes it clear that Sierra Club 

is incorrect to suggest that the PTE for the IG emergency generators “be based on 8760 

hours per year.”

Here, 52 hours is considered a reasonable and realistic worse-case assumption. This 

allows for weekly maintenance and readiness testing of the each of these emergency 

engines. Regarding the emergency generators, given the specifics of this project, it is not 

necessary to additionally include any expected hours of predicted power interruption. 

This is because IG’s power will come from its own steam turbine power generation. In the 

event of loss of IG’s steam turbine, power can be supplied by the external power grid. In 

the event of loss of the external power grid, IG can run independently on the steam 

turbine generator. The emergency diesel generators will only be needed in the extremely 

unlikely double contingency emergency where IG loses both power sources at the same 

time. Regarding the emergency fire water pumps, outside of readiness/maintenance 

testing, these also will only be operated in the extremely unlikely event of a fire. Such an 

event is not expected and should not be considered in estimating reasonable and realistic 

facility PTE.

Comment 12: The September 29, 2011 spreadsheet also indicates that the wrong stack parameters 

may have been used in the modeling for the normal operations of the hydrocarbon flare. 

Again, we cannot be certain because we do not have the modeling. The spreadsheet 

indicates that the modeling used the stack height and stack diameter of the acid gas flare, 

that is 215 ft and 0.30 ft respectively, for the hydrocarbon flare during normal operations 

(pilot) when the actual stack height and stack diameter should be 292 ft and 16.89 ft. In 

addition, the spreadsheet claims that the temperature and exit velocity for the 

hydrocarbon flare are the same whether it is just burning natural gas in the pilot or burning 

methanol during gasifier start-up. This does not seem physically possible. Therefore, 

these values must be corrected if they are wrong in all of the modeling for all of the 

pollutants, the modeling re-run and a new public comment period held. 

Response 12: The spreadsheet does indicate the hydrocarbon flare does have the same stack height 

and stack diameter as the acid gas flare during normal operations. The differences occur 

during different operating modes for the flares. Flares are different than normal stacks in 

that their pollutants are not released from a contained stack, but rather are emitted from 

the top of an open flame which is external to, and on top of, the flare stack. For flares, the

emissions plume starts above the flame. Therefore, to properly account for this in the 

modeling, an effective stack height representing the top of the flame should be used in 

the model. Also, when the plume develops above the flame it may have a significantly 

different diameter than the actual flare stack diameter. Therefore, an effective diameter is 

estimated and input into the model. 

There is a procedure U.S. EPA has published in the SCREEN 3 Model User’s Guide (U.S. 
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EPA OAQPS, September 1995) to calculate effective stack parameters. The SCREEN 

model, and its methodology, calculates effective release height and effective release 

diameter based on the total heat release of the flared gases. These calculations 

(explained further in IG’s application beginning on page 6-5) result in larger flaring heat 

releases with larger stack tip flames being modeled with correspondingly larger effective 

stack heights and diameters than flares in “normal” pilot mode. 

These effective stack parameters and the resulting buoyancy flux estimate are expected 

to give reasonable final plume rise estimates for flares. 

Comment 13: IDEM IMPROPERLY FAILED TO CONDUCT AN AMBIENT IMPACT ANALYSIS FOR 

OZONE

The Clean Air Act requires that new major sources of pollution demonstrate that they will 

not cause or contribute to a violation of any ambient air quality standard. The current 

ambient air quality standard for ozone is 75 parts per billion. Ozone causes a variety of 

adverse impacts including asthma attacks and decreased yields of crops such as corn 

and soybeans. 

Response 13: See response to U.S. EPA Comment 1.

Comment 14: IG and IDEM made no attempt to establish whether the proposed IG facility will cause or 

contribute to a violation of the ozone ambient air quality standard. There are no ozone 

monitors in Spenser County and IDEM failed to require IG to conduct pre-construction 

ozone monitoring so we do not know how bad the ozone problem is even before adding in 

IG’s addition pollution. However, what we do know is that Clark County’s ozone level for 

2009-2011 is 75.3 parts per billion. See Ex. 1, 2, and 3. Thus, Clark County is already 

exceeding the ozone ambient air quality standard before we adding in pollution from 

Indiana Gasification. IG will surely contribute to this problem. The monitor in New Albany 

at the Green Valley Elementary School was at 80 parts per billion, well above the 75 parts 

per billion standard, in 2011. See Ex. 3. Scientific research has shown that children are 

especially susceptible to injury from ozone pollution because their lungs are still 

developing and they are generally more activity outside than adults. The monitor in 

Greene County had a three year average in 2009-2011 of 74 parts per billion. See Ex. 1,

2, and 3. Though just barely below the ambient standard, Indiana Gasification and IDEM 

did not use a computer model to see if the pollution from Indiana Gasification would send 

Greene County over the limit. IDEM started operating a new monitor in Knox County at 

the Southwest Purdue Agricultural Center in Vincennes in 2011. It monitored at 77 parts 

per billion, above the 75 parts per billion standard. The monitor in Perry County had a 

reading of 74 parts per billion in 2011, again just barely below the standard. On the other 

hand, Posey County had a reading of 76, Boonville High School in Warrick County had a 

reading of 75, and Evansville had a reading of 77 parts per billion in 2011, exceeding the 

standard. 

Before IDEM allows additional ozone forming pollution that can cause asthma attacks, 

decreased crop yields and other problems, they should require Indiana Gasification to use 

a state of the art computer model such as CAMx to establish that the additional pollution 

from Indiana Gasification will not cause or contribute to violation of the ozone ambient air 

quality standard.

Response 14: See Response to U.S. EPA Comment 1 and Response 38 under comments received by 

the Public.

Comment 15: IDEM claims that VOCs are below the significant emission rate. TSD pdf page 812. 

However, NO2 is also an ozone precursor. IG is over the 100 TPY significant level for 

NO2. Therefore an ambient impact analysis is required for ozone. 
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IDEM claims:

An air quality analysis is not performed for VOCs because they are 

photochemically reactive. Photochemical models like UAM-V are used in 

regulatory or policy assessments to simulate the impacts from all sources by 

estimating pollutant concentrations and deposition of both inert and chemically 

reactive pollutants over large spatial scales. Currently, U.S. EPA has no 

regulatory photochemical models which can take into account small spatial scales 

or single source PSD modeling for ozone. AERMOD is not a photochemical 

model.

This is not true. To begin with, at a minimum, Appendix W requires that IDEM consult 

with EPA and obtain EPA’s approval of the modeling approach to addressing ozone. 

Furthermore, it is now clear that there are models that are capable of modeling a PSD 

source’s impact to ozone. This is demonstrated in Sierra Club’s Petition for Rulemaking 

to Designate Air Quality Models to use for PSD Permit Applications with Regard to Ozone 

and PM2.5, the December 8, 2011 letter providing additional documents which support the 

petition, and US EPA’s January 4, 2012 response to the petition. We are providing you 

with these documents which we hereby incorporate herein by reference.

Response 15: See response to U.S. EPA Comment 1. Also, in reading the January 4, 2012 U.S. EPA 

response letter cited by the Commenter, it is not “...now clear that there are models that 

are capable of modeling a source’s impact to ozone.” In its review of U.S. EPA’s 

response letter, IDEM was unable to find any information regarding a model with this 

capability. What this letter actually says, on pages 2 and 3, follows: 

“However, recent advances in photochemical modeling science suggest that it may now 

be reasonable for the EPA to provide more specific, generally-applicable guidelines that 

identify particular analytical techniques or models that may be used under specific 

circumstances for assessing the impacts of an individual source on ozone concentrations 

and on the secondary formation of PM2.5. These advances have resulted in some 

methods that may allow for tracking the formation and transport of ozone and secondary 

PM2.5 impacts from specific emissions sources and calculating the contribution of sources 

and precursors to ozone and PM2.5 at individual receptor locations. In fact, the EPA 

engaged the modeling community on these developments at the 9th Conference on Air 

Quality Modeling in October 2008 by devoting a session to photochemical modeling with 

instrumented techniques such as "source apportionment" to promote understanding of 

their emerging capabilities by the regulatory modeling community. 

“The EPA has scheduled the 10th Conference on Air Quality Modeling for March 13-15, 

2012, in Research Triangle Park, North Carolina. We intend to issue the Federal Register 

notice announcing the conference in early 2012 which will outline the agenda with the 

topic of chemistry models and related techniques for addressing impacts of ozone and 

secondary PM2.5 being a major session and focus of the EPA's efforts to engage the 

regulatory modeling community. 

This modeling conference will serve as the initial venue for gaining public input to begin 

the rulemaking process of updating Appendix W. As was the case in promulgating new 

dispersion models (CALPUFF and AERMOD) in 2003 and 2005, the EPA expects to form 

a similar workgroup to conduct the necessary evaluations and inter-comparisons of 

technical approaches and models to inform the rulemaking process and provide sufficient 

technical justification for those technical approaches and/or models that are ultimately 

determined to be appropriate for incorporation into Appendix W. 
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This workgroup will be critical in informing the rulemaking process, and the reports and 

other findings will be made publicly available and be central to discussion at future 

modeling conferences. Consistent with the past practice described earlier, the EPA 

expects such discussion to occur at the 11 th Conference on Air Quality Modeling with 

consideration of the specifics of the EPA's proposed rule to update Appendix W. 

“Furthermore, as this complex rulemaking process proceeds, the EPA will be taking 

additional steps in the interim to enhance understanding of acceptable techniques for 

evaluating impacts of individual source emissions on ozone concentrations and 

secondary PM2.5 formation.”

(Emphasis added). In summary, IDEM did use output from a regional model to perform 

the ozone analysis (see response to U.S. EPA Comment 1). However, it is clear from the 

above paragraphs, that while there may be some methods available to track formation, 

these techniques have not yet been evaluated or finalized and no models exist for this 

purpose. The above states that the March 2012 10th Conference on Air Quality Modeling 

will serve as the initial venue to begin the process of updating Appendix W. While it 

would be desirable to have a model available now for this purpose, it will be years before 

such a model will be available.

Comment 16: THE NOx AMBIENT IMPACTS ANALYSIS WAS INADEQUATE

The TSD claims that the modeling demonstrated that IG has a modeled impact of 7.4 

ug/m3 which is below the significant impact level (SIL) of 7.55 ug/m3 for the 1-hour NOx 

NAAQS. TSD at pdf page 814. Thus, the TSD claims that a cumulative NOx analysis is 

not required. This is incorrect.

Response 16: For the reasons discussed in response to Sierra Club Comment 2 with respect to SO2, 

the NOx ambient impacts analysis was appropriate and correct. 

For the 1-hour SO2 and 1-hour NO2 standards, U.S. EPA provided an interim SIL. The 

interim SIL for NO2 is 4 ppb (7.55 μg/m3

). See Memorandum from Anna Marie Wood, 

Acting Director, U.S. EPA Air Quality Policy Division, to Regional Air Division Directors, 

“General Guidance for Implementing the 1-hour NO2 National Ambient Air Quality 

Standard in Prevention of Significant Deterioration Permits, Including an Interim 1-hour

NO2 Significant Impact Level” (June 28, 2010) (“NO2 SIL Guidance”); see also

Memorandum from Tyler Fox, Leader, U.S. EPA Air Quality Modeling Group, to Regional 

Air Division Directors, “Additional Clarification Regarding Application of Appendix W 

Modeling Guidance for the 1-hour NO2 National Ambient Air Quality Standard” (March 1, 

2011). 

U.S. EPA explained the basis for this SIL value: 
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We derived this interim 1-hour NO2 SIL by using an impact equal to 4% 

of the 1-hour NO2 NAAQS (which is 100 ppb). We have chosen this 

approach because we believe it is reasonable to base the interim 1-hour 

NO2 SIL directly on consideration of impacts relative to the 1-hour NO2

NAAQS. In 1980, we defined SER for each pollutant subject to PSD. For 

PM and SO2, we defined the SER as the emissions rate that resulted in 

an ambient impact equal to 4% of the applicable short-term NAAQS. The 

1980 analysis focused on levels no higher than 5% of the primary 

standard because of concerns that higher levels were found to result in 

unreasonably large amounts of increment being consumed by a single 

source. Within the range of impacts analyzed, we considered two factors 

that had an important influence on the choice of de minimis emissions 

levels: (1) cumulative effect on increment consumption of multiple 

sources in an area, each making the maximum de minimis emissions 

increase; and (2) the projected consequence of a given de minimis level 

on administrative burden. 

As explained in the preamble to the 1980 rulemaking and the supporting 

documentation, EPA decided to use 4% of the 24-hour primary NAAQS 

for PM and SO2 to define the significant emissions rates (SERs) for those

pollutants. It was noted that, at the time, only an annual NO2 NAAQS 

existed. Thus, for reasons explained in the 1980 preamble, to define the 

SER for NOx emissions we used a design value of 2% of the annual NO2

NAAQS. Looking now at a short-term NAAQS for NO2, we believe that it 

is reasonable as an interim approach to use a SIL value that represents 

4% of the 1-hour NO2 NAAQS.

NO2 SIL Guidance at 12-13 (internal citations omitted). The SIL was made available to 

States with U.S. EPA-approved implementation plans containing a PSD program to use at 

their discretion. NO2 SIL Guidance at 10 (“EPA intends to implement the interim 1-hour 

NO2 SIL contained herein under the federal PSD program and offers states the 

opportunity to use it in their PSD programs if they choose to do so.”). IDEM agrees with 

U.S. EPA’s basis for this interim SIL value of 4 ppb, and the SIL was implemented in 

accordance with the NO2 SIL Guidance. Thus, although the SIL for NO2 is not 

incorporated into Indiana’s SIP, it does not need to be in order for IDEM to utilize this 

screening tool. 

Consistent with U.S. EPA’s guidance, IDEM used the maximum 1st highest 1-hour 

concentration averaged over 5 years for comparison to the 1-hour NO2 SIL of 4 ppb (7.55 

μg/m3

). 

Comment 17: To begin with, the SIL is not in Indiana’s SIP. Therefore, IDEM cannot rely on it to issue a 

Title V permit. Furthermore, IDEM has offered nothing in the record to support the use of 

a SIL in generally or a 7.55 ug/m3 1-hour SO2. Thus, IDEM cannot rely on this SIL. 

Response 17: Assuming the commenter is referring to the use of a 7.55 ug/m3 1-hour NO2 SIL, this issue 

is addressed in the response to Sierra Club Comment 16. See the response to Sierra 

Club comment 2 for a justification of the 1-hour SO2 SIL.

Comment 18: Also, even if the SIL was permissible, IDEM averaged five years of impacts and 

compared the average to the SIL. The proper analysis would be where any one year 

exceeded the SIL. While, as explained above, we do not have the modeling files because 

IDEM failed to make them available at the library, we believe, based on the average being 

so close to the SIL, that at least one year was above the SIL. Therefore, a cumulative 

impact analysis is required followed by an additional public comment period. 
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Response 18: For the same reasons discussed in response to Sierra Club Comment 2 with respect to 

SO2, the NOx ambient impacts analysis was appropriate and correct. IDEM modeled NO2

in accordance with U.S. EPA guidance. See Memorandum from Anna Marie Wood, Acting 

Director, U.S. EPA Air Quality Policy Division, to Regional Air Division Directors, “General 

Guidance for Implementing the 1-hour NO2 National Ambient Air Quality Standard in 

Prevention of Significant Deterioration Permits, Including an Interim 1-hour NO2 Significant 

Impact Level” (June 28, 2010) (“NO2 SIL Guidance”); Memorandum from Tyler Fox, 

Leader, U.S. EPA Air Quality Modeling Group, to Regional Air Division Directors, 

“Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1-

hour NO2 National Ambient Air Quality Standard” (March 1, 2011). Specifically, the NO2

SIL Guidance provides:

In this guidance, EPA recommends an interim 1-hour NO2 SIL value of 4 ppb. To 

determine initially whether a proposed project’s emissions increase will have a significant 

impact (resulting in the need for a cumulative air quality analysis), this interim SIL should 

be compared to either of the following:

• The highest of the 5-year averages of the maximum modeled 1-hour NO2

concentrations predicted each year at each receptor, based on 5 years of 

National Weather Service data; or

• The highest modeled 1-hour NO2 concentration predicted across all receptors 

based on 1 year of site-specific meteorological data, or the highest of the multiyear averages of the maximum modeled 1-hour NO2 concentrations predicted 

each year at each receptor, based on 2 or more, up to 5 complete years of 

available site-specific meteorological data.

NO2 SIL Guidance at 12 (emphasis added). Because representative nearby National 

Weather Service data was available, IG used the first option listed above rather than 

collect 1 year of site-specific meterological data. Following this guidance, IDEM used the 

maximum 1st highest 1-hour concentration at each receptor averaged over 5 years for 

comparison to the 1-hour NO2 SIL of 4 ppb (7.55 μg/m3

). 

Comment 19: In addition, the draft permit does not contain any enforceable 1-hour averaging time 

emission limits. Therefore, the modeling must use 1-hour averaging time PTE. In the 

NOx modeling, according to the spreadsheet submitted to IDEM under a September 29, 

2011 cover letter, the modeling used an NOx emission rate of 0.09 lb/hr for the 

emergency diesel engines. We do not know where this value came from. However, 

IDEM lists the permitted PTE of the emergency diesel engines as 14.58 lb/hr. TSD at pdf 

page 427, 363. Thus, the modeling must use 14.58 lb/hr rather than 0.09 lb/hr.

The same is true for the firewater diesel pumps. In the NOx modeling, according to the 

spreadsheet submitted to IDEM under a September 29, 2011 cover letter, the modeling 

used a NOx emission rate of 0.02 lb/hr for the emergency diesel engines. We do not 

know where this value came from. However, IDEM lists the permitted PTE of the 

emergency diesel engines as 3.131 lb/hr. TSD at pdf page 431, 363. Thus, the modeling 

must use 3.131 lb/hr rather than 0.02 lb/hr.

Response 19: See response to Sierra Club Comment 9, which discusses the same issue regarding 

SO2 emissions from these emergency engines. In summary, this emergency equipment 

will only operate intermittently and briefly. Therefore, their emissions rate for modeling 

purposes varies depending on the averaging time of the standard being modeled. 

Comment 20: Furthermore, the PTE and emissions used for the annual averaging time modeling for the 

emergency diesel generators and firewater pumps is limited to 52 hours based on the 
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permit condition limiting these emission units to 52 hours of non-emergency operations 

per year. However, there is no exemption to PSD prohibition on violations of NAAQS to 

“emergency.” This is because air pollution is very dangerous and even deadly so IG’s 

understanding of an emergency does not permit it to release pollution that can injury or 

even kill innocent people. Thus, unless the permit contains a permit condition that 

absolutely limits operations of the emergency diesel generators and fire water pumps, the 

modeling has to be based on 8760 hours per year rather than 52 hours per year. 

Response 20: See response to Sierra Club Comment 10 regarding U.S. EPA guidance on estimating 

PTE for emergency equipment.

Comment 21: The September 29, 2011 spreadsheet also indicates that the wrong stack parameters 

may have been used in the modeling for the normal operations of the hydrocarbon flare. 

Again, we cannot be certain because we do not have the modeling. The spreadsheet 

indicates that the modeling used the stack height and stack diameter of the acid gas flare, 

that is 215 ft and 0.30 ft respectively, for the hydrocarbon flare during normal operations 

(pilot) when the actual stack height and stack diameter should be 292 ft and 16.89 ft. In 

addition, the spreadsheet claims that the temperature and exit velocity for the 

hydrocarbon flare are the same whether it is just burning natural gas in the pilot or burning 

methanol during gasifier start-up. This does not seem physically possible. Therefore, 

these values must be corrected if they are wrong in all of the modeling for all of the 

pollutants, the modeling re-run and a new public comment period held. 

Response 21: See response to Sierra Club Comment 12 for an explanation of the basis for flare 

modeling parameters. 

Comment 22: Finally, the TSD indicates that a Tier II 80% conversion of NO to NO2 was assumed 

based on the March 1, 2011 Tyler Fox memorandum. TSD pdf page 814. IDEM would 

need to obtain US EPA approval to use this 80% conversion of NO to NO2. There is no 

indication that IDEM obtained it. Furthermore, IDEM would need to give a valid 

justification for the use of this approach. IDEM has offered none. 

Response 22: U.S. EPA has allowed the use of the 0.80 NO to NO2 ambient ratio as a default without 

prior approval. According to the March 1, 2011, Memorandum from Tyler Fox, it states on 

page 5: 

“In order to ease the burden on permit applicants in addressing the need to demonstrate 

compliance with the 1-hour NO2 NAAQS, as well as the burden on the permitting authority 

in reviewing such applications, we offer additional discussion and recommendations in 

relation to the use of Tier 2 and Tier 3 options. Specifically, we recommend the following:

• Use of 0.80 as a default ambient ratio for the 1-hour NO2 standard under Tier 2 

without additional justification by applicants;"

(Emphasis added). Page 6 of the above memorandum further states – “We still do not 

consider 0.75 as an appropriate default ambient ratio for the 1-hour standard, but several 

references cite ambient ratios of about 0.80 for hourly NO2/NOx (e.g., Wang, et al., 2011; 

Janssen, et al., 1991), and we believe it would be appropriate to accept that as a default 

ambient ratio for the 1-hour NO2 standard.” (Emphasis added). 

Comment 23: THE AMBIENT IMPACT ANALYSIS FOR PM2.5 IS INADEQUATE

IDEM acknowledges that it modeled a violation of the 24-hour PM2.5 NAAQS to which IG 

is contributing. However, IDEM claims that IG can still obtain its PSD permit because the 

contribution from IG is below the SIL. To begin with, the SIL is not in Indiana’s SIP. 

Therefore, IDEM cannot rely on it to issue a Title V permit. Furthermore, IDEM has 
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offered nothing in the record to support the use of a SIL. Thus, IDEM cannot rely on this 

SIL. 

Response 23: For an analysis of the appropriateness of use of SILs in PSD permitting, see responses to 

Sierra Club Comments 2 and 24. 

For 24-hour and annual PM2.5 standards, U.S. EPA published a final rule in the Federal 

Register on October 20, 2010. 75 Fed. Reg. 64,864 (Oct. 20, 2010). This rule codified 

the SILs in the federal PSD regulations at 40 C.F.R. § 52.21. In the preamble to the final 

rulemaking, U.S. EPA explained, “[t]he SILs for PM2.5 are incorporated into the Federal 

PSD program as well as into the regulations for state-implemented PSD programs, 

although they are regarded as optional for State programs.” 75 Fed. Reg. 64,864, 64,866 

(emphasis added). The relevant SIL for the 24-hour averaging period is 1.2 ug/m3 and for

the annual averaging period is 0.3 ug/m3

. Id. As explained by U.S. EPA in the Final Rule, 

these values were derived by scaling the PM10 SIL values by the ratio of the PM2.5 

NAAQS to the PM10 NAAQS. Id. at 64890. Of the three methodologies originally 

proposed by U.S. EPA for setting the PM2.5 SIL values, the option chosen in the Final 

Rule resulted in the most stringent (lowest) SIL values. Id. 

Indiana has put these same stringent SILs into an “Emergency Rule” – LSA Document 

#12-68(E), section 13(b) which supersedes 326 IAC 2-3-2(f). LSA Document #12-68(E) 

became effective on February 2, 2012, though the original “Emergency Rule” 

incorporating the PM2.5 SILs into the Indiana Administrative Code (IAC) became effective 

on August 3, 2011. See “Emergency Rule” – LSA Document #11-447(E), section 13(b); 

see also “Emergency Rule” – LSA Document #11-680(E), section 13(b) (extending the 

PM2.5 emergency rule from November 2, 2011 to January 31, 2012). The SIL for PM2.5 

was implemented in accordance with LSA Document #12-68(E), section 13(b) and U.S. 

EPA’s PM2.5 rulemaking. 

Commenter is incorrect in its claim that “IDEM acknowledges that it modeled a violation of 

the 24-hour PM2.5 NAAQS to which IG is contributing.” During the time of the two 

modeled NAAQS violations, IG’s modeled contribution was merely 0.15 and 0.14 ug/m3, 

respectively, which results are well below the de minimis SIL value of 1.2 ug/m3. Air 

Quality Analysis, pages 6-7 of 49. Therefore, IDEM concluded “Even though the model 

predicts a NAAQS violation, IG was not significant at the same receptor and time period. 

Therefore, IG does not cause or contribute to a violation of the NAAQS.” Id. (emphasis 

added). See also U.S. EPA Workshop NSR Manual (Draft 1990) at C.52 (“The source 

will not be considered to cause or contribute to the violation if its own impact is not 

significant at any violating receptor at the time of each predicted violation.”). Thus, 

consistent with U.S. EPA guidance, IDEM concluded that the proposed facility will not 

cause or contribute to a violation of the PM2.5 NAAQS. 

Comment 24: Further, the use of SILs is illegal. We explained this in the Opening Brief of Sierra Club in 

Sierra Club v. United States Environmental Protection Agency, 10-1413 (D.C. Cir) which 

were are attaching as Exhibit 4 and hereby incorporating by reference. 

Response 24: The arguments made by Sierra Club in its opening brief in Sierra Club v. United States 

Environmental Protection Agency regarding the legality of SILs have been repeatedly 

rejected by U.S. EPA and federal courts alike. U.S. EPA has long-approved the use of 

SILs, and challenges to the legality of SILs have been rejected by federal courts and the 

Environmental Appeals Board. See, e.g., Sur Contra La Contaminacion v. EPA, 202 F.3d 

443, 448-49 (1st Cir. 2000) (upholding U.S. EPA’s use of SILs to allow permit applicant to 

avoid full impact analysis); In re Prairie State Generation Company, 13 E.A.D. 1, 104-108 

(Aug. 24, 2006) (same).
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U.S. EPA’s use of SILs is rooted in the de minimis exception observed in Alabama Power 

v. Costle, 636 F.2d 323, 360 (D.C. Cir. 1979). Historically, “EPA has allowed the use of 

several types of screening tools to facilitate implementation of preconstruction review 

process to reduce the permit applicant’s burden and streamline the permitting process for 

de minimis circumstances. These tools include ...SILs....” 75 Fed. Reg. 64,864, 64,866 

(Oct. 20, 2010) (final rule establishing SILs for PM2.5). As explained in U.S. EPA’s 1990 

New Source Review manual:

The EPA does not require a full impact analysis for a particular pollutant 

when emissions of that pollutant from a proposed source or modification 

would not increase ambient concentrations by more than prescribed 

significant ambient impact levels, including Class I significance levels. 

However, the applicant should check with any applicable State or local 

PSD program requirements in order to determine whether such 

requirements may contain any different procedures which may be more 

stringent,

U.S. EPA NSR Workshop Manual (Draft 1990) at C.24-C.25. Thus, while IDEM has the 

authority to establish more stringent procedures (i.e., not allow the use of screening tools 

in air quality modeling), IDEM—like U.S. EPA—permits the use of SILs. For a description 

of the status of Indiana’s rulemaking to codify the SIL for PM2.5 in Indiana’s rules, see 

IDEM’s response to Sierra Club Comment 23. 

Comment 25: In addition, the PM2.5 modeling failed to include all PM2.5. First, it failed to include 

secondary PM2.5, that is chemicals that are emitted from stacks and vents as PM2.5

precursors and converted to PM2.5 in the ambient air. Above, we explained how ozone 

impacts can be modeled for a single source. Those same documents establish that 

secondary PM2.5 can also be modeled for a single source.

Response 25: See response to Sierra Club Comment 15. This same analysis, regarding U.S. EPA’s 

January 4, 2012 response letter, applies to secondary PM2.5.

Also, 40 CFR Part 51, Appendix W, Sec. 5.2.2.1.c provides the following for PM2.5:

Estimating the Impact of Individual Sources. Choice of methods used to assess 

the impact of an individual source depends on the nature of the source and its 

emissions. Thus, model users should consult with the Regional Office to 

determine the most suitable approach on a case-by-case basis. . . . 

Additionally, in a March 23, 2010 U.S. EPA guidance memorandum entitled “Modeling 

Procedures for Demonstrating Compliance with PM 2.5 NAAQS,” U.S. EPA recognized 

that because secondary formation of PM2.5 often contributes significantly to total ambient 

levels of PM2.5, certain aspects of standard modeling practices used for PM-10 and other 

criteria pollutants may not be appropriate for PM2.5. See Memorandum from Stephen D. 

Page, Director, U.S. EPA Office of Air Quality Planning and Standards, “Modeling 

Procedures for Demonstrating Compliance with PM.5 NAAQS” (March 23, 2010) at 3-7.

IDEM has fully considered PM 2.5 impacts from this project. In accordance with the 

foregoing U.S. EPA regulatory position, an analysis for PM2.5 secondary formation can be 

found at pages 9-12 of 49 in the Air Quality Analysis for the permit.

Comment 26: Finally, the PM2.5 modeling failed to include emissions from the barges and trains in the 

PM2.5 NAAQS modeling. These sources should have been included the NAAQS 

modeling as nearby background sources. 
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Response 26: Regarding the appropriate sources to include in the NAAQS modeling inventory, U.S. 

EPA states:

... Also, sources from which secondary emissions will occur as a result of 

the proposed source should be identified and evaluated for inclusion in 

the NAAQS inventory. While existing mobile source emissions are 

considered in the determination of background air quality for the NAAQS 

analysis (typically using existing air quality data), it should be noted that 

the applicant need not model estimates of future mobile source 

emissions growth that could result from the proposed project because the 

definition of "secondary emissions" specifically excludes any emissions 

coming directly from mobile sources.

NSR Workshop Manual (Draft, Oct. 1990) at C.34. Consistent with this, existing mobile 

source emissions are included in background for the modeling. 

As part of the cumulative PSD analysis for the PM2.5 24-hour and annual NAAQS, 

representative background monitoring data in vicinity of the IG facility are included in the 

analysis to represent the ambient background PM2.5 concentrations from sources not 

included in the regional modeling analysis, such as mobile emissions and smaller 

unpermitted sources.

There were six monitoring stations considered for use in the modeling analysis – including 

two in Kentucky and four in Indiana. Of those, the Owensboro monitoring station was 

chosen. It is located in the Wyndall Shopping Center, an area of commercial use in the 

suburban area of Owensboro. The Owensboro monitoring station is the most 

representative of the IG site based upon its proximity (9.7 miles south of the IG site, the 

closest of the stations evaluated), location type similarity (not urban), and there are no 

significant topographical features separating the site and monitoring station. Additionally, 

the 24-hour PM2.5 design value of 26 micrograms per cubic meter (ug/m3

) for the 

Owensboro station is the highest of the three closest stations to the IG facility.

IG used the Owensboro background design values of 26 ug/m3 and 12.2 ug/m3 for the 24-

hour and annual cumulative analysis, respectively. These conservative background 

values include existing mobile emissions.

Hazardous Air Pollutants (HAPs)

Comment 27: Since this facility unquestionably has the potential to emit HAPs in excess of major source 

HAP emission thresholds and the permit does not have enforceable limitations on the 

potential to emit that would ensure emissions remain below this threshold, IDEM cannot 

authorize construction of IG without issuing a MACT/NESHAP determination for all the 

MACT/NESHAP standards that IDEM claims are not applicable because IG is a minor 

source.

IDEM finds that the proposed plant would not be a major source of HAPs because 

potential emissions from these emission points would be less than the applicable 

thresholds of 25 tons per year in the aggregate for total HAPs and less than 10 tons per 

year for any single HAP. TSD at 9-11, Appendix A 2. Accordingly, the IDEM finds that 

the plant is not subject to the National Emission Standards for Hazardous Air Pollutants 

(“NESHAPs”), adopted by U.S. EPA under 40 CFR 63, that apply to major sources of 

HAPs. IDEM further fails to apply a case-by-case determination of maximum achievable 

control technology (“MACT”) pursuant to Section 112(g) of the Clean Air Act for those 

emission units at the facility that would not be subject to the NESHAP standards.

As demonstrated below, IDEM’s conclusions are erroneous and based on severely flawed 

and not adequately supported emission estimates for HAPs. The Draft Permit then 
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compounds these errors by failing to reflect the emission calculations in enforceable 

permit limits. When properly estimated, potential emissions of HAPs from the proposed 

facility exceed the major source thresholds for both single and total HAPs, making the 

proposed facility a major source of HAPs and requiring MACT for the sources. 

Response 27: Absent controls and enforceable permit limits, the facility could have the potential to emit 

HAPs above the major source threshold of 25 tons/yr of total HAPs or above 10 tons/yr of 

any individual HAP. However, there are sufficient controls and enforceable limits to 

assure the facility will be a minor source of HAPs. The necessary limitations on HAP 

emissions appear in permit condition D.4.11. As indicated in the response to EPA 

Comment 9, these provisions are being revised to assure the effectiveness of these 

requirements. As revised, the condition includes specific practically enforceable limits on 

the emissions of methanol and total HAPs from the AGR vents. These limits ensure that 

the limited AGR PTE and the PTE of all the other HAP sources in total will be less than 10 

tpy for any one HAP and 25 tpy for all HAPs.

The most significant single HAP from this facility is methanol, which is predominantly 

emitted from the AGR vents. It should be noted at the outset that all HAPs evaluations for 

the AGR vent are made assuming that the entire CO2 stream is directed to the vent 

during the full year, with none to the pipeline (i.e., resulting in 6,430,000 tpy of CO2

emissions from the AGR vent). In fact, the figures used are allowed only during year 2 of 

operation. Beginning in year three, the AGR vent will be allowed only 1,290,000 tpy of 

CO2, and actual HAPs emissions from the vent would therefore be significantly less. 

Absent controls, the two AGR vents’ methanol emissions could be more than 10 tons/yr. 

However, the permit requires that the AGR vent gas streams be controlled with a 

regenerative thermal oxidizer (RTO) with total methanol emissions from both AGR’s 

limited to less than 9 tons/yr. RTOs are very effective in controlling organic HAPs and are 

expected to be 99% effective in controlling methanol. The permit requires performance 

testing of the RTOs to verify compliance with the emissions limitation and ongoing 

parametric monitoring of the RTO temperature to assure continuous compliance. Thus, 

the facility’s most significant HAP stream is well controlled and will be assured to emit less 

than 9 tons/yr of the single largest facility HAP, methanol. The PTE of the other facility 

methanol emissions sources is no more than 0.66 tons/yr. The other facility methanol 

emission sources are the methanol tankage, which has emissions controlled and 

regulated by NSPS Kb, and methanol piping equipment leaks, which will be controlled 

through a formal Leak Detection and Repair program, specified in permit condition E.6.1. 

Therefore, total facility-wide methanol emissions will be less than the major source 

threshold of 10 tons/yr.

The only other single HAP which has the potential to be emitted in levels greater than 10 

tons/yr if uncontrolled is Carbonyl Sulfide (COS). The only significant source of COS 

emissions is the AGR vents which may contain up to 2 lb/hr of COS in each of the two 

vents, for a combined total of about 17 tons/yr in these vents before they are controlled 

by the RTOs. The regenerative thermal oxidizers are expected to be 98% effective in 

controlling the COS, with a resultant emissions rate of COS of well below 10 tpy. The 

permit conditions D.4.17 and D.4.20 assure that the RTO will be operating properly 

whenever the AGR vents are in operation.

The permit limits the total HAPs from the AGR/RTO vents. As described in Response to 

EPA Comment 9, this limit is being lowered slightly to 17.0 tons/yr. 

As detailed in the response to the EPA Comment 9, the permit conditions for the testing 

and reporting of HAPs from the AGR/RTO vents are being modified. The testing of the 

RTO vent under permit condition D.4.19(d) has been expanded to address other HAPs 

that may be emitted and the compliance demonstration for the total HAPs limit on the 

AGR/RTO vents has been specified in permit condition D.4.11
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Plantwide, all other HAP pollutants are emitted in very small amounts, totaling less than 

2.1 tons/yr. These other HAPs are either fugitive emissions addressed by the LDAR 

program in permit section E.6 or they are byproducts of combustion (e.g. formaldehyde 

and hexane) and require no additional controls. Consequently, the facility total HAPS 

emissions are limited to less than 10/25 tpy by the limits on the AGR/RTO vents. Thus, 

the facility will not be a major source of HAPs.

Comment 28: THE TSD INCORRECTLY ASSUMED VARIOUS EMISSION UNITS HAVE ZERO HAPS 

EMISSION

The TSD assumes that the syngas hydrocarbon flare, the acid gas flare, the emergency 

diesel generators and the emergency firewater pumps each have a PTE of 0 TPY HAPs. 

TSD at 9. This is not correct. 

To begin with, IDEM assumes that the uncontrolled PTE from the syngas hydrocarbon 

flare, acid gas flare, emergency diesel generator and emergency firewater engine are all 

zero. TSD App A at 1. This is obviously incorrect. It is well documented that diesel fired 

generators emit hazardous air pollutants. See e.g. AP-42 at 3.3-6 - 3.3-7, 3.4-7. IDEM 

provides no information on how it calculated that HAP emissions from the emergency 

diesel generators and emergency firewater engines are zero. See TSD at pdf page 427 -

430 (showing greenhouse gas and criteria pollutants but not HAP emission calculations). 

It does seem that IDEM based its HAPs emission calculations on limited hours of 

operations for the diesel fire water pump and diesel emergency generator. However, 

these emission units are only limited to 52 hours per year of non-emergency operations. 

This is not a valid restriction on operations because there is no exemption from PTE 

definition for emergency operations. Obviously, operation of the emergency diesel 

engines and firewater pumps is a realistic worst case scenario. If it was not realistic that 

these units would operate during emergencies, IG would not have them. Therefore, the 

PTE has to be based on 8760 hours per year. 

Response 28: This comment addresses HAP emissions from three sources: the syn gas flare, the acid 

gas flare and the emergency engines. The response addresses each in that order:

Syn Gas Flare: The permit analysis considered and quantified flare emissions during 

flare standby, flaring at start up and flaring during gasifier shutdown. When in stand-by, 

the flare pilot burns either natural gas or SNG. The emissions analysis uses the AP-42 

HAP emissions factors for natural gas and assumes the pilots operate at all times. SNG 

and natural gas are predominantly methane and contain other trace components. SNG 

combustion is expected to have fewer total HAP than natural gas combustion. (See the 

response to Sierra Club comment 29). The use of the natural gas emissions factors for 

natural gas is appropriate and, for SNG combustion, is conservative. During gasifier 

start-up, the flare receives syngas from the gasifier. The gasifiers are always started with 

methanol as feedstock. Startup begins with heating the gasifier to its operating 

temperature with the preheat burner and feed to the gasifier does not occur until the 

gasifier is hot enough to convert the methanol to CO, H2, CO2 and a trace amount of 

methane. The combustion of this clean mixture does not result in HAP emissions beyond 

those of the pilot burner that is operating during start up. A small amount of coal/coke 

derived syngas will be vented to the flare during the final vessel depressurization during 

planned shutdowns. The total quantity of these gases vented to the flare is very small. 

Also, these flared gases, are products of the gasification process and are predominantly 

CO, CO2 and H2. These compounds would combust in a flare extremely cleanly, with 

negligible HAP formation. 
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Nevertheless, as further verification of their insignificant magnitude, IDEM has, for 

informational purposes, estimated worse case HAPs emissions for syngas combustion 

during shutdowns using metal HAP emissions factors from a recently permitted syngas 

facility (the Edwardsport IGCC facility, Permit No. 083-23529-00003), August 2006 permit 

application, Table 2-19.), the HCl concentration maximum provided by the gasifier 

manufacturer and EPA’s organic HAPs emissions factors for natural gas. Using these 

conservative factors, total HAPs from combustion of shutdown flare venting amounts to 

less than 0.005 tons/yr. 

Acid Gas Flare: As with the syn gas flare, the HAP PTE analysis includes emissions of 

the pilot on the flare operating 8760 hours a year. The acid gas flare has no other 

emissions during startups or planned shutdowns. 

Emergency Engines: HAPs from the diesel engines (firewater pumps and emergency 

engines) are extremely small. For informational purposes, total emergency engine HAPs 

emissions using EPA’s diesel fuel internal combustion HAP emissions factors during 

permitted operation are 0.002 tons/yr. 

Regarding the appropriate consideration of malfunction and emergency operation when 

calculating PTE, see response to Sierra Club Comments 5 and 10. 

The emission calculations for all three sources described above are set out in the 

attached tables in 30464 ATSD - Appendix A.

Comment 29: IDEM used AP-42 rather than an enforceable emission limit for the total VOC HAPs. See 

e.g. TSD at pdf page 403. EPA has consistently rejected this approach. IDEM provides 

no information about where it obtained the mercury emission factor. Id. Agencies are not 

allowed to use random numbers to calculate PTE without an citation to where the mercury 

emission factor came from. Thus, IDEM significantly underestimated the HAPs PTE. 

Response 29: Except for the emergency engines and fire pumps, all the facility fired equipment operates 

on natural gas or SNG. Natural gas and SNG are both primarily methane with other trace 

components. Natural gas is more likely to have the precursors of HAPs than SNG, 

though still in very small quantities. While natural gas contains some light hydrocarbons 

that remain from the separation of liquids and gases during its extraction and production, 

the methane in SNG is chemically built from CO, H2 and water in reactions that do not 

produce higher molecular weight hydrocarbons. The organic HAP emissions attributed to 

natural gas are the dominant HAPs and the other HAPs are trivial by comparison. It is 

therefore appropriate for natural gas and conservative for SNG to use the standard 

emissions factors for natural gas to determine such small levels of HAPs from 

combustion. 

IDEM and EPA have used AP-42 factors for natural gas consistently in a wide range of 

HAP emissions determinations. (This is discussed further in the response to Sierra Club 

comment 34) Further, when the HAPs PTE of a source is very small and the total HAPs 

PTE is still below the major source limit, unit by unit limits on trivial sources of HAPs that 

reflect their PTE for HAPs are not appropriate.

The basis for the site specific emissions factor for mercury is presented in the IDEM pdf 

page 489 of 880. As noted on that page, the site specific mercury emissions factor for

SNG of 1.65x10-6 lb mercury per MMBtu (HHV) is based on a reported maximum 

mercury content of Indiana coal, assuming that virtually all of that mercury ends up in the 

syngas and 98.6% of the mercury is removed in sulfided carbon beds which treat the 

syngas before methanation (the process that converts it to SNG). Average reported 

mercury levels in Indiana coal is about 1/4th the assumed level. Therefore, the mercury 

emissions estimate is conservative. 
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Comment 30: IDEM FAILED TO CONSIDER SSM WHEN CALCULATING PTE FOR HAPS

For the acid gas flare and hydrocarbon flare, IDEM completely ignored HAPs emissions 

when the flares are flaring process gases during upsets and malfunctions even though 

IDEM acknowledges that this does happen. See TSD at pdf page 363, 403. Rather, the 

only emissions considered are from the pilot in the flare or from startup on methanol. Id. 

IDEM must calculate PTE to include flaring of process gases during upsets and 

malfunctions. 

Response 30: As explained in the response to Sierra Club Comment 5, emissions associated with 

malfunction events do not reflect source emissions under normal or usual operating 

conditions and thus do not reflect the source operations “under its physical and 

operational design.” Therefore, IDEM is not required to account for such events in a 

source’s PTE. This is as true for HAPs as it is for criteria pollutants. Although the Clean 

Air Act’s criteria and hazardous air pollutant programs may apply to different pollutants 

and may have different major source thresholds, the Clean Air Act consistently defines a 

major source in both programs in terms of both its actual and potential emissions. The 

definition of PTE in EPA’s HAPs regulations is the same as the definition in Part 51 

applicable to state implementation plans. Compare 40 C.F.R. § 63.2 (PTE is defined as 

“the maximum capacity of a stationary source to emit a pollutant under its physical and 

operational design. . . .”) to 40 C.F.R. § 51.166 (PTE is defined as “the maximum capacity 

of a stationary source to emit a pollutant under its physical and operational design. . . .”). 

Comment 31: IDEM’s analysis of HAPs emissions from the auxiliary boilers and gasifier preheater 

burners is based on steady state operations. However, HAPs emissions from combustion 

of natural gas, especially formaldehyde and aldehydes can be exponentially higher during 

startups, shutdowns and malfunctions. It is well known that, HAP emissions increase with 

reduced operating loads. Boilers are designed to run efficiently at full load where fuel 

combustion is nearly 100 percent efficient. At lower loads, and during startup, they are 

extremely inefficient, which results in incomplete combustion. This increases products of 

incomplete combustion, such as carbon monoxide (“CO”), aldehydes, and hydrocarbons. 

However, the relationship is not necessarily directly proportional and differs for individual 

HAPs as well as with the type of boiler. 

Response 31: In calculating HAP emissions from boilers and the other IG combustion devices, it is 

standard practice to use the same emissions factors (lb/MMBtu), regardless of operating 

load of the combustion device. Further, the two emissions sources mentioned by the 

commenter, the auxiliary boilers and gasifier preheat burners, will not normally operate at 

very low loads. For example, the main need for both sources is during startups, at which 

time they will normally operate at greater than 50% load.

To support their contention that combustion devices have higher HAPs emissions at low 

loads, the commenter cites three references. The first two references (footnotes 11 and 

12) address emissions from gas-fired turbines. The proposed IG facility does not have 

any combustion turbines and, from an emissions perspective, they are very different from 

boilers and heaters. The third footnote (13) references a study entitled “Gas-Fired Boiler 

and Turbine Air Toxics Summary Report”, August 1996. This report predominately 

discusses combustion turbines performance, which is not relevant to the IG combustion 

sources. This report also contains HAP testing results for two gas-fired utility boilers at 

various loads. However, that testing does not support the commenter’s contention that 

boilers at low loads have significantly higher HAPs. In contrast, the report states that 

emissions of the HAPs tested (formaldehyde, benzene, and toluene) “were not 

significantly impacted by unit load or excess air level and were lower than emissions from 

the combustion turbines” (pg. 30 and 67). Additionally, it is of interest that the emissions 

for the three HAPs that were detected in the boiler emissions were less than the sum of 

the emissions factors for these three HAPs in AP42 which was used by IDEM to calculate 
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the IG gas combustion HAP emissions. 

In conclusion, the use of applicable AP42 factors for natural gas and for estimating 

combustion HAP emissions for the IG facility was appropriate and is consistent with 

standard practice for the types of sources included in this proposed facility.

Comment 32: Considering these increased HAPs emission rates during SSM is enough to bring IG to 

over the 25 TPY major source threshold. Otherwise, the permit would need to include 

HAPs CEMs that record emissions at all times, including SSM. 

Thus, because IG is a major source of HAPs, all of the NESHAPs that the TSD says are 

not applicable because IG is an area source are actually applicable. 

Response 32: As explained in response to Sierra Club comment 28 above, HAP emissions associated 

with startup and shutdown have been evaluated and accounted for in determining the 

PTE of the facility. In regards to HAP emissions during malfunctions, see Response to 

Sierra Club Comment 30. 

Synthetic Natural Gas Is Not Guaranteed to Have the Same 

Combustion Characteristics as Natural Gas

Comment 33: Synthetic Natural Gas Is Not Guaranteed to Have the Same Combustion Characteristics 

as Natural Gas

The Applicant derived emission factors for various HAPs based on U.S. EPA’s 

Compilation of Air Pollution Emission Factors (“AP-42”), Chapters regarding natural gas 

combustion. Neither the Applicant nor IDEM provides a satisfactory explanation why 

emission factors derived for natural gas-fired combustion sources are considered 

applicable to combustion of SNG in IG. 

Response 33: As explained in response to Sierra Club comment 29 above, the use of the AP-42 organic 

HAP factors for natural gas when determining the HAP emissions when burning SNG is 

conservative because natural gas contains more HAP emissions precursors than SNG. 

For mercury and lead, AP-42 was not used. Instead, the permit applicant developed 

specific factors based on the performance of controls inherent in the SNG production 

process.

Comment 34: First, while the produced SNG may have similar physical and chemical characteristics 

compared to pipeline natural gas, the two gases are just that: similar, but not identical. 

SNG may have a similar heat content, maximum sulfur fuel content, and higher methane 

content as natural gas but may have a different content of other components that affect 

the combustion process and the formation of pollutants. 

Response 34: As discussed in response to Sierra Club comment 29 and 33, SNG is expected to have 

fewer organic HAPs and HAP formation precursors in it than natural gas. Therefore SNG 

is expected to have fewer HAP emissions, upon combustion, than natural gas. Regarding 

the non-organic HAP precursor trace constituents of coal (sulfur, chloride, fluoride, 

metals, etc.) from which the SNG is derived, these will removed by the intensive gas 

treatment and processing associated with the conversion of the solid feedstock into 

syngas and the syngas into SNG. These gas treatment and processing steps include 

water washing, acid gas removal, carbon adsorption and catalytic conversion. 

All these processing steps, inherent in the SNG production process, are very effective in 

removing HAPs and HAP precursors. For example, these processing steps remove 

virtually all entrained particulate which would otherwise carry with it non-volatile metallic
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HAP compounds. The water washing and wet scrubbings steps are very effective in 

removing sulfur, chlorine and fluoride compounds. Semi-volatile metallic compounds 

such as mercury are very effectively removed by sulfide carbon beds through which the 

syngas must pass. Additionally, of the very small amount of HAP compounds that pass 

thru these rigorous treatment steps, some amount of additional removal occurs from on 

the catalyst beds of the shift conversion and methanation processes. From an overall 

HAPs perspective, SNG combustion should have lower HAPs than natural gas 

combustion. 

Specifically regarding metallic compounds (excluding lead and mercury which are 

calculated separately), IG’s estimated metallic HAP content of syngas is only slightly 

higher than the AP42 assumptions for natural gas for metallic HAPs. The gas treatment 

steps to convert the syngas to SNG are expected to remove approximately 85% of these 

metallic HAP compounds. Thus, the resulting SNG will have trace levels of metals that, 

cumulatively, are less than one quarter the AP42 metallic HAP factors for natural gas 

combustion. Therefore, even for metallic HAPs, the use of natural gas metallic HAP 

factors for SNG combustion is conservative.

Comment 35: Second, the Draft Permit does not contain a requirement that SNG be consistently 

produced to any particular specifications. For example, Draft Permit does not require 

testing for methane, hydrogen, carbon monoxide or moisture content or the higher 

heating value of the SNG, all of which affect the combustion process and the formation of 

combustion products including HAPs.

Response 35: The SNG is being produced and sold into the natural gas market. Therefore, it has to 

meet the same quality requirements that any natural gas producer must meet before 

placing gas in a pipeline. It will not be materially different than natural gas in regards to the 

constituents listed by the commenter and it is less likely to contain the organics that serve 

as the key combustion HAP precursors for natural gas.

Comment 36: Non-Metallic HAP Emission Factors Used By Applicant Underestimate Potential 

to Emit.

Even if one accepted the Applicant’s premise that SNG is equivalent to natural gas, the 

emission factors used by the Applicant to determine potential to emit for non-metallic 

HAPs (based on AP-42, Chapter 3.1) are not appropriate for estimating the “maximum 

capacity of a stationary source to emit any air pollutant” as required under 40 CFR §§ 

63.2 and 63.41. 

First, almost all of the tests evaluated for AP-42, were conducted for compliance 

purposes. Compliance tests, or source tests, are typically announced and, thus, give the 

operator the opportunity for optimizing equipment and operating at optimal conditions. As 

such, measured emission rates are most likely on the lower end of what would be 

observed under non-optimized conditions. 

Second, the average emission factors from AP-42 are not appropriate to determine the 

maximum HAP emissions from the facility. Either the maximum or the 95th percentile 

emission factors measured during those tests would have been more appropriate. In a 

memorandum on HAP emission factors from natural gas-fired turbines, the U.S. EPA 

emphasizes that “[t]he 95th upper percentile emission factor may be more appropriate to 

use [than the average emission factor] for determining whether a source is major since it 

considers the test result variability.” 

Third, most of the emission factors used have a rating of E. This is the lowest rating in 

terms of reliability. 
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The Environmental Appeals Board decision in In re Peabody Western Coal Co., 12 E.A.D. 

22, CAA Appeal No. 04-01 (Feb. 18, 2005) demonstrates why relying on emission factors 

is not sufficient in a potential to emit analysis. In that case, Peabody tried to establish that 

one of its facilities was a synthetic minor source for purposes of PSD. Peabody’s request 

for a PTE limit of 185 ton/year relied on a quantitative estimate of the Facility’s capacity to 

emit PM10. This estimate, in turn, relied on emission factors and assumed emission 

control efficiencies. Peabody estimated the uncontrolled emissions from each emissions 

unit based on the application of AP-42 emission factors. Peabody then estimated the net 

emissions from these units by applying assumed control efficiencies, and requested that 

Region IX establish a PTE limit for the Facility based on the cumulative total estimated net 

emissions. Similarly, Peabody’s proposed compliance regimen did not include direct 

measurement of PM emissions.

U.S. EPA, Region IX, however, found a fundamental conceptual difference between PTE 

and actual emission performance that made Peabody’s complete reliance on emission 

factors inappropriate in this instance. “While PTE is intended to identify the highest 

possible level of emissions that a facility is capable of releasing in light of its physical 

design and operational characteristics (considering enforceable restrictions on emission 

capacity), emission factors are intended to provide a generalized estimate of the average 

emissions performance of a particular type of emission source. According to AP-42, ‘[i]n 

most cases, these factors are simply averages of all available data of acceptable quality, 

and are generally assumed to be representative of long-term averages for all facilities in 

the source category (i.e., a population average).’ As a result, according to Region IX, 

emission factors do not necessarily reflect the level of emission appropriate for calculating 

PTE.” In re Peabody Western Coal Co., 12 E.A.D. 22. Region IX stated that it “was not 

‘disputing Peabody’s use of emission factors and control efficiencies for the purpose of 

calculating actual emissions,’ but that because ‘PTE is meant to be a worst case 

emissions calculation,’ Peabody’s approach was not adequate for ‘the creation of a 

practically enforceable PTE limit for regulatory purposes.’” Id. The Environmental Appeals 

Board upheld the Region’s decision that this could not be a synthetic minor source when 

its PTE were based on emission factors. Id. Similarly, IG’s reliance of emission factors in 

its potential to emit HAPs analysis is inadequate.

Response 36: As an initial matter, the emission factors used for organic HAPs in natural gas are based 

on AP-42 Chapter 1.4, not Chapter 3.1 as suggested by Commenter. See Permit pdf pg 

567 of 880. 

The case cited by Commenter, In re Peabody Western Coal Co., 12 E.A.D. 22, is 

inapplicable to this situation. First, Peabody involved the use of AP-42 emission factors in 

establishing a PTE limit for the source. In contrast, IG is using AP-42 emission factors to 

calculate PTE of trace organic constituents found in natural gas for purposes of making 

an applicability determination and not for purposes of taking a PTE limit for these small 

HAPs. The Introduction to AP-42 contemplates the use of AP-42 emission factors for this 

purpose: “[e]mission factor use may also be appropriate in some permitting applications, 

such as in applicability determinations and establishing operating permit fees.” 

Compilation of Air Pollutant Emission Factors, Fifth Edition, Introduction p. 2 (January 

1995) (AP-42). AP-42 factors for natural gas are commonly used to estimate annual 

unlimited PTE for combustion sources. 

Second, Peabody involved use of AP-42 emission factors to estimate and limit 

sourcewide fugitive particulate emissions (coal dust) from many coal handling points, 

which necessarily involves many different technical issues than the calculation of potential 

to emit trace HAP constituents in natural gas combustion exhaust. 

In evaluating the technical issues involved in the calculation of PTE of HAPs for natural 

gas combustion sources, IDEM finds that the AP-42 HAPs emission factors used are 
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representative of the natural gas combustion sources at the facility and appropriate for 

use in determining unlimited annual PTE of HAPs for these sources. Natural gas consists 

of a very high percentage of methane, typically over 85%, and smaller amounts of ethane, 

propane, and butane. AP-42 Chapter 1.4.1 (July 1998). There are also trace amounts of 

organic HAPs. See AP-42 Chapter 1.4, Table 1.4-3. Of the 24 organic HAPs compounds 

listed in the table on page 567 of the Permit, for 13 of these trace compounds, the 

underlying test data used to develop the respective emission factors in AP-42 are based 

on the method detection limits, meaning that the constituent was not detected at levels 

above the lowest level that could be detected by the test method. 

Although several of the smaller trace HAP constituents are assigned an emission factor of 

“E,” their use is appropriate in this case. As explained in the background document 

describing the development of the current emission factors found in Chapter 1.4, the 

underlying test data used to develop the HAPs emission factors were all assigned a data 

quality rating of “A.” See Emission Factor Documentation for AP-42 Section 1.4 Natural 

Gas Combustion, Table 2.2-1 (March 1998). This means that the “tests are performed by 

a sound methodology and are reported in enough detail for adequate validation.” Id. at 

Section 2.1. The “E” rating for these specific emission factors are because the emission 

factors are based on “less than three A- or B-rated source tests” (in this case, the source 

tests used were all rated “A”). Id. at p. 3.10. 

Therefore, the points raised by Commenters overall about AP-42 are unpersuasive. It is 

noted that this project will have new, state of the art boilers, which should have combustion 

efficiencies better than the average performance of the units tested to establish the AP-42 

factors. Therefore, use of these factors is conservative in that regard. Also, the 

Commenter’s reference to a US EPA memorandum regarding gas combustion turbines to 

support a suggestion that the 95th percentile test result for estimating HAPs should be

used is inappropriate because this project has no gas combustion turbines – the unique 

combustion characteristics of a combustion turbine are irrelevant to the types of gas-fired 

sources at this facility. Combustion HAPs emissions are very small, estimated to be under 

1.6 tpy. Thus, even if the emission factor for any individual organic HAP is inaccurate by a 

significant amount, such error will not adversely impact the overall applicability 

determination. 

Thus, use of AP-42 emission factors to estimate organic HAPs PTE for natural gas 

combustion sources at this facility is appropriate. 

Comment 37: Hydrogen Chloride Emissions Were Omitted

During the gasification process, most of the chloride species in coal are converted to 

hydrogen chloride (“HCl”), which is a HAP. The actual concentration of HCl vapor in a 

coal gas stream will depend on the chlorine content of the coal, the gasification 

temperature, the type of gasifier, and the presence/concentration of alkali metals in the 

gasification system. 

The PTE calculations do not provide estimates for HCl emissions from the flares, 

equipment leak fugitives, and sources that combust SNG, including the auxiliary boilers 

and preheaters, the AGR vent catalytic oxidizer. The permit record does not provide a

satisfactory explanation why HCl emissions were not quantified for these sources. 

The air permit application for the Kentucky NewGas SNG production facility, which was 

prepared by Trinity Consultants, established separate HCl emission factors for syngas

and SNG combustion based on emission factors determined from a series of stack tests 

conducted at the Wabash River and Louisiana Gasification Technologies, Inc. (“LGTI”) 

facilities. The Application and TSD provide no discussion whatsoever why these emission 

factors were not deemed equally applicable to combustion of SNG at the IG facility and 
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instead zero emissions were assumed for combustion of these gases. Actual emissions 

of HCl from IG may be considerably higher than LGTI because of the substantially higher 

chlorine content in the Illinois basin coal that would be gasified at the IG facility compared 

to the western subbituminous coal from Rochelle mine in the Powder River Basin in 

Wyoming that was gasified at LGTI. The chlorine content of coal gasified at LGTI was 

measured at 0.0039 percent by weight (%wt). The Application, Permit Summary and 

Draft Permit are silent on the chlorine content of the coal the operator will gasify at the 

facility. 

Response 37: No, HCl is generated during start up flaring of the syngas from gasifiers because the unit

starts up on a feed, methanol, that does not contain any chlorine compounds. HCl is 

produced when coal is gasified. All but a trace amount of that HCl is removed in the 

quenching of the gas in the gasifier. Less than 10 ppm of HCl remains in the syngas. 

During a planned shutdown, a small amount of coal- or coke-derived syngas is vented to 

the flare. The HCl emissions at the flare during these conditions are no more than 0.0023 

tons/year.

As the syngas is converted to SNG, this small amount of HCl is removed.

The commenter references other permit actions and the HCl emissions attributed to 

gasification products for other gasification plants. First, it should be noted that the permit 

record for this project has been supplemented with a quantification of the extremely small 

HCl emissions that may result from syngas combustion. Second, the gasification process 

in this case involves greater quenching and removal of HCl than would be found with 

different designs and this project involves extensive processing of the syngas to convert it 

to SNG while certain of the other projects involve the direct combustion of syngas. Lastly, 

there is no technical basis to assume that HCl would be present in the SNG even if other 

permitting actions have applied simplifying assumptions to this point. Also, we will note 

that the total HAPs attributed to syngas and SNG firing in this permitting action on a 

pounds/MMBtu basis are similar to or greater than the total HAPs presented in the 

references used by this commenter.

Comment 38: Other HAP Emissions Were Omitted

Similar to hydrogen chloride, the Applicant failed to account for emissions of a number of 

other HAPs including benzo(e)pyrene, carbon disulfide, dichloromethane (methylene 

chloride), hydrogen cyanide, perylene, and phenanthrene from sources that combust 

SNG. Again, the permit record provides no discussion why the emission factors 

developed for the Kentucky NewGas SNG production facility were not deemed equally 

applicable to combustion of SNG at the IG and instead zero emissions were assumed for 

combustion of these gases.

Response 38: The SNG is chemically derived from reactions of H2, CO and water and those reactions 

do not produce the organic HAPs listed by the commenter. Kentucky NewGas in their 

assessment of SNG organic HAPs chose to use factors derived from the combustion of 

coal and from testing of a completely different type of gasifier than that to be used by IG. 

IG will use a GE quench gasifier which has significantly different operating parameters 

and produces significantly different syngas than the Conoco-Phillips gasifier whose test 

results which were used, in part, as the basis for Kentucky New Gas’s HAPs factors. Ky 

NewGas’s factors are not representative of the organic HAPs that are likely to occur when 

IG’s SNG is combusted. The HAPs attributed to natural gas are more representative of 

those of SNG. It should be noted that with either approach the HAPs from SNG 

combustion are very small and the total using the factors for natural gas is actually greater 

than those attributed to SNG in the Kentucky New Gas documentation.
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Comment 39: IG IS NOT A SYNTHETIC MINOR SOURCE OF HAPS AS THE DRAFT PERMIT FAILS 

TO INCLUDE ADEQUATE TERMS AND CONDITIONS TO CREATE FEDERALLY AND 

PRACTICALLY ENFORCEABLE LIMITATIONS ON IG’S POTENTIAL TO EMIT HAPS 

BELOW MAJOR SOURCE EMISSION THRESHOLDS.

As detailed above, IG is not a genuine minor source of HAPs as it will easily exceed the 

significance thresholds for a number of pollutants. As discussed above, a “synthetic 

minor” source of HAPs is one with potential emissions in excess of major source 

emission thresholds except that enforceable limitations (practically enforceable) on the 

source’s potential to emit are imposed to keep the source from emitting at or above major 

source emission thresholds. Therefore, IDEM could only find IG is a minor source if the 

permit establishes practically enforceable limitations that prevent it from exceeding those 

significance thresholds. The draft Permit does not meet that standard, so IG cannot deem 

this facility a synthetic minor source. 

Response 39: See Response to Sierra Club Comment 27.

Comment 40: TESTING FOR THE RTO IS INADEQUATE

The draft permit only requires testing for methanol from the acid gas recovery unit’s 

regenerative thermal oxidizer (RTO) once every five years. TSD at 40. A stack test once 

every five years does not adequately ensure that emissions of methanol are keep below 

the minor source threshold in the time period between the stack tests. Performance of 

the system can vary dramatically during five years. Also, the stack test does not provide 

any data on methanol emissions during startups, shutdowns and malfunctions as the 

stack test is performed only at steady state operations. Finally, the methanol testing of 

the RTO does not provide any information about other HAPs emissions from the RTO. 

Adequately testing would require a HAPs CEMS or at least quarterly stack testing, 

including testing during startup, shutdown and malfunction of all possible HAPs coupled 

with continuous parametric monitoring based on a well established correlation between 

the parameter monitored and the emission rates observed during the stack test. 

Response 40: As indicated in the Response to EPA Comment 9, the requirements for testing and 

documentation of emissions for HAPs from the AGR units are being amended to include 

testing for additional HAPs other than methanol and the determination of emissions 

factors based on the units’ emissions. Those factors will be applied to the flow from these 

units to determine total HAP emissions from the AGR units. Because the gases that are 

vented from the AGR to the RTOs are otherwise a process product stream, the 

composition of that stream and the emissions from the RTOs are not expected to vary. 

Further, proper operation of the RTO is assured through continuous monitoring of their 

operating temperature. 

PERMIT CONDITIONS ARE NOT ENFORCEABLE

Comment 41: HYDROCARBON FLARE

The TSD claims that massive SO2 emissions from the hydrocarbon flare will be avoided 

by only using methanol as a feed stock during startup. Condition D.2.4(3)A addresses 

this situation. However, Condition D.2.4(3) is too vague to be enforceable as a practical 

matter. The second paragraph of Condition D.2.4(3)A should have the following sentence 

added to the end of it to ensure its enforceability: “The permittee may not introduce 

coal or pet coke into the gasifiers until the valve to the syngas hydrocarbon flare is 

completely closed.”

Response 41: The proposed permit includes requirements sufficient to ensure compliance with the 

startup SO2 limit in Condition D.2.4(3)A. The permittee must use only methanol during 
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startup conditions requiring flaring -- D.2.4(3)A. The permittee must continuously monitor 

and record flow rate to the flares –D.2.4(3)A. -- and record the date, time, and total number 

of minutes for each startup flaring event – D.2.9(d) -- as well as the feedstock used during 

each gasifier startup that requires flaring – D.2.9(e)i. These records must be used to 

determine and record emissions according to the calculations in the permit, including 

startup emissions – D.2.7(c) and D.2.9(f). Finally, for malfunction events that cause gases 

to be sent to a flare, the “root cause” analysis provision applies – this includes anytime 

gases are sent to the flare that are not startup or shutdown events – D.2.4(3)A. Therefore, 

specific monitoring and recordkeeping requirements already apply to each condition 

requiring flaring, whether the feedstock is methanol or coal or petcoke, and these 

conditions are practically enforceable.

Comment 42: Also, the TSD assumes maximum emission of 0.70 lb/hr SO2 from the flare except during 

certain startup and shutdown events. Thus, the permit needs a condition limiting SO2

emissions to 0.70 lb/hr except during startup and shutdown. This emission limit needs to 

apply at all time except startup or shutdown.

Response 42: The emissions estimate for the hydrocarbon flare of 0.70 lb/hr SO2 set out in the TSD is 

for startup flaring. Compliance with this limit is achieved by the permit requirement to use 

only methanol during startup conditions requiring flaring -- D.2.4(3)A. Outside of startups 

and shutdowns, in normal operation the only emissions from the flare will be the 

combustion emissions from the pilot. The TSD sets forth an SO2 emissions estimate for 

the pilot of 0.00068 tons annually, based on 8,760 hours of operation, or less than 0.0002 

lbs./hr. See TSD page PDF 491 of 880. These amounts, based on AP-42 emission 

factors for combustion of natural gas, are extremely small. There are no controls 

available for burners of this size and type, and no limitations are necessary or appropriate 

given the very small potential to emit of the units. However, for consistency, it is 

appropriate to include a requirement that the pilot operate on SNG or natural gas only, as 

is already included, for example, for the AGR RTOs (see Condition D.4.4). 

The following changes have been made to the permit:

D.2.67 Flare Pilot Flame

In order to ensure compliance with Condition D.2.4, the flare must be operated 

with a flame present at all times when the Syngas Hydrocarbon Flare is in 

operation and at least one gasifier is in operation or in startup or shutdown. Only 

natural gas or SNG shall be used in the pilot for the Syngas Hydrocarbon 

Flare (EU-001).

D.3.6 Flare Pilot Flame

In order to ensure compliance with Condition D.3.4, the flare must be operated 

with a flame present at all times when the Acid Gas Flare, identified as EU-002 is 

in operation and at least one gasifier is in operation or in startup or shutdown.

Only natural gas or SNG shall be used in the pilot for the Acid gas Flare 

(EU-002).

Comment 43: The draft permit uses emission factors to determine compliance with the SO2 emission 

limits during startup and shutdown. See Draft permit at page 59. The draft permit has 

absolutely no compliance mechanism at all for SO2 emissions from the hydrocarbon flare 

for times other than startup and shutdown. Id. 
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Response 43: As explained in response to EPA Comment 5, startups and shutdowns are the only 

operating scenarios in which flaring is expected at the syngas hydrocarbon flare in normal 

operation. Outside of startups or shutdowns, in normal operation the only emissions from 

the flare will be the combustion emissions from the pilot. To document the compliance 

status with the requirements of Condition D.2.4(3)(A), the permittee is required to 

maintain a record of the feedstock used during each gasifier startup requiring flaring, the 

routing of gas whenever a gasifier is depressurized during a planned gasifier shutdown, 

and the operating rate of each gasifier prior to and during a planned shutdown of a gas

treatment train. See Condition D.2.9(e). Condition D.2.9(e) also requires that the 

permittee shall have available for inspection copies of the procedures used to implement 

the measures in the flare minimization plan (FMP) and records of training sessions on 

those procedures. Also, the Permittee shall have a written record of each root cause 

analysis, the actions recommended from the analysis, and documentation on the 

implementation of any corrective actions stemming from the root cause analyses under 

the FMP.

Comment 44: The draft permit must have monitoring for SO2 emissions from the hydrocarbon flare that 

applies at all times, including startup, shutdown, malfunction and upset. IDEM must 

require a total sulfur monitor. See MONTANA SULPHUR & CHEMICAL COMPANY v. 

US EPA, ___ F.3d ____, NOS. 02-71657, 08-72642 (9TH CIR. JAN. 19, 2012) Slip Op. at 

12; 73 Fed. Reg. at 21,426-21,428. In the alternative, IDEM could consider a grab or 

integrated sampling although at this point, it does not seem like that is necessary as total 

sulfur monitors have had adequate time to mature. See e.g. 73 Fed. Reg. at 21,429. 

Response 44: The monitoring required by the permit is appropriate for this source. The case cited by the 

Commenter, Montana Sulphur & Chem. Co. v. U.S. EPA, 666 F.3d 1174 (9th Cir. 2012), 

arises out of SO2 NAAQS attainment demonstrations in Montana and requirements 

(including flare emission limits) in the resulting SIP and FIP, and does not address or 

change the analysis of appropriate monitoring requirements for individual units at the IG 

facility. The Ninth Circuit did not find, as the commenter appears to suggest, that the types 

of monitoring discussed in the court’s opinion must be applied to all flares in all 

circumstances. The Ninth Circuit decision is a narrow one – holding that EPA did not act in 

an arbitrary or capricious manner by requiring total sulfur monitoring and grab or integrated 

sampling in the FIP for Montana Sulphur Chemical Company’s flares. This opinion does 

not stand for the proposition that IDEM “must require a total sulfur monitor.” 

In this case, monitoring for the hydrocarbon flare beyond what is required in the permit is 

unnecessary. (See, the responses to Sierra Club Comments 41, 42, and 43 for additional 

information on the compliance requirements for this unit.) The emissions factors specified 

for use in Condition D.2.7(c) are based on very conservative assumptions and the actual 

sulfur levels in the flared gases would be the same or lower than these numbers. In 

addition, the estimated PTE is very low, at only 1.97 tons per year (see TSD p. 9 of 43). 

As a consequence, any additional sampling, including continuous monitoring, is 

unnecessary and overly burdensome. 

Startup SO2 emissions will be negligible due to the startup feedstock required. The 

emission factor used to calculate SO2 emissions during startup, 0.10 x 10-6 lb SO2/scf, is 

extremely low because it is based on flaring of syngas generated from methanol, which is 

virtually sulfur free. Permit Condition D.2.4.3 requires the use of methanol feedstock 

during startups. Thus, no sampling or other additional monitoring is necessary to 

determine compliance for startup emission limits.

For shutdown, even though the emission factor is based on very conservative 

assumptions, SO2 emissions will be very low due to the strict requirements for shutdown 

operations. The emission factor used to calculate SO2 emissions during shutdown is 

0.001264 lb SO2/scf. This sulfur content is calculated based on the conservative 
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assumption that the feedstock contains highest sulfur content the plant is designed to 

handle (5.79%wt dry sulfur in coal/coke) and assuming all the feedstock sulfur is converted 

into sulfur compounds in the syngas and all sulfur compounds covert into SO2 emissions 

when combusted in the flare. Actual sulfur content and SO2 emissions per cubic foot of 

syngas flared should be no more than this conservative assumption, and will normally be 

lower. Therefore, any sampling or other additional monitoring would not provide additional 

meaningful information to assure compliance for shutdown emission limits. 

Even with these conservative assumptions in the emission factor, SO2 emissions from the 

hydrocarbon flare will be very low due to the strict requirements for shutdown in Condition 

D.2.4(3), including: 1) routing the contained volume of each gasifier train to a WSA during 

planned shutdown; and 2) gasifier feed rate reduction prior to a scheduled gas treatment 

train outage.

The emissions estimate for pilot fuel SO2 emissions is based on the very low sulfur content 

of either pipeline quality natural gas or SNG which is used for the flare pilot in small 

quantities. For consistency with other terms, a requirement is being added to the permit 

that the pilot operate on SNG or natural gas only, as described in response to Sierra Club 

Comment 42. 

Comment 45: RTO DOES NOT HAVE A MINIMUM TEMPERATURE

The Permit requires continuous monitoring of thermal oxidizer temperature and further 

requires that the unit be operated at or above a three-hour average temperature of 

1,600°F, or some other value determined in a stack test. Draft Permit at pdf p. 80. There 

are two problems with this requirement.

First, the thermal oxidizer temperature determines the amount of emissions. 

Temperatures higher than design can significantly increase NOx while temperatures 

lower than design can significantly increase VOCs and aldehydes. Thus, we recommend 

that the Permit be revised to require testing to establish an operating range within which 

all limits are met and that this range be set as an enforceable permit condition.

Second, the permit does not consider a temperature below the three-hour average to be a 

deviation of the permit. Id. As explained above, thermal oxidizers should be operated in 

a fairly narrow optimal range. A lower operating temperature will increase emissions of 

VOCs and aldehydes. This problem could be solved by adopting our recommendation to 

establish an operating range.

Response 45: The primary purpose of the AGR thermal oxidizer is to provide thermal destruction of 

methanol and other organic and HAP compounds in the AGR vent stream. This is the 

classic use of this technology. To assure proper destruction, it is standard practice to 

require maintenance of a minimum operating temperature on the oxidizer. It is not 

customary for oxidizers to be required to undertake numerous stack test runs at multiple 

operating temperatures to try to establish a maximum temperature, or to discern an 

optimum. Rather, as is customary practice for thermal oxidizer controls, IG’s thermal 

oxidizers will be required to conduct a performance test to demonstrate that the unit 

complies with the emission limits for methanol, other HAPs, and other emissions. 

Operators of thermal oxidizers have no incentive to operate significantly above their 

minimum required temperature, because doing so wastes fuel. A control system will 

ensure that the operating temperature is maintained. 

The temperature monitoring requirements in Condition D.4.20 are included to ensure 

compliance with the corresponding emission limits. The stack test will determine the threehour average temperature at which the unit is meeting the emission limits. Because some 

variability in operating temperature can be expected to occur, a set minimum temperature 

with no averaging would necessarily require operation of the unit consistently above that 
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level, resulting in the wasted fuel addressed above. Therefore, IDEM determined that 

maintaining the units’ three-hour average temperature at or above the three-hour average 

temperature achieved during the stack test is an appropriate means of assuring 

compliance with the underlying emission limit. The permit requires the temperature to be 

monitored continuously and response steps to be taken whenever the three-hour average 

temperature falls below that observed during the most recent compliant stack test. 

Comment 47: The gasifier preheat burners do not have monitoring requirements:

There are five proposed natural gas-fired and SNG fuel-fired gasifier preheat burners, 

emission units EU-008A through EU-008E. Draft permit at pdf p. 94. These burners have 

very exacting emission limits. Id. at 94-95. The only compliance determination 

requirement for these limits is use of natural gas or SNG in the burners. Id. at 95. These 

are work practices, which EPA’s NSR Manual ranks last in its compliance monitoring 

hierarchy. NSR Manual at H.5. IDEM should not rely on work practices alone unless no 

other preferred monitoring technique is feasible. If this is the case, IDEM should explain 

so.

Response 47: IDEM has already conducted a top-down BACT analysis for all the emissions in the 

gasifier preheat burners as included in Appendix B of the Technical Support Document. 

The control technologies evaluated for the gasifier preheat burners are as follows:

PM, PM10 and PM2.5

(1) Mechanical Collectors (such as Cyclones or Multiclones);

(2) Wet Scrubbers;

(3) Electrostatic Precipitators (ESP); and

(4) Fabric Filter Dust Collectors (Baghouses).

Carbon Monoxide (CO)

(1) Regenerative thermal oxidation; 

(2) Catalytic oxidation; 

(3) Flares

(4) Combustion Control

Sulfur Dioxide (SO2)

(1) Flue Gas Desulfurization

(2) Low sulfur fuel

Nitrogen Oxide (NOx)

(1) Selective Catalytic Reduction (SCR)

(2) Flue Gas Recirculation (FGR)

(3) Low NOx Burner (LNB)

The RACT, BACT, LAER Clearinghouse (RBLC) was reviewed to obtain recent 

determinations for these emissions from similar processes. The search criteria used was 

Gasifier Startup Burners/ Preheat Startup Burners for all the pollutants. There was no 

BACT determination for this category listed for the time period between 03/21/2000 and 

12/30/2010, except Hyperion Energy that has a control device (Low NOx Burners) for the 

NOx emissions. The Low NOx Burners are not technically feasible for the preheat burners 

due to the design of the burners and the extremely high gasifier temperature required 

(2500 F). The burners are designed similar to a lance, or fuel nozzle, and are only used 

during preheat. 
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The burners fire into the gasifiers which do not include tubes or other heat absorbing 

material. This results in the temperature being much higher than many applications that 

incorporate low NOx burner technology. The extreme desired operating temperature is 

above the temperature that nitrogen breaks apart making NOx reduction not effective. 

The BACT concluded that there are no technically feasible add-on control technologies for 

these intermittently used, relatively small, clean fuel fired burners. Because the gasifier 

preheat burners will not have any control device, there are no monitoring conditions in the 

permit associated with emissions controls or their performance for this emission unit. 

Comment 48: Emission Unit EU-012A does not have compliance demonstration testing requirements

Feedstock that arrives by barge is unloaded to a hopper transfer point. This process 

produces fugitive particulate emissions that are identified as emission unit EU-012A. 

Draft Permit at 55. These emissions are controlled by work practices alone—wet 

suppression with a control efficiency of 90%. Id. at 56. This work practice is identified as 

Condition D.1.4(b) in the Draft Permit. Id. Compliance with Condition D.1.4(b) is 

supposed to be determined via Testing Requirement D.1.7(b). Id. at 59. This test—which 

monitors compliance with seven other conditions in addition to D.14(b)—calls for stack 

testing of a representative dust exhaust extraction system of baghouse. Id. 

Emission unit EU-012A is not equipped with either a dust extraction system or a 

baghouse. It is controlled with wet suppression only. Furthermore, this emission unit is 

not included in the list of units to which testing Requirement D.1.7(b) applies. Id. This 

means that this testing requirement cannot be used to demonstrate compliance with 

Condition D.1.4(b). IDEM must alter testing requirement D.1.7(b) to clarify that this test 

cannot be performed on this unit, specify a new test of compliance, and require that test 

for emission unit EU-012A.

Response 48: IDEM has inadventently included emission unit EU-012A in Condition D.1.7(b), this is 

a typographical error that has been corrected . Sub-condition D.1.7(b) has been revised in 

the permit accordingly. 

D.1.7 Testing Requirements [326 IAC 2-1.1-11]

..........................................................................................................................................................

(b) In order to demonstrate compliance with Conditions D.1.4(bc) - (h) and (k), not later than 

one hundred and eighty (180) days after initial startup of the first gasifier, the Permittee 

shall conduct stack testing of the emissions from a representative dust extraction system 

or baghouse or one of each if both are used controlling rail unloading to rail hoppers (EU012G/H); Barge Unloading from the Hopper to the Belt (EU-012B) and Barge Conveyor 

Transfer Points (EU-012C-F); Rail Hoppers Unloading to the Conveyor Belts (EU-012I-J) 

and Rail Conveyor Belt to the Stacker (EU-012K); Stacker Belts to the Radial Stacker 

(EU-012L-M); Transfer Systems Consisting of Hoppers and Conveyor Belts Transferring 

Feedstock from the Piles to Classification Tower (EU-012R-S), Classification Towers

(EU-012T-U), and Classification Tower to a Day Bin (EU-012V); Truck/Rail Conveyor 

Transfer Tower (EU-012Y); the truck stations unloading to a truck hopper (EU-012Z, AB 

and AC); and truck hopper unloading to the conveyor belts (EU-012AA); and one 

representative baghouse controlling the Radial Stackers to the Pile (EU-012N-O) to 

determine compliance with the PM, PM10, and PM2.5 emissions limitations, utilizing 

methods as approved by the commissioner. These tests shall be repeated at least once 

every five years from the date of the most recent valid compliance demonstration. 

Testing shall be conducted in accordance with the provisions of 326 IAC 3-6 (Source 

Sampling Procedures). Section C - Performance Testing contains the Permittee's 

obligations with regard to the performance testing required by this condition. 

The emission unit, identified as EU-012A has compliance determination requirements in 

Condition D.1.6(c) - PM, PM10 and PM2.5 Control and Condition D.1.12 - Record Keeping 

Requirements of the permit.
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Comment 50: Emission Unit EU-012Z does not have emission limitations or monitoring 

Requirements

Emission unit EU-012Z is one of three truck stations that unloads to a truck hopper. Two 

of these units, EU-012AB and EU-012AC, are included in operating condition D.1.4, PSD 

BACT for particulate matter. Draft Permit at pdf p. 57. The third unit, EU-012Z, is not 

included in operating condition D.1.4. This means that the unit is not required to employ 

either a wet dust extraction system or a baghouse, and does not have enforceable 

maximum outlet concentrations for PM, PM10, and PM2.5. Id.

IDEM has not explained its reason for omitting EU-012Z from operating condition D.1.4. 

If the omission was intentional, IDEM must explain why this operating condition should not 

apply to this unit. If it was an oversight, it must be corrected.

Response 50: IDEM inadvertently omitted one of the truck stations unloading to a truck hopper, 

identified as EU-012Z and its conditions from the permit. There are three (3) truck 

stations unloading to a truck hoppers in the permit, identified as EU-012Z, EU-012AB and 

EU-012AC, these emission units are the same units with the same applicable 

requirements. This typographical error has been corrected by including the missing 

emission unit, EU-012Z back into the permit. 

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

Pursuant to PSD/Operating Permit T 147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the Incoming 

Solid feedstock material handling and the Process area solid feedstock conveying storage, 

identified as EU-011A/B and EU-012A-AC shall be as follows:

............................................................................................................................................................

(k) The PM, PM10 and PM2.5 emissions from the Truck/rail conveyor transfer tower (EU012Y); truck stations unloading to a truck hopper (EU-012Z, AB, - and AC); and truck 

hopper unloading to the conveyor Belts (EU-012AA) operation shall be limited as follows: 

............................................................................................................................................................

Comment 51: COMPRESSOR FOR CO2:

Presumably the CO2 will be shipped out of the facility via a pipeline. The permit must 

contain an enforceable condition requiring this. If this is the case, the pipeline would need 

a compressor. The compressor engine must be included as one of the emissions units 

subject to BACT and inclusion in the ambient impacts analysis. If the compressor is 

going to be electric, than there must be an enforceable permit condition requiring that the 

compressor be electric. 

Response 51: With respect to the assertion that a permit condition is necessary to require the shipment 

of CO2 by pipeline, see Responses to Public Comments 7 and 10. The facility is designed 

to deliver at least 80% of the high-purity CO2 manufactured by the AGR to a product 

pipeline. The Clean Air Act and the state air permitting rules do not provide IDEM with the 

authority to require the manufacturer of any product to ship it in a particular manner. 

With respect to the pipeline compressor, it is not a point source of emissions and is 

therefore not included as a permitted emission unit. Fugitive emissions from the 

compressors are addressed in the permit. See Draft Permit Condition D.15.4. No permit 

condition requiring the use of an electric compressor is necessary—the permittee is not 

authorized to construct or operate a compressor that is a point source of combustion 

emissions.

Comment 52: EU-012R AND EU-012S:

The draft permit states that the two transfer systems identified as EU-012R and UE-012S 

are controlled with dust extraction systems or baghouses identified as C-012R and C012S. Draft Permit at page 2 of 6. IDEM cannot permit hypothetical or alternative 
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sources. The draft permit must identify C-012R and C-012S as a specific device. It 

cannot be one of two possible devices. Similarly, Conditions (A)(2)(a) - (k) indentify 

“control devices” C-012B - M, T, U, V, Y, Z, AB, AC, AA . IDEM cannot permit generic 

“control devices.” Rather the permit must specifically identify the type of control devices. 

Response 52: IDEM conducted a top - down BACT analysis for all these emission units comparing wet 

dust extraction systems and baghouses and in Step 3 of the analysis the percent reduction 

for both the wet dust extraction systems and the baghouses are the same.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Fabric Filter Dust Collectors (Baghouses) (>99% PM/PM10/PM2.5 Reduction);

 

(2) Wet Dust Extraction (>99% PM/PM10/PM2.5 Reduction). 

The two systems offer comparable control of greater than 99% reduction of PM, PM10 and PM2.5 

emissions. Because their percent control is the same and either would have to meet the same 

BACT emission limitation, the source can use one or the other to control the emissions of PM, 

PM10 and PM2.5, and IDEM has included in the permit compliance determination and monitoring 

requirements for both systems. In addition, IDEM believes that either of the control measures 

proposed by the source will be protective of human health and the environment. 

Fugitive Emissions

Comment 53: The Haul Roads fugitive emissions calculation is inadequate

IDEM has failed to properly calculate fugitive particulate emissions from paved roads. 

This invalidates the PM10 and PM2.5 ambient impact analysis.

With some 32,659 vehicle miles traveled (VMT) annually on paved roads, IDEM 

calculates particulate emissions at only 0.4531 tpy. TSD at pdf p. 482. These emissions 

levels are far too small to be credible. The problem can be partially explained by the use 

of unrealistic or inaccurate variables discussed below.

Fugitive dust emissions from paved roads were calculated using AP-42 Chapter 13, 

Section 2.1: Miscellaneous Sources, Paved Roads. Performing this calculation using IG’s 

variables does yield the emissions they claim (assuming 90% control efficiency): 

Table 1

Max lb/hr lb/day tpy

PM10 0.0226 0.54 0.0906

PM2.5 0.0055 0.13 0.0222

PM 0.1124 2.70 0.4531

TSD at pdf p. 482. The problem lies in IDEM’s assignment of values to the variables in 

the equation. The calculation includes the following input variables:

1. Road Surface Silt Loading, sL

2. Average Truck Weight, W

3. Truck Trips per day

4. Total Round-Trip Distance 

5. “Wet” days, P

Id. As will be shown below, the values for several of these variables are unrealistic or 

inaccurate.

Response 53: The values for input variables used in the roadway dust equation are reasonable as 

discussed in the following responses to Sierra Club Comments 54 through 68.
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Comment 54: The silt loading value is too small

Dust emissions from paved roads vary with the amount of silt on the road surface, 

referred to as “silt loading.” The TSD uses a background silt loading value of sL=1 g/m2

. 

There are several reasons why this value is inaccurate and understates the true silt 

loading value.

Response 54: Roadway silt loading is one of the parameters used in the AP-42 equation for paved 

roads. The higher the silt factor used, the higher the calculated emissions. IDEM used 

an assumed road silt loading factor of 1.0 g/m2

. The commenter suggests that this 

number is too low (and instead suggests in Sierra Club Comment 58 that it should be 9.7 

g/m2 (Steel/Iron Production mean silt from AP-42 table 13.2.1-3)). However, the value of 

1.0 g/m2 is reasonable for this particular facility for the following reasons:

• This silt factor is higher (i.e.: more conservative) than silt factors used for several 

other recent permitting actions for similar facilities.

• The IG facility is not similar to any of the industry types for which silt information is 

provided in AP42; for example IG is not an iron and steel production facility. 

Further, the industrial silt values in AP42 (for other types of industries) are from 

testing approximately 30 years ago, and are not necessarily relevant to modern 

facilities with extremely high levels of particulate controls (BACT) on all plant PM 

emission sources.

Each of the above points is discussed further below.

A review of the permitting record for other similar facilities shows their use of similar, but 

even lower silt loading factors for paved roadways. 

• Duke Edwardsport IGCC project assumed 0.4 g/m2 for their silt factor for paved 

roads;

• Cash Creek Generation SNG/NGCC permit in Kentucky used 0.4 g/m2

; and

• KY Newgas used 0.6 g/m2 for their paved roadway calculations.

The use of 1.0 g/m2 is higher than and more conservative than these other recent similar 

permits.

Regarding the appropriateness of silt factors presented in AP42, AP 42 lists default silt 

factors for public roads and typical silt loadings for certain types of industrial facilities. 

The default public road factors, depending on traffic usage range from 0.015 g/m2 to 0.6 

g/m2

. The proposed IG silt factor of 1.0 g/m2 is higher (more conservative) than any of 

these numbers. While the roads within the facility will not be public roads, the silt loading 

is a function of nature of the road, its use, and its location – not who owns it (i.e.: public 

versus industrial). 

AP-42 also lists what it calls “typical” silt contents for paved roads at several types of 

industrial facilities. However, that data is not particularly applicable to IG for several 

reasons. 

• First, none of the industries listed are similar to the proposed IG facility. 

• Additionally, even for those industries listed, a wide range of silt loadings are 

presented – without guidance on how to use that information. 
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• Also, those industrial facility silt loading values presented in AP42 Table 13.2.1-3 

are based upon road dust samples collected in the mid to late 1970's through the 

mid to late 1980's. (http://www.epa.gov/ttn/chief/ap42/ch13/bgdocs/b13s0201.pdf

(page 16)) There is no information to know if the facilities tested employed any 

measures to minimize fugitive dust of material handling or other dust sources 

nearby. It is likely that a well-managed modern facility with high degree of control 

of nearby fugitive dust sources would have significantly lower roadway silt levels 

than AP42’s thirty year old industrial roadway data. 

For additional perspective on silt values, there is the background documentation used by 

EPA to support the development of Section 13.2.1 of AP-42 and, in particular, the data 

included in Table A1-2 and Table A1-4 of the September 1997 Addendum to Emissions 

Factor Documentation for AP-42 for Paved Roads which is one part of the collection of 

background documents for this AP-42 section. 

These tables show actual silt loading values from tests on a number of industrial paved 

roads and help illustrate the wide range of results summarized in AP-42 for industrial 

facilities. Review of the data in the background document shows that a significant portion 

of the industrial roads in the studies had silt loading values equal to or less than 0.4 g/m2. 

( http://epa-sdcc.ornl.gov/pdfs/b13s02-11.pdf ) The use of 1.0 g/m2 as the silt loading 

factor in estimating fugitive PM10/PM2.5 emissions was within the range of silt loadings 

found at industrial facilities. 

Given that IG will be a new facility with BACT level control on all particulate sources, 

roadway silt deposits from nearby operations should be low and it is reasonable to 

assume that silt levels will be consistent with tests from the better/lower end of the range 

of the industrial data available.

Comment 55: Default baseline values are inadequate

AP-42 specifically states that the use of a tabulated default value for silt loading results in 

only an order-of-magnitude estimate of the emission factor for fugitive dust from truck 

traffic on paved roads, and, therefore, the collection and use of site-specific silt loading 

data is “highly recommended.” AP-42, 13.2.1-8. This is even truer for industrial sites, 

given that “the collection of site specific silt loading data from industrial roads is easier 

and safer than for public roads.” Id. at 13.2.1-9. Therefore, to be enforceable, the permit 

must require at least daily monitoring and reporting to confirm that the silt load upon which 

any final permit is based is complied with in reality. 

Response 55: The silt factor assumed in the estimation of fugitive dust from paved roadways is 

considered reasonable and conservative as discussed in response to Sierra Club 

Comment 54. It is not common to require testing of every parameter used in every 

emissions estimate. Specific to roadway silt, it is not common in permits for industrial 

facilities to require such testing. For example, no such testing has been required of the 

three gasification plants listed in response to Sierra Club Comment 54 which assumed an 

even lower silt loading than IG. The silt factor used in estimating this small emission 

source at the IG facility has a reasonable and conservative basis and does not require 

testing. 

Comment 56: In the event that a site-specific value is not available, AP-42 recommends the selection of 

an appropriate mean value from a table listing silt loadings that were experimentally 

determined for a variety of industrial roads but cautions that the quality rating of the 

equation decreases by 2 levels. The industrial roadway table provides a range of mean 

silt loading values from 7.4 to 292 g/m2

. AP-42 Sec. 13.2.1-4, Table 13.2.1-4.
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Response 56: AP42 does not “recommend” the selection of a mean value from the table of industrial silt 

loadings. It merely states that an appropriate value “may” be selected from those tables. 

However, as discussed in response to Sierra Club Comment 54, there are no appropriate 

values listed in AP42 for this specific type of facility. Instead, an appropriate value was 

selected based on review of other permits and the background test data used in 

developing AP42 as discussed in response to Sierra Club Comment 54. 

Comment 57: The chosen silt loading value is inadequate for industrial roads

The paved roads of interest here are within the boundary of an existing industrial site and 

thus are industrial roadways. Silt loading values of industrial roads are much higher, vary 

greatly, and are reported in chapter 13 of AP-42. AP-42, 13.2.1-10, Table 13.2.1-3. 

Response 57: See response to Sierra Club Comment 54.

Comment 58: IDEM used a silt loading value of 1 g/m2

, thereby considerably underestimating PM 

emissions from paved roads within the facility. TSD at pdf p. 482. A more appropriate silt 

loading value is 9.7 g/m2

, the mean silt loading of an iron and steel production facility. 

AP-42, 13.2.1-10, Table 13.2.1-3. This value is appropriate not only because it is near the

lower end of the AP-42 industrial roadway range, but also because these facilities use 

coal. If this value is used in the calculation, the PM emissions from paved roads 

increases to 7.165 tpy of PM10 and 1.759 tpy of PM2.5, an increase of more than an order 

of magnitude. If the upper end of the industrial road range of 292 g/m2 is used, which is 

appropriate for a potential to emit calculation, the emissions increase hugely to 159 tpy of 

PM10 and 39 tpy of PM2.5. 

Response 58: AP42 lists ranges silt loadings for a variety of industrial categories, including data for an 

iron and steel facility. However, as discussed in response to Sierra Club Comment 54, IG 

will not be an Iron and Steel facility and mean silt values for that industry type are not 

appropriate for characterizing IG’s emissions. Instead, an appropriate value was selected 

based on review of other permits and the background test data used in developing AP42 

as discussed in response to Sierra Club Comment 54. 

Comment 59: In no event is there any justification for the use of IDEM’s 1 g/m2

, which is well below the 

bottom of the range given in AP-42. IDEM offers no data to support its 1 g/m2

value. The 

TSD does say this is reasonably considering the control achieved through road watering. 

However, setting a low silt content based on control achieved through road watering is 

double counting because road watering is already considered in the TSD values by 

including a 90% control factor. In order words, IDEM seems to set a low silt loading value 

based on road watering and then also set a high control factor based on road watering. 

There is actually no justification for either. 

Response 59: A detailed explanation of the basis for the selection of 1 g/m2 silt loading factor is provided 

in response to Sierra Club Comment 54. Also, the commenter mischaracterizes 

statements on the emissions calculation table which mention that the silt factor is 

conservative. The factor was not double counting road watering control. The factor, as 

discussed in response to Comment 54, instead does consider the fact that other nearby 

dust sources will have planned frequent wet suppression to achieve BACT on those 

sources. The wet suppression and other BACT controls on material handling steps will 

reduce the overall ambient dust levels and reduce the dust/silt that could become 

deposited on the roadways.

Comment 60: The effect of wintertime on silt loading is ignored

In the winter, roads covered with ice and snow are treated with application of antiskid 

abrasives. For areas that experience frozen precipitation and application of antiskid 

material, AP-42 recommends a winter baseline multiplier. AP-42, 13.2.1-8. For low 

volume roads (those with Average Daily Traffic of less than 500) the multiplier is four, 
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meaning that the silt loading value should be quadrupled in the winter months. AP-42 

also suggests that each application of antiskid abrasives leads to “an additional (but 

temporary) silt loading contribution of 2 g/m2

.” Id. 

Response 60: AP42 does mention that higher silt loadings can occur “in areas that experience frozen 

precipitation with periodic application of antiskid material”. However, AP42’s reference to 

adjustments for these factors is an analysis done using studies in Denver Colorado and 

Duluth Minnesota associated with the application of sand as a wintertime antiskid 

material. (http://www.epa.gov/ttnchie1/conference/ei11/dust/cowherd.pdf). In southern 

Indiana, which has much milder winters than Colorado or Minnesota, salt is the common 

wintertime road treatment. AP42, (page 13.2.1-8) specifically states that “Ordinary rock 

salt and other chemical deicers add little to the silt loading, because most of the chemical 

dissolves during the snow/ice melting process.” Nevertheless, even with sand, the 

increase to baseline silt content is not necessarily significant compared to IG’s assumed 

silt level. Below is the Denver silt loading study from the above referenced EPA report. 

Note that even winter silt loadings on the tested roads, treated with sand for antiskid in 

winter, are below the assumed 1.0 g/m2.

Comment 61: IDEM has failed to even consider whether a wintertime baseline multiplier or an additional 

antiskid contribution is appropriate. This is particularly troubling in light of IDEM’s 

allowance of 117 “wet” days throughout the year—some of these days must include snow 

and ice. IDEM must either adjust its wintertime silt loading calculations or explain why it 

has disregarded AP-42’s recommendation that it do so.

Response 61: See response to Sierra Club Comment 60.

Comment 62: Mud and dirt trackout is ignored

Similarly, IDEM has not considered the silt loading contribution from mud and dirt 

trackout. AP-42, 13.2.1-8. There are at least some unpaved areas on IG’s cite—there 

are two bulldozers making more than 500 trips a day on unpaved roads. Application at 

pdf p. 227-30. These bulldozers are used to maintain the feedstock pile and help feed the 

hoppers. Application at pdf p. 11, 15. If these bulldozers ever leave the unpaved area, or 

if any other vehicles ever drive into the unpaved area, a track out point is created. 

Response 62: The commenter has suggested that since there are unpaved areas at the IG facility, and 

since vehicles may occasionally travel on those unpaved areas and return to the paved 

roads, that this constitutes a trackout point that should be accounted for in the roadway 

emissions calculations.
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AP42 does suggest an adjustment to the PM emissions calculations from public paved 

roadways for mud/dirt trackout from “active construction sites” due to the significant mud 

and dirt that can be carried onto public roads by construction traffic. This suggestion is 

for use by states/counties in estimated and modeling regional emissions for regulatory 

purposes. AP42 also suggests evaluating other types of trackout to public roads (i.e. dirt 

roads in agricultural areas joining public paved roads.) However, AP42 is not specific 

about how to address the less significant trackout from sources other than active 

construction sites. Also, AP42 makes no mention of trackout in the context of industrial 

facilities emissions calculations. 

Specific to the IG facility – the plant will not contain an active construction site once it 

begins operation. When the plant is in operation, the proposed permit requires that all 

haul roads be paved, and the permit requires prompt cleanup of any spilled material. The 

paving of all haul roads will eliminate dirt trackout effects from haul vehicles. Also, the 

requirement to promptly cleanup spilled material (permit condition D.12.4.3) would logical 

extend to significant deposits of any type on the road including occasional trackout from 

non-routine activities. For these reasons, trackout impacts are expected to be minimal 

and to be reasonably accounted for in the silt factor of 1.0 g/m3 which, as discussed 

previously (response to Comment 54), is an appropriate and conservative value for this 

type of facility.

Comment 63: It may be that Indiana Gasification intends to keep its bulldozers in unpaved areas and its 

trucks on paved roads at all times. If this is IG’s intent, these limits on vehicular traffic 

must become enforceable permit conditions. If IG does intend to allow vehicles to travel 

on both paved and unpaved roads—which seems much more likely—then mud and dirt 

trackout must be factored into the haul roads fugitive emissions calculations. IDEM did 

not do this, and rather than making improbable assumptions about intended vehicle 

traffic, we conclude that IDEM simply ignored the silt loading contribution from mud and 

dirt trackout.

Response 63: There is no routine reason for the bull dozers used to manage the stockpiles to travel or 

cause “track-out” on paved roadways. Also, as explained in response to Sierra Club 

Comments 54 and 62, the conservative silt factor and existing permit language 

adequately address this issue.

Comment 64: The vehicle miles traveled calculation is unsupported and likely too small

IDEM has also not accounted for all of its truck traffic. In addition to coal and coke 

feedstock, the plant will use aqueous ammonia in its SCRs, diesel and gasoline to power 

its generators and vehicles, and glycol for use in its absorbers. The plant will be selling 

sulfuric acid and argon. Draft Permit at pdf p. 1. All of these incoming and outgoing 

materials must be moved somehow, but the permit makes no consideration for any of 

them in its calculation of vehicle miles traveled. IDEM has only the most general 

description of truck traffic. Draft Permit at pdf p. 156. There is no comprehensive 

explanation of how many trucks there will be, what they weigh, what they are used for, 

and how often they will be used. Without such an explanation, the haul roads particulate 

emissions calculation is inadequate.

Response 64: The emissions calculations for haul vehicles on paved roadways are presented in the TSD 

on pages 576 and 577 of the pdf and show the number of truck trips, assumed weight of 

the trucks and vehicle miles traveled. These calculations represent three categories of 

trucking activities: 1) 187.6 trucks/day for truck receipts of coal or coke feedstocks; 2) 51.7 

trucks/day for truck hauling of byproduct slag; and 3) 31 trucks/day for other miscellaneous 

trucking, as a conservative contingency to cover other trucking activities mentioned by the 

commenter. The estimate for miscellaneous trucking addresses trucking of other 

materials such as sulfuric acid, diesel, gasoline, ammonia, argon, methanol, slag filter 

cake, cooling tower chemicals, glycol, and trash.
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The last of these categories was included to address other miscellaneous trucking 

activities mentioned by the commenter. This 31 truck/day contingency category is 

presented together with, and as part of, the Slag Trucking emissions calculation TSD page 

577. This conservative contingency, together with conservative estimates for coal/coke 

trucking and slag handling are more than adequate to address all the facilities trucking 

activities. 

The permit assumptions are overall very conservative. For many days, actual truck vehicle 

miles traveled will be significantly less than the daily maximum estimated. For example, 

the facility will, at times, receive feedstock coal or coke by either rail or barge instead of by 

truck. Likewise, the permit assumptions for trucking of slag included double handling all 

the facility slag production by transporting it to a temporary storage pile. In practice, most 

of the time slag is expected to be hauled directly offsite to customers (which shortens the 

on-site trucking distance and avoids double handling/double trucks.) Also, product sulfuric 

acid and argon are expected to be shipped primarily by rail.

Comment 65: The draft permit does not have enforceable conditions which lead to 90% 

control efficiency

The TSD emission calculations of fugitive PM, PM10 and PM2.5 assume 90% of these 

emissions. However, the draft permit does not contain any enforceable emission limits to 

ensure that 90% controls are achieved, much less continuously achieved. IDEM has 

declined to use any formal controls at all to reduce particulate emissions from haul roads. 

In its application, IG gave this description of its controls:

These emissions are very small, even uncontrolled result in only 0.53 tons/yr. Because of 

the very small amount of emission, no formal controls are proposed beyond just good 

housekeeping, i.e.: cleaning off the roadways of any material spilled or other road 

cleaning if visible emissions are observed.

BACT for PM10 is proposed to be good housekeeping of roadways by cleaning roads if 

visible emissions are observed or if material is spilled onto roadways.

Application p. 5-36 pdf 82. As explained above, emissions from haul roads are “very 

small” because they have not been properly calculated. 

Response 65: The originally submitted permit application was amended to increase the amount of truck 

traffic and the BACT analysis was amended to require the use of wet suppression to 

achieve 90%. Permit conditions requiring controls on haul roads are in D.12.4, D12.5 and 

D.12.6. For additional information about proposed improvements to these permit 

conditions see response to Sierra Club Comment 67.

Comment 66: IDEM assumes these “good housekeeping” practices will achieve a 90% control factor—

“the highest specified in the [RACT/BACT/LAER Clearinghouse] for such sources.” TSD 

at pdf p. 774.

Response 66: See response to Sierra Club comment 67.

Comment 67: IDEM has not adequately explained how it arrived at a control factor of 90%. Wet 

suppression is the only control to be used on the paved roads, and it is subject to the 

following exceptions: 

• Rainfall of 0.1 or more inches has accumulated during the 24-hour period prior to 

the scheduled treatment,

• It is raining or snowing at the time of the scheduled treatment,
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• The ambient air temperature is at or below 32 degrees, or forecast to be so within 

the next 24 hours, 

• A significant portion of the haul road is covered by ice or snow or a majority of the 

road remains wet from recent precipitation or the previous watering, or

• The road is not being used as a haul road on that day.

Draft Permit at pdf p. 109. The 30-year mean temperature in southwest Indiana in 

January is 34°F. Indiana State Climate Office, (available at 

http://climate.agry.purdue.edu/climate/index.asp). This means it will be below freezing 

nearly half the time. IDEM also assumes 9-10 days of precipitation each month. Indiana 

Gasification could go days or even weeks without any wet suppression at all, and yet 

IDEM has assumed it 90% control efficiency even for those periods of time when the 

permit does not require wet suppression.

Response 67: Even uncontrolled paved roadway dust emissions are very small. Uncontrolled, the 

emissions from paved haul roads are conservatively estimated to be no more than 1.3 

tons/yr PM10, and 0.3 tons/yr PM2.5 before control. With controls, emissions are 0.13 

tons/yr PM10 and 0.03 tons/yr PM2.5. The permit requirement regarding the use of wet 

suppression to achieve 90% control effectiveness was based on the BACT review of other 

recently permitted facilities, including ones with the use of wet suppression with a control 

efficiency of 90%. (e.g. 2008 Ohio River Clean Fuels RBLC OH-0317, 2010 Cash Creek 

Gasification KY permit V-09-006). In addition to the use of wet suppression, roadway dust 

will be controlled by good housekeeping (prompt cleanup of spills), and speed limits. Upon 

further review, several revisions to the permit conditions are appropriate to add clarity and 

reduce the amount of time when the allowable exceptions to the use of wet suppression

would be in effect, and either vacuum sweeping or wet suppression will be required when 

the ambient air temperature is below 32°F. 

In the originally proposed permit, wet suppression treatments would not have been 

required if there had been a threshold amount of rain in the past 24 hours. This permit 

condition has been amended to excuse treatments only if the roadway remains wet from a 

previous precipitation or treatment. This avoids the need to quantitatively monitor 

precipitation, while still recognizing the control benefits of natural wet suppression.

Also, in the originally proposed permit conditions, wet suppression would not have been 

required when ambient temperatures were forecast to be below 32°F in the next 24 hours. 

Although this recognized the safety sensitivities of wetting a road in possible freezing 

conditions and the fact that fugitive dust is much less mobile in freezing conditions, this 

exemption is being modified to exempt wet suppression only when the actual ambient air 

temperature at the time of the scheduled wet suppression is below 32°F, and to require 

vacuum sweeping in lieu of wet suppression if the Permittee takes advantage of the 

temperature exemption. Paved haul road wet suppression when the actual temperature is 

below 32°F is not deemed appropriate or necessary for the following reasons.

• There are practical and safety limitations of using wet suppression on paved 

roadways in freezing temperatures.

• In freezing conditions, there is a natural mitigating effect on the mobility of surface 

fugitive dust from project and regional sources. For example, a review of ambient 

particulate monitoring data shows a significant drop in peak ambient particulate 

levels in freezing conditions. Dust is generally not as much of a concern in 

freezing conditions.

• A new permit condition requiring vacuum sweeping when wet suppression is not 

employed due solely to freezing temperatures. 

• A new permit condition limiting vehicle speeds will afford some additional control, 

including those times when no wet suppression is used.
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• A review of past temperature data for the area (Evansville Met data for 2006-2009) 

shows that temperatures consistently below 32 F are infrequent in this area. In 

fact, less than 1% of the time the temperature gets that low without either 

precipitation (which would provide natural mitigation) or warmer temperatures 

within the past 48 hours (which would allow the use of wet suppression). 

Accordingly, the exemption from watering at temperatures below 32 degrees F 

would not result in significant periods of no wet suppression. 

• Although a portion of the benefit of wet suppression is the wetting of surface dust 

particles to limit their mobility, an additional benefit is that some roadway dust is 

washed off the roadway. This benefit, from an active and ongoing wet 

suppression program, would continue even during brief interruptions due to cold 

temperatures. 

Additionally, in considering the appropriateness of allowing infrequent exceptions to some 

roadway dust control measures, it is noteworthy that the ambient air quality standards for 

particulate are probabilistic standards, which means that a few values above the standard 

would not constitute an exceedance of the standard. The very conservative assumptions 

in the permit review provide adequate assurance that the project will not cause or 

contribute to a violation of the NAAQS. For example:

• The project air quality analysis assumed that the worse-case paved haul road 

emissions occur on a day when all other project sources are at their worst case 

emissions rates, and the background ambient levels are at their worst case levels, 

and wind conditions are present which result in the worst case dispersion 

characteristics. This is an extremely unlikely and conservative scenario given the 

actual variability of haul road traffic, wind speed and direction, and background 

ambient concentrations.

• As discussed in response to Sierra Club comment 64, the total truck traffic and 

vehicle miles travelled assumed in the permit evaluation is very conservative. 

Actual truck traffic on many days will be much less than the level assumed in the 

permitting. Even no roadway controls at such times would result in no more 

emissions than were assumed in the permitting.

• Also, as mentioned above, even in the brief absence of wet suppression 

treatment, some dust control is achieved by good housekeeping, speed limits, 

continuing benefits from past wet suppression, and natural mitigation from the subfreezing temperatures. 

Therefore, the Section D.12 has been revised in the permit accordingly. 

D.12.5 Compliance Determination Requirements

To demonstrate compliance status with Condition D.12.4 - PM, PM10 and PM2.5 PSD BACT: 

(a) Wet Suppression for roadway dust control shall be performed on paved Haul Roads, 

except when:

- Rainfall of 0.1 or more inches has accumulated during the 24-hour period prior to the 

scheduled treatment,

- It is raining or snowing at the time of the scheduled treatment,

- The ambient air temperature is at or below 32 degrees, or forecast to be so within the 

next 24 hours,

- The subject A significant portion of the haul road is covered by ice or snow or a majority 

of the road remains wet from recent precipitation or the previous wet suppression

watering, or 

- The road is not being used as a haul road on that day.

If the ambient air temperature is below 32oF at the time of a scheduled wet suppression 
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treatment, the permittee may clean the roadway dust with a vacuum sweeper in lieu of the 

wet suppression treatment.

(b) Compliance shall be demonstrated for each active haul road using records of haul road 

usage and control measures and. The frequency of required roadway dust control 

treatments for haul roads with between one (1) and ten (10) truck trips per day 

shall be at least every other day, unless a treatment is not required for one of the 

reasons under (a) above. For haul roads with more than 10 trucks per day, the 

frequency shall be sufficient to achieve 90% control based on the following formula 

or an equivalent:

Control Efficiency = 96 – (0.263 * (T/C))

Where:

Control Efficiency = percent control efficiency

T = Daily truck trips on roadway (truck trips/calendar day)

C = Number of Wet Suppressionroadway dust control treatments per calendar day (watering 

events / calendar day)

For the purposes of this formula, if at the time of a scheduled roadway dust control 

treatment, the treatment is not required for one of the reasons under (a) above, such an 

event shall be counted as a roadway dust control treatment.

(c) Haul truck speed limits on haul roads shall be posted as 15 miles per hour or less.

Compliance Monitoring Requirements 

D.12.6 Ambient Temperature Monitoring

To demonstrate the compliance status with Condition D.12.5, the Permittee shall 

maintain an ambient temperature monitor when ambient temperatures may drop 

below 32o

F.

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

D.12.67Record Keeping Requirements

To document the compliance status with Conditions D.12.4 - PM, PM10 and PM2.5 PSD BACT and 

Condition D.12.5 – Compliance Determination Requirements, the Permittee shall maintain the 

following daily records for haul roads:

(1) The number of trucks on the haul road each calendar day.

(2) The date, approximate time, and type of each roadway dust control treatment.

(3) If a treatment is not required and not performed pursuant to D.12.5(a) skipped, 

records shall be maintained documenting of the reason (i.e.: the ambient 

temperature, precipitation, recent rainfall, road conditions observation,( snow

already wet roads, haul road not used, etc.).

Comment 68: Even IDEM’s own formula for calculating control efficiency demonstrates that this figure is 

unrealistic. The formula is:

Control Efficiency = 96 – (0.263*(T/C)

Where: T = daily truck trips; 

C = Number of wet suppression treatments per day.
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Draft permit at pdf p.110. This formula shows that, with IG’s average of 186.8 truck trips 

per day, there will be eight applications of wet suppressant needed each day to maintain 

90% control efficiency:

 Control Efficiency = 96 – (0.263*(186.8/8)

= 89.9%

IDEM cannot reasonably expect to achieve 90% control efficiency if it excuses wet 

suppression so frequently. There is also no explanation of how Indiana Gasification will 

determine if a tenth of an inch of rain has accumulated in the last 24 hours, what 

constitutes a “significant portion” of ice or snow coverage, what constitutes the road 

“remain[ing] wet,” or how IG will determine and enforce which days the road will not be 

used. IDEM cannot simply rely on vague assurances and assume 90% control efficiency 

despite mathematical evidence that it cannot be achieved. 

Response 68: As discussed in response to Sierra Club comment 67, the permit language is being 

changed to allow fewer exceptions from the requirement for controls and remove the need 

for certain potentially subjective terminology. 

Comment 69: Bulldozer controls are overestimated and unenforceable

IDEM also assumed 90% control efficiency for its bulldozer activity. Draft Permit at pdf p. 

465. IDEM cannot assume 90% control efficiency without an enforceable permit limit to 

that effect. IDEMs permit limits for the bulldozers are just as inadequate as those for the 

haul roads. Draft permit at pdf p. 58.

Response 69: The coal/coke pile dozer permit conditions D.1.4.(i) and (j), D.1.6 (d), and D.1.12(e) require 

the use of wet suppression. Similarly, permit conditions D.13.4, D.13.5 and D13.6 require 

wet suppression control of the slag pile dozer activities. The assumption of 90% control 

efficiency is reasonable for regular wet suppression of such activities. Aggregate piles will 

retain moisture longer than, for example, paved roadways, allowing less frequent watering 

to achieve the same level of control

The Permittee has agreed to certain revisions related to the conditions D.1.6(d) and 

D.13.5. Below is revised language for those and related conditions. This language 

narrows the provision that allows the permittee to delay wet suppression if is raining or 

snowing or if temperatures are below freezing, which provision is appropriate for the 

following reasons. 

• If it is raining or snowing, natural wet dust suppression is achieved. 

• If temperatures are below freezing, it is not reasonable to require water sprays 

onto coal/coke storage piles. Also, at freezing conditions, the moisture present in 

the coal/coke (naturally present and from previous wet suppression) will help hold 

available dust particles together, significantly decreasing their likelihood to become 

airborne. 

• The emissions mitigation effect of freezing weather is more significant for the 

coal/coke/slag piles than it would be for a paved roadway because aggregate piles 

will retain moisture much longer, allowing less frequent watering to achieve the 

same level of control and allowing enhanced mitigation benefits in freezing 

temperatures. This is one reason for differences in the permit conditions for dozer 

activities on piles versus those for truck traffic on paved haul roads. 

Therefore, the Sections D.1 and D.13 have been revised in the permit accordingly. 
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D.1.6 PM, PM10 and PM2.5 Control [326 IAC 2-7-6(6)]

...........................................................................................................................................................

(d) In order to ensure compliance with Conditions D.1.4(i) and (j), wet suppression using water 

sprays shall be used daily on active areas of the pile (areas with dozer activity and /or new 

feedstock being loaded). The non-active areas of the pile will have wet suppression 

applications weekly.

Wet suppression treatments of feedstock piles may be delayed for 24 hours until the next day

whenever:

- Rainfall of 0.1 or more inches has accumulated during the 24-hour period prior to 

the scheduled treatment,

- It is raining or snowing at the time of the scheduled treatment, or

- The ambient air temperature is at or below 32o

F degrees, or forecast to be so 

within the next 24 hours,

- The subject Dozer activity areas are is covered by ice or snow or standing water, 

or

- The dozers are not being used on that day. 

............................................................................................................................................................

D.1.12 Ambient Temperature Monitoring

To demonstrate the compliance status with Conditions D.1.6(c) and (d), the Permittee 

shall maintain an ambient temperature monitor when ambient temperatures may drop 

below 32o

F.

D.1.123Record Keeping Requirements

............................................................................................................................................................

(d) To document the compliance status with Conditions D.1.4(b) - PM, PM10 and PM2.5 PSD 

BACT and D.1.6(c) - PM, PM10 and PM2.5 Control, the permittee shall maintain the 

following daily records:

- The date of each unloading operation.

- A log indicating whether or not water sprays were used and whether or not the 

level in the hopper ever exceeded the height of the sides of the barge unloading 

hopper during each unloading.

If a treatment is not required and not performed pursuant to D.1.6(c) skipped, 

records shall be maintained documenting of the reason (i.e.: the ambient temperature or 

, precipitation rainfall, etc.).

(e) To document the compliance status with Conditions D.1.4(i), and (j) - PM, PM10 and 

PM2.5 PSD BACT and D.1.6(d) - PM, PM10 and PM2.5 Control, the Permittee shall 

maintain the following daily records :

- The date and approximate time of each feedstock pile watering treatment.

- If a treatment is not required and not performed pursuant to D.1.6(d) 

skipped, records shall be maintained documenting of the reason (i.e.: the 

ambient temperature, precipitation, or the subject area is covered by ice or 

snow or standing water.recent rainfall, snow, etc.

............................................................................................................................................................
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D.13.5 Compliance Determination Requirements

To demonstrate compliance status with Condition D.13.4 - PM, PM10 and PM2.5 PSD BACT, wet 

suppression shall be applied weekly to the entire slag storage pile/pad. Dust control is aided by 

the fact that the incoming slag is inherently wet. Additional wet suppression should be applied if 

any visible emissions are observed. 

Wet suppression treatments of the slag pile area may be delayed 24 hours until the next day

whenever:

- Rainfall of 0.1 or more inches has accumulated during the 24-hour period prior to the

scheduled treatment,

- It is raining or snowing at the time of the scheduled treatment,

- The ambient air temperature is at or below 32 degrees o

F, or forecast to be so within

the next 24 hours,

- The majority of the pile is covered by ice or snow, or

- If tThere is no material stored and no vehicle traffic at the temporary slag storage area.

Compliance Monitoring Requirements 

D.13.6 Ambient Temperature Monitoring

To demonstrate the compliance status with Condition D.13.5, the Permittee shall 

maintain an ambient temperature monitor when ambient temperatures may drop 

below 32o

F.

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

D.13.67Record Keeping Requirement

To document the compliance status with Conditions D.13.4 - PM, PM10 and PM2.5 PSD BACT and 

D.13.5 – Compliance Determination Requirements, the Permittee shall maintain the following 

weekly records:

(1) The date and approximate time of each feedstock pile watering treatment.

(2) If a treatment is not required and not performed pursuant to D.13.5 skipped, 

records shall be maintained documenting of the reason (i.e.: the ambient temperature, 

precipitation, or there is no material stored and no vehicle traffic at the temporary 

slag storage area. recent rainfall, snow, etc.)

Monitoring and Controls

Comment 70: Compliance Monitoring is not adequate to ensure Enforceability

Permit limits are enforced through monitoring. The hierarchy for specifying monitoring to 

determine compliance is: (1) continuous direct measurement where feasible; (2) initial 

and periodic direct measurement where continuous monitoring is not feasible; (3) use of 

indirect monitoring, e.g., surrogate monitoring, where direct monitoring is not feasible; and 

(4) equipment and work practice standards where direct and indirect monitoring are not 

feasible. U.S. EPA, New Source Review Workshop Manual (“NSR Manual”), Draft, 

October 1990 (available at http://www.epa.gov/ttn/nsr/gen/wkshpman.pdf), at H.5.

For the reasons explained below, IDEM has ignored EPA’s monitoring compliance 

hierarchy.

Work Practices do not constitute enforceable emissions limits

Equipment and work practice standards are not numerical emissions limits and are not 

enforceable at all times. They are the least preferred method of compliance monitoring 

and should be avoided when any other monitoring technique is feasible. IDEM proposes 
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to control emission from at least six emissions units with work practices alone (EU-012A, 

EU-012P, EU-012Q, EU-012W, EU-012X, FUG-ROADS). IDEM should require more 

accurate monitoring techniques, or explain why other techniques are not feasible for each 

of these six units.

Response 70: IDEM has appropriately evaluated the monitoring options for each emission unit. 

Generally, many emission units do have requirements in the permit for CEMS, 

periodic testing, or surrogate monitoring such as pressure drop or continuous 

temperature monitoring. 

Regarding the six units specifically identified in this comment, these are all fugitive 

particulate emissions sources for which many of the types of monitoring identified by the 

commenter are not possible. Also, the work practice standards for these units have been 

identified as BACT, and no more stringent controls were identified. The requirements 

imposed on these units are consistent with requirements for fugitive sources at other 

facilities and are appropriate for addressing fugitive dust.

No revisions to the draft permit are required as a result of this comment.

Comment 71: Parametric monitoring is inadequate 

Parametric monitoring techniques measure proxies—such as temperature, pressure, or 

flow rates—to estimate emissions. The NSR Manual prefers continuous direct 

measurement or initial and periodic direct measurement over parametric monitoring. 

NSR Manual at H.5. Parametric monitoring should only be used when these other, more 

accurate techniques are not feasible. At least thirty-four emissions units rely on 

parametric monitoring (EU-012B, EU-012C, EU-012D, EU-012E, EU-012F, EU-012G, 

EU-012H, EU-012I, EU-012J, EU-012K, EU-012L, EU-012M, EU-012T, EU-012U, EU012V, EU-012Z, EU-012AB, EU-012AC, EU-012AA, EU-012Y, EU-012N, EU-012O, EU012R, EU-012S, EU-011A, EU-011B, EU-001, EU-002, EU-015A, EU-015B, EU-032, EU024, EU-025, EU-033). IDEM should follow EPA’s compliance monitoring hierarchy and 

require continuous direct monitoring or initial and periodic direct monitoring where feasible 

for these 34 emissions units.

Response 71: IDEM requires either direct emissions measurement or parametric monitoring for all 

emission units that have control device(s) in the permit. The type of monitoring used for 

each source and pollutant has been selected based on consideration of the magnitude of 

the emissions its expected variability, and the relative cost of the monitoring options. The 

permit also includes testing requirements for most of the emission units, except for the 

syngas hydrocarbon flare and acid gas flare that are extremely difficult to test. Stack 

testing of the ZLD Spray Dryer for NOx emission is not included because of its small size 

and low emissions rate.

The schedule of compliance testing, along with applicable parametric monitoring are

sufficient to provide the information needed to evaluate continuous compliance with 

the emission limits at this source. Furthermore, all parametric monitoring requires that 

Indiana Gasification, LLC respond to and correct any deviations from the prescribed 

monitoring ranges. No revisions to the draft permit are required as a result of this 

comment.

Comment 72: Direct periodic monitoring has not been used where feasible

IDEM has failed to require sufficient direct periodic monitoring where feasible. It requires 

stack testing only once every five years for the Acid Gas Removal Units, Draft Permit at 

pdf p. 79, the Wet Sulfuric Acid plant trains, Id. at 86, and the ZLD Spray Dryer, Id. at 99. 

Stack testing is only required once for the natural gas-fired auxiliary boilers during the 

lifetime of the facility. Id. at 91. The permit should be revised to strengthen these and all 

other monitoring provisions. 
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Response 72: IDEM believes all permit terms and conditions are correct and the permit has sufficient 

testing and monitoring requirements to ensure compliance given the size of the emission 

units. Continuous or daily monitoring is required for many operating parameters at this 

facility, as shown in the TSD section called “Testing Requirements” (TSD page 40 of 43). 

Much of the testing required by the permit will also be used to set compliance monitoring 

parameters that can then be monitored continuously, as in the case of the operating 

temperature for the RTO, or daily, as in the case of pressure drop across the scrubber for 

the WSA. However, IDEM may require compliance testing at any specific time when 

necessary to determine if these facilities are in compliance. If testing is required by IDEM, 

compliance shall be determined by a performance test conducted in accordance with 

Section C - Performance Testing. No revisions to the draft permit are required as a result 

of this comment. See also the response to Public Comment 29 regarding stack testing 

requirements for the auxiliary boilers.

Comment 73: Visible emissions notations are inadequate to monitor enforceable 

emission limits

IDEM proposes to monitor compliance for no less than 27 emission units with Visible 

Emissions Notations. Draft permit at pdf p. 60-61, 100. This requires a trained plant 

employee to record once a day whether emissions are “normal or abnormal.” Id. at 60. 

“Normal” is defined as “those conditions prevailing, or expected to prevail, at least 80% of 

the time the process is in operation, not counting startup or shutdown time.” Id.

In its New Source Review Manual, EPA explains that emission and operational limits 

“must be clearly expressed, easily measurable, and allow no subjectivity... Such limits 

should be of a short term nature, continuous and enforceable.” NSR Manual at H.5 

(emphasis added). Visible emissions notations are not adequate to monitor enforceable 

emission limits for several reasons.

First, the testing is subjective. Different observers could make different notations. This 

problem would be cured if a recognized and repeatable test method were used to confirm 

the presence or absence of visible emissions and to quantify their magnitude. At a 

minimum, the permit should be revised to require a Method 9 test once a day during 

maximum operations.

Response 73: All of the BACT limits are numerical limits subject to stack testing to determine compliance, 

as already required by the permit. As such, the suggested Method 9 (or other) 

quantification of the opacity level would not be relevant and would not provide meaningful 

information for assuring compliance beyond what the permit currently requires. 

The visible emission notation requirements are included in the permit as compliance 

monitoring, used to assure compliance between stack tests. The Method 9 training or its 

equivalent is not a requirement for making an abnormal or normal visible emissions 

determination, and Method 9 observations also have the potential to vary with the 

observer. IDEM requires that the employee be trained in the appearance and 

characteristics of normal visible emissions for that specific process. 

It is also important to understand that visible emissions monitoring is a complement to 

other requirements. In the case of the failure of a single compartment baghouse or a wet 

dust extraction system, the associated process (and/or feed) must be shut down 

immediately. Further, depending on the control device, the permit requires pressure drop 

and/or flow rate monitoring, and the permit requires the Permittee to take reasonable 

response steps if abnormal emissions are observed or the pressure drop or flow rate is out 

of range. IDEM believes these monitoring requirements are sufficient enough for the 

source to comply with the limit given in the permit.
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Comment 74: Second, the permit does not require that a relationship be established between visible 

emissions and the underlying PM/PM10 emission rates. Many of the emissions units 

monitored via visible emissions notations have very exacting emissions limits. See, e.g., 

Draft Permit at pdf p. 90-91 (emission limits for ZLD Spray Dryer). These emission limits 

cannot be effectively monitored with such a subjective technique.

Response 74: The visible emission notation is not meant to exact a correlation with any emission limit.

The visible emission notation is an indicator of continuous compliance to the limit given in 

the permit. Visible emissions observations and notations are designed to identify and 

correct potential problems with equipment or operating practices. While visible emissions 

observations serve this purpose well, it is generally not feasible to establish a direct and 

consistent relationship between visible observations and the emission rate of the source. 

Overall, monitoring the visible emissions and the operating parameters of control devices 

such as baghouses and dust extraction systems provides assurance that the units are 

operating similarly to when their emissions were established or tested. 

Comment 75: Third, the definition of “trained employee” does not require a recognized and certified 

training program. Draft Permit at pdf p. 60. The permit requires only that the employee 

has worked at the plant for a month and “has been trained in the appearance and 

characteristics of normal visible emissions for that specific process.” Id. at 60. The 

permit should be revised to require that the “trained employee” successfully complete a 

training course equivalent to certification in Method 9.

Response 75: The Method 9 training or its equivalent is associated with determining a quantitative 

estimate of visible emissions and goes beyond this aspect of the permit. As a result,

Method 9 training is not a requirement for making an abnormal or normal visible emissions

determination. IDEM requires that the personnel be familiar with the operation at the 

source and what is normal or abnormal relative to visible emissions.

Comment 76: Fourth, the permit does not identify the information that would be recorded beyond a 

notation as to whether the emissions are normal or abnormal. Id. If these conditions are 

retained, they should be revised to require recording of the date, time of day, and weather 

conditions.

Response 76: According to Condition D.1.12(a), the source is already recording the day (date) of the 

visible emission notation reading. If there is an abnormal reading, the source will take 

response steps to correct the situation and record the steps taken to correct the out of 

range reading. The time of day and the weather conditions are not required. Therefore, 

there is no change to the permit condition.

Comment 77: Fifth, the observations are only made during normal daylight hours. This excludes all

non-daylight hours, excluding from compliance many operating hours. This does not 

assure continuous compliance.

Response 77: The proper and accurate visible emission notation can only be taken during daylight. Any 

reading during non-daylight hours will not be accurate. Moreover, this reading is not 

feasible after dark. The source is already monitoring the pressure drop of the baghouse so 

this will be another indicator that the source is complying with the limit given by IDEM

BACT Analysis

Comment 78: The BACT analysis for the acid gas flare is incomplete and unsupported for several 

reasons. BACT for the flare is a flare minimization plan and flare best practices. Draft 

Permit at pdf p. 70-71. Flare minimization requires an investigation of the cause of the 

flaring event. Flare best practices require operation with no visible emissions, operation 
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with a flame at all times, and continuous monitoring for the presence of a flame. There is 

no discussion of emission rates or limits for the flare. 

Furthermore, IDEM did not make any attempt to set BACT for the flare specifically for 

periods of shutdown and malfunction. Periods of SSM cannot be ignored under the PSD 

program. BACT requirements, like PTE requirements, apply to SSM emissions. See, 

e.g., In re Tallmadge Generating Station, Order Denying Review in Part and Remanding 

in Part, PSD Appeal No. 02-12, slip op. (EAB May 21, 2003) (“BACT requirements cannot 

be waived or otherwise ignored during periods of startup and shutdown.”) Exemption of a 

source “from any concentration limits during startup and shutdown,” including short-term 

limits, is “potentially a...serious concern.” See In re Indeck-Niles Energy Center, PSD 

Permit No. 364-00A; PSD Appeal No. 04-01, 2004 EPA App. LEXIS 36, n. 9 (EAB Sept. 

30, 2004) (emphasis added).

Response 78: IDEM’s draft permit does impose BACT requirements to the acid gas flare that pertain at 

all times, including periods of start-up, shutdown and malfunction. See Conditions D.3.4 

through D.3.7 of the Draft Permit. In its BACT analysis supporting the draft permit, and 

consistent with the top-down approach to evaluating potential BACT control alternatives, 

IDEM evaluated BACT for flare emissions from the acid gas flare and identified the 

technically feasible BACT control alternatives, which are, depending on the pollutant at 

issue: flare design and proper operation; and/or process flaring minimization practices. 

See TSD pages 22-33 of 181. As a result, IDEM is specifically requiring that IG implement 

these measures as part of detailed work practice standard that will apply to the acid gas 

flare and associated equipment at all times. Specifically, the Draft Permit requires that IG 

implement and comply with the following BACT requirements: 1) Flare minimization plan; 

2) Root cause investigation and corrective action of all malfunction events; 3) Flare “best 

practices,” including designing and operating the flare to avoid visible emissions (except 

for periods not to exceed 5 minutes every two hours), operating the flare with a flame 

present at all time, and continuously monitoring the flare; and 4) Preventative 

Maintenance Plan. 

IDEM, however, is not requiring acid gas flare emission limits or rates during normal 

operation, start-up or shutdown because there are not expected to be any emissions from 

the acid gas flare at those times, [except for pilot emissions]. As IG stated in its permit 

application, the acid gas flare is not expected to “have gas vented to it during normal 

operations or normal facility startups or shutdowns.” Permit Application at p. 5-22. See 

also TSD pp. 23, 26, 29, 32 (“No non-emergency flaring is anticipated.”) Accordingly, 

IDEM need not require that a specific emission rate or limit apply as there will be no 

expected emissions during those times. Further, the BACT analysis indicates that of the 

facilities reviewed with a similar acid gas flare, no other facility has any emission limits on 

startup, shutdown, or malfunctions. 

IDEM also is not imposing specific emission limits or rates for malfunction event-related 

emissions. Given the inherently unpredictable nature of malfunction events and the 

inability to estimate associated emissions, numeric limits are infeasible. Further, BACT 

review anticipates the consideration of work practices as an appropriate control 

alternative. See, U.S. EPA, Draft New Source Review Workshop Manual, p. B.10 (1990) 

(emphasis added). As discussed above, IDEM is requiring IG to implement extensive 

BACT work practice requirements, including the implementation of flare emission 

minimization measures and the identification and correction of the root cause of any 

malfunction events contributing to acid gas flare emissions. This is again consistent with 

BACT requirements for other similar sources.
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Footnote Comments

Comment 79: (a) We note that Section A and Section D claim that the information describing the 

source in Conditions A.1 through A.3 is not an enforceable condition. See Draft 

Permit page 14. However, the 0.015 lb/hr emission rate is based on the 

assumption that the emergency diesel generators are 1,341 hp. TSD pdf page at 

427. If this is true that the description of the emergency diesel generators in the 

draft permit as 1,341 hp units is not an enforceable condition, then even the 0.015

lb/hr emission rate would be invalid because IG could install a larger diesel 

generator and have higher mass emissions than what is used in the modeling. 

This is true for all of the mass emission rates for other emission units determined 

based on the size of the emission unit, e.g. mmbtu/hr or hp, used in the modeling. 

(b) We note that Section A and Section D claim that the information describing the 

source in Conditions A.1 through A.3 is not an enforceable condition. See Draft 

Permit page 14. However, the 14.58 lb/hr emission rate is based on the 

assumption that the emergency diesel generators are 1,341 hp. TSD pdf page at 

427. If this is true that the description of the emergency diesel generators in the 

draft permit as 1,341 hp units is not an enforceable condition, then even the 14.58

lb/hr emission rate would be invalid because IG could install a larger diesel 

generator and have higher mass emissions than what is used in the modeling. 

This is true for all of the mass emission rates for other emission units determined 

based on the size of the emission unit, e.g. mmbtu/hr or hp, used in the modeling. 

Response 79: IDEM believes that, the statement "The information describing the process contained in 

this emissions unit description box is descriptive information and does not constitute 

enforceable conditions" contained in the Emission Unit Description box is correct and not 

misleading. The 1,341 hp is the permitted capacity for the emergency diesel generators 

and the Permittee may not construct the source inconsistent with the permit. Changes to 

the permitted capacities of the source are governed by the requirements of 326 IAC 2.

Other Changes

Upon further review IDEM, OAQ has made the following changes to the Title V permit T147-30464-

00060. (deleted language appears as strikout and the new language bolded):

Change 1: On October 27, 2010, the Indiana Air Pollution Control Board issued revisions to 326 IAC 

2. These revisions resulted in changes to the rule citations listed in the permit. These 

changes are not changes to the underlining provisions. The change is only to citations of 

these rules in Section A - General Information, Section A - Emission Units and Pollution 

Control Equipment Summary, Section A - Specifically Regulated Insignificant Activities, 

Section B - Preventative Maintenance Plan, Section B - Emergency Provisions, Section B 

- Operational Flexibility, Section C - Risk Management Plan, the Facility Descriptions, and 

Section D - Preventative Maintenance Plan. 

A.1 General Information [326 IAC 2-7-4(c)][326 IAC 2-7-5(14) (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(14) (15)]

***

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

5(14) (15)]

***
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B.12 Preventive Maintenance Plan [326 IAC 2-7-5(1),(3) and (13) (12)] [326 IAC 2-7-6(1) and (6)][326 

IAC 1-6-3]

***

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

***

(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) (8) be 

revised in response to an emergency.

***

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

(a) The Permittee may make any change or changes at the source that are described in 326 

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

conditions is met:

***

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

document all such changes and emission trades that are subject to 326 IAC 2-7-

20(b), or (c), or (e). The Permittee shall make such records available, upon 

reasonable request, for public review. 

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

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

***

C.14 Risk Management Plan [326 IAC 2-7-5(1112)] [40 CFR 68]

***

Change 2: IDEM has moved to separate CAM language for Section C - compliance monitoring, REE, 

and reporting. This language is mainly verbatim from the CAM rule and is to clarify the 

Permittee's responsibility under CAM. 

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

(a) Unless otherwise specified in this permit, for all monitoring requirements not already 

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

permit issuance or of initial start-up of the emission unit for which the monitoring is 

required, whichever is later, to begin such monitoring. If due to circumstances beyond the 

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

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

startup of the emission unit for which the monitoring is required, whichever is later, the 

Permittee may extend the compliance schedule related to the equipment for an additional 

ninety (90) days provided the Permittee notifies:

Indiana Department of Environmental Management

Compliance and Enforcement Branch, Office of Air Quality

100 North Senate Avenue

MC 61-53 IGCN 1003

Indianapolis, Indiana 46204-2251

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

justification of the reasons for the inability to meet this date.
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Permit Reviewer: Josiah Balogun

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

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

326 IAC 2-7-1(34).

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

monitoring for new emission units or emission units added through a source modification

shall be implemented when operation begins.

(b) 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.

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

malfunctions, associated repairs, and required quality assurance or control 

activities (including, as applicable, calibration checks and required zero and span 

adjustments), the Permittee shall conduct all monitoring in continuous operation 

(or shall collect data at all required intervals) at all times that the pollutant-specific 

emissions unit is operating. Data recorded during monitoring malfunctions, 

associated repairs, and required quality assurance or control activities shall not be 

used for purposes of this part, including data averages and calculations, or 

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

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

operation of the control device and associated control system. A monitoring 

malfunction is any sudden, infrequent, not reasonably preventable failure of the 

monitoring to provide valid data. Monitoring failures that are caused in part by poor

maintenance or careless operation are not malfunctions.

C.15 Response to Excursions or Exceedances [40 CFR 64][326 IAC 3-8][326 IAC 2-7-5] 

[326 IAC 2-7-6]

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

exceedance of a limitation in this permit:

..........................................................................................................................................

(II) 

(a) CAM Response to excursions or exceedances. 

(1) Upon detecting an excursion or exceedance, subject to CAM, the 

Permittee shall restore operation of the pollutant-specific emissions 

unit (including the 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. 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). Such actions may include initial inspection 

and evaluation, recording that operations returned to normal 

without operator action (such as through response by a 

computerized distribution control system), or any necessary followup actions to return operation to within the indicator range, 

designated condition, or below the applicable emission limitation or 

standard, as applicable.
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(2) 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, monitoring results, review of operation and maintenance 

procedures and records, and inspection of the control device, 

associated capture system, and the process.

(b) If the Permittee identifies a failure to achieve compliance with an emission 

limitation, subject to CAM, or standard, subject to CAM, for which the 

approved monitoring did not provide an indication of an excursion or 

exceedance while providing valid data, or the results of compliance or 

performance testing document a need to modify the existing indicator 

ranges or designated conditions, the Permittee shall promptly notify the 

IDEM, OAQ and, if necessary, submit a proposed significant permit 

modification to this permit to address the necessary monitoring changes. 

Such a modification may include, but is not limited to, reestablishing 

indicator ranges or designated conditions, modifying the frequency of 

conducting monitoring and collecting data, or the monitoring of additional 

parameters.

(c) Based on the results of a determination made under paragraph (II)(a)(2) of 

this condition, the EPA or IDEM, OAQ may require the Permittee to develop 

and implement a QIP. The Permittee shall develop and implement a QIP if 

notified to in writing by the EPA or IDEM, OAQ.

(d) Elements of a QIP:

The Permittee shall maintain a written QIP, if required, and have it available 

for inspection. The plan shall conform to 40 CFR 64.8 b (2).

(e) If a QIP is required, the Permittee shall develop and implement a QIP as 

expeditiously as practicable and shall notify the IDEM, OAQ if the period for 

completing the improvements contained in the QIP exceeds 180 days from 

the date on which the need to implement the QIP was determined.

(f) Following implementation of a QIP, upon any subsequent determination 

pursuant to paragraph (II)(a)(2) of this condition the EPA or the IDEM, OAQ 

may require that the Permittee make reasonable changes to the QIP if the 

QIP is found to have:

(1) Failed to address the cause of the control device performance 

problems; or

(2) Failed to provide adequate procedures for correcting control device 

performance problems as expeditiously as practicable in 

accordance with good air pollution control practices for minimizing 

emissions.

(g) Implementation of a QIP shall not excuse the Permittee from compliance 

with any existing emission limitation or standard, or any existing 

monitoring, testing, reporting or recordkeeping requirement that may apply 

under federal, state, or local law, or any other applicable requirements 

under the Act.

(h) CAM recordkeeping requirements. 

(1) The Permittee shall maintain records of monitoring data, monitor 

performance data, corrective actions taken, any written quality 
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Permit Reviewer: Josiah Balogun

improvement plan required pursuant to paragraph (II)(a)(2) of this 

condition and any activities undertaken to implement a quality 

improvement plan, and other supporting information required to be 

maintained under this condition (such as data used to document 

the adequacy of monitoring, or records of monitoring maintenance 

or corrective actions). Section C - General Record Keeping 

Requirements of this permit contains the Permittee's obligations 

with regard to the records required by this condition.

(2) Instead of paper records, the owner or operator may maintain 

records on alternative media, such as microfilm, computer files, 

magnetic tape disks, or microfiche, provided that the use of such 

alternative media allows for expeditious inspection and review, and 

does not conflict with other applicable recordkeeping requirements.

Change 3: On October 27, 2010, the Indiana Air Pollution Control Board issued revisions to 326 IAC 

2. These revisions included the incorporation of the U.S. EPA's definition of reasonable 

possibility. The permit previously cited to the EPA definition. Also, the revisions resulted 

in changes to other rule cites listed in the permit. And IDEM, OAQ has clarified the 

Permittee's responsibility with regard to record keeping. 

C.18 General Record Keeping Requirements [326 IAC 2-7-5(3)] [326 IAC 2-7-6] [326 IAC 2-2] 

[326 IAC 2-3]

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

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

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

following:

(AA) All calibration and maintenance records.

(BB) All original strip chart recordings for continuous monitoring

instrumentation.

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

Records of required monitoring information include the following:

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

measurements.

(BB) The dates analyses were performed.

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

(DD) The analytical techniques or methods used.

(EE) The results of such analyses.

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

measurement.

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

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

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

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

the Commissioner within a reasonable time.

....................................................................................................................................................
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(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) 326 IAC 

2-2-8 (b)(6)(A), 326 IAC 2-2-8 (b)(6)(B), 326 IAC 2-3-2 (l)(6)(A), and/or 326 IAC 2-3-2 

(l)(6)(B)) that a “project” (as defined in 326 IAC 2-2-1(qq oo) and/or 326 IAC 2-3-1(ll jj)) at 

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

Limitation (PAL), which is not part of a “major modification” (as defined in 326 IAC 2-2-

1(ee dd) and/or 326 IAC 2-3-1(z y)) may result in significant emissions increase and the 

Permittee elects to utilize the “projected actual emissions” (as defined in 326 IAC 2-2-1(rr

pp) and/or 326 IAC 2-3-1(mm kk)), the Permittee shall comply with following:

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

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

document and maintain the following records:

(A) A description of the project.

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

source review pollutant could be affected by the project.

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

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

(i) Baseline actual emissions;

(ii) Projected actual emissions;

(iii) Amount of emissions excluded under section 

326 IAC 2-2-1(rr pp)(2)(A)(iii) and/or 326 IAC 2-3-1 (mm

kk)(2)(A)(iii); and

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

netting calculations, if applicable.

(d) If there is a reasonable possibility (as defined in 40 CFR 51.165(a)(6)(vi)(A) and/or 40 

CFR 51.166(r)(6)(vi)(a) 326 IAC 2-2-8 (b)(6)(A) and/or 326 IAC 2-3-2 (l)(6)(A)) that a 

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

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

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

and/or 326 IAC 2-3-1(z y)) may result in significant emissions increase and the Permittee 

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

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

...............................................................................................................................................

C.19 General Reporting Requirements [326 IAC 2-7-5(3)(C)] [326 IAC 2-1.1-11] [326 IAC 2-2]

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

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

its equivalent. Proper notice submittal under Section B –Emergency Provisions satisfies the 

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

date(s) of each deviation, the cause of the deviation, and the response steps taken must 

be reported except that a deviation required to be reported pursuant to an applicable 

requirement that exists independent of this permit, shall be reported according to the 

schedule stated in the applicable requirement and does not need to be included in this 

report. This report shall be submitted not later than thirty (30) days after the end of the 

reporting period. The Quarterly Deviation and Compliance Monitoring Report shall 

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

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

limitation or a failure to comply with a requirement of the permit.
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Rockport, Indiana T 147-30464-00060

Permit Reviewer: Josiah Balogun

On and after the date by which the Permittee must use monitoring that meets the 

requirements of 40 CFR Part 64 and 326 IAC 3-8, the Permittee shall submit CAM 

reports to the IDEM, OAQ.

A report for monitoring under 40 CFR Part 64 and 326 IAC 3-8 shall include, at a 

minimum, the information required under paragraph (a) of this condition and the 

following information, as applicable:

(1) Summary information on the number, duration and cause (including 

unknown cause, if applicable) of excursions or exceedances, as applicable, 

and the corrective actions taken;

(2) Summary information on the number, duration and cause (including 

unknown cause, if applicable) for monitor downtime incidents (other than 

downtime associated with zero and span or other daily calibration checks, 

if applicable); and

(3) A description of the actions taken to implement a QIP during the reporting 

period as specified in Section C-Response to Excursions or Exceedances.

Upon completion of a QIP, the owner or operator shall include in the next 

summary report documentation that the implementation of the plan has 

been completed and reduced the likelihood of similar levels of excursions 

or exceedances occurring.

The Permittee may combine the Quarterly Deviation and Compliance Monitoring 

Report and a report pursuant to 40 CFR 64 and 326 IAC 3-8.

............................................................................................................................................................

Change 4: The ZLD-Spray Dryer, identified as EU-032 is a small unit that is not subject to CAM. 

Therefore the CAM citation has been removed from Conditions D.8.15, D.8.16 and D.8.17 

of the permit accordingly.

D.8.15 Broken or Failed Bag Detection [40 CFR 64]

(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. Operations may continue only if the 

event qualifies as an emergency and the Permittee satisfies the requirements of the 

emergency provisions of this permit (Section B - Emergency Provisions).

...............................................................................................................................................

D.8.16 Visible Emissions Notations [40 CFR 64]

(a) Visible emission notations of the ZLD-Spray Dryer, identified as EU-032 stack exhausts 

(S-014) shall be performed once per day during normal daylight operations. A trained 

employee shall record whether emissions are normal or abnormal. 

...................................................................................................................................

D.8.17 Parametric Monitoring [40 CFR 64]

In order to demonstrate the compliance status with Condition D.8.4, the Permittee shall record the 

pressure drop across the baghouse used in conjunction with the ZLD-Spray Dryer operations at 

least once per day when this unit is in operation. When the pressure drop across the baghouse is 

outside the normal range of 1.0 and 5.0 inches of water or a range established during the latest 

stack test, the Permittee shall take reasonable response steps. Section C - Response to 

Excursions or Exceedances contains the Permittee's obligation with regard to the reasonable 

response steps required by this condition. A pressure reading that is outside the above mentioned 

range is not a deviation from this permit. Failure to take response steps shall be considered a 

deviation from this permit.
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.....................................................................................................................................................

Change 5: Any finalized requirements of the Standards of Performance for Greenhouse Gas Emissions 

for New Stationary Sources: Electric Utility Generating Units, proposed by U.S. EPA on April 

13, 2012 (77 Fed. Reg. 22392), will not apply to any emission units at the source. The 

requirements of this proposed rule will apply to electric generating units that commence 

construction after the publication date of the proposed rule with a base load rating of more 

than 73 MW (250 MMBtu/hr). The proposed rule defines an “electric generating unit” as “any 

steam electric generating unit or stationary combustion turbine that is constructed for the 

purpose of supplying more than one-third of its potential electric output capacity and more 

than 25 MW net-electrical output to any utility power distribution system for sale.” While the 

two auxiliary boilers exceed the 250 MMBtu/hr applicability threshold, they are not considered 

“electric generating units” because they are not constructed for the purpose of supplying 

more than one-third of their potential electric output capacity to a utility power distribution 

system for sale, and Permit Condition D.6.9 limits operation of the auxiliary boilers to less 

than one-third of their potential electric output capacity.

Therefore, it is appropriate to add the following to Condition B.14(b) – Permit Shield:

The typo in Condition B.14 - Permit Shield has been corrected and the non applicable 

portion of the carbon dioxide (CO2e) NSPS has been added to the Permit Shield.

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

.......................................................................................................................................................

(b) In addition to the nonapplicability determinations set forth in Section D of this permit, the 

IDEM, OAQ has made the following determinations regarding this source.

...............................................................................................................................................

(4) 40 CFR 60, Subpart Da - Standards of Performance for Electric Utility Steam 

Generating Units for which Construction is Commenced after September 

18, 1978: 

(A) This source is not subject to 40 CFR Part 60, Subpart Da because the 

auxiliary boilers, which can supply steam to an electric generating steam 

turbine are steam-generating units, but they are not considered an 

electric utility unit because they will not supply more than 1/3 of its 

potential electrical output capacity to any utility power distribution system. 

(B) This source is not subject to 40 CFR Part 60, Subpart Da because the 

thermal oxidizers (EUs 007A, B) or gasifier pre-heat burners (EUs 008AE) since they do not meet the definition of an electric utility steam 

generating unit. Specifically, the thermal oxidizers and the pre-heat 

burners do not generated steam, and thus are not steam generating 

units.

..............................................................................................................................................

(11) Proposed Standards of Performance for Greenhouse Gas Emissions for New 

Stationary Sources: Electric Utility Generating Units: The source will not be 

subject to any finalized requirements of the “Standards of Performance for 

Greenhouse Gas Emissions for New Stationary Sources: Electric Utility 

Generating Units” proposed by U.S. EPA on April 13, 2012 (77 Fed. Reg. 

22392), because no electric generating unit at the facility is a steam electric 

generating unit that is constructed for the purpose of supplying more than 

one-third of its potential electric output capacity and more than 25 MW netelectrical output to any utility power distribution system for sale.
Indiana Gasification, LLC Page 120 of 122

Rockport, Indiana T 147-30464-00060

Permit Reviewer: Josiah Balogun

(1112) 326 IAC 24 Clean Air Interstate Rule (CAIR): The source is not subject to the 

requirements of 326 IAC 24 or the federal final rule issued on August 8, 2011 

limiting the interstate transport of NOx and SO2 (76 Fed. Reg. 48208 et seq.

Pursuant to 326 IAC 24-1(b)(1)(B) and the applicability requirements of 76 Fed. 

Reg. 48208, neither rule applies to a boiler serving a generator that supplies, in 

any calendar year, less than 1/3 of the unit's potential electric output capacity or 

219,000 MW-hours (25 MW), whichever is greater, to any utility power distribution 

system for sale.

(1213) 40 CFR Part 72-78 Acid Rain Program: This source is not subject to the 

requirements of 40 CFR Part 72-78 because it does not sell greater than 1/3 of 

its generated electric electricity.

..............................................................................................................................................

Change 6: IDEM, OAQ has updated the language in Condition D.2.9 (now D.2.10) - Record Keeping 

Requirement in the permit accordingly.

D.2.910 Record Keeping Requirements

..............................................................................................................................................

(c) To document the compliance status with the shutdown emission limits for SO2 in Condition 

D.2.4(3)(B), the Permittee shall maintain records of the total number of minutes for 

each shutdown flaring event.

(dc) To document the compliance status with Condition D.2.4, the Permittee shall maintain 

records of the date, time, and total number of minutes for each startup and shutdown flaring 

event.

.............................................................................................................................................

Change 7: IDEM, OAQ has updated and clarify the language in Condition D.4.23 now D.4.24 - Record 

Keeping Requirement in the permit accordingly.

D.4.234 Record Keeping Requirements

(a) In order to document the compliance status with Conditions D.4.4 - PM, PM10 and PM2.5

PSD BACT, D.4.6 – SO2 PSD BACT, D.4.9 - GHGs PSD BACT, D.4.13 – Compliance 

Determination Requirements PM, PM10, and PM2.5 Calculations, D.4.15 – Sulfur Dioxide 

Control and Calculations, and D.4.16 – Compliance Determination Requirements

Greenhouse Gases (GHGs) Calculations, the Permittee shall maintain monthly records 

of the amount and type of fuel combusted in the RTOs for the Acid Gas Removal (AGR) 

Unit vents.

...................................................................................................................................

(c) To document the compliance status with Condition D.4.10 – Alternate Emissions 

Limitation During Gasifier Startup Flaring, the Permittee shall maintain monthly 

records of the NOx emissions during gasifier startup flaring.

............................................................................................................................................................

Change 8: IDEM, OAQ has updated the language in Condition D.8.11 - Compliance Determination 

Requirement in the permit.

D.8.11 Compliance Determination Requirements

In order to ensure compliance with Conditions D.8.5 – CO PSD BACT, D.8.6 - SO2 PSD BACT, D.8.7 

– NOx PSD BACT, and D.8.8(a) - GHGs PSD BACT, the Permittee shall only use natural gas or SNG 

in the ZLD-Spray Dryer (EU-032).
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Change 9: IDEM has included new Condition D.2.5 to clarify the area source status for this source. 

D.2.5 Hazardous Air Pollutants (HAPs) Minor Limits

The single HAP and total HAP from the syngas hydrocarbon flare identified as EU-001 shall 

be limited by compliance with the SO2 emission limit is Condition D.2.4(3) and, combined 

with the potential to emit HAP emissions from all other emission units, this requirement 

will limit the potential to emit from this source to less than ten (10) tons per year of any 

individual HAP and twenty-five (25) tons per year of any combination of HAPs and make 

the source an area source of HAPs.

........................................................................................................................................................

Change 10: IDEM has revised these emission unit descriptions in Section A.2, A.3, D1 through D.18 

and E1 through E.6 of the permit. And the word "to be permitted in 2012" has been 

changed to "permitted in 2012" throughout the permit.

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

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

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

(A) Incoming solid feedstock materials handling system, transferring material from the barge 

unloading facility and railcar unloading facility to storage piles and day bins, consisting of: 

[Under 40 CFR 60, Subpart Y, the incoming solid feedstock materials handling system, 

transferring material from the barge unloading facility and railcar unloading facility to 

storage piles and day bins are new affected sources.]

(1) One (1) barge unloading to hopper transfer point, to be permitted in 2012, 

nominally rated at 750 tons per hour, identified as EU-012A, with particulate 

emissions controlled by wet suppression.

....................................................................................................................................................

(E) Two (2) Acid Gas Removal (AGR) Unit vents, identified as EU-007A and EU-007B, to be

permitted in 2012, with methanol, H2S, COS, HAP, VOC and CO emissions controlled by 

two (2) regenerative thermal oxidizers (RTO) identified as C-007A and C-007B, 

respectively, each nominally rated at 38.8 MMBtu/hr HHV fuel input, exhausting through 

two (2) stack, identified as S-007A and S-007B.

(F) Two (2) Wet Sulfuric Acid (WSA) plant trains, each nominally rated at 800 stpd H2SO4

and identified as EU-015A and EU-015B, to be permitted in 2012, with NOx, SO2, H2SO4

emissions controlled by two (2) selective catalytic reduction (SCR) systems identified as 

C-015-1A and C-015-1B, respectively, and particulate, H2SO4, and SO2 emissions 

controlled by two (2) hydrogen peroxide scrubbers identified as C-015-2A and C-015-2B, 

respectively, and particulate and H2SO4 emissions controlled by a high efficiency 

mist eliminator, exhausting through two (2) stacks, identified as S-015A and S-015B 

respectively. These emissions units also include two (2) preheat burners (one for each 

train), each nominally rated at 35.00 MMBtu/hr HHV, venting through the same stacks.

........................................................................................................................................................

(I) One (1) ZLD-Spray Dryer, to be permitted in 2012, nominally rated at 5.6 MMBtu/hr with 

PM particulate emissions controlled by a baghouse identified as C-032, nominally rated 

at 2,735 dscfm, and identified as EU-032, with low NOx burners (LNB), exhausting 

through one (1) stack, identified as S-014.
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Rockport, Indiana T 147-30464-00060

Permit Reviewer: Josiah Balogun

Change 11: A reporting form has been added to the permit to report the emission of the Carbonyl 

Sulfide (Single HAP).

INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

OFFICE OF AIR QUALITY 

COMPLIANCE AND ENFORCEMENT BRANCH

Part 70 Quarterly Report

Source Name: Indiana Gasification, LLC

Source Address: CR 200 N and Base Road, Rockport, Indiana 47635

Part 70 Permit No.: T147-30464-00060

Facility: Acid Gas Removal Unit Vents (EU-007A/B)

Parameter: Single HAPs Emissions (Carbonyl Sulfide)

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: 
Page 1 of 2 ATSD Appx A

Emissions shown are those limited by permit conditions.

Emission unit Total HAPs (tons/year)

Syngas hydrocarbon Flare 

(001) 0.0049

Acid Gas Flare (002) 0.0022

Auxiliary Boiler (005A-B) 1.40

Acid Gas Recovery Unit (007AB) 17.00

Gasifier Preheat Burners (008AE) 0.10

Emergency Diesel Generator 

(009A-B) 0.00077

Revised to Include HAPs per 

AP42

Emergency Firewater Engine 

(010A-C) 0.00122

Revised to Include HAPs per 

AP42

Process Area Solid Feedstock 

(011) 0

Incoming Solid Feedstock 

Handling (012A-AC) 0

Rod Mill (013A-D) 0

Wet Sulfuric Acid Plant (015AB) 0

Cooling Tower - ASU (016A) 0

Cooling Tower - Main (016B) 0

ASU Molecular Sieve 

Regeneration (017A-B) 0

Slag Sump (023A-E) 0

Methanol De-Inventory Storage 

Tank (024) 0.16

Fresh Methanol Storage Tank 

(025) 0.13

Sour Water Stripper Surge 

Tank (026) 0

Sulfuric Acid Storage Tank 

(027A-F) 0

Diesel Fuel Storage Tank (029) 0.07

Gasoline Fuel Storage Tank 

(030) 0

Triethylene Glycol Storage 

Tank (031) 0

ZLD Spray Dryer (032) 0.046

ZLD Inert Gas Vent (033) 0

EU-034A and 034C 0

Fugitve Emissions

Gasification, Shift Conv. AGR, 

methanation (FUG) 0.381

Fugitive Emission - WSA 

(FUG-WSA) 0

Plant Haul Roads (FUGROAD) 0

Electric Circuit Breakers (FUGSF6) 0

Total Emissions 19.30

Appendix A: Emissions Calculations

Emission Summary (Total HAPS)
Page 1 of 2 ATSD Appx A

Estimated HAP Emissions From Emergency Diesel Engines (Emergency Generators EU# 009A/B, Fire Water Pump Engine EU 010A/B/C)

EU# Emissions Unit HAPs (TPY)

009A Emergency Diesel Power Generator A 1,341 HP 500 hr/yr 1.10E-05 lb/hp-hr 0.00369 

009B Emergency Diesel Power Generator B 1,341 HP 500 hr/yr 1.10E-05 lb/hp-hr 0.00369 

010A Fire Water Diesel Pump A 575 HP 500 hr/yr 2.71E-05 lb/hp-hr 0.00390 

010B Fire Water Diesel Pump B 575 HP 500 hr/yr 2.71E-05 lb/hp-hr 0.00390 

010C Fire Water Diesel Pump C 575 HP 500 hr/yr 2.71E-05 lb/hp-hr 0.00390 

Total HAPs 0.01908 

These calculations assume unlimited operation of engines up to 500 hrs/yr each.

Emergency Engine HAPs factors Emergency Engine HAPs factors

Internal Combustion, > 600 HP Internal Combustion, < 600 HP

AP-42 Section 3.4 Table 3.4-2 & 3.4-3 AP-42 Section 3.3 Table 3.3-2

HAP HAP

Benzene 7.76E-04 lb/mmBtu Benzene 9.33E-04 lb/mmBtu

Toluene 2.81E-04 lb/mmBtu Toluene 4.09E-04 lb/mmBtu

Xylenes 1.93E-04 lb/mmBtu Xylenes 2.85E-04 lb/mmBtu

Formaldehyde 7.89E-05 lb/mmBtu 1,3-Butadiene 3.91E-05 lb/mmBtu

Acetaldehyde 2.52E-05 lb/mmBtu Formaldehyde 1.18E-03 lb/mmBtu

Acrolein 7.88E-06 lb/mmBtu Acetaldehyde 7.67E-04 lb/mmBtu

Naphthalene 1.30E-04 lb/mmBtu Acrolein 9.25E-05 lb/mmBtu

Acenaphthylene 9.23E-06 lb/mmBtu Naphthalene 8.48E-05 lb/mmBtu

Acenaphthene 4.68E-06 lb/mmBtu Acenaphthylene 5.06E-06 lb/mmBtu

Fluorene 1.28E-05 lb/mmBtu Acenaphthene 1.42E-06 lb/mmBtu

Phenanthrene 4.08E-05 lb/mmBtu Fluorene 2.92E-05 lb/mmBtu

Anthracene 1.23E-06 lb/mmBtu Phenanthrene 2.94E-05 lb/mmBtu

Fluoranthene 4.03E-06 lb/mmBtu Anthracene 1.87E-06 lb/mmBtu

Pyrene 3.71E-06 lb/mmBtu Fluoranthene 7.61E-06 lb/mmBtu

Benz(a)anthracene 6.22E-07 lb/mmBtu Pyrene 4.78E-06 lb/mmBtu

Chrysene 1.53E-06 lb/mmBtu Benzo(a)anthracene 1.68E-06 lb/mmBtu

Benzo(b)fluoranthene 1.11E-06 lb/mmBtu Chrysene 3.53E-07 lb/mmBtu

Benzo(k)fluoranthene 2.18E-07 lb/mmBtu Benzo(b)fluoranthene 9.91E-08 lb/mmBtu

Benzo(a)pyrene 2.57E-07 lb/mmBtu Benzo(k)fluoranthene 1.55E-07 lb/mmBtu

Indeno(1,2,3-cd)pyrene 4.14E-07 lb/mmBtu Benzo(a)pyrene 1.88E-07 lb/mmBtu

Dibenz(a,h)anthracene 3.46E-07 lb/mmBtu Indeno(1,2,3-cd)pyrene 3.75E-07 lb/mmBtu

Rating Frequency (Unlimited) Emission Factor

Factor Factor

Dibenz(a,h)anthracene 3.46E 07 lb/mmBtu Indeno(1,2,3 cd)pyrene 3.75E 07 lb/mmBtu

Benzo(g,h,l)perylene 5.56E-07 lb/mmBtu Dibenz(a,h)anthracene 5.83E-07 lb/mmBtu

Total 1.57E-03 lb/mmBtu Benzo(g,h,l)perylene 4.89E-07 lb/mmBtu

Total in different units 1.10E-05 lb/hr-hr Total 3.87E-03 lb/mmBtu

2.71E-05 lb/hr-hr

Conversion Factor 7,000 Btu/hp-hr

AP-42 Section 3.3 Table 3.3-1 reference a & Section 3.4 Table 3.4-1 reference e
Page 1 of 2 ATSD Appx 

Estimated HAP Emissions From Emergency Diesel Engines (Emergency Generators EU# 009A/B, Fire Water Pump Engine EU 010A/B/C)

EU# Emissions Unit HAPs (TPY)

009A Emergency Diesel Power Generator A 1,341 HP 52 hr/yr 1.10E-05 lb/hp-hr 0.00038

009B Emergency Diesel Power Generator B 1,341 HP 52 hr/yr 1.10E-05 lb/hp-hr 0.00038

010A Fire Water Diesel Pump A 575 HP 52 hr/yr 2.71E-05 lb/hp-hr 0.00041

010B Fire Water Diesel Pump B 575 HP 52 hr/yr 2.71E-05 lb/hp-hr 0.00041010C Fire Water Diesel Pump C 575 HP 52 hr/yr 2.71E-05 lb/hp-hr 0.00041

Total HAPs 0.00198

These calculations assume each engine is limited by permit to 52 hrs/yr each.Emergency Engine HAPs factors Emergency Engine HAPs factorsInternal Combustion, > 600 HP Internal Combustion, < 600 HPAP-42 Section 3.4 Table 3.4-2 & 3.4-3 AP-42 Section 3.3 Table 3.3-2

HAP HAP

Benzene 7.76E-04 lb/mmBtu Benzene 9.33E-04 lb/mmBtuToluene 2.81E-04 lb/mmBtu Toluene 4.09E-04 lb/mmBtuXylenes 1.93E-04 lb/mmBtu Xylenes 2.85E-04 lb/mmBtuFormaldehyde 7.89E-05 lb/mmBtu 1,3-Butadiene 3.91E-05 lb/mmBtuAcetaldehyde 2.52E-05 lb/mmBtu Formaldehyde 1.18E-03 lb/mmBtuAcrolein 7.88E-06 lb/mmBtu Acetaldehyde 7.67E-04 lb/mmBtuNaphthalene 1.30E-04 lb/mmBtu Acrolein 9.25E-05 lb/mmBtuAcenaphthylene 9.23E-06 lb/mmBtu Naphthalene 8.48E-05 lb/mmBtuAcenaphthene 4.68E-06 lb/mmBtu Acenaphthylene 5.06E-06 lb/mmBtuFluorene 1.28E-05 lb/mmBtu Acenaphthene 1.42E-06 lb/mmBtu

Ph th 4 08E 05 lb/ Bt Fl 2 92E 05 lb/ Bt

Rating Frequency - Limited by Permit Emission Factor

Factor Factor

Phenanthrene 4.08E-05 lb/mmBtu Fluorene 2.92E-05 lb/mmBtu

Anthracene 1.23E-06 lb/mmBtu Phenanthrene 2.94E-05 lb/mmBtuFluoranthene 4.03E-06 lb/mmBtu Anthracene 1.87E-06 lb/mmBtuPyrene 3.71E-06 lb/mmBtu Fluoranthene 7.61E-06 lb/mmBtuBenz(a)anthracene 6.22E-07 lb/mmBtu Pyrene 4.78E-06 lb/mmBtuChrysene 1.53E-06 lb/mmBtu Benzo(a)anthracene 1.68E-06 lb/mmBtuBenzo(b)fluoranthene 1.11E-06 lb/mmBtu Chrysene 3.53E-07 lb/mmBtuBenzo(k)fluoranthene 2.18E-07 lb/mmBtu Benzo(b)fluoranthene 9.91E-08 lb/mmBtuBenzo(a)pyrene 2.57E-07 lb/mmBtu Benzo(k)fluoranthene 1.55E-07 lb/mmBtuIndeno(1,2,3-cd)pyrene 4.14E-07 lb/mmBtu Benzo(a)pyrene 1.88E-07 lb/mmBtuDibenz(a,h)anthracene 3.46E-07 lb/mmBtu Indeno(1,2,3-cd)pyrene 3.75E-07 lb/mmBtuBenzo(g,h,l)perylene 5.56E-07 lb/mmBtu Dibenz(a,h)anthracene 5.83E-07 lb/mmBtu

Total 1.57E-03 lb/mmBtu Benzo(g,h,l)perylene 4.89E-07 lb/mmBtu

Total in different units 1.10E-05 lb/hr-hr Total 3.87E-03 lb/mmBtu

2.71E-05 lb/hr-hr

Conversion Factor 7,000 Btu/hp-hr

AP-42 Section 3.3 Table 3.3-1 reference a & Section 3.4 Table 3.4-1 reference e
FLARE SOURCES Page 1 of 3 ATSD App A

NAME Hydrocarbon / Gasifier Start-up Flare "Not-Limited" by Permit Limits" Unit ID: 001

(With S/D HAPS added)

STACK DATA

HEIGHT 300 ft

DIAMETER 6 ft

EMISSIONS: Scenario 1: Gasifier Start-Up Syngas Flaring hr/yr = 8760

Firing Rate = 861.7 MMBtu/hr

CO DRE 0 %

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb-mol/hr lb-mol/hr lb-mol/hr Mol % lb/hr lb/hr TPY

PM10 -- -- -- -- 6.42 6.42 28.12

PM2.5 0.09 0.09 0.41

SO2 0.01 0 -- -- 0.70 0.70 3.045

NOx -- -- -- -- 86.17 86.17 377.42

CO -- -- 18237.12 13.50 68939.73 68939.73 301956.00

H2S (TAP) 0.01 -- -- -- 0.01 0.01 0.03

COS (TAP)(VOC) -- 0.00 -- -- 0.00 0.00 0.00

Other VOC -- -- -- -- 0.09 0.09 0.41

Total VOC 0.09 0.09 0.41

EMISSIONS: Scenario 2: Gasifier Start-Up Flare Pilot Burners Operating hr/yr = 8,760

Pilot Firing Rate = 0.27 MMBtu/hr

AP-42 Heating Value = 1,020 Btu/scf

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb/hr lb/hr TPY

PM10 0.0020 0.0020 0.0087

PM2.5 0.0019 0.0019 0.0081

SO2 0.0002 0.0002 0.00068

NOx 0.053 0.053 0.23

CO 0.013 0.013 0.06

VOC 0.005 0.005 0.02

Total VOC HAPs 0.0005 0.0005 0.0022

Mercury (HAP) 4.4E-07 4.4E-07 1.9E-06

TOTAL STARTUP FLARING AND PILOT

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb/hr lb/hr TPY

PM10 6.422 6.42 28.13

PM2.5 0.095 0.09 0.41

SO2 0.70 0.70 3.046

NOx 86.22 86.22 377.65

CO 68939.74 68939.74 301956.05

H2S (TAP) 0.013 0.01 0.06

COS (TAP)(VOC) 0.00 0.00 0.00

Total VOC 0.0982 0.09 0.43

Total VOC HAPs 0.0005 0.0005 0.0022

Mercury (HAP) 4.4E-07 4.4E-07 1.9E-06

Calculations:

Scenario 1:

Emissions (SO2)(Avg. lb/hr)=H2S in Syngas (lb-mol/hr) + COS in Syngas (lb-mol/hr) X 64.063 lb/mol

Emissions (CO)(Avg. lb/hr)=(Raw Syngas flared (lbmols/hr) X CO in Syngas (mol %)/100) X 28.01 lb/mol X (100 - CO DRE)/100

Emissions (H2S)(Avg. lb/hr)=H2S in Syngas (lb-mol/hr) X 34.08 lb/mol X 2/100

Emissions (COS)(Avg. lb/hr)=COS in Syngas (lb-mol/hr) X 60.0764 lb/mol X 2/100

Emissions (NOx, PM10, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

Scenarios 2 and 3:

Emissions (PM10, SO2)(Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft

3

) X Heat Input (MMBtu/hr)

Emissions (NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions-Pilot Case (SO2, NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

NOx PM10 VOC

0.100 0.007 0.0001

H2S in Syngas COS in Syngas

Raw Syngas 

Flared CO in Syngas

Scenario 1

Factor (lb/MMBtu)
Page 2 of 3 ATSD App A

PM10 SO2

7.600 0.60

NOx CO VOC

0.200 0.050 0.020

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

Number Shutdown Flaring Events / year = 15

Flaring Event Duration (hrs) = 3

Firing Rate (MMBtu/Event) = 34.26

SHUTDOWN FLARING Total MMBtu/yr 513.9

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb/event lb/hr TPY

PM10 0.260 0.09 0.002

PM2.5 0.260 0.09 0.002

SO2 255.62 85.21 1.917

NOx 3.43 1.14 0.026

CO 21.22 7.07 0.159

H2S (TAP) 2.660 0.89 0.020

COS (TAP)(VOC) 0.20 0.07 0.002

VOC 0.0037 0.00 0.000

Total HAPS 0.3728 0.12 0.0028

Total HAPs Emiss. Factor shown on separate page: 1.09E-02 lb/MMBtu

GHG Emissions from Gasifier Start-up

lb/hr TPY MT/yr

CO2 for Gasifier Flare = 185,818.1 813,883.3 738354.9

Equation Y-5

N2O = Annual nitrous oxide emissions from flared gas (metric ton N2O/year)

CO2 = Emission rate of CO2 from flared gas calculated (metric ton/year)

EmFN2O = Default N2O emission factor for “Petroleum Products” from Table C-2 of subpart C (General Stationary Fuel Combustion Sources) (kg N2O/MMBtu) = 0.0006

EmF = Default CO2 emission factor for flare gas of 60 kg CO2/MMBtu (HHV basis)

N2O for Gasifier Flare = 7.384 MT

GHG Emissions from Pilot

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

Scenario 2

Factor (lb/MMBtu)

Sources: NOx and CO, and VOC are based on values from vendor supplied data. 

Mercury Factor (lb/MMBtu)

DRE for H2S and COS is considered as 98%.

DRE for CO is considered as 99.5%.

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs for natural gas to the pilot are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4. Flared gas is primarly CO and H2 - HAPs assumed negligable.

Scenario 1: Gasifier Start-up Syngas Flaring

Scenario 2: Gasifier Start-up Flare Pilot Burners Operating 

Scenario 3: Normal Operations-Purge Gas and Pilot Gas Flaring

The feed to the gasifier flare during the start-up of a gasifier contains CO and CO2, but no other carbon compounds. A mass balance was used to determine the CO2 

and N2O emissions. There will be no CH4 emissions. The GHG Subpart Y (Refinery) flare equations are not applicable; however, the Subpart Y equation for N2O will 

be used to conservatively estimate N2O emissions.

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for PM10. 

Sources: NOx and PM10 for Syngas are based on values from vendor supplied data. VOC for Syngas = 2% of AP-42 Section 1.4 "Natural Gas Combustion" Table 1.4-2 

Scenario 2

Factor (lb/MMscf)
CO2 = 123.2 MT Page 3 of 3 ATSD App A

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0023 MT

N2O = 0.0002 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 2,277,600 scf

High heat value 

of the fuel from 

all valid samples 

for the year

Annual Average 0.00102 MMBtu per scf

Startup

GHG Pollutant GHG

Metric Tons

GWP Factors Metric Tons 

CO2e

CO2 738,355 1 738,355

CH4 0 21 0

N2O 7.384 310 2,288.9

TOTAL = 740,644 816,190 TPY CO2

Shutdown

GHG Pollutant GHG

Metric Tons

GWP Factors Metric Tons 

CO2e

CO2 36,918 1 36,918

CH4 0 21 0

N2O 0.369 310 114.4

TOTAL = 37,032 40,809 TPY CO2

Shutdown flared gas volume on an annual basis is 5% of startup flared gas volume.

Pilot

GHG Pollutant GHG

Metric Tons

GWP Factors Metric Tons 

CO2e

CO2 123.2 1 123.2

CH4 0.0023 21 0.05

N2O 0.0002 310 0.07

TOTAL = 123.3 136 TPY CO2

Hydrocarbon / Gasifier Startup Flare
FLARE SOURCES Page 1 of 3 ATSD App A

NAME Hydrocarbon / Gasifier Start-up Flare "Limited by Permit Limits" Unit ID: 001

(With S/D HAPS added)

STACK DATA

HEIGHT 300 ft

DIAMETER 6 ft

EMISSIONS: Scenario 1: Gasifier Start-Up Syngas Flaring hr/yr = 135

Firing Rate = 861.7 MMBtu/hr

CO DRE 99.5 %

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb-mol/hr lb-mol/hr lb-mol/hr Mol % lb/hr lb/hr TPY

PM10 -- -- -- -- 6.42 6.42 0.43

PM2.5 6.02 6.02 0.41

SO2 0.01 0 -- -- 0.70 0.70 0.047

NOx -- -- -- -- 86.17 86.17 5.82

CO -- -- 18237.12 13.50 344.70 344.70 23.27

H2S (TAP) 0.01 -- -- -- 0.01 0.01 0.00

COS (TAP)(VOC) -- 0.00 -- -- 0.00 0.00 0.00

Other VOC -- -- -- -- 0.09 0.09 0.01

Total VOC 0.09 0.09 0.01

EMISSIONS: Scenario 2: Gasifier Start-Up Flare Pilot Burners Operating hr/yr = 8,760

Pilot Firing Rate = 0.27 MMBtu/hr

AP-42 Heating Value = 1,020 Btu/scf

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb/hr lb/hr TPY

PM10 0.0020 0.0020 0.0087

PM2.5 0.0019 0.0019 0.0081

SO2 0.0002 0.0002 0.00068

NOx 0.053 0.053 0.23

CO 0.013 0.013 0.06

VOC 0.005 0.005 0.02

Total VOC HAPs 0.0005 0.0005 0.0022

Mercury (HAP) 4.4E-07 4.4E-07 1.9E-06

TOTAL STARTUP FLARING AND PILOT

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb/hr lb/hr TPY

PM10 0.101 6.42 0.44

PM2.5 0.095 6.02 0.41

SO2 0.01 0.70 0.048

NOx 1.38 86.22 6.05

CO 5.33 344.71 23.33 

H2S (TAP) 0.005 0.01 0.02

COS (TAP)(VOC) 0.00 0.00 0.00

Total VOC 0.0067 0.09 0.03

Total VOC HAPs 0.0005 0.0005 0.0022

Mercury (HAP) 4.4E-07 4.4E-07 1.9E-06

Calculations:

Scenario 1:

Emissions (SO2)(Avg. lb/hr)=H2S in Syngas (lb-mol/hr) + COS in Syngas (lb-mol/hr) X 64.063 lb/mol

Emissions (CO)(Avg. lb/hr)=(Raw Syngas flared (lbmols/hr) X CO in Syngas (mol %)/100) X 28.01 lb/mol X (100 - CO DRE)/100

Emissions (H2S)(Avg. lb/hr)=H2S in Syngas (lb-mol/hr) X 34.08 lb/mol X 2/100

Emissions (COS)(Avg. lb/hr)=COS in Syngas (lb-mol/hr) X 60.0764 lb/mol X 2/100

Emissions (NOx, PM10, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

Scenarios 2 and 3:

Emissions (PM10, SO2)(Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft

3

) X Heat Input (MMBtu/hr)

Emissions (NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions-Pilot Case (SO2, NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

NOx PM10 VOC

0.100 0.007 0.0001

H2S in Syngas COS in Syngas

Raw Syngas 

Flared CO in Syngas

Scenario 1

Factor (lb/MMBtu)
Page 2 of 3 ATSD App A

PM10 SO2

7.600 0.60

NOx CO VOC

0.200 0.050 0.020

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

Number Shutdown Flaring Events / year = 15

Flaring Event Duration (hrs) = 3

Firing Rate (MMBtu/Event) = 34.26

SHUTDOWN FLARING

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb/event lb/hr TPY

PM10 0.260 0.09 0.002

PM2.5 0.260 0.09 0.002

SO2 255.62 85.21 1.917

NOx 3.43 1.14 0.026

CO 21.22 7.07 0.159

H2S (TAP) 2.660 0.89 0.020

COS (TAP)(VOC) 0.20 0.07 0.002

VOC 0.0037 0.00 0.000

Total HAPS 0.3728 0.12 0.0028

Total HAPs Emiss. Factor shown on separate page: 1.09E-02 lb/MMBtu

GHG Emissions from Gasifier Start-up

lb/hr TPY MT/yr

CO2 for Gasifier Flare = 185,818.1 12,542.7 11378.8

Equation Y-5

N2O = Annual nitrous oxide emissions from flared gas (metric ton N2O/year)

CO2 = Emission rate of CO2 from flared gas calculated (metric ton/year)

EmFN2O = Default N2O emission factor for “Petroleum Products” from Table C-2 of subpart C (General Stationary Fuel Combustion Sources) (kg N2O/MMBtu) = 0.0006

EmF = Default CO2 emission factor for flare gas of 60 kg CO2/MMBtu (HHV basis)

N2O for Gasifier Flare = 0.114 MT

GHG Emissions from Pilot

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 123.2 MT

Scenario 2

Factor (lb/MMBtu)

Sources: NOx and CO, and VOC are based on values from vendor supplied data. 

Mercury Factor (lb/MMBtu)

DRE for H2S and COS is considered as 98%.

DRE for CO is considered as 99.5%.

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs for natural gas to the pilot are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4. Flared gas is primarly CO and H2 - HAPs assumed negligable.

Scenario 1: Gasifier Start-up Syngas Flaring

Scenario 2: Gasifier Start-up Flare Pilot Burners Operating 

Scenario 3: Normal Operations-Purge Gas and Pilot Gas Flaring

The feed to the gasifier flare during the start-up of a gasifier contains CO and CO2, but no other carbon compounds. A mass balance was used to determine the CO2 

and N2O emissions. There will be no CH4 emissions. The GHG Subpart Y (Refinery) flare equations are not applicable; however, the Subpart Y equation for N2O will 

be used to conservatively estimate N2O emissions.

Sources: NOx and PM10 for Syngas are based on values from vendor supplied data. VOC for Syngas = 2% of AP-42 Section 1.4 "Natural Gas Combustion" Table 1.4-2 

Scenario 2

Factor (lb/MMscf)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for PM10. 
Page 3 of 3 ATSD App A

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0023 MT

N2O = 0.0002 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 2,277,600 scf

High heat value 

of the fuel from 

all valid samples 

for the year

Annual Average 0.00102 MMBtu per scf

Startup

GHG Pollutant GHG

Metric Tons

GWP Factors Metric Tons 

CO2e

CO2 11,379 1 11,379

CH4 0 21 0

N2O 0.114 310 35.3

TOTAL = 11,414 12,578 TPY CO2

Shutdown

GHG Pollutant GHG

Metric Tons

GWP Factors Metric Tons 

CO2e

CO2 569 1 569

CH4 0 21 0

N2O 0.006 310 1.8

TOTAL = 571 629 TPY CO2

Shutdown flared gas volume on an annual basis is 5% of startup flared gas volume.

Pilot

GHG Pollutant GHG

Metric Tons

GWP Factors Metric Tons 

CO2e

CO2 123.2 1 123.2

CH4 0.0023 21 0.05

N2O 0.0002 310 0.07

TOTAL = 123.3 136 TPY CO2

Hydrocarbon / Gasifier Startup Flare
Hydrocarbon Flare Shutdown Emissions HAP Calculations Page 1 of 2 A

Emission Point Emissions Unit HAPs (TPY)

001 Hydrocarbon Flare Shutdown Emissions 514 mmBtu/year 1.09E-02 lb/mmBtu 0.0028

HAPs factors for Syngas Flaring during Shutdowns

HAP

2-Methylnaphthalene 2.35E-08 lb/mmBtu AP-42, Table 1.4-43-Methylchloranthrene 1.76E-09 lb/mmBtu AP-42, Table 1.4-47,12-Dimethylbenz(a)anthracene 1.57E-08 lb/mmBtu AP-42, Table 1.4-4Acenaphthene 1.76E-09 lb/mmBtu AP-42, Table 1.4-4Acenaphthylene 1.76E-09 lb/mmBtu AP-42, Table 1.4-4Anthracene 2.35E-09 lb/mmBtu AP-42, Table 1.4-4Benz(a)anthracene 1.76E-09 lb/mmBtu AP-42, Table 1.4-4Benzene 2.06E-06 lb/mmBtu AP-42, Table 1.4-4Benzo(a)pyrene 1.18E-09 lb/mmBtu AP-42, Table 1.4-4Benzo(b)fluoranthene 1.76E-09 lb/mmBtu AP-42, Table 1.4-4Benzo(g,h,i)perylene 1.18E-09 lb/mmBtu AP-42, Table 1.4-4Benzo(k)fluoranthene 1.76E-09 lb/mmBtu AP-42, Table 1.4-4Chrysene 1.76E-09 lb/mmBtu AP-42, Table 1.4-4Dibenzo(a,h)anthracene 1.18E-09 lb/mmBtu AP-42, Table 1.4-4Dichlorobenzene 1.18E-06 lb/mmBtu AP-42, Table 1.4-4Fluoranthene 2.94E-09 lb/mmBtu AP-42, Table 1.4-4Fluorene 2.75E-09 lb/mmBtu AP-42, Table 1.4-4Formaldehyde 7.35E-05 lb/mmBtu AP-42, Table 1.4-4Hexane 1.76E-03 lb/mmBtu AP-42, Table 1.4-4Indeno(1,2,3-cd)pyrene 1.76E-09 lb/mmBtu AP-42, Table 1.4-4Naphthalene 5.98E-07 lb/mmBtu AP-42, Table 1.4-4Phenanathrene 1.67E-08 lb/mmBtu AP-42, Table 1.4-4Pyrene 4.90E-09 lb/mmBtu AP-42, Table 1.4-4Toluene 3.33E-06 lb/mmBtu AP-42, Table 1.4-4(Continued on Next Page)

Shutdown Gas Flow Emission Factor

Factor Basis of Factor
HAPs factors for Syngas Flaring during Shutdowns (Continued) Page 2 of 2 A

HAP

Hydrochloric Acid1 8.85E-03 lb/mmBtu Note 1 

Arsenic2 1.60E-06 lb/mmBtu Note 2Beryllium2 1.80E-07 lb/mmBtu Note 2Cadmium2 2.20E-07 lb/mmBtu Note 2Chromium2 1.00E-06 lb/mmBtu Note 2Cobalt2 8.24E-08 lb/mmBtu Note 2Manganese2 1.10E-06 lb/mmBtu Note 2Mercury3 1.71E-04 lb/mmBtu Note 3Nickel2 1.10E-06 lb/mmBtu Note 2Selenium2 1.50E-06 lb/mmBtu Note 2Lead2 4.00E-06 lb/mmBtu Note 2

Total HAPs for Syngas combustion 1.09E-02 lb/mmBtu

Shutdown Syngas Flaring Emissions factor basis.

Note 3 - Mercury content of syngas is .0352 ppmv per engineering estimate. Note 4 - Organic HAPs conservatively assumed equal to AP42 for NG combustionNote 1 - HCL emissions are based on conservative assumption of 10 ppm HCL in syngas per Note 2 - Metal HAP factors (except mercury) are from Proposed Duke Edwardsport IGCC , 

Factor Basis of Factor
Page 1 of 2 ATSD Appx 

Fugitive Emissions: Additional HAP Calculations for Emiss. Unit FUG and FUG-WSA

HCl1

HAP Conc

%v lb/hr/component lb/hr % lb/hr 

Valves 270 0.0010% 0.0089 0.00002 0 0.00002 Flanges 650 0.0010% 0.0029 0.00002 0 0.00002 Compressor Seals 0 0.0010% 0.5027 0 0 0 Pump Seals 0 0.0010% 0.0386 0 0 0 Relief Valves 36 0.0010% 0.2293 0.00008 0 0.0001 Sample Connections 8 0.0010% 0.033 0.000003 0 0.000003 

Total HAPs 0.0001 

Fugitve HCl Emissions factor basis.Note 1 - HCl emissions are based on conservative assumption of 10 ppmv HCl in syngas per vendor. Other Metals (see below)

Total Metalic HAP Conc.

%v lb/hr/component lb/hr % lb/hr 

Valves 270 0.000004% 0.0089 0.0000001 0 0.0000001 Flanges 650 0.000004% 0.0029 0.0000001 0 0.0000001 Compressor Seals 0 0.000004% 0.5027 0 0 0 Pump Seals 0 0.000004% 0.0386 0 0 0 Relief Valves 36 0.000004% 0.2293 0.0000003 0 0.0000003 Sample Connections 8 0.000004% 0.033 0.00000001 0 0.00000001 Total HAPs 0.000001 

See next page for metalic hap 

Specifically, the below caluclations quantify HAPs from syngas piping leaks of HCl and trace metals. Other HAPs prfrom Emission Unit FUG and FUG-WSA (e.g. Methanol, COS) are documented on a separate spreadsheet which was Application and IDEM's proposed TSD document.

Fugitive SourceFugitive Source Controlle

Component Controlle

Count

Emission Factors

Uncontrolled 

Emissions

Control 

Efficiency

Component

Count

Emission Factors

Uncontrolled 

Emissions

Control 

Efficiency
Page 1 of 2 

Metal HAPs factors for Fugitives leaks of Syngas

HAP

Arsenic2 0.0000001% volume % Note 2

Beryllium2 0.0000001% volume % Note 2Cadmium2 0.00000001% volume % Note 2Chromium2 0.0000001% volume % Note 2Cobalt2 0.00000001% volume % Note 2Manganese2 0.0000001% volume % Note 2Mercury3 0.000004% volume % Note 3Nickel2 0.0000001% volume % Note 2Selenium2 0.0000001% volume % Note 2Lead2 0.0000001% volume % Note 2

Total HAPs for Syngas combustion 0.000004% volume %

Fugitve Metal HAPs Emissions factor basis.

Note 3 - Mercury content of syngas is .0352 ppmv per engineering estimate. Note 2 - Metal HAP factors (except mercury) are from Proposed Duke Edwardsport 

Factor Basis of Factor

Control Efficiencies shown above of zero reflect the fact that the syngas piping is not subject to any control requirements (i.e

not required.)
Indiana Department of Environmental Management

Office of Air Quality

Addendum to the Technical Support Document (ATSD) 

Appendix B – Public Comments List

Source Description and Location

Source Name: Indiana Gasification, LLC

Source Location: CR 200 N and Base Road, Rockport, IN 47635

County: Spencer

SIC Code: 4925, 2819

Operation Permit No.: T 147-30464-00060

Permit Reviewer: Josiah Balogun

Public Commenters

OAQ received comments from the following people (and groups of people):

Alec Kalla 8733 West Summit Circle Drive, French Lick, IN 47432

Don Schroeder 2281 W. Co. Road 350S, Rockport IN 47635

David L. Boggs 216 Western Hills Drive, Mount Vernon, IN 47620

John Blair Valley Watch, Inc 800 Adams Avenue, Evansville IN 47713

Ben A. Taylor 419 Yelvington - Grandview Rd, Maceo, KY 42355

Meleah Geertsma 1152 15th Street, NW, Suite 300 Washington, DC 20005 

George Peridas 111 Sutter St. 20th Floor, San Francisco, CA 94104

Robert Ukeiley 435R Chestnut Street, Suite 1 Berea KY 40403

John Thompson Clean Air Task Force, 18 Tremont St., Suite 530 Boston MA 02108

Greg Sitzman 410 Seminary St, Rockport, IN 47635

Richard Michel 2222E County Rd. 700N, Grandview, IN 47615

Kathy Ferguson Rockport

Evelyn Godwin

Rex Windchill

Cara Beth Jones

Greg James

William Rosenberg
Indiana Gasification, LLC Page 2 of 2

Rockport, Indiana T 147-30464-00060

Permit Reviewer: Josiah Balogun

Speakers Present at the Public Hearing and Public Meeting held on Wednesday, January 25, 2011 

at South Spencer High School, Auditorium, 1141 North Orchard Road, Rockport Indiana.

Bowden Quinn

Wayne Werne

Rock Blanchard

Angela Vanover

Marvin Byrer

James Lacy Kamuf

Mickey Toler

Dan Rininger

Tom Utter

Harold Goffinet

Greg James 

Rex Winchell

Ferman Yearby

Chuck Botsko

John Blair

Jean Dolezal

N. Ryan Zaricki

Wallace McMullen

Ben Taylor

Thomas Pearce

William Rosenberg

Ryan Hidalgo

Steve Sisley

Steve McNamara

Larry Herm

Rick Mckee
Indiana Gasification LLC Page 1 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

Indiana Department of Environmental Management 

Office of Air Quality

Technical Support Document (TSD) for a New Source Construction 

and Part 70 Permit 

Source Description and Location 

Source Name: Indiana Gasification, LLC 

Source Location: CR 200 N and Base Road, Rockport, IN 47635 

County: Spencer 

SIC Code: 4925, 2819 

Operation Permit No.: T 147-30464-00060 

Operation Permit Issuance Date: Yet to be Issued 

Permit Reviewer: Josiah Balogun 

The Office of Air Quality (OAQ) has reviewed a New Source Construction and Part 70 operating 

permit application submitted by Indiana Gasification LLC, on April 20, 2011, in relating to the 

construction and operation of a state - of- the - art substitute natural gas ("SNG") and liquefied 

carbon dioxide ("CO2") production plant. 

History 

The proposed facility is designed to convert Illinois Basin coal and petroleum coke into pipelinequality SNG and liquefied CO2. The project will produce up to 48 billion standard cubic feet (Bscf) of SNG 

annually utilizing approximately 3.5 million tons of feedstock. About 39 Bscf will be sold to the Indiana 

Finance Authority (“IFA”) for use by Indiana natural gas consumers with the remaining sold in the natural 

gas marketplace. The project will also produce annually up to approximately 6.43 million tons of liquefied 

CO2 that will be sold to third parties for use in Enhanced Oil Recovery (“EOR”) where it is estimated to 

produce approximately 10,000,000 barrels per year of additional domestic oil in the Gulf Coast region. 

Facility development is supported by an agreement with the IFA regarding the purchase of the SNG 

production and a loan guarantee currently being negotiated with the Department of Energy, which is intended 

to encourage advanced coal gasification facilities. As a result, the project must conform to any provisions in 

contracts relating to these agreements. 

The facility will have several products in addition to SNG and liquefied CO2. Sulfur compounds in the 

feedstocks will be processed into sulfuric acid, which IG plans to sell into the industrial market. Argon will be 

recovered from the air separation unit and sold to one or more industrial gas companies. Heat generated 

during the gasification process will be used to produce steam for steam turbines that can produce 

approximately 300 MW, primarily to meet on-site power needs. Depending on process and ambient conditions, 

a small amount of power will be exported into or imported from the nearby electrical transmission system. 

Existing Approvals 

There have been no previous approvals issued to this source. 
Indiana Gasification LLC Page 2 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

County Attainment Status 

The source is located in Spencer County. 

Pollutant Designation 

SO2 Better than national standards. 

CO Unclassifiable or attainment effective November 15, 1990. 

O3 Unclassifiable or attainment effective June 15, 2004, for the 8-hour 

ozone standard.1

PM10 Unclassifiable effective November 15, 1990. 

NO2 Cannot be classified or better than national standards. 

PM2.5 Attainment effective November 2, 2011, for the annual PM2.5 

standard for the Evansville area, including Ohio Township of Spencer 

County. 

Pb Not designated. 

1

Unclassifiable or attainment effective October 18, 2000, for the 1-hour ozone 

standard which was revoked effective June 15, 2005. 

 (a) Ozone Standards 

Volatile organic compounds (VOC) and Nitrogen Oxides (NOx) are regulated under the 

Clean Air Act (CAA) for the purposes of attaining and maintaining the National Ambient 

Air Quality Standards (NAAQS) for ozone. Therefore, VOC and NOx emissions are 

considered when evaluating the rule applicability relating to ozone. Spencer County has 

been designated as attainment or unclassifiable for ozone. Therefore, VOC and NOx 

emissions were reviewed pursuant to the requirements for Prevention of Significant 

Deterioration (PSD), 326 IAC 2-2. 

 (b) PM2.5

Spencer County has been classified as attainment for PM2.5. On May 8, 2008, U.S. EPA 

promulgated the requirements for Prevention of Significant Deterioration (PSD) for PM2.5 

emissions. These rules became effective on July 15, 2008. On May 4, 2011 the air 

pollution control board issued an emergency rule establishing the direct PM2.5 significant 

level at ten (10) tons per year. This rule became effective, November 2, 2011. Therefore, 

direct PM2.5 and SO2 emissions were reviewed pursuant to the requirements for 

Prevention of Significant Deterioration (PSD), 326 IAC 2-2. See the State Rule 

Applicability – Entire Source section. 

(c) Other Criteria Pollutants 

Spencer County has been classified as attainment or unclassifiable in Indiana for all other 

pollutants. Therefore, these emissions were reviewed pursuant to the requirements for 

Prevention of Significant Deterioration (PSD), 326 IAC 2-2. 

Fugitive Emissions 

Since this source is considered one of the twenty-eight (28) listed source categories, as specified 

in 326 IAC 2-2, 326 IAC 2-3, or 326 IAC 2-7. Therefore, fugitive emissions are counted toward the 

determination of PSD, Emission Offset, and Part 70 Permit applicability. 

Description of New Source and Emission Units with Control Equipment Summary 

The Office of Air Quality (OAQ) has reviewed a New Source Construction application, submitted by 

Indiana Gasification, LLC on April 20, 2011, relating to the construction and operation of a state - 

of- the - art substitute natural gas ("SNG") and liquefied carbon dioxide ("CO2") production plant. 

The proposed facility is designed to convert Illinois Basin coal and petroleum coke into pipeline-
Indiana Gasification LLC Page 3 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

quality SNG and liquefied CO2. The project will produce up to 48 billion standard cubic feet (Bscf) 

of SNG annually utilizing approximately 3.5 million tons of feedstock. The project will also produce 

annually approximately 4.9 million tons of liquefied CO2 that will be sold to third parties for use in 

Enhanced Oil Recovery (“EOR”) where it is estimated to produce approximately 10,000,000 barrels 

per year of additional domestic oil in the Gulf Coast region. The following is a list of the proposed 

emission unit(s) and pollution control device(s): 

(A) Incoming solid feedstock materials handling system, transferring material from the barge 

unloading facility and railcar unloading facility to storage piles and day bins, consisting of: 

 [Under 40 CFR 60, Subpart Y, the incoming solid feedstock materials handling system, 

transferring material from the barge unloading facility and railcar unloading facility to 

storage piles and day bins are new affected sources.] 

(1) One (1) barge unloading to hopper transfer point, to be permitted in 2012, 

nominally rated at 750 tons per hour, identified as EU-012A, with particulate 

emissions controlled by wet suppression. 

(2) The following twenty (20) transfer points, each with particulate emissions 

controlled with a dust extraction system or baghouse nominally rated at 1,500 

acfm: 

(a) One (1) barge unloading from the hopper to the belt, identified as EU012B, to be permitted in 2012, with one (1) control device, identified as C012B, exhausting through one (1) vent, identified as S-012B; 

(b) Four (4) barge conveyor transfer points, identified as EU-012C through 

EU-012F, to be permitted in 2012, with four (4) control devices, identified 

as C-012C through C-012F, respectively, exhausting through four (4) 

vents, identified as S-012C through S-012F, respectively; 

(c) Two (2) rail unloading to rail hoppers, identified as EU-012G and EU012H, to be permitted in 2012, with two (2) control devices, identified as 

C-012G through C-012H, respectively, exhausting through two (2) vents, 

identified as S-012G through S-012H, respectively; 

(d) Two (2) rail hoppers unloading to the conveyor belts, identified as EU012I and EU-012J, to be permitted in 2012, with two (2) control devices, 

identified as C-012I and C-012J, respectively, exhausting through two (2) 

vents, identified as S-012I through S-012J, respectively; 

(e) One (1) rail conveyor belt to the stacker, identified as EU-012K, to be 

permitted in 2012, with one (1) control device, identified as C-012K, 

exhausting through one (1) vent, identified as S-012K; 

(f) Two (2) stacker belts to the radial stacker, identified as EU-012L and EU012M, to be permitted in 2012, with two (2) control devices, identified as 

C-012L and C-012M, respectively, exhausting through two (2) vents, 

identified as S-012L through S-012M, respectively; 

(g) Two (2) classification towers, identified as EU-012T and EU-012U, to be 

permitted in 2012, with two (2) control devices, identified as C-012T and 

C-012U, respectively, exhausting through two (2) vents, identified as S012T through S-012U, respectively; 

(h) One (1) classification tower to a day bin, identified as EU-012V, to be 

permitted in 2012, with one (1) control device, identified as C-012V, 

exhausting through one (1) vent, identified as S-012V; 
Indiana Gasification LLC Page 4 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

(i) Three (3) truck stations unloading to a truck hopper, identified as EU012Z, EU-012AB and EU-012AC, to be permitted in 2012, with three (3) 

control devices, identified as C-012Z, C-012AB and C-012AC, 

respectively, exhausting through three (3) vents, identified as S-012Z, S012AB and S-012AC, respectively; 

(j) One (1) truck hopper unloading to the conveyor belts, identified as EU012AA, to be permitted in 2012, with one (1) control device, identified as 

C-012AA exhausting through one (1) vent, identified as S-012AA; and 

(k) One (1) truck/rail conveyor transfer tower, identified as EU-012Y, to be 

permitted in 2012, with one (1) control device, identified as C-012Y, 

exhausting through one (1) vent, identified as S-012Y; 

(3) Two (2) radial stackers to the pile, nominally rated at 3,000 tons per hour each, to 

be permitted in 2012, with particulate emissions controlled by telescoping chutes 

with two (2) fabric filters identified as C-012N and C-012O, exhausting through 

two (2) stacks, identified as S-012N and S-012O. 

(4) Two (2) transfer systems consisting of hoppers and conveyor belts transferring 

feed stock from the piles to classification towers, identified as EU-012R and EU012S, to be permitted in 2012, with particulate emissions controlled with two (2) 

dust extraction systems or baghouses, identified as C-012R and C-012S, 

respectively, each nominally rated at 6,000 acfm, exhausting through two (2) 

vents, identified as S-012R and S-012S, respectively. 

(5) Two (2) dozer activities on the piles, nominally rated at 1,500 tons per hour each, 

identified as EU-012P and EU-012Q, to be permitted in 2012, with particulate 

emissions controlled by wet suppression. 

(6) Two (2) storage piles with a nominal capacity of 300,000 tons each, identified as 

EU-012W and EU-012X, to be permitted in 2012, with particulate emissions 

controlled by wet suppression and compaction. 

(B) Two (2) process area solid feedstock conveying, storage, and feed bins (main and spare), 

identified as EU-011A and EU-011B, to be permitted in 2012, with particulate emissions 

controlled by two (2) baghouses identified as C-011A and C-011B, respectively, each 

nominally rated at 33,760 dscfm, exhausting through two (2) stacks, identified as S-011A 

and S-011B, respectively. [Under 40 CFR 60, Subpart Y, the process area solid feedstock 

conveying, storage, and feed bins (main and spare) are new affected sources.] 

(C) One (1) syngas hydrocarbon flare, with a pilot nominally rated at 0.27 MMBtu/hr HHV and 

identified as EU-001, to be permitted in 2012, exhausting through one (1) tip, identified as 

S-001. 

(D) One (1) acid gas flare, with a pilot nominally rated at 0.27 MMBtu/hr HHV and identified as 

EU-002, to be permitted in 2012, exhausting through one (1) tip, identified as S-002. 

(E) Two (2) Acid Gas Removal (AGR) Unit vents, identified as EU-007A and EU-007B, to be 

permitted in 2012, with methanol, H2S, COS, and CO emissions controlled by two (2) 

regenerative thermal oxidizers (RTO) identified as C-007A and C-007B, respectively, 

each nominally rated at 38.8 MMBtu/hr HHV fuel input, exhausting through two (2) stacks, 

identified as S-007A and S-007B. 

(F) Two (2) Wet Sulfuric Acid (WSA) plant trains, each nominally rated at 800 stpd H2SO4 and 

identified as EU-015A and EU-015B, to be permitted in 2012, with NOx, SO2, H2SO4

emissions controlled by two (2) selective catalytic reduction (SCR) systems identified as 

C-015-1A and C-015-1B, respectively, and two (2) hydrogen peroxide scrubbers identified 

as C-015-2A and C-015-2B, respectively, exhausting through two (2) stacks, identified as 
Indiana Gasification LLC Page 5 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

S-015A and S-015B respectively. These emissions units also include two (2) preheat 

burners (one for each train), each nominally rated at 35.00 MMBtu/hr HHV, venting 

through the same stacks. 

 (G) Two (2) natural gas-fired auxiliary boilers, nominally rated at 408 MMBtu/hr HHV each, 

identified as EU-005A and EU-005B, to be permitted in 2012, with NOx emissions 

controlled by ultra-low NOx burners/Flue Gas Recirculation (ULNB/FGR), with both boilers 

exhausting through one (1) stack, identified as S-005. [Under 40 CFR 60, Subpart Db, the 

natural gas-fired auxiliary boilers are new affected sources.] 

(H) Five (5) natural gas-fired and SNG fuel-fired gasifier preheat burners, each nominally 

rated with a heat input of 35.00 MMBtu/hr HHV, and identified as EU-008A through EU008E, to be permitted in 2012, exhausting through five (5) vents, identified as S-008A 

through S-008E, respectively. 

(I) One (1) ZLD-Spray Dryer, to be permitted in 2012, nominally rated at 5.6 MMBtu/hr with 

PM emissions controlled by a baghouse identified as C-032, nominally rated at 2,735 

dscfm, and identified as EU-032, with low NOx burners (LNB), exhausting through one (1) 

stack, identified as S-014. 

(J) Methanol Tanks: 

(1) One (1) Methanol De-Inventory Tank, with a nominal capacity of 700,000 gallons, 

identified as EU-024, to be permitted in 2012, with emissions controlled by a 

vapor recovery system and exhausting through one (1) vent, identified as S-024. 

[40 CFR 60 Subpart Kb]. 

(2) One (1) Fresh Methanol Storage Tank, with a nominal capacity of 332,000 

gallons, identified as EU-025, to be permitted in 2012, with emissions controlled 

by a vapor recovery system and exhausting through one (1) vent, identified as S025. [40 CFR 60 Subpart Kb]. 

(K) Paved Plant Haul Roads are identified as emissions unit FUG-ROAD. 

(L) Electrical Circuit Breakers (approximately six) containing sulfur hexafluoride (SF6) 

identified as emissions unit FUG-SF6, to be permitted in 2012, with fugitive GHG 

emissions controlled by full enclosure. 

(M) Fugitive Equipment Leaks from the gasification, shift conversion, gas cooling, AGR, CO2

compression, WSA and methanation are identified as emissions units FUG and FUGWSA and will be controlled by a Leak Detection and Repair (LDAR) program. 

(N) One (1) ZLD Inert Gas Vent identified as EU-033, to be permitted in 2012, with mercury 

(Hg) emissions controlled by a sulfided carbon adsorbent identified as C-033, exhausting 

through one (1) stack, identified as S-033. 

Insignificant and Trivial Activities 

The source also consists of the following insignificant activities as defined in 326 IAC 2-7-1(21): 

(a) Two (2) emergency diesel generators, each nominally rated at 1,341 horsepower, 

identified as EU-009A and EU-009B, to be permitted in 2012, exhausting through two (2) 

vents, identified as S-009A and S-009B, respectively. [Under 40 CFR 60, Subpart IIII, 

each, emergency diesel fired generator is considered a new affected source.][Under 40 

CFR 63, Subpart ZZZZ, each, emergency diesel fired generator is considered a new 

affected source.] 
Indiana Gasification LLC Page 6 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

(b) Three (3) firewater pump diesel engines, each nominally rated at 575 horsepower and 

identified as EU-010A through EU-010C, to be permitted in 2012, exhausting through 

three (3) vents, identified as S-010A through S-010C, respectively. [Under 40 CFR 60, 

Subpart IIII, each firewater pump diesel engine is considered a new affected 

source.][Under 40 CFR 63, Subpart ZZZZ, each firewater pump diesel engine is 

considered a new affected source.] 

(c) Four (4) rod mill eductor vent stacks, to be permitted in 2012, nominally rated at 180 cfm 

and identified as EU-013A through EU-013D, and exhausting through four (4) vents, 

identified as S-013A through S-013D, respectively. 

(d) One (1) six (6) cell ASU cooling tower, nominally rated with a circulation rate of 54,960 

gpm and identified as EU-016A, to be permitted in 2012, with high efficiency drift/mist 

eliminators, and exhausting through six (6) vents, identified as S-016A-A through 

 S-016A-F. 

(e) One (1) twenty-four (24) cell main cooling tower, nominally rated with a circulation rate of 

404,700 gpm and identified as EU-016B, to be permitted in 2012, with high efficiency 

drift/mist eliminators, and exhausting through twenty-four (24) vents, identified as S-016BA through S-016B-X. 

(f) Two (2) Air Separation Unit (ASU) molecular sieve regeneration train vents, which each 

vent a nominal 187,000 cubic feet per minute during regenerations, identified as EU-017A 

and EU-017B, to be permitted in 2012, exhausting through two (2) vents, identified as S017A andS-017B, respectively. 

(g) One (1) slag handling storage pad, to be permitted in 2012, nominally rated at 43 tons per 

hour, identified as EU-034A, with fugitive particulate emissions controlled by wet 

suppression. 

(h) One (1) front-end loader activity on the slag storage pad, to be permitted in 2012, 

nominally rated at 1,440 tons per day, identified as EU-034C, with fugitive particulate 

emissions controlled by wet suppression. 

(i) One (1) fixed roof recycle solid tank, to be permitted in 2012, with a nominal capacity of 

14,400 gallons, identified as EU-019. 

(j) Five (5) fixed roof slurry run tanks, each, to be permitted in 2012, with a nominal capacity 

of 47,700 gallons, identified as EU-020A through EU-020E. 

(k) Two (2) fixed roof grey water tanks, to be permitted in 2012, each with a nominal capacity 

of 88,000 gallons, identified as EU-021A and EU-021B. 

(l) One (1) fixed roof slurry additive tank, to be permitted in 2012, with a nominal capacity of 

28,500 gallons, identified as EU-022. 

(m) Five (5) open slag sumps, to be permitted in 2012, each with a nominal capacity of 15,600 

gallons, identified as EU-023A through EU-023E. 

(n) One (1) pressurized Sour Water Stripper Surge Tank, to be permitted in 2012, with a 

nominal capacity of 175,000 gallons, identified as EU-026. 

(o) Six (6) fixed roof sulfuric acid storage tanks, to be permitted in 2012, each with a nominal 

capacity of 866,500 gallons - identified as EU-027A through EU-027F. 

(p) Two (2) fixed roof aqueous ammonia storage tanks, to be permitted in 2012, each with a 

nominal capacity of 31,000 gallons - identified as EU-028A and EU-028B, with ammonia 

emissions controlled with two (2) water scrubbers identified as C-028A and C-028B, 

respectively. 
Indiana Gasification LLC Page 7 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

(q) One (1) fixed roof Diesel Fuel Storage Tank, to be permitted in 2012, with a nominal 

capacity of 9,240 gallons, identified as EU-029. 

(r) One (1) fixed roof Gasoline Fuel Storage Tank, to be permitted in 2012, with a nominal 

capacity of 1,030 gallons, identified as EU-030. 

(s) One (1) fixed roof triethylene glycol storage tank, to be permitted in 2012, with a nominal 

capacity of less than 10,000 gallons, identified as EU-031. 

Enforcement Issues 

There are no pending enforcement actions. 

Emission Calculations 

See Appendix A of this Technical Support Document for detailed emission calculations. 

Unrestricted Potential Emissions – Part 70 

Pursuant to 326 IAC 2-1.1-1(16), Potential to Emit is defined as “the maximum capacity of a 

stationary source or emission unit to emit any air pollutant under its physical and operational 

design. Any physical or operational limitation on the capacity of a source to emit an air pollutant, 

including air pollution control equipment and restrictions on hours of operation or type or amount 

of material combusted, stored, or processed shall be treated as part of its design if the limitation is 

enforceable by the U. S. EPA, IDEM, or the appropriate local air pollution control agency.” 

The following table is used to determine the appropriate permit level under 326 IAC 2-7-10.5. This 

table reflects the PTE before controls. Control equipment is not considered federally enforceable 

until it has been required in a federally enforceable permit. 

PTE Before Controls 

Pollutant Potential To Emit (ton/yr) 

PM 322.93 

PM10 207.09 

PM2.5 73.63 

SO2 119.9 

VOC 90.26 

CO 302,916 

NOX 588.4 

H2SO4 43.89 

H2S 12.3 

Pb 0.04 

Hg 0.07 

GHGs as CO2e 3,094,536 (Note 1)

HAPs Potential To Emit (tons/year) 

Methanol 17.98 

Lead 0.04 

Beryllium 0.000059 

Mercury 0.07 

Manganese < 10 

 Chlorine < 10 
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

HAPs Potential To Emit (tons/year) 

Formaldehyde < 10 

other HAPs greater than 10 

Total HAPs greater than 25 

Note 1: The above GHG emissions reflect the PTE in operating Year 3 and beyond. The PTE Year 1 estimated as 

6,494,536 tons/yr CO2e. The PTE Year 2 estimated as 8,234,536 tons/yr CO2e. 

 (a) The potential to emit (as defined in 326 IAC 2-7-1(29)) of PM10, PM2.5, SO2, CO and NOx 

are equal to or greater than 100 tons per year. Therefore, the source is subject to the 

provisions of 326 IAC 2-7 and will be issued a Part 70 Operating Permit. 

(b) The potential to emit (as defined in 326 IAC 2-7-1(29)) of GHGs is equal to or greater than 

one hundred thousand (100,000) tons of CO2 equivalent emissions (CO2e) per year. 

Therefore, the source is subject to the provisions of 326 IAC 2-7 and will be issued a Part 

70 Operating Permit. 

(c) The potential to emit (as defined in 326 IAC 2-7-1(29)) of all other regulated pollutants are 

less than 100 tons per year. 

(d) The potential to emit (as defined in 326 IAC 2-7-1(29)) of any single HAP is equal to or 

greater than ten (10) tons per year and the potential to emit (as defined in 326 IAC 2-7-

1(29)) of a combination of HAPs is equal to or greater than twenty-five (25) tons per year. 

 Therefore, the source is subject to the provisions of 326 IAC 2-7. 

Actual Emissions 

No previous emission data has been received from the source. 

Part 70 Permit Conditions 

This source is subject to the requirements of 326 IAC 2-7, because the source met the following: 

(a) Emission limitations and standards, including those operational requirements and 

limitations that assure compliance with all applicable requirements at the time of issuance 

of Part 70 permits. 

(b) Monitoring and related record keeping requirements which assume that all reasonable 

information is provided to evaluate continuous compliance with the applicable 

requirements.
Indiana Gasification LLC Page 9 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 Permit Reviewer: Josiah Balogun

Permit Level Determination – PSD 

The table below summarizes the potential to emit, reflecting all limits, of the emission units at Indiana Gasification, LLC. An

equipment is considered federally enforceable only after issuance of this Part 70 permit, and only to the extent that the effec

equipment is made practically enforceable in the permit. 

Potential to Emit (ton/yr) 

Process / Emission Unit 

PM PM10 PM2.5 SO2 VOC CO NOx H2SO4 H2S Pb Hg M

Syngas Hydrocarbon Flare001 

0.44 0.44 0.41 1.97 0.03 23.5 6.07 0 0.04 3E-06 1.9E-06 

Acid Gas Flare -002 

0.01 0.01 0.01 0.001 0.023 0.06 0.23 0 0 3E-06 1.9E-06 

Auxiliary Boiler (AB) -005 5.62 5.62 5.62 0.44 4.07 27.15 9.43 0 0 2E-03 1.3E-03 Acid Gas Recovery Unit (A-B) -007 2.46 2.46 2.46 26.98 8.96 410.27 16.85 0 0.1 9.6E- 0.4 5.5E-04 Gasifier Preheat Burners (A-E) -008 0.04 0.04 0.04 0.03 0.3 3.08 5.51 0 0 1.6E- 04 9.0E-05 Emergency Diesel Generators (A-B) -009 

0.003 0.003 3E-04 0.008 0.015 0.019 

0.76 

0 

0 0 0 

Emergency Firewater pumps (A-C) - 010 

0.008 0.008 8E-03 5E-04 0.017 0.06 

0.24 

0 

0 0 0 

Process Area Solid Feedstock Handling (Coal/Petcoke) - 011 

3.8 3.8 1.86 0 0 0 0 0 0 1.1E03 5.5E-06 

Incoming Solid Feed stock handling (Coal/petcoke) (A5.45 3.25 0.88 0 0 0 0 0 0 0 8.9E-06 
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 Permit Reviewer: Josiah Balogun

Potential to Emit (ton/yr) 

Process / Emission Unit 

PM PM10 PM2.5 SO2 VOC CO NOx H2SO4 H2S Pb Hg M

AC) - 012 Rod Mill (A-D) -013 0.44 0.44 0.13 0 0 0 0 0 0 0 3.8E-07 Wet Sulfuric Acid Plant (A-B) - 015 42.6 42.6 42.6 70.74 0.01 159.7 86.93 42.6 0 6E-06 3.5E-06 Cooling Tower - ASU - 016A 0.9 0.9 0.70 0 0 0 0 0 0 0 0 Cooling Tower - Main - 016B 6.65 6.65 5.19 0 0 0 0 0 0 0 0 ASU Molecular Sieve Regeneration (A-B) - 017 

0.22 0.22 0.08 0 0 0 0 0 0 0 0 

Slag Sump (A-E) - 023 0 0 0 0 0 0 0 0 0.1 0 0 Methanol Deinventory Tank - 024 

0 0 0 0 0.16 0 

0 

0 

0 0 0 

Fresh Methanol Storage Tank - 025 0 0 0 0 0.13 0 0 0 0 0 0 Sour Water Striper Surge Tank - 026 0 0 0 0 0.004 0 0 0 0.54 0 0 Sulfuric Acid Storage Tank (A-F) - 027 

0.0015 0.0015 0.0015 0 0 0 

0 

0.0015 

0 0 0 

Diesel Fuel Storage Tank - 029 0 0 0 0 0.35 0 0 0 0 0 0 Gasoline Fuel Storage Tank - 030 0 0 0 0 0.1 0 0 0 0 0 0 
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 Permit Reviewer: Josiah Balogun

Potential to Emit (ton/yr) 

Process / Emission Unit 

PM PM10 PM2.5 SO2 VOC CO NOx H2SO4 H2S Pb Hg M

Triethylene Glycol Storage Tank - 031 0 0 0 0 0 0 

0 

0 

0 0 0 

ZLD Spray Dryer - 032 0.51 0.51 0.48 0.015 0.13 0.89 0.86 0 0 7E-05 4.1E-05 ZLD Inert Gas Vent (033) 0 0 0 0 0 0 0 0 0 0 3.6E-04 EU-034A and EU034C 0.04 0.017 0.0024 0 0 0 0 0 0 0 0 Fugitive Emissions Gasification, Shift Conv., AGR, Methanation - FUG 

0 0 0 0 1.61 9.45 

0 

0 

0.37 0 0 

WSA - FUG-WSA 0 0 0 0.003 0 0 0 009 3.74 0 0 Plant Haul Road - FUG ROAD 0.45 0.09 0.022 0 0 0 0 0 0 0 0 Electric Circuit Breakers - FUG SF6 

0 0 0 0 0 0 

0 

0 

0 0 0 

Total Emission for New Source Construction 

69.63 67.05 60.48 100.2 15.90 634.18 126.9 42.68 4.89 0.004 0.0023 

Nonattainment NSR Major Source Thresholds 

-- -- 100 100 -- -- 

-- 

-- 

-- -- -- 

Significant Level 25 15 10 40 40 100 40 7 10 0.6 0.1 

Note 2: The above GHG emissions reflect the PTE in operating year three and beyond. The PTE Year 1 estimated as 5,275,448 tons/yr CO2e. The PTE 

7,015,448 tons/yr CO2e. 
Indiana Gasification LLC Page 12 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 Permit Reviewer: Josiah Balogun

This new stationary source is a major stationary source, under PSD (326 IAC 2-2), because a regulated pollutant is 

tons per year or more, emissions of GHGs are equal to or greater than one hundred thousand (>100,000) tons of C

(CO2e) per year, which is greater than the PSD threshold and it is one of the twenty-eight (28) listed source catego

 IAC 2-2-1(gg)(1). Therefore, pursuant to 326 IAC 2-2, the PSD requirements do apply to the new source.
Indiana Gasification LLC Page 13 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

Federal Rule Applicability Determination 

The following federal rules are applicable to the source due to this New Source Construction: 

(a) Pursuant to 40 CFR 64.2, Compliance Assurance Monitoring (CAM) is applicable to new 

or modified emission units that involve a pollutant-specific emission unit and meet the 

following criteria: 

(1) has a potential to emit before controls equal to or greater than the Part 70 major 

source threshold for the pollutant involved; 

(2) is subject to an emission limitation or standard for that pollutant; and 

(3) uses a control device, as defined in 40 CFR 64.1, to comply with that emission 

limitation or standard. 

The following table is used to identify the applicability of each of the criteria, under 40 CFR 64.1, 

to each new or modified emission unit involved: 

CAM Applicability Analysis 

Emission Unit Control 

Device

Used 

Emission

Limitation

(Y/N)

Uncontrolled

PTE

(ton/yr)

Controlled

PTE

(ton/yr)

Part 70 

Major

Source

Threshold 

(ton/yr)

CAM

Applicable

(Y/N)

Large

Unit 

(Y/N)

Syngas 

Hydrocarbon 

Flare -001 (CO) 

N Y > 100 < 100 100 N N 

Auxiliary Boiler 

- 005 (CO) 

N Y > 100 < 100 100 N N 

Acid Gas 

Recovery Unit 

(A-B) -007 (CO) 

Y Y > 100 > 100 100 Y Y 

Wet Sulfuric 

Acid Plant (A-B) 

- 015 (NOx) 

Y Y >100 < 100 100 Y N 

Wet Sulfuric 

Acid Plant (A-B) 

- 015 (SO2) 

Y Y >100 < 100 100 Y N 

Wet Sulfuric 

Acid Plant (A-B) 

- 015 (H2SO4) 

Y Y > 100 < 100 100 Y N 

Based on this evaluation, the requirements of 40 CFR Part 64, CAM are applicable to Wet 

Sulfuric Acid Plant (A-B) - 015 for NOx, SO2 and H2SO4, the Acid Gas Recovery Unit (A-B) -007 

for CO, upon start-up. A CAM plan has been submitted (See Appendix D for the detailed CAM 

Plan). 

 

CAM does not apply to any other emission units at this source, either because their uncontrolled 

emissions rate is less than 100 tpy or because emissions are limited by inherent process equipment 

that is not considered a control device per the 40 CFR 64.1 definition of inherent process equipment. 

 

 (b) The requirements of Area Source MACT- National Emission Standards for Hazardous Air 

Pollutants – Industrial, Commercial, and Institutional Boilers at Area Sources 40 CFR Part 63 

Subpart JJJJJJ recently promulgated for Industrial, Commercial, and Institutional Boilers 

(Area Boiler MACT) do not apply to the auxiliary boiler, identified as (E005). The final EPA 
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

rule does not regulate area source boilers that fire only natural gas fuel – because they do not 

emit sufficient urban air toxics to require regulation. In the proposed rule preamble, EPA 

states: “ . . . pursuant to section 112(c)(3) of the CAA, we are proposing emission standards 

for the above mentioned HAP for area source boilers fired by coal, oil, and wood, but not 

standards for boilers fired by natural gas.” In the final rule Preamble EPA again clarified that

“Notably, gas-fired units are not included in the source category listing for area source 

boilers.” 

(c) 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 are not 

applicable to any sources in this project. The requirements of this rule apply to steamgenerating units that commence construction, modification, or reconstruction after August 17, 

1971 and that have a heat input capacity from fuels combusted in the steam generating unit 

of greater than 73 MW (250 million Btu/hour). Although the auxiliary boilers (EU 005A/B) 

have a heat input capacity greater than 250 MMBtu/hr, each and are steam-generating units, 

pursuant to 40 CFR 60.40b(j) the auxiliary boilers are exempt from the requirements of 

NSPS Subpart D because they are instead subject to the requirements of NSPS Subpart Db.

   

The thermal oxidizers (EUs 007A, B) and the gasifier pre-heat burners (EUs 008A-E) have a 

maximum design heat input capacity less than 73 MW (250 MMBtu/hr) and they are not 

steam-generating units; therefore Subpart D does not apply to these sources. 

(d) The requirements of Standards of Performance for Electric Utility Steam Generating Units for 

which Construction is Commenced after September 18, 1978 40 CFR 60, Subpart Da 

 do not apply to any emission units at the sources. The requirements of this rule apply to 

electric utility steam-generating units that commence construction, modification, or 

reconstruction after September 18, 1978, and that have a heat input capacity from fuels 

combusted in the steam-generating unit of greater than 73 MW (250 million Btu/hour). The 

auxiliary boilers, which can supply steam to an electric generating steam turbine are steamgenerating units, but they are not considered electric utility units because they will not supply 

more than 1/3 of its potential electrical output capacity to any utility power distribution system. 

 The requirements of this rule 40 CFR 60, Subpart Da are not applicable to the thermal 

oxidizers (EUs 007A, B) or gasifier pre-heat burners (EUs 008A-E) since they do not meet the 

definition of an electric utility steam generating unit. Specifically, the thermal oxidizers and 

the pre-heat burners do not generate steam, and thus are not steam generating units. 

(e) The requirements of Standards of Performance for Small Industrial Commercial Institutional 

Steam Generating Units 40 CFR 60, Subpart Dc are not applicable to any of the emission 

units at source. The requirements of this rule are applicable to steam generating units for 

which construction, modification, or reconstruction is commenced after June 9, 1989 and that 

has a maximum design heat input capacity of 29 megawatts (MW) (100 MMBtu/hr) or less, 

but greater than or equal to 2.9 MW (10 MMBtu/hr). The auxiliary boilers (EU 005A/B) have a 

heat input capacity greater 100 MMBtu/hr; therefore Subpart Dc does not apply. The thermal 

oxidizers (EUs 007A, B) and the burners (EUs 008A-E) are not steam generating units; 

therefore, 40 CFR 60, Subpart Dc does not apply. 

(f) 40 CFR Part 63 Subpart VVVVVV—National Emission Standards for Hazardous Air 

Pollutants for Chemical Manufacturing Area Sources While this facility is an area 

source of HAPs, This source is not subject to 40 CFR Part 63 Subpart VVVVVV because 

this rule only regulates facilities that use as feedstocks, generates as byproducts, or 

produces as products any of the hazardous air pollutants (HAP) listed in Table 1 to this 

subpart. This facility does not use any of the listed HAPs as a feedstock or generate them 

as products or byproducts. 

(g) 40 CFR 60 Subparts VVa, III, NNN, RRR and YYY –Standards of Performance that apply 

to the Synthetic Organic Chemicals Manufacturing Industry. This facility does not 
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

manufacturer any of the SOCMI chemicals listed in 40 CFR 60.489 

(h) 40 CFR 60 Subparts J,GGGa, and QQQ – Standards of Performance that apply to 

petroleum refineries. This facility does not process petroleum and therefore does not meet 

the definition of petroleum refinery under these standards. 

(i) 40 CFR 60 Subparts KKK and LLL – Standards of Performance that apply to natural gas 

processing facilities. These rules apply to facilities that extract and process natural gas 

liquids from field gas. This facility does not meet the definition of a natural gas processing 

facility under these two rules. 

 (j) The requirements of Standards of Performance for Sulfuric Acid Plants 40 CFR 60, Subpart 

H do not apply to the project’s Sulfuric Acid Plant, because it does not meet the rule’s 

definition of a sulfuric acid production unit. 40 CFR 60, Subpart H applies to sulfuric acid 

plants defined as follows (emphasis added): 

(1) Sulfuric acid production unit means any facility producing sulfuric acid by the 

contact process by burning elemental sulfur, alkylation acid, hydrogen 

sulfide, organic sulfides and mercaptans, or acid sludge, but does not 

include facilities where conversion to sulfuric acid is utilized primarily as a 

means of preventing emissions to the atmosphere of sulfur dioxide or other 

sulfur compounds. 

The Indiana Gasification, LLC Sulfuric Acid Plant is utilized primarily as a means of 

preventing emissions to the atmosphere of sulfur dioxide or other sulfuric compounds. 

Therefore, it does not fit the applicability requirement shown above. The sulfuric acid facility 

is a sulfur recovery process which converts the sulfur compounds removed from the syngas 

in the AGR, thereby preventing their emissions to the atmosphere. The H2S and COS in the 

acid gas stream from the Rectisol Process is combusted for conversion to SO2. The SO2 rich 

gas produced is sent to catalyst beds for conversion to SO3 and then conversion to sulfuric 

acid (H2SO4) after reaction with water. 

Therefore, the Indiana Gasification sulfuric acid plant does not meet the definition of sulfuric 

acid production unit as defined by 40 CFR 60, Subpart H and does not apply to the WSA 

stack vents (EUs 015A, B). This is further confirmed by an EPA applicability determination 

for an analogous sulfuric acid plant at a petroleum refinery. In this 1995 applicability memo 

(ADI control number 9600093), EPA states that a WSA that produces H2SO4 from H2S is not 

covered by NSPS Subpart H. 

(k) The requirements of Standards of Performance for Volatile Organic Liquid Storage 

Vessels (including Petroleum Liquid Storage Vessels) for Which Construction, 

Reconstruction, or Modification Commenced after July 23, 1984 40 CFR 60, Subpart Kb 

are not applicable to the following storage tanks listed below because the tanks do not 

store organic materials and have capacities and maximum true vapor pressure less than 

151 cubic meters (m3

) and 3.5 kPa, respectively. 

EU No. Tank ID Tank 

Capacity 

(Gal) 

Max. Vapor 

Pressure 

Psia 

40 CFR 60, 

Subpart Kb 

Tank Vents 

to: 

023 A Slag Sump 25,284 1.52 No (1) Atmosphere 

023 B Slag Sump 25,284 1.52 No (1) Atmosphere 

023 C Slag Sump 25,284 1.52 No (1) Atmosphere 

023 D Slag Sump 25,284 1.52 No (1) Atmosphere 

023 E Slag Sump 25,284 1.52 No (1) Atmosphere 
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

EU No. Tank ID Tank 

Capacity 

(Gal) 

Max. Vapor 

Pressure 

Psia 

40 CFR 60, 

Subpart Kb 

Tank Vents 

to: 

027 A Sulfuric Acid Storage 

Tank 

867,000 <0.5 No (1) Atmosphere 

027 B Sulfuric Acid Storage 

Tank 

867,000 <0.5 No (1) Atmosphere 

027 C Sulfuric Acid Storage 

Tank 

867,000 <0.5 No (1) Atmosphere 

027 D Sulfuric Acid Storage 

Tank 

867,000 <0.5 No (1) Atmosphere 

027 E Sulfuric Acid Storage 

Tank 

867,000 <0.5 No (1) Atmosphere 

027 F Sulfuric Acid Storage 

Tank 

867,000 <0.5 No (1) Atmosphere 

028 A Aqueous Ammonia Tank 32,243 5.38 No (1) Atmosphere 

028 B Aqueous Ammonia Tank 32,243 5.38 No (1) Atmosphere 

030 Gasoline Tank 1,175 6.20 No (2) Atmosphere 

Note: (1) Tank does not store VOCs. 

 (2) This source is not subject to NSPS Subpart Kb because the tank does not meet the capacity criteria. 

(l) The auxiliary boilers, identified as EU 005A and EU-5B are subject to the requirements of 

the New Source Performance Standard, 40 CFR 60, Subpart Db, Standard of Performance 

for Industrial -Commercial Institutional Steam Generating Unit, which is incorporated by 

reference as 326 IAC 12 because they are boilers that will commence construction, 

modification, or reconstruction after June 19, 1984, and that have a heat input capacity 

from fuels combusted in the steam generating unit of greater than 29 megawatts (MW) 

(100 million British thermal units per hour (MMBtu/hr)). The auxiliary boilers, identified as 

EU 005A and EU- 5B, each has a heat input capacity greater than 100 MMBtu/hr. The 

specific facilities subject to this rule includes the following. 

(1) Two (2) natural gas-fired auxiliary boilers, nominally rated at 408 MMBtu/hr HHV 

each, identified as EU-005A and EU-005B, to be permitted in 2012, with NOx

emissions controlled by ultra-low NOx burners/Flue Gas Recirculation 

(ULNB/FGR), with both boilers exhausting through one (1) stack, identified as S005. [Under 40 CFR 60, Subpart Db, the natural gas-fired auxiliary boilers are 

new affected source.] 

 The boilers are subject to the following portions of Subpart Db: 

 (1) 40 CFR 60.40b(a); 

 (2) 40 CFR 60.40b(j); 

 (3) 40 CFR 60.41b(b); 

 (4) 40 CFR 60.42b(k)(2); 

 (5) 40 CFR 60.44b(h); 

 (6) 40 CFR 60.44b(i); 

 (7) 40 CFR 60.44b(l); 

 (8) 40 CFR 60.46b(a); 

 (9) 40 CFR 60.46b(c); 

 (10) 40 CFR 60.46b(e)(1); 

 (11) 40 CFR 60.46b(e)(3); 

 (12) 40 CFR 60.48b(b); 

 (13) 40 CFR 60.48b(c); 

 (14) 40 CFR 60.48b(d); 

 (15) 40 CFR 60.48b(e)(2); 

 (16) 40 CFR 60.48b(e)(3); 

 (17) 40 CFR 60.48b(f); 
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Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

 (18) 40 CFR 60.49b(a); 

 (19) 40 CFR 60.49b(b); 

 (20) 40 CFR 60.49b(d); 

 (21) 40 CFR 60.49b(g); 

 (22) 40 CFR 60.49b(i); and 

 (23) 40 CFR 60.49b(o). 

NOTE: The auxiliary boilers will only fire natural gas or SNG. Therefore, Subpart Db will not 

impose any applicable PM10 or SO2 emission standards. The Subpart Db NOx standard 

applicable to these sources, high heat release boilers, is 0.10 lb/MMBtu (per 40 CFR 

60.44b (a) (1) (ii)). This emission limit is less restrictive than the proposed Best Available 

Control Technology (BACT) limit discussed in Section 5. NOx emission will be controlled 

with the use of ultra low NOx burners and flue gas recirculation. 

Compliance testing will be performed per 40 CFR 60.46b(e). NOx monitoring will be 

accomplished using a continuous emission monitoring system (CEMS) per 40 CFR 

60.48b(b)(1). 

(m) The requirements of Standards of Performance for Volatile Organic Liquid Storage Vessels 

(including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or 

Modification Commenced after July 23, 1984 40 CFR 60, Subpart Kb are applicable to the 

Methanol Deinventory Tank, Identified as 024 and the fresh Methanol Storage Tank, 

identified as 025 because they store organic materials, will have commenced construction 

after July 23, 1984, have capacities greater than 151 cubic meters (m3

) (39,889 gallons) 

and store only volatile organic compounds with a maximum true vapor pressure greater 

than 3.5 kPa. The specific facilities subject to this rule includes the following. 

 (A) Methanol Tanks: 

(1) One (1) Methanol De-Inventory Tank, with a nominal capacity of 700,000 

gallons, identified as EU-024, to be permitted in 2012, with emissions 

controlled by a vapor recovery system and exhausting through one (1) 

vent, identified as S-024. [40 CFR 60 Subpart Kb]. 

(2) One (1) Fresh Methanol Storage Tank, with a nominal capacity of 

332,000 gallons, identified as EU-025, to be permitted in 2012, with 

emissions controlled by a vapor recovery system and exhausting through 

one (1) vent, identified as S-025. [40 CFR 60 Subpart Kb]. 

 The storage tanks are subject to the following portions of Subpart Kb: 

 

 (1) 40 CFR 60.110b(a); 

 (2) 40 CFR 60.110b(e); 

 (3) 40 CFR 60.111b; 

 (4) 40 CFR 60.112b(a)(3); 

 (5) 40 CFR 60.112b(a)(4); 

 (6) 40 CFR 60.113b(c); 

 (7) 40 CFR 60.114b(c); 

 (8) 40 CFR 60.115b(c); 

 (9) 40 CFR 60.116b(a); 

 (10) 40 CFR 60.116b(b); 

 (11) 40 CFR 60.116b(e); and 

 (12) 40 CFR 60.116b(g). 

(n) The source is subject to the New Source Performance Standard - Standards of 

Performance for Coal Preparation and Processing Plants, 40 CFR 60, Subpart Y, which is 

incorporated by reference as 326 IAC 12. These requirements apply to facilities that 

prepare coal by one of more of several listed processes and which process more than 161 
Indiana Gasification LLC Page 18 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

mega-grams per day (200 tons per day) of coal and commenced construction after May 27, 

2009. The activities regulated by this NSPS include crushing, screening, conveying, and 

transferring of coal. The specific facilities subject to this rule include the following. 

(A) Incoming solid feedstock materials handling system, transferring material from the 

barge unloading facility and railcar unloading facility to storage piles and day bins, 

consisting of: [Under 40 CFR 60, Subpart Y, the incoming solid feedstock 

materials handling system, transferring material from the barge unloading facility 

and railcar unloading facility to storage piles and day bins are new affected 

sources.] 

(1) One (1) barge unloading to hopper transfer point, to be permitted in 2012, 

nominally rated at 750 tons per hour, identified as EU-012A, with particulate 

emissions controlled by wet suppression. 

(2) The following twenty (20) transfer points, each with particulate emissions 

controlled with a dust extraction system or baghouse nominally rated at 1,500 

acfm: 

(a) One (1) barge unloading from the hopper to the belt, identified as EU012B, to be permitted in 2012, with one (1) control device, identified as C012B, exhausting through one (1) vent, identified as S-012B; 

(b) Four (4) barge conveyor transfer points, identified as EU-012C through 

EU-012F, to be permitted in 2012, with four (4) control devices, identified 

as C-012C through C-012F, respectively, exhausting through four (4) 

vents, identified as S-012C through S-012F, respectively; 

(c) Two (2) rail unloading to rail hoppers, identified as EU-012G and EU012H, to be permitted in 2012, with two (2) control devices, identified as 

C-012G through C-012H, respectively, exhausting through two (2) vents, 

identified as S-012G through S-012H, respectively; 

(d) Two (2) rail hoppers unloading to the conveyor belts, identified as EU012I and EU-012J, to be permitted in 2012, with two (2) control devices, 

identified as C-012I and C-012J, respectively, exhausting through two (2) 

vents, identified as S-012I through S-012J, respectively; 

(e) One (1) rail conveyor belt to the stacker, identified as EU-012K, to be 

permitted in 2012, with one (1) control device, identified as C-012K, 

exhausting through one (1) vent, identified as S-012K; 

(f) Two (2) stacker belts to the radial stacker, identified as EU-012L and EU012M, to be permitted in 2012, with two (2) control devices, identified as 

C-012L and C-012M, respectively, exhausting through two (2) vents, 

identified as S-012L through S-012M, respectively; 

(g) Two (2) classification towers, identified as EU-012T and EU-012U, to be 

permitted in 2012, with two (2) control devices, identified as C-012T and 

C-012U, respectively, exhausting through two (2) vents, identified as S012T through S-012U, respectively; 

(h) One (1) classification tower to a day bin, identified as EU-012V, to be 

permitted in 2012, with one (1) control device, identified as C-012V, 

exhausting through one (1) vent, identified as S-012V; 

(i) Three (3) truck stations unloading to a truck hopper, identified as EU012Z, EU-012AB and EU-012AC, to be permitted in 2012, with three (3) 

control devices, identified as C-012Z, C-012AB and C-012AC, 
Indiana Gasification LLC Page 19 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

respectively, exhausting through three (3) vents, identified as S-012Z, S012AB and S-012AC, respectively; 

(j) One (1) truck hopper unloading to the conveyor belts, identified as EU012AA, to be permitted in 2012, with one (1) control device, identified as 

C-012AA exhausting through one (1) vent, identified as S-012AA; and 

(k) One (1) truck/rail conveyor transfer tower, identified as EU-012Y, to be 

permitted in 2012, with one (1) control device, identified as C-012Y, 

exhausting through one (1) vent, identified as S-012Y; 

(3) Two (2) radial stackers to the pile, nominally rated at 3,000 tons per hour each, to 

be permitted in 2012, with particulate emissions controlled by telescoping chutes 

with two (2) fabric filters identified as C-012N and C-012O, exhausting through 

two (2) stacks, identified as S-012N and S-012O. 

(4) Two (2) transfer systems consisting of hoppers and conveyor belts transferring 

feed stock from the piles to classification towers, identified as EU-012R and EU012S, to be permitted in 2012, with particulate emissions controlled with two (2) 

dust extraction systems or baghouses, identified as C-012R and C-012S, 

respectively, each nominally rated at 6,000 acfm, exhausting through two (2) 

vents, identified as S-012R and S-012S, respectively. 

(5) Two (2) dozer activities on the piles, nominally rated at 1,500 tons per hour each, 

identified as EU-012P and EU-012Q, to be permitted in 2012, with particulate 

emissions controlled by wet suppression. 

(6) Two (2) storage piles with a nominal capacity of 300,000 tons each, identified as 

EU-012W and EU-012X, to be permitted in 2012, with particulate emissions 

controlled by wet suppression and compaction. 

 (B) Two (2) process area solid feedstock conveying, storage, and feed bins (main 

and spare), identified as EU-011A and EU-011B, to be permitted in 2012, with 

particulate emissions controlled by two (2) baghouses identified as C-011A and 

C-011B, respectively, each nominally rated at 31,870 dscfm, exhausting through 

two (2) stacks, identified as S-011A and S-011B, respectively. [Under 40 CFR 60, 

Subpart Y, the process area solid feedstock conveying, storage, and feed bins 

(main and spare) are new affected sources.] 

The source is subject to the following portions of Subpart Y. 

(1) 40 CFR 60.250(a); 

(2) 40 CFR 60.250(d); 

(3) 40 CFR 60.251; 

(4) 40 CFR 60.254(b); 

(4) 40 CFR 60.254(c); 

(5) 40 CFR 60.255(b); 

(6) 40 CFR 60.255(c); 

(7) 40 CFR 60.255(d); 

(8) 40 CFR 60.255(e); 

(9) 40 CFR 60.255(f); 

(10) 40 CFR 60.255(g); 

(11) 40 CFR 60.255(h); 

(12) 40 CFR 60.256(b)(1); 

(13) 40 CFR 60.256(b)(3); 

(14) 40 CFR 60.256(c); 

(15) 40 CFR 60.257(a); 

(16) 40 CFR 60.258(a)(1); 
Indiana Gasification LLC Page 20 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

(17) 40 CFR 60.258(a)(2); 

(18) 40 CFR 60.258(a)(3); 

(19) 40 CFR 60.258(a)(4); 

(20) 40 CFR 60.258(a)(5); 

(21) 40 CFR 60.258(a)(6); 

(22) 40 CFR 60.258(a)(7); 

(23) 40 CFR 60.258(a)(8); 

(24) 40 CFR 60.258(a)(10); 

(25) 40 CFR 60.258(b)(2); 

(26) 40 CFR 60.258(b)(3); 

(27) 40 CFR 60.258(c); and 

(28) 40 CFR 60.258(d). 

 

(o) The source is subject to the requirements of 40 CFR, Subpart IIII - Standard of 

Performance for Stationary Compression Ignition Internal Combustion Engines because 

the emergency generators and the firewater diesel pump will be constructed after July 11, 

2005 and manufactured after April 1, 2006. The specific facilities subject to this rule 

includes the following. 

 (a) Two (2) emergency diesel generators, each nominally rated at 1,341 horsepower, 

identified as EU-009A and EU-009B, to be permitted in 2012, exhausting through 

two (2) vents, identified as S-009A and S-009B, respectively. [Under 40 CFR 60, 

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

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

considered a new affected source.]. 

(b) Three (3) firewater pump diesel engines, each nominally rated at 575 horsepower 

and identified as EU-010A through EU-010C, to be permitted in 2012, exhausting 

through three (3) vents, identified as S-010A through S-010C, respectively. 

[Under 40 CFR 60, Subpart IIII, emergency diesel fired generator is considered a 

new affected source.][Under 40 CFR 63, Subpart ZZZZ, emergency diesel fired 

generator is considered a new affected source.]. 

 The emergency generator and the firewater pumps are subject to the following sections of 

40 CFR Part 60, Subpart IIII. 

 (1) 40 CFR 60.4200(a); 

 (2) 40 CFR 60.4205(b); 

 (3) 40 CFR 60.4205(c); 

 (4) 40 CFR 60.4206; 

 (5) 40 CFR 60.4207(a); 

 (6) 40 CFR 60.4207(b); 

 (7) 40 CFR 60.4208(a); 

 (8) 40 CFR 60.4208(b); 

 (9) 40 CFR 60.4208(g); 

 (10) 40 CFR 60.4209(a); 

 (11) 40 CFR 60.4211(a); 

 (12) 40 CFR 60.4211(c); 

 (13) 40 CFR 60.4211(e); 

 (14) 40 CFR 60.4212(a); 

 (15) 40 CFR 60.4212(b); 

 (16) 40 CFR 60.4212(c); 

 (17) 40 CFR 60.4214(b); 

 (18) 40 CFR 60.4218; 

 (19) 40 CFR 60.4219; 

(20) Table 4 to Subpart IIII of Part 60 - Emission Standard for Stationary Fire Pump 

Engines; 

(21) Table 5 to Subpart IIII of Part 60 - Labeling and Recordkeeping Requirements for 

New Stationary Emergency Engines; 
Indiana Gasification LLC Page 21 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

(22) Table 6 to Subpart IIII of Part 60 - Optional 3-Mode Test Cycle for Stationary Fire 

Pump Engines; and 

(23) Table 8 to Subpart IIII of Part 60 - Applicability of General Provisions to 

 Subpart III. 

(p) The source is subject to the National Emission Standards for Hazardous Air Pollutants for 

Stationary Reciprocating Internal Combustion Engines (NESHAPs) (326 IAC 14, 326 IAC 

20 and 40 CFR Part 63 Subpart ZZZZ). These Standards apply to new stationary 

reciprocating internal combusting engines (RICE) and are located at facilities that are area 

source of HAPs. The specific facilities subject to this rule include the following.

 These emissiosn units are subject to the following portions of Subpart ZZZZ: 

 (a) Two (2) emergency diesel generators, each nominally rated at 1,341 horsepower, 

identified as EU-009A and EU-009B, to be permitted in 2012, exhausting through 

two (2) vents, identified as S-009A and S-009B, respectively. [Under 40 CFR 60, 

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

source.][Under 40 CFR 63, Subpart ZZZZ, emergency diesel fired generator is 

considered a new affected source.]. 

(b) Three (3) firewater pump diesel engines, each nominally rated at 575 horsepower 

and identified as EU-010A through EU-010C, to be permitted in 2012, exhausting 

through three (3) vents, identified as S-010A through S-010C, respectively. 

[Under 40 CFR 60, Subpart IIII, emergency diesel fired generator is considered a 

new affected source.][Under 40 CFR 63, Subpart ZZZZ, emergency diesel fired 

generator is considered a new affected source.]. 

 The emergency generator and the firewater pumps are subject to the following sections of 

40 CFR Part 63, Subpart ZZZZ. 

 (1) 40 CFR 63.6590(c)(1). 

 Pursuant to 40 CFR 63.6665, the two (2) emergency diesel generators and the three (3) 

firewater pump diesel engines do not have to meet the requirements of 40 CRF 63, 

Subpart A (General Provisions), since they are considered new stationary RICE located 

at an area source of HAP emissions. 

(q) The source is not a major source of HAPs and is not subject to any of the major source 

MACT standards under 40 CFR Part 63. However, in the context of the BACT 

determination for this source, the substantive requirements of 40 CFR 63 Subpart H, 

addressing equipment leaks, apply to the components listed under 40 CFR 63.160(a) that 

are in service at the facility for the following process streams: methanol streams, 

propylene streams, and product SNG streams. The same Subpart H requirements apply 

to any leaks of SO2 in the Wet Sulfuric Acid unit piping between the combustor and 

oxidation reactor, beginning with the connector at the combustor and ending with the 

connector at the oxidation reactor, except that references in the regulations to methane or 

VOCs will instead be applied to the pollutant SO2. 

The following standards will apply to the components subject to this permit requirement: 

 1. 40 CFR 63.161; 

 2. 40 CFR 63.162(a); 

 3. 40 CFR 63.162(c); 

 4. 40 CFR 63.162(d); 

 5. 40 CFR 63.162(f); 

 6. 40 CFR 63.162(g); 

 7. 40 CFR 63.162(h); 

8. 40 CFR 63.163; 

9. 40 CFR 63.164; 
Indiana Gasification LLC Page 22 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

10. 40 CFR 63.165; 

11. 40 CFR 63.166; 

12. 40 CFR 63.167; 

13. 40 CFR 63.168; 

14. 40 CFR 63.169; 

15. 40 CFR 63.170; 

16. 40 CFR 63.171; 

17. 40 CFR 63.172; 

18. 40 CFR 63.173; and 

19. 40 CFR 63.174. 

The alternative quality improvement program for valves under 40 CFR 63.175 and pumps 

under 40 CFR 63.176 may be used in lieu of the specified requirements of 40 CFR 63.168 

and 40 CFR 63.163. The source may apply any alternative method approved by the EPA 

Administrator under 40 CFR 63.177(e) with written notification to IDEM 30 days in 

advance of the use of the alternative method. That notification shall include a copy of the 

EPA approval of the alternative method and an indication of where at the plant the 

alternative will be applied. 

The test methods and procedures used shall be those delineated under 40 CFR 63.180. 

For the SO2 monitoring of the components in the Wet Sulfuric Acid (WSA), references to 

methane or VOCs in 40 CFR 63.180 or 40 CFR 60 Appendix A, Method 21 shall be 

applied instead to the pollutant SO2. If a monitor is used that has a range lower than the 

defined leak rate, then any reading within 90% of the monitor’s range shall be treated as a 

leak. 

 The Greenhouse Gases BACT determination for this source, shall be to monitor monthly 

seals of the CO2 product compressors using audio/visual methods. Any leakage 

determined by audio/visual or other inspection shall be repaired within the time frames 

specified in 40 CFR 63.164 (g) except as provided by 63.171 and Recordkeeping shall 

conform to the provisions of 40 CFR 63.181. 

(r) 326 IAC 24 Clean Air Interstate Rule (CAIR) 

The Clean Air Interstate Rule (CAIR) is not applicable to any source at the IG facility. 

CAIR applies to fossil-fuel fired boilers serving a generator with a nameplate capacity of 

more than 25 MW and producing electricity for sale. The Auxiliary Boilers (EU-05A/B) are 

fossil-fuel fired boilers serving a generator. However, pursuant to 326 IAC 24-1(b)(1)(B) 

the CAIR does not apply to a boiler serving a generator that supplies, in any calendar 

year, less than 1/3 of the unit's potential electric output capacity or 219,000 MW-hours (25 

MW), whichever is greater, to any utility power distribution system for sale. Electricity 

produced by the Indiana Gasification facility is intended to balance the energy 

requirements of the facility. This electricity will normally be produced from process 

generated steam in a steam turbine generator, and any excess that is distributed for sale 

will not exceed 1/3 of the potential generation. Therefore, the auxiliary boilers, identified 

as EU-05A and EU-05B are not subject to the requirements of 326 IAC 24. 

(s) 40 CFR Part 72-78 Acid Rain Program 

326 IAC 21 incorporates by reference the provisions of 40 CFR 72 through 40 CFR 78 for 

the purposes of implementing an acid rain program that meets the requirements of Title IV 

of the Clean Air Act and to incorporate monitoring, record keeping, and reporting 

requirements for nitrogen oxide and sulfur dioxide emissions to demonstrate compliance 

with nitrogen oxides and sulfur dioxide emission reduction requirements. This source is 

not subject to the requirements of 326 IAC 21 because it does not sell greater than 1/3 its 

generated electric. This regulation applies to electric utility generating units that supply 

greater than 1/3 their potential electrical output and greater than 219,000 MWe-hrs 

(25MW) actual electrical output on an annual basis to any utility power distribution system 

for sale. Therefore, the auxiliary boilers, identified as EU-05A and EU-05B are not subject 

to the requirements of 326 IAC 21. 
Indiana Gasification LLC Page 23 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

(t) 40 CFR 68 Chemical Accident Prevention Provisions 

 Chemical accident prevention provisions (Risk Management Plans - RMP) are applicable 

to the stationary sources that have more than a threshold quantity of a regulated 

substance in a process, as determined under 40 CFR 68.115. Compounds present on 

site which are RMP regulated pollutants includes ammonia, methane and hydrogen 

sulfide. However, none are present in concentrations or total quantities which trigger RMP 

applicability. Indiana Gasification, LLC will use aqueous ammonia, however its 

concentration is less than 20% ammonia – and is therefore is not hazardous enough to be 

regulated per RMP regulations. Methane, the major product of the facility, is not present 

in any process greater than the RMP threshold quantity of 10,000 lbs. Hydrogen sulfide 

will be present in the process, but is present in most processes in concentrations less 

than 1% (H2S is not RMP regulated below this concentration.) The total quantity of H2S 

in processes where it is present less than 1.0% concentration is below the RMP threshold 

quantity of 10,000 lbs. 

State Rule Applicability Determination 

326 IAC 2-2 (Prevention of Significant Deterioration) 

This new stationary source is one of the 28 listed source categories and has potential to emit of at 

least one regulated pollutant greater than 100 tons per year. This source is a major source 

pursuant to 326 IAC 2-2 (PSD). 

326 IAC 2-2-3 (PSD BACT: Control Technology Review Requirements) 

Pursuant to PSD/Operating Permit T147-30464-00060 and 326 IAC 2-2-3 (Prevention of 

Significant Deterioration (PSD)), the Best Available Control Technologies (BACT) for the source 

shall be as follows: 

Syngas Hydrocarbon Flare, identified as (EU-001): 

(1) The PM, PM10 and PM2.5 emissions from the Syngas Hydrocarbon Flare, identified as 

 (EU-001) shall be limited as follows: 

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

PM, PM10 and PM2.5 emissions during startups, shutdowns and other flaring 

events. 

During a planned shutdown of a gasifier, the permittee shall route the contents of 

each gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during initial 

depressurization to one of the Wet Sulfuric Acid (WSA) plants. 

The permittee shall reduce gasifier feed rates such that all syngas can be 

processed through one gas treatment train prior to a scheduled gas treatment 

train outage. This limits the amount of syngas that will have to be sent to the 

syngas hydrocarbon flare. 

The permittee shall have written procedures for the above operations and the 

permittee shall train the operators on these procedures. 

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented. 
Indiana Gasification LLC Page 24 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

B. Comply with the following flare best practices: 

 a. Flares shall be designed for and operated with no visible emissions, except 

for periods not to exceed 5 minutes during any 2 consecutive hours. 

 b. Flares shall be operated with a flame present at all times. 

 c. Flares shall be continuously monitored to assure the presence of a pilot 

flame with a thermocouple, infrared monitor, or other approved device. 

C. The Syngas Hydrocarbon Flare PM/PM10 emissions shall not exceed 3.21 lb/hour 

during startup or shutdown, based on a 3-hour average. 

D. The Syngas Hydrocarbon Flare PM2.5 emissions shall not exceed 3.01 lb/hour 

during startup or shutdown, based on a 3-hour average. 

(2) The CO emissions from the Syngas Hydrocarbon Flare, identified as (EU-001) shall be 

limited as follows: 

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

CO emissions during startups, shutdowns and other flaring events. 

During a planned shutdown of a gasifier, the permittee shall route the contents of 

each gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during initial 

depressurization to one of the Wet Sulfuric Acid (WSA) plants. 

The permittee shall reduce gasifier feed rates such that all syngas can be 

processed through one gas treatment train prior to a scheduled gas treatment 

train outage. This limits the amount of syngas that will have to be sent to the 

syngas hydrocarbon flare. 

The permittee shall have written procedures for the above operations and the 

permittee shall train the operators on these procedures. 

The Permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented. 

 B. Comply with the following flare best practices: 

 a. Flares shall be designed for and operated with no visible emissions, 

 except for periods not to exceed 5 minutes during any 2 consecutive 

 hours. 

 b. Flares shall be operated with a flame present at all times. 

c. Flares shall be continuously monitored to assure the presence of a pilot 

flame with a thermocouple, infrared monitor, or other approved device. 

 

C. The Syngas Hydrocarbon Flare CO emissions shall not exceed 172.4 lb/hour 

during startup or shutdown based on a 3 hour average. 

 (3) The SO2 emissions from the Syngas Hydrocarbon Flare, identified as (EU-001) shall be 

limited as follows: 

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

SO2 emissions during startups, shutdowns, and other flaring events. 

The permittee will use methanol, rather than coal or pet coke, as the feedstock in 

each gasifier during startup conditions requiring syngas flaring, thereby reducing 

emissions of sulfur dioxide at the syngas hydrocarbon flare. 
Indiana Gasification LLC Page 25 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

During a planned shutdown of a gasifier, the permittee shall route the contents of 

each gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during initial 

depressurization to one of the Wet Sulfuric Acid (WSA) plants. 

The permittee shall reduce gasifier feed rates such that all syngas can be 

processed through one gas treatment train prior to a scheduled gas treatment 

train outage. This limits the amount of syngas that will have to be sent to the 

syngas hydrocarbon flare. 

The permittee shall have written procedures for the above operations and the 

permittee shall train the operators on these procedures. 

 

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented 

 The SO2 emissions from the Syngas Hydrocarbon Flare during a shutdown 

 event shall not exceed 85.21 lb/hr based on a 3-hour average and shall not 

 exceed 255.6 lb per 24 hours. The SO2 emissions from the Syngas 

 Hydrocarbon Flare shall not exceed 0.35 lb/hour during startup, based on a 3 

 hour average. 

 (4) The NOx emissions from the Syngas Hydrocarbon Flare, identified as (EU-001) shall be 

limited as follows: 

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

NOx emissions during startups, shutdowns, and other flaring events. 

During a planned shutdown of a gasifier, the permittee shall route the contents of 

each gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during initial 

depressurization to one of the Wet Sulfuric Acid (WSA) plants. 

The permittee shall reduce gasifier feed rates such that all syngas can be 

processed through one gas treatment train prior to a scheduled gas treatment 

train outage. This limits the amount of syngas that will have to be sent to the 

syngas hydrocarbon flare. 

In addition, the permittee shall have written procedures for the above operations 

and the permittee shall train the operators on these procedures. 

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented. 

B. The Syngas Hydrocarbon Flare NOx emissions shall not exceed 43.09 lb/hour 

during startup or shutdown based on a 3 hour average. 

 (5) The GHGs emissions from the Syngas Hydrocarbon Flare, identified as (EU-001) shall 

 be limited as follows: 

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

GHG emissions during startups, shutdowns, and other flaring events. 
Indiana Gasification LLC Page 26 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

During a planned shutdown of a gasifier, the permittee shall route the contents of 

each gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during initial 

depressurization to one of the Wet Sulfuric Acid (WSA) plants. 

The permittee shall reduce gasifier feed rates such that all syngas can be 

processed through one gas treatment train prior to a scheduled gas treatment 

train outage. This limits the amount of syngas that will have to be sent to the 

syngas hydrocarbon flare. 

In addition, the permittee shall have written procedures for the above operations 

and the permittee shall train the operators on these procedures. 

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional preventative 

measures that can be implemented to minimize re-occurrence of these events. Such 

identified measures shall be implemented and documented. 

Acid Gas Flare, identified as (EU-002): 

(1) The PM, PM10 and PM2.5 emissions from the Acid Gas Flare, identified as (EU-002) shall 

be limited as follows: 

 

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

emissions during flaring events. 

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented. 

 B. Comply with the following flare best practices: 

a. Flares shall be designed for and operated with no visible emissions, except 

for periods not to exceed 5 minutes during any 2 consecutive hours. 

b. Flares shall be operated with a flame present at all times. 

c. Flares shall be continuously monitored to assure the presence of a pilot flare 

with a thermocouple, infrared monitor, or other approved device. 

 (2) The CO emissions from the Acid Gas Flare, identified as (EU-002) shall be limited as 

follows: 

A The permittee shall comply with the following Flare Minimization Plan to reduce 

emissions during flaring events. 

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented. 

 

 B Comply with the following flare best practices: 

a. Flares shall be designed for and operated with no visible emissions, except 

for periods not to exceed 5 minutes during any 2 consecutive hours. 

 b. Flares shall be operated with a flame present at all times. 

c. Flares shall be continuously monitored to assure the presence of a pilot 

flame with a thermocouple, infrared monitor, or other approved device. 

 (3) The SO2 emissions from the Acid Gas Flare, identified as (EU-002) shall be limited as 

follows: 
Indiana Gasification LLC Page 27 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

emissions during flaring events. 

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented. 

(4) The NOx emissions from the Acid Gas Flare, identified as (EU-002) shall be limited as 

follows: 

B. The permittee shall comply with the following Flare Minimization Plan to reduce 

emissions during flaring events. 

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented. 

 (5) The GHG emissions from the Acid Gas Flare, identified as (EU-002) shall be: 

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

emissions during flaring events. 

The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of 

these events. Such identified measures shall be implemented and documented. 

Auxiliary Boilers, identified as (EU-005 A and B): 

(1) The PM, PM10 and PM2.5 emissions from the Auxiliary Boilers (EU-005A/B) operation shall 

 not exceed 0.0075 lb per MMBtu and only natural gas or SNG shall be used.

(2) The CO emissions from the Auxiliary Boilers (EU-005A/B) operation shall not exceed 

 0.036 lb/MMBtu based on a 3 - hour average and good combustion practices shall be 

 used. 

(3) The SO2 emissions from the Auxiliary Boilers (EU-005A/B) operation shall not exceed 

 0.0006 lb/MMBtu and only natural gas or SNG shall be used. 

(4) The NOx emissions from the Auxiliary Boilers (EU-005A/B) operation shall not exceed 

 0.0125 lb/MMBtu based on a 24-hour block daily average basis and shall use Ultra Low 

 NOx burners with FGR. 

 (5) The GHGs BACT for the Auxiliary Boilers shall be as follows: 

(a) Use of natural gas or SNG; 

(b) Energy efficient boiler design (utilizing an economizer, condensate recovery, inlet 

air controls and blowdown heat recovery.) 

 (c) Boiler designed for 81% thermal efficiency (HHV). 

(d) The total CO2 emissions from the auxiliary boilers shall not exceed 88,167 tons 

per twelve (12) consecutive month period, with compliance determined at the end 

of each month. 
Indiana Gasification LLC Page 28 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

Acid Gas Recovery Unit Vents, identified as (EU-007 A and B): 

(1) The PM, PM10 and PM2.5 emissions from operation of the AGR Regenerative Thermal 

Oxidizers (C-007A/B) shall not exceed 0.29 pounds per hour, each and shall use good 

combustion practices. Only natural gas or SNG shall be used in the AGR Regenerative 

Thermal Oxidizers (C-007A/B). 

 (2) The CO emissions shall be controlled by the use of regenerative thermal oxidizer (RTO) 

and the CO emissions shall not exceed 48 pounds per hour for the Acid Gas Removal 

Unit Vents (EU-007A/B), each, based on a 3-hour average. 

(3) The SO2 emissions shall be reduced by the use of a Rectisol process and the SO2

emissions shall not exceed 3.17 pounds per hour for each Acid Gas Removal Unit Vent 

(EU-007A/B), based on a 3-hour average. 

(4) The NOx emissions from the Acid Gas Removal Unit Vents (EU-007A/B) shall be 

controlled by Low NOx Performance with natural gas injection and the NOx emissions 

shall not exceed 1.98 pounds per hour from each AGR/RTO unit based on a 3-hour 

average. 

 (5) The CO2 emissions from the Acid Gas Recovery (AGR) Vents operation shall be limited 

as follows: 

 (A) The CO2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed

4,690,000 tons of CO2 during the first 12 months of operation. 

(B) The CO2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed

6,430,000 tons of CO2 during the second 12 months of operation. 

(C) The CO2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed 1, 

290,000 tons of CO2 during the third 12 months of operation. 

(D) Thereafter, the CO2 emissions from the Acid Gas Recovery (AGR) Vents shall not 

exceed 1,290,000 tons CO2 per twelve (12) consecutive month period with 

compliance determined at the end of each month. 

Gasifier Preheat Burners, identified as (EU-008 A - E): 

(1) The PM, PM10 and PM2.5 emissions from the Gasifier Preheat Burners (EU-008A-E) 

operation shall not exceed 0.0007 lb /MMBtu and shall use only natural gas or SNG. 

 (2) The CO emissions from the Gasifier Preheat Burners (EU-008A-E) operation shall not 

exceed 0.056 lb CO/MMBtu and shall use good combustion practices. 

 (3) The SO2 emissions from the Gasifier Preheat Burners (EU-008A-E) operation shall be not 

exceed 0.0006 lb SO2/MMBtu and shall use natural gas or SNG. 

 (4) The NOx emissions from the Gasifier Preheat Burners (EU-008A-E) operation shall not 

exceed 0.10 lb NOx /MMBtu and shall use good combustion practices. 

 (5) The GHGs BACT for the Gasifier Preheat Burners shall be as follows: 

A. The use of good engineering design; and 

 B. The use of natural gas or SNG.
Indiana Gasification LLC Page 29 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

C. The CO2 emissions from the Gasifier Preheater Burners shall not exceed 6,438 

tons CO2 per twelve (12) consecutive month period, with compliance determined 

at the end of each month. 

Emergency Generators, identified as (EU-009 A and B): 

The BACT for the Emergency generator has been established as follows: 

 (1) NOx: emissions shall be limited through the implementation of good combustion 

 practices and limited hours of non-emergency operation; 

 

(2) CO: emissions shall be limited through the implementation of good combustion 

 practices and limited hours of non-emergency operation; 

(3) PM/PM10/PM2.5: emissions shall be limited through the use of low-S diesel (less 

than15ppm sulfur) and limited hours of non-emergency operation; 

(4) SO2: emissions shall be limited through the use of low-S diesel (less than15ppm sulfur) 

and limited hours of non-emergency operation; and 

(5) Each emergency generator shall not exceed 52 hours per year of non-emergency 

operation, each. 

(6) The total CO2 emissions from the emergency engines (EU-009A/B and EU-010A/B/C) 

shall not exceed 84 tons CO2 per twelve (12) consecutive month period from nonemergency operation, with compliance determined at the end of each month. 

Firewater Pump Engines, identified as (EU-010 A - C): 

The BACT for the firewater pump engines has been established as follows: 

(1) NOx: emissions shall be limited through the implementation of good combustion 

 practices and limited hours of non-emergency operation; 

 

(2) CO: emissions shall be limited through the implementation of good combustion 

 practices and limited hours of non-emergency operation; 

(3) PM, PM10 and PM2.5: emissions shall be limited through the use of low-S diesel (less 

than15ppm sulfur) and limited hours of non-emergency operation; 

(4) SO2: emissions shall be limited through the use of low-S diesel (less than15ppm sulfur) 

and limited hours of non-emergency operation; and 

 (5) Each firewater pumps shall not exceed 52 hours per year of non- 

 emergency operation, each. 

 Process Area Solid Feedstock Conveying, storage and feedbin (EU-011 A and B): 

(1) The PM, PM10 and PM2.5 emissions from the Process Area Solid Feedstock Conveying, 

storage and feedbin (EU-011A/B) shall be limited through a baghouse. 

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf. 

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf. 

Incoming Solid Feedstock Material Handling System - Barge Unloading (EU-012A): 
Indiana Gasification LLC Page 30 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

The PM, PM10 and PM2.5 emissions from the barge unloading to hopper transfer point (EU-012A) 

operation shall be controlled by a wet suppression with a control efficiency of 90%. 

Railcar Unloading to Rail Hoppers (EU-012G/H): 

(1) The PM, PM10 and PM2.5 emissions from the railcar unloading to rail hoppers shall be 

controlled by a wet dust extraction system or baghouse. 

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf. 

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf. 

Barge Unloading from Hopper to the Belt (EU-012B) and Barge Conveyor Transfer Points 

 (EU-012C-F): 

(1) The PM, PM10 and PM2.5 emissions from the Barge Unloading from the Hopper to the Belt 

(EU-012B) and Barge Conveyor Transfer Points (EU-012C-F) shall be controlled by a wet 

dust extraction system or a baghouse. 

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf. 

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf. 

Rail Hoppers Unloading to the Belts (EU-012I-J) and Rail Conveyor Belt to the Stacker 

(EU-012K): 

(1) The PM, PM10 and PM2.5 emissions shall be controlled by a wet dust extraction system or 

a baghouse. 

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf. 

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf. 

Stacker Belt to the Radial Stacker (EU-012 L- M): 

(1) The PM, PM10 and PM2.5 emissions from the Stacker Belts to the Radial Stacker shall be 

controlled by a wet dust extraction system or a baghouse. 

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf. 

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf. 

Transfer systems consisting of hoppers and conveyor belts transferring feed stock from 

the piles to classification towers (EU-012R-S); Classification towers (EU-012T-U); and 

Classification tower to a day bin (EU-012V): 

(1) The PM, PM10 and PM2.5 emissions shall be controlled by a wet dust extraction system or 

a baghouse. 

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf. 

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf. 

 

Radial Stacker to the Pile (EU-012 N-O): 

(1) The PM, PM10 and PM2.5 emissions shall be controlled by a Telescoping chute with dust 

collection. 
Indiana Gasification LLC Page 31 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

(2) The PM and PM10 emissions shall not exceed 0.003 gr/dscf. 

(3) The PM2.5 emissions shall not exceed 0.0015 gr/dscf. 

Storage Pile (EU-012W/X): 

The PM, PM10 and PM2.5 emissions from the Storage Piles (EU-012W/X) operation shall be 

controlled by wet suppression with pile compaction with a control efficiency of 90 %. 

Dozer Activity (EU-012P/Q): 

The PM, PM10 and PM2.5 emissions from the Dozer Activities (EU-012P/Q) operation shall be 

controlled by wet suppression with pile compaction with a control efficiency of 90 %. 

Truck/rail conveyor transfer tower (EU-012Y); truck stations unloading to a truck hopper 

 (EU-012AB-AC); and truck hopper unloading to the conveyor Belts (EU-012AA): 

(1) An enclosed vent to a wet dust extraction system or a baghouse for control of PM, PM10 

and PM2.5 emissions. 

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf. 

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf. 

Rod Mill Vent (EU-013A-D): 

(1) The PM and PM10 emissions from each Rod Mill Vents shall not exceed 0.025 pounds per 

hour based on a 3-hour average. 

(2) The PM2.5 emissions from each Rod Mill Vent shall not exceed 0.0074 pounds per hour 

based on a 3-hour average. 

ASU Regeneration Vent (EU-017A and B): 

(1) The PM and PM10 emissions from each Air Separation Unit (ASU) shall not exceed 0.026 

pounds per hour based on a daily average. 

(2) The PM2.5 emissions from the Air Separation Unit (ASU) shall not exceed 0.009 pounds 

per hour based on a daily average. 

Wet Sulfuric Acid Plants (EU-015 A and B): 

(1) The PM, PM10 and PM2.5 emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall 

be controlled by a high Efficiency Mist Eliminator and H2O2 scrubber and the PM, PM10

and PM2.5 emissions shall not exceed 0.15 pounds per ton of acid produced and 5 lb/hour, 

each, based on a 3-hour average. 

 (2) The H2SO4 emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall be controlled 

by a high Efficiency Mist Eliminator and H2O2 scrubber and the H2SO4 emissions shall not 

exceed 0.15 pounds per ton of acid produced and 5 lb/hour, each, based on a 3-hour 

average. 

 (3) The CO emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall not exceed 18.7 

pounds per hour, each based on a 3-hour average. 

 (4) The SO2 emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall be controlled by 

a peroxide scrubber, the SO2 emissions shall not exceed 0.25 lb/ton acid produced and 

8.3 lbs SO2 per hour, each based on a 24-hour block daily average. 
Indiana Gasification LLC Page 32 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

 (5) The NOx emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall be limited by the 

use of a selective catalytic reduction (SCR) when the flow to the SCR is at or above a 

temperature of 750 degrees F and the NOx emissions shall not exceed 10.2 pounds per 

hour NOx based on a 24-hour block daily average for each Wet Sulfuric Acid unit. 

 (6) The CO2 emissions from the Wet Sulfuric Acid Plant operation shall not exceed 474,000 

tons per twelve (12) consecutive month period, with compliance determined at the end of 

each month. 

ASU and Main Cooling Tower (EU-016A and 016B): 

The PM, PM10 and PM2.5 emissions from the ASU Cooling Tower (EU-016A) and the Main Cooling 

Tower (EU-016B) shall be controlled by High efficiency drift eliminators designed with a drift loss 

rate of less than 0.0005% and total dissolved solids shall not exceed 1500 ppm based on a daily 

average. 

Sulfuric Acid Tanks (EU-027A - F): 

The H2SO4 emissions from the Sulfuric Acid tanks shall be limited by the use of a fixed roof tank 

and submerged fill. 

ZLD Spray Dryer (EU-032): 

(1) The PM, PM10 and PM2.5 emissions from the Zero Liquid Discharge (ZLD) spray dryer 

shall be controlled by a fabric filter baghouse and the PM, PM10 and PM2.5 emissions shall 

not exceed a 0.005 gr/dscf based on a 3 hour average. 

(2) The CO emissions from the Zero Liquid Discharge (ZLD) Spray Dryer shall not exceed 

0.036 lb/MMBtu and shall use good combustion practices. 

 (3) The SO2 emissions from the Zero Liquid Discharge (ZLD) Spray Dryer shall be limited 

through the use of natural gas or SNG. 

 (4) The NOx emissions from the Zero Liquid Discharge (ZLD) Spray Dryer shall not exceed 

0.035 lb/MMBtu and shall use a Low NOx Burner (LNB). 

 (5) The GHGs BACT for the Zero Liquid Discharge (ZLD) Spray Dryer shall be as follows: 

A. The CO2 BACT for the Zero Liquid Discharge (ZLD) Spray Dryer shall be the use 

of good engineering design and the use of natural gas or SNG. 

B. The CO2 emissions from the ZLD Spray Dryer shall not exceed 2,884 tons CO2

per twelve (12) consecutive month period, with compliance determined at the end 

of each month. 

Fugitive Leaks from piping (FUG & FUG-WSA): 

(1) The BACT for fugitive leaks of CO and H2SO4 is no-controls. 

(2) The BACT for the fugitive leaks of SO2 in the WSA is the use of a Leak Detection and 

Repair (LDAR) program. 

(3) The BACT for fugitive GHG emissions is the use of a leak detection and repair (LDAR) 

program for the natural gas and SNG piping and weekly audio/visual inspection of the 

CO2 compressors while they are in operation in any week in which there are at least 

twenty-four (24) hours of operation of the CO2 compressor to be inspected. 

 
Indiana Gasification LLC Page 33 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

Fugitive Dust From Paved Roads (FUG-ROAD): 

The PM, PM10 and PM2.5 emissions from the paved road (FUG-ROAD) shall be controlled by 90 % 

by the use of; 

(1) Paving all plant haul roads, 

(2) Use of wet or chemical suppression 

(3) Prompt cleanup of any spilled materials. 

Front -end Loader Slag Handling (EU-034A) and Vehicle Dust on Slag Pile (EU-034C): 

The PM, PM10 and PM2.5 emissions from the Front-end Loader Slag Handling (EU-034A) and 

Vehicle Dust on Slag Pile (EU-034C) shall be controlled by a Wet Suppression or Chemical 

suppression with 90% control efficiency. 

Electric Circuit Breaker (FUG-SF6): 

The GHGs BACT for the Electrical Circuit Breaker (FUG-SF6) shall be the use of fully enclosed 

pressurized SF6 circuit breakers with leak detection (low pressure alarm). 

 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 and greater than twenty-five (25) tons per year for a combination of HAPs, therefore: 

The emission units shall be limited as follows: 

(a) The Acid Gas Recovery Units, identified as EU-007A/B, Methanol 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 Acid Gas recovery Units, identified as EU-007A/B, combined Hazardous Air 

Pollutants (HAPs) emissions shall be limited to less than 22.5 tons per twelve (12) 

consecutive month period, with compliance determined at the end of each month. 

(c) The methanol emissions from the AGRs shall be calculated by the following 

 equation: 

Methanol emissions = Vent Flow x Methanol Conc. x (1 – Control Effic.) 

Where: 

Vent Flow = Total AGR vent flow to the thermal oxidizers (million SCF/period) to be 

monitored continuously by the Permittee. 

Methanol Conc. = Methanol Concentration of the inlet to the thermal oxidizer (lbs 

methanol/million SCF of vent gas), as determined in the most recent stack test of the 

oxidizer. Until the initial testing is performed, the engineering estimate of 12.7 lbs 

methanol/million SCF shall be used. 

Control Effic. = The control efficiency of the Regenerative Thermal Oxidizer as determined 

by stack test. Until the initial stack test is performed, the engineering estimate of 99% 

control shall be used. 
Indiana Gasification LLC Page 34 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

(d) The Permittee shall operate a carbon adsorber on the ZLD Inert Gas Vent. The carbon 

adsorber shall be used at all times the ZLD inert gas vent is in operation except during 

carbon adsorber maintenance, repair or carbon replacement. The system shall be 

designed with a carbon replacement interval of no less than once per year (based on 

maximum design flow rate and mercury concentration). 

Compliance with the above limits and requirements and combined with the potential to emit HAP 

emissions from all other emission units will limit the potential to emit from this source to less than 

ten (10) tons per year of any individual HAP and twenty-five (25) tons per year of any combination 

of HAPs and make the source an area source of HAPs. 

Operating Restrictions during Gasifier Startup Flaring 

During startup flaring of the gasifiers, the Permittee shall not test an emergency engine (EU009A/B and EU-010A/B/C). This operating restriction shall be applicable beginning when a 

starting up gasifier first begins to flare generated syngas and ends when the generated syngas 

begins diversion from the flare to the downstream AGR/WSA trains. 

Alternative Emissions Limitation during Gasifier Startup Flaring 

(a) During startup flaring of the gasifiers, NOx emissions from the AGR units (EU-007A/B) 

shall be limited to 2.97 lbs/hr combined from both AGR units (EU-007A/B) and shall be 

applicable beginning when a starting up gasifier first begins to flare generated syngas and 

ends when the generated syngas begins diversion from the flare to the downstream 

AGR/WSA trains. 

(b) During startup flaring of the gasifiers, NOx emissions from the WSA units (EU-015A/B) 

shall be limited to 15.26 lbs/hr combined from both WSA units (EU-015A/B) and shall be 

applicable beginning when a starting up gasifier first begins to flare generated syngas and 

ends when the generated syngas begins diversion from the flare to the downstream 

AGR/WSA trains. 

Operational Limits for the auxiliary Boilers 

The total throughput of fuel to the two (2) natural gas-fired auxiliary boilers, identified as EU005A/B, shall be limited to a total firing rate of 1430 billion Btu per twelve (12) consecutive month 

period, with compliance determined at the end of each month. 

326 IAC 2-4.1 (Major Sources of Hazardous Air Pollutants (HAP)) 

The operation of emission units in the plant will emit less than ten (10) tons per year for a single 

HAP and less than twenty-five (25) tons per year for a combination of HAPs. Therefore, 326 IAC 

2-4.1 does not apply. 

326 IAC 1-7 (Actual Stack Height Provisions) 

326 IAC 1-7 applies to exhaust stacks with potential particulate or sulfur dioxide emissions of 25 

tons per year or more. 326 IAC 1-7-3(a) requires that new stacks meeting these criteria be 

constructed using either good engineering practice (GEP) or, at least, with a stack height sufficient 

to insure that emissions will not cause excessive ground level concentrations due to downwash, 

eddies, or wakes. 

Each Regenerative Thermal Oxidizer Vent (EU-07) and each Wet Sulfuric Acid Plant Vent (EU15) will have potential SO2 emissions greater than 25 tons per year, so these stacks will be 

subject to this rule for SO2. No other stacks at the proposed facility meet the applicability criteria. 

326 IAC 2-6 (Emission Reporting) 

Since this source is required to have an operating permit under 326 IAC 2-7, Part 70 Permit 

Program, this source is subject to 326 IAC 2-6 (Emission Reporting). In accordance with the 

compliance schedule in 326 IAC 2-6-3, an emission statement must be submitted triennially. The 

first report is due no later than July 1, 2014, and subsequent reports are due every three (3) years 

thereafter. The emission statement shall contain, at a minimum, the information specified in 326 

IAC 2-6-4. 
Indiana Gasification LLC Page 35 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

326 IAC 5-1 (Opacity Limitations) 

This source is subject to the opacity limitations specified in 326 IAC 5-1-2(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 subject to the requirements of 326 IAC 6-5 because it is a new source of fugitive 

particulate matter emissions, located anywhere in the state, requiring a permit as set forth in 326 

IAC 2, which has not received all the necessary preconstruction approvals before December 13, 

1985. 

326 IAC 3-5 (Continuous Monitoring of Emissions) 

The auxiliary boilers, identified as EU-05A and EU-05B 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. 

(a) Pursuant to 326 IAC 3-5-1(c)(2)(A), a continuous monitoring system for NOx shall be 

installed, calibrated, maintained, and operated to measure the NOx emissions from the 

exhaust of the two auxiliary boilers, identified as EU-05A and EU-05B. 

(b) Pursuant to 326 IAC 3-5-1(c)(2)(C) and (D), a continuous monitoring system shall be 

installed, calibrated, maintained, and operated to measure Nitrogen Oxide (NOx) and 

either O2 or CO2 emissions from auxiliary boilers, identified as EU-05A and EU-05B since 

the boilers are subject to NOx monitoring under 40 CFR 60. 

(c) Pursuant to 326 IAC 3-5(c) (2) (A) (i) the Auxiliary Boiler are exempts from continuous 

opacity monitoring because it burns only gaseous fuels. SO2 monitoring is not required 

because the boiler will not be subject to SO2 monitoring under 40 CFR 60 and will not 

have SO2 air pollution control equipment. 

(d) The requirements of 326 IAC 3-5 also applies to "sulfuric acid plants or production 

facilities of greater than 300 tons per day acid production capacity". 326 IAC does not 

contain a definition of "sulfuric acid plants or production facilities", other than in 40 CFR 60 

Subpart H incorporated by reference at 326 IAC 12 which exempts processes with the 

primary purpose of reducing atmospheric emissions of sulfur compounds. 

The IG Sulfuric Acid Plants are facilities where the conversion to sulfuric acid is performed 

primarily as a means of reducing atmospheric emissions of SO2 or other sulfuric compounds. 

Since the Indiana Gasification sulfuric acid plants do not meet the definition of sulfuric acid 

production unit in Subpart H, the sulfuric acid plants are not be subject to the requirements of 

326 IAC 3-5. 

326 IAC 6-2-4 (Particulate Emission Limitations for Sources of Indirect Heating) 

(a) Pursuant to 326 IAC 6-2-4 (Particulate Emission Limitations for Sources of Indirect 

Heating: Emission Limitations for facilities specified in 326 IAC 6-2-1(d)), the PM 

emissions from the auxilliary boilers, identified as EU-05A and EU-05B shall not exceed 

0.19 pounds per million Btu heat input (lb/MMBtu), each. This limitation was calculated 

using the following equation: 

0.26 Q

1.09

Pt 

Where: 

 
Indiana Gasification LLC Page 36 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

 Q = total source heat input capacity (MMBtu/hr). 

 For these units, Q = 816.0 MMBtu/hr. 

However, 326 IAC 6-2-4 (h) states that if a limitation established by this rule is inconsistent 

with a limitation required by the permit regulations, then the permit regulation limit will prevail. 

Since the BACT emissions limit is significantly more stringent than the above calculated limit, 

compliance with the BACT particulate matter limits renders the above rule (326 IAC 6-2-4) not 

applicable to these auxiliary boilers. 

(b) The gasifier startup burners, identified as EU-08 and WSA preheat burners, identified as 

EU-15 are process heaters and not indirect heat exchangers pursuant to 40 CFR 60 

Subpart Dc, therefore, these emission units are not subject to the requirements of 326 

IAC 6-2. 

326 IAC 6-3-2 (Particulate Emission Limitations for Manufacturing Processes) 

(a) Pursuant to 326 IAC 6-3-2, the allowable particulate matter (PM) from the Process Area 

Solid Feedstock Handling Operations (EU-11A/B) and Wind Erosion from the coal/coke 

piles (EU-12W/X) shall not exceed 67.2 pounds per hour when operating at a process 

weight rate of 430 tons per hour. The pound per hour limitation was calculated with the 

following equation: 

 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 

The BACT limit for these emission units are much more stringent. Therefore, pursuant to 

326 IAC 6-3-1(b), these emission units are exempt from the requirements of 

326 IAC 6-3-2. 

(b) Pursuant to 326 IAC 6-3-1(b)(14), EU-13 Rod Mill Air Eductors and EU-17 ASU Sieve 

Regeneration are exempt from this rule because potential PM emissions are less than 

0.551 lb per hour. 

(c) Pursuant to 326 IAC 6-3-1(b)(14), the noncontact cooling tower systems, trivial activities 

as defined at 326 IAC 2-7-1(40), processes with potential emissions less than 0.551 lb/hr, 

and where a particulate limit established under BACT or another rule is more stringent 

 are exempt from this rule. 

 326 IAC 7-1.1-2 (Sulfur Dioxide Emission Limitations)

(a) This Acid gas removal (AGR) unit and the Wet sulfuric acid (WSA) are subject to the 

requirements of 326 IAC 7-1.1-2 because the emission units have potential to emit greater 

than 25 tons of SO2 per year, each. However, pursuant to this rule, there are no specific 

SO2 emission limitations for the combustion of natural gas. Therefore, the requirements of 

326 IAC 7-1.1-2 (Sulfur Dioxide Emission Limitations) are not applicable to the Acid gas 

removal (AGR) units and the Wet sulfuric acid (WSA) at this source. 

(b) All other emission units are not subject to the requirements of 326 IAC 7-1.1-2 because 

they have the potential to emit less than 25 tons of SO2 per year. Therefore, the 

requirements of 326 IAC 7-1.1-2 (Sulfur Dioxide Emission Limitations) are not applicable 

to any emission unit at this source. 

 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 25 tons or more per year, located anywhere in the state, which are not 

otherwise regulated by other provisions of 326 IAC 8, shall reduce VOC emissions using 

Best Available Control Technology (BACT). The uncontrolled VOC emissions from the 

Acid Gas Recovery Unit Vents, identified as EU-007A/B are greater than 25 tons per year. 
Indiana Gasification LLC Page 37 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

 Pursuant to 326 IAC 8-1-6, IDEM has established BACT for VOC for the Acid Gas 

Recovery Unit Vents, identified as EU-007A/B as follows: 

The VOC emissions from the Acid Gas Recovery Unit vents (EU-007A/B) shall be 

controlled through the use of a Regenerative Thermal Oxidizer on each vent and the VOC 

emissions for each vent shall not exceed 1.05 pounds per hour based on a 3-hour 

average. 

(b) The uncontrolled VOC emissions from all other emission units are less than 25 tons per 

year, therefore, all other emission units at this source are not subject to the requirements 

of 326 IAC 8-1-6 (New Facilities; General Reduction Requirements). 

 326 IAC 8-4-6 (Gasoline Dispensing Facilities)

Pursuant to 326 IAC 8-4-1(f) and 326 IAC 8-4-6 the requirements of this rule do not apply to the 

gasoline storage tank at a gasoline dispensing facility, though this facility is constructed after July 1, 

1989 the facility has a monthly gasoline throughput of less than ten thousand (10,000) gallons per 

month. 

 326 IAC 8-9-1 (Volatile Organic Liquid Storage Vessels) 

 Pursuant 326 IAC 8-9-1(a) this rule only applies to VOL storage vessels located in Clark, Floyd, 

 Lake, or Porter County. This source is located in Spencer County. 

 326 IAC 9-1 (Carbon Monoxide Emission Limits)

This source is subject to 326 IAC 9-1 because it is a stationary source of CO emissions commencing 

operation after March 21, 1972 and has CO emissions of more than 100 tons per year. There are no 

applicable CO emission limits, under this state rule, established for this type of operation. 

326 IAC 2-2-4 (Air Quality Analysis Requirements) 

Section (4)(a) of this rule, requires that the PSD application shall contain an analysis of ambient 

air quality in the area that the major stationary source would affect for pollutants that are emitted 

at major levels or significant amounts. Indiana Gasification LLC has submitted an air quality 

analysis, which has been evaluated by IDEM's Technical Support and Modeling Section. See 

details in Appendix C. 

NAAQS modeling for the 24-hour time-averaging period for PM2.5was conducted and compared to 

the respective NAAQS limit. For the 24-hour modeling, two scenarios were examined and had to 

do with feedstock deliveries both by truck or train. These operations cannot occur at the same 

time due to equipment and logistical constraints. OAQ modeling results are shown in Table 5a. 

All maximum-modeled concentrations were compared to the respective NAAQS limit. All 

maximum-modeled concentrations during the five years plus background were not below the 

NAAQS limit and a culpability analysis was required. 

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. 
Indiana Gasification LLC Page 38 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

(3) Modifications or substitution of any model may only be done in accordance with guideline 

documents and with written approval from U.S. EPA and shall be subject to public 

comment procedures set forth in 326 IAC 2-1.1-6. 

 Economic Growth 

The purpose of the growth analysis is to quantify project associated growth and estimate the air 

quality impacts from this growth either quantitatively or qualitatively. 

 It is estimated that approximately 200 additional jobs will be created as a result of the proposed 

project. Most of the employees will be drawn from surrounding areas. Since the area is 

predominately rural, it is not expected the growth impacts will cause a violation of the NAAQs or 

the PSD increment. 

Soils and Vegetation Analysis

 A list of soil types present in the general area was determined. Soil types include the following: 

Moderately thick loess over weathered loamy glacial till, discontinuous loess over weathered 

sandstone and shale, discontinuous loess over weathered limestone and shale. 

 

 Due to the agricultural nature of the land, crops in the Spencer County area consist mainly of corn, 

sorghum, wheat, soybeans, and oats (2002 Agricultural Census for Spencer County). The 

maximum modeled concentrations for Indiana Gasification, LLC are well below the threshold limits 

necessary to have adverse impacts on the surrounding vegetation such as autumn bent, 

nimblewill, barnyard grass, bishop’s cap and horsetail, and milkweed (Flora of Indiana – Charles 

Deam). Livestock in Spencer County consist mainly of hogs, cattle, and sheep (2002 Agricultural 

Census for Spencer County) and will not be adversely impacted from the facility. Trees in the 

area are mainly hardwoods. These are hardy trees and no significant adverse impacts are 

expected due to modeled concentrations. 

Federal and State Endangered Species Analysis

 Federal and state endangered species are listed by the U.S. Fish and Wildlife Service; Division of 

Endangered Species for Indiana, and includes 5 amphibians, 27 birds, 10 fishes, 6 mammals, 15 

mollusks, and 15 reptiles. Of the federal and state endangered species on the list, 1 reptile, 3 

mollusks, 1 fish, 4 birds, and 2 mammals have habitat within Spencer County. The mollusks, fish, 

amphibians, and certain species of birds and mammals are found along rivers and lakes while the 

other species of birds and mammals are found in forested areas. The facility is not expected to 

have any additional adverse effects on the habitats of the species than what has already occurred 

from the industrial, farming, and residential activities in the area. 

 Federal and state endangered plants are listed by the U.S. Fish and Wildlife Service, Division of 

Endangered Species for Indiana. At this time 8 state endangered plant species are found in 

Spencer County. The endangered plants do not thrive in industrialized and residential areas. The 

facility is not expected to adversely affect any plant on the endangered species list. 

326 IAC 2-2-6 (Increment Consumption Requirements) 

326 IAC 2-2-6(a) requires that any demonstration under section 5 of this rule shall demonstrate 

that increased emissions caused by the proposed major stationary source will not exceed eighty 

percent (80%) of the available maximum allowable increases (MAI) over the baseline 

concentration of sulfur dioxide, particulate matter, and nitrogen dioxide indicated in subsection 

(b)(1) of this rule. 

326 IAC 2-2-7 (Additional Analysis, Requirements) 

326 IAC 2-2-7(a) requires an analysis of the impairment to visibility, soils and vegetation. An 

analysis of the air quality impact projected for the area as a result of general commercial, 

residential, industrial, and other growth associated with the source. 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 
Indiana Gasification LLC Page 39 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

discontinued for a period of eighteen (18) months or more, or if construction is not 

completed within a reasonable time. 

(2) Approval for construction shall not relieve the Permittee of the responsibility to comply 

fully with applicable provisions of the state implementation plan and any other 

requirements under local, state, or federal law. 

326IAC 2-2-10 (Source Information) 

The Permittee has submitted all information necessary to perform an analysis or make the 

determination required under this rule. 

326 IAC 2-2-12 (Permit Rescission) 

The permit issued under this rule shall remain in effect unless and until it is rescinded, modified, 

revoked, or it expires in accordance with 326 IAC 2-1.1-9.5 or section 8 of this rule. 

 326 IAC 24 Clean Air Interstate Rule (CAIR) 

The Clean Air Interstate Rule (CAIR) is not applicable to any source at the IG facility. CAIR 

applies to fossil-fuel fired boilers serving a generator with a nameplate capacity of more than 25 

MW and producing electricity for sale. The Auxiliary Boilers (EU-05A/B) are fossil-fuel fired boilers 

serving a generator. However, pursuant to 326 IAC 24-1(b)(1)(B) the CAIR does not apply to a 

boiler serving a generator that supplies, in any calendar year, less than 1/3 of the unit's potential 

electric output capacity or 219,000 MW-hours (25 MW), whichever is greater, to any utility power 

distribution system for sale. Electricity produced by the Indiana Gasification facility is intended to 

balance the energy requirements of the facility. This electricity will normally be produced from 

process generated steam in a steam turbine generator, and any excess that is distributed for sale 

will not exceed 1/3 of the potential generation. Therefore, the auxiliary boilers, identified as EU05A and EU-05B are not subject to the requirements of 326 IAC 24. 

 326 IAC 21 Acid Deposition Control 

 326 IAC 21 incorporates by reference the provisions of 40 CFR 72 through 40 CFR 78 for the 

purposes of implementing an acid rain program that meets the requirements of Title IV of the 

Clean Air Act and to incorporate monitoring, record keeping, and reporting requirements for 

nitrogen oxide and sulfur dioxide emissions to demonstrate compliance with nitrogen oxides and 

sulfur dioxide emission reduction requirements. This source is not subject to the requirements of 

326 IAC 21 because it does not sell greater than 1/3 its generated electric. This regulation applies 

to electric utility generating units that supply greater than 1/3 their potential electrical output and 

greater than 219,000 MWe-hrs (25MW) actual electrical output on an annual basis to any utility 

power distribution system for sale. Therefore, the auxiliary boilers, identified as EU-05A and EU05B are not subject to the requirements of 326 IAC 21. 

Compliance Determination and Monitoring Requirements 

Permits issued under 326 IAC 2-7 are required to ensure that sources can demonstrate 

compliance with all applicable state and federal rules on a continuous basis. All state and federal 

rules contain compliance provisions; however, these provisions do not always fulfill the 

requirement for a continuous demonstration. When this occurs, IDEM, OAQ, in conjunction with 

the source, must develop specific conditions to satisfy 326 IAC 2-7-5. As a result, Compliance 

Determination Requirements are included in the permit. The Compliance Determination 

Requirements in Section D of the permit are those conditions that are found directly within state 

and federal rules and the violation of which serves as grounds for enforcement action. 

If the Compliance Determination Requirements are not sufficient to demonstrate continuous 

compliance, they will be supplemented with Compliance Monitoring Requirements, also in Section 

D of the permit. Unlike Compliance Determination Requirements, failure to meet Compliance 

Monitoring conditions would serve as a trigger for corrective actions and not grounds for 

enforcement action. However, a violation in relation to a compliance monitoring condition will 

arise through a source’s failure to take the appropriate corrective actions within a specific time 

period. 
Indiana Gasification LLC Page 40 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

The compliance monitoring requirements applicable to this modification are as follows: 

Testing Requirements 

(a) Testing Requirements 

Emission units Control device When to test Pollutants Frequency 

of testing 

Limit or 

Requirement 

Auxiliary Boiler 

(A-B) -005 

No control not later than 180 days 

after initial startup of the 

first gasifier 

CO one time 

testing 

326 IAC -2-2-3 

Auxiliary Boiler 

(A-B) -005 

No control not later than 180 days 

after initial startup of the 

first gasifier 

Thermal 

Efficiency 

one time 

testing 

326 IAC -2-2-3 

Acid Gas 

Recovery Unit 

(A-B) -007 

No Control No later than 180 days 

after initial startup of the 

second gasifier but not 

later than 365 days after 

the initial startup of the 

first gasifier 

NOx one time 

testing 

326 IAC -2-2-3 

Acid Gas 

Recovery Unit 

(A-B) -007 

Regenerative 

Thermal 

Oxidizer 

No later than 180 days 

after initial startup of the 

second gasifier but not 

later than 365 days after 

the initial startup of the 

first gasifier 

CO Every five 

(5) years 

326 IAC -2-2-3 

Acid Gas 

Recovery Unit 

(007 A-B) 

Regenerative 

Thermal 

Oxidizer 

No later than 180 days 

after initial startup of the 

second gasifier but not 

later than 365 days after 

the initial startup of the 

first gasifier 

VOC Every five 

(5) years 

326 IAC 8-1-6 

Acid Gas 

Recovery Unit 

(007 A-B) 

Regenerative 

Thermal 

Oxidizer 

No later than 180 days 

after initial startup of the 

second gasifier but not 

later than 365 days after 

the initial startup of the 

first gasifier 

HAPs 

(Methanol) 

Every five 

(5) years 

HAPs Minor 

Limit 

Process Area 

Solid Feedstock 

Handling 

(Coal/Petcoke) 

- 011 

Baghouse No later than 180 days 

after initial startup of the 

second gasifier but not 

later than 365 days after 

the initial startup of the 

first gasifier 

PM, PM10

and PM2.5

Every five 

(5) years 

326 IAC -2-2-3 

Incoming Solid 

Feed stock 

handling 

(Coal/petcoke) 

(B-V, Y-AC) - 

012 

Dust Extraction, 

or Baghouse, 

Telescoping 

Chute/ Wet 

Suppression 

No later than 180 days 

after initial startup of the 

first gasifier 

PM, PM10

and PM2.5

Every five 

(5) years 

326 IAC -2-2-3 
Indiana Gasification LLC Page 41 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

Emission units Control device When to test Pollutants Frequency 

of testing 

Limit or 

Requirement 

Wet Sulfuric 

Acid Plant (A-B) 

- 015 

Mist 

eliminator/Pero

xide Scrubber 

not later than 180 days 

after initial startup of the 

second gasifier but not 

later than 365 days after 

the initial startup of the 

first gasifier 

PM, PM10

PM2.5 and 

H2S04

Every five 

(5) years 

326 IAC -2-2-3 

Wet Sulfuric 

Acid Plant (A-B) 

- 015 

No Control not later than 180 days 

after initial startup of the 

second gasifier but not 

later than 365 days after 

the initial startup of the 

first gasifier 

CO one time 

testing 

326 IAC -2-2-3 

ZLD Spray 

Dryer 

Baghouse not later than 180 days 

after initial startup of the 

fourth gasifier, but not 

later than 365 days after 

the initial startup of the 

first gasifier 

PM, PM10

and PM2.5

Every five 

(5) years 

326 IAC -2-2-3 

Stack testing of the ZLD Spray Dryer for NOx emission is not justified because of its small size and low 

emissions rate. NOx emissions from this source results from combustion of natural gas in a standard gas 

burner incorporated in the dryer design. The maximum capacity of the burner is only 5.6 MMBtu per hr and 

NOx emissions are less than one (1) ton per yr. Stack testing this small, uncontrolled source is not 

required for this unit. 

 

Stack testing the Gasifier Preheat Burners for NOx emissions is not justified because it is technically very 

difficult and also because the burners are each such small sources. There are five (5) preheat burners, 

which are used intermittently during gasifier startups and/or to keep a spare gasifier in hot standby. All five 

burners added together, over the course of a year, average only 12 MMBtu per hr (2.4 MMBtu/hr each) and 

collectively only emit 5.26 tons per year of NOx. Also, it would be technically very difficult to test these 

emissions because of the unique process configuration. The burners are used inside of the gasifier vessel 

to warm it prior to startup. Unlike a conventional heater or boiler, the gasifier vessels are fully enclosed 

vessels and can’t rely on natural draft for combustion air or for venting combustion exhaust. Instead this is 

accomplished by use of a steam eductor to draw out the combustion exhaust. The steam eductor injects 

steam directly into the exhaust flow. The resultant vent stream is mostly water vapor, with only a small 

amount of exhaust. The extremely high moisture content of this vent stream would be technically very 

difficult to stack test. Because of these difficulties and the small size of these sources, stack testing is not 

required for this emission unit. 

(b) The compliance monitoring requirements applicable to this source are as follows: 

Control Parameter Frequency Range/ 

Value 

Excursions 

and 

Exceedances 

Limit or 

Requirement 

Syngas Hydrocarbon 

Flare (EU-001) 

Flare pilot flame Continuous 

N/A 

Response 

steps Total gas flow 326 IAC 2-2-3 

Visible 

Emissions Daily 

Acid Gas Flare (EU002) (Thermocouple) 

Flare pilot flame Continuous 

N/A 

Response 

steps 326 IAC 2-2-3 Visible 

Emissions Daily 

Acid Gas Recovery 

Unit (A-B) -007 (RTO) Temperature Continuous > 1600 o

F 
Indiana Gasification LLC Page 42 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

Control Parameter Frequency Range/ 

Value 

Excursions 

and 

Exceedances 

Limit or 

Requirement 

Acid Gas Recovery 

Unit (A-B) -007 (water 

wash tower) 

Water wash flow 

rate Continuous N/A 

Response 

steps 

HAPs Minor 

Limit 

Wet Sulfuric Acid Plant 

(A-B) - 015 (Peroxide 

Scrubber)

Compliance with 

the SO2

emissions limit 

Continuous 

(w/CEM) 

8.3 lb/hr 

each WSA 

(24 hr 

average) 

Response 

steps 

326 IAC 2-2-3 

and 40 CFR 64 

Wet Sulfuric Acid Plant 

(A-B) - 015 (SCR) Temperature 

Continuous 

when SCR 

is not 

operating 

N/A 

Response 

steps 

326 IAC 2-2-3 

Wet Sulfuric Acid Plant 

(A-B) - 015 (Mist 

Eliminator/Peroxide 

Scrubber)

Flow Rate 

Daily 

N/A Response 

steps 

326 IAC 2-2-3 

and 40 CFR 64 

Pressure Drop 1.0 - 5.0 

inches 

Wet Sulfuric Acid Plant 

(A-B) - 015 (SCR) 

compliance with 

NOx emission 

limit 

Daily NA 

Response 

steps 

326 IAC 2-2-3 

and 40 CFR 64 

Process Area Solid 

Feedstock Handling 

(Coal/Petcoke) - 011 

(Baghouse) 

Water Pressure 

Drop 

Daily 

1.0 to 5.0 

inches Response 

steps 

326 IAC 2-2-3 

and 40 CFR 64 

Visible 

Emissions 

NormalAbnormal 

Incoming Solid Feed 

stock Radial Stacker 

(N-O) -012 (Fabric 

Filters/Telescoping 

Chute 

Water Pressure 

Drop 

Daily 

1.0 to 5.0 

inches Response 

steps 

326 IAC 2-2-3 

and 40 CFR 64 

Visible 

Emissions 

NormalAbnormal 

Incoming Solid Feed 

stock open handling 

(A,P,Q,W,X) -012 (Wet 

Suppression) 

Visible 

Emissions Daily NormalAbnormal 

Response 

steps 

326 IAC 2-2-3 

and 40 CFR 64 

Incoming Solid Feed 

stock enclosed 

handling (B-M, R-V, YAC) EU- 012 Wet Dust 

Extractor or Baghouse 

Water flow rate 

Daily 

> 1. 5 gpm 

Response 

steps 

326 IAC 2-2-3 

Water Pressure and 40 CFR 64 

Drop 

1.0 to 5.0 

inches 

Visible 

Emissions 

NormalAbnormal 

Incoming Solid Feed 

stock enclosed 

handling (R-S) EU012 Wet Dust Extractor 

or Baghouse 

Water flow rate 

Daily 

> 5.0 gpm 

Response 

steps 

326 IAC 2-2-3 

Water Pressure and 40 CFR 64 

Drop 

1.0 to 5.0 

inches 

Visible 

Emissions 

NormalAbnormal 

ZLD Spray Dryer - 

032(Baghouse)

Water Pressure 

Drop Daily 

1.0 to 5.0 

inches Response 

steps 

326 IAC 2-2-3 

and 40 CFR 64 

Visible 

Emissions 

NormalAbnormal 

Methanol Storage 

Tank (Condenser) 

Refrigerant 

Temperature Continuous < 0o

F Response 

steps 

40 CFR 64 

ZLD Vent EU-033 

Sulfided Carbon 

Adsorbent 

Pressure Drop Weekly N/A Response 

steps 

HAPs Minor 

Limit 
Indiana Gasification LLC Page 43 of 43 

Rockport, Indiana PSD and TV Permit No.: 147-30464-00060 

Permit Reviewer: Josiah Balogun

(c) Continuous Emission Monitoring System (CEMs) Requirements applicable to this source 

are as follows: 

Control Parameter Frequency Value Excursions and 

Exceedances 

Requirement 

Auxiliary Boiler (AB) -005 NOx CEMS Continuous N/A 

Continuous emission 

monitoring system 

measurement data. 

326 IAC 2-2-3 

Wet Sulfuric Acid 

Plant (A-B) - 015 NOx CEMS Continuous N/A 

Continuous emission 

monitoring system 

measurement data. 

326 IAC 2-2-3 

Wet Sulfuric Acid 

Plant (A-B) - 015 SO2 CEMS Continuous N/A 

Continuous emission 

monitoring system 

measurement data. 

326 IAC 2-2-3 

Wet Sulfuric Acid 

Plant (A-B) - 015 CO2 CEMS Continuous N/A 

Continuous emission 

monitoring system 

measurement data. 

326 IAC 2-2-3 

Conclusion and Recommendation 

The construction and operation of this proposed new source shall be subject to the conditions of 

the attached proposed Part 70 PSD/New Source Construction and operating permit No.T147-

30464-00060. The staff recommends to the Commissioner that this Part 70 PSD/New Source 

Construction and operating permit be approved. 

IDEM Contact 

(a) Questions regarding this proposed permit can be directed to Josiah Balogun at the Indiana 

Department Environmental Management, Office of Air Quality, Permits Branch, 100 North Senate 

Avenue, MC 61-53 IGCN 1003, Indianapolis, Indiana 46204-2251 or by telephone at (317) (234-

5257) or toll free at 1-800-451-6027 extension (4-5257). 

(b) A copy of the findings is available on the Internet at: http://www.in.gov/ai/appfiles/idem-caats/

(c) For additional information about air permits and how the public and interested parties can 

participate, refer to the IDEM’s Guide for Citizen Participation and Permit Guide on the Internet at: 

www.idem.in.gov
Appendix A: Emissions Calculations Page 1 of 2 TSD App A

Emission Summary

Source Name: Indiana Gasification, LLC

Source Location: CR 200 N and Based Road, Rockport, IN 47635

Permit Number: 147-30464-00060

Permit Reviewer: Josiah Balogun

Date: 30-Jun-2011

Uncontrolled Potential to Emit 

PM 

(tons/yr)

PM10 

(tons/yr) 

PM2.5 

(tons/yr)

SO2 

(tons/yr)

VOC 

(tons/yr) 

CO 

(tons/yr)

NOx 

(tons/yr)

H2SO4 

(tons/yr)

H2S 

(tons/yr)

Pb 

(tons/yr)

Hg 

(tons/yr)

Methanol 

(tons/yr)

Total 

HAPs 

(tons/yr) CO2 (tons/yr)

Total CO2e 

(tons/yr)

Emission UnitSyngas Hydrocarbon Flare (001) 28.12 28.12 0.41 3.045 0.43 301956 377.65 0 0.06 3.4E-06 1.90E-06 0 0 816,190 857,135Acid Gas Flare (002) 0.01 0.01 0.01 0.001 0.023 0.06 0.23 0 0 3.4E-06 1.90E-06 0 0 136 136Auxiliary Boiler (005A-B) 26.93 26.93 5.62 2.13 19.49 130.13 45.2 0 0 0.033 6.10E-03 0 6.69 422401 422816Acid Gas Recovery Unit (007A-B) 3.8 3.8 2.46 41.62 39.64 632.8 25.99 0 7.47 0.000986 8.20E-04 10.54 37.83 1,289,735 1,290,000Gasifier Preheat Burners (008A-E) 0.3 0.3 0.04 0.23 2.15 22.1 39.4 0 0 0.0003 6.50E-04 0 0.75 46,383 46,405Emergency Diesel Generator (009A-B) 0.03 0.03 0.003 0.008 0.015 0.019 7.28 0 0 0.00E+00 0.00E+00 0 0 350.88 352.1Emergency Firewater Engine (010A-C) 0.08 0.08 0.0078 0.0046 0.164 0.6 2.35 0 0 0.00E+00 0.00E+00 0 0 199.9 200.6Process Area Solid Feedstock (011) 5.49 5.49 1.94 0 0 0 0 0 0 0.00105 5.40E-06 0 0 0 0Incoming Solid Feedstock Handling (012A-AC)

202.1 88.38 12.24 0 0 0 0 0 0 0.00E+00 8.94E-06 0 0 0 0

Rod Mill (013A-D) 0.44 0.44 0.13 0 0 0 0 0 0 0.00E+00 3.78E-07 0 0 0 0Wet Sulfuric Acid Plant (015A-B) 43.8 43.8 43.8 72.76 0.0113 164.3 89.4 43.8 0 0.00044 3.52E-06 0 0 474000 474000Cooling Tower -ASU (016A) 0.9 0.9 0.75 0 0 0 0 0 0 0.00E+00 0.00E+00 0 0 0 0Cooling Tower -Main (016B) 6.65 6.65 5.52 0 0 0 0 0 0 0.00E+00 0.00E+00 0 0 0 0ASU Molecular Sieve Regeneration (017A-B) 1.1 1.1 0.08 0 0 0 0 0 0 0.00E+00 0.00E+00 0 0 0 0Slag Sump (023A-E) 0 0 0 0 0 0 0 0 0.1 0.00E+00 0.00E+00 0 0 0 0Methanol De-Inventory Storage Tank (024) 0 0 0 0 0.16 0 0 0 0 0.00E+00 0.00E+00 0.16 0.16 0 0Fresh Methanol Storage Tank (025) 0 0 0 0 0.13 0 0 0 0 0.00E+00 0.00E+00 0.13 0.13 0 0Sour Water Stripper Surge Tank (026) 0 0 0 0 0.004 0 0 0 0.54 0.00E+00 0.00E+00 0 0 0 0Sulfuric Acid Storage Tank (027A-F) 0.0015 0.0015 0.0015 0 0 0 0 0.0015 0 0.00E+00 0.00E+00 0 0 0 0Diesel Fuel Storage Tank (029) 0 0 0 0 0.35 0 0 0 0 0.00E+00 0.00E+00 0 0.07 0 0Gasoline Fuel Storage Tank (030) 0 0 0 0 0.1 0 0 0 0 0.00E+00 0.00E+00 0 0 0 0Triethylene Glycol Storage Tank (031) 0 0 0 0 0 0 0 0 0 0.00E+00 0.00E+00 0 0 0 0ZLD Spray Drier (032) 0.51 0.51 0.48 0.015 0.13 0.89 0.86 0 0 0.000071 4.10E-05 0 0.046 2882.8 2886ZLD Inert Gas Vent (033) 0 0 0 0 0 0 0 0 0 0.00E+00 6.53E-02 0 0 203.67 203.67EU-034A and 034C 0.041 0.017 0.0024 0 0 0 0 0 0 0.00E+00 0.00E+00 0 0 0 0Fugitive EmissionsGasification, Shift Conv. AGR, methanation (FUG) 0 0 0 0 27.46 9.45 0 0 0.38 0.00E+00 0.00E+00 7.15 7.58 48.86 325.6Fugitive Emission - WSA (FUG-WSA) 0 0 0 0.1 0 0 0 0.09 3.74 0.00E+00 0.00E+00 0 0 4 4Plant Haul Roads (FUGROAD) 2.63 0.53 0.13 0 0 0 0 0 0 0.00E+00 0.00E+00 0 0 0 0Electric Circuit Breakers (FUG-SF6) 0 0 0 0 0 0 0 0 0 0.00E+00 0.00E+00 0 0 0 72Total Emissions 322.93 207.09 73.63 119.91 90.26 302916 588.36 43.89 12.29 0.04 7.29E-02 17.98 53.26 3052535.11 3094535.97

Appendix A: Emissions Calculations Page 2 of 2 TSD App A
Emission Summary

Source Name: Indiana Gasification, LLC

Source Location: CR 200 N and Based Road, Rockport, IN 47635

Permit Number: 147-30464-00060

Permit Reviewer: Josiah Balogun

Date: 30-Jun-2011

Limited Potential to Emit 

PM 

(tons/yr)

PM10 

(tons/yr) 

PM2.5 

(tons/yr)

SO2 

(tons/yr)

VOC 

(tons/yr) 

CO 

(tons/yr)

NOx 

(tons/yr)

H2SO4 

(tons/yr)

H2S 

(tons/yr)

Pb 

(tons/yr)

Hg 

(tons/yr)

Methanol 

(tons/yr)

Total 

HAPs 

(tons/yr) CO2 (tons/yr)

Total CO2e 

(tons/yr)

Emission UnitSyngas Hydrocarbon Flare (001) 0.44 0.44 0.41 1.97 0.03 23.5 6.07 0 0.04 3.4E-06 1.90E-06 0 0 13302 13,343

Acid Gas Flare (002) 0.01 0.01 0.01 0.001 0.023 0.06 0.23 0 0 3.4E-06 1.90E-06 0 0 136 136Auxiliary Boiler (005A-B) 5.62 5.62 5.62 0.44 4.07 27.15 9.43 0 0 0.0022 1.3E-03 0 1.4 88167 88254Acid Gas Recovery Unit (007A-B) 2.46 2.46 2.46 26.98 8.96 410.27 16.85 0 0.1 0.00096 5.30E-04 9 22.5 1,289,735 1,290,000Gasifier Preheat Burners (008A-E) 0.04 0.04 0.04 0.03 0.3 3.08 5.51 0 0 0.00016 9.05E-05 0 0.1 6438 6444Emergency Diesel Generator (009A-B) 0.003 0.003 0.0003 0.0008 0.0015 0.019 0.76 0 0 0.00E+00 0.00E+00 0 0Emergency Firewater Engine (010A-C) 0.008 0.008 0.0078 0.0005 0.017 0.06 0.24 0 0 0.00E+00 0.00E+00 0 0

Process Area Solid Feedstock (011) 3.8 3.8 1.86 0 0 0 0 0 0 0.00103 5.40E-06 0 00 0Incoming Solid Feedstock Handling (012A-AC)

5.45 3.25 0.88 0 0 0 0 0 0 0.00E+00 8.94E-06 0 0 0 0

Rod Mill (013A-D) 0.44 0.44 0.13 0 0 0 0 0 0 0.00E+00 3.80E-07 0 00 0

Wet Sulfuric Acid Plant (015A-B) 42.59 42.59 42.59 70.74 0.01 159.7 86.93 42.59 0 6.1E-06 3.52E-06 0 0 474000 474000Cooling Tower -ASU (016A) 0.9 0.9 0.7 0 0 0 0 0 0 0.00E+00 0.00E+00 0 00 0Cooling Tower -Main (016B) 6.65 6.65 5.19 0 0 0 0 0 0 0.00E+00 0.00E+00 0 00 0

ASU Molecular Sieve Regeneration (017A-B) 0.22 0.22 0.08 0 0 0 0 0 0 0.00E+00 0.00E+00 0 00 0

Slag Sump (023A-E) 0 0 0 0 0 0 0 0 0.1 0.00E+00 0.00E+00 0 00 0Methanol De-Inventory Storage Tank (024) 0 0 0 0 0.16 0 0 0 0 0.00E+00 0.00E+00 0.16 0.16 0 0

Fresh Methanol Storage Tank (025) 0 0 0 0 0.13 0 0 0 0 0.00E+00 0.00E+00 0.13 0.13 0 0

Sour Water Stripper Surge Tank (026) 0 0 0 0 0.004 0 0 0 0.54 0.00E+00 0.00E+00 0 00 0Sulfuric Acid Storage Tank (027A-F) 0.0015 0.0015 0.0015 0 0 0 0 0.0015 0 0.00E+00 0.00E+00 0 00 0

Diesel Fuel Storage Tank (029) 0 0 0 0 0.35 0 0 0 0 0.00E+00 0.00E+00 0 0.07 0 0

Gasoline Fuel Storage Tank (030) 0 0 0 0 0.1 0 0 0 0 0.00E+00 0.00E+00 0 00 0

Triethylene Glycol Storage Tank (031) 0 0 0 0 0 0 0 0 0 0.00E+00 0.00E+00 0 00 0ZLD Spray Dryer (032) 0.51 0.51 0.48 0.015 0.13 0.89 0.86 0 0 0.000071 4.10E-05 0 0.046 2882.8 2886ZLD Inert Gas Vent (033) 0 0 0 0 0 0 0 0 0 0.00E+00 3.60E-04 0 0 203.67 203.67EU-034A and 034C 0.04 0.017 0.0024 0 0 0 0 0 0 0.00E+00 0.00E+00 0 00 0

Fugitive EmissionsGasification, Shift Conv. AGR, methanation (FUG) 0 0 0 0 1.61 9.45 0 0 0.37 0.00E+00 0.00E+00 0.37 0.38 19 21

Fugitive Emission - WSA (FUG-WSA) 0 0 0 0.003 0 0 0 0.09 3.74 0.00E+00 0.00E+00 0 04 4Plant Haul Roads (FUGROAD) 0.45 0.09 0.022 0 0 0 0 0 0 0.00E+00 0.00E+00 0 00 0

Electric Circuit Breakers (FUG-SF6) 0 0 0 0 0 0 0 0 0 0.00E+00 0.00E+00 0 0 0 72Total Emissions 69.63 67.05 60.48 100.18 15.90 634.18 126.88 42.68 4.89 0.004 0.00231 9.66 24.79 1874971.47 1875447.67

84 84
FLARE SOURCES Page 1 of 3 TSD App A

NAME Hydrocarbon / Gasifier Start-up Flare Unit ID: 001

STACK DATA

HEIGHT 300 ft

DIAMETER 6 ft

EMISSIONS: Scenario 1: Gasifier Start-Up Syngas Flaring hr/yr = 8760

Firing Rate = 861.7 MMBtu/hr

CO DRE 0 %

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb-mol/hr lb-mol/hr lb-mol/hr Mol % lb/hr lb/hr TPY

PM10 -- -- -- -- 6.42 6.42 28.12

PM2.5 0.09 0.09 0.41

SO2 0.01 0 -- -- 0.70 0.70 3.045

NOx -- -- -- -- 86.17 86.17 377.42

CO -- -- 18237.12 13.50 68939.73 68939.73 301956.00

H2S (TAP) 0.01 -- -- -- 0.01 0.01 0.03

COS (TAP)(VOC) -- 0.00 -- -- 0.00 0.00 0.00

Other VOC -- -- -- -- 0.09 0.09 0.41

Total VOC 0.09 0.09 0.41

EMISSIONS: Scenario 2: Gasifier Start-Up Flare Pilot Burners Operating hr/yr = 8,760

Pilot Firing Rate = 0.27 MMBtu/hr

AP-42 Heating Value = 1,020 Btu/scf

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb/hr lb/hr TPY

PM10 0.0020 0.0020 0.0087

PM2.5 0.0019 0.0019 0.0081

SO2 0.0002 0.0002 0.00068

NOx 0.053 0.053 0.23

CO 0.013 0.013 0.06

VOC 0.005 0.005 0.02

Total VOC HAPs 0.0005 0.0005 0.0022

Mercury (HAP) 4.4E-07 4.4E-07 1.9E-06

TOTAL STARTUP FLARING AND PILOT

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb/hr lb/hr TPY

PM10 6.422 6.42 28.13

PM 0 095 0 09 0 41

H2S in Syngas COS in Syngas

Raw Syngas 

Flared CO in Syngas

PM2.5 0.095 0.09 0.41

SO2 0.70 0.70 3.046

NOx 86.22 86.22 377.65

CO 68939.74 68939.74 301956.05

H2S (TAP) 0.013 0.01 0.06

COS (TAP)(VOC) 0.00 0.00 0.00

Total VOC 0.0982 0.09 0.43

Total VOC HAPs 0.0005 0.0005 0.0022

Mercury (HAP) 4.4E-07 4.4E-07 1.9E-06
Calculations: Page 2 of 3 TSD App A

Scenario 1:

Emissions (SO2)(Avg. lb/hr)=H2S in Syngas (lb-mol/hr) + COS in Syngas (lb-mol/hr) X 64.063 lb/mol

Emissions (CO)(Avg. lb/hr)=(Raw Syngas flared (lbmols/hr) X CO in Syngas (mol %)/100) X 28.01 lb/mol X (100 - CO DRE)/100

Emissions (H2S)(Avg. lb/hr)=H2S in Syngas (lb-mol/hr) X 34.08 lb/mol X 2/100

Emissions (COS)(Avg. lb/hr)=COS in Syngas (lb-mol/hr) X 60.0764 lb/mol X 2/100

Emissions (NOx, PM10, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

Scenarios 2 and 3:

Emissions (PM10, SO2)(Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft

3

) X Heat Input (MMBtu/hr)

Emissions (NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions-Pilot Case (SO2, NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

NOx PM10 VOC

0.100 0.007 0.0001

PM10 SO2

7.600 0.60

NOx CO VOC

0.200 0.050 0.020

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

Number Shutdown Flaring Events / year = 15

Flaring Event Duration (hrs) = 3

Firing Rate (MMBtu/Event) = 34.26

SHUTDOWN FLARING

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb/event lb/hr TPY

Scenario 1

Factor (lb/MMBtu)

Sources: NOx and PM10 for Syngas are based on values from vendor supplied data. VOC for Syngas = 2% of AP-42 Section 1.4 "Natural Gas Combustion" Table 1.4-2 

Scenario 2

Factor (lb/MMscf)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for PM10. 

Scenario 2

Factor (lb/MMBtu)

Sources: NOx and CO, and VOC are based on values from vendor supplied data. 

Mercury Factor (lb/MMBtu)

DRE for H2S and COS is considered as 98%.

DRE for CO is considered as 99.5%.

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs for natural gas to the pilot are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4. Flared gas is primarly CO and H2 - HAPs assumed negligable.

Scenario 1: Gasifier Start-up Syngas Flaring

Scenario 2: Gasifier Start-up Flare Pilot Burners Operating 

Scenario 3: Normal Operations-Purge Gas and Pilot Gas Flaring

PM10 0.260 0.09 0.002

PM2.5 0.260 0.09 0.002

SO2 255.62 85.21 1.917

NOx 3.43 1.14 0.026

CO 21.22 7.07 0.159

H2S (TAP) 2.660 0.89 0.020

COS (TAP)(VOC) 0.20 0.07 0.002

VOC 0.0037 0.00 0.000
Page 3 of 3 TSD App A

GHG Emissions from Gasifier Start-up

lb/hr TPY MT/yr

CO2 for Gasifier Flare = 185,818.1 813,883.3 738354.9

Equation Y-5

N2O = Annual nitrous oxide emissions from flared gas (metric ton N2O/year)

CO2 = Emission rate of CO2 from flared gas calculated (metric ton/year)

EmFN2O = Default N2O emission factor for “Petroleum Products” from Table C-2 of subpart C (General Stationary Fuel Combustion Sources) (kg N2O/MMBtu) = 0.0006

EmF = Default CO2 emission factor for flare gas of 60 kg CO2/MMBtu (HHV basis)

N2O for Gasifier Flare = 7.384 MT

GHG Emissions from Pilot

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 123.2 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0023 MT

N2O = 0.0002 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

The feed to the gasifier flare during the start-up of a gasifier contains CO and CO2, but no other carbon compounds. A mass balance was used to determine the CO2 

and N2O emissions. There will be no CH4 emissions. The GHG Subpart Y (Refinery) flare equations are not applicable; however, the Subpart Y equation for N2O will 

be used to conservatively estimate N2O emissions.















   EmF

EmF N O CO N2O

2 2

CO    Fuel  HHV  EF  3

2 1 10

CH orN O    Fuel  HHV  EF  3

4 2 1 10

gaseous fuel 

combusted

Annual 2,277,600 scf

High heat value 

of the fuel from 

all valid samples 

for the year

Annual Average 0.00102 MMBtu per scf

Startup

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 738,355 1 738,355

CH4 0 21 0

N2O 7.384 310 2,288.9

TOTAL = 740,644 816,190 TPY CO2

Shutdown

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 36,918 1 36,918

CH4 0 21 0

N2O 0.369 310 114.4

TOTAL = 37,032 40,809 TPY CO2

Shutdown flared gas volume on an annual basis is 5% of startup flared gas volume.

Pilot

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 123.2 1 123.2

CH4 0.0023 21 0.05

N2O 0.0002 310 0.07

TOTAL = 123.3 136 TPY CO2

Hydrocarbon / Gasifier Startup Flare
FLARE SOURCES Page 1 of 2 TSD App A

NAME Acid Gas Flare Unit ID: 002

The Acid Gas Flare normally operates on pilot gas (natural gas) only. During an upset, acid gases can be routed to this flare.

STACK DATA

HEIGHT 300 ft

DIAMETER 1.6 ft

EMISSIONS: Acid Gas Flare Pilot Only

hr/yr = 8,760

Pilot Firing Rate = 0.27 MMBtu/hr

AP-42 Heating Value = 1,020 Btu/scf

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb/hr lb/hr TPY

PM10 0.0020 0.0020 0.0087

PM2.5 0.0019 0.0019 0.0081

SO2 0.0002 0.0002 0.00068

NOx 0.053 0.053 0.23

CO 0.013 0.013 0.058

VOC 0.005 0.005 0.023

Total VOC HAPs 0.0005 0.0005 0.0022

Mercury (HAP) 4.4E-07 4.4E-07 1.9E-06

CO2 31.00 31.00 136

Calculations:

Emissions (PM10, SO2)(Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

PM10 SO2

7.600 0.60

NOx CO VOC CO2

0.200 0.050 0.020 116.890

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

Source: NOx, CO, and VOC factors from AP-42 Section 13.5 "Industrial Flares" Table 13.5-1

Mercury Factor (lb/MMBtu)

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S).

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

Natural Gas Combustion

Factor (lb/MMscf)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for PM10. 

Flare

Factor (lb/MMBtu)

16_30464 Calcs F 6 5/3/2012
Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis) Page 2 of 2 TSD App A

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 123 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0023 MT

N2O = 0.0002 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 2,277,600 scf

High heat value 

of the fuel from 

all valid samples 

for the year

Annual 

Average 0.00102 MMBtu per scf

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 123 1 123

CH4 0.0 21 0

N2O 0.0 310 0

TOTAL = 123 136 TPY CO2

Acid Gas Flare

CO    Fuel  HHV  EF  3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

16_30464 Calcs F 7 5/3/2012
COMBUSTION SOURCES Page 1 of 3 TSD App A

NAME Auxiliary Boiler Unit ID: 005A & B

Emissions shown are for sum of two (2) boilers each at 408 MMBtu/hr

STACK DATA

HEIGHT 200 ft

DIAMETER 11 ft

GAS EXIT TEMP- Full rate - Natural Gas 310 °F

GAS EXIT TEMP- Full rate (Black Start) - Natural Gas 310 °F

GAS EXIT VELOCITY - Full rate - Natural Gas 48.73 fps

GAS EXIT VELOCITY - Full rate (Black Start) - Natural Gas 48.73 fps

COMBUSTION DATA

HEAT INPUT - Full rate - Natural Gas 816.33 MM Btu/hr

HEAT INPUT - Full rate (Black Start) - Natural Gas 816.33 MM Btu/hr

HEAT INPUT - Pilot Gas - Natural Gas 10.00 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS- Full rate - Natural Gas 8760 hr/yr

OPERATING HOURS - Full rate (Black Start) - Natural Gas 96 hr/yr

EMISSIONS: Full rate case - Natural Gas

lb/hr avg. lb/hr max. TPY 

PM10 6.08 6.08 26.64

PM2.5 1.22 1.22 5.33

SO2 0.48 0.48 2.10

NOx 10.20 10.20 44.69

CO 29.39 29.39 128.72

VOC 4.40 4.40 19.28

Total VOC HAPs 1.51 1.51 6.62

Mercury (HAP) 1.4E-03 1.4E-03 6.0E-03

EMISSIONS: Full rate (Black Start) case - Natural Gas

lb/hr avg. lb/hr max. TPY 

PM10 6.08 6.08 0.29

PM2.5 6.08 6.08 0.29

SO2 0 48 . 0 48 . 0 023 .

NOx 10.20 10.20 0.49

CO 29.39 29.39 1.41

VOC 4.40 4.40 0.21

Total VOC HAPs 1.51 1.51 0.073

Mercury (HAP) 1.4E-03 1.4E-03 6.6E-05
EMISSIONS: Normal Operations Total Page 2 of 3 TSD App A

lb/hr avg. lb/hr max. TPY 

PM10 6.15 6.08 26.93

PM2.5 1.28 6.08 5.62

SO2 0.49 0.48 2.13

NOx 10.32 10.20 45.18

CO 29.71 29.39 130.13

VOC 4.45 4.40 19.49

Total VOC HAPs 1.53 1.51 6.69

Mercury (HAP) 1.4E-03 1.4E-03 6.1E-03

CALCULATIONS

Emissions (PM10, VOC, and SO2)(Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (NOx, CO) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Total Emissions (Avg. lb/hr) = Total TPY x 2,000 lb/ton / 8,760 hr/yr

Total Emissions (Max. lb/hr) = Highest Maximum lb/hr value from either case

PM10 VOC SO2 HAP

7.600 5.50 0.60 1.89

NOx CO

0.0125 0.036

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

Factor (lb/MMBtu)

Natural Gas Combustion

Factor (lb/MMscf)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10.

Mercury Factor (lb/MMBtu)

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

To be conservative SO2 emissions will be calculated assuming all scenarios fire natural gas If SNG is fired there will be no SO2 emissions as SNG is assumed to contain 

Natural Gas/SNG Combustion

Source: Emission factors for NOx and CO are based on vendor data for Low NOx burners (LNB), SCR and Flue Gas Recirculation. 

To be conservative, SO2 emissions will be calculated assuming all scenarios fire natural gas. If SNG is fired, there will be no SO2 emissions as SNG is assumed to contain 

no sulfur.

To be conservative, the mercury factor for SNG (Coal-Coke) will be used for all cases.

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).
Page 3 of 3 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 383,304 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 7.2294 MT

N2O = 0.7229 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 7,087,677,766 scf

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

combusted

High heat value 

of the fuel from 

all valid samples 

for the year

Annual 

Average 0.00102 MMBtu per scf

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 383,304 1 383,304

CH4 7.2 21 152

N2O 0.7 310 224

TOTAL = 383,680 422,816 TPY CO2

Auxiliary Boiler
COMBUSTION SOURCES Page 1 of 9 TSD App A

NAME AGR CO2 Regenerative Thermal Oxidizer Unit ID: 007

STACK DATA

HEIGHT 200 ft

DIAMETER 9 ft

GAS EXIT TEMP 250 °F

GAS EXIT VELOCITY 60.5 fps

COMBUSTION DATA (max from either case)

HEAT INPUT: Two Units at full rate 77.62 MM Btu/hr

HEAT INPUT: One Unit at full rate 38.81 MM Btu/hr

HEAT INPUT: Black-starts (1 unit at half rate) 19.41 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS: Two Units at full rate 8760 hr/yr

OPERATING HOURS: One Unit at full rate 8760 hr/yr

OPERATING HOURS: Black-start 24 hr/yr

H2S in Waste gas to each RTO = 0.57 lb/hr

COS in Waste gas to each RTO = 2.00 lb/hr

CO in Waste gas to each RTO: 4673.99 lb/hr

Total Sulfur in Waste gas to each RTO: 1.60 lb/hr

Methanol in Waste Gas to each RTO: 80.20 lb/hr

H2S and COS DRE: %

CO and Methanol DRE: %

EMISSIONS: Two Units at Full Rate

lb/hr avg. lb/hr max. TPY 

PM10 0.58 0.58 2.53

PM2.5 0.55 0.55 2.40

SO 6 33 6 33 27 73

There are 2 RTOs which share a common chimney (although there are separate stacks), and receive waste gas feeds from the Acid Gas Removal Unit.

Emissions are calculated for both cases (coal / coke and coal only) and the higher (conservative) value for each pollutant will be permitted. 

SO2 6.33 6.33 27.73

NOx 3.95 3.95 17.32

CO 96.27 96.27 421.68

VOC 6.03 6.03 26.42

H2S (TAP) 1.14 1.14 4.98

COS (HAP)(VOC) 4.01 4.01 17.56

Methanol (HAP)(VOC) 1.60 1.60 7.03

Total VOC HAPs 5.76 5.76 25.22

Mercury (HAP) 1.2E-04 1.2E-04 5.5E-04

EMISSIONS: Two Units on Hot Standby

lb/hr avg. lb/hr max. TPY 

PM10 0.29 0.29 1.27

PM2.5 0.01 0.01 0.06

SO2 3.17 3.17 13.87

NOx 1.98 1.98 8.66

CO 48.14 48.14 210.84

VOC 3.02 3.02 13.21

H2S (TAP) 0.57 0.57 2.49

COS (HAP)(VOC) 2.00 2.00 8.78

Methanol (HAP)(VOC) 0.80 0.80 3.51

Total VOC HAPs 2.88 2.88 12.61

Mercury (HAP) 6.2E-05 6.2E-05 2.7E-04
EMISSIONS: One Unit at half rate - Conservatively assume Natural Gas for entire 24 hrs Page 2 of 9 TSD App A

lb/hr avg. lb/hr max. TPY 

PM10 0.14 0.14 0.0017

PM2.5 0.14 0.14 0.0017

SO2 1.58 1.58 0.019

NOx 0.99 0.99 0.012

CO 24.07 24.07 0.29

VOC 0.53 0.53 0.006

H2S (TAP) 0.01 0.01 0.0001

COS (HAP)(VOC) 0.02 0.02 0.0002

Methanol (HAP)(VOC) 0.40 0.40 0.0048

Total VOC HAPs 0.46 0.46 0.005

Mercury (HAP) 3.1E-05 3.1E-05 3.7E-07

EMISSIONS: Normal Operations Total

lb/hr avg. lb/hr max. TPY 

PM10 0.87 0.58 3.80

PM2.5 0.56 0.56 2.46

SO2 9.50 6.33 41.62

NOx 5.93 3.95 25.99

CO 144.48 96.27 632.81

VOC 9.05 6.03 39.64

H2S (TAP) 1.706 1.14 7.47

COS (HAP)(VOC) 6.01 4.01 26.35

Methanol (HAP)(VOC) 2.41 1.60 10.54

Total VOC HAPs 8.64 5.76 37.83

Mercury (HAP) 1.9E-04 1.2E-04 8.2E-04

CALCULATIONS

Emissions (PM10) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions - Normal (SO2) (Avg. lb/hr) = S in Waste Gas to each RTO (lb/hr) X 2 X DRE/100 X Mw SO2 (lb/lb-mol) / Mw S (lb/lb-mol)

Emissions - Black-start (SO2) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (NOx) (Avg. lb/hr) = Vendor Factor (lb/MMBtu) X Heat Input (MMBtu/hr)

Emissions (CO) (Avg. lb/hr) = Vendor Factor (lb/MMBtu) X Heat Input (MMBtu/hr) + CO in Waste Gas (lb/hr) X 2 X (1 - DRE)/100 3 Emissions (VOC) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft ) X Heat Input (MMBtu/hr) + COS (lb/hr) + MeOH (lb/hr)

Emissions (COS, MeOH) (Avg. lb/hr) = lb in Waste Gas (lb/hr) X 2 X (1 - DRE)/100

Emissions for each Case (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Maximum Emissions for each Case (lb/hr) = Average Emissions

Emissions TPY Total = Sum of individual cases

Emissions (Avg. lb/hr) Total = TPY Total X 2,000 (lb/T) / (Total Hrs Operation)

Natural Gas Combustion PM10 VOC SO2 HAP

7.60 5.50 0.6 1.89

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10

Natural Gas Combustion NOx CO

0.05 0.036

Comments:

Factor (lb/MM scf)

Factor (lb/MMBtuf)

SO2 emissions based on 98% conversion of sulfur in waste gas to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S).

During "normal operations" the thermal oxidizer burns SNG (which contains no sulfur); during a black-start, it fires natural gas for the first 4 hours. Permitted emissions will 

conservatively be based on firing natural gas only.

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

Source: Emission factors for NOx and CO are based on information from vendor supplied data and the use of Low NOx burners. 
Page 3 of 9 TSD App A

This page left blank Intentionally.
Page 4 of 9 TSD App A

Coal / Coke Case

COMBUSTION DATA

HEAT INPUT: Two Units at full rate 62.69 MM Btu/hr

HEAT INPUT: One Unit at full rate 31.35 MM Btu/hr

HEAT INPUT: Black-starts (1 unit at half rate) 15.67 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS: Two Units at full rate 8760 hr/yr

OPERATING HOURS: One Unit at full rate 8760 hr/yr

OPERATING HOURS: Black-start 24 hr/yr

H2S in Waste gas to each RTO = 0.56 lb/hr

COS in Waste gas to each RTO = 1.97 lb/hr

CO in Waste gas to each RTO: 4595.57 lb/hr

Total Sulfur in Waste gas to each RTO: 1.58 lb/hr

Methanol in Waste Gas to each RTO: 78.86 lb/hr

H2S and COS DRE: 98 %

CO and Methanol DRE: 99 %

EMISSIONS: Two Units at Full Rate

lb/hr avg. lb/hr max. TPY 

PM10 0.47 0.47 2.05

SO2 6.22 6.22 27.23

NOx 3.19 3.19 13.99

CO 94.17 94.17 412.46

VOC 1.99 1.99 8.73

H2S (TAP) 1.12 1.12 4.90

COS (HAP)(VOC) 0.08 0.08 0.35

Methanol (HAP)(VOC) 1.58 1.58 6.91

Total HAPs 1.77 1.77 7.76

Mercury (HAP) 1.1E-04 1.1E-04 4.6E-04

EMISSIONS: One Unit at full rate 

lb/hr avg. lb/hr max. TPY 

PM10 0.23 0.23 1.02

SO2 3.11 3.11 13.616

NOx 1.60 1.60 6.99

CO 47.08 47.08 206.23

VOC 2.93 2.93 12.83

H2S (TAP) 0.56 0.56 2.449

COS (HAP)(VOC) 1.97 1.97 8.63

Methanol (HAP)(VOC) 0.79 0.79 3.45

Total HAPs 2.82 2.82 12.34

Mercury (HAP) 5.3E-05 5.3E-05 2.3E-04
EMISSIONS: One Unit at half rate - Conservatively assume Natural Gas (for SO2) and SNG (for Hg) for entire 24 hrs Page 5 of 9 TSD App A

lb/hr avg. lb/hr max. TPY 

PM10 0.12 0.12 0.0014

SO2 1.55 1.55 0.019

NOx 0.80 0.80 0.010

CO 23.54 23.54 0.28

VOC 0.50 0.50 0.0060

H2S (TAP) 0.01 0.01 0.0001

COS (HAP)(VOC) 0.02 0.02 0.00024

Methanol (HAP)(VOC) 0.39 0.39 0.0047

Total HAPs 0.44 0.44 0.0053

Mercury (HAP) 2.6E-05 2.6E-05 3.2E-07

EMISSIONS: Normal Operations Total

lb/hr avg. lb/hr max. TPY 

PM10 0.70 0.47 3.07

SO2 9.33 6.22 40.87

NOx 4.79 3.19 20.99

CO 141.32 94.17 618.97

VOC 4.92 2.93 21.57

H2S (TAP) 1.68 1.12 7.35

COS (HAP)(VOC) 2.05 1.97 8.98

Methanol (HAP)(VOC) 2.37 1.58 10.37

Total HAPs 4.59 2.82 20.11

Mercury (HAP) 1.6E-04 1.1E-04 6.9E-04

Natural Gas Combustion PM10 VOC SO2 HAP

7.60 5.50 0.6 1.89

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10

Natural Gas Combustion NOx CO

0.05 0.036

Factor (lb/MM scf)

Factor (lb/MMBtu)

Natural Gas SNG

Mercury Factor (lb/MMBtu) 1.95E-07 1.68E-06
Page 6 of 9 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 9,711 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.1832 MT

N2O = 0.0183 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 179,564,678 scf

High heat value 

of the fuel from Annual 0.00102 MMBtu per scf

Coal / Coke Case

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

all valid samples 

for the year

Average

0.00102 MMBtu per scf

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 9,711 1 9,711

CH4 0.18 21 4

N2O 0.018 310 6

TOTAL = 9,720 10,712 TPY CO2

Feeds to RTO (CO2 + combusted CO): 1,427,034 lb/hr at full rate per Eng. Design

20% percent of max vented per year.

 1,250,082 tons/yr 

1,134,067 MTCO2e 1,250,082 Subtotal TPY CO2

Total CO2e: 1,143,784 MTCO2e 1,260,793 Total TPY CO2e
Page 7 of 9 TSD App A

Coal Only Case

COMBUSTION DATA

HEAT INPUT: Two Units at full rate 77.62 MM Btu/hr

HEAT INPUT: One Unit at full rate 38.81 MM Btu/hr

HEAT INPUT: Black-starts (1 unit at half rate) 19.41 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS: Two Units at full rate 8760 hr/yr

OPERATING HOURS: One Unit at full rate 8760 hr/yr

OPERATING HOURS: Black-start 24 hr/yr

H2S in Waste gas to each RTO = 0.57 lb/hr

COS in Waste gas to each RTO = 2.00 lb/hr

CO in Waste gas to each RTO: 4673.99 lb/hr

Total Sulfur in Waste gas to each RTO: 1.60 lb/hr

Methanol in Waste Gas to each RTO: 80.20 lb/hr

H2S and COS DRE: 98 %

CO and Methanol DRE: 99 %

EMISSIONS: Two Units at Full Rate (100%)

lb/hr avg. lb/hr max. TPY 

PM10 0.58 0.58 2.53

SO2 6.33 6.33 27.73

NOx 3.95 3.95 17.32

CO 96.27 96.27 421.68

VOC 6.03 6.03 26.42

H2S (TAP) 1.14 1.14 4.98

COS (HAP)(VOC) 4.01 4.01 17.56

Methanol (HAP)(VOC) 1.60 1.60 7.03

Total HAPs 5.76 5.76 25.22

Mercury (HAP) 1.2E-04 1.2E-04 5.5E-04

EMISSIONS: One Unit at full rate 

lb/hr avg. lb/hr max. TPY 

PM10 0.29 0.29 1.27

SO2 3.17 3.17 13.87

NOx 1.98 1.98 8.66

CO 48.14 48.14 210.84

VOC 3.02 3.02 13.21

H2S (TAP) 0.57 0.57 2.491

COS (HAP)(VOC) 2.00 2.00 8.78

Methanol (HAP)(VOC) 0.80 0.80 3.51

Total HAPs 2.88 2.88 12.61

Mercury (HAP) 6.2E-05 6.2E-05 2.7E-04
EMISSIONS: One Unit at half rate (25%) - Conservatively assume Natural Gas (for SO2) and SNG (for Hg) for entire 24 hrs Page 8 of 9 TSD App A

lb/hr avg. lb/hr max. TPY 

PM10 0.14 0.14 0.0017

SO2 1.58 1.58 0.019

NOx 0.99 0.99 0.012

CO 24.07 24.07 0.29

VOC 0.53 0.53 0.0063

H2S (TAP) 0.01 0.01 0.0001

COS (HAP)(VOC) 0.02 0.02 0.0002

Methanol (HAP)(VOC) 0.40 0.40 0.0048

Total HAPs 0.46 0.46 0.0055

Mercury (HAP) 3.1E-05 3.1E-05 3.7E-07

EMISSIONS: Normal Operations Total

lb/hr avg. lb/hr max. TPY 

PM10 0.87 0.58 3.80

SO2 9.50 6.33 41.62

NOx 5.93 3.95 25.99

CO 144.48 96.27 632.81

VOC 9.05 6.03 39.64

H2S (TAP) 1.706 1.14 7.47

COS (HAP)(VOC) 6.01 4.01 26.35

Methanol (HAP)(VOC) 2.41 1.60 10.54

Total HAPs 8.64 5.76 37.83

Mercury (HAP) 1.9E-04 1.2E-04 8.2E-04

Natural Gas Combustion PM10 VOC SO2 HAP

7.60 5.50 0.6 1.89

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10

Natural Gas Combustion NOx CO

0.05 0.036

Factor (lb/MM scf)

Factor (lb/MMBtu)

Natural Gas SNG

Mercury Factor (lb/MMBtu) 1.95E-07 1.61E-06
Page 9 of 9 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 10,976 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.2070 MT

N2O = 0.0207 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 202,961,074 scf

High heat value of

the fuel from all Annual 0.00102 MMBtu per scf

Coal Only Case

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

valid samples for 

the year

Average

0.00102 MMBtu per scf

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 10,976 1 10,976

CH4 0.21 21 4

N2O 0.021 310 6

TOTAL = 10,987 12,108 TPY CO2

Feeds to RTO (CO2 + combusted CO): 1,458,491 lb/hr at full rate per Eng. Design

20% percent of max vented per year.

1,277,638 tons/yr 

1,159,066 MTCO2e 1,277,638 subtotal TPY CO2

Total CO2e: 1,170,050 MTCO2e 1,289,746 Total TPY CO2e

Max CO2e: 1,170,050 MT/yr
COMBUSTION SOURCES Page 1 of 10 TSD App A

NAME Gasifier Start-up Preheat Burner A Unit ID: 008 A

STACK DATA

HEIGHT 150 ft

DIAMETER 4 ft

GAS EXIT TEMP 232 °F

GAS EXIT VELOCITY: Normal Ops 65.00 fps

GAS EXIT VELOCITY: Black Start 126.39 fps

COMBUSTION DATA

HEAT INPUT: Normal Ops 18.00 MM Btu/hr

HEAT INPUT: Black Start 35.00 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS -Normal Case 8760 hr/yr

OPERATING HOURS -Black Starts 28.8 hr/yr

EMISSIONS: Normal Case

lb/hr avg. lb/hr max. TPY 

PM10 0.013 0.013 0.0587

PM2.5 0.002 0.002 0.0073

SO2 0.011 0.011 0.0464

NOx 1.800 1.800 7.88

CO 1.008 1.008 4.42

VOC 0.097 0.097 0.43

Total VOC HAPs 0.033 0.033 0.15

Mercury (HAP) 3.0E-05 3.0E-05 1.3E-04

EMISSIONS: Black Starts

lb/hr avg. lb/hr max. TPY 

PM10 0.026 0.026 0.00038

PM2.5 0.024 0.024 0.00035

SO2 0.021 0.021 0.00030

NOx 3.500 3.500 0.05

CO 1.960 1.960 0.0282

VOC 0.189 0.189 0.00272

Total VOC HAPs 0.065 0.065 0.00093

Mercury (HAP) 6.8E-06 6.8E-06 9.8E-08

CALCULATIONS

Emissions (SO2) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (PM10, NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu/hr) x Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

Natural Gas Combustion SO2

0.6

Natural Gas Combustion PM10 NOx CO VOC

0.0007 0.100 0.056 0.005

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

Natural gas or SNG may be combusted. Conservatively assumed natural gas for SO2 calculation (as SNG contains no sulfur).

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

Factor (lb/MM Btu)

Source: Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

Factor (lb/MM scf)

Mercury Factor (lb/MMBtu)
Page 2 of 10 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 8,414 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.1587 MT

N2O = 0.0159 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 155,576,471 scf

High heat value 

of the fuel from all

valid samples for 

the year

Annual 

Average 0.00102 MMBtu per scf

GHG Pollutant GHG GWP Factors Metric Tons CO2e

Gasifier Start-up 

Preheat Burner A

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

GHG Pollutant Metric Tons GWP Factors Metric Tons CO2e

CO2 8,414 1 8,414

CH4 0.2 21 3

N2O 0.0 310 5

TOTAL = 8,422 9,281 TPY CO2
COMBUSTION SOURCES Page 3 of 10 TSD App A

NAME Gasifier Start-up Preheat Burner B Unit ID: 008 B

STACK DATA

HEIGHT 150 ft

DIAMETER 4 ft

GAS EXIT TEMP 232 °F

GAS EXIT VELOCITY: Normal Ops 65.00 fps

GAS EXIT VELOCITY: Black Start 126.39 fps

COMBUSTION DATA

HEAT INPUT: Normal Ops 18.00 MM Btu/hr

HEAT INPUT: Black Start 35.00 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS -Normal Case 8760 hr/yr

OPERATING HOURS -Black Starts 28.8 hr/yr

EMISSIONS: Normal Case

lb/hr avg. lb/hr max. TPY 

PM10 0.013 0.013 0.0587

PM2.5 0.002 0.002 0.0073

SO2 0.011 0.011 0.0464

NOx 1.800 1.800 7.88

CO 1.008 1.008 4.42

VOC 0.097 0.097 0.43

Total VOC HAPs 0.033 0.033 0.15

Mercury (HAP) 3.0E-05 3.0E-05 1.3E-04

EMISSIONS: Black Starts

lb/hr avg. lb/hr max. TPY 

PM10 0.026 0.026 0.00038

PM2.5 0.024 0.024 0.00035

SO2 0.021 0.021 0.00030

NOx 3.500 3.500 0.05

CO 1.960 1.960 0.0282

VOC 0.189 0.189 0.00272

Total VOC HAPs 0.065 0.065 0.00093

Mercury (HAP) 6.8E-06 6.8E-06 9.8E-08

CALCULATIONS

Emissions (SO2) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (PM10, NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu/hr) x Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

Natural Gas Combustion SO2

0.6

Natural Gas Combustion PM10 NOx CO VOC

0.0007 0.100 0.056 0.005

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

Natural gas or SNG may be combusted. Conservatively assumed natural gas for SO2 calculation (as SNG contains no sulfur).

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

Factor (lb/MM Btu)

Source: Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

Factor (lb/MM scf)

Mercury Factor (lb/MMBtu)
Page 4 of 10 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 8,414 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.1587 MT

N2O = 0.0159 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 155,576,471 scf

High heat value of

the fuel from all 

valid samples for 

the year

Annual 

Average 0.00102 MMBtu per scf

GHG M ti T 

Gasifier Start-up 

Preheat Burner B

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

GHG Pollutant GHG

Metric Tons GWP Factors Metric TonsCO2e

CO2 8,414 1 8,414

CH4 0.2 21 3

N2O 0.0 310 5

TOTAL = 8,422 9,281 TPY CO2
COMBUSTION SOURCES Page 5 of 10 TSD App A

NAME Gasifier Start-up Preheat Burner C Unit ID: 008 C

STACK DATA

HEIGHT 150 ft

DIAMETER 4 ft

GAS EXIT TEMP 232 °F

GAS EXIT VELOCITY: Normal Ops 65.00 fps

GAS EXIT VELOCITY: Black Start 126.39 fps

COMBUSTION DATA

HEAT INPUT: Normal Ops 18.00 MM Btu/hr

HEAT INPUT: Black Start 35.00 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS -Normal Case 8760 hr/yr

OPERATING HOURS -Black Starts 28.8 hr/yr

EMISSIONS: Normal Case

lb/hr avg. lb/hr max. TPY 

PM10 0.013 0.013 0.0587

PM2.5 0.002 0.002 0.0073

SO2 0.011 0.011 0.0464

NOx 1.800 1.800 7.88

CO 1.008 1.008 4.42

VOC 0.097 0.097 0.43

Total VOC HAPs 0.033 0.033 0.15

Mercury (HAP) 3.0E-05 3.0E-05 1.3E-04

EMISSIONS: Black Starts

lb/hr avg. lb/hr max. TPY 

PM10 0.026 0.026 0.00038

PM2.5 0.024 0.024 0.00035

SO2 0.021 0.021 0.00030

NOx 3.500 3.500 0.05

CO 1.960 1.960 0.0282

VOC 0.189 0.189 0.00272

Total VOC HAPs 0.065 0.065 0.00093

Mercury (HAP) 6.8E-06 6.8E-06 9.8E-08

CALCULATIONS

Emissions (SO2) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (PM10, NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu/hr) x Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

Natural Gas Combustion SO2

0.6

Natural Gas Combustion PM10 NOx CO VOC

0.0007 0.100 0.056 0.005

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

Natural gas or SNG may be combusted. Conservatively assumed natural gas for SO2 calculation (as SNG contains no sulfur).

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

Factor (lb/MM Btu)

Source: Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

Factor (lb/MM scf)

Mercury Factor (lb/MMBtu)
Page 6 of 10 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 8,414 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.1587 MT

N2O = 0.0159 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 155,576,471 scf

High heat value of

the fuel from all 

valid samples for 

the year

Annual 

Average 0.00102 MMBtu per scf

Gasifier Start-up 

Preheat Burner C

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons 

CO2e

CO2 8,414 1 8,414

CH4 0.2 21 3

N2O 0.0 310 5

TOTAL = 8,422 9,281 TPY CO2
COMBUSTION SOURCES Page 7 of 10 TSD App A

NAME Gasifier Start-up Preheat Burner D Unit ID: 008 D

STACK DATA

HEIGHT 150 ft

DIAMETER 4 ft

GAS EXIT TEMP 232 °F

GAS EXIT VELOCITY: Normal Ops 65.00 fps

GAS EXIT VELOCITY: Black Start 126.39 fps

COMBUSTION DATA

HEAT INPUT: Normal Ops 18.00 MM Btu/hr

HEAT INPUT: Black Start 35.00 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS -Normal Case 8760 hr/yr

OPERATING HOURS -Black Starts 28.8 hr/yr

EMISSIONS: Normal Case

lb/hr avg. lb/hr max. TPY 

PM10 0.013 0.013 0.0587

PM2.5 0.002 0.002 0.0073

SO2 0.011 0.011 0.0464

NOx 1.800 1.800 7.88

CO 1.008 1.008 4.42

VOC 0.097 0.097 0.43

Total VOC HAPs 0.033 0.033 0.15

Mercury (HAP) 3.0E-05 3.0E-05 1.3E-04

EMISSIONS: Black Starts

lb/hr avg. lb/hr max. TPY 

PM10 0.026 0.026 0.00038

PM2.5 0.024 0.024 0.00035

SO2 0.021 0.021 0.00030

NOx 3.500 3.500 0.05

CO 1.960 1.960 0.0282

VOC 0.189 0.189 0.00272

Total VOC HAPs 0.065 0.065 0.00093

Mercury (HAP) 6.8E-06 6.8E-06 9.8E-08

CALCULATIONS

Emissions (SO2) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (PM10, NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu/hr) x Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

Natural Gas Combustion SO2

0.6

Natural Gas Combustion PM10 NOx CO VOC

0.0007 0.100 0.056 0.005

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

Natural gas or SNG may be combusted. Conservatively assumed natural gas for SO2 calculation (as SNG contains no sulfur).

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

Factor (lb/MM Btu)

Source: Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

Factor (lb/MM scf)

Mercury Factor (lb/MMBtu)
Page 8 of 10 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 8,414 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.1587 MT

N2O = 0.0159 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 155,576,471 scf

High heat value of

the fuel from all 

valid samples for 

the year

Annual 

Average 0.00102 MMBtu per scf

GHG M i T 

Gasifier Start-up 

Preheat Burner D

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons 

CO2e

CO2 8,414 1 8,414

CH4 0.2 21 3

N2O 0.0 310 5

TOTAL = 8,422 9,281 TPY CO2
COMBUSTION SOURCES Page 9 of 10 TSD App A

NAME Gasifier Start-up Preheat Burner E Unit ID: 008 E

STACK DATA

HEIGHT 150 ft

DIAMETER 4 ft

GAS EXIT TEMP 232 °F

GAS EXIT VELOCITY: Normal Ops 65.00 fps

GAS EXIT VELOCITY: Black Start 126.39 fps

COMBUSTION DATA

HEAT INPUT: Normal Ops 18.00 MM Btu/hr

HEAT INPUT: Black Start 35.00 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS -Normal Case 8760 hr/yr

OPERATING HOURS -Black Starts 28.8 hr/yr

EMISSIONS: Normal Case

lb/hr avg. lb/hr max. TPY 

PM10 0.013 0.013 0.0587

PM2.5 0.002 0.002 0.0073

SO2 0.011 0.011 0.0464

NOx 1.800 1.800 7.88

CO 1.008 1.008 4.42

VOC 0.097 0.097 0.43

Total VOC HAPs 0.033 0.033 0.15

Mercury (HAP) 3.0E-05 3.0E-05 1.3E-04

EMISSIONS: Black Starts

lb/hr avg. lb/hr max. TPY 

PM10 0.026 0.026 0.00038

PM2.5 0.024 0.024 0.00035

SO2 0.021 0.021 0.00030

NOx 3.500 3.500 0.05

CO 1.960 1.960 0.0282

VOC 0.189 0.189 0.00272

Total VOC HAPs 0.065 0.065 0.00093

Mercury (HAP) 6.8E-06 6.8E-06 9.8E-08

CALCULATIONS

Emissions (SO2) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (PM10, NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu/hr) x Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

Natural Gas Combustion SO2

0.6

Natural Gas Combustion PM10 NOx CO VOC

0.0007 0.100 0.056 0.005

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

Natural gas or SNG may be combusted. Conservatively assumed natural gas for SO2 calculation (as SNG contains no sulfur).

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

Factor (lb/MM Btu)

Source: Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

Factor (lb/MM scf)

Mercury Factor (lb/MMBtu)
Page 10 of 10 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 8,414 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.1587 MT

N2O = 0.0159 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 155,576,471 scf

High heat value of

the fuel from all 

valid samples for 

the year

Annual 

Average 0.00102 MMBtu per scf

GHG Metric Tons 

Gasifier Start-up 

Preheat Burner E

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 8,414 1 8,414

CH4 0.2 21 3

N2O 0.0 310 5

TOTAL = 8,422 9,281 TPY CO2
COMBUSTION SOURCES Page 1 of 4 TSD App A

NAME Emergency Diesel Power Generator A Unit ID: 009 A

COMBUSTION DATA

FUEL TYPE Diesel

ENGINE SIZE 1,341 HP

HOURS OF OPERATION 500 hr/yr

EMISSIONS avg lb/hr lb/hr max. TPY

PM10 0.06 0.06 0.0148

PM2.5 0.01 0.01 0.0014

SO2 0.015 0.015 0.00377

NOX 14.58 14.58 3.64

CO 0.38 0.38 0.096

VOC (TOC) 0.03 0.03 0.00739

CALCULATIONS:

Emissions (LB/HR) = Vendor Factor X HP

Emissions (TPY) = Emissions (LB/HR) X (Hours of operation/2000)

PM10 SO2 NOX CO VOC

4.4E-05 1.1E-05 0.0109 2.9E-04 2.2E-05

COMMENTS

ASSUMED MAXIMUM HOURLY EMISSIONS EQUAL TO AVERAGE HOURLY EMISSIONS.

HAPs emission from this limited use source assumed to be negligable

Diesel Industrial Engine Factors 

(Lb/hp-hr)

Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

SO2 emissions based on 15 ppm S in diesel and 100% conversion to SO2.

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).
Page 2 of 4 TSD App A

Stationary Combustion Sources - Diesel

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume) 0.138

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 73.96

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 212.3 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.003

0.0006

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.00861 MT

N2O = 0.001722 MT

Emission Points Data Required

MRR

Frequency Data Units

Gallons of diesel 

fuel combusted Annual 20,800 Gallons

High heat value 

of the fuel from 

all valid samples 

for the year

Annual 

Average 0.13800 MMBtu per gal

Emergency 

Diesel Power 

Generator A

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

for the year

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 212.3 1 212.3

CH4 0.00861 21 0.1808

N2O 0.001722 310 0.534

TOTAL = 213.0 234.7 TPY CO2

Fuel Consumption 50% load = 20.8 gal/hr.

Assumed Fuel at 100% Load = 41.6 gal/hr.
COMBUSTION SOURCES Page 3 of 4 TSD App A

NAME Emergency Diesel Power Generator B Unit ID: 009 B

COMBUSTION DATA

FUEL TYPE Diesel

ENGINE SIZE 1,341 HP

HOURS OF OPERATION 500 hr/yr

EMISSIONS avg lb/hr lb/hr max. TPY

PM10 0.06 0.06 0.0148

PM2.5 0.01 0.01 0.0014

SO2 0.015 0.015 0.00377

NOX 14.58 14.58 3.64

CO 0.38 0.38 0.096

VOC (TOC) 0.03 0.03 0.00739

CALCULATIONS:

Emissions (LB/HR) = Vendor Factor X HP

Emissions (TPY) = Emissions (LB/HR) X (Hours of operation/2000)

PM10 SO2 NOX CO VOC

4.4E-05 1.1E-05 0.0109 2.9E-04 2.2E-05

COMMENTS

ASSUMED MAXIMUM HOURLY EMISSIONS EQUAL TO AVERAGE HOURLY EMISSIONS.

HAPs emission from this limited use source assumed to be negligable

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Diesel Industrial Engine Factors 

(Lb/hp-hr)

Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

SO2 emissions based on 15 ppm S in diesel and 100% conversion to SO2.
Page 4 of 4 TSD App A

Stationary Combustion Sources - Diesel

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume) 0.138

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 73.96

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 106.1 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.003

0.0006

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.00431 MT

N2O = 0.000861 MT

Emission Points Data Required

MRR

Frequency Data Units

Gallons of diesel 

fuel combusted Annual 10,400 Gallons

High heat value 

of the fuel from 

all valid samples 

for the year

Annual 

Average 0.13800 MMBtu per gal

Emergency 

Diesel Power 

Generator B

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

for the year

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 106.1 1 106.1

CH4 0.00431 21 0.0904

N2O 0.000861 310 0.267

TOTAL = 106.5 117.4 TPY CO2

Fuel Consumption 50% load = 20.8 gal/hr.

Assumed Fuel at 100% Load = 41.6 gal/hr.
COMBUSTION SOURCES Page 1 of 6 TSD App A

NAME Fire Water Diesel Pump A Unit ID: 010 A

COMBUSTION DATA

FUEL TYPE Diesel

ENGINE SIZE 575 HP

HOURS OF OPERATION 500 hr/yr

EMISSIONS avg lb/hr lb/hr max. TPY

PM10 0.108 0.108 0.0269

PM2.5 0.011 0.011 0.0026

SO2 0.0061 0.0061 0.00152

NOX 3.131 3.131 0.783

CO 0.799 0.799 0.200

VOC 0.218 0.218 0.0545

CALCULATIONS:

Emissions (LB/HR) = Vendor Factor X HP

Emissions (TPY) = Emissions (LB/HR) X (Hours of operation/2000)

PM10 SO2 NOX CO VOC 

1.9E-04 1.1E-05 0.0054 1.4E-03 3.8E-04

COMMENTS

ASSUMED MAXIMUM HOURLY EMISSIONS EQUAL TO AVERAGE HOURLY EMISSIONS.

HAPs emission from this limited use source assumed to be negligable

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Diesel Industrial Engine Factors 

(Lb/hp-hr)

Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

SO2 emissions based on 15 ppm S in diesel and 100% conversion to SO2.
Page 2 of 6 TSD App A

Stationary Combustion Sources - Diesel

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume) 0.138

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 73.96

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 101 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.003

0.0006

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0041 MT

N2O = 0.00082 MT

Emission Points Data Required

MRR

Frequency Data Units

Gallons of diesel 

fuel combusted Annual 9,875 Gallons

High heat value 

of the fuel from all 

valid samples for 

the year

Annual 

Average 0.13800 MMBtu per gal

Fire Water Diesel 

Pump A

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

the year

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 100.8 1 100.8

CH4 0.00409 21 0.0859

N2O 0.000818 310 0.253

TOTAL = 101.1 111.4 TPY CO2

Fuel Consumption 40% load = 7.9 gal/hr.

Assumed Fuel at 100% Load = 19.75 gal/hr.
COMBUSTION SOURCES Page 3 of 6 TSD App A

NAME Fire Water Diesel Pump B Unit ID: 010 B

COMBUSTION DATA

FUEL TYPE Diesel

ENGINE SIZE 575 HP

HOURS OF OPERATION 500 hr/yr

EMISSIONS avg lb/hr lb/hr max. TPY

PM10 0.108 0.108 0.0269

PM2.5 0.011 0.011 0.0026

SO2 0.0061 0.0061 0.00152

NOX 3.131 3.131 0.783

CO 0.799 0.799 0.200

VOC 0.218 0.218 0.0545

CALCULATIONS:

Emissions (LB/HR) = Vendor Factor X HP

Emissions (TPY) = Emissions (LB/HR) X (Hours of operation/2000)

PM10 SO2 NOX CO VOC 

1.9E-04 1.1E-05 0.0054 1.4E-03 3.8E-04

COMMENTS

ASSUMED MAXIMUM HOURLY EMISSIONS EQUAL TO AVERAGE HOURLY EMISSIONS.

HAPs emission from this limited use source assumed to be negligable

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Diesel Industrial Engine Factors 

(Lb/hp-hr)

Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

SO2 emissions based on 15 ppm S in diesel and 100% conversion to SO2.
Page 4 of 6 TSD App A

Stationary Combustion Sources - Diesel

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume) 0.138

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 73.96

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 40 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.003

0.0006

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0016 MT

N2O = 0.00033 MT

Emission Points Data Required

MRR

Frequency Data Units

Gallons of diesel 

fuel combusted Annual 3,950 Gallons

High heat value 

of the fuel from all 

valid samples for 

the year

Annual 

Average 0.13800 MMBtu per gal

Fire Water Diesel 

Pump B

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

the year

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 40.3 1 40.3

CH4 0.00164 21 0.0343

N2O 0.000327 310 0.101

TOTAL = 40.5 44.6 TPY CO2

Fuel Consumption 40% load = 7.9 gal/hr.

Assumed Fuel at 100% Load = 19.75 gal/hr.
COMBUSTION SOURCES Page 5 of 6 TSD App A

NAME Fire Water Diesel Pump C Unit ID: 010 C

COMBUSTION DATA

FUEL TYPE Diesel

ENGINE SIZE 575 HP

HOURS OF OPERATION 500 hr/yr

EMISSIONS avg lb/hr lb/hr max. TPY

PM10 0.108 0.108 0.0269

PM2.5 0.011 0.011 0.0026

SO2 0.0061 0.0061 0.00152

NOX 3.131 3.131 0.783

CO 0.799 0.799 0.200

VOC 0.218 0.218 0.0545

CALCULATIONS:

Emissions (LB/HR) = Vendor Factor X HP

Emissions (TPY) = Emissions (LB/HR) X (Hours of operation/2000)

PM10 SO2 NOX CO VOC 

1.9E-04 1.1E-05 0.0054 1.4E-03 3.8E-04

COMMENTS

ASSUMED MAXIMUM HOURLY EMISSIONS EQUAL TO AVERAGE HOURLY EMISSIONS.

HAPs emission from this limited use source assumed to be negligable

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Diesel Industrial Engine Factors 

(Lb/hp-hr)

Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

SO2 emissions based on 15 ppm S in diesel and 100% conversion to SO2.
Page 6 of 6 TSD App A

Stationary Combustion Sources - Diesel

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume) 0.138

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 73.96

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 40 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.003

0.0006

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0016 MT

N2O = 0.00033 MT

Emission Points Data Required

MRR

Frequency Data Units

Gallons of diesel 

fuel combusted Annual 3,950 Gallons

High heat value 

of the fuel from all 

valid samples for 

the year

Annual 

Average 0.13800 MMBtu per gal

Fire Water Diesel 

Pump C

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

the year

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 40.3 1 40.3

CH4 0.00164 21 0.0343

N2O 0.000327 310 0.101

TOTAL = 40.5 44.6 TPY CO2

Fuel Consumption 40% load = 7.9 gal/hr.

Assumed Fuel at 100% Load = 19.75 gal/hr.
Page 1 of 3 TSD App A

Explanation of PTE Calculation for Material Handling Sources.

The spreadsheets in this workbook present "Uncontrolled" emissions calculations for the 

feedstock material handling sources (EU-011 and EU-012) of the Indiana Gasification 

Facility. 

Most of these sources are controlled by add-on control devices (fabric filters or wet dust 

extraction systems). "Controlled" emissions for such sources were separately calculated 

based on vendor guaranteed control device exit grain loading (gr/acf). However, realistic 

"uncontrolled emissions" cannot be back-calculated by "undoing" an estimated control 

efficiency for those devices. Instead, uncontrolled maximum emissions have been 

calculated in this spreadsheet using AP42 aggregate handling equations from Chapter 

13.2.4 - which is the standard methodology for such operations if they were not enclosed 

and controlled. 

Uncontrolled maximum PTE for open sources such as dozer activity and wind erosion 

which are controlled by wet suppression, are estimated using the uncontrolled lb/hr 

emissions rate factor presented in the 4/20/11 air permit application Appendix B, pages 

D2&3, not taking credit for any controls, and assuming 8760 hrs/yr. 

Based on the calculations provided, the provisions of 40 CFR Part 64 for Compliance

Assurance Monitoring do not apply to these emission units.
Page 2 of 3 TSD App A

PM10 Total PM

Annual PM10 Factor Annual 

Emissions PM Total/ Emissions

Unit ID Name TPY PM10 TPY

012 A Barge Unload to Hopper 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 B Barge Unload Hopper to Belt 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 C Barge Conveyor Transfer Drop 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 D Barge Conveyor Transfer Drop 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 E Barge Conveyor Transfer Drop 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 F Barge Conveyor Transfer Drop 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 G Rail Unload 1 to Hopper 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 H Rail Unload 2 to Hopper 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 I Rail Unload Hopper 1 to Belt 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 J Rail Unload Hopper 2 to Belt 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 K Rail Unload Belts 1 & 2 to Stacker Belt 1 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 L Stacker Belt 1 to Radial Stacker (Pile1 ) 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 M Stacker Belt 2 from Radial Stacker (Pile 1) 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 N Radial Stacker to Pile 1 3,000 TPH 0.00056 lb/ton 8,760 7.32 2.114 15.48

012 O Radial Stacker to Pile 2 3,000 TPH 0.00056 lb/ton 8,760 7.32 2.114 15.48

012 P Dozer Activity on Pile 1 1,500 TPH 0.798 lb/hr 8,760 3.50 4.58 16.01

012 Q Dozer Activity on Pile 2 1,500 TPH 0.798 lb/hr 8,760 3.50 4.58 16.01

012 R Pile 1 / Bottom Hopper / Belt / Classification 

Tower (assume 3 transfers) 750 TPH 0.00167 lb/ton 8,760 5.49

2.114

11.61

012 S Pile 1 / Bottom Hopper / Belt / Classification 

Tower (assume 3 transfers) 750 TPH 0.00167 lb/ton 8,760 5.49

2.114

11.61

012 T CLASSIFICATION TOWER #1 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 U CLASSIFICATION TOWER #2 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 V Classification Towers to Day Bin 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 W Wind Erosion Pile 1 300,000 Tons 2.157 lb/hr 8,760 9.45 2.0 18.90

012 X Wind Erosion Pile 2 300,000 Tons 1.794 lb/hr 8,760 7.86 2.0 15.72

012 Y Transfer tower from Truck/Rail conveyor to 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 Z Truck Bay 1 dump to Hopper 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 AA Truck hopper to conveyor 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 AB Truck Bay 2 dump to Hopper 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

012 AC Truck Bay 3 dump to Hopper 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87

011 A/B Process Area Coal-Coke Handling System 

(assume 3 transfers) 750 TPH 0.002 lb/ton 8,760 5.49 1.0 5.49

UNCONTROLLED PTE OF FEEDSTOCK HANDLING SOURCES

Total PM/PM10 EMISSIONS Uncontrolled Annual Ave Process 

Rate

Uncontrolled Emission 

Factor

Operating 

Hours
Comments:

Dozer activity (012 P and 012 Q) factors calculated based on equations from AP-42 Section 13.2.2

All others based on Transfer point factors calculated based on equations from AP-42 Section 13.2.4

Coke / Coal pile (012 W and 012 X) wind erosion factors calculated based on equations from WRAP document

Page 3 of 3 TSD App A

Annual

Emissions

Unit ID Name TPY

012 A Barge Unload to Hopper 750 TPH 0.00008 lb/ton 8,760 0.28

012 B Barge Unload Hopper to Belt 750 TPH 0.00008 lb/ton 8,760 0.28

012 C Barge Conveyor Transfer Drop 750 TPH 0.00008 lb/ton 8,760 0.28

012 D Barge Conveyor Transfer Drop 750 TPH 0.00008 lb/ton 8,760 0.28

012 E Barge Conveyor Transfer Drop 750 TPH 0.00008 lb/ton 8,760 0.28

012 F Barge Conveyor Transfer Drop 750 TPH 0.00008 lb/ton 8,760 0.28

012 G Rail Unload 1 to Hopper 750 TPH 0.00008 lb/ton 8,760 0.28

012 H Rail Unload 2 to Hopper 750 TPH 0.00008 lb/ton 8,760 0.28

012 I Rail Unload Hopper 1 to Belt 750 TPH 0.00008 lb/ton 8,760 0.28

012 J Rail Unload Hopper 2 to Belt 750 TPH 0.00008 lb/ton 8,760 0.28

012 K Rail Unload Belts 1 & 2 to Stacker Belt 1 750 TPH 0.00008 lb/ton 8,760 0.28

012 L Stacker Belt 1 to Radial Stacker (Pile1 ) 750 TPH 0.00008 lb/ton 8,760 0.28

012 M Stacker Belt 2 from Radial Stacker (Pile 1) 750 TPH 0.00008 lb/ton 8,760 0.28

012 N Radial Stacker to Pile 1 3,000 TPH 0.00008 lb/ton 8,760 1.11

012 O Radial Stacker to Pile 2 3,000 TPH 0.00008 lb/ton 8,760 1.11

012 P Dozer Activity on Pile 1 1,500 TPH 0.080 lb/hr 8,760 0.35

012 Q Dozer Activity on Pile 2 1,500 TPH 0.080 lb/hr 8,760 0.35

012 R Pile 1 / Bottom Hopper / Belt / Classification 

Tower (assume 3 transfers) 750 TPH 0.00025 lb/ton 8,760 0.83

012 S Pile 1 / Bottom Hopper / Belt / Classification 

Tower (assume 3 transfers) 750 TPH 0.00025 lb/ton 8,760 0.83

012 T CLASSIFICATION TOWER #1 750 TPH 0.00008 lb/ton 8,760 0.28

012 U CLASSIFICATION TOWER #2 750 TPH 0.00008 lb/ton 8,760 0.28

012 V Classification Towers to Day Bin 750 TPH 0.00008 lb/ton 8,760 0.28

012 W Wind Erosion Pile 1 300,000 tons 0.229 lb/hr 8,760 1.00

012 X Wind Erosion Pile 2 300,000 Tons 0.190 lb/hr 8,760 0.83

012 Y Transfer tower from Truck/Rail conveyor to 750 TPH 0.00008 lb/ton 8,760 0.28

012 Z Truck Bay 1 dump to Hopper 750 TPH 0.00008 lb/ton 8,760 0.28

012 AA Truck hopper to conveyor 750 TPH 0.00008 lb/ton 8,760 0.28

012 AB Truck Bay 2 dump to Hopper 750 TPH 0.00008 lb/ton 8,760 0.28

012 AC Truck Bay 3 dump to Hopper 750 TPH 0.00008 lb/ton 8,760 0.28

011 A/B Process Area Coal-Coke Handling System 

(conservatively assume 7 transfers steps) 750 TPH 0.00059 lb/ton 8,760 1.94

Comments:

Dozer activity (012 P and 012 Q) factors calculated based on equations from AP-42 Section 13.2.2

All others based on Transfer point factors calculated based on equations from AP-42 Section 13.2.4

Coke / Coal pile (012 W and 012 X) wind erosion factors calculated based on equations from WRAP document

PM2.5 EMISSIONS Uncontrolled Annual Ave Process 

Rate

Uncontrolled Emission 

Factor

Operating 

Hours
Page 1 of 2 TSD App A

Emission Unit Emission Description

Each Material Handling Step Handling (Drop) emissions for handling/loading - if done so without controls

Calculation Methodology

Calculation of Potential Emissions:

Number of Drops(handling steps) 1.000 drops

Mean wind speed 7.0 mph

Material Moisture content 4.50 %

CALCULATION SHEET

Max. Annual 

Feedstock Usage: 10,401.0 tons/day a

AP-42 Chapter 13, Section 2.4:Aggregate Handling and Storage Piles

Uncontrolled Emissions per handling step calculated using equation (1)

Where:

E = emissions factor in lbs emissions per ton aggregate handled

U = mean wind speed, mph 

M = material moisture content 

k = particle size multplier (dimensionless)

Total PM k=0.74

PM10 k=0.35

PM2.5 k=0.053

 

1.3

1.4

5 0.0032

2

U

E k

M

      

     

 

1.3

1.4

5 0.0032

2

U

E k

M

      

     

Particle Size Multiplier, k: 0.35 PM10 Nominal Capacity 750 tons/hr 

Particle Size Multiplier, k: 0.053 PM2.5 Hours per yr of activity 8760.0 hr/yr

Particle Size Multiplier, k: 0.74 Total PM

Potential PM10 Emissions:

EF lb/ton tpy

Each Material Handling Step 0.00056 1.8309

Potential PM2.5 Emisions:

EF lb/ton tpy

Each Material Handling Step 0.00008 0.2773

Potential Total PM Emisions:

EF lb/ton tpy total PM/PM10 ratio

Each Material Handling Step 0.00118 3.8710 2.11429

Control Efficiency Not included in this pre-control 

PTE calc.

g

 

1.3

1.4

5 0.0032

2

U

E k

M

      

     

 

1.3

1.4

5 0.0032

2

U

E k

M

      

     
Page 2 of 2 TSD App A

Uncontrolled Emissions Factors for open material handling sources

Total PM PM10 PM2.5

Dozer Activity (each pile) lb/hr 3.65484 0.798 0.08

Wind Erosion Pile 1 lb/hr 4.314 2.157 0.229

Wind Erosion Pile 2 lb/hr 3.588 1.794 0.19

Factor for total PM is based on PM10 factor times 2.114 for dozer, and 2.0 for wind 

erosion. These factors based on ratio of particle size multipler factors from AP42 

13.2.2 for the dozer and the WRAP document for Wind Erosion.

Above factors for PM10 and PM2.5 from page D2 and D3 of Appendix B of air permit 

application submitted 4/20/11.
Page 1 of 1 TSD App A

NAME Rod Mill Air Eductors

STACK DATA

HEIGHT 125 ft

DIAMETER 0.5 ft

GAS EXIT TEMP 80 °F

GAS EXIT VELOCITY 15.46 fps

OPERATING HOURS 8,760 hr/yr

PM10 EMISSIONS Average Maximum Annual PM10 Annual PM2.5

Emissions Hourly Emissions Emissions

Unit ID lb/hr lb/hr TPY TPY

013 A 0.025 0.025 0.11 0.032

013 C 0.025 0.025 0.11 0.032

013 C 0.025 0.025 0.11 0.032

013 D 0.025 0.025 0.11 0.032

Total 0.10 0.10 0.44 0.13

Emissions based on engineered equipment data

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

VENT SOURCES

16_30464 Calcs D 45 5/3/2012
VENT SOURCES Page 1 of 9 TSD App A

NAME Wet Sulfuric Acid (WSA) Unit Stack A Unit ID: 015 A

Emissions of all pollutants are higher for the Coal / Coke Case.

STACK DATA

HEIGHT 200 ft

DIAMETER 4.83 ft

GAS EXIT TEMP 176 °F

GAS EXIT VELOCITY: Two Unit Operation 102.2 fps

GAS EXIT VELOCITY: One Unit Operation 51.1 fps

GAS EXIT VELOCITY: Black start 25.5 fps

GAS EXIT VELOCITY: Preheat 115.3 fps

COMBUSTION DATA

HEAT INPUT - Preheat 35.00 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1,020 Btu/ft3

OPERATING HOURS: Two Unit Operation 8,760 hr/yr

OPERATING HOURS: One Unit Operation 0 hr/yr

OPERATING HOURS: Black-start 24 hr/yr

OPERATING HOURS: Preheat 60 hr/yr

EMISSIONS: Full Rate

lb/hr avg. lb/hr max. TPY 

SO2 8.30 8.30 36.35

NOx 10.17 10.17 44.55

CO 18.72 18.72 82.01

H2SO4 5.00 5.00 21.88

Mercury (HAP) 3.3E-10 3.3E-10 1.5E-09

EMISSIONS: Full Rate for 219 hr/yr OR Half Rate for 438 hr/yr

lb/hr avg. lb/hr max. TPY 

SO2 4.15 4.15 0.00

NOx 5.09 5.09 0.00

CO 9.36 9.36 0.00

H2SO4 2.50 2.50 0.00

Mercury (HAP) 3 3E 10 3.3E-10 3 3E 10 3.3E-10 0 0E+00 0.0E+00

EMISSIONS: Half Rate (including Black Start)

lb/hr avg. lb/hr max. TPY 

SO2 2.08 2.08 0.02

NOx 2.54 2.54 0.03

CO 4.68 4.68 0.06

H2SO4 1.25 1.25 0.01

Mercury (HAP) 3.3E-10 3.3E-10 4.0E-12

EMISSIONS: Preheat

lb/hr avg. lb/hr max. TPY 

PM10 0.03 0.03 0.0008

PM2.5 0.02 0.02 0.0006

SO2 0.02 0.02 0.0006

NOx 3.85 3.85 0.12

CO 1.96 1.96 0.059

VOC 0.19 0.19 0.006

Total VOC HAPs 0.06 0.06 0.0019

Mercury (HAP) 5.9E-05 5.9E-05 1.8E-06
EMISSIONS: Normal Operations Total Page 2 of 9 TSD App A

lb/hr avg. lb/hr max. TPY 

PM10 0.00018 0.03 0.0008

PM2.5 0.00015 0.02 0.0006

SO2 8.31 8.30 36.38

NOx 10.21 10.17 44.70

CO 18.75 18.72 82.13

VOC 0.0013 0.19 0.006

Total VOC HAPs 0.0004 0.06 0.0019

Mercury (HAP) 4.0E-07 6.5E-02 1.8E-06

H2SO4 5.00 5.00 21.90

PM2.5 including H2SO4 5.00 5.00 21.90

CALCULATIONS

Emissions Preheat Case: (NOx, CO) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

PM10 VOC SO2

7.600 5.50 0.60

NOx CO

0.110 0.056

Comments:

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10. 

Emissions Preheat Case: (PM10, VOC, and SO2)(Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3) X Heat Input (MMBtu/hr)

Preheat Case: Natural Gas 

Combustion

Factor (lb/MMscf)

SO2 emissions for preheat case based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 

scf (<5 ppmv of H2S). 

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis 

Group).

Total HAPs are based on AP-42 Section 1 4 Tables 1 4-3 and 1 4-4

Preheat Case: Natural 

Gas Combustion

Factor (lb/MMBtu)

Source: Emission factors for NOx and CO are based on information from vendor supplied data.

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

The emission rate data from the WSA Trains is based on information from process licensee.

Total WSA capacity for two trains is 136,658 lb/h of 97.5 wt% Sulfuric Acid production OR 1,599 stpd on dry basis (100% acid).

Burner flue gas is scrubbed in gasifier quench water to remove over 90% of particulate.
Page 3 of 9 TSD App A

This page left blank Intentionally.
Page 4 of 9 TSD App A

Coal / Coke Case

35.00 MM Btu/hr

1,020 Btu/ft3

Full Rate 8,760 hr/yr

Half Rate 0 hr/yr

Black Start 24 hr/yr

Preheat 60 hr/yr

EMISSIONS: Full Rate

lb/hr avg. lb/hr max. TPY 

SO2 8.30 8.30 36.35

NOx 10.17 10.17 44.55

CO 18.72 18.72 82.01

H2SO4 5.00 5.00 21.88

Mercury (HAP) 3.3E-10 3.3E-10 1.4E-09

EMISSIONS: Full Rate for 219 hr/yr OR Half Rate for 438 hr/yr

lb/hr avg. lb/hr max. TPY 

SO2 4.15 4.15 0.00

NOx 5.09 5.09 0.00

CO 9.36 9.36 0.00

H2SO4 2.50 2.50 0.00

Mercury (HAP) 3.3E-10 3.3E-10 0.0E+00

EMISSIONS: Half Rate (including Black Start)

lb/hr avg. lb/hr max. TPY 

SO2 2.08 2.08 0.02

NOx 2.54 2.54 0.03

CO 4.68 4.68 0.06

H2SO4 1.25 1.25 0.01

Mercury (HAP) 3.3E-10 3.3E-10 3.9E-12

EMISSIONS: Preheat

lb/hr avg. lb/hr max. TPY 

PM10 0.03 0.03 0.0008

SO2 0.02 0.02 0.0006

NOx 3.85 3.85 0.12

CO 1.96 1.96 0.059

VOC 0.19 0.19 0.006

Total VOC HAPs 0.06 0.06 0.0019

Mercury (HAP) 5.9E-05 5.9E-05 1.8E-06

PM10 VOC SO2

7.600 5.50 0.60

NOx CO

0.110 0.056

Natural Gas SNG (Coal-Coke)

1.95E-07 1.68E-06

Preheat Case: Natural Gas Combustion

Factor (lb/MMscf)

Factor (lb/MMBtu)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10. 

Mercury Factor (lb/MMBtu)

Preheat Case: Natural 

Gas Combustion
Page 5 of 9 TSD App A

This page left blank Intentionally.
Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis) Page 6 of 9 TSD App A

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 111 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0021 MT

N2O = 0.0002 MT

Emission 

Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 2,058,824 scf

High heat value of the 

fuel from all valid 

samples for the year

Annual 

Average 0.00102 MMBtu per scf

GHG

WSA Preheat 

Burners

CO    Fuel  HHV  EF  3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 111 1 111

CH4 0.0 21 0

N2O 0.0 310 0

TOTAL = 111 123 TPY CO2

Feeds to WSA (CO2 + combusted CO):

WSA Exhaust = 14538.1 lb-mole/hr

CO2% = 6.60%

CO2 MW = 44.01 lb/lb-mole

CO2 Emissions = 42,209 lb/hr 185,003 TPY CO2

15% Contingency due to lack of performance guarantee

 212,999 TPY CO2
Page 7 of 9 TSD App A

Coal Only Case

35.00 MM Btu/hr

1,020 Btu/ft3

Full Rate 8,760 hr/yr

Half Rate 0 hr/yr

Black Start 24 hr/yr

Preheat 60 hr/yr

EMISSIONS: Full Rate

lb/hr avg. lb/hr max. TPY 

SO2 7.57 7.57 33.15

NOx 7.40 7.40 32.43

CO 13.63 13.63 59.69

H2SO4 3.64 3.64 15.93

Mercury (HAP) 3.3E-10 3.3E-10 1.5E-09

EMISSIONS: Full Rate for 219 hr/yr OR Half Rate for 438 hr/yr

lb/hr avg. lb/hr max. TPY 

SO2 3.78 3.78 0.00

NOx 3.70 3.70 0.00

CO 6.81 6.81 0.00

H2SO4 1.82 1.82 0.00

Mercury (HAP) 3.3E-10 3.3E-10 0.0E+00

EMISSIONS: Half Rate (including Black Start)

lb/hr avg. lb/hr max. TPY 

SO2 1.89 1.89 0.02

NOx 1.85 1.85 0.02

CO 3.41 3.41 0.04

H2SO4 0.91 0.91 0.01

Mercury (HAP) 3.3E-10 3.3E-10 4.0E-12

EMISSIONS: Preheat

lb/hr avg. lb/hr max. TPY 

PM10 0.03 0.03 0.0008

SO2 0.02 0.02 0.0006

NOx 3.85 3.85 0.12

CO 1.96 1.96 0.059

VOC 0.19 0.19 0.006

Total VOC HAPs 0.06 0.06 0.0019

Mercury (HAP) 5.6E-05 5.6E-05 1.7E-06

PM10 VOC SO2

7.600 5.50 0.60

NOx CO

0.110 0.056

Natural Gas SNG (Coal Only)

1.95E-07 1.61E-06

Combustion

Factor (lb/MMscf)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10. 

Preheat Case: Natural 

Gas Combustion

Mercury Factor (lb/MMBtu)

Factor (lb/MMBtu)
Page 8 of 9 TSD App A

This page left blank Intentionally.
Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis) Page 9 of 9 TSD App A

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 111 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0021 MT

N2O = 0.0002 MT

Emission 

Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 2,058,824 scf

High heat value of the

fuel from all valid 

samples for the year

Annual 

Average 0.00102 MMBtu per scf

GHG GHG GWP Metric Tons 

WSA Preheat 

Burners

CO    Fuel  HHV  EF  3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

GHG 

Pollutant

GHG

Metric Tons

GWP 

Factors

Metric Tons 

CO2e

CO2 111 1 111

CH4 0.0 21 0

N2O 0.0 310 0

TOTAL = 111 123 TPY CO2

Feeds to WSA (CO2 + combusted CO):

WSA Exhaust = 10393.9 lb-mole/hr

CO2% = 10.262%

CO2 MW = 44.01 lb/lb-mole

CO2 Emissions = 46,941 lb/hr 205,743 TPY CO2

15% Contingency due to lack of performance guarantee

 236,877 TPY CO2
VENT SOURCES Page 1 of 9 TSD App A

NAME Wet Sulfuric Acid (WSA) Unit Stack B Unit ID: 015 B

Emissions of all pollutants are higher for the Coal / Coke Case.

STACK DATA

HEIGHT 200 ft

DIAMETER 4.83 ft

GAS EXIT TEMP 176 °F

GAS EXIT VELOCITY: Two Unit Operation 102.2 fps

GAS EXIT VELOCITY: One Unit Operation 51.1 fps

GAS EXIT VELOCITY: Black start 25.5 fps

GAS EXIT VELOCITY: Preheat 115.3 fps

COMBUSTION DATA

HEAT INPUT - Preheat 35.00 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1,020 Btu/ft3

OPERATING HOURS: Two Unit Operation 8,760 hr/yr

OPERATING HOURS: One Unit Operation 0 hr/yr

OPERATING HOURS: Black-start 24 hr/yr

OPERATING HOURS: Preheat 60 hr/yr

EMISSIONS: Full Rate

lb/hr avg. lb/hr max. TPY 

SO2 8.30 8.30 36.35

NOx 10.17 10.17 44.55

CO 18.72 18.72 82.01

H2SO4 5.00 5.00 21.88

Mercury (HAP) 3.3E-10 3.3E-10 1.5E-09

EMISSIONS: Full Rate for 219 hr/yr OR Half Rate for 438 hr/yr

lb/hr avg. lb/hr max. TPY 

SO2 4.15 4.15 0.00

NOx 5.09 5.09 0.00

CO 9.36 9.36 0.00

H2SO4 2.50 2.50 0.00

Mercury (HAP) 3 3E 10 3.3E-10 3 3E 10 3.3E-10 0 0E+00 0.0E+00

EMISSIONS: Half Rate (including Black Start)

lb/hr avg. lb/hr max. TPY 

SO2 2.08 2.08 0.02

NOx 2.54 2.54 0.03

CO 4.68 4.68 0.06

H2SO4 1.25 1.25 0.01

Mercury (HAP) 3.3E-10 3.3E-10 4.0E-12

EMISSIONS: Preheat

lb/hr avg. lb/hr max. TPY 

PM10 0.03 0.03 0.0008

PM2.5 0.02 0.02 0.0006

SO2 0.02 0.02 0.00062

NOx 3.85 3.85 0.116

CO 1.96 1.96 0.059

VOC 0.19 0.19 0.0057

Total VOC HAPs 0.06 0.06 0.00194

Mercury (HAP) 5.9E-05 5.9E-05 1.8E-06
EMISSIONS: Normal Operations Total Page 2 of 9 TSD App A

lb/hr avg. lb/hr max. TPY 

PM10 0.00018 0.03 0.0008

PM2.5 0.00015 0.02 0.0006

SO2 8.31 8.30 36.38

NOx 10.21 10.17 44.70

CO 18.75 18.72 82.13

VOC 0.0013 0.19 0.006

Total VOC HAPs 0.0004 0.06 0.0019

Mercury (HAP) 4.0E-07 6.5E-02 1.8E-06

H2SO4 5.00 5.00 21.90

PM2.5 including H2SO4 5.00 5.00 21.90

CALCULATIONS

Emissions Preheat Case: (NOx, CO) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

PM10 VOC SO2

7.600 5.50 0.60

NOx CO

0.110 0.056

Comments:

Preheat Case: Natural 

Gas Combustion

Factor (lb/MMBtu)

Source: Emission factors for NOx and CO are based on information from vendor supplied data.

Preheat Case: Natural Gas 

Combustion

SO2 emissions for preheat case based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 

grains/10^6 scf (<5 ppmv of H2S). 

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis 

Group).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

Factor (lb/MMscf)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10. 

Emissions Preheat Case: (PM10, VOC, and SO2)(Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3) X Heat Input (MMBtu/hr)

Burner flue gas is scrubbed in gasifier quench water to remove over 90% of particulate.

The emission rate data from the WSA Trains is based on information from process licensee.

Total WSA capacity for two trains is 136,658 lb/h of 97.5 wt% Sulfuric Acid production OR 1,599 stpd on dry basis (100% acid).
Page 3 of 9 TSD App A

This page left blank Intentionally.
Page 4 of 9 TSD App A

Coal / Coke Case

35.00 MM Btu/hr

1,020 Btu/ft3

Full Rate 8,760 hr/yr

Half Rate 0 hr/yr

Black Start 24 hr/yr

Preheat 60 hr/yr

EMISSIONS: Full Rate

lb/hr avg. lb/hr max. TPY 

SO2 8.30 8.30 36.35

NOx 10.17 10.17 44.55

CO 18.72 18.72 82.01

H2SO4 5.00 5.00 21.88

Mercury (HAP) 3.3E-10 3.3E-10 1.4E-09

EMISSIONS: Full Rate for 219 hr/yr OR Half Rate for 438 hr/yr

lb/hr avg. lb/hr max. TPY 

SO2 4.15 4.15 0.00

NOx 5.09 5.09 0.00

CO 9.36 9.36 0.00

H2SO4 2.50 2.50 0.00

Mercury (HAP) 3.3E-10 3.3E-10 0.0E+00

EMISSIONS: Half Rate (including Black Start)

lb/hr avg. lb/hr max. TPY 

SO2 2.08 2.08 0.02

NOx 2.54 2.54 0.03

CO 4.68 4.68 0.06

H2SO4 1.25 1.25 0.01

Mercury (HAP) 3.3E-10 3.3E-10 3.9E-12

EMISSIONS: Preheat

lb/hr avg. lb/hr max. TPY 

PM10 0.03 0.03 0.00078

SO2 0.02 0.02 0.00062

NOx 3.85 3.85 0.116

CO 1.96 1.96 0.059

VOC 0.19 0.19 0.0057

Total VOC HAPs 0.06 0.06 0.00194

Mercury (HAP) 5.9E-05 5.9E-05 1.8E-06

PM10 VOC SO2

7.600 5.50 0.60

NOx CO

0.110 0.056

Natural Gas SNG (Coal-Coke)

1.95E-07 1.68E-06

Combustion

Factor (lb/MMscf)

Factor (lb/MMBtu)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10. 

Preheat Case: Natural 

Gas Combustion

Mercury Factor (lb/MMBtu)
Page 5 of 9 TSD App A

This page left blank Intentionally.
Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Page 6 of 9 TSD App A

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 111 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per m 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0021 MT

N2O = 0.0002 MT

Emission 

Points

Data 

Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 2,058,824 scf

High heat 

value of the 

fuel from all 

valid samples 

for the year

Annual 

Average 0.00102 MMBtu per scf

WSA Preheat 

Burners

CO    Fuel  HHV  EF 3

2 1 10

CH orNO  FuelHHVEF 3

4 2 1 10

for the year

GHG 

Pollutant

GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 111 1 111

CH4 0.0 21 0

N2O 0.0 310 0

TOTAL = 111 123 TPY CO2

Feeds to WSA (CO2 + combusted CO):

WSA Exhaust = 14538.1 lb-mole/hr

CO2% = 6.60%

CO2 MW = 44.01 lb/lb-mole

CO2 Emissions = 42,209 lb/hr 185,003 TPY CO2

15% Contingency due to lack of performance guarantee

 212,999 TPY CO2
Page 7 of 9 TSD App A

Coal Only Case

35.00 MM Btu/hr

1,020 Btu/ft3

Full Rate 8,760 hr/yr

Half Rate 0 hr/yr

Black Start 24 hr/yr

Preheat 60 hr/yr

EMISSIONS: Full Rate

lb/hr avg. lb/hr max. TPY 

SO2 7.57 7.57 33.15

NOx 7.40 7.40 32.43

CO 13.63 13.63 59.69

H2SO4 3.64 3.64 15.93

Mercury (HAP) 3.3E-10 3.3E-10 1.5E-09

EMISSIONS: Full Rate for 219 hr/yr OR Half Rate for 438 hr/yr

lb/hr avg. lb/hr max. TPY 

SO2 3.78 3.78 0.00

NOx 3.70 3.70 0.00

CO 6.81 6.81 0.00

H2SO4 1.82 1.82 0.00

Mercury (HAP) 3.3E-10 3.3E-10 0.0E+00

EMISSIONS: Half Rate (including Black Start)

lb/hr avg. lb/hr max. TPY 

SO2 1.89 1.89 0.02

NOx 1.85 1.85 0.02

CO 3.41 3.41 0.04

H2SO4 0.91 0.91 0.01

Mercury (HAP) 3.3E-10 3.3E-10 4.0E-12

EMISSIONS: Preheat

lb/hr avg. lb/hr max. TPY 

PM10 0.03 0.03 0.00078

SO2 0.02 0.02 0.00062

NOx 3.85 3.85 0.116

CO 1.96 1.96 0.059

VOC 0.19 0.19 0.0057

Total VOC HAPs 0.06 0.06 0.00194

Mercury (HAP) 5.6E-05 5.6E-05 1.7E-06

PM10 VOC SO2

7.600 5.50 0.60

NOx CO

0.110 0.056

Natural Gas SNG (Coal Only)

1.95E-07 1.61E-06

Combustion

Factor (lb/MMscf)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10. 

Factor (lb/MMBtu)

Preheat Case: Natural 

Gas Combustion

Mercury Factor (lb/MMBtu)
Page 8 of 9 TSD App A

This page left blank Intentionally.
Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Page 9 of 9 TSD App A

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 111 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mm 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0021 MT

N2O = 0.0002 MT

Emission 

Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 2,058,824 scf

High heat 

value of the 

fuel from all 

valid samples 

for the year

Annual 

Average 0.00102 MMBtu per scf

WSA Preheat 

Burners

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel HHV EF 3

4 2 1 10

for the year

GHG 

Pollutant

GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 111 1 111

CH4 0.0 21 0

N2O 0.0 310 0

TOTAL = 111 123 TPY CO2

Feeds to WSA (CO2 + combusted CO):

WSA Exhaust = 10393.9 lb-mole/hr

CO2% = 10.262%

CO2 MW = 44.01 lb/lb-mole

CO2 Emissions = 46,941 lb/hr 205,743 TPY CO2

15% Contingency due to lack of performance guarantee

 236,877 TPY CO2
Page 1 of 2 TSD App A

NAME ASU Cooling Water Tower CAP Unit ID: 016a

Evaporative Cooler Operating Parameters Emissions Emissions

Flow Rate, (gpm) Drift Rate, % Drift lb/hr TDS (ppm) PM lb/hr PM TPY PM2.5 lb/hr PM2.5 TPY

54,956 0.0005 138 1,500 0.21 0.90 0.16 0.70

Comments:

Drift rate guaranteed by vendor.

Assume all dissolved solids to be PM10. PM2.5 assumed to be 78% of total PM

Total Spray flow provided by B&V.

 COOLING TOWER 

The ASU Cooling Water Tower consists of 6 individual cells, which are being capped under EIQ No. 16a. The total water flow rate cannot 

exceed the CAP value, regardless of the number of cells in operation. Therefore, the emissions listed above are the capped total lb/hr and 

TPY.

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis 

Group).
Page 2 of 2 TSD App A

NAME Main Cooling Water Tower CAP Unit ID: 016b

Evaporative Cooler Operating Parameters Emissions Emissions

Flow Rate, (gpm) Drift Rate, % Drift lb/hr TDS (ppm) PM10 lb/hr PM10 TPY PM2.5 lb/hr PM2.5 TPY

404,676 0.0005 1,013 1,500 1.52 6.65 1.18 5.19

Comments:

Drift rate guaranteed by vendor.

Assume all dissolved solids to be PM10. PM2.5 assumed to be 78% of total PM

Total flow provided by B&V.

 COOLING TOWER 

The Main Cooling Water Tower consists of 24 individual cells, which are being capped under EIQ No. 16b. The total water flow rate cannot 

exceed the CAP value, regardless of the number of cells in operation. Therefore, the emissions listed above are the capped total lb/hr and 

TPY.

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis 

Group).
Page 1 of 1 TSD App A

NAME ASU Molecular Sieve Regeneration Vents

The molecular sieves are regenerated by blowing nitrogen through them.

STACK DATA

HEIGHT 60 ft

DIAMETER 8 ft

GAS EXIT TEMP 260 °F

GAS EXIT VELOCITY 62.02 fps

OPERATING HOURS (each) 8,760 hr/yr

PM10 EMISSIONS Average Maximum Annual PM10 Annual PM2.5

Emissions Hourly Emissions Emissions

Unit ID lb/hr lb/hr TPY TPY

017 A 0.13 0.13 0.55 0.039

017 B 0.13 0.13 0.55 0.039

Total 0.25 0.25 1.10 0.077

Regeneration occurs for 1 hr out of every 5 hr for each molecular sieve.

The vent stream is primarily nitrogen (>98%), with a trace amount of particulates.

Emissions based on engineered equipment data

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group)

VENT SOURCES

16_30464 Calcs D 66 5/3/2012
Page 1 of 4 TSD App A

UNCONTROLLED

AVERAGE* EMISSION UNPAVED UNCONTROLLED Trucks Trucks

TYPES OF TRUCKS TRUCK FACTOR PRECIPITATION EMISSION FACTOR Trips Trips

WEIGHT UNPAVED CORRECTION UNPAVED per day per hour

TONS lb/VMT lb/VMT

COAL PILE DOZER OPERATIONS 41.38 1.061 0.68 0.73 155 12.9

ASSUMPTIONS

CAT 824H Wheel Dozer lbs Tons

Estimate Total Capacity 100,195 50.10

Tare 65,325 32.66

Estimate Capacity 34,870 17.44

Average Equipment Weight 82,760 41.38

Maximum Feedstock moved each hr (12hr/day) 450,000 225.00

Maximum Number of Trips per Hour 12.9

Unpaved Road Equation is based on speeds of 15-45 mph.

Based on the speed of the dozer - 3 - 8 mph, an overall 95% control efficiency is possible.

Wet suppression is used for additional control.

A 90% control efficiency is being conservatively used.

Average daily dozer travel distance each trip assumed to be 1/2 pile radius times two (for round trip). 

Emission Calculation for Dozer Activity on the pile [EU-012P & EU-012Q / PM10] (Calc for each pile)
Page 2 of 4 TSD App A

Ave Daily

MILES MILES ON-SITE VMT/DAY UNCONTROLLED PERCENT CONTROLLED CONTROLLED CONTROLLED

ROUND TRIP ROUND TRIP UNPAVED EMISSIONS CONTROL EMISSIONS EMISSIONS EMISSIONS

PAVED UNPAVED LBS/DAY LBS/DAY LBS/HR* Tons/yr

each trip

0 0.05105 7.91 5.7 90% 0.5747 0.0239 0.1049

UNPAVED ROADS EQUATIONS

E = size specific emission factor (lbs/VMT) Eext = natural mitigation emission factor (lb/VMT)

k = particle size multiplier for particle size range P = number of days per year with 0.01 in or more of precipitation

s = surface material silt content (%) 

a = constant based on size of particulate

b = constant based on size of particulate

W = Coal Trucks = 50 tons, Ash Trucks = 50 tons, Limestone Trucks = 25 tons

INPUTS

k 1.5 lb/VMT P 115 wet days/yr

s 2.2 % AP-42 13.2.4-1

a 0.9

b 0.45

P 115 days

Emission Calculation for Dozer Activity on the pile [EU-012P & EU-012Q / PM10] (Calc. for each pile)

    12 3 * s * Wa b

E  k 



 



  

365

365 P

E ext E
Page 3 of 4 TSD App A

UNCONTROLLED

AVERAGE* EMISSION UNPAVED UNCONTROLLED Trucks Trucks

TYPES OF TRUCKS TRUCK FACTOR PRECIPITATION EMISSION FACTOR Trips Trips

WEIGHT UNPAVED CORRECTION UNPAVED per day per hour

TONS lb/VMT lb/VMT

COAL PILE DOZER OPERATIONS 41.38 0.106 0.68 0.07 155 12.9

ASSUMPTIONS

CAT 824H Wheel Dozer lbs Tons

Estimate Total Capacity 100,195 50.10

Tare 65,325 32.66

Estimate Capacity 34,870 17.44

Average Equipment Weight 82,760 41.38

Maximum Feedstock moved each hr (12hr/day) 450,000 225.0

Maximum Number of Trips per Hour 12.9

Unpaved Road Equation is based on speeds of 15-45 mph.

Based on the speed of the dozer - 3 - 8 mph, an overall 95% control efficiency is reasonable.

Average daily dozer travel distance each trip assumed to be 1/2 pile radius times two (for round trip). 

Emission Calculation for Dozer Activity on the pile [EU-012P & EU-012Q / PM2.5] (each pile)
Page 4 of 4 TSD App A

Ave Daily

MILES MILES ON-SITE VMT/DAY UNCONTROLLED PERCENT CONTROLLED CONTROLLED CONTROLLED

ROUND TRIP ROUND TRIP UNPAVED EMISSIONS CONTROL EMISSIONS EMISSIONS EMISSIONS

PAVED UNPAVED* LBS/DAY LBS/DAY LBS/HR* Tons/yr

each trip

0 0.05105 7.9 0.57 90% 0.0575 0.0024 0.0105

UNPAVED ROADS EQUATIONS

E = size specific emission factor (lbs/VMT) Eext = natural mitigation emission factor (lb/VMT)

k = particle size multiplier for particle size range P = number of days per year with 0.01 in or more of precipitation

s = surface material silt content (%) 

a = constant based on size of particulate

b = constant based on size of particulate

W = Coal Trucks = 50 tons, Ash Trucks = 50 tons, Limestone Trucks = 25 tons

INPUTS

k 0.15 lb/VMT P 115 wet days/yr

s 2.2 % AP-42 13.2.4-1

a 0.9

b 0.45

P 115 days

Emission Calculation for Dozer Activity on the pile [EU-012P & EU-012Q / PM2.5] (each pile)

    12 3 * s * Wa b

E  k 



 



  

365

365 P

E ext E
Emissions Calculations for Fugitive Dust from Wind Erosion [EU-012W &EU-012X]

Page 1 of 1 TSD App A

Referened document can be obtained at:

http://www.wrapair.org/forums/dejf/fdh/content/Ch9-Storage_Pile_Wind%20Erosion_Rev06.pdf

WRAP document basis for equation is stated to be from 1989 EPA document:

USEPA, January 1989. Air/Superfund National Technical Guidance Study Series;

Volume III – Estimation of Air Emissions from Cleanup Activities at Superfund

Sites, Interim final report EPA-450/1-89-003.

Assumptions

Data Descript. Basis

silt 2.20 % (s) Silt content

% windy 100.00 % (f) % high wind Conservatively assume high winds on worse case day.

PM10 Multiplier 0.5 ratio PM10 vs TSP

PM2.5 Multiplier 0.053 ratio PM2.5 vs TSP

Control effective. 90% Watering and compaction / BACT

Pile size coal 6.230 acres (see attached Surf. Area Calcs.)

Pile size coke 5.180 acres (see attached Surf. Area Calcs.)

Basis: Wrap Fugitive Dust Handbook, Prepared for Governers Conference, Western Regional Air 

Partnership (WRAP) Methodology for wind erosion. 

AP-42 13.2.4-1, Coal as received, coal power plant. Also 

used for coke (coke should be lower).

Calculated Emiss. Factors from above Equation

Uncontrolled Emissions Factors

TSP 16.62 lb/day/acre of surface

PM10 8.31 lb/day/acre of surface

PM2.5 0.881 lb/day/acre of surface

Controlled Emissions Factors

PM10 0.83 lb/day/acre of surface

PM2.5 0.088 lb/day/acre of surface

Calculated Emissions Rate

Controlled Emissions Rate - lb/hr worse case day

(= Controlled factor * acres / 24hr/day)

Coal Pile Coke Pile

PM10 0.216 lb PM10/hr PM10 0.179 lb PM10/hr

PM2.5 0.023 lb PM2.5/hr PM2.5 0.019 lb PM2.5/hr

Annual Emissons - conservatively assuming max rate on all days.

PM10 0.94 TPY PM10 PM10 0.79 TPY PM10

PM2.5 0.10 TPY PM2.5 PM2.5 0.08 TPY PM2.5

". . .Calculated emissions represent intermittent events and should not be input directly into

dispersion models that assume steady-state emission rates. "

Note: the above method is used for calculating emissions for air modeling purposes in preference to AP42 

section 13.2.5 because, as stated in AP42 section 13.2.5, page 13.2.5-3, regarding its wind erosion formula: 
Emissions Calculations for Fugitive Dust from Wind Erosion [EU-012W &EU-012X] 

6.23 acres

271,379 ft^2

top height = 203

top diameter = 150

top slant = 135.62 √[(top height ‐ pile height)^2+(top diameter/2)^2]

pile height = 90

pile diameter = 539

pile slant = 337.40 √[(top height)^2+(pile diameter/2)^2]

Surface area truncated cone = SA of whole cone - SA of top/removed cone + area of top.

5.18 acres

225,647 ft^2

top height = 186

top diameter = 150

top slant = 135.62 √[(top height ‐ pile height)^2+(top diameter/2)^2]

pile height = 73

pile diameter = 494

pile slant = 309.20 √[(top height)^2+(pile diameter/2)^2]

coal pile surface area =

coke pile surface area =

2

p p t t t SA    r  s   r  s   r

16_30464 Calcs D 72 
Page 2 of 2 TSD App A

Emissions Calculations for Fugitive Dust from Wind Erosion [EU-012W &EU-012X]

Coke x 1 100% coal 85% coal 51% coal

BOOM REACH 135.00 150.00 150.00 150.00 FT

ANGLE OF REPOSE 37.00 37.00 37.00 37.00 DEGREES

PILE HEIGHT 73.00 90.00 90.00 90.00 FT

TOWER RADIUS 20.00 20.00 20.00 20.00 FT

TANGENT 0.75 0.75 0.75 0.75 

OUTSIDE CONE RADIUS 269.43 231.87 269.43 269.43 FT

OUTSIDE PILE DIAMETER 538.85 463.74 538.85 538.85 FT

PI*R*R 228,051.00 168,901.00 228,051.00 228,051.00 SQ FT

HEIGHT OF TOTAL CONE 203.04 174.74 203.04 203.04 FT

TOTAL CONE CAPACITY 15,434,491.70 9,837,695.00 15,434,491.70 15,434,491.70 CU FT

TOP CONE RADIUS 150.00 135.00 150.00 150.00 FT

PI*R*R 70,685.80 57,255.50 70,685.80 70,685.80 

HEIGHT OF TOP CONE 113.04 101.74 113.04 113.04 FT

TOP CONE CAPACITY 2,663,441.00 1,941,649.00 2,663,441.00 2,663,441.00 CU FT

INSIDE TOWER 1,257.00 1,257.00 1,257.00 1,257.00 SQ FT

LOSS CAPACITY - TOWER 113,130.00 91,761.00 113,130.00 113,130.00 CU FT

NET CAPACITY 12,657,920.70 7,804,285.00 12,657,920.70 12,657,920.70 CU FT

MAT'L DENSITY 47.00 50.00 50.00 50.00 LB/CU FT

NET CAPACITY 632,896,035.00 366,801,395.00 632,896,035.00 632,896,035.00 LBS

 2,000.00 2,000.00 2,000.00 2,000.00 LBS/TON

NET CAPACITY 316,448.00 183,400.70 316,448.00 316,448.00 TONS

AREA OF PILE 228,050.64 168,901.25 228,050.64 228,050.64 SQ FT

AREA OF PILE 5.24 3.88 5.24 5.24 ACRES

DAYS STORAGE 33.08 44.87 38.92 64.86 DAYS each

Coal Consumption (100% fuel) 8,131.10 9,565.00 4,878.66 tpd

Coke Consumption (49% fuel) 4,087.00 tpd

% Tons Days storage

Coke 49% 4,087.00 44.87 

Coal 51% 4,878.15 64.87 

85% 8,130.25 38.92 

100% 9,565.00 33.08 

AGRICO STACKER STORAGE PILE CAPACITY

16_30464 Calcs D 73 5/3/2012
COMBUSTION SOURCES Page 1 of 3 TSD App A

NAME ZLD Spray Dryer Stack Unit ID: 032

STACK DATA

HEIGHT 100 ft

DIAMETER 1 ft

GAS EXIT TEMP 310 °F

GAS EXIT VELOCITY 35.49 fps

COMBUSTION DATA

HEAT INPUT 5.6 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1,020 Btu/ft3

PROCESS FLOW RATE 2,735 dscfm

OPERATING HOURS 8,760 hr/yr

EMISSIONS:

lb/hr avg. lb/hr max. TPY 

PM10 0.12 0.12 0.51

PM2.5 0.11 0.11 0.48

SO2 0.003 0.003 0.015

NOx 0.197 0.197 0.86

CO 0.203 0.203 0.89

VOC 0.030 0.030 0.13

Total VOC HAPs 0.010 0.010 0.046

Mercury (HAP) 9.4E-06 9.4E-06 4.1E-05

CALCULATIONS

Emissions (SO2) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu/hr) x Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

Natural Gas Combustion SO2 Fabric Filter PM10 

0.60 Factor (gr/dscf) 0.0050

Natural Gas Combustion NOx CO VOC

0.035 0.036 0.005

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

Mercury Factor (lb/MMBtu)

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

Natural gas or SNG may be combusted. Conservatively assumed natural gas for SO2 calculation (as SNG contains no sulfur).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Factor (lb/MM scf)

Factor (lb/MM Btu)

Source: Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.
Page 2 of 3 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 2,616 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0493 MT

N2O = 0.0049 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 48,379,046 scf

High heat value 

of the fuel from all 

valid samples for 

Annual 

Average 0.00102 MMBtu per scf

ZLD Spray Dryer 

Stack

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

valid samples for 

the year

Average

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 2,616 1 2,616

CH4 0.049 21 1

N2O 0.0049 310 2

TOTAL = 2,619 2,886 TPY CO2
URS INDIANA GASIFICATION FACILITY Vent Calculations

Page 3 of 3 TSD App A

NAME ZLD Inert Gas Vent Unit ID: 033

Mercury is controlled using a sulfided carbon adsorbent with a vendor guarantee of 0.5 ppbv.

STACK DATA

HEIGHT 15 ft

DIAMETER 0.083 ft

GAS EXIT TEMP 150 °F

GAS EXIT VELOCITY 31.74 fps

OPERATING HOURS 8,760 hr/yr

Average Maximum Average Annual Average Annual

EMISSIONS Emissions Hourly Emissions Emissions

lb/hr lb/hr lb/yr TPY

Carbon Dioxide 46.50 46.50 407,340 203.7

Mercury 1.40E-07 0.0149 0.7168 < 0.001 

Assumptions:

Vent stream is 75.5% CO2 and 24.5% H20.

Mercury in solids feed to Gasifier at max is 0.745 lb/hr

Gasification process wastewater picks up 2% of the mercury in the gasifiers, resulting in 0.0149 lb/hr mercury in the water, all of which goes to the ZLD inert gas vent.

Sulfided carbon adsorbent control is >99.99% effective, but is offline up to 2 days/year for carbon changeout.

VENT SOURCES

16_30464 Calcs 76 5/3/2012
Basis of Total HAP Emission Factor for Natural Gas Combustion Page 1 of 2 TSD App A

Project: Indiana Gasification

Emissions Estimation 

AP-42 Heating Value 1,020 Btu/scf

EMISSION FACTOR BASED INVENTORY Notes

POLLUTANT CAS # Em.Fac. Source lb/MMscf lb/MMBtu

2-Methylnaphthalene 91-57-6 AP-42, Table 1.4-3 2.40E-05 2.35E-08 b

3-Methylchloranthrene 56-49-5 AP-42, Table 1.4-3 1.80E-06 1.76E-09 b

7,12-Dimethylbenz(a)anthracene --- AP-42, Table 1.4-3 1.60E-05 1.57E-08 b, c

Acenaphthene 83-32-9 AP-42, Table 1.4-3 1.80E-06 1.76E-09 b, c

Acenaphthylene 203-96-8 AP-42, Table 1.4-3 1.80E-06 1.76E-09 b, c

Anthracene 120-12-7 AP-42, Table 1.4-3 2.40E-06 2.35E-09 b, c

Benz(a)anthracene 56-55-3 AP-42, Table 1.4-3 1.80E-06 1.76E-09 b, c

Benzene 71-43-2 AP-42, Table 1.4-3 2.10E-03 2.06E-06 b

Benzo(a)pyrene 50-32-8 AP-42, Table 1.4-3 1.20E-06 1.18E-09 b, c

Benzo(b)fluoranthene 205-99-2 AP-42, Table 1.4-3 1.80E-06 1.76E-09 b, c

Benzo(g,h,i)perylene 191-24-2 AP-42, Table 1.4-3 1.20E-06 1.18E-09 b, c

Benzo(k)fluoranthene 205-82-3 AP-42, Table 1.4-3 1.80E-06 1.76E-09 b, c

Chrysene 218-01-9 AP-42, Table 1.4-3 1.80E-06 1.76E-09 b, c

Dibenzo(a,h)anthracene 53-70-3 AP-42, Table 1.4-3 1.20E-06 1.18E-09 b, c

Dichlorobenzene 25321-22-6 AP-42, Table 1.4-3 1.20E-03 1.18E-06 b

Fluoranthene 206-44-0 AP-42, Table 1.4-3 3.00E-06 2.94E-09 b, c

Fluorene 86-73-7 AP-42, Table 1.4-3 2.80E-06 2.75E-09 b, c

Formaldehyde 50-00-0 AP-42, Table 1.4-3 7.50E-02 7.35E-05 b

Hexane 110-54-3 AP-42, Table 1.4-3 1.80E+00 1.76E-03 b

Indeno(1,2,3-cd)pyrene 193-39-5 AP-42, Table 1.4-3 1.80E-06 1.76E-09 b, c

Naphthalene 91-20-3 AP-42, Table 1.4-3 6.10E-04 5.98E-07 b

Phenanathrene 85-01-8 AP-42, Table 1.4-3 1.70E-05 1.67E-08 b, c

Pyrene 129-00-0 AP-42, Table 1.4-3 5.00E-06 4.90E-09 b, c

Toluene 108-88-3 AP-42, Table 1.4-3 3.40E-03 3.33E-06 b

Arsenic 7440-38-2 AP-42, Table 1.4-4 2.00E-04 1.96E-07 b

Beryllium 7440-41-7 AP-42, Table 1.4-4 1.20E-05 1.18E-08 b

Cadmium 7440-43-9 AP-42, Table 1.4-4 1.10E-03 1.08E-06 b

Chromium 7440-47-3 AP-42, Table 1.4-4 1.40E-03 1.37E-06 b

Cobalt 7440-48-4 AP-42, Table 1.4-4 8.40E-05 8.24E-08 b

Manganese 7439-96-5 AP-42, Table 1.4-4 3.80E-04 3.73E-07 b

Mercury 7439-97-6 AP-42, Table 1.4-4 2.60E-04 2.55E-07 b

Nickel 7440-02-0 AP-42, Table 1.4-4 2.10E-03 2.06E-06 b

Selenium 7782-49-2 AP-42, Table 1.4-4 2.40E-05 2.35E-08 b

Total HAP = 1.88796 0.00185

Notes: 

a. Criteria pollutant by name or association, i.e., VOC as surrogates for O3

b. Hazardous Air Pollutant (HAP) as defined by Section 112(b) of the Clean Air Act.

c. HAP because it is Polycyclic Organic Matter (POM). POM is a HAP as defined by Section 112(b) of Clean Air Act

d. non-VOC per 40 CFR 51.100(s)(1); methane and ethane are not considered as regulated photochemical reactive VOC 

e. Soot in concentration values, 0 micrograms per liter (ug/L); lightly smoking flares, 40 ug/L; average smoking flares, 177 ug/L; and heavily smoking flares 274 ug/L.

f. To be used where source testing or fuel analysis are not required by the AB2588 Criteria and Guidelines Regulations, Appendix D

g. Based on 100% conversion of fuel sulfur to SO2.

Assumes sulfur content is natural gas of 2,000 grains/10^6 scf. The SO2 emission factor in this table can

be converted to other natural gas sulfur contents by multiplying the SO2 emission factor by the ratio of

the site-specific sulfur content (grains/10^6 scf) to 2,000 grains/10^6 scf.

AP-42 Em. Factor
Page 2 of 2 TSD App A

EMISSION FACTOR BASED INVENTORY 001 002 005 007 008 015 024 025 029 030 032 FUG

112252111111 Notes

POLLUTANT CAS # 0.27 0.27 408.17 38.81 35.00 35.00 ---- 5.63 - MMBtu/hr

2-Methylnaphthalene 91-57-6 6.24E-09 6.24E-09 9.60E-06 9.13E-07 4.12E-06 8.24E-07 ---- 1.33E-07 - b

3-Methylchloranthrene 56-49-5 4.68E-10 4.68E-10 7.20E-07 6.85E-08 3.09E-07 6.18E-08 ---- 9.94E-09 - b

7,12-Dimethylbenz(a)anthracene --- 4.16E-09 4.16E-09 6.40E-06 6.09E-07 2.75E-06 5.49E-07 ---- 8.84E-08 - b, c

Acenaphthene 83-32-9 4.68E-10 4.68E-10 7.20E-07 6.85E-08 3.09E-07 6.18E-08 ---- 9.94E-09 - b, c

Acenaphthylene 203-96-8 4.68E-10 4.68E-10 7.20E-07 6.85E-08 3.09E-07 6.18E-08 ---- 9.94E-09 - b, c

Anthracene 120-12-7 6.24E-10 6.24E-10 9.60E-07 9.13E-08 4.12E-07 8.24E-08 - - 2.88E-07 - 1.33E-08 - b, c

Arsenic 7440-38-2 5.20E-08 5.20E-08 8.00E-05 7.61E-06 3.43E-05 6.86E-06 ---- 1.10E-06 - b

Benz(a)anthracene 56-55-3 4.68E-10 4.68E-10 7.20E-07 6.85E-08 3.09E-07 6.18E-08 ---- 9.94E-09 - b, c

Benzene 71-43-2 5.46E-07 5.46E-07 8.40E-04 7.99E-05 3.60E-04 7.21E-05 - - 1.08E-03 5.59E-05 1.16E-05 - b

Benzo(a)pyrene 50-32-8 3.12E-10 3.12E-10 4.80E-07 4.57E-08 2.06E-07 4.12E-08 ---- 6.63E-09 - b, c

Benzo(b)fluoranthene 205-99-2 4.68E-10 4.68E-10 7.20E-07 6.85E-08 3.09E-07 6.18E-08 ---- 9.94E-09 - b, c

Benzo(g,h,i)perylene 191-24-2 3.12E-10 3.12E-10 4.80E-07 4.57E-08 2.06E-07 4.12E-08 ---- 6.63E-09 - b, c

Benzo(k)fluoranthene 205-82-3 4.68E-10 4.68E-10 7.20E-07 6.85E-08 3.09E-07 6.18E-08 ---- 9.94E-09 - b, c

Beryllium 7440-41-7 3.12E-09 3.12E-09 4.80E-06 4.57E-07 2.06E-06 4.12E-07 ---- 6.63E-08 - b

Biphenyl 92-52-4 -------- 3.18E-06 - - - b,c

Cadmium 7440-43-9 2.86E-07 2.86E-07 4.40E-04 4.19E-05 1.89E-04 3.77E-05 ---- 6.07E-06 - b

Carbonyl Sulfide 463-58-1 6.67E-02 - - 7.80E-02 ------- 2.82E-03 b

Chromium 7440-47-3 3.64E-07 3.64E-07 5.60E-04 5.33E-05 2.40E-04 4.80E-05 ---- 7.73E-06 - b

Chrysene 218-01-9 4.68E-10 4.68E-10 7.20E-07 6.85E-08 3.09E-07 6.18E-08 ---- 9.94E-09 - b, c

Cobalt 7440-48-4 2.18E-08 2.18E-08 3.36E-05 3.20E-06 1.44E-05 2.88E-06 ---- 4.64E-07 - b

Cumene 98-82-8 --------- 4.65E-06 - - b

Dibenzo(a,h)anthracene 53-70-3 3.12E-10 3.12E-10 4.80E-07 4.57E-08 2.06E-07 4.12E-08 ---- 6.63E-09 - b, c

Dichlorobenzene 25321-22-6 3.12E-07 3.12E-07 4.80E-04 4.57E-05 2.06E-04 4.12E-05 ---- 6.63E-06 - b

Ethylbenzne 100-41-4 -------- 5.37E-03 2.07E-05 - - b

Fluoranthene 206-44-0 7.80E-10 7.80E-10 1.20E-06 1.14E-07 5.15E-07 1.03E-07 ---- 1.66E-08 - b, c

Fluorene 86-73-7 7.28E-10 7.28E-10 1.12E-06 1.07E-07 4.80E-07 9.61E-08 ---- 1.55E-08 - b, c

Formaldehyde 50-00-0 1.95E-05 1.95E-05 3.00E-02 2.85E-03 1.29E-02 2.57E-03 ---- 4.14E-04 - b

Hexane 110-54-3 4.68E-04 4.68E-04 7.20E-01 6.85E-02 3.09E-01 6.18E-02 - - - 5.42E-04 9.94E-03 - b

Indeno(1,2,3-cd)pyrene 193-39-5 4.68E-10 4.68E-10 7.20E-07 6.85E-08 3.09E-07 6.18E-08 ---- 9.94E-09 - b, c

Manganese 7439-96-5 9.88E-08 9.88E-08 1.52E-04 1.45E-05 6.52E-05 1.30E-05 ---- 2.10E-06 - b

Mercury 7439-97-6 6.76E-08 6.76E-08 1.04E-04 9.89E-06 4.46E-05 8.92E-06 ---- 1.44E-06 - b

Methanol 67-56-1 - - - 1.56E+00 - - 3.58E-02 3.03E-02 - - - 8.40E-02 b

Naphthalene 91-20-3 1.59E-07 1.59E-07 2.44E-04 2.32E-05 1.05E-04 2.09E-05 - - 2.05E-04 - 3.37E-06 - b

Nickel 7440-02-0 5.46E-07 5.46E-07 8.40E-04 7.99E-05 3.60E-04 7.21E-05 ---- 1.16E-05 - b

Phenanathrene 85-01-8 4.42E-09 4.42E-09 6.80E-06 6.47E-07 2.92E-06 5.83E-07 ---- 9.39E-08 - b, c

Pyrene 129-00-0 1.30E-09 1.30E-09 2.00E-06 1.90E-07 8.58E-07 1.72E-07 ---- 2.76E-08 - b, c

Selenium 7782-49-2 6.24E-09 6.24E-09 9.60E-06 9.13E-07 4.12E-06 8.24E-07 ---- 1.33E-07 - b

Toluene 108-88-3 8.84E-07 8.84E-07 1.36E-03 1.29E-04 5.83E-04 1.17E-04 - - 3.21E-03 1.40E-04 1.88E-05 - b

Xylene 1330-20-7 -------- 6.85E-03 4.26E-05 - - b

6.72E-02 4.91E-04 7.55E-01 1.71E+00 3.24E-01 6.48E-02 3.58E-02 3.03E-02 1.67E-02 8.05E-04 1.04E-02 8.69E-02 -

Notes: 

a. Criteria pollutant by name or association, i.e., VOC as surrogates for O3

b. Hazardous Air Pollutant (HAP) as defined by Section 112(b) of the Clean Air Act.

c. HAP because it is Polycyclic Organic Matter (POM). POM is a HAP as defined by Section 112(b) of Clean Air Act

d. non-VOC per 40 CFR 51.100(s)(1); methane and ethane are not considered as regulated photochemical reactive VOC 

e. Soot in concentration values, 0 micrograms per liter (ug/L); lightly smoking flares, 40 ug/L; average smoking flares, 177 ug/L; and heavily smoking flares 274 ug/L.

f. To be used where source testing or fuel analysis are not required by the AB2588 Criteria and Guidelines Regulations, Appendix D

g. Based on 100% conversion of fuel sulfur to SO2.

Assumes sulfur content is natural gas of 2,000 grains/10^6 scf. The SO2 emission factor in this table can

be converted to other natural gas sulfur contents by multiplying the SO2 emission factor by the ratio of

the site-specific sulfur content (grains/10^6 scf) to 2,000 grains/10^6 scf.

h. lb/hr Values in columns 024, 025, 029, and 030 are sourced from the Tanks Emissions Calculations 

i. lb/hr Vlaues in column FUG are sourced from the Fugitive Emissions Calculations

j. the lb/hr vlaues for Methanol and Carbonyl Sulfide in Unit 007 are sourced from the Combustion Emissions Calculations

k. Thelb/hr value fro Carbonyl Sulfide in Unit 001 is sourced from the Flares Emissions Calculations

lb/hr (per individual emission unit, maximum short term)

Number of emission units

Total
Page 1 of 6 TSD App A

NAME Fugitive Emissions - Gasification, Shift Conversion, Methanation, AGR (Rectisol) Unit ID: FUG

Methanol fugitives in the AGR (Rectisol) Unit: 100% Methanol

lb/hr/component lb/hr % lb/hr TPY

Gas 0 0.0089 0 0 0 0

Light Liquid 250 0.0035 0.875 0 0.88 3.83

Heavy Liquid 0 0.0007 0 0 0 0

Gas 0 0.0029 0 0 0 0

Light Liquid 500 0.0005 0.250 0 0.25 1.10

Heavy Liquid 0 0.00007 0 0 0 0

Light Liquid 8 0.0386 0.309 0 0.31 1.35

Heavy Liquid 0 0.0161 0 0 0 0

Compressors Gas 0 0.5027 0 0 0 0

Gas 0 0.2293 0 0 0 0

Light Liquid 19 0.0035 0.067 0 0 0

Sampling Connections All 4 0.033 0.132 0 0.132 0.578

Total Methanol 781 1.63 7.15

VOC fugitives in the AGR (Rectisol) Unit: 100% non-TAP VOC (propylene)

lb/hr/component lb/hr % lb/hr TPY

Gas 78 0.0089 0.694 0 0.69 3.0

Light Liquid 33 0.0035 0.116 0 0.12 0.51

Heavy Liquid 0 0.0007 0 0 0 0

Gas 193 0.0029 0.560 0 0.56 2.45

Light Liquid 82 0.0005 0.041 0 0.041 0.18

Heavy Liquid 0 0.00007 0 0 0 0

Light Liquid 2 0.0386 0.077 0 0.077 0.34

Heavy Liquid 0 0.0161 0 0 0 0

Compressors Gas 3 0.5027 1.508 0 1.51 6.61

Gas 7 0.2293 1.605 0 2 7

Light Liquid 0 0.0035 0 0 0 0

Sampling Connections All 1 0.033 0.033 0 0.033 0.145

Total VOCs 399 4.63 20.30

Carbonyl Sulfide

COS Conc

%v lb/hr/component lb/hr % lb/hr TPY

Valves Raw Syngas 100 0.029 0.0089 0.00026 0 2.6E-04 1.1E-03

Shifted Syngas 50 0.008 0.0089 0.00003 0 3.3E-05 1.5E-04

Mixed Syngas 100 0.024 0.0089 0.00022 0 2.2E-04 0.00095

Sweet Syngas 20 5.0E-07 0.0089 8.9E-10 0 8.9E-10 3.9E-09

Flanges Raw Syngas 250 0.029 0.0029 0.00021 0 2.1E-04 0.00093

Shifted Syngas 100 0.008 0.0029 0.00002 0 2.2E-05 9.5E-05

Mixed Syngas 250 0.024 0.0029 0.00018 0 1.8E-04 0.00077

Sweet Syngas 50 5.0E-07 0.0029 7.3E-10 0 7.3E-10 3.2E-09

Compressor Seals Raw Syngas 0 0.029 0.5027 0 000

Shifted Syngas 0 0.008 0.5027 0 000

Mixed Syngas 0 0.024 0.5027 0 000

Sweet Syngas 0 5.0E-07 0.5027 0 000

Pump Seals Raw Syngas 0 0.029 0.0386 0 000

Shifted Syngas 0 0.008 0.0386 0 000

Mixed Syngas 0 0.024 0.0386 0 000

Sweet Syngas 0 5.0E-07 0.0386 0 000

Relief Valves Raw Syngas 20 0.029 0.2293 0.00134 0 0.0013 0.0059

Shifted Syngas 4 0.008 0.2293 0.00007 0 6.9E-05 3.0E-04

Mixed Syngas 8 0.024 0.2293 0.00045 0 4.5E-04 0.00196

Sweet Syngas 4 5.0E-07 0.2293 4.6E-09 0 4.6E-09 2.01E-08

Sample Connections Raw Syngas 2 0.029 0.033 0.00002 0 1.9E-05 8.5E-05

Shifted Syngas 2 0.008 0.033 0.00000 0 5.0E-06 2.2E-05

Mixed Syngas 2 0.024 0.033 0.00002 0 1.6E-05 7.0E-05

Sweet Syngas 2 5.0E-07 0.033 3.3E-10 0 3.3E-10 1.4E-09

Total COS 2.8E-03 1.2E-02

No Control Efficiency claimed due to low concentration. Total VOCs = 6.27 27.46

Control 

Efficiency Controlled Emissions

Control 

Efficiency Controlled Emissions

Controlled Emissions

Control 

Component Efficiency

Count

Emission Factors

Valves

Fugitive Source

Flanges

Pumps

Relief Valves

Component

Count

Emission Factors

Uncontrolled 

Emissions

Uncontrolled 

Emissions

Flanges

Pumps

Relief Valves

Fugitive Source

Stream Type

Fugitive Source

Stream Type

FUGITIVES

Emission Factors

Uncontrolled 

Process Emissions

Stream

Component 

Count

Valves
Carbon Monoxide Page 2 of 6 TSD App A

CO Conc

%v lb/hr/component lb/hr % lb/hr TPY

Valves Raw Syngas 100 20.4 0.0089 0.18156 0 0.1816 0.795

Shifted Syngas 50 3.7 0.0089 0.01666 0 1.7E-02 0.073

Mixed Syngas 100 14.8 0.0089 0.13181 0 0.1318 0.577

Sweet Syngas 20 22.5 0.0089 0.03997 0 0.0400 0.175

Flanges Raw Syngas 250 20.4 0.0029 0.14790 0 0.1479 0.648

Shifted Syngas 100 3.7 0.0029 0.01086 0 0.0109 0.048

Mixed Syngas 250 14.8 0.0029 0.10737 0 0.1074 0.470

Sweet Syngas 50 22.5 0.0029 0.03256 0 0.0326 0.143

Compressor Seals Raw Syngas 0 20.4 0.5027 0 000

Shifted Syngas 0 3.7 0.5027 0 000

Mixed Syngas 0 14.8 0.5027 0 000

Sweet Syngas 0 22.5 0.5027 0 000

Pump Seals Raw Syngas 0 20.4 0.0386 0 000

Shifted Syngas 0 3.7 0.0386 0 000

Mixed Syngas 0 14.8 0.0386 0 000

Sweet Syngas 0 22.5 0.0386 0 000

Relief Valves Raw Syngas 20 20.4 0.2293 0.93554 0 0.9355 4.0977

Shifted Syngas 4 3.7 0.2293 0.03434 0 0.0343 0.1504

Mixed Syngas 8 14.8 0.2293 0.27167 0 0.2717 1.1899

Sweet Syngas 4 22.5 0.2293 0.20596 0 0.2060 0.9021

Sample Connections Raw Syngas 2 20.4 0.033 0.01346 0 1.3E-02 0.0590

Shifted Syngas 2 3.7 0.033 0.00247 0 2.5E-03 1.1E-02

Mixed Syngas 2 14.8 0.033 0.00977 0 9.8E-03 0.0428

Sweet Syngas 2 22.5 0.033 0.01482 0 1.5E-02 0.0649

Total CO 2.157 9.446

Hydrogen Sulfide

H2S Conc

%v lb/hr/component lb/hr % lb/hr TPY

Valves Raw Syngas 100 0.58 0.0089 0.00519 0 5.2E-03 0.023

Shifted Syngas 50 0.61 0.0089 0.00269 0 2.7E-03 0.012

Mixed Syngas 100 1.10 0.0089 0.00978 0 9.8E-03 0.043

Sweet Syngas 20 2.8E-06 0.0089 5.0E-09 0 5.0E-09 2.2E-08

Flanges Raw Syngas 250 0.58 0.0029 0.00423 0 4.2E-03 0.019

Shifted Syngas 100 0.61 0.0029 0.00176 0 1.8E-03 7.7E-03

Mixed Syngas 250 1.10 0.0029 0.00797 0 8.0E-03 0.035

Sweet Syngas 50 2.8E-06 0.0029 4.1E-09 0 4.1E-09 1.8E-08

Compressor Seals Raw Syngas 0 0.58 0.5027 0 000

Shifted Syngas 0 0.61 0.5027 0 000

Mixed Syngas 0 1.10 0.5027 0 000

Sweet Syngas 0 2.8E-06 0.5027 0 000

Pump Seals Raw Syngas 0 0.58 0.0386 0 000

Shifted Syngas 0 0.61 0.0386 0 000

Mixed Syngas 0 1.10 0.0386 0 000

Sweet Syngas 0 2.8E-06 0.0386 0 000

Relief Valves Raw Syngas 20 0.58 0.2293 0.02675 0 0 0

Shifted Syngas 4 0.61 0.2293 0.00555 0 0 0

Mixed Syngas 8 1.10 0.2293 0.02016 0 0 0

Sweet Syngas 4 2.8E-06 0.2293 2.6E-08 0 0 0

Sample Connections Raw Syngas 2 0.58 0.033 0.00039 0 3.9E-04 1.7E-03

Shifted Syngas 2 0.61 0.033 0.00040 0 4.0E-04 1.7E-03

Mixed Syngas 2 1.10 0.033 0.00073 0 7.3E-04 3.2E-03

Sweet Syngas 2 2.8E-06 0.033 1.9E-09 0 1.9E-09 8.2E-09

Total Hydrogen Sulfide 0.086 0.375

No Control Efficiency claimed for components in sweet syngas service due to low concentration.

Controlled Emissions

Emission Factors

Uncontrolled 

Emissions

Control 

Efficiency Controlled Emissions

Control 

Efficiency

Fugitive Source

Component

Count

Component

Count

Emission Factors

Uncontrolled 

Emissions

Process 

Stream

Fugitive Source Process 

Stream
Ammonia Page 3 of 6 TSD App A

NH3 Conc

%v lb/hr/component lb/hr % lb/hr TPY

Valves Raw Syngas 100 0.0012 0.0089 1.0E-05 0 1.0E-05 4.5E-05

Shifted Syngas 50 0.0012 0.0089 5.2E-06 0 5.2E-06 2.3E-05

Mixed Syngas 100 0.0012 0.0089 1.0E-05 0 1.0E-05 4.5E-05

Sweet Syngas 20 0 0.0089 0 000

Flanges Raw Syngas 250 0.0012 0.0029 8.4E-06 0 8.4E-06 3.7E-05

Shifted Syngas 100 0.0012 0.0029 3.4E-06 0 3.4E-06 1.5E-05

Mixed Syngas 250 0.0012 0.0029 8.4E-06 0 8.4E-06 3.7E-05

Sweet Syngas 50 0 0.0029 0 000

Compressor Seals Raw Syngas 0 0.0012 0.5027 0 000

Shifted Syngas 0 0.0012 0.5027 0 000

Mixed Syngas 0 0.0012 0.5027 0 000

Sweet Syngas 0 0 0.5027 0 000

Pump Seals Raw Syngas 0 0.0012 0.0386 0 000

Shifted Syngas 0 0.0012 0.0386 0 000

Mixed Syngas 0 0.0012 0.0386 0 000

Sweet Syngas 0 0 0.0386 0 000

Relief Valves Raw Syngas 20 0.0012 0.2293 5.3E-05 0 5.3E-05 2.3E-04

Shifted Syngas 4 0.0012 0.2293 1.1E-05 0 1.1E-05 4.7E-05

Mixed Syngas 8 0.0012 0.2293 2.1E-05 0 2.1E-05 9.3E-05

Sweet Syngas 4 0 0.2293 0 000

Sample Connections Raw Syngas 2 0.0012 0.033 7.7E-07 0 7.7E-07 3.4E-06

Shifted Syngas 2 0.0012 0.033 7.7E-07 0 7.7E-07 3.4E-06

Mixed Syngas 2 0.0012 0.033 7.7E-07 0 7.7E-07 3.4E-06

Sweet Syngas 2 0 0.033 0 000

Total Ammonia 1.3E-04 5.8E-04

Notes:

1 Component counts are preliminary subject to change during detailed project engineering.

2 Emissions factors and control efficiencies from TCEQ 28VHP LDAR Program.

3 Relief valves discharge to flare.

4 No LDAR program is required for syngas streams, therefore, no control efficiency assumed.

Uncontrolled 

Component Emissions

Count

Process 

Stream

Fugitive Source Emission Factors Controlled Emissions

Control 

Efficiency
Page 4 of 6 TSD App A

NAME Fugitive Emissions - Wet Sulfuric Acid Units Unit ID: FUG - WSA

Summary of Fugitive Vapor Emissions for Wet Sulfuric Acid Process

H2S

H2S Conc

Per Train Total %v lb/hr/component lb/hr % lb/hr TPY

Valves Acid Gas 10 20 44.00 0.00890 0.0783 0 0.0783 0.3430

Flanges Acid Gas 100 200 44.00 0.00290 0.2552 0 0.2552 1.1178

Compressor Seals Acid Gas 0 0 44.00 0.50270 0 0 0.0000 0.0000

Pump Seals Acid Gas 0 0 44.00 0.03860 0 0 0.0000 0.0000

Relief Valves Acid Gas 2 4 44.00 0.22930 0.4036 0 0.4036 1.7676

Sample Connections Acid Gas 4 8 44.00 0.03300 0.1162 0 0.11616 0.5088

Total H2S 0.8532 3.7372

SO2

SO2 Conc

Per Train Total %v lb/hr/component lb/hr % lb/hr TPY

Valves Acid Gas 0 0 6.20 0.00890 0 0 0.0000 0.0000

Flanges Acid Gas 20 40 6.20 0.00290 0.0072 0 0.0072 0.0315

Compressor Seals Acid Gas 0 0 6.20 0.50270 0 0 0.0000 0.0000

Pump Seals Acid Gas 0 0 6.20 0.03860 0 0 0.0000 0.0000

Relief Valves Acid Gas 0 0 6.20 0.22930 0 0 0.0000 0.0000

Sample Connections Acid Gas 4 8 6.20 0.03300 0.0164 0 0.01637 0.0717

Total SO2 0.0236 0.1032

SO3

SO3 Conc

Per Train Total %v lb/hr/component lb/hr % lb/hr TPY

Valves Acid Gas 0 0 3.30 0.00890 0.0000 0 0.0000 0.0000

Flanges Acid Gas 30 60 3.30 0.00290 0.0057 0 0.0057 0.0251

Compressor Seals Acid Gas 0 0 3.30 0.50270 0 0 0.0000 0.0000

Pump Seals Acid Gas 0 0 3.30 0.03860 0 0 0.0000 0.0000

Relief Valves Acid Gas 0 0 3.30 0.22930 0.0000 0 0.0000 0.0000

Sample Connections Acid Gas 3 6 3.30 0.03300 0.0065 0 0.00653 0.0286

Total SO3 0.0123 0.0538

Total SO3 as H2SO4 0.01504 0.0659

H2SO4 Vapor

Acid Conc

Per Train Total %v lb/hr/component lb/hr % lb/hr TPY

Valves Acid Gas 0 0 3.60 0.00890 0.0000 0 0.0000 0.0000

Flanges Acid Gas 10 20 3.60 0.00290 0.0021 0 0.0021 0.0091

Compressor Seals Acid Gas 0 0 3.60 0.50270 0 0 0.0000 0.0000

Pump Seals Acid Gas 0 0 3.60 0.03860 0 0 0.0000 0.0000

Relief Valves Acid Gas 0 0 3.60 0.22930 0.0000 0 0.0000 0.0000

Sample Connections Acid Gas 1 2 3.60 0.03300 0.0024 0 0.00238 0.0104

Total H2SO4 0.0045 0.0196

Total H2SO4 including SO3 0.020 0.0854

Notes:

1 Component counts are preliminary subject to change during detailed project engineering.

2 Emissions factors and control efficiencies from TCEQ 28VHP LDAR Program.

3 Relief valves discharge to flare.

FUGITIVES

Uncontrolled 

Emissions

Control 

Efficiency

Process Emission Factors

Stream

Emission Factors

Process Emission Factors

Stream

Uncontrolled 

Emissions

Control 

Efficiency

Uncontrolled 

Emissions

Process 

Stream

Component

Count

Controlled Emissions

Controlled Emissions

Control 

Efficiency Controlled Emissions

Component

Count

Component

Count Controlled Emissions

Uncontrolled 

Emissions

Fugitive Source Process 

Stream

Component

Count

Emission Factors

Fugitive Source

Fugitive Source

Fugitive Source

Control 

Efficiency
Page 5 of 6 TSD App A

NAME Fugitive Emissions - Greenhouse Gas Emissions Only (from Gasification/SNG and from WSA) Unit ID: FUG & FUG-WSA

CO2 in WSA (FUG-WSA)

Total Average Uncontrolled Control Controlled Controlled

Emission Source Source Component Conc Emissions Total Emissions Efficiency Total Emissions Total Emissions

Process Stream Count %w Factor lb/hr lb/hr % lb/hr tpy

Valves Acid Gas 20 42.90 0.00890 0.076 0.0764 0.3345

Flanges Acid Gas 200 42.90 0.00290 0.249 0.2488 1.0898

Compressor Seals Acid Gas 0 42.90 0.50270 0.000 0.0000 0.0000

Pump Seals Acid Gas 0 42.90 0.03860 0.000 0.0000 0.0000

Relief Valves Acid Gas 4 42.90 0.22930 0.393 0.3935 1.7234

Sample Connections Acid Gas 8 42.90 0.03300 0.113 0.1133 0.4961

Total 0.832 0.8319 3.644

Carbon Dioxide from FUG

CO2 Emissions Factor Uncontrolled Control Controlled Controlled

Emission Source Source Component Conc lb/hr/component Total Emissions Efficiency Total Emissions Total Emissions

Process Stream Count %v (discounted by %v) lb/hr % lb/hr tpy

Valves Raw Syngas 100 6.2 0.001 0.055 0.0554 0.243

Shifted Syngas 50 23.6 0.002 0.105 0.1049 0.460

Mixed Syngas 100 32.2 0.003 0.287 0.2867 1.256

Sweet Syngas 20 6.3 0.001 0.011 0.0112 0.049

CO2 30 99.0 0.009 0.264 0.2643 1.158

Flanges Raw Syngas 250 6.2 0.000 0.045 0.0451 0.198

Shifted Syngas 100 23.6 0.001 0.068 0.0684 0.299

Mixed Syngas 250 32.2 0.001 0.234 0.2335 1.023

Sweet Syngas 50 6.3 0.000 0.009 0.0092 0.040

CO2 60 99.0 0.003 0.172 0.1723 0.754

Compressor Seals Raw Syngas 0 6.2 0.031 0.000 0 0.0000 0.000

Shifted Syngas 0 23.6 0.119 0.000 0 0.0000 0.000

Mixed Syngas 0 32.2 0.162 0.000 0 0.0000 0.000

Sweet Syngas 0 6.3 0.032 0.000 0 0.0000 0.000

CO2 16 99.0 0.498 7.963 0 7.9628 34.877

Pump Seals Raw Syngas 0 6.2 0.002 0.000 0.0000 0.000

Shifted Syngas 0 23.6 0.009 0.000 0.0000 0.000

Mixed Syngas 0 32.2 0.012 0.000 0.0000 0.000

Sweet Syngas 0 6.3 0.002 0.000 0.0000 0.000

CO2 0 99.0 0.038 0.000 0.0000 0.000

Relief Valves Raw Syngas 20 6.2 0.014 0.286 0.2856 1.251

Shifted Syngas 4 23.6 0.054 0.216 0.2162 0.947

Mixed Syngas 8 32.2 0.074 0.591 0.5909 2.588

Sweet Syngas 4 6.3 0.014 0.058 0.0580 0.254

CO2 3 99.0 0.227 0.681 0.6810 2.983

Sample Connections Raw Syngas 2 6.2 0.002 0.004 0.0041 0.018

Shifted Syngas 2 23.6 0.008 0.016 0.0156 0.068

Mixed Syngas 2 32.2 0.011 0.021 0.0213 0.093

Sweet Syngas 2 6.3 0.002 0.004 0.0042 0.018

CO2 2 99.0 0.033 0.065 0.0653 0.286

Total 11.091 11.1559 48.863

48.577
Methane from FUG Page 6 of 6 TSD App A

CH4 Uncontrolled Control Controlled Controlled

Emission Source Source Component Conc Emissions Factor Total Emissions Efficiency Total Emissions Total Emissions

Process Stream Count %v lb/hr/component lb/hr % lb/hr tpy

Valves Raw Syngas 100 0.025 0.000 0.000 0 0.0002 0.001

Shifted Syngas 50 0.025 0.000 0.000 0 0.0001 0.000

Mixed Syngas 100 0.060 0.000 0.001 0 0.0005 0.002

Sweet Syngas 20 0.063 0.000 0.000 0 0.0001 0.000

Fuel Gas 25 94.2 0.008 0.210 0 0.2096 0.918

SNG 10 94.2 0.008 0.084 0 0.0838 0.367

Flanges Raw Syngas 250 0.025 0.000 0.000 0 0.0002 0.001

Shifted Syngas 100 0.025 0.000 0.000 0 0.0001 0.000

Mixed Syngas 250 0.060 0.000 0.000 0 0.0004 0.002

Sweet Syngas 50 0.063 0.000 0.000 0 0.0001 0.000

Fuel Gas 30 94.2 0.003 0.082 0 0.0820 0.359

SNG 20 94.2 0.003 0.055 0 0.0546 0.239

Compressor Seals Raw Syngas 0 0.025 0.000 0.000 0 0.0000 0.000

Shifted Syngas 0 0.025 0.000 0.000 0 0.0000 0.000

Mixed Syngas 0 0.060 0.000 0.000 0 0.0000 0.000

Sweet Syngas 0 0.063 0.000 0.000 0 0.0000 0.000

Fuel Gas 0 95 0.008 0.000 0 0.0000 0.000

Fuel Gas 0 94.2 0.474 0.000 0 0.0000 0.000

SNG 4 94.2 0.474 1.894 0 1.8942 8.296

Pump Seals Raw Syngas 0 0.025 0.000 0.000 0 0.0000 0.000

Shifted Syngas 0 0.025 0.000 0.000 0 0.0000 0.000

Mixed Syngas 0 0.060 0.000 0.000 0 0.0000 0.000

Sweet Syngas 0 0.063 0.000 0.000 0 0.0000 0.000

Fuel Gas 0 94.2 0.036 0.000 0 0.0000 0.000

SNG 0 94.2 0.036 0.000 0 0.0000 0.000

Relief Valves Raw Syngas 20 0.025 0.000 0.001 0 0.0011 0.005

Shifted Syngas 4 0.025 0.000 0.000 0 0.0002 0.001

Mixed Syngas 8 0.060 0.000 0.001 0 0.0011 0.005

Sweet Syngas 4 0.063 0.000 0.001 0 0.0006 0.003

Fuel Gas 1 94.2 0.216 0.216 0 0.2160 0.946

SNG 2 94.2 0.216 0.432 0 0.4320 1.892

Sample Connections Raw Syngas 2 0.025 0.000 0.000 0 0.0000 0.000

Shifted Syngas 2 0.025 0.000 0.000 0 0.0000 0.000

Mixed Syngas 2 0.060 0.000 0.000 0 0.0000 0.000

Sweet Syngas 2 0.063 0.000 0.000 0 0.0000 0.000

Fuel Gas 0 94.2 0.031 0.000 0 0.0000 0.000

SNG 1 94.2 0.031 0.031 0 0.0311 0.136

Total 2.977 3.0082 13.176

TPY CO2e from FUG= 325.56

Notes:

1 Component counts are preliminary subject to change during detailed project engineering.

2 Emissions factors and control efficiencies from TCEQ 28VHP LDAR Program.

3 Relief valves discharge to flare
Page 1 of 3 TSD App A 

Emission Unit Emission Description

FUG-ROAD-C (Coal Trucks) Fugitive Dust: Paved Road Truck Traffic for Coal/Coke delivery by Truck

Calculation Methodology

Calculation of Potential Emissions:

Average Round-Trip Distance: 0.479 mile/trip "Wet" Days, P: 117 days

Road Surface Silt Loading, sL: 1.0 g/m2 Days in Ave. Period, N: 365 days

Average Truck Weight, W: 25.7 tons Highest Day Wet Coal 249.1 tons/hr 50% plant capacity

Particle Size Multiplier, k: 0.0022 PM10 Carried each Load: 32.0 tons/truck

Particle Size Multiplier, k: 0.00054 PM2.5 Truck Trips: 186.8 trip/day

Particle Size Multiplier, k: 0.011 PM Truck Trips: 100.9 54% of daily trips

Potential PM10 Emissions:

EP Max lb/hr lb/day tpy

FUG-ROAD-C (Coal Trucks) 0.0225 0.54 0.0906

Potential PM2.5 Emisions:

EP Max lb/hr lb/day tpy

FUG-ROAD-C (Coal Trucks) 0.0055 0.13 0.0222

Potential PM Emissions:

EP Max lb/hr lb/day tpy

FUG-ROAD-C (Coal Trucks) 0.1124 2.70 0.4531

CALCULATION SHEET

Control Efficiency for 

Watering: 90%

daily trip 

(yr avg)

AP-42 Chapter 13, Section 2.1 : Miscellaneous Sources, Paved Roads

Max Hourly and Daily Emissions calculated using equation (1)

Annual Emissions calculated using equation (2)

k factor from Table 13.2.1-1

PM = 0.011

PM10 = 0.0022

PM2.5 = 0.00054

Road Surface Silt Loading, sL = 1.0 g/m2 (Conservative value considering planned frequent watering)

EmptyTruck weight = 9.7 tons

Full Truck weight = 41.7 tons

"Wet" days, P = 117 days

Number of days in averaging period, N = 365

    0.91 1.02 E  k sL  W

Eext k   sL W   1 P/4N 0.91 1.02   

16_30464 Calcs H 85 5/3/2012
Page 2 of 3 TSD App A

Emission Unit Emission Description

FUG-ROAD-S (Slag) Fugitive Dust: Paved Roads for Slag Truck Hauling

Calculation Methodology

Calculation of Potential Emissions:

T t l R d T i Di t 0 644 il /t i "W t" D P 117 d

CALCULATION SHEET

AP-42 Chapter 13, Section 2.1 : Miscellaneous Sources, Paved Roads

Max Hourly and Daily Emissions calculated using equation (1) emissions factor

Annual Emissions calculated using equation (2) emissions factor

k factor from Table 13.2.1-1

PM = 0.011

PM10 = 0.0022

PM2.5 = 0.00054

EmptyTruck weight = 9.7 tons

Load each trip = 20 tons

"Wet" days, P = 117 days

Number of days in averaging period, N = 365

Trip Distance = 600 ft, each way in process block (normal). Additionally, if slag hauled to coal yard temporary storage, then it must travel 900 

feet offsite to coal yard area, then it travels 1100 feet in coal yard to drop off and 1100 feet in coal yard to pick up. (worse-case total = 

600+600+1100+1100 excluding the portion of travel "offsite"/outside the fenceline.)

Emissions calculated = Emissions factor (lb/vmt) * trip distance (miles) * number of trips * (1-control efficiency)

   0.91 1.02 E  k sL  W

Eext k   sL W   1 P/4N 0.91 1.02   

Total Round-Trip Distance: 0.644 mile/trip "Wet" Days, P: 117 days

Road Surface Silt Loading, sL: 1.0 g/m2 Days in Ave. Period, N: 365 days

Average Truck Weight, W: 19.7 tons Slag Production: 43.08 tons/hr

Particle Size Multiplier, k: 0.0022 PM10 Carried each Load: 20.0 tons/truck

Particle Size Multiplier, k: 0.00054 PM2.5 Truck Trips: 82.7

Particle Size Multiplier, k: 0.011 Total PM

Potential PM10 Emissions:

EP Max lb/hr lb/day tpy Process Road Segment

FUG-ROAD-S (Slag) 0.0102 0.24 0.0411 PM10 0.0036 lb/hr

PM2.5 0.00088 lb/hr

Potential PM2.5 Emisions: Total PM 0.01801 lb/hr

EP Max lb/hr lb/day tpy

FUG-ROAD-S (Slag) 0.0025 0.06 0.0101 Coal Yard Road Segment

PM10 0.0066 lb/hr

Potential Total PM Emisions: PM2.5 0.0016 lb/hr

EP Max lb/hr lb/day tpy Total PM 0.0330 lb/hr

FUG-ROAD-S (Slag) 0.0510 1.22 0.2056

Control Efficiency for 

Watering: 90%

trip/day (includes 31 

trucks/day contingency)

   0.91 1.02 E  k sL  W

Eext k   sL W   1 P/4N 0.91 1.02   
Page 3 of 3 TSD App A 

Emission Unit Emission Description

EU-034A Handling (Drop) emissions for handling/loading Slag at temp. Storage pile.

Calculation Methodology

Assume that slag dumped from trucks coming from process is so wet that there are no emissions.

Then assume slag is picked up by front end loader and loaded into truck for haulting out (1 handling step)

Assume watering used to keep slag wet Control effectiveness of watering reflected in assumed moisture content

CALCULATION SHEET

Also assume when/if slag is initially picked up by front end loader and piled or moved within storage site that it is still 

wet enough to not have emissions

AP-42 Chapter 13, Section 2.4:Aggregate Handling and Storage Piles

Uncontrolled Emissions per handling step calculated using equation (1)

Where:

E = emissions factor in lbs emissions per ton aggregate handled

U = mean wind speed, mph 

M = material moisture content 

k = particle size multplier (dimensionless)

Total PM k = 0.74

PM10 k = 0.35

PM2.5 k = 0.053

 

1.3

1.4

5 0.0032

2

U

E k

M

      

     

 

1.3

1.4

5 0.0032

2

U

E k

M

      

     

Assume watering used to keep slag wet. Control effectiveness of watering reflected in assumed moisture content.

Calculation of Potential Emissions:

Number of Drops(handling steps) 1.000 drops Maximum daily slag 1,034 tons/day max

Mean wind speed 8.0 mph Max hourly slag 43.08 tons/hr

Material Moisture content 15.00 % Annual Slag Production: 720.0 tons/day annual average

Particle Size Multiplier, k: 0.35 PM10 Average hourly slag 30 tons/hr annual average

Particle Size Multiplier, k: 0.053 PM2.5 Hours per yr of activity 8760.0

Particle Size Multiplier, k: 0.74 Total PM

Potential PM10 Emissions:

EP Max lb/hr Max lb/day tpy

EU-034A 0.0053 0.13 0.0161

Potential PM2.5 Emisions:

EP Max lb/hr lb/day tpy

EU-034A 0.0008 0.02 0.0024

Potential Total PM Emisions:

EP Max lb/hr lb/day tpy

EU-034A 0.0112 0.27 0.0341

Control Efficiency for 

Watering

Addressed by moisture 

content assumption

 

1.3

1.4

5 0.0032

2

U

E k

M

      

     

 

1.3

1.4

5 0.0032

2

U

E k

M

      

     
Although Storage Pad is paved, assume it is partially covered in slag, calculate emissions assuming unpaved road equation.Description of Vehicles Load Size

Vehicle Weight 

Empty

Average 

Vehicle 

Weight

Daily Slag 

(annual 

average)

Max Slag 

per day

Miles per 

trip

Maximum 

Daily Ave Annu

tons tons tons tons/day tons/day Mile/trip Trips/day Trips/day 

Front End Loader 20 32.66 26.33 1,440 2,068 0.0142 103.4 72 

Assume each trip of front end loader trip is 75 feet round trip (1/4 width of pad times 2)

Average 

Vehicle weigh 

(tons)

Uncontrolled 

Emissions 

factor (lbs total 

PM/VMT)

Uncontrolled 

Emissions 

factor (lbs 

PM10/VMT)

Uncontrolled 

Emissions 

factor (lbs 

PM2.5/VMT)

Control 

Efficiency

Max daily 

lb/hr Total 

PM

Max daily 

lb/hr PM10

Max daily 

lb/hr PM2

Front End Loader/dozer 26.33 2.287 0.426 0.043 90% 0.014 0.003 0.000 

Total 0.014 0.003 0.000

Max Annual 

Tons/yr 

Total PM

Max Annual 

Tons/yr 

PM10

Max Annu

Tons/yr 

PM2.5

0.007 0.001 0.000 

Note: Slag handled is slag production assuming that slag is either delivered to or picked up from the storage pad each day. (Not being dropped off all day picked up all day on the same day).

EU-034C Emission Calculation for Front-End Loader and Slag truck Activity on the temp. Slag storage pad/pile

Total 0.007 0.001 0.000

UNPAVED ROADS EQUATIONS Industrial Roads - AP42 13.2.4 (equations 1a and 2)

E = size specific emission factor (lbs/VMT)

k = particle size multiplier for particle size range (lb/VMT)s = surface material silt content (%) 

a = constant based on size of particulateb = constant based on size of particulate

W = Vehicle average weight (tons)

P = number of days per year with 0.01 in or more of precipitation

INPUTS TO EQUATION/CALCULATIONS Total PM PM10 PM2.5

k 4.9 1.5 0.15 lb/vmt

s1 1 1 %

a 0.7 0.9 0.9b 0.45 0.45 0.45

P 117 117 117 days/yr

    12

3 * s * Wa b

E



k 

 

  

365

365

P

E ext

E
Page 1 of 1 TSD App A

Indiana Gasification, LLC Spencer County Facility 

Emission Unit:

FUG‐SF6 Emission Estimate for Fugitive Emissions of SF6 from Circuit Breakers

The IG facility will include a switchyard with circuit breakers that include

sulfur hexafluoride (SF6), a greenhouse gas, as a gaseous dielectric.

The circuit breakers will be totally enclosed and pressurized.

Fugitive emissions are estimated as 1% leakage per year.

Emission Calculation

Number of circuit break 6

Amount of SF6 in each 100 lbs

Assumed leak rate: 1%

Emissions (lb/yr): 6 lbs/yr

GWP of SF6: 23,900

CO2e (tons/yr): 71.7 tons/yr
Basis: 100%w Coal with Gasifier Methanol Startups 8,339,799.29

4 Operating GE Quench Gasifiers (design capacity x 1.25) Page 1 of 3 TSD App A

10,401 STPD dry coal (design capacity x 1.25)

12,968 BTU/lb dry HHV/lb coal design 

11,240 MMBTU/hr HHV coal (design capacity x 1.25)

3.66 %wt dry sulfur in coal during normal operation

600 MMSCFD H2+CO2 Total Raw Syngas from Gasifiers (design capacity x 1.25)

154 MMSCFD SNG Gross Production (design capacity x 1.25)

302.2 MMSCFD CO2 Captured 

0 MMSCFD CO2 to EOR Pipeline

1,164 STPD 100%w H2SO4

Installed Operating Preliminary

Number of 

Stacks

Number of 

Stacks

Stack Height 

feet Rating Units lb/MMBTU lb/hr Tons/yr lb/MMBTU lb/hr Tons/yr

001 Gasifier Startup Flare Emissions (methanol fuel) - 90 per year at 90 min 1 1 300 862 MMBtu/h HHV 8760

001 Syngas Flare - Nat Gas Pilots 1 1 300 0.27 MMBtu/h HHV 8760 1.65E-06 4.376E-07 0.0000019 2.90E-06 7.69E-07 0.0000034

002 Acid Gas Flare - Nat Gas Pilots 1 1 300 0.27 MMBtu/h HHV 8760 1.65E-06 4.376E-07 0.0000019 2.90E-06 7.69E-07 0.0000034

005 Auxiliary Boiler, Full Load Operation - black plant su (nat gas fuel) 1 1 200 816 MMBtu/h HHV 8760 2.55E-07 2.081E-04 0.0009072 4.90E-07 4.00E-04 0.0017447

005 Auxiliary Boiler, Full Load Operation (SNG or Nat Gas) 1 1 200 816 MMBtu/h HHV 8760 1.65E-06 1.347E-03 0.0058725 2.90E-06 2.37E-03 0.0103217

005 Auxiliary Boiler, Half Load Operation (SNG or Nat Gas) 1 1 200 408 MMBtu/h HHV 0 1.65E-06 6.735E-04 0.0029363 2.90E-06 1.18E-03 0.0051608

008 Gasifier Preheat Burners - black plant su (nat gas fuel) 5 5 200 35 MMBtu/h HHV 8760 2.55E-07 8.922E-06 0.0000389 4.90E-07 1.72E-05 0.0000748

008 Gasifier Preheat Burners (one operating 8 months per year, SNG or NG fuel 5 1 200 18 MMBtu/h HHV 8760 1.65E-06 2.970E-05 0.0001295 2.90E-06 5.22E-05 0.0002276

009 Emergency Diesel Generators (2 units each tested 1 hour weekly) 2 1 20 1,341 hp 500

010 Diesel Fire Water Pump Engine (3 units each tested 1 hour weekly) 3 1 20 575 hp 500

011 Coal Conveying and Feed Bins Dust Control System Vents 2 1 200 8760 1.244E-06 0.0000054 2.42E-04 0.0010546

012 Coal Unloading and Storage (Barge, Rail, Truck) 0.0000000 0.0000000

013 Rod Mill Vent Stacks 4 4 125 8760 0.0000000 0.0000000

032 ZLD Spray Drier Stack 1 1 100 5.6 MMBtu/h HHV 8760 1.65E-06 9.294E-06 0.0000405 2.90E-06 1.63E-05 0.0000712

033 ZLD Inert Gas Vent 1 1 100 8760 1.404E-07 0.0000006

015 WSA Preheat 2 1 200 35.0 MMBtu/h HHV 8760 1.65E-06 5.775E-05 0.0002518 2.90E-06 1.02E-04 0.0004425

015 WSA Stack - black plant su 2 1 213 291

stpd 100% 

H2SO4 8760 8.348E-11 0.0000000

015 WSA Stack - One Unit Operation 2 1 213 582

stpd 100% 

H2SO4 8760 1.670E-10 0.0000000

015 WSA Stack - Two Unit Operation 2 2 213 1,164

stpd 100% 

H2SO4 8760 3.339E-10 0.0000000

16a Cooling Tower -ASU 6 6 65 8760

16b Cooling Tower -Main 24 24 65 8760

017 ASU Molecular Sieve Regeneration Vents 2 Int 60 8760

024 Methanol Storage Scrubber Vent Stack 1 Int 30 8760

Fugitive Emissions - Gasification, Shift Conversion, Rectisol, Methanation NA NA 8760

Fugitive Emissions - WSA NA NA 8760

Plant Totals without CO2 Venting 0.002336 0.01 0.004382 0.02

RTO Case

007 Regen Thermal Oxidizers -black plant su, one gasifier op (nat gas fuel) 1 1 200 19.4

MMBtu/h HHV 

NG 8760 1.65E-06 3.202E-05 0.0001396 2.90E-06 5.63E-05 0.0002454

007 Regen Thermal Oxidizers (Note 1, Two Units Hot Standby 80% of the year, SNG 1 1 200 10.3

MMBtu/h HHV 

SNG 0 1.65E-06 1.705E-05 0.0000743 2.90E-06 3.00E-05 0.0001307

007 Regen Thermal Oxidizers (Note 1, One Unit Op, SNG fuel) 1 1 200 38.8

MMBtu/h HHV 

SNG 8760 1.65E-06 6.404E-05 0.0002792 2.90E-06 1.13E-04 0.0004907

007 Regen Thermal Oxidizers (Note 1, Two Units with common, SNG fuel) 1 1 200 77.6

MMBtu/h HHV 

SNG 8760 1.65E-06 1.281E-04 0.0005584 2.90E-06 2.25E-04 0.0009815

007 RTO Totals 0.000241 0.00 0.000199 0.001848

Plant Totals with 100% CO2 to RTO 0.002578 0.01 0.004581 0.02

Notes:

1 Mercury and lead emissions are based on firing SNG in pilots, aux boiler and WSA preheater except for black plant su. RTO Hg and Pb emissions are based on SNG including black plant su.

Rated in terms of Plant 

Capacity

Mercury 

Rated in terms of Plant 

Capacity

Rated in terms of Plant 

Capacity

Rated in terms of Plant 

Capacity

Rated in terms of Plant 

Capacity

Rated in terms of Plant 

Capacity

Lead

Rated in terms of Plant 

Capacity

EPN # Emission Units

Estimated 

Annual 

Operating 

Hours

Operating Rate
Indiana Gasification, LLC Page 2 of 3 TSD App A

Plant Mercury Balance for 125% of design plant operating rate

Mercury in Natural Gas:

2.60E-04 lb mercury/MMSCF natural gas from EPA AP-42 Natural Gas Combustion

1.02E+03 BTU/SCF natural gas HHV from EPA AP-42 Natural Gas Combustion 

2.55E-07 lb mercury/MMBTU HHV natural gas calculated

Mercury in Solids Feed to Gasifiers:

0.11 ppm dry mercury is average reported by Indiana Geological Survey 2004 Characterization of Indiana's Coal Resource Table 24A

0.86 ppm dry mercury is maximum reported by Indiana Geological Survey 2004 Characterization of Indiana's Coal Resource Table 24A

Total Mercury max Mercury max

stph dry ppm, dry lb/hr

Coal: 433.38 0.86 0.745

Coke: 0.00 0.05

Total coal + coke 433.38 0.745

Output streams: max mercury

Slag 0% mercury in gasifier feed goes out in slag (maximum Hg to wastewater)

0.0000 lb/hr Hg in slag

Wastewater 2% mercury in gasifier feed goes out in gasification process wastewater

0.0149 lb/hr Hg in gasification process wastewater

0.5 ppbv Hg in ZLD vent gas from sulfided carbon mercury removal guaranteed

1.4 lb-mole/hour ZLD vent gas

7E-10 lb-moles/hour mercury in ZLD vent gas

200.59 lb/lb-mole mercury molecular weight

1.40E-07 lb/hr mercury in ZLD vent gas

1.49E-02 lb/hr mercury removed by sulfided carbon

Syngas to Sulfided Carbon 98% mercury in gasifier feed is in syngas to mercury removal

0.7305 lb/hr Hg in syngas to mercury removal

Syngas from Sulfided Carbon 0.5 ppbv Hg in syngas from mercury removal guaranteed

103,526 lb-moles/hr total syngas from mercury removal

5.18E-05 lb-moles/hr Hg in syngas from mercury removal

0.010 lb/hr mercury in syngas to Rectisol

98.6% mercury removal on sulfided carbon

Rectisol Treated Syngas 66,958 lb-moles/hr treated syngas from Rectisol

-27 F Treated Rectisol syngas from absorber

99.99998% Hg in syngas to Rectisol assumed to be in syngas from Rectisol (worst case no accumulation in Rectisol)

0.0104 lb/hr mercury in syngas from Rectisol

0.77 ppbv Hg in Rectisol treated syngas

SNG 0.0104 lb/hr mercury in SNG

2.94 ppbv Hg in SNG

6,293 MMBTU/hr HHV SNG rate

1.65E-06 lb Hg/MMBTU HHV SNG

Rectisol CO2 33,184 lb-moles/hr CO2 from Rectisol

-42 F CO2 Temperature from MP Flash

1.45E-08 lb Hg solubility/lb Methanol

3.28E-06 Vapor pressure of Hg, mbar

2.89E-07 ppbv Hg in CO2 from Rectisol

1.92E-09 lb/hr Hg in CO2 

Rectisol Acid Gas 3,264 lb-moles/hr acid gas from Rectisol

-31 F acid gas temperature at the acid gas separator

2.71E-08 lb Hg solubility/lb Methanol

4.98E-06 Vapor pressure of Hg, mbar at -31F

5.10E-07 ppbv Hg in acid gas from Rectisol

3.34E-10 lb/hr Hg in acid gas

Coal Particulate Emissions 1.45 lb/hr coal dust from Coal Conveying and Feed Bins Dust Control System Vents

1.24E-06 lb/hr mercury in coal dust from coal converying and feed bins dust control system vents

1.09E-02 lb/yr mercury in coal dust from coal conveying and feed bins dust control system vents

10.39 tons per year coal dust from coal unloading and storage

1.79E-02 lb/yr mercury in coal dust from coal unloading and storage

0.44 tons per year coal dust from rod mills

7.57E-04 lb/yr mercury in coal dust from rod mills
Indiana Gasification, LLC Page 3 of 3 TSD App A

Plant Lead Balance for 125% of design plant operating rate

Natural Gas Combustion

5.00E-04 lb lead/MMSCF natural gas from EPA AP-42 Natural Gas Combustion

1.02E+03 BTU/SCF natural gas HHV from EPA AP-42 Natural Gas Combustion 

4.90E-07 lb lead /MMBTU HHV natural gas calculated

SNG Combustion

Lead in Solids Feed to Gasifiers:

21.36 ppm dry lead is average reported by Indiana Geological Survey 2004 Characterization of Indiana's Coal Resource Table 46A

167.17 ppm dry lead is maximum reported by Indiana Geological Survey 2004 Characterization of Indiana's Coal Resource Table 46A

Total Lead max Lead max

stph dry ppm, dry lb/hr

Coal: 433.38 167.17 144.89

Coke: 0.00 0.5

Total coal + coke 433.38 144.89

Output streams: max lead

Slag 33% lead in gasifier feed goes out in slag per LGTI Gasification Plant metal mass balances (2002 IGCC Environmental Assessment by SAIC & NETL)

47.82 lb/hr lead in slag 

SNG 2.90E-06 lb/MMBTU HHV SNG based on LGTI Gasification Plant metal mass balances (2002 IGCC Environmental Assessment by SAIC & NETL)

6,293 MMBTU/hr HHV SNG rate

0.0182 lb/hr lead in SNG

Accumulation 97.06 lb/hr lead accumulated on shift catalyst, sulfided carbon beds, sulfur guard beds, methanation catalyst, and liquid filters

Coal Particulate Emissions 1.45 lb/hr coal dust from Coal Conveying, Storage and Feed Bins Dust Control System Vents

2.42E-04 lb/hr lead in coal dust from coal converying, storage and feed bins dust control system vents

2.12 lb/yr lead in coal dust from coal conveying and feed bins dust control system vents

10.39 tons per year coal dust from coal unloading and storage

3.47 lb/yr lead in coal dust from coal unloading and storage

0.44 tons per year coal dust from rod mills

0.15 lb/yr lead in coal dust from rod mills

Solid particulates Emission rate:

Emission Point Source cfm dscfm

Emission 

Rate, lb/hr

11a 30,000 33,760 1.4469

11b (spare) 30,000 33,760 

Notes: 

Note 1: All sources (Coal & Coke Dust Collectors) will be fabric filter units with exhaust fans and will be specified to have a dust

emissions limit, as measured in gr/dscf, equal to: 0.005 grains per drscf
FLARE SOURCES Page 1 of 3 TSD App A

NAME Hydrocarbon / Gasifier Start-up Flare Unit ID: 001

STACK DATA

HEIGHT 300 ft

DIAMETER 6 ft

EMISSIONS: Scenario 1: Gasifier Start-Up Syngas Flaring hr/yr = 135

Firing Rate = 861.7 MMBtu/hr

CO DRE 99.5 %

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb-mol/hr lb-mol/hr lb-mol/hr Mol % lb/hr lb/hr TPY

PM10 -- -- -- -- 6.42 6.42 0.43

PM2.5 6.02 6.02 0.41

SO2 0.01 0 -- -- 0.70 0.70 0.047

NOx -- -- -- -- 86.17 86.17 5.82

CO -- -- 18237.12 13.50 344.70 344.70 23.27

H2S (TAP) 0.01 -- -- -- 0.01 0.01 0.00

COS (TAP)(VOC) -- 0.00 -- -- 0.00 0.00 0.00

Other VOC -- -- -- -- 0.09 0.09 0.01

Total VOC 0.09 0.09 0.01

EMISSIONS: Scenario 2: Gasifier Start-Up Flare Pilot Burners Operating hr/yr = 8,760

Pilot Firing Rate = 0.27 MMBtu/hr

AP-42 Heating Value = 1,020 Btu/scf

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb/hr lb/hr TPY

PM10 0.0020 0.0020 0.0087

PM2.5 0.0019 0.0019 0.0081

SO2 0.0002 0.0002 0.00068

NOx 0.053 0.053 0.23

CO 0.013 0.013 0.06

VOC 0.005 0.005 0.02

Total VOC HAPs 0.0005 0.0005 0.0022

Mercury (HAP) 4.4E-07 4.4E-07 1.9E-06

TOTAL STARTUP FLARING AND PILOT

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb/hr lb/hr TPY

PM10 0.101 6.42 0.44

PM 0 095 6 02 0 41

H2S in Syngas COS in Syngas

Raw Syngas 

Flared CO in Syngas

PM2.5 0.095 6.02 0.41

SO2 0.01 0.70 0.048

NOx 1.38 86.22 6.05

CO 5.33 344.71 23.33 

H2S (TAP) 0.005 0.01 0.02

COS (TAP)(VOC) 0.00 0.00 0.00

Total VOC 0.0067 0.09 0.03

Total VOC HAPs 0.0005 0.0005 0.0022

Mercury (HAP) 4.4E-07 4.4E-07 1.9E-06
Calculations: Page 2 of 3 TSD App A

Scenario 1:

Emissions (SO2)(Avg. lb/hr)=H2S in Syngas (lb-mol/hr) + COS in Syngas (lb-mol/hr) X 64.063 lb/mol

Emissions (CO)(Avg. lb/hr)=(Raw Syngas flared (lbmols/hr) X CO in Syngas (mol %)/100) X 28.01 lb/mol X (100 - CO DRE)/100

Emissions (H2S)(Avg. lb/hr)=H2S in Syngas (lb-mol/hr) X 34.08 lb/mol X 2/100

Emissions (COS)(Avg. lb/hr)=COS in Syngas (lb-mol/hr) X 60.0764 lb/mol X 2/100

Emissions (NOx, PM10, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

Scenarios 2 and 3:

Emissions (PM10, SO2)(Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft

3

) X Heat Input (MMBtu/hr)

Emissions (NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions-Pilot Case (SO2, NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

NOx PM10 VOC

0.100 0.007 0.0001

PM10 SO2

7.600 0.60

NOx CO VOC

0.200 0.050 0.020

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

Number Shutdown Flaring Events / year = 15

Flaring Event Duration (hrs) = 3

Firing Rate (MMBtu/Event) = 34.26

SHUTDOWN FLARING

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb/event lb/hr TPY

Scenario 2

Factor (lb/MMBtu)

Sources: NOx and CO, and VOC are based on values from vendor supplied data. 

Mercury Factor (lb/MMBtu)

DRE for H2S and COS is considered as 98%.

DRE for CO is considered as 99.5%.

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs for natural gas to the pilot are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4. Flared gas is primarly CO and H2 - HAPs assumed negligable.

Scenario 1: Gasifier Start-up Syngas Flaring

Scenario 2: Gasifier Start-up Flare Pilot Burners Operating 

Scenario 3: Normal Operations-Purge Gas and Pilot Gas Flaring

Scenario 1

Factor (lb/MMBtu)

Sources: NOx and PM10 for Syngas are based on values from vendor supplied data. VOC for Syngas = 2% of AP-42 Section 1.4 "Natural Gas Combustion" Table 1.4-2 

Scenario 2

Factor (lb/MMscf)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for PM10. 

PM10 0.260 0.09 0.002

PM2.5 0.260 0.09 0.002

SO2 255.62 85.21 1.917

NOx 3.43 1.14 0.026

CO 21.22 7.07 0.159

H2S (TAP) 2.660 0.89 0.020

COS (TAP)(VOC) 0.20 0.07 0.002

VOC 0.0037 0.00 0.000
Page 3 of 3 TSD App A

GHG Emissions from Gasifier Start-up

lb/hr TPY MT/yr

CO2 for Gasifier Flare = 185,818.1 12,542.7 11378.8

Equation Y-5

N2O = Annual nitrous oxide emissions from flared gas (metric ton N2O/year)

CO2 = Emission rate of CO2 from flared gas calculated (metric ton/year)

EmFN2O = Default N2O emission factor for “Petroleum Products” from Table C-2 of subpart C (General Stationary Fuel Combustion Sources) (kg N2O/MMBtu) = 0.0006

EmF = Default CO2 emission factor for flare gas of 60 kg CO2/MMBtu (HHV basis)

N2O for Gasifier Flare = 0.114 MT

GHG Emissions from Pilot

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 123.2 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0023 MT

N2O = 0.0002 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

The feed to the gasifier flare during the start-up of a gasifier contains CO and CO2, but no other carbon compounds. A mass balance was used to determine the CO2 

and N2O emissions. There will be no CH4 emissions. The GHG Subpart Y (Refinery) flare equations are not applicable; however, the Subpart Y equation for N2O will 

be used to conservatively estimate N2O emissions.















   EmF

EmF N O CO N2O

2 2

CO    Fuel  HHV  EF  3

2 1 10

CH orN O    Fuel  HHV  EF  3

4 2 1 10

gaseous fuel 

combusted

Annual 2,277,600 scf

High heat value 

of the fuel from 

all valid samples 

for the year

Annual Average 0.00102 MMBtu per scf

Startup

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 11,379 1 11,379

CH4 0 21 0

N2O 0.114 310 35.3

TOTAL = 11,414 12,578 TPY CO2

Shutdown

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 569 1 569

CH4 0 21 0

N2O 0.006 310 1.8

TOTAL = 571 629 TPY CO2

Shutdown flared gas volume on an annual basis is 5% of startup flared gas volume.

Pilot

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 123.2 1 123.2

CH4 0.0023 21 0.05

N2O 0.0002 310 0.07

TOTAL = 123.3 136 TPY CO2

Hydrocarbon / Gasifier Startup Flare
FLARE SOURCES Page 1 of 2 TSD App A

NAME Acid Gas Flare Unit ID: 002

The Acid Gas Flare normally operates on pilot gas (natural gas) only. During an upset, acid gases can be routed to this flare.

STACK DATA

HEIGHT 300 ft

DIAMETER 1.6 ft

EMISSIONS: Acid Gas Flare Pilot Only

hr/yr = 8,760

Pilot Firing Rate = 0.27 MMBtu/hr

AP-42 Heating Value = 1,020 Btu/scf

Average Maximum Annual

Emissions Emissions Emissions

Pollutant lb/hr lb/hr TPY

PM10 0.0020 0.0020 0.0087

PM2.5 0.0019 0.0019 0.0081

SO2 0.0002 0.0002 0.00068

NOx 0.053 0.053 0.23

CO 0.013 0.013 0.058

VOC 0.005 0.005 0.023

Total VOC HAPs 0.0005 0.0005 0.0022

Mercury (HAP) 4.4E-07 4.4E-07 1.9E-06

CO2 31.00 31.00 136

Calculations:

Emissions (PM10, SO2)(Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

PM10 SO2

7.600 0.60

NOx CO VOC CO2

0.200 0.050 0.020 116.890

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

Source: NOx, CO, and VOC factors from AP-42 Section 13.5 "Industrial Flares" Table 13.5-1

Mercury Factor (lb/MMBtu)

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S).

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

Natural Gas Combustion

Factor (lb/MMscf)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for PM10. 

Flare

Factor (lb/MMBtu)

17_30464 limited Calcs F 4 5/3/2012
Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis) Page 2 of 2 TSD App A

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 123 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0023 MT

N2O = 0.0002 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 2,277,600 scf

High heat value 

of the fuel from 

all valid samples 

for the year

Annual 

Average 0.00102 MMBtu per scf

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 123 1 123

CH4 0.0 21 0

N2O 0.0 310 0

TOTAL = 123 136 TPY CO2

Acid Gas Flare

CO    Fuel  HHV  EF  3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

17_30464 limited Calcs F 5 5/3/2012
COMBUSTION SOURCES Page 1 of 3 TSD App A

NAME Auxiliary Boiler Unit ID: 005A & B

Emissions shown are for sum of two (2) boilers each at 408 MMBtu/hr

STACK DATA

HEIGHT 200 ft

DIAMETER 11 ft

GAS EXIT TEMP- Full rate - Natural Gas 310 °F

GAS EXIT TEMP- Full rate (Black Start) - Natural Gas 310 °F

GAS EXIT VELOCITY - Full rate - Natural Gas 48.73 fps

GAS EXIT VELOCITY - Full rate (Black Start) - Natural Gas 48.73 fps

COMBUSTION DATA

HEAT INPUT - Full rate - Natural Gas 816.33 MM Btu/hr

HEAT INPUT - Full rate (Black Start) - Natural Gas 816.33 MM Btu/hr

HEAT INPUT - Pilot Gas - Natural Gas 10.00 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS- Full rate - Natural Gas 1752 hr/yr

OPERATING HOURS - Full rate (Black Start) - Natural Gas 96 hr/yr

EMISSIONS: Full rate case - Natural Gas

lb/hr avg. lb/hr max. TPY 

PM10 6.08 6.08 5.33

PM2.5 6.08 6.08 5.33

SO2 0.48 0.48 0.42

NOx 10.20 10.20 8.94

CO 29.39 29.39 25.74

VOC 4.40 4.40 3.86

Total VOC HAPs 1.51 1.51 1.32

Mercury (HAP) 1.4E-03 1.4E-03 1.2E-03

EMISSIONS: Full rate (Black Start) case - Natural Gas

lb/hr avg. lb/hr max. TPY 

PM10 6.08 6.08 0.29

PM2.5 6.08 6.08 0.29

SO2 0 48 . 0 48 . 0 023 .

NOx 10.20 10.20 0.49

CO 29.39 29.39 1.41

VOC 4.40 4.40 0.21

Total VOC HAPs 1.51 1.51 0.073

Mercury (HAP) 1.4E-03 1.4E-03 6.6E-05
EMISSIONS: Normal Operations Total Page 2 of 3 TSD App A

lb/hr avg. lb/hr max. TPY 

PM10 1.28 6.08 5.62

PM2.5 1.28 6.08 5.62

SO2 0.10 0.48 0.44

NOx 2.15 10.20 9.43

CO 6.20 29.39 27.15

VOC 0.93 4.40 4.07

Total VOC HAPs 0.32 1.51 1.40

Mercury (HAP) 2.9E-04 1.4E-03 1.3E-03

CALCULATIONS

Emissions (PM10, VOC, and SO2)(Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (NOx, CO) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Total Emissions (Avg. lb/hr) = Total TPY x 2,000 lb/ton / 8,760 hr/yr

Total Emissions (Max. lb/hr) = Highest Maximum lb/hr value from either case

PM10 VOC SO2 HAP

7.600 5.50 0.60 1.89

NOx CO

0.0125 0.036

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

Factor (lb/MMBtu)

Natural Gas Combustion

Factor (lb/MMscf)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10.

Mercury Factor (lb/MMBtu)

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

To be conservative SO2 emissions will be calculated assuming all scenarios fire natural gas If SNG is fired there will be no SO2 emissions as SNG is assumed to contain 

Natural Gas/SNG Combustion

Source: Emission factors for NOx and CO are based on vendor data for Low NOx burners (LNB), SCR and Flue Gas Recirculation. 

To be conservative, SO2 emissions will be calculated assuming all scenarios fire natural gas. If SNG is fired, there will be no SO2 emissions as SNG is assumed to contain 

no sulfur.

To be conservative, the mercury factor for SNG (Coal-Coke) will be used for all cases.

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).
Page 3 of 3 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 79,985 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 1.5086 MT

N2O = 0.1509 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 1,479,000,509 scf

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

combusted

High heat value 

of the fuel from 

all valid samples 

for the year

Annual 

Average 0.00102 MMBtu per scf

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 79,985 1 79,985

CH4 1.5 21 32

N2O 0.2 310 47

TOTAL = 80,063 88,230 TPY CO2

Auxiliary Boiler
COMBUSTION SOURCES Page 1 of 9 TSD App A

NAME AGR CO2 Regenerative Thermal Oxidizer Unit ID: 007

STACK DATA

HEIGHT 200 ft

DIAMETER 9 ft

GAS EXIT TEMP 250 °F

GAS EXIT VELOCITY 60.5 fps

COMBUSTION DATA (max from either case)

HEAT INPUT: Two Units at full rate 77.62 MM Btu/hr

HEAT INPUT: One Unit at full rate 38.81 MM Btu/hr

HEAT INPUT: Black-starts (1 unit at half rate) 19.41 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS: Two Units at full rate 8298 hr/yr

OPERATING HOURS: One Unit at full rate 438 hr/yr

OPERATING HOURS: Black-start 24 hr/yr

H2S in Waste gas to each RTO = 0.57 lb/hr

COS in Waste gas to each RTO = 2.00 lb/hr

CO in Waste gas to each RTO: 4673.99 lb/hr

Total Sulfur in Waste gas to each RTO: 1.60 lb/hr

Methanol in Waste Gas to each RTO: 80.20 lb/hr

H2S and COS DRE: 98 %

CO and Methanol DRE: 99 %

EMISSIONS: Two Units at Full Rate

lb/hr avg. lb/hr max. TPY 

PM10 0.58 0.58 2.40

PM2.5 0.58 0.58 2.40

SO 6 33 6 33 26 27

There are 2 RTOs which share a common chimney (although there are separate stacks), and receive waste gas feeds from the Acid Gas Removal Unit.

Emissions are calculated for both cases (coal / coke and coal only) and the higher (conservative) value for each pollutant will be permitted. 

SO2 6.33 6.33 26.27

NOx 3.95 3.95 16.41

CO 96.27 96.27 399.44

VOC 2.10 2.10 8.72

H2S (TAP) 0.02 0.02 0.09

COS (HAP)(VOC) 0.08 0.08 0.33

Methanol (HAP)(VOC) 1.60 1.60 6.66

Total VOC HAPs 1.83 1.83 7.58

Mercury (HAP) 1.2E-04 1.2E-04 5.2E-04

EMISSIONS: Two Units on Hot Standby

lb/hr avg. lb/hr max. TPY 

PM10 0.29 0.29 0.06

PM2.5 0.29 0.29 0.06

SO2 3.17 3.17 0.69

NOx 1.98 1.98 0.43

CO 48.14 48.14 10.54

VOC 1.05 1.05 0.23

H2S (TAP) 0.01 0.01 0.00

COS (HAP)(VOC) 0.04 0.04 0.01

Methanol (HAP)(VOC) 0.80 0.80 0.18

Total VOC HAPs 0.91 0.91 0.20

Mercury (HAP) 6.2E-05 6.2E-05 1.4E-05
EMISSIONS: One Unit at half rate - Conservatively assume Natural Gas for entire 24 hrs Page 2 of 9 TSD App A

lb/hr avg. lb/hr max. TPY 

PM10 0.14 0.14 0.0017

PM2.5 0.14 0.14 0.0017

SO2 1.58 1.58 0.019

NOx 0.99 0.99 0.012

CO 24.07 24.07 0.29

VOC 0.53 0.53 0.006

H2S (TAP) 0.01 0.01 0.0001

COS (HAP)(VOC) 0.02 0.02 0.0002

Methanol (HAP)(VOC) 0.40 0.40 0.0048

Total VOC HAPs 0.46 0.46 0.005

Mercury (HAP) 3.1E-05 3.1E-05 3.7E-07

EMISSIONS: Normal Operations Total

lb/hr avg. lb/hr max. TPY 

PM10 0.56 0.58 2.46

PM2.5 0.56 0.56 2.46

SO2 6.16 6.33 26.98

NOx 3.85 3.95 16.85

CO 93.67 96.27 410.27

VOC 2.05 2.10 8.96

H2S (TAP) 0.022 0.02 0.10

COS (HAP)(VOC) 0.08 0.08 0.34

Methanol (HAP)(VOC) 1.56 1.60 6.84

Total VOC HAPs 1.78 1.83 7.79

Mercury (HAP) 1.2E-04 1.2E-04 5.3E-04

CALCULATIONS

Emissions (PM10) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions - Normal (SO2) (Avg. lb/hr) = S in Waste Gas to each RTO (lb/hr) X 2 X DRE/100 X Mw SO2 (lb/lb-mol) / Mw S (lb/lb-mol)

Emissions - Black-start (SO2) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (NOx) (Avg. lb/hr) = Vendor Factor (lb/MMBtu) X Heat Input (MMBtu/hr)

Emissions (CO) (Avg. lb/hr) = Vendor Factor (lb/MMBtu) X Heat Input (MMBtu/hr) + CO in Waste Gas (lb/hr) X 2 X (1 - DRE)/100 3 Emissions (VOC) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft ) X Heat Input (MMBtu/hr) + COS (lb/hr) + MeOH (lb/hr)

Emissions (COS, MeOH) (Avg. lb/hr) = lb in Waste Gas (lb/hr) X 2 X (1 - DRE)/100

Emissions for each Case (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Maximum Emissions for each Case (lb/hr) = Average Emissions

Emissions TPY Total = Sum of individual cases

Emissions (Avg. lb/hr) Total = TPY Total X 2,000 (lb/T) / (Total Hrs Operation)

Natural Gas Combustion PM10 VOC SO2 HAP

7.60 5.50 0.6 1.89

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10

Natural Gas Combustion NOx CO

0.05 0.036

Comments:

Factor (lb/MM scf)

Factor (lb/MMBtuf)

SO2 emissions based on 98% conversion of sulfur in waste gas to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S).

During "normal operations" the thermal oxidizer burns SNG (which contains no sulfur); during a black-start, it fires natural gas for the first 4 hours. Permitted emissions will 

conservatively be based on firing natural gas only.

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

Source: Emission factors for NOx and CO are based on information from vendor supplied data and the use of Low NOx burners. 
Page 3 of 9 TSD App A

This page left blank Intentionally.
Page 4 of 9 TSD App A

Coal / Coke Case

COMBUSTION DATA

HEAT INPUT: Two Units at full rate 62.69 MM Btu/hr

HEAT INPUT: One Unit at full rate 31.35 MM Btu/hr

HEAT INPUT: Black-starts (1 unit at half rate) 15.67 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS: Two Units at full rate 8298 hr/yr

OPERATING HOURS: One Unit at full rate 438 hr/yr

OPERATING HOURS: Black-start 24 hr/yr

H2S in Waste gas to each RTO = 0.56 lb/hr

COS in Waste gas to each RTO = 1.97 lb/hr

CO in Waste gas to each RTO: 4595.57 lb/hr

Total Sulfur in Waste gas to each RTO: 1.58 lb/hr

Methanol in Waste Gas to each RTO: 78.86 lb/hr

H2S and COS DRE: 98 %

CO and Methanol DRE: 99 %

EMISSIONS: Two Units at Full Rate

lb/hr avg. lb/hr max. TPY 

PM10 0.47 0.47 1.94

SO2 6.22 6.22 25.80

NOx 3.19 3.19 13.25

CO 94.17 94.17 390.70

VOC 1.99 1.99 8.27

H2S (TAP) 0.02 0.02 0.09

COS (HAP)(VOC) 0.08 0.08 0.33

Methanol (HAP)(VOC) 1.58 1.58 6.54

Total HAPs 1.77 1.77 7.35

Mercury (HAP) 1.1E-04 1.1E-04 4.4E-04

EMISSIONS: One Unit at full rate 

lb/hr avg. lb/hr max. TPY 

PM10 0.23 0.23 0.05

SO2 3.11 3.11 0.681

NOx 1.60 1.60 0.35

CO 47.08 47.08 10.31

VOC 1.00 1.00 0.22

H2S (TAP) 0.01 0.01 0.002

COS (HAP)(VOC) 0.04 0.04 0.01

Methanol (HAP)(VOC) 0.79 0.79 0.17

Total HAPs 0.89 0.89 0.19

Mercury (HAP) 5.3E-05 5.3E-05 1.2E-05
EMISSIONS: One Unit at half rate - Conservatively assume Natural Gas (for SO2) and SNG (for Hg) for entire 24 hrs Page 5 of 9 TSD App A

lb/hr avg. lb/hr max. TPY 

PM10 0.12 0.12 0.0014

SO2 1.55 1.55 0.019

NOx 0.80 0.80 0.010

CO 23.54 23.54 0.28

VOC 0.50 0.50 0.0060

H2S (TAP) 0.01 0.01 0.0001

COS (HAP)(VOC) 0.02 0.02 0.00024

Methanol (HAP)(VOC) 0.39 0.39 0.0047

Total HAPs 0.44 0.44 0.0053

Mercury (HAP) 2.6E-05 2.6E-05 3.2E-07

EMISSIONS: Normal Operations Total

lb/hr avg. lb/hr max. TPY 

PM10 0.45 0.47 1.99

SO2 6.05 6.22 26.50

NOx 3.11 3.19 13.61

CO 91.62 94.17 401.30

VOC 1.94 1.99 8.50

H2S (TAP) 0.02 0.02 0.10

COS (HAP)(VOC) 0.08 0.08 0.34

Methanol (HAP)(VOC) 1.53 1.58 6.72

Total HAPs 1.72 1.77 7.55

Mercury (HAP) 1.0E-04 1.1E-04 4.5E-04

Natural Gas Combustion PM10 VOC SO2 HAP

7.60 5.50 0.6 1.89

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10

Natural Gas Combustion NOx CO

0.05 0.036

Factor (lb/MM scf)

Factor (lb/MMBtu)

Natural Gas SNG

Mercury Factor (lb/MMBtu) 1.95E-07 1.68E-06
Page 6 of 9 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 9,711 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.1832 MT

N2O = 0.0183 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 179,564,678 scf

High heat value 

of the fuel from Annual 0.00102 MMBtu per scf

Coal / Coke Case

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

all valid samples 

for the year

Average

0.00102 MMBtu per scf

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 9,711 1 9,711

CH4 0.18 21 4

N2O 0.018 310 6

TOTAL = 9,720 10,712 TPY CO2

Feeds to RTO (CO2 + combusted CO): 1,427,034 lb/hr at full rate per Eng. Design

20% percent of max vented per year.

 1,250,082 tons/yr 

1,134,067 MTCO2e 1,250,082 Subtotal TPY CO2

Total CO2e: 1,143,784 MTCO2e 1,260,793 Total TPY CO2e
Page 7 of 9 TSD App A

Coal Only Case

COMBUSTION DATA

HEAT INPUT: Two Units at full rate 77.62 MM Btu/hr

HEAT INPUT: One Unit at full rate 38.81 MM Btu/hr

HEAT INPUT: Black-starts (1 unit at half rate) 19.41 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS: Two Units at full rate 8298 hr/yr

OPERATING HOURS: One Unit at full rate 438 hr/yr

OPERATING HOURS: Black-start 24 hr/yr

H2S in Waste gas to each RTO = 0.57 lb/hr

COS in Waste gas to each RTO = 2.00 lb/hr

CO in Waste gas to each RTO: 4673.99 lb/hr

Total Sulfur in Waste gas to each RTO: 1.60 lb/hr

Methanol in Waste Gas to each RTO: 80.20 lb/hr

H2S and COS DRE: 98 %

CO and Methanol DRE: 99 %

EMISSIONS: Two Units at Full Rate (100%)

lb/hr avg. lb/hr max. TPY 

PM10 0.58 0.58 2.40

SO2 6.33 6.33 26.27

NOx 3.95 3.95 16.41

CO 96.27 96.27 399.44

VOC 2.10 2.10 8.72

H2S (TAP) 0.02 0.02 0.09

COS (HAP)(VOC) 0.08 0.08 0.33

Methanol (HAP)(VOC) 1.60 1.60 6.66

Total HAPs 1.83 1.83 7.58

Mercury (HAP) 1.2E-04 1.2E-04 5.2E-04

EMISSIONS: One Unit at full rate 

lb/hr avg. lb/hr max. TPY 

PM10 0.29 0.29 0.06

SO2 3.17 3.17 0.69

NOx 1.98 1.98 0.43

CO 48.14 48.14 10.54

VOC 1.05 1.05 0.23

H2S (TAP) 0.01 0.01 0.002

COS (HAP)(VOC) 0.04 0.04 0.01

Methanol (HAP)(VOC) 0.80 0.80 0.18

Total HAPs 0.91 0.91 0.20

Mercury (HAP) 6.2E-05 6.2E-05 1.4E-05
EMISSIONS: One Unit at half rate (25%) - Conservatively assume Natural Gas (for SO2) and SNG (for Hg) for entire 24 hrs Page 8 of 9 TSD App A

lb/hr avg. lb/hr max. TPY 

PM10 0.14 0.14 0.0017

SO2 1.58 1.58 0.019

NOx 0.99 0.99 0.012

CO 24.07 24.07 0.29

VOC 0.53 0.53 0.0063

H2S (TAP) 0.01 0.01 0.0001

COS (HAP)(VOC) 0.02 0.02 0.0002

Methanol (HAP)(VOC) 0.40 0.40 0.0048

Total HAPs 0.46 0.46 0.0055

Mercury (HAP) 3.1E-05 3.1E-05 3.7E-07

EMISSIONS: Normal Operations Total

lb/hr avg. lb/hr max. TPY 

PM10 0.56 0.58 2.46

SO2 6.16 6.33 26.98

NOx 3.85 3.95 16.85

CO 93.67 96.27 410.27

VOC 2.05 2.10 8.96

H2S (TAP) 0.022 0.02 0.10

COS (HAP)(VOC) 0.08 0.08 0.34

Methanol (HAP)(VOC) 1.56 1.60 6.84

Total HAPs 1.78 1.83 7.79

Mercury (HAP) 1.2E-04 1.2E-04 5.3E-04

Natural Gas Combustion PM10 VOC SO2 HAP

7.60 5.50 0.6 1.89

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10

Natural Gas Combustion NOx CO

0.05 0.036

Factor (lb/MM scf)

Factor (lb/MMBtu)

Natural Gas SNG

Mercury Factor (lb/MMBtu) 1.95E-07 1.61E-06
Page 9 of 9 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 10,976 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.2070 MT

N2O = 0.0207 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 202,961,074 scf

High heat value of

the fuel from all Annual 0.00102 MMBtu per scf

Coal Only Case

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

valid samples for 

the year

Average

0.00102 MMBtu per scf

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 10,976 1 10,976

CH4 0.21 21 4

N2O 0.021 310 6

TOTAL = 10,987 12,108 TPY CO2

Feeds to RTO (CO2 + combusted CO): 1,458,491 lb/hr at full rate per Eng. Design

20% percent of max vented per year.

1,277,638 tons/yr 

1,159,066 MTCO2e 1,277,638 subtotal TPY CO2

Total CO2e: 1,170,050 MTCO2e 1,289,746 Total TPY CO2e

Max CO2e: 1,170,050 MT/yr
COMBUSTION SOURCES Page 1 of 10 TSD App A

NAME Gasifier Start-up Preheat Burner A Unit ID: 008 A

STACK DATA

HEIGHT 150 ft

DIAMETER 4 ft

GAS EXIT TEMP 232 °F

GAS EXIT VELOCITY: Normal Ops 65.00 fps

GAS EXIT VELOCITY: Black Start 126.39 fps

COMBUSTION DATA

HEAT INPUT: Normal Ops 18.00 MM Btu/hr

HEAT INPUT: Black Start 35.00 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS -Normal Case 1168 hr/yr

OPERATING HOURS -Black Starts 28.8 hr/yr

EMISSIONS: Normal Case

lb/hr avg. lb/hr max. TPY 

PM10 0.013 0.013 0.0078

PM2.5 0.013 0.013 0.0073

SO2 0.011 0.011 0.0062

NOx 1.800 1.800 1.05

CO 1.008 1.008 0.59

VOC 0.097 0.097 0.057

Total VOC HAPs 0.033 0.033 0.019

Mercury (HAP) 3.0E-05 3.0E-05 1.8E-05

EMISSIONS: Black Starts

lb/hr avg. lb/hr max. TPY 

PM10 0.026 0.026 0.00038

PM2.5 0.024 0.024 0.00035

SO2 0.021 0.021 0.00030

NOx 3.500 3.500 0.05

CO 1.960 1.960 0.0282

VOC 0.189 0.189 0.00272

Total VOC HAPs 0.065 0.065 0.00093

Mercury (HAP) 6.8E-06 6.8E-06 9.8E-08

CALCULATIONS

Emissions (SO2) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (PM10, NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu/hr) x Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

Natural Gas Combustion SO2

0.6

Natural Gas Combustion PM10 NOx CO VOC

0.0007 0.100 0.056 0.005

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

Natural gas or SNG may be combusted. Conservatively assumed natural gas for SO2 calculation (as SNG contains no sulfur).

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

Factor (lb/MM Btu)

Source: Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

Factor (lb/MM scf)

Mercury Factor (lb/MMBtu)
Page 2 of 10 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 1,168 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0220 MT

N2O = 0.0022 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 21,600,000 scf

High heat value 

of the fuel from all

valid samples for 

the year

Annual 

Average 0.00102 MMBtu per scf

GHG Pollutant GHG GWP Factors Metric Tons CO2e

Gasifier Start-up 

Preheat Burner A

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

GHG Pollutant Metric Tons GWP Factors Metric Tons CO2e

CO2 1,168 1 1,168

CH4 0.0 21 0

N2O 0.0 310 1

TOTAL = 1,169 1,289 TPY CO2
COMBUSTION SOURCES Page 3 of 10 TSD App A

NAME Gasifier Start-up Preheat Burner B Unit ID: 008 B

STACK DATA

HEIGHT 150 ft

DIAMETER 4 ft

GAS EXIT TEMP 232 °F

GAS EXIT VELOCITY: Normal Ops 65.00 fps

GAS EXIT VELOCITY: Black Start 126.39 fps

COMBUSTION DATA

HEAT INPUT: Normal Ops 18.00 MM Btu/hr

HEAT INPUT: Black Start 35.00 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS -Normal Case 1168 hr/yr

OPERATING HOURS -Black Starts 28.8 hr/yr

EMISSIONS: Normal Case

lb/hr avg. lb/hr max. TPY 

PM10 0.013 0.013 0.0078

PM2.5 0.013 0.013 0.0073

SO2 0.011 0.011 0.0062

NOx 1.800 1.800 1.05

CO 1.008 1.008 0.59

VOC 0.097 0.097 0.057

Total VOC HAPs 0.033 0.033 0.019

Mercury (HAP) 3.0E-05 3.0E-05 1.8E-05

EMISSIONS: Black Starts

lb/hr avg. lb/hr max. TPY 

PM10 0.026 0.026 0.00038

PM2.5 0.024 0.024 0.00035

SO2 0.021 0.021 0.00030

NOx 3.500 3.500 0.05

CO 1.960 1.960 0.0282

VOC 0.189 0.189 0.00272

Total VOC HAPs 0.065 0.065 0.00093

Mercury (HAP) 6.8E-06 6.8E-06 9.8E-08

CALCULATIONS

Emissions (SO2) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (PM10, NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu/hr) x Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

Natural Gas Combustion SO2

0.6

Natural Gas Combustion PM10 NOx CO VOC

0.0007 0.100 0.056 0.005

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

Natural gas or SNG may be combusted. Conservatively assumed natural gas for SO2 calculation (as SNG contains no sulfur).

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

Factor (lb/MM Btu)

Source: Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

Factor (lb/MM scf)

Mercury Factor (lb/MMBtu)
Page 4 of 10 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 1,168 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0220 MT

N2O = 0.0022 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 21,600,000 scf

High heat value of

the fuel from all 

valid samples for 

the year

Annual 

Average 0.00102 MMBtu per scf

GHG M ti T 

Gasifier Start-up 

Preheat Burner B

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

GHG Pollutant GHG

Metric Tons GWP Factors Metric TonsCO2e

CO2 1,168 1 1,168

CH4 0.0 21 0

N2O 0.0 310 1

TOTAL = 1,169 1,289 TPY CO2
COMBUSTION SOURCES Page 5 of 10 TSD App A

NAME Gasifier Start-up Preheat Burner C Unit ID: 008 C

STACK DATA

HEIGHT 150 ft

DIAMETER 4 ft

GAS EXIT TEMP 232 °F

GAS EXIT VELOCITY: Normal Ops 65.00 fps

GAS EXIT VELOCITY: Black Start 126.39 fps

COMBUSTION DATA

HEAT INPUT: Normal Ops 18.00 MM Btu/hr

HEAT INPUT: Black Start 35.00 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS -Normal Case 1168 hr/yr

OPERATING HOURS -Black Starts 28.8 hr/yr

EMISSIONS: Normal Case

lb/hr avg. lb/hr max. TPY 

PM10 0.013 0.013 0.0078

PM2.5 0.013 0.013 0.0073

SO2 0.011 0.011 0.0062

NOx 1.800 1.800 1.05

CO 1.008 1.008 0.59

VOC 0.097 0.097 0.057

Total VOC HAPs 0.033 0.033 0.019

Mercury (HAP) 3.0E-05 3.0E-05 1.8E-05

EMISSIONS: Black Starts

lb/hr avg. lb/hr max. TPY 

PM10 0.026 0.026 0.00038

PM2.5 0.024 0.024 0.00035

SO2 0.021 0.021 0.00030

NOx 3.500 3.500 0.05

CO 1.960 1.960 0.0282

VOC 0.189 0.189 0.00272

Total VOC HAPs 0.065 0.065 0.00093

Mercury (HAP) 6.8E-06 6.8E-06 9.8E-08

CALCULATIONS

Emissions (SO2) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (PM10, NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu/hr) x Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

Natural Gas Combustion SO2

0.6

Natural Gas Combustion PM10 NOx CO VOC

0.0007 0.100 0.056 0.005

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

Natural gas or SNG may be combusted. Conservatively assumed natural gas for SO2 calculation (as SNG contains no sulfur).

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

Factor (lb/MM Btu)

Source: Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

Factor (lb/MM scf)

Mercury Factor (lb/MMBtu)
Page 6 of 10 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 1,168 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0220 MT

N2O = 0.0022 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 21,600,000 scf

High heat value of

the fuel from all 

valid samples for 

the year

Annual 

Average 0.00102 MMBtu per scf

Gasifier Start-up 

Preheat Burner C

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons 

CO2e

CO2 1,168 1 1,168

CH4 0.0 21 0

N2O 0.0 310 1

TOTAL = 1,169 1,289 TPY CO2
COMBUSTION SOURCES Page 7 of 10 TSD App A

NAME Gasifier Start-up Preheat Burner D Unit ID: 008 D

STACK DATA

HEIGHT 150 ft

DIAMETER 4 ft

GAS EXIT TEMP 232 °F

GAS EXIT VELOCITY: Normal Ops 65.00 fps

GAS EXIT VELOCITY: Black Start 126.39 fps

COMBUSTION DATA

HEAT INPUT: Normal Ops 18.00 MM Btu/hr

HEAT INPUT: Black Start 35.00 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS -Normal Case 1168 hr/yr

OPERATING HOURS -Black Starts 28.8 hr/yr

EMISSIONS: Normal Case

lb/hr avg. lb/hr max. TPY 

PM10 0.013 0.013 0.0078

PM2.5 0.013 0.013 0.0073

SO2 0.011 0.011 0.0062

NOx 1.800 1.800 1.05

CO 1.008 1.008 0.59

VOC 0.097 0.097 0.057

Total VOC HAPs 0.033 0.033 0.019

Mercury (HAP) 3.0E-05 3.0E-05 1.8E-05

EMISSIONS: Black Starts

lb/hr avg. lb/hr max. TPY 

PM10 0.026 0.026 0.00038

PM2.5 0.024 0.024 0.00035

SO2 0.021 0.021 0.00030

NOx 3.500 3.500 0.05

CO 1.960 1.960 0.0282

VOC 0.189 0.189 0.00272

Total VOC HAPs 0.065 0.065 0.00093

Mercury (HAP) 6.8E-06 6.8E-06 9.8E-08

CALCULATIONS

Emissions (SO2) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (PM10, NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu/hr) x Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

Natural Gas Combustion SO2

0.6

Natural Gas Combustion PM10 NOx CO VOC

0.0007 0.100 0.056 0.005

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

Natural gas or SNG may be combusted. Conservatively assumed natural gas for SO2 calculation (as SNG contains no sulfur).

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

Factor (lb/MM Btu)

Source: Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

Factor (lb/MM scf)

Mercury Factor (lb/MMBtu)
Page 8 of 10 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 1,168 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0220 MT

N2O = 0.0022 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 21,600,000 scf

High heat value of

the fuel from all 

valid samples for 

the year

Annual 

Average 0.00102 MMBtu per scf

GHG M i T 

Gasifier Start-up 

Preheat Burner D

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons 

CO2e

CO2 1,168 1 1,168

CH4 0.0 21 0

N2O 0.0 310 1

TOTAL = 1,169 1,289 TPY CO2
COMBUSTION SOURCES Page 9 of 10 TSD App A

NAME Gasifier Start-up Preheat Burner E Unit ID: 008 E

STACK DATA

HEIGHT 150 ft

DIAMETER 4 ft

GAS EXIT TEMP 232 °F

GAS EXIT VELOCITY: Normal Ops 65.00 fps

GAS EXIT VELOCITY: Black Start 126.39 fps

COMBUSTION DATA

HEAT INPUT: Normal Ops 18.00 MM Btu/hr

HEAT INPUT: Black Start 35.00 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft3

OPERATING HOURS -Normal Case 1168 hr/yr

OPERATING HOURS -Black Starts 28.8 hr/yr

EMISSIONS: Normal Case

lb/hr avg. lb/hr max. TPY 

PM10 0.013 0.013 0.0078

PM2.5 0.013 0.013 0.0073

SO2 0.011 0.011 0.0062

NOx 1.800 1.800 1.05

CO 1.008 1.008 0.59

VOC 0.097 0.097 0.057

Total VOC HAPs 0.033 0.033 0.019

Mercury (HAP) 3.0E-05 3.0E-05 1.8E-05

EMISSIONS: Black Starts

lb/hr avg. lb/hr max. TPY 

PM10 0.026 0.026 0.00038

PM2.5 0.024 0.024 0.00035

SO2 0.021 0.021 0.00030

NOx 3.500 3.500 0.05

CO 1.960 1.960 0.0282

VOC 0.189 0.189 0.00272

Total VOC HAPs 0.065 0.065 0.00093

Mercury (HAP) 6.8E-06 6.8E-06 9.8E-08

CALCULATIONS

Emissions (SO2) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (PM10, NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu/hr) x Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

Natural Gas Combustion SO2

0.6

Natural Gas Combustion PM10 NOx CO VOC

0.0007 0.100 0.056 0.005

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

Natural gas or SNG may be combusted. Conservatively assumed natural gas for SO2 calculation (as SNG contains no sulfur).

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

Factor (lb/MM Btu)

Source: Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

Factor (lb/MM scf)

Mercury Factor (lb/MMBtu)
Page 10 of 10 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 1,168 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0220 MT

N2O = 0.0022 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 21,600,000 scf

High heat value of

the fuel from all 

valid samples for 

the year

Annual 

Average 0.00102 MMBtu per scf

GHG Metric Tons 

Gasifier Start-up 

Preheat Burner E

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 1,168 1 1,168

CH4 0.0 21 0

N2O 0.0 310 1

TOTAL = 1,169 1,289 TPY CO2
COMBUSTION SOURCES Page 1 of 4 TSD App A

NAME Emergency Diesel Power Generator A Unit ID: 009 A

COMBUSTION DATA

FUEL TYPE Diesel

ENGINE SIZE 1,341 HP

HOURS OF OPERATION 52 hr/yr

EMISSIONS avg lb/hr lb/hr max. TPY

PM10 0.06 0.06 0.0015

PM2.5 0.06 0.06 0.0014

SO2 0.015 0.015 0.00039

NOX 14.58 14.58 0.38

CO 0.38 0.38 0.010

VOC (TOC) 0.03 0.03 0.00077

CALCULATIONS:

Emissions (LB/HR) = Vendor Factor X HP

Emissions (TPY) = Emissions (LB/HR) X (Hours of operation/2000)

PM10 SO2 NOX CO VOC

4.4E-05 1.1E-05 0.0109 2.9E-04 2.2E-05

COMMENTS

ASSUMED MAXIMUM HOURLY EMISSIONS EQUAL TO AVERAGE HOURLY EMISSIONS.

HAPs emission from this limited use source assumed to be negligable

Diesel Industrial Engine Factors 

(Lb/hp-hr)

Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

SO2 emissions based on 15 ppm S in diesel and 100% conversion to SO2.

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).
Page 2 of 4 TSD App A

Stationary Combustion Sources - Diesel

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume) 0.138

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 73.96

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 22.1 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.003

0.0006

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.00090 MT

N2O = 0.000179 MT

Emission Points Data Required

MRR

Frequency Data Units

Gallons of diesel 

fuel combusted Annual 2,163 Gallons

High heat value 

of the fuel from 

all valid samples 

for the year

Annual 

Average 0.13800 MMBtu per gal

Emergency 

Diesel Power 

Generator A

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

for the year

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 22.1 1 22.1

CH4 0.00090 21 0.0188

N2O 0.000179 310 0.056

TOTAL = 22.2 24.4 TPY CO2

Fuel Consumption 50% load = 20.8 gal/hr.

Assumed Fuel at 100% Load = 41.6 gal/hr.
COMBUSTION SOURCES Page 3 of 4 TSD App A

NAME Emergency Diesel Power Generator B Unit ID: 009 B

COMBUSTION DATA

FUEL TYPE Diesel

ENGINE SIZE 1,341 HP

HOURS OF OPERATION 52 hr/yr

EMISSIONS avg lb/hr lb/hr max. TPY

PM10 0.06 0.06 0.0015

PM2.5 0.06 0.06 0.0014

SO2 0.015 0.015 0.00039

NOX 14.58 14.58 0.38

CO 0.38 0.38 0.010

VOC (TOC) 0.03 0.03 0.00077

CALCULATIONS:

Emissions (LB/HR) = Vendor Factor X HP

Emissions (TPY) = Emissions (LB/HR) X (Hours of operation/2000)

PM10 SO2 NOX CO VOC

4.4E-05 1.1E-05 0.0109 2.9E-04 2.2E-05

COMMENTS

ASSUMED MAXIMUM HOURLY EMISSIONS EQUAL TO AVERAGE HOURLY EMISSIONS.

HAPs emission from this limited use source assumed to be negligable

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Diesel Industrial Engine Factors 

(Lb/hp-hr)

Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

SO2 emissions based on 15 ppm S in diesel and 100% conversion to SO2.
Page 4 of 4 TSD App A

Stationary Combustion Sources - Diesel

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume) 0.138

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 73.96

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 11.0 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.003

0.0006

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.00045 MT

N2O = 0.000090 MT

Emission Points Data Required

MRR

Frequency Data Units

Gallons of diesel 

fuel combusted Annual 1,082 Gallons

High heat value 

of the fuel from 

all valid samples 

for the year

Annual 

Average 0.13800 MMBtu per gal

Emergency 

Diesel Power 

Generator B

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

for the year

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 11.0 1 11.0

CH4 0.00045 21 0.0094

N2O 0.000090 310 0.028

TOTAL = 11.1 12.2 TPY CO2

Fuel Consumption 50% load = 20.8 gal/hr.

Assumed Fuel at 100% Load = 41.6 gal/hr.
COMBUSTION SOURCES Page 1 of 6 TSD App A

NAME Fire Water Diesel Pump A Unit ID: 010 A

COMBUSTION DATA

FUEL TYPE Diesel

ENGINE SIZE 575 HP

HOURS OF OPERATION 52 hr/yr

EMISSIONS avg lb/hr lb/hr max. TPY

PM10 0.108 0.108 0.0028

PM2.5 0.101 0.101 0.0026

SO2 0.0061 0.0061 0.00016

NOX 3.131 3.131 0.081

CO 0.799 0.799 0.021

VOC 0.218 0.218 0.0057

CALCULATIONS:

Emissions (LB/HR) = Vendor Factor X HP

Emissions (TPY) = Emissions (LB/HR) X (Hours of operation/2000)

PM10 SO2 NOX CO VOC 

1.9E-04 1.1E-05 0.0054 1.4E-03 3.8E-04

COMMENTS

ASSUMED MAXIMUM HOURLY EMISSIONS EQUAL TO AVERAGE HOURLY EMISSIONS.

HAPs emission from this limited use source assumed to be negligable

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Diesel Industrial Engine Factors 

(Lb/hp-hr)

Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

SO2 emissions based on 15 ppm S in diesel and 100% conversion to SO2.
Page 2 of 6 TSD App A

Stationary Combustion Sources - Diesel

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume) 0.138

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 73.96

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 10 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.003

0.0006

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0004 MT

N2O = 0.00009 MT

Emission Points Data Required

MRR

Frequency Data Units

Gallons of diesel 

fuel combusted Annual 1,027 Gallons

High heat value 

of the fuel from all 

valid samples for 

the year

Annual 

Average 0.13800 MMBtu per gal

Fire Water Diesel 

Pump A

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

the year

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 10.5 1 10.5

CH4 0.00043 21 0.0089

N2O 0.000085 310 0.026

TOTAL = 10.5 11.6 TPY CO2

Fuel Consumption 40% load = 7.9 gal/hr.

Assumed Fuel at 100% Load = 19.75 gal/hr.
COMBUSTION SOURCES Page 3 of 6 TSD App A

NAME Fire Water Diesel Pump B Unit ID: 010 B

COMBUSTION DATA

FUEL TYPE Diesel

ENGINE SIZE 575 HP

HOURS OF OPERATION 52 hr/yr

EMISSIONS avg lb/hr lb/hr max. TPY

PM10 0.108 0.108 0.0028

PM2.5 0.101 0.101 0.0026

SO2 0.0061 0.0061 0.00016

NOX 3.131 3.131 0.081

CO 0.799 0.799 0.021

VOC 0.218 0.218 0.0057

CALCULATIONS:

Emissions (LB/HR) = Vendor Factor X HP

Emissions (TPY) = Emissions (LB/HR) X (Hours of operation/2000)

PM10 SO2 NOX CO VOC 

1.9E-04 1.1E-05 0.0054 1.4E-03 3.8E-04

COMMENTS

ASSUMED MAXIMUM HOURLY EMISSIONS EQUAL TO AVERAGE HOURLY EMISSIONS.

HAPs emission from this limited use source assumed to be negligable

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Diesel Industrial Engine Factors 

(Lb/hp-hr)

Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

SO2 emissions based on 15 ppm S in diesel and 100% conversion to SO2.
Page 4 of 6 TSD App A

Stationary Combustion Sources - Diesel

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume) 0.138

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 73.96

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 4 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.003

0.0006

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0002 MT

N2O = 0.00003 MT

Emission Points Data Required

MRR

Frequency Data Units

Gallons of diesel 

fuel combusted Annual 411 Gallons

High heat value 

of the fuel from all 

valid samples for 

the year

Annual 

Average 0.13800 MMBtu per gal

Fire Water Diesel 

Pump B

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

the year

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 4.2 1 4.2

CH4 0.00017 21 0.0036

N2O 0.000034 310 0.011

TOTAL = 4.2 4.6 TPY CO2

Fuel Consumption 40% load = 7.9 gal/hr.

Assumed Fuel at 100% Load = 19.75 gal/hr.
COMBUSTION SOURCES Page 5 of 6 TSD App A

NAME Fire Water Diesel Pump C Unit ID: 010 C

COMBUSTION DATA

FUEL TYPE Diesel

ENGINE SIZE 575 HP

HOURS OF OPERATION 52 hr/yr

EMISSIONS avg lb/hr lb/hr max. TPY

PM10 0.108 0.108 0.0028

PM2.5 0.101 0.101 0.0026

SO2 0.0061 0.0061 0.00016

NOX 3.131 3.131 0.081

CO 0.799 0.799 0.021

VOC 0.218 0.218 0.0057

CALCULATIONS:

Emissions (LB/HR) = Vendor Factor X HP

Emissions (TPY) = Emissions (LB/HR) X (Hours of operation/2000)

PM10 SO2 NOX CO VOC 

1.9E-04 1.1E-05 0.0054 1.4E-03 3.8E-04

COMMENTS

ASSUMED MAXIMUM HOURLY EMISSIONS EQUAL TO AVERAGE HOURLY EMISSIONS.

HAPs emission from this limited use source assumed to be negligable

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Diesel Industrial Engine Factors 

(Lb/hp-hr)

Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.

SO2 emissions based on 15 ppm S in diesel and 100% conversion to SO2.
Page 6 of 6 TSD App A

Stationary Combustion Sources - Diesel

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume) 0.138

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 73.96

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 4 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.003

0.0006

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0002 MT

N2O = 0.00003 MT

Emission Points Data Required

MRR

Frequency Data Units

Gallons of diesel 

fuel combusted Annual 411 Gallons

High heat value 

of the fuel from all 

valid samples for 

the year

Annual 

Average 0.13800 MMBtu per gal

Fire Water Diesel 

Pump C

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

the year

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 4.2 1 4.2

CH4 0.00017 21 0.0036

N2O 0.000034 310 0.011

TOTAL = 4.2 4.6 TPY CO2

Fuel Consumption 40% load = 7.9 gal/hr.

Assumed Fuel at 100% Load = 19.75 gal/hr.
URS INDIANA GASIFICATION FACILITY Vent Calculations

Source 011 B is a spare for source 011 A. Only one of these two sources will be in operation at one time.

Average Maximum Annual PM10 Annual PM2.5

Emissions Hourly Emissions Emissions

Unit ID Name dscfm gr/dscf lb/hr lb/hr TPY TPY

011 A System 1A -- Coal-Coke Handling 

System 33,760 0.003 0.868 0.868 3.80 1.86

011 B System 1B -- Coal-Coke Handling 

System (Spare)

Comments:

VENT SOURCES

The following are the vent sources related to solids handling, including coke and coal. These sources are all controlled by baghouses.

PM10 EMISSIONS

Exhaust Air 

Flow per filter

Filter PM10

Performance

Outlet grain loading factor (gr/acfm) 0.003 gr/dscf PM/PM10, 0.0015 gr/dscf PM2.5.

17_30464 limited Calcs D 38 5/3/2012
URS INDIANA GASIFICATION FACILITY Vent Calculations

Height of Piles 90 ft

Diameter of Piles 539 ft

Average Maximum Annual Factor Average Maximum Annual

Emissions Hourly Emissions PM Total/ Emissions Hourly Emissions

Unit ID Name lb/hr lb/hr TPY lb/hr lb/hr TPY

012 A Barge Unload to Hopper 750 TPH 0.00056 lb/ton WET SUPPRESSION 85.0% 2,678 0.063 0.063 0.084 2.114 0.13 0.13 0.18

012 B Barge Unload Hopper to Belt 1,500 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 2,678 0.039 0.039 0.052 Note 2 0.039 0.039 0.052

012 C Barge Conveyor Transfer Drop 1,500 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 2,678 0.039 0.039 0.052 Note 2 0.039 0.039 0.052

012 D Barge Conveyor Transfer Drop 1,500 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 2,678 0.039 0.039 0.052 Note 2 0.039 0.039 0.052

012 E Barge Conveyor Transfer Drop 1,500 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 2,678 0.039 0.039 0.052 Note 2 0.039 0.039 0.052

012 F Barge Conveyor Transfer Drop 1,500 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 2,678 0.039 0.039 0.052 Note 2 0.039 0.039 0.052

012 G Rail Unload 1 to Hopper 1,500 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 663 0.039 0.039 0.013 Note 2 0.039 0.039 0.013

012 H Rail Unload 2 to Hopper 1,500 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 663 0.039 0.039 0.013 Note 2 0.039 0.039 0.013

012 I Rail Unload Hopper 1 to Belt 1,500 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 663 0.039 0.039 0.013 Note 2 0.039 0.039 0.013

012 J Rail Unload Hopper 2 to Belt 1,500 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 663 0.039 0.039 0.013 Note 2 0.039 0.039 0.013

012 K Rail Unload Belts 1 & 2 to Stacker Belt 1 1,500 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 663 0.039 0.039 0.013 Note 2 0.039 0.039 0.013

012 L Stacker Belt 1 to Radial Stacker (Pile1 ) 1,500 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 2,002 0.039 0.039 0.039 Note 2 0.039 0.039 0.039

012 M Stacker Belt 2 from Radial Stacker (Pile 1) 1,500 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 2,002 0.039 0.039 0.039 Note 2 0.039 0.039 0.039

012 N Radial Stacker to Pile 1 3,000 TPH 0.00056 lb/ton FABRIC FILTERS w/TELESCOPING CHUTE 99.9% 2,002 0.002 0.002 0.002 Note 2 0.002 0.002 0.002

012 O Radial Stacker to Pile 2 3,000 TPH 0.00056 lb/ton FABRIC FILTERS w/TELESCOPING CHUTE 99.9% 2,002 0.002 0.002 0.002 Note 2 0.002 0.002 0.002

012 P Dozer Activity on Pile 1 1,500 TPH 0.239 lb/hr WET SUPPRESSION 90.0% 4,380 0.024 0.048 0.052 Note 1 0.11 0.22 0.24

012 Q Dozer Activity on Pile 2 1,500 TPH 0.239 lb/hr WET SUPPRESSION 90.0% 4,380 0.024 0.048 0.052 Note 1 0.11 0.22 0.24

012 R Pile 1 / Bottom Hopper / Belt / Classification 

Tower 6,000 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 2,708 0.15 0.15 0.21 Note 2 0.15 0.15 0.21

012 S Pile 2 / Bottom Hopper / Belt / Classification 

Tower 6,000 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 2,708 0.15 0.15 0.21 Note 2 0.15 0.15 0.21

012 T CLASSIFICATION TOWER #1 1,500 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 2,708 0.039 0.039 0.052 Note 2 0.039 0.039 0.052

012 U CLASSIFICATION TOWER #2 1,500 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 2,708 0.039 0.039 0.052 Note 2 0.039 0.039 0.052

012 V Classification Towers to Day Bin 1,500 ACFM 2.50 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.88% 2,708 0.039 0.039 0.052 Note 2 0.039 0.039 0.052

012 W Wind Erosion Pile 1 300,000 Tons 2.157 lb/hr WET SUPPRESSION/COMPACTION 90.0% 8,760 0.22 0.22 0.94 2.0 0.43 0.43 1.89

012 X Wind Erosion Pile 2 300,000 Tons 1.794 lb/hr WET SUPPRESSION/COMPACTION 90.0% 8,760 0.18 0.18 0.79 2.0 0.36 0.36 1.57

012 Y-AC on separate spreadsheet Tab

TOTAL PM10 = 2.90 TOTAL Particulate = 5.10

Comments:

Dozer activity (012 P and 012 Q) factors calculated based on equations from AP-42 Section 13.2.2

Transfer point (012 A, 012 N and 012 O) factors calculated based on equations from AP-42 Section 13.2.4

Coke / Coal pile (012 W and 012 X) wind erosion factors calculated based on equations from AP-42 Section 13.2.5

Inlet grain loading factor (gr/acfm) estimated by vendor, control efficiencies for filtered exhausts achieve 0.003 gr/dscf PM/PM10, 0.0015 gr/dscf PM2.5.

Total PM Emissions (Calc. here)

VENT SOURCES

The following are the sources related to solids unloading (barge and rail car) and handling, including coke and coal piles.

PM10 EMISSIONS Process Rate Emission Factor Control

Type

Control 

Efficiency

Operating 

Hours

17_30464 limited Calcs D 39 5/3/2012
URS INDIANA GASIFICATION FACILITY Vent Calculations

VENT SOURCES

Average Maximum Annual

Emissions Hourly Emissions

Unit ID Name lb/hr lb/hr TPY

012 A Barge Unload to Hopper 750 TPH 0.000084 lb/ton WET SUPPRESSION 85.0% 2,678 0.0095 0.0095 0.013

012 B Barge Unload Hopper to Belt 1,500 ACFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 2,678 0.019 0.019 0.026

012 C Barge Conveyor Transfer Drop 1,500 ACFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 2,678 0.019 0.019 0.026

012 D Barge Conveyor Transfer Drop 1,500 ACFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 2,678 0.019 0.019 0.026

012 E Barge Conveyor Transfer Drop 1,500 ACFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 2,678 0.019 0.019 0.026

012 F Barge Conveyor Transfer Drop 1,500 ACFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 2,678 0.019 0.019 0.026

012 G Rail Unload 1 to Hopper 1,500 ACFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 663 0.019 0.019 0.006

012 H Rail Unload 2 to Hopper 1,500 ACFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 663 0.019 0.019 0.006

012 I Rail Unload Hopper 1 to Belt 1,500 ACFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 663 0.019 0.019 0.006

012 J Rail Unload Hopper 2 to Belt 1,500 ACFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 663 0.019 0.019 0.006

012 K Rail Unload Belts 1 & 2 to Stacker Belt 1 1,500 ACFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 663 0.019 0.019 0.006

012 L Stacker Belt 1 to Radial Stacker (Pile1 ) 1,500 ACFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 2,002 0.019 0.019 0.019

012 M Stacker Belt 2 from Radial Stacker (Pile 1) 1,500 ACFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 2,002 0.019 0.019 0.019

012 N Radial Stacker to Pile 1 3,000 TPH 0.000084 lb/ton FABRIC FILTERS w/TELESCOPING CHUTE 99.9% 2,002 0.00025 0.00025 0.00025

012 O Radial Stacker to Pile 2 3,000 TPH 0.000084 lb/ton FABRIC FILTERS w/TELESCOPING CHUTE 99.9% 2,002 0.00025 0.00025 0.00025

012 P Dozer Activity on Pile 1 1,500 TPH 0.024 lb/hr WET SUPPRESSION 90.0% 4,380 0.002 0.005 0.005

012 Q Dozer Activity on Pile 2 1,500 TPH 0.024 lb/hr WET SUPPRESSION 90.0% 4,380 0.002 0.005 0.005

012 R Pile 1 / Bottom Hopper / Belt / Classification 

Tower 6,000 ACFM 0.18 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 2,708 0.077 0.077 0.10

012 S Pile 2 / Bottom Hopper / Belt / Classification 

Tower 6,000 ACFM 0.18 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 2,708 0.077 0.077 0.10

012 T CLASSIFICATION TOWER #1 1,500 ACFM 0.18 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 2,708 0.019 0.019 0.026

012 U CLASSIFICATION TOWER #2 1,500 ACFM 0.18 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 2,708 0.019 0.019 0.026

012 V Classification Towers to Day Bin 1,500 ACFM 0.18 GR/ACFM DUST EXTRACTION SYSTEM or FILTER 99.14% 2,708 0.019 0.019 0.026

012 W Wind Erosion Pile 1 300,000 Tons 0.229 lb/hr WET SUPPRESSION/COMPACTION 90.0% 8,760 0.023 0.023 0.10

012 X Wind Erosion Pile 2 300,000 Tons 0.190 lb/hr WET SUPPRESSION/COMPACTION 90.0% 8,760 0.019 0.019 0.083

TOTAL PM10 = 0.70

Comments:

Dozer activity (012 P and 012 Q) factors calculated based on equations from AP-42 Section 13.2.2

Transfer point (012 A, 012 N and 012 O) factors calculated based on equations from AP-42 Section 13.2.4

Coke / Coal pile (012 W and 012 X) wind erosion factors calculated based on equations from AP-42 Section 13.2.5

Inlet grain loading factor (gr/acfm) estimated by vendor, control efficiencies for filtered exhausts achieve 0.003 gr/dscf PM/PM10, 0.0015 gr/dscf PM2.5.

PM2.5 EMISSIONS Process Rate Emission Factor Control

Type

Control 

Efficiency

Operating 

Hours

17_30464 limited Calcs D 40 5/3/2012
URS INDIANA GASIFICATION FACILITY Vent Calculations

VENT SOURCES

Basis of Factors to convert PM10 estimate to Total PM

Aggregate Handling Sources

 - Total PM Aerodynamic Particle Size Multiplier (k) from 0.74

 - PM10 Aerodynamic Particle Size Multiplier (k) from AP 0.35

Factor to c 2.114

Wind Erosion From Piles

- Total Particulate Factor for Alternative Method from WR 1.0

 - PM10 factor for Alternative Method from WRAP docum 0.5

Factor to c 2.0

Note 1: Dozer ( Unpaved Roadway) Sources

Dozer Total PM is calculated on separate worksheet page, "Total PM for Dozers" because

the calcualion involves more than a simple k factor (ie: exponents, etc)

Note 2: Fabric Filter controlled sources:

These sources have PM10 estimated using estimated design total particulate grain loading on the outlet.

All outlet PM is conservatively assumed to be PM10, therefore total PM = PM10.

17_30464 limited Calcs D 41 5/3/2012
Page 1 of 1 TSD App A

NAME Rod Mill Air Eductors

STACK DATA

HEIGHT 125 ft

DIAMETER 0.5 ft

GAS EXIT TEMP 80 °F

GAS EXIT VELOCITY 15.46 fps

OPERATING HOURS 8,760 hr/yr

PM10 EMISSIONS Average Maximum Annual PM10 Annual PM2.5

Emissions Hourly Emissions Emissions

Unit ID lb/hr lb/hr TPY TPY

013 A 0.025 0.025 0.11 0.032

013 C 0.025 0.025 0.11 0.032

013 C 0.025 0.025 0.11 0.032

013 D 0.025 0.025 0.11 0.032

Total 0.10 0.10 0.44 0.13

Emissions based on engineered equipment data

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

VENT SOURCES

17_30464 limited Calcs D 42 5/3/2012
VENT SOURCES Page 1 of 9 TSD App A

NAME Wet Sulfuric Acid (WSA) Unit Stack A Unit ID: 015 A

Emissions of all pollutants are higher for the Coal / Coke Case.

STACK DATA

HEIGHT 200 ft

DIAMETER 4.83 ft

GAS EXIT TEMP 176 °F

GAS EXIT VELOCITY: Two Unit Operation 102.2 fps

GAS EXIT VELOCITY: One Unit Operation 51.1 fps

GAS EXIT VELOCITY: Black start 25.5 fps

GAS EXIT VELOCITY: Preheat 115.3 fps

COMBUSTION DATA

HEAT INPUT - Preheat 35.00 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1,020 Btu/ft3

OPERATING HOURS: Two Unit Operation 8,298 hr/yr

OPERATING HOURS: One Unit Operation 438 hr/yr

OPERATING HOURS: Black-start 24 hr/yr

OPERATING HOURS: Preheat 60 hr/yr

EMISSIONS: Full Rate

lb/hr avg. lb/hr max. TPY 

SO2 8.30 8.30 34.44

NOx 10.17 10.17 42.20

CO 18.72 18.72 77.69

H2SO4 5.00 5.00 20.73

Mercury (HAP) 3.3E-10 3.3E-10 1.4E-09

EMISSIONS: Full Rate for 219 hr/yr OR Half Rate for 438 hr/yr

lb/hr avg. lb/hr max. TPY 

SO2 4.15 4.15 0.91

NOx 5.09 5.09 1.11

CO 9.36 9.36 2.05

H2SO4 2.50 2.50 0.55

Mercury (HAP) 3 3E 10 3.3E-10 3 3E 10 3.3E-10 7 3E 11 7.3E-11

EMISSIONS: Half Rate (including Black Start)

lb/hr avg. lb/hr max. TPY 

SO2 2.08 2.08 0.02

NOx 2.54 2.54 0.03

CO 4.68 4.68 0.06

H2SO4 1.25 1.25 0.01

Mercury (HAP) 3.3E-10 3.3E-10 4.0E-12

EMISSIONS: Preheat

lb/hr avg. lb/hr max. TPY 

PM10 0.03 0.03 0.0008

PM2.5 0.02 0.02 0.0006

SO2 0.02 0.02 0.0006

NOx 3.85 3.85 0.12

CO 1.96 1.96 0.059

VOC 0.19 0.19 0.006

Total VOC HAPs 0.06 0.06 0.0019

Mercury (HAP) 5.9E-05 5.9E-05 1.8E-06
EMISSIONS: Normal Operations Total Page 2 of 9 TSD App A

lb/hr avg. lb/hr max. TPY 

PM10 0.00018 0.03 0.0008

PM2.5 0.00015 0.02 0.0006

SO2 8.53 8.30 35.37

NOx 9.92 10.17 43.46

CO 18.23 18.72 79.85

VOC 0.0013 0.19 0.006

Total VOC HAPs 0.0004 0.06 0.0019

Mercury (HAP) 4.0E-07 6.5E-02 1.8E-06

H2SO4 4.86 5.00 21.29

PM2.5 including H2SO4 4.86 5.00 21.29

CALCULATIONS

Emissions Preheat Case: (NOx, CO) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

PM10 VOC SO2

7.600 5.50 0.60

NOx CO

0.110 0.056

Comments:

SO2 emissions for preheat case based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 

scf (<5 ppmv of H2S). 

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis 

Group).

Total HAPs are based on AP-42 Section 1 4 Tables 1 4-3 and 1 4-4

Preheat Case: Natural 

Gas Combustion

Factor (lb/MMBtu)

Source: Emission factors for NOx and CO are based on information from vendor supplied data.

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10. 

Emissions Preheat Case: (PM10, VOC, and SO2)(Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Preheat Case: Natural Gas 

Combustion

Factor (lb/MMscf)

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

The emission rate data from the WSA Trains is based on information from process licensee.

Total WSA capacity for two trains is 136,658 lb/h of 97.5 wt% Sulfuric Acid production OR 1,599 stpd on dry basis (100% acid).

Burner flue gas is scrubbed in gasifier quench water to remove over 90% of particulate.
Page 3 of 9 TSD App A

This page left blank Intentionally.
Page 4 of 9 TSD App A

Coal / Coke Case

35.00 MM Btu/hr

1,020 Btu/ft3

Full Rate 8,298 hr/yr

Half Rate 438 hr/yr

Black Start 24 hr/yr

Preheat 60 hr/yr

EMISSIONS: Full Rate

lb/hr avg. lb/hr max. TPY 

SO2 8.30 8.30 34.44

NOx 10.17 10.17 42.20

CO 18.72 18.72 77.69

H2SO4 5.00 5.00 20.73

Mercury (HAP) 3.3E-10 3.3E-10 1.4E-09

EMISSIONS: Full Rate for 219 hr/yr OR Half Rate for 438 hr/yr

lb/hr avg. lb/hr max. TPY 

SO2 4.15 4.15 0.91

NOx 5.09 5.09 1.11

CO 9.36 9.36 2.05

H2SO4 2.50 2.50 0.55

Mercury (HAP) 3.3E-10 3.3E-10 7.1E-11

EMISSIONS: Half Rate (including Black Start)

lb/hr avg. lb/hr max. TPY 

SO2 2.08 2.08 0.02

NOx 2.54 2.54 0.03

CO 4.68 4.68 0.06

H2SO4 1.25 1.25 0.01

Mercury (HAP) 3.3E-10 3.3E-10 3.9E-12

EMISSIONS: Preheat

lb/hr avg. lb/hr max. TPY 

PM10 0.03 0.03 0.0008

SO2 0.02 0.02 0.0006

NOx 3.85 3.85 0.12

CO 1.96 1.96 0.059

VOC 0.19 0.19 0.006

Total VOC HAPs 0.06 0.06 0.0019

Mercury (HAP) 5.9E-05 5.9E-05 1.8E-06

PM10 VOC SO2

7.600 5.50 0.60

NOx CO

0.110 0.056

Natural Gas SNG (Coal-Coke)

1.95E-07 1.68E-06

Factor (lb/MMBtu)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10. 

Mercury Factor (lb/MMBtu)

Preheat Case: Natural 

Gas Combustion

Preheat Case: Natural Gas Combustion

Factor (lb/MMscf)
Page 5 of 9 TSD App A

This page left blank Intentionally.
Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis) Page 6 of 9 TSD App A

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 111 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0021 MT

N2O = 0.0002 MT

Emission 

Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 2,058,824 scf

High heat value of the 

fuel from all valid 

samples for the year

Annual 

Average 0.00102 MMBtu per scf

GHG

WSA Preheat 

Burners

CO    Fuel  HHV  EF  3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 111 1 111

CH4 0.0 21 0

N2O 0.0 310 0

TOTAL = 111 123 TPY CO2

Feeds to WSA (CO2 + combusted CO):

WSA Exhaust = 14538.1 lb-mole/hr

CO2% = 6.60%

CO2 MW = 44.01 lb/lb-mole

CO2 Emissions = 42,209 lb/hr 179,875 TPY CO2

18% Contingency due to lack of performance guarantee

 212,999 TPY CO2
Page 7 of 9 TSD App A

Coal Only Case

35.00 MM Btu/hr

1,020 Btu/ft3

Full Rate 8,298 hr/yr

Half Rate 438 hr/yr

Black Start 24 hr/yr

Preheat 60 hr/yr

EMISSIONS: Full Rate

lb/hr avg. lb/hr max. TPY 

SO2 7.57 7.57 31.40

NOx 7.40 7.40 30.72

CO 13.63 13.63 56.54

H2SO4 3.64 3.64 15.09

Mercury (HAP) 3.3E-10 3.3E-10 1.4E-09

EMISSIONS: Full Rate for 219 hr/yr OR Half Rate for 438 hr/yr

lb/hr avg. lb/hr max. TPY 

SO2 3.78 3.78 0.83

NOx 3.70 3.70 0.81

CO 6.81 6.81 1.49

H2SO4 1.82 1.82 0.40

Mercury (HAP) 3.3E-10 3.3E-10 7.3E-11

EMISSIONS: Half Rate (including Black Start)

lb/hr avg. lb/hr max. TPY 

SO2 1.89 1.89 0.02

NOx 1.85 1.85 0.02

CO 3.41 3.41 0.04

H2SO4 0.91 0.91 0.01

Mercury (HAP) 3.3E-10 3.3E-10 4.0E-12

EMISSIONS: Preheat

lb/hr avg. lb/hr max. TPY 

PM10 0.03 0.03 0.0008

SO2 0.02 0.02 0.0006

NOx 3.85 3.85 0.12

CO 1.96 1.96 0.059

VOC 0.19 0.19 0.006

Total VOC HAPs 0.06 0.06 0.0019

Mercury (HAP) 5.6E-05 5.6E-05 1.7E-06

PM10 VOC SO2

7.600 5.50 0.60

NOx CO

0.110 0.056

Natural Gas SNG (Coal Only)

1.95E-07 1.61E-06

Factor (lb/MMBtu)

Combustion

Factor (lb/MMscf)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10. 

Preheat Case: Natural 

Gas Combustion

Mercury Factor (lb/MMBtu)
Page 8 of 9 TSD App A

This page left blank Intentionally.
Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis) Page 9 of 9 TSD App A

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 111 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0021 MT

N2O = 0.0002 MT

Emission 

Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 2,058,824 scf

High heat value of the

fuel from all valid 

samples for the year

Annual 

Average 0.00102 MMBtu per scf

GHG GHG GWP Metric Tons 

WSA Preheat 

Burners

CO    Fuel  HHV  EF  3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

GHG 

Pollutant

GHG

Metric Tons

GWP 

Factors

Metric Tons 

CO2e

CO2 111 1 111

CH4 0.0 21 0

N2O 0.0 310 0

TOTAL = 111 123 TPY CO2

Feeds to WSA (CO2 + combusted CO):

WSA Exhaust = 10393.9 lb-mole/hr

CO2% = 10.262%

CO2 MW = 44.01 lb/lb-mole

CO2 Emissions = 46,941 lb/hr 200,039 TPY CO2

18% Contingency due to lack of performance guarantee

 236,877 TPY CO2
VENT SOURCES Page 1 of 9 TSD App A

NAME Wet Sulfuric Acid (WSA) Unit Stack B Unit ID: 015 B

Emissions of all pollutants are higher for the Coal / Coke Case.

STACK DATA

HEIGHT 200 ft

DIAMETER 4.83 ft

GAS EXIT TEMP 176 °F

GAS EXIT VELOCITY: Two Unit Operation 102.2 fps

GAS EXIT VELOCITY: One Unit Operation 51.1 fps

GAS EXIT VELOCITY: Black start 25.5 fps

GAS EXIT VELOCITY: Preheat 115.3 fps

COMBUSTION DATA

HEAT INPUT - Preheat 35.00 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1,020 Btu/ft3

OPERATING HOURS: Two Unit Operation 8,298 hr/yr

OPERATING HOURS: One Unit Operation 438 hr/yr

OPERATING HOURS: Black-start 24 hr/yr

OPERATING HOURS: Preheat 60 hr/yr

EMISSIONS: Full Rate

lb/hr avg. lb/hr max. TPY 

SO2 8.30 8.30 34.44

NOx 10.17 10.17 42.20

CO 18.72 18.72 77.69

H2SO4 5.00 5.00 20.73

Mercury (HAP) 3.3E-10 3.3E-10 1.4E-09

EMISSIONS: Full Rate for 219 hr/yr OR Half Rate for 438 hr/yr

lb/hr avg. lb/hr max. TPY 

SO2 4.15 4.15 0.91

NOx 5.09 5.09 1.11

CO 9.36 9.36 2.05

H2SO4 2.50 2.50 0.55

Mercury (HAP) 3 3E 10 3.3E-10 3 3E 10 3.3E-10 7 3E 11 7.3E-11

EMISSIONS: Half Rate (including Black Start)

lb/hr avg. lb/hr max. TPY 

SO2 2.08 2.08 0.02

NOx 2.54 2.54 0.03

CO 4.68 4.68 0.06

H2SO4 1.25 1.25 0.01

Mercury (HAP) 3.3E-10 3.3E-10 4.0E-12

EMISSIONS: Preheat

lb/hr avg. lb/hr max. TPY 

PM10 0.03 0.03 0.0008

PM2.5 0.02 0.02 0.0006

SO2 0.02 0.02 0.00062

NOx 3.85 3.85 0.116

CO 1.96 1.96 0.059

VOC 0.19 0.19 0.0057

Total VOC HAPs 0.06 0.06 0.00194

Mercury (HAP) 5.9E-05 5.9E-05 1.8E-06
EMISSIONS: Normal Operations Total Page 2 of 9 TSD App A

lb/hr avg. lb/hr max. TPY 

PM10 0.00018 0.03 0.0008

PM2.5 0.00015 0.02 0.0006

SO2 8.08 8.30 35.37

NOx 9.92 10.17 43.46

CO 18.23 18.72 79.85

VOC 0.0013 0.19 0.006

Total VOC HAPs 0.0004 0.06 0.0019

Mercury (HAP) 4.0E-07 6.5E-02 1.8E-06

H2SO4 4.86 5.00 21.29

PM2.5 including H2SO4 4.86 5.00 21.29

CALCULATIONS

Emissions Preheat Case: (NOx, CO) (Avg. lb/hr) = Vendor Factor (lb/MM Btu) X Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

PM10 VOC SO2

7.600 5.50 0.60

NOx CO

0.110 0.056

Comments:

Preheat Case: Natural Gas 

Combustion

SO2 emissions for preheat case based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 

grains/10^6 scf (<5 ppmv of H2S). 

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis 

Group).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

Factor (lb/MMscf)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10. 

Emissions Preheat Case: (PM10, VOC, and SO2)(Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3) X Heat Input (MMBtu/hr)

Preheat Case: Natural 

Gas Combustion

Factor (lb/MMBtu)

Source: Emission factors for NOx and CO are based on information from vendor supplied data.

The emission rate data from the WSA Trains is based on information from process licensee.

Total WSA capacity for two trains is 136,658 lb/h of 97.5 wt% Sulfuric Acid production OR 1,599 stpd on dry basis (100% acid).

Burner flue gas is scrubbed in gasifier quench water to remove over 90% of particulate.
Page 3 of 9 TSD App A

This page left blank Intentionally.
Page 4 of 9 TSD App A

Coal / Coke Case

35.00 MM Btu/hr

1,020 Btu/ft3

Full Rate 8,298 hr/yr

Half Rate 438 hr/yr

Black Start 24 hr/yr

Preheat 60 hr/yr

EMISSIONS: Full Rate

lb/hr avg. lb/hr max. TPY 

SO2 8.30 8.30 34.44

NOx 10.17 10.17 42.20

CO 18.72 18.72 77.69

H2SO4 5.00 5.00 20.73

Mercury (HAP) 3.3E-10 3.3E-10 1.4E-09

EMISSIONS: Full Rate for 219 hr/yr OR Half Rate for 438 hr/yr

lb/hr avg. lb/hr max. TPY 

SO2 4.15 4.15 0.91

NOx 5.09 5.09 1.11

CO 9.36 9.36 2.05

H2SO4 2.50 2.50 0.55

Mercury (HAP) 3.3E-10 3.3E-10 7.1E-11

EMISSIONS: Half Rate (including Black Start)

lb/hr avg. lb/hr max. TPY 

SO2 2.08 2.08 0.02

NOx 2.54 2.54 0.03

CO 4.68 4.68 0.06

H2SO4 1.25 1.25 0.01

Mercury (HAP) 3.3E-10 3.3E-10 3.9E-12

EMISSIONS: Preheat

lb/hr avg. lb/hr max. TPY 

PM10 0.03 0.03 0.00078

SO2 0.02 0.02 0.00062

NOx 3.85 3.85 0.116

CO 1.96 1.96 0.059

VOC 0.19 0.19 0.0057

Total VOC HAPs 0.06 0.06 0.00194

Mercury (HAP) 5.9E-05 5.9E-05 1.8E-06

PM10 VOC SO2

7.600 5.50 0.60

NOx CO

0.110 0.056

Natural Gas SNG (Coal-Coke)

1.95E-07 1.68E-06

Preheat Case: Natural 

Gas Combustion

Mercury Factor (lb/MMBtu)

Combustion

Factor (lb/MMscf)

Factor (lb/MMBtu)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10. 
Page 5 of 9 TSD App A

This page left blank Intentionally.
Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Page 6 of 9 TSD App A

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 111 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per m 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0021 MT

N2O = 0.0002 MT

Emission 

Points

Data 

Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 2,058,824 scf

High heat 

value of the 

fuel from all 

valid samples 

for the year

Annual 

Average 0.00102 MMBtu per scf

WSA Preheat 

Burners

CO    Fuel  HHV  EF 3

2 1 10

CH orN O   FuelHHVEF 3

4 2 1 10

for the year

GHG 

Pollutant

GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 111 1 111

CH4 0.0 21 0

N2O 0.0 310 0

TOTAL = 111 123 TPY CO2

Feeds to WSA (CO2 + combusted CO):

WSA Exhaust = 14538.1 lb-mole/hr

CO2% = 6.60%

CO2 MW = 44.01 lb/lb-mole

CO2 Emissions = 42,209 lb/hr 179,875 TPY CO2

18% Contingency due to lack of performance guarantee

 212,999 TPY CO2
Page 7 of 9 TSD App A

Coal Only Case

35.00 MM Btu/hr

1,020 Btu/ft3

Full Rate 8,298 hr/yr

Half Rate 438 hr/yr

Black Start 24 hr/yr

Preheat 60 hr/yr

EMISSIONS: Full Rate

lb/hr avg. lb/hr max. TPY 

SO2 7.57 7.57 31.40

NOx 7.40 7.40 30.72

CO 13.63 13.63 56.54

H2SO4 3.64 3.64 15.09

Mercury (HAP) 3.3E-10 3.3E-10 1.4E-09

EMISSIONS: Full Rate for 219 hr/yr OR Half Rate for 438 hr/yr

lb/hr avg. lb/hr max. TPY 

SO2 3.78 3.78 0.83

NOx 3.70 3.70 0.81

CO 6.81 6.81 1.49

H2SO4 1.82 1.82 0.40

Mercury (HAP) 3.3E-10 3.3E-10 7.3E-11

EMISSIONS: Half Rate (including Black Start)

lb/hr avg. lb/hr max. TPY 

SO2 1.89 1.89 0.02

NOx 1.85 1.85 0.02

CO 3.41 3.41 0.04

H2SO4 0.91 0.91 0.01

Mercury (HAP) 3.3E-10 3.3E-10 4.0E-12

EMISSIONS: Preheat

lb/hr avg. lb/hr max. TPY 

PM10 0.03 0.03 0.00078

SO2 0.02 0.02 0.00062

NOx 3.85 3.85 0.116

CO 1.96 1.96 0.059

VOC 0.19 0.19 0.0057

Total VOC HAPs 0.06 0.06 0.00194

Mercury (HAP) 5.6E-05 5.6E-05 1.7E-06

PM10 VOC SO2

7.600 5.50 0.60

NOx CO

0.110 0.056

Natural Gas SNG (Coal Only)

Mercury Factor (lb/MMBtu) 1.95E-07 1.61E-06

Combustion

Factor (lb/MMscf)

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM10. 

Factor (lb/MMBtu)

Preheat Case: Natural 

Gas Combustion
Page 8 of 9 TSD App A

This page left blank Intentionally.
Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Page 9 of 9 TSD App A

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 111 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mm 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0021 MT

N2O = 0.0002 MT

Emission 

Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 2,058,824 scf

High heat 

value of the 

fuel from all 

valid samples 

for the year

Annual 

Average 0.00102 MMBtu per scf

WSA Preheat 

Burners

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

for the year

GHG 

Pollutant

GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 111 1 111

CH4 0.0 21 0

N2O 0.0 310 0

TOTAL = 111 123 TPY CO2

Feeds to WSA (CO2 + combusted CO):

WSA Exhaust = 10393.9 lb-mole/hr

CO2% = 10.262%

CO2 MW = 44.01 lb/lb-mole

CO2 Emissions = 46,941 lb/hr 200,039 TPY CO2

18% Contingency due to lack of performance guarantee

 236,877 TPY CO2
Page 1 of 2 TSD A

NAME ASU Cooling Water Tower CAP Unit ID:

Evaporative Cooler Operating Parameters Emissions Emis

Flow Rate, (gpm) Drift Rate, % Drift lb/hr TDS (ppm) PM lb/hr PM TPY PM2.5 lb/hr

54,956 0.0005 138 1,500 0.21 0.90 0.16

Comments:

Drift rate guaranteed by vendor.

Assume all dissolved solids to be PM10. PM2.5 assumed to be 78% of total PM

Total Spray flow provided by B&V.

 COOLING TOWER 

The ASU Cooling Water Tower consists of 6 individual cells, which are being capped under EIQ No. 16a. The total water flow rate cannot 

exceed the CAP value, regardless of the number of cells in operation. Therefore, the emissions listed above are the capped total lb/hr and 

TPY.

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis 

Group).
App A

016a

ssions

PM2.5 TPY

0.70
Page 2 of 2 TSD A

NAME Main Cooling Water Tower CAP Unit ID:

Evaporative Cooler Operating Parameters Emissions Emis

Flow Rate, (gpm) Drift Rate, % Drift lb/hr TDS (ppm) PM10 lb/hr PM10 TPY PM2.5 lb/hr

404,676 0.0005 1,013 1,500 1.52 6.65 1.18

Comments:

Drift rate guaranteed by vendor.

Assume all dissolved solids to be PM10. PM2.5 assumed to be 78% of total PM

Total flow provided by B&V.

 COOLING TOWER 

The Main Cooling Water Tower consists of 24 individual cells, which are being capped under EIQ No. 16b. The total water flow rate cannot 

exceed the CAP value, regardless of the number of cells in operation. Therefore, the emissions listed above are the capped total lb/hr and 

TPY.

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis 

Group).
App A

016b

ssions

PM2.5 TPY

5.19
Page 1 of 1 TSD App A

NAME ASU Molecular Sieve Regeneration Vents

The molecular sieves are regenerated by blowing nitrogen through them.

STACK DATA

HEIGHT 60 ft

DIAMETER 8 ft

GAS EXIT TEMP 260 °F

GAS EXIT VELOCITY 62.02 fps

OPERATING HOURS (each) 1,752 hr/yr

PM10 EMISSIONS Average Maximum Annual PM10 Annual PM2.5

Emissions Hourly Emissions Emissions

Unit ID lb/hr lb/hr TPY TPY

017 A 0.13 0.13 0.11 0.039

017 B 0.13 0.13 0.11 0.039

Total 0.25 0.25 0.22 0.077

Regeneration occurs for 1 hr out of every 5 hr for each molecular sieve.

The vent stream is primarily nitrogen (>98%), with a trace amount of particulates.

Emissions based on engineered equipment data

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group)

VENT SOURCES

17_30464 limited Calcs D 65 5/3/2012
Page 1 of 4 TSD App A

UNCONTROLLED

AVERAGE* EMISSION UNPAVED UNCONTROLLED Trucks Trucks

TYPES OF TRUCKS TRUCK FACTOR PRECIPITATION EMISSION FACTOR Trips Trips

WEIGHT UNPAVED CORRECTION UNPAVED per day per hour

TONS lb/VMT lb/VMT

COAL PILE DOZER OPERATIONS 41.38 1.061 0.68 0.73 155 12.9

ASSUMPTIONS

CAT 824H Wheel Dozer lbs Tons

Estimate Total Capacity 100,195 50.10

Tare 65,325 32.66

Estimate Capacity 34,870 17.44

Average Equipment Weight 82,760 41.38

Maximum Feedstock moved each hr (12hr/day) 450,000 225.00

Maximum Number of Trips per Hour 12.9

Unpaved Road Equation is based on speeds of 15-45 mph.

Based on the speed of the dozer - 3 - 8 mph, an overall 95% control efficiency is possible.

Wet suppression is used for additional control.

A 90% control efficiency is being conservatively used.

Average daily dozer travel distance each trip assumed to be 1/2 pile radius times two (for round trip). 

Emission Calculation for Dozer Activity on the pile [EU-012P & EU-012Q / PM10] (Calc for each pile)
Page 2 of 4 TSD App A

Ave Daily

MILES MILES ON-SITE VMT/DAY UNCONTROLLED PERCENT CONTROLLED CONTROLLED CONTROLLED

ROUND TRIP ROUND TRIP UNPAVED EMISSIONS CONTROL EMISSIONS EMISSIONS EMISSIONS

PAVED UNPAVED LBS/DAY LBS/DAY LBS/HR* Tons/yr

each trip

0 0.05105 7.91 5.7 90% 0.5747 0.0239 0.1049

UNPAVED ROADS EQUATIONS

E = size specific emission factor (lbs/VMT) Eext = natural mitigation emission factor (lb/VMT)

k = particle size multiplier for particle size range P = number of days per year with 0.01 in or more of precipitation

s = surface material silt content (%) 

a = constant based on size of particulate

b = constant based on size of particulate

W = Coal Trucks = 50 tons, Ash Trucks = 50 tons, Limestone Trucks = 25 tons

INPUTS

k 1.5 lb/VMT P 115 wet days/yr

s 2.2 % AP-42 13.2.4-1

a 0.9

b 0.45

P 115 days

Emission Calculation for Dozer Activity on the pile [EU-012P & EU-012Q / PM10] (Calc. for each pile)

    12 3 * s * Wa b

E  k 



 



  

365

365 P

E ext E
Page 3 of 4 TSD App A

UNCONTROLLED

AVERAGE* EMISSION UNPAVED UNCONTROLLED Trucks Trucks

TYPES OF TRUCKS TRUCK FACTOR PRECIPITATION EMISSION FACTOR Trips Trips

WEIGHT UNPAVED CORRECTION UNPAVED per day per hour

TONS lb/VMT lb/VMT

COAL PILE DOZER OPERATIONS 41.38 0.106 0.68 0.07 155 12.9

ASSUMPTIONS

CAT 824H Wheel Dozer lbs Tons

Estimate Total Capacity 100,195 50.10

Tare 65,325 32.66

Estimate Capacity 34,870 17.44

Average Equipment Weight 82,760 41.38

Maximum Feedstock moved each hr (12hr/day) 450,000 225.0

Maximum Number of Trips per Hour 12.9

Unpaved Road Equation is based on speeds of 15-45 mph.

Based on the speed of the dozer - 3 - 8 mph, an overall 95% control efficiency is reasonable.

Average daily dozer travel distance each trip assumed to be 1/2 pile radius times two (for round trip). 

Emission Calculation for Dozer Activity on the pile [EU-012P & EU-012Q / PM2.5] (each pile)
Page 4 of 4 TSD App A

Ave Daily

MILES MILES ON-SITE VMT/DAY UNCONTROLLED PERCENT CONTROLLED CONTROLLED CONTROLLED

ROUND TRIP ROUND TRIP UNPAVED EMISSIONS CONTROL EMISSIONS EMISSIONS EMISSIONS

PAVED UNPAVED* LBS/DAY LBS/DAY LBS/HR* Tons/yr

each trip

0 0.05105 7.9 0.57 90% 0.0575 0.0024 0.0105

UNPAVED ROADS EQUATIONS

E = size specific emission factor (lbs/VMT) Eext = natural mitigation emission factor (lb/VMT)

k = particle size multiplier for particle size range P = number of days per year with 0.01 in or more of precipitation

s = surface material silt content (%) 

a = constant based on size of particulate

b = constant based on size of particulate

W = Coal Trucks = 50 tons, Ash Trucks = 50 tons, Limestone Trucks = 25 tons

INPUTS

k 0.15 lb/VMT P 115 wet days/yr

s 2.2 % AP-42 13.2.4-1

a 0.9

b 0.45

P 115 days

Emission Calculation for Dozer Activity on the pile [EU-012P & EU-012Q / PM2.5] (each pile)

    12 3 * s * Wa b

E  k 



 



  

365

365 P

E ext E
UNCONTROLLED

AVERAGE* EMISSION UNPAVED UNCONTROLLED Trucks Truc

TYPES OF TRUCKS TRUCK FACTOR PRECIPITATION EMISSION FACTOR Trips Trip

WEIGHT UNPAVED CORRECTION UNPAVED per day per h

TONS lb/VMT lb/VMT

COAL PILE DOZER OPERATIONS 41.38 4.868 0.68 3.33 155 12.

ASSUMPTIONSCAT 824H Wheel Dozer lbs TonsEstimate Total Capacity 100,195 50.10Tare 65,325 32.66Estimate Capacity 34,870 17.44Average Equipment Weight 82,760 41.38Maximum Feedstock moved each hr (12hr/day) 450,000 225.00Maximum Number of Trips per Hour 12.9

Emission Calculation for Dozer Activity on the pile [EU-012P & EU-012Q / Total Particulate]

70

Unpaved Road Equation is based on speeds of 15-45 mph.Based on the speed of the dozer - 3 - 8 mph, an overall 95% control efficiency is possible.Wet suppression is used for additional control.A 90% control efficiency is being conservatively used.Average daily dozer travel distance each trip assumed to be 1/2 pile radius times two (for round trip). 

70
MILES MILES ON-SITE VMT/DAY UNCONTROLLED PERCENT CONTROLLE

ROUND TRIP ROUND TRIP UNPAVED EMISSIONS CONTROL EMISSIONS 

PAVED UNPAVED LBS/DAY LBS/DAY 

each trip

0 0.05105 7.91 26.4 90% 2.6357 

UNPAVED ROADS EQUATIONS

E = size specific emission factor (lbs/VMT) Eext = natural mitigation emission factor (lb/VM

k = particle size multiplier for particle size range P = number of days per year with 0.01 in or m

s = surface material silt content (%) 

a = constant based on size of particulate

b constant based on size of particulate

Emission Calculation for Dozer Activity on the pile [EU-012P & EU-012Q / Total Parti







 12

3 * s * Wa b

E



k 

 







365

365

P

E ext

E

71

b = constant based on size of particulate

W = Vehicle average weight

INPUTS

k 4.9 lb/VMT P 

s 2.2 % AP-42 13.2.4-1

a 0.7b 0.45

P 115 days

71
CONTROLLED

EMISSIONS

Tons/yr

0.4810

72
Emissions Calculations for Fugitive Dust from Wind Erosion [EU-012W &EU-012X]

Page 1 of 1 TSD App A

Referened document can be obtained at:

http://www.wrapair.org/forums/dejf/fdh/content/Ch9-Storage_Pile_Wind%20Erosion_Rev06.pdf

WRAP document basis for equation is stated to be from 1989 EPA document:

USEPA, January 1989. Air/Superfund National Technical Guidance Study Series;

Volume III – Estimation of Air Emissions from Cleanup Activities at Superfund

Sites, Interim final report EPA-450/1-89-003.

Assumptions

Data Descript. Basis

silt 2.20 % (s) Silt content

% windy 100.00 % (f) % high wind Conservatively assume high winds on worse case day.

PM10 Multiplier 0.5 ratio PM10 vs TSP

PM2.5 Multiplier 0.053 ratio PM2.5 vs TSP

Control effective. 90% Watering and compaction / BACT

Pile size coal 6.230 acres (see attached Surf. Area Calcs.)

Pile size coke 5.180 acres (see attached Surf. Area Calcs.)

Basis: Wrap Fugitive Dust Handbook, Prepared for Governers Conference, Western Regional Air 

Partnership (WRAP) Methodology for wind erosion. 

AP-42 13.2.4-1, Coal as received, coal power plant. Also 

used for coke (coke should be lower).

Calculated Emiss. Factors from above Equation

Uncontrolled Emissions Factors

TSP 16.62 lb/day/acre of surface

PM10 8.31 lb/day/acre of surface

PM2.5 0.881 lb/day/acre of surface

Controlled Emissions Factors

PM10 0.83 lb/day/acre of surface

PM2.5 0.088 lb/day/acre of surface

Calculated Emissions Rate

Controlled Emissions Rate - lb/hr worse case day

(= Controlled factor * acres / 24hr/day)

Coal Pile Coke Pile

PM10 0.216 lb PM10/hr PM10 0.179 lb PM10/hr

PM2.5 0.023 lb PM2.5/hr PM2.5 0.019 lb PM2.5/hr

Annual Emissons - conservatively assuming max rate on all days.

PM10 0.94 TPY PM10 PM10 0.79 TPY PM10

PM2.5 0.10 TPY PM2.5 PM2.5 0.08 TPY PM2.5

". . .Calculated emissions represent intermittent events and should not be input directly into

dispersion models that assume steady-state emission rates. "

Note: the above method is used for calculating emissions for air modeling purposes in preference to AP42 

section 13.2.5 because, as stated in AP42 section 13.2.5, page 13.2.5-3, regarding its wind erosion formula: 
Emissions Calculations for Fugitive Dust from Wind Erosion [EU-012W &EU-012X] 

6.23 acres

271,379 ft^2

top height = 203

top diameter = 150

top slant = 135.62 √[(top height ‐ pile height)^2+(top diameter/2)^2]

pile height = 90

pile diameter = 539

pile slant = 337.40 √[(top height)^2+(pile diameter/2)^2]

Surface area truncated cone = SA of whole cone - SA of top/removed cone + area of top.

5.18 acres

225,647 ft^2

top height = 186

top diameter = 150

top slant = 135.62 √[(top height ‐ pile height)^2+(top diameter/2)^2]

pile height = 73

pile diameter = 494

pile slant = 309.20 √[(top height)^2+(pile diameter/2)^2]

coal pile surface area =

coke pile surface area =

2

p p t t t SA    r  s   r  s   r

17_30464 limited Calcs D 74 
Page 2 of 2 TSD App A

Emissions Calculations for Fugitive Dust from Wind Erosion [EU-012W &EU-012X]

Coke x 1 100% coal 85% coal 51% coal

BOOM REACH 135.00 150.00 150.00 150.00 FT

ANGLE OF REPOSE 37.00 37.00 37.00 37.00 DEGREES

PILE HEIGHT 73.00 90.00 90.00 90.00 FT

TOWER RADIUS 20.00 20.00 20.00 20.00 FT

TANGENT 0.75 0.75 0.75 0.75 

OUTSIDE CONE RADIUS 269.43 231.87 269.43 269.43 FT

OUTSIDE PILE DIAMETER 538.85 463.74 538.85 538.85 FT

PI*R*R 228,051.00 168,901.00 228,051.00 228,051.00 SQ FT

HEIGHT OF TOTAL CONE 203.04 174.74 203.04 203.04 FT

TOTAL CONE CAPACITY 15,434,491.70 9,837,695.00 15,434,491.70 15,434,491.70 CU FT

TOP CONE RADIUS 150.00 135.00 150.00 150.00 FT

PI*R*R 70,685.80 57,255.50 70,685.80 70,685.80 

HEIGHT OF TOP CONE 113.04 101.74 113.04 113.04 FT

TOP CONE CAPACITY 2,663,441.00 1,941,649.00 2,663,441.00 2,663,441.00 CU FT

INSIDE TOWER 1,257.00 1,257.00 1,257.00 1,257.00 SQ FT

LOSS CAPACITY - TOWER 113,130.00 91,761.00 113,130.00 113,130.00 CU FT

NET CAPACITY 12,657,920.70 7,804,285.00 12,657,920.70 12,657,920.70 CU FT

MAT'L DENSITY 47.00 50.00 50.00 50.00 LB/CU FT

NET CAPACITY 632,896,035.00 366,801,395.00 632,896,035.00 632,896,035.00 LBS

 2,000.00 2,000.00 2,000.00 2,000.00 LBS/TON

NET CAPACITY 316,448.00 183,400.70 316,448.00 316,448.00 TONS

AREA OF PILE 228,050.64 168,901.25 228,050.64 228,050.64 SQ FT

AREA OF PILE 5.24 3.88 5.24 5.24 ACRES

DAYS STORAGE 33.08 44.87 38.92 64.86 DAYS each

Coal Consumption (100% fuel) 8,131.10 9,565.00 4,878.66 tpd

Coke Consumption (49% fuel) 4,087.00 tpd

% Tons Days storage

Coke 49% 4,087.00 44.87 

Coal 51% 4,878.15 64.87 

85% 8,130.25 38.92 

100% 9,565.00 33.08 

AGRICO STACKER STORAGE PILE CAPACITY

17_30464 limited Calcs D 75 5/3/2012
COMBUSTION SOURCES Page 1 of 2 TSD App A

NAME ZLD Spray Dryer Stack Unit ID: 032

STACK DATA

HEIGHT 100 ft

DIAMETER 1 ft

GAS EXIT TEMP 310 °F

GAS EXIT VELOCITY 35.49 fps

COMBUSTION DATA

HEAT INPUT 5.6 MM Btu/hr

AP-42 NATURAL GAS HEAT VALUE 1,020 Btu/ft3

PROCESS FLOW RATE 2,735 dscfm

OPERATING HOURS 8,760 hr/yr

EMISSIONS:

lb/hr avg. lb/hr max. TPY 

PM10 0.12 0.12 0.51

PM2.5 0.11 0.11 0.48

SO2 0.003 0.003 0.015

NOx 0.197 0.197 0.86

CO 0.203 0.203 0.89

VOC 0.030 0.030 0.13

Total VOC HAPs 0.010 0.010 0.046

Mercury (HAP) 9.4E-06 9.4E-06 4.1E-05

CALCULATIONS

Emissions (SO2) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft3

) X Heat Input (MMBtu/hr)

Emissions (NOx, CO, VOC) (Avg. lb/hr) = Vendor Factor (lb/MM Btu/hr) x Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton)

Average Emissions (lb/hr) = Maximum Emissions.

Natural Gas Combustion SO2 Fabric Filter PM10 

0.60 Factor (gr/dscf) 0.0050

Natural Gas Combustion NOx CO VOC

0.035 0.036 0.005

Natural Gas SNG (Coal-Coke) SNG (Coal Only)

1.95E-07 1.68E-06 1.61E-06

Comments:

Mercury Factor (lb/MMBtu)

SO2 emissions based on 100% conversion of fuel sulfur to SO2. Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). 

Natural gas or SNG may be combusted. Conservatively assumed natural gas for SO2 calculation (as SNG contains no sulfur).

Total HAPs are based on AP-42 Section 1.4, Tables 1.4-3 and 1.4-4.

PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculator for SCCs per Roy Huntley (EPA EI and Analysis Group).

Factor (lb/MM scf)

Factor (lb/MM Btu)

Source: Emission factors for NOx, CO, VOC and PM10 are based on information from vendor supplied data.
Page 2 of 2 TSD App A

Stationary Combustion Sources - Natural Gas (semi-annual or more frequent analysis)

Meter ID Billing Meter

Alt. Meter ID

Meter Name

Equation C-2a

CO2 = Annual CO2 mass emissions (metric tons)

Fuel = Annual volume of the gaseous fuel combusted (scf)

HHV = Annual average high heat value (MMBtu per mass or volume)

EF = Fuel-specific default CO2 emission factor (kg CO2/MMBtu) = 53.02

1 x 10-3 = Conversion factor from kilograms to metric tons

CO2 = 2,616 MT

Equation C-9a

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of fuel (metric tons)

Fuel = Mass or volume of the fuel combusted during the reporting year

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (MMBtu per mass or volume)

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 = (kg CH4 or N2O per mmBtu) = 0.001 CH4

0.0001 N2O

1 x 10-3 = Conversion factor from kilograms to metric tons

CH4 = 0.0493 MT

N2O = 0.0049 MT

Emission Points Data Required

MRR

Frequency Data Units

Volume of the 

gaseous fuel 

combusted

Annual 48,379,046 scf

High heat value 

of the fuel from all 

valid samples for 

Annual 

Average 0.00102 MMBtu per scf

ZLD Spray Dryer 

Stack

CO    Fuel  HHV  EF 3

2 1 10

CH orN O    Fuel  HHV  EF 3

4 2 1 10

valid samples for 

the year

Average

GHG Pollutant GHG

Metric Tons GWP Factors Metric Tons CO2e

CO2 2,616 1 2,616

CH4 0.049 21 1

N2O 0.0049 310 2

TOTAL = 2,619 2,886 TPY CO2
URS INDIANA GASIFICATION FACILITY Vent Calculations

NAME ZLD Inert Gas Vent Unit ID: 033

Mercury is controlled using a sulfided carbon adsorbent with a vendor guarantee of 0.5 ppbv.

STACK DATA

HEIGHT 15 ft

DIAMETER 0.083 ft

GAS EXIT TEMP 150 °F

GAS EXIT VELOCITY 31.74 fps

OPERATING HOURS 8,760 hr/yr

Average Maximum Average Annual Average Annual

EMISSIONS Emissions Hourly Emissions Emissions

lb/hr lb/hr lb/yr TPY

Carbon Dioxide 46.50 46.50 407,340 203.7

Mercury 1.40E-07 0.0149 0.7168 < 0.001 

Assumptions:

Vent stream is 75.5% CO2 and 24.5% H20.

Mercury in solids feed to Gasifier at max is 0.745 lb/hr

Gasification process wastewater picks up 2% of the mercury in the gasifiers, resulting in 0.0149 lb/hr mercury in the water, all of which goes to the ZLD inert gas vent.

Sulfided carbon adsorbent control is >99.99% effective, but is offline up to 2 days/year for carbon changeout.

VENT SOURCES

17_30464 limited Calcs 78 5/3/2012
Basis of Total HAP Emission Factor for Natural Gas Combustion Page 1 of 2 TSD App A

Project: Indiana Gasification

Emissions Estimation 

AP-42 Heating Value 1,020 Btu/scf

EMISSION FACTOR BASED INVENTORY Notes

POLLUTANT CAS # Em.Fac. Source lb/MMscf lb/MMBtu

2-Methylnaphthalene 91-57-6 AP-42, Table 1.4-3 2.40E-05 2.35E-08 b

3-Methylchloranthrene 56-49-5 AP-42, Table 1.4-3 1.80E-06 1.76E-09 b

7,12-Dimethylbenz(a)anthracene --- AP-42, Table 1.4-3 1.60E-05 1.57E-08 b, c

Acenaphthene 83-32-9 AP-42, Table 1.4-3 1.80E-06 1.76E-09 b, c

Acenaphthylene 203-96-8 AP-42, Table 1.4-3 1.80E-06 1.76E-09 b, c

Anthracene 120-12-7 AP-42, Table 1.4-3 2.40E-06 2.35E-09 b, c

Benz(a)anthracene 56-55-3 AP-42, Table 1.4-3 1.80E-06 1.76E-09 b, c

Benzene 71-43-2 AP-42, Table 1.4-3 2.10E-03 2.06E-06 b

Benzo(a)pyrene 50-32-8 AP-42, Table 1.4-3 1.20E-06 1.18E-09 b, c

Benzo(b)fluoranthene 205-99-2 AP-42, Table 1.4-3 1.80E-06 1.76E-09 b, c

Benzo(g,h,i)perylene 191-24-2 AP-42, Table 1.4-3 1.20E-06 1.18E-09 b, c

Benzo(k)fluoranthene 205-82-3 AP-42, Table 1.4-3 1.80E-06 1.76E-09 b, c

Chrysene 218-01-9 AP-42, Table 1.4-3 1.80E-06 1.76E-09 b, c

Dibenzo(a,h)anthracene 53-70-3 AP-42, Table 1.4-3 1.20E-06 1.18E-09 b, c

Dichlorobenzene 25321-22-6 AP-42, Table 1.4-3 1.20E-03 1.18E-06 b

Fluoranthene 206-44-0 AP-42, Table 1.4-3 3.00E-06 2.94E-09 b, c

Fluorene 86-73-7 AP-42, Table 1.4-3 2.80E-06 2.75E-09 b, c

Formaldehyde 50-00-0 AP-42, Table 1.4-3 7.50E-02 7.35E-05 b

Hexane 110-54-3 AP-42, Table 1.4-3 1.80E+00 1.76E-03 b

Indeno(1,2,3-cd)pyrene 193-39-5 AP-42, Table 1.4-3 1.80E-06 1.76E-09 b, c

Naphthalene 91-20-3 AP-42, Table 1.4-3 6.10E-04 5.98E-07 b

Phenanathrene 85-01-8 AP-42, Table 1.4-3 1.70E-05 1.67E-08 b, c

Pyrene 129-00-0 AP-42, Table 1.4-3 5.00E-06 4.90E-09 b, c

Toluene 108-88-3 AP-42, Table 1.4-3 3.40E-03 3.33E-06 b

Arsenic 7440-38-2 AP-42, Table 1.4-4 2.00E-04 1.96E-07 b

Beryllium 7440-41-7 AP-42, Table 1.4-4 1.20E-05 1.18E-08 b

Cadmium 7440-43-9 AP-42, Table 1.4-4 1.10E-03 1.08E-06 b

Chromium 7440-47-3 AP-42, Table 1.4-4 1.40E-03 1.37E-06 b

Cobalt 7440-48-4 AP-42, Table 1.4-4 8.40E-05 8.24E-08 b

Manganese 7439-96-5 AP-42, Table 1.4-4 3.80E-04 3.73E-07 b

Mercury 7439-97-6 AP-42, Table 1.4-4 2.60E-04 2.55E-07 b

Nickel 7440-02-0 AP-42, Table 1.4-4 2.10E-03 2.06E-06 b

Selenium 7782-49-2 AP-42, Table 1.4-4 2.40E-05 2.35E-08 b

Total HAP = 1.88796 0.00185

Notes: 

a. Criteria pollutant by name or association, i.e., VOC as surrogates for O3

b. Hazardous Air Pollutant (HAP) as defined by Section 112(b) of the Clean Air Act.

c. HAP because it is Polycyclic Organic Matter (POM). POM is a HAP as defined by Section 112(b) of Clean Air Act

d. non-VOC per 40 CFR 51.100(s)(1); methane and ethane are not considered as regulated photochemical reactive VOC 

e. Soot in concentration values, 0 micrograms per liter (ug/L); lightly smoking flares, 40 ug/L; average smoking flares, 177 ug/L; and heavily smoking flares 274 ug/L.

f. To be used where source testing or fuel analysis are not required by the AB2588 Criteria and Guidelines Regulations, Appendix D

g. Based on 100% conversion of fuel sulfur to SO2.

Assumes sulfur content is natural gas of 2,000 grains/10^6 scf. The SO2 emission factor in this table can

be converted to other natural gas sulfur contents by multiplying the SO2 emission factor by the ratio of

the site-specific sulfur content (grains/10^6 scf) to 2,000 grains/10^6 scf.

AP-42 Em. Factor
Page 2 of 2 TSD App A

EMISSION FACTOR BASED INVENTORY 001 002 005 007 008 015 024 025 029 030 032 FUG

112252111111 Notes

POLLUTANT CAS # 0.27 0.27 408.17 38.81 35.00 35.00 ---- 5.63 - MMBtu/hr

2-Methylnaphthalene 91-57-6 6.24E-09 6.24E-09 9.60E-06 9.13E-07 4.12E-06 8.24E-07 ---- 1.33E-07 - b

3-Methylchloranthrene 56-49-5 4.68E-10 4.68E-10 7.20E-07 6.85E-08 3.09E-07 6.18E-08 ---- 9.94E-09 - b

7,12-Dimethylbenz(a)anthracene --- 4.16E-09 4.16E-09 6.40E-06 6.09E-07 2.75E-06 5.49E-07 ---- 8.84E-08 - b, c

Acenaphthene 83-32-9 4.68E-10 4.68E-10 7.20E-07 6.85E-08 3.09E-07 6.18E-08 ---- 9.94E-09 - b, c

Acenaphthylene 203-96-8 4.68E-10 4.68E-10 7.20E-07 6.85E-08 3.09E-07 6.18E-08 ---- 9.94E-09 - b, c

Anthracene 120-12-7 6.24E-10 6.24E-10 9.60E-07 9.13E-08 4.12E-07 8.24E-08 - - 2.88E-07 - 1.33E-08 - b, c

Arsenic 7440-38-2 5.20E-08 5.20E-08 8.00E-05 7.61E-06 3.43E-05 6.86E-06 ---- 1.10E-06 - b

Benz(a)anthracene 56-55-3 4.68E-10 4.68E-10 7.20E-07 6.85E-08 3.09E-07 6.18E-08 ---- 9.94E-09 - b, c

Benzene 71-43-2 5.46E-07 5.46E-07 8.40E-04 7.99E-05 3.60E-04 7.21E-05 - - 1.08E-03 5.59E-05 1.16E-05 - b

Benzo(a)pyrene 50-32-8 3.12E-10 3.12E-10 4.80E-07 4.57E-08 2.06E-07 4.12E-08 ---- 6.63E-09 - b, c

Benzo(b)fluoranthene 205-99-2 4.68E-10 4.68E-10 7.20E-07 6.85E-08 3.09E-07 6.18E-08 ---- 9.94E-09 - b, c

Benzo(g,h,i)perylene 191-24-2 3.12E-10 3.12E-10 4.80E-07 4.57E-08 2.06E-07 4.12E-08 ---- 6.63E-09 - b, c

Benzo(k)fluoranthene 205-82-3 4.68E-10 4.68E-10 7.20E-07 6.85E-08 3.09E-07 6.18E-08 ---- 9.94E-09 - b, c

Beryllium 7440-41-7 3.12E-09 3.12E-09 4.80E-06 4.57E-07 2.06E-06 4.12E-07 ---- 6.63E-08 - b

Biphenyl 92-52-4 -------- 3.18E-06 - - - b,c

Cadmium 7440-43-9 2.86E-07 2.86E-07 4.40E-04 4.19E-05 1.89E-04 3.77E-05 ---- 6.07E-06 - b

Carbonyl Sulfide 463-58-1 6.67E-02 - - 7.80E-02 ------- 2.82E-03 b

Chromium 7440-47-3 3.64E-07 3.64E-07 5.60E-04 5.33E-05 2.40E-04 4.80E-05 ---- 7.73E-06 - b

Chrysene 218-01-9 4.68E-10 4.68E-10 7.20E-07 6.85E-08 3.09E-07 6.18E-08 ---- 9.94E-09 - b, c

Cobalt 7440-48-4 2.18E-08 2.18E-08 3.36E-05 3.20E-06 1.44E-05 2.88E-06 ---- 4.64E-07 - b

Cumene 98-82-8 --------- 4.65E-06 - - b

Dibenzo(a,h)anthracene 53-70-3 3.12E-10 3.12E-10 4.80E-07 4.57E-08 2.06E-07 4.12E-08 ---- 6.63E-09 - b, c

Dichlorobenzene 25321-22-6 3.12E-07 3.12E-07 4.80E-04 4.57E-05 2.06E-04 4.12E-05 ---- 6.63E-06 - b

Ethylbenzne 100-41-4 -------- 5.37E-03 2.07E-05 - - b

Fluoranthene 206-44-0 7.80E-10 7.80E-10 1.20E-06 1.14E-07 5.15E-07 1.03E-07 ---- 1.66E-08 - b, c

Fluorene 86-73-7 7.28E-10 7.28E-10 1.12E-06 1.07E-07 4.80E-07 9.61E-08 ---- 1.55E-08 - b, c

Formaldehyde 50-00-0 1.95E-05 1.95E-05 3.00E-02 2.85E-03 1.29E-02 2.57E-03 ---- 4.14E-04 - b

Hexane 110-54-3 4.68E-04 4.68E-04 7.20E-01 6.85E-02 3.09E-01 6.18E-02 - - - 5.42E-04 9.94E-03 - b

Indeno(1,2,3-cd)pyrene 193-39-5 4.68E-10 4.68E-10 7.20E-07 6.85E-08 3.09E-07 6.18E-08 ---- 9.94E-09 - b, c

Manganese 7439-96-5 9.88E-08 9.88E-08 1.52E-04 1.45E-05 6.52E-05 1.30E-05 ---- 2.10E-06 - b

Mercury 7439-97-6 6.76E-08 6.76E-08 1.04E-04 9.89E-06 4.46E-05 8.92E-06 ---- 1.44E-06 - b

Methanol 67-56-1 - - - 1.56E+00 - - 3.58E-02 3.03E-02 - - - 8.40E-02 b

Naphthalene 91-20-3 1.59E-07 1.59E-07 2.44E-04 2.32E-05 1.05E-04 2.09E-05 - - 2.05E-04 - 3.37E-06 - b

Nickel 7440-02-0 5.46E-07 5.46E-07 8.40E-04 7.99E-05 3.60E-04 7.21E-05 ---- 1.16E-05 - b

Phenanathrene 85-01-8 4.42E-09 4.42E-09 6.80E-06 6.47E-07 2.92E-06 5.83E-07 ---- 9.39E-08 - b, c

Pyrene 129-00-0 1.30E-09 1.30E-09 2.00E-06 1.90E-07 8.58E-07 1.72E-07 ---- 2.76E-08 - b, c

Selenium 7782-49-2 6.24E-09 6.24E-09 9.60E-06 9.13E-07 4.12E-06 8.24E-07 ---- 1.33E-07 - b

Toluene 108-88-3 8.84E-07 8.84E-07 1.36E-03 1.29E-04 5.83E-04 1.17E-04 - - 3.21E-03 1.40E-04 1.88E-05 - b

Xylene 1330-20-7 -------- 6.85E-03 4.26E-05 - - b

6.72E-02 4.91E-04 7.55E-01 1.71E+00 3.24E-01 6.48E-02 3.58E-02 3.03E-02 1.67E-02 8.05E-04 1.04E-02 8.69E-02 -

Notes: 

a. Criteria pollutant by name or association, i.e., VOC as surrogates for O3

b. Hazardous Air Pollutant (HAP) as defined by Section 112(b) of the Clean Air Act.

c. HAP because it is Polycyclic Organic Matter (POM). POM is a HAP as defined by Section 112(b) of Clean Air Act

d. non-VOC per 40 CFR 51.100(s)(1); methane and ethane are not considered as regulated photochemical reactive VOC 

e. Soot in concentration values, 0 micrograms per liter (ug/L); lightly smoking flares, 40 ug/L; average smoking flares, 177 ug/L; and heavily smoking flares 274 ug/L.

f. To be used where source testing or fuel analysis are not required by the AB2588 Criteria and Guidelines Regulations, Appendix D

g. Based on 100% conversion of fuel sulfur to SO2.

Assumes sulfur content is natural gas of 2,000 grains/10^6 scf. The SO2 emission factor in this table can

be converted to other natural gas sulfur contents by multiplying the SO2 emission factor by the ratio of

the site-specific sulfur content (grains/10^6 scf) to 2,000 grains/10^6 scf.

h. lb/hr Values in columns 024, 025, 029, and 030 are sourced from the Tanks Emissions Calculations 

i. lb/hr Vlaues in column FUG are sourced from the Fugitive Emissions Calculations

j. the lb/hr vlaues for Methanol and Carbonyl Sulfide in Unit 007 are sourced from the Combustion Emissions Calculations

k. Thelb/hr value fro Carbonyl Sulfide in Unit 001 is sourced from the Flares Emissions Calculations

lb/hr (per individual emission unit, maximum short term)

Number of emission units

Total
Page 1 of 6 TSD App A

NAME Fugitive Emissions - Gasification, Shift Conversion, Methanation, AGR (Rectisol) Unit ID: FUG

Methanol fugitives in the AGR (Rectisol) Unit: 100% Methanol

lb/hr/component lb/hr % lb/hr TPY

Gas 0 0.0089 0 97 0 0

Light Liquid 250 0.0035 0.875 97 0.026 0.11

Heavy Liquid 0 0.0007 0 0 0 0

Gas 0 0.0029 0 30 0 0

Light Liquid 500 0.0005 0.250 97 0.008 0.033

Heavy Liquid 0 0.00007 0 30 0 0

Light Liquid 8 0.0386 0.309 85 0.046 0.20

Heavy Liquid 0 0.0161 0 0 0 0

Compressors Gas 0 0.5027 0 75 0 0

Gas 0 0.2293 0 100 0 0

Light Liquid 19 0.0035 0.067 100 0 0

Sampling Connections All 4 0.033 0.132 97 0.004 0.017

Total Methanol 781 0.08 0.37

VOC fugitives in the AGR (Rectisol) Unit: 100% non-TAP VOC (propylene)

lb/hr/component lb/hr % lb/hr TPY

Gas 78 0.0089 0.694 97 0.021 0.09

Light Liquid 33 0.0035 0.116 97 0.003 0.015

Heavy Liquid 0 0.0007 0 0 0 0

Gas 193 0.0029 0.560 97 0.017 0.074

Light Liquid 82 0.0005 0.041 97 0.001 0.005

Heavy Liquid 0 0.00007 0 30 0 0

Light Liquid 2 0.0386 0.077 85 0.012 0.051

Heavy Liquid 0 0.0161 0 0 0 0

Compressors Gas 3 0.5027 1.508 85 0.23 0.99

Gas 7 0.2293 1.605 100 0 0

Light Liquid 0 0.0035 0 100 0 0

Sampling Connections All 1 0.033 0.033 97 0.001 0.004

Total VOCs 399 0.28 1.23

Carbonyl Sulfide

COS Conc

%v lb/hr/component lb/hr % lb/hr TPY

Valves Raw Syngas 100 0.029 0.0089 0.00026 0 2.6E-04 1.1E-03

Shifted Syngas 50 0.008 0.0089 0.00003 0 3.3E-05 1.5E-04

Mixed Syngas 100 0.024 0.0089 0.00022 0 2.2E-04 0.00095

Sweet Syngas 20 5.0E-07 0.0089 8.9E-10 0 8.9E-10 3.9E-09

Flanges Raw Syngas 250 0.029 0.0029 0.00021 0 2.1E-04 0.00093

Shifted Syngas 100 0.008 0.0029 0.00002 0 2.2E-05 9.5E-05

Mixed Syngas 250 0.024 0.0029 0.00018 0 1.8E-04 0.00077

Sweet Syngas 50 5.0E-07 0.0029 7.3E-10 0 7.3E-10 3.2E-09

Compressor Seals Raw Syngas 0 0.029 0.5027 0 000

Shifted Syngas 0 0.008 0.5027 0 000

Mixed Syngas 0 0.024 0.5027 0 000

Sweet Syngas 0 5.0E-07 0.5027 0 000

Pump Seals Raw Syngas 0 0.029 0.0386 0 000

Shifted Syngas 0 0.008 0.0386 0 000

Mixed Syngas 0 0.024 0.0386 0 000

Sweet Syngas 0 5.0E-07 0.0386 0 000

Relief Valves Raw Syngas 20 0.029 0.2293 0.00134 0 0.0013 0.0059

Shifted Syngas 4 0.008 0.2293 0.00007 0 6.9E-05 3.0E-04

Mixed Syngas 8 0.024 0.2293 0.00045 0 4.5E-04 0.00196

Sweet Syngas 4 5.0E-07 0.2293 4.6E-09 0 4.6E-09 2.01E-08

Sample Connections Raw Syngas 2 0.029 0.033 0.00002 0 1.9E-05 8.5E-05

Shifted Syngas 2 0.008 0.033 0.00000 0 5.0E-06 2.2E-05

Mixed Syngas 2 0.024 0.033 0.00002 0 1.6E-05 7.0E-05

Sweet Syngas 2 5.0E-07 0.033 3.3E-10 0 3.3E-10 1.4E-09

Total COS 2.8E-03 1.2E-02

No Control Efficiency claimed due to low concentration. Total VOCs = 0.37 1.61

FUGITIVES

Emission Factors

Uncontrolled 

Process Emissions

Stream

Component 

Count

Valves

Emission Factors

Uncontrolled 

Emissions

Uncontrolled 

Emissions

Flanges

Pumps

Relief Valves

Fugitive Source

Stream Type

Fugitive Source

Stream Type

Component 

Count

Emission Factors

Valves

Fugitive Source

Flanges

Pumps

Relief Valves

Component

Count

Control 

Efficiency Controlled Emissions

Control 

Efficiency Controlled Emissions

Controlled Emissions

Control 

Efficiency
Carbon Monoxide Page 2 of 6 TSD App A

CO Conc

%v lb/hr/component lb/hr % lb/hr TPY

Valves Raw Syngas 100 20.4 0.0089 0.18156 0 0.1816 0.795

Shifted Syngas 50 3.7 0.0089 0.01666 0 1.7E-02 0.073

Mixed Syngas 100 14.8 0.0089 0.13181 0 0.1318 0.577

Sweet Syngas 20 22.5 0.0089 0.03997 0 0.0400 0.175

Flanges Raw Syngas 250 20.4 0.0029 0.14790 0 0.1479 0.648

Shifted Syngas 100 3.7 0.0029 0.01086 0 0.0109 0.048

Mixed Syngas 250 14.8 0.0029 0.10737 0 0.1074 0.470

Sweet Syngas 50 22.5 0.0029 0.03256 0 0.0326 0.143

Compressor Seals Raw Syngas 0 20.4 0.5027 0 000

Shifted Syngas 0 3.7 0.5027 0 000

Mixed Syngas 0 14.8 0.5027 0 000

Sweet Syngas 0 22.5 0.5027 0 000

Pump Seals Raw Syngas 0 20.4 0.0386 0 000

Shifted Syngas 0 3.7 0.0386 0 000

Mixed Syngas 0 14.8 0.0386 0 000

Sweet Syngas 0 22.5 0.0386 0 000

Relief Valves Raw Syngas 20 20.4 0.2293 0.93554 0 0.9355 4.0977

Shifted Syngas 4 3.7 0.2293 0.03434 0 0.0343 0.1504

Mixed Syngas 8 14.8 0.2293 0.27167 0 0.2717 1.1899

Sweet Syngas 4 22.5 0.2293 0.20596 0 0.2060 0.9021

Sample Connections Raw Syngas 2 20.4 0.033 0.01346 0 1.3E-02 0.0590

Shifted Syngas 2 3.7 0.033 0.00247 0 2.5E-03 1.1E-02

Mixed Syngas 2 14.8 0.033 0.00977 0 9.8E-03 0.0428

Sweet Syngas 2 22.5 0.033 0.01482 0 1.5E-02 0.0649

Total CO 2.157 9.446

Hydrogen Sulfide

H2S Conc

%v lb/hr/component lb/hr % lb/hr TPY

Valves Raw Syngas 100 0.58 0.0089 0.00519 0 5.2E-03 0.023

Shifted Syngas 50 0.61 0.0089 0.00269 0 2.7E-03 0.012

Mixed Syngas 100 1.10 0.0089 0.00978 0 9.8E-03 0.043

Sweet Syngas 20 2.8E-06 0.0089 5.0E-09 0 5.0E-09 2.2E-08

Flanges Raw Syngas 250 0.58 0.0029 0.00423 0 4.2E-03 0.019

Shifted Syngas 100 0.61 0.0029 0.00176 0 1.8E-03 7.7E-03

Mixed Syngas 250 1.10 0.0029 0.00797 0 8.0E-03 0.035

Sweet Syngas 50 2.8E-06 0.0029 4.1E-09 0 4.1E-09 1.8E-08

Compressor Seals Raw Syngas 0 0.58 0.5027 0 000

Shifted Syngas 0 0.61 0.5027 0 000

Mixed Syngas 0 1.10 0.5027 0 000

Sweet Syngas 0 2.8E-06 0.5027 0 000

Pump Seals Raw Syngas 0 0.58 0.0386 0 000

Shifted Syngas 0 0.61 0.0386 0 000

Mixed Syngas 0 1.10 0.0386 0 000

Sweet Syngas 0 2.8E-06 0.0386 0 000

Relief Valves Raw Syngas 20 0.58 0.2293 0.02675 0 0 0

Shifted Syngas 4 0.61 0.2293 0.00555 0 0 0

Mixed Syngas 8 1.10 0.2293 0.02016 0 0 0

Sweet Syngas 4 2.8E-06 0.2293 2.6E-08 0 0 0

Sample Connections Raw Syngas 2 0.58 0.033 0.00039 0 3.9E-04 1.7E-03

Shifted Syngas 2 0.61 0.033 0.00040 0 4.0E-04 1.7E-03

Mixed Syngas 2 1.10 0.033 0.00073 0 7.3E-04 3.2E-03

Sweet Syngas 2 2.8E-06 0.033 1.9E-09 0 1.9E-09 8.2E-09

Total Hydrogen Sulfide 0.086 0.375

No Control Efficiency claimed for components in sweet syngas service due to low concentration.

Process 

Stream

Fugitive Source Process 

Stream

Fugitive Source

Component

Count

Component

Count

Emission Factors

Uncontrolled 

Emissions Controlled Emissions

Emission Factors

Uncontrolled 

Emissions

Control 

Efficiency Controlled Emissions

Control 

Efficiency
Ammonia Page 3 of 6 TSD App A

NH3 Conc

%v lb/hr/component lb/hr % lb/hr TPY

Valves Raw Syngas 100 0.0012 0.0089 1.0E-05 0 1.0E-05 4.5E-05

Shifted Syngas 50 0.0012 0.0089 5.2E-06 0 5.2E-06 2.3E-05

Mixed Syngas 100 0.0012 0.0089 1.0E-05 0 1.0E-05 4.5E-05

Sweet Syngas 20 0 0.0089 0 000

Flanges Raw Syngas 250 0.0012 0.0029 8.4E-06 0 8.4E-06 3.7E-05

Shifted Syngas 100 0.0012 0.0029 3.4E-06 0 3.4E-06 1.5E-05

Mixed Syngas 250 0.0012 0.0029 8.4E-06 0 8.4E-06 3.7E-05

Sweet Syngas 50 0 0.0029 0 000

Compressor Seals Raw Syngas 0 0.0012 0.5027 0 000

Shifted Syngas 0 0.0012 0.5027 0 000

Mixed Syngas 0 0.0012 0.5027 0 000

Sweet Syngas 0 0 0.5027 0 000

Pump Seals Raw Syngas 0 0.0012 0.0386 0 000

Shifted Syngas 0 0.0012 0.0386 0 000

Mixed Syngas 0 0.0012 0.0386 0 000

Sweet Syngas 0 0 0.0386 0 000

Relief Valves Raw Syngas 20 0.0012 0.2293 5.3E-05 0 5.3E-05 2.3E-04

Shifted Syngas 4 0.0012 0.2293 1.1E-05 0 1.1E-05 4.7E-05

Mixed Syngas 8 0.0012 0.2293 2.1E-05 0 2.1E-05 9.3E-05

Sweet Syngas 4 0 0.2293 0 000

Sample Connections Raw Syngas 2 0.0012 0.033 7.7E-07 0 7.7E-07 3.4E-06

Shifted Syngas 2 0.0012 0.033 7.7E-07 0 7.7E-07 3.4E-06

Mixed Syngas 2 0.0012 0.033 7.7E-07 0 7.7E-07 3.4E-06

Sweet Syngas 2 0 0.033 0 000

Total Ammonia 1.3E-04 5.8E-04

Notes:

1 Component counts are preliminary subject to change during detailed project engineering.

2 Emissions factors and control efficiencies from TCEQ 28VHP LDAR Program.

3 Relief valves discharge to flare.

4 No LDAR program is required for syngas streams, therefore, no control efficiency assumed.

Emission Factors Controlled Emissions

Control 

Efficiency

Uncontrolled 

Component Emissions

Count

Process 

Stream

Fugitive Source
Page 4 of 6 TSD App A

NAME Fugitive Emissions - Wet Sulfuric Acid Units Unit ID: FUG - WSA

Summary of Fugitive Vapor Emissions for Wet Sulfuric Acid Process

H2S

H2S Conc

Per Train Total %v lb/hr/component lb/hr % lb/hr TPY

Valves Acid Gas 10 20 44.00 0.00890 0.0783 0 0.0783 0.3430

Flanges Acid Gas 100 200 44.00 0.00290 0.2552 0 0.2552 1.1178

Compressor Seals Acid Gas 0 0 44.00 0.50270 0 0 0.0000 0.0000

Pump Seals Acid Gas 0 0 44.00 0.03860 0 0 0.0000 0.0000

Relief Valves Acid Gas 2 4 44.00 0.22930 0.4036 0 0.4036 1.7676

Sample Connections Acid Gas 4 8 44.00 0.03300 0.1162 0 0.11616 0.5088

Total H2S 0.8532 3.7372

SO2

SO2 Conc

Per Train Total %v lb/hr/component lb/hr % lb/hr TPY

Valves Acid Gas 0 0 6.20 0.00890 0 97 0.0000 0.0000

Flanges Acid Gas 20 40 6.20 0.00290 0.0072 97 0.0002 0.0009

Compressor Seals Acid Gas 0 0 6.20 0.50270 0 0 0.0000 0.0000

Pump Seals Acid Gas 0 0 6.20 0.03860 0 85 0.0000 0.0000

Relief Valves Acid Gas 0 0 6.20 0.22930 0 100 0.0000 0.0000

Sample Connections Acid Gas 4 8 6.20 0.03300 0.0164 97 0.00049 0.0022

Total SO2 0.0007 0.0031

SO3

SO3 Conc

Per Train Total %v lb/hr/component lb/hr % lb/hr TPY

Valves Acid Gas 0 0 3.30 0.00890 0.0000 0 0.0000 0.0000

Flanges Acid Gas 30 60 3.30 0.00290 0.0057 0 0.0057 0.0251

Compressor Seals Acid Gas 0 0 3.30 0.50270 0 0 0.0000 0.0000

Pump Seals Acid Gas 0 0 3.30 0.03860 0 0 0.0000 0.0000

Relief Valves Acid Gas 0 0 3.30 0.22930 0.0000 0 0.0000 0.0000

Sample Connections Acid Gas 3 6 3.30 0.03300 0.0065 0 0.00653 0.0286

Total SO3 0.0123 0.0538

Total SO3 as H2SO4 0.01504 0.0659

H2SO4 Vapor

Acid Conc

Per Train Total %v lb/hr/component lb/hr % lb/hr TPY

Valves Acid Gas 0 0 3.60 0.00890 0.0000 0 0.0000 0.0000

Flanges Acid Gas 10 20 3.60 0.00290 0.0021 0 0.0021 0.0091

Compressor Seals Acid Gas 0 0 3.60 0.50270 0 0 0.0000 0.0000

Pump Seals Acid Gas 0 0 3.60 0.03860 0 0 0.0000 0.0000

Relief Valves Acid Gas 0 0 3.60 0.22930 0.0000 0 0.0000 0.0000

Sample Connections Acid Gas 1 2 3.60 0.03300 0.0024 0 0.00238 0.0104

Total H2SO4 0.0045 0.0196

Total H2SO4 including SO3 0.020 0.0854

Notes:

1 Component counts are preliminary subject to change during detailed project engineering.

2 Emissions factors and control efficiencies from TCEQ 28VHP LDAR Program.

3 Relief valves discharge to flare.

Fugitive Source Process 

Stream

Component

Count

Emission Factors

Fugitive Source

Fugitive Source

Fugitive Source

Control 

Efficiency

Controlled Emissions

Controlled Emissions

Control 

Efficiency Controlled Emissions

Component

Count

Component

Count Controlled Emissions

Uncontrolled 

Emissions

Uncontrolled 

Emissions

Control 

Efficiency

Uncontrolled 

Emissions

Process 

Stream

Component

Count

FUGITIVES

Uncontrolled 

Emissions

Control 

Efficiency

Process Emission Factors

Stream

Emission Factors

Process Emission Factors

Stream
Page 5 of 6 TSD App A

NAME Fugitive Emissions - Greenhouse Gas Emissions Only (from Gasification/SNG and from WSA) Unit ID: FUG & FUG-WSA

CO2 in WSA (FUG-WSA)

Total Average Uncontrolled Control Controlled Controlled

Emission Source Source Component Conc Emissions Total Emissions Efficiency Total Emissions Total Emissions

Process Stream Count %w Factor lb/hr lb/hr % lb/hr tpy

Valves Acid Gas 20 42.90 0.00890 0.076 0.0764 0.3345

Flanges Acid Gas 200 42.90 0.00290 0.249 0.2488 1.0898

Compressor Seals Acid Gas 0 42.90 0.50270 0.000 0.0000 0.0000

Pump Seals Acid Gas 0 42.90 0.03860 0.000 0.0000 0.0000

Relief Valves Acid Gas 4 42.90 0.22930 0.393 0.3935 1.7234

Sample Connections Acid Gas 8 42.90 0.03300 0.113 0.1133 0.4961

Total 0.832 0.8319 3.644

Carbon Dioxide from FUG

CO2 Emissions Factor Uncontrolled Control Controlled Controlled

Emission Source Source Component Conc lb/hr/component Total Emissions Efficiency Total Emissions Total Emissions

Process Stream Count %v (discounted by %v) lb/hr % lb/hr tpy

Valves Raw Syngas 100 6.2 0.001 0.055 0.0554 0.243

Shifted Syngas 50 23.6 0.002 0.105 0.1049 0.460

Mixed Syngas 100 32.2 0.003 0.287 0.2867 1.256

Sweet Syngas 20 6.3 0.001 0.011 0.0112 0.049

CO2 30 99.0 0.009 0.264 0.2643 1.158

Flanges Raw Syngas 250 6.2 0.000 0.045 0.0451 0.198

Shifted Syngas 100 23.6 0.001 0.068 0.0684 0.299

Mixed Syngas 250 32.2 0.001 0.234 0.2335 1.023

Sweet Syngas 50 6.3 0.000 0.009 0.0092 0.040

CO2 60 99.0 0.003 0.172 0.1723 0.754

Compressor Seals Raw Syngas 0 6.2 0.031 0.000 85 0.0000 0.000

Shifted Syngas 0 23.6 0.119 0.000 85 0.0000 0.000

Mixed Syngas 0 32.2 0.162 0.000 85 0.0000 0.000

Sweet Syngas 0 6.3 0.032 0.000 85 0.0000 0.000

CO2 16 99.0 0.498 7.963 85 1.1944 5.232

Pump Seals Raw Syngas 0 6.2 0.002 0.000 0.0000 0.000

Shifted Syngas 0 23.6 0.009 0.000 0.0000 0.000

Mixed Syngas 0 32.2 0.012 0.000 0.0000 0.000

Sweet Syngas 0 6.3 0.002 0.000 0.0000 0.000

CO2 0 99.0 0.038 0.000 0.0000 0.000

Relief Valves Raw Syngas 20 6.2 0.014 0.286 0.2856 1.251

Shifted Syngas 4 23.6 0.054 0.216 0.2162 0.947

Mixed Syngas 8 32.2 0.074 0.591 0.5909 2.588

Sweet Syngas 4 6.3 0.014 0.058 0.0580 0.254

CO2 3 99.0 0.227 0.681 0.6810 2.983

Sample Connections Raw Syngas 2 6.2 0.002 0.004 0.0041 0.018

Shifted Syngas 2 23.6 0.008 0.016 0.0156 0.068

Mixed Syngas 2 32.2 0.011 0.021 0.0213 0.093

Sweet Syngas 2 6.3 0.002 0.004 0.0042 0.018

CO2 2 99.0 0.033 0.065 0.0653 0.286

Total 11.091 4.3876 19.218

48.577
Methane from FUG Page 6 of 6 TSD App A

CH4 Uncontrolled Control Controlled Controlled

Emission Source Source Component Conc Emissions Factor Total Emissions Efficiency Total Emissions Total Emissions

Process Stream Count %v lb/hr/component lb/hr % lb/hr tpy

Valves Raw Syngas 100 0.025 0.000 0.000 97 0.0000 0.000

Shifted Syngas 50 0.025 0.000 0.000 97 0.0000 0.000

Mixed Syngas 100 0.060 0.000 0.001 97 0.0000 0.000

Sweet Syngas 20 0.063 0.000 0.000 97 0.0000 0.000

Fuel Gas 25 94.2 0.008 0.210 97 0.0063 0.028

SNG 10 94.2 0.008 0.084 97 0.0025 0.011

Flanges Raw Syngas 250 0.025 0.000 0.000 97 0.0000 0.000

Shifted Syngas 100 0.025 0.000 0.000 97 0.0000 0.000

Mixed Syngas 250 0.060 0.000 0.000 97 0.0000 0.000

Sweet Syngas 50 0.063 0.000 0.000 97 0.0000 0.000

Fuel Gas 30 94.2 0.003 0.082 97 0.0025 0.011

SNG 20 94.2 0.003 0.055 97 0.0016 0.007

Compressor Seals Raw Syngas 0 0.025 0.000 0.000 99.7 0.0000 0.000

Shifted Syngas 0 0.025 0.000 0.000 99.7 0.0000 0.000

Mixed Syngas 0 0.060 0.000 0.000 99.7 0.0000 0.000

Sweet Syngas 0 0.063 0.000 0.000 99.7 0.0000 0.000

Fuel Gas 0 95 0.008 0.000 99.7 0.0000 0.000

Fuel Gas 0 94.2 0.474 0.000 99.7 0.0000 0.000

SNG 4 94.2 0.474 1.894 99.7 0.0057 0.025

Pump Seals Raw Syngas 0 0.025 0.000 0.000 85 0.0000 0.000

Shifted Syngas 0 0.025 0.000 0.000 85 0.0000 0.000

Mixed Syngas 0 0.060 0.000 0.000 85 0.0000 0.000

Sweet Syngas 0 0.063 0.000 0.000 85 0.0000 0.000

Fuel Gas 0 94.2 0.036 0.000 85 0.0000 0.000

SNG 0 94.2 0.036 0.000 85 0.0000 0.000

Relief Valves Raw Syngas 20 0.025 0.000 0.001 99.7 0.0000 0.000

Shifted Syngas 4 0.025 0.000 0.000 99.7 0.0000 0.000

Mixed Syngas 8 0.060 0.000 0.001 99.7 0.0000 0.000

Sweet Syngas 4 0.063 0.000 0.001 99.7 0.0000 0.000

Fuel Gas 1 94.2 0.216 0.216 99.5 0.0011 0.005

SNG 2 94.2 0.216 0.432 99.5 0.0022 0.009

Sample Connections Raw Syngas 2 0.025 0.000 0.000 97 0.0000 0.000

Shifted Syngas 2 0.025 0.000 0.000 97 0.0000 0.000

Mixed Syngas 2 0.060 0.000 0.000 97 0.0000 0.000

Sweet Syngas 2 0.063 0.000 0.000 97 0.0000 0.000

Fuel Gas 0 94.2 0.031 0.000 97 0.0000 0.000

SNG 1 94.2 0.031 0.031 97 0.0009 0.004

Total 2.977 0.0228 0.100

TPY CO2e from FUG= 21.32

Notes:

1 Component counts are preliminary subject to change during detailed project engineering.

2 Emissions factors and control efficiencies from TCEQ 28VHP LDAR Program.

3 Relief valves discharge to flare
Pag

Note: Truck and Rail unloading is not simultantious, During Trucking reciepts, the below sources replace 12g, h, I, j and k.

Unit ID Name 

012 Y Transfer tower from Truck/Rail conveyor to 

pile conveyor 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 8,760 24 

012 Z Truck Bay 1 dump to Hopper 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 2,365 12 

012 AA Truck hopper to conveyor 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 2,365 12 012 AB Truck Bay 2 dump to Hopper 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 2,365 12 

012 AC Truck Bay 3 dump to Hopper 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 2,365 12 

Unit ID Name 

012 Y Transfer tower from Truck/Rail conveyor to 

pile conveyor 1,500 ACFM 0.175 GR/ACF DUST EXTRACTION SYSTEM 99.14% 8,760 24 

012 Z Truck Bay 1 dump to Hopper 1,500 ACFM 0.175 GR/ACF DUST EXTRACTION SYSTEM 99.14% 2,365 12 

012 AA Truck hopper to conveyor 1,500 ACFM 0.175 GR/ACF DUST EXTRACTION SYSTEM 99.14% 2,365 12 012 BB Truck Bay 2 dump to Hopper 1,500 ACFM 0.175 GR/ACF DUST EXTRACTION SYSTEM 99.14% 2,365 12 

012 CC Truck Bay 3 dump to Hopper 1,500 ACFM 0.175 GR/ACF DUST EXTRACTION SYSTEM 99.14% 2,365 12 

Unit ID Name 

012 Y Transfer tower from Truck/Rail conveyor to 

pile conveyor 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 8,760 24 

012 Z Truck Bay 1 dump to Hopper 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 2,365 12 

012 AA Truck hopper to conveyor 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 2,365 12 012 BB Truck Bay 2 dump to Hopper 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 2,365 12 

012 CC Truck Bay 3 dump to Hopper 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 2,365 12 

Comments:PM10 AND PM2.5 Inlet grain loading factor (gr/acfm) and control efficiency provided by vendor.

Total PM Inlet grain loading factor (gr/acfm) calculated from NSPS Subpart Y outlet grain loading requirement of 0.01 gr/dscf PM

Operating 

Hours/day

Operating 

Hours/yr

Operating 

Hours/yr

Control 

Efficiency

Operating 

Hours/yr

Process Rate Emission Factor Operating Hours/day

Operating 

Hours/day

Coal/Coke Truck Unloading Operation 

Emission Factor Control Type

Control

Type

PM2.5 EMISSIONS

Control 

Efficiency

Control 

Efficiency

TOTAL PARTICULATE EMISSIONS Process Rate Emission Factor Control Type

Process Rate

PM10 EMISSIONS
Page 1 of 3 TSD App A 

Emission Unit Emission Description

FUG-ROAD-C (Coal Trucks) Fugitive Dust: Paved Road Truck Traffic for Coal/Coke delivery by Truck

Calculation Methodology

Calculation of Potential Emissions:

Average Round-Trip Distance: 0.479 mile/trip "Wet" Days, P: 117 days

Road Surface Silt Loading, sL: 1.0 g/m2 Days in Ave. Period, N: 365 days

Average Truck Weight, W: 25.7 tons Highest Day Wet Coal 249.1 tons/hr 50% plant capacity

Particle Size Multiplier, k: 0.0022 PM10 Carried each Load: 32.0 tons/truck

Particle Size Multiplier, k: 0.00054 PM2.5 Truck Trips: 186.8 trip/day

Particle Size Multiplier, k: 0.011 PM Truck Trips: 100.9 54% of daily trips

Potential PM10 Emissions:

EP Max lb/hr lb/day tpy

FUG-ROAD-C (Coal Trucks) 0.0225 0.54 0.0906

Potential PM2.5 Emisions:

EP Max lb/hr lb/day tpy

FUG-ROAD-C (Coal Trucks) 0.0055 0.13 0.0222

Potential PM Emissions:

EP Max lb/hr lb/day tpy

FUG-ROAD-C (Coal Trucks) 0.1124 2.70 0.4531

CALCULATION SHEET

Control Efficiency for 

Watering: 90%

daily trip 

(yr avg)

AP-42 Chapter 13, Section 2.1 : Miscellaneous Sources, Paved Roads

Max Hourly and Daily Emissions calculated using equation (1)

Annual Emissions calculated using equation (2)

k factor from Table 13.2.1-1

PM = 0.011

PM10 = 0.0022

PM2.5 = 0.00054

Road Surface Silt Loading, sL = 1.0 g/m2 (Conservative value considering planned frequent watering)

EmptyTruck weight = 9.7 tons

Full Truck weight = 41.7 tons

"Wet" days, P = 117 days

Number of days in averaging period, N = 365

    0.91 1.02 E  k sL  W

Eext k   sL W   1 P/4N 0.91 1.02   

17_30464 limited Calcs H 88 5/3/2012
Page 2 of 3 TSD App A

Emission Unit Emission Description

FUG-ROAD-S (Slag) Fugitive Dust: Paved Roads for Slag Truck Hauling

Calculation Methodology

Calculation of Potential Emissions:

T t l R d T i Di t 0 644 il /t i "W t" D P 117 d

CALCULATION SHEET

AP-42 Chapter 13, Section 2.1 : Miscellaneous Sources, Paved Roads

Max Hourly and Daily Emissions calculated using equation (1) emissions factor

Annual Emissions calculated using equation (2) emissions factor

k factor from Table 13.2.1-1

PM = 0.011

PM10 = 0.0022

PM2.5 = 0.00054

EmptyTruck weight = 9.7 tons

Load each trip = 20 tons

"Wet" days, P = 117 days

Number of days in averaging period, N = 365

Trip Distance = 600 ft, each way in process block (normal). Additionally, if slag hauled to coal yard temporary storage, then it must travel 900 

feet offsite to coal yard area, then it travels 1100 feet in coal yard to drop off and 1100 feet in coal yard to pick up. (worse-case total = 

600+600+1100+1100 excluding the portion of travel "offsite"/outside the fenceline.)

Emissions calculated = Emissions factor (lb/vmt) * trip distance (miles) * number of trips * (1-control efficiency)

   0.91 1.02 E  k sL  W

Eext k   sL W   1 P/4N 0.91 1.02   

Total Round-Trip Distance: 0.644 mile/trip "Wet" Days, P: 117 days

Road Surface Silt Loading, sL: 1.0 g/m2 Days in Ave. Period, N: 365 days

Average Truck Weight, W: 19.7 tons Slag Production: 43.08 tons/hr

Particle Size Multiplier, k: 0.0022 PM10 Carried each Load: 20.0 tons/truck

Particle Size Multiplier, k: 0.00054 PM2.5 Truck Trips: 82.7

Particle Size Multiplier, k: 0.011 Total PM

Potential PM10 Emissions:

EP Max lb/hr lb/day tpy Process Road Segment

FUG-ROAD-S (Slag) 0.0102 0.24 0.0411 PM10 0.0036 lb/hr

PM2.5 0.00088 lb/hr

Potential PM2.5 Emisions: Total PM 0.01801 lb/hr

EP Max lb/hr lb/day tpy

FUG-ROAD-S (Slag) 0.0025 0.06 0.0101 Coal Yard Road Segment

PM10 0.0066 lb/hr

Potential Total PM Emisions: PM2.5 0.0016 lb/hr

EP Max lb/hr lb/day tpy Total PM 0.0330 lb/hr

FUG-ROAD-S (Slag) 0.0510 1.22 0.2056

Control Efficiency for 

Watering: 90%

trip/day (includes 31 

trucks/day contingency)

   0.91 1.02 E  k sL  W

Eext k   sL W   1 P/4N 0.91 1.02   
Page 3 of 3 TSD App A 

Emission Unit Emission Description

EU-034A Handling (Drop) emissions for handling/loading Slag at temp. Storage pile.

Calculation Methodology

Assume that slag dumped from trucks coming from process is so wet that there are no emissions.

Then assume slag is picked up by front end loader and loaded into truck for haulting out (1 handling step)

Assume watering used to keep slag wet Control effectiveness of watering reflected in assumed moisture content

CALCULATION SHEET

Also assume when/if slag is initially picked up by front end loader and piled or moved within storage site that it is still 

wet enough to not have emissions

AP-42 Chapter 13, Section 2.4:Aggregate Handling and Storage Piles

Uncontrolled Emissions per handling step calculated using equation (1)

Where:

E = emissions factor in lbs emissions per ton aggregate handled

U = mean wind speed, mph 

M = material moisture content 

k = particle size multplier (dimensionless)

Total PM k = 0.74

PM10 k = 0.35

PM2.5 k = 0.053

 

1.3

1.4

5 0.0032

2

U

E k

M

      

     

 

1.3

1.4

5 0.0032

2

U

E k

M

      

     

Assume watering used to keep slag wet. Control effectiveness of watering reflected in assumed moisture content.

Calculation of Potential Emissions:

Number of Drops(handling steps) 1.000 drops Maximum daily slag 1,034 tons/day max

Mean wind speed 8.0 mph Max hourly slag 43.08 tons/hr

Material Moisture content 15.00 % Annual Slag Production: 720.0 tons/day annual average

Particle Size Multiplier, k: 0.35 PM10 Average hourly slag 30 tons/hr annual average

Particle Size Multiplier, k: 0.053 PM2.5 Hours per yr of activity 8760.0

Particle Size Multiplier, k: 0.74 Total PM

Potential PM10 Emissions:

EP Max lb/hr Max lb/day tpy

EU-034A 0.0053 0.13 0.0161

Potential PM2.5 Emisions:

EP Max lb/hr lb/day tpy

EU-034A 0.0008 0.02 0.0024

Potential Total PM Emisions:

EP Max lb/hr lb/day tpy

EU-034A 0.0112 0.27 0.0341

Control Efficiency for 

Watering

Addressed by moisture 

content assumption

 

1.3

1.4

5 0.0032

2

U

E k

M

      

     

 

1.3

1.4

5 0.0032

2

U

E k

M

      

     
Although Storage Pad is paved, assume it is partially covered in slag, calculate emissions assuming unpaved road equation.Description of Vehicles Load Size

Vehicle Weight 

Empty

Average 

Vehicle 

Weight

Daily Slag 

(annual 

average)

Max Slag 

per day

Miles per 

trip

Maximum 

Daily Ave Annu

tons tons tons tons/day tons/day Mile/trip Trips/day Trips/day 

Front End Loader 20 32.66 26.33 1,440 2,068 0.0142 103.4 72 

Assume each trip of front end loader trip is 75 feet round trip (1/4 width of pad times 2)

Average 

Vehicle weigh 

(tons)

Uncontrolled 

Emissions 

factor (lbs total 

PM/VMT)

Uncontrolled 

Emissions 

factor (lbs 

PM10/VMT)

Uncontrolled 

Emissions 

factor (lbs 

PM2.5/VMT)

Control 

Efficiency

Max daily 

lb/hr Total 

PM

Max daily 

lb/hr PM10

Max daily 

lb/hr PM2

Front End Loader/dozer 26.33 2.287 0.426 0.043 90% 0.014 0.003 0.000 

Total 0.014 0.003 0.000

Max Annual 

Tons/yr 

Total PM

Max Annual 

Tons/yr 

PM10

Max Annu

Tons/yr 

PM2.5

0.007 0.001 0.000 

Note: Slag handled is slag production assuming that slag is either delivered to or picked up from the storage pad each day. (Not being dropped off all day picked up all day on the same day).

EU-034C Emission Calculation for Front-End Loader and Slag truck Activity on the temp. Slag storage pad/pile

Total 0.007 0.001 0.000

UNPAVED ROADS EQUATIONS Industrial Roads - AP42 13.2.4 (equations 1a and 2)

E = size specific emission factor (lbs/VMT)

k = particle size multiplier for particle size range (lb/VMT)s = surface material silt content (%) 

a = constant based on size of particulateb = constant based on size of particulate

W = Vehicle average weight (tons)

P = number of days per year with 0.01 in or more of precipitation

INPUTS TO EQUATION/CALCULATIONS Total PM PM10 PM2.5

k 4.9 1.5 0.15 lb/vmt

s1 1 1 %

a 0.7 0.9 0.9b 0.45 0.45 0.45

P 117 117 117 days/yr

    12

3 * s * Wa b

E



k 

 

  

365

365

P

E ext

E
Page 1 of 1 TSD App A

Indiana Gasification, LLC Spencer County Facility 

Emission Unit:

FUG‐SF6 Emission Estimate for Fugitive Emissions of SF6 from Circuit Breakers

The IG facility will include a switchyard with circuit breakers that include

sulfur hexafluoride (SF6), a greenhouse gas, as a gaseous dielectric.

The circuit breakers will be totally enclosed and pressurized.

Fugitive emissions are estimated as 1% leakage per year.

Emission Calculation

Number of circuit break 6

Amount of SF6 in each 100 lbs

Assumed leak rate: 1%

Emissions (lb/yr): 6 lbs/yr

GWP of SF6: 23,900

CO2e (tons/yr): 71.7 tons/yr
Page 1 

This workbook documents calculations for total particulate emissions from the Indiana Gasification Syngas Plant. Most 

calculations are based on and / or are related to the estimates of PM10 emissions. For most of the sources, the estim

particulate emissions estimates are equal to the PM10 estimated emissions because all particulate is finer than PM10.

Notable exceptions are uncontrolled material handling and roadway emissions sources which have a higher quantity of 

compared to the PM10. For such sources, emissions of various particle sizes are based on standard equations utilizing 

multipliers unique to the source under consideration.

This workbook has a summary of the total PM emissions for the Indiana Gasification plant, with notes on the basis of th

estimates. For sources where total PM is not equal to PM10, other worksheet pages document those emissions calcula

material handling sources and roadway emissions).

93
Page 2 of 3 TSD A

Emissions

Unit

Number Source Name

Total

Particulate

Same as

Estimated

PM10

Ba

Tot

Est

1 Syngas Hydrocarbon Flare 0.44 Yes N

2 Acid Gas Flare 0.01 Yes N

5 Auxiliary Boilers (A‐B) 5.62 Yes N

7 Acid Gas Recovery Unit (A‐B) 2.46 Yes N

8 Gasifier Preheat Burners (A‐E) 0.04 Yes N

9 Emergency Diesel Generators (A‐B) 0.00 Yes N

10 Emergency Firewater Pumps Diesel Engines (A‐C) 0.01 Yes N

11 Process Area Solid Feedstock Handling (coal/pet coke) 6.35 Yes N

12 (A‐X) Incoming Solid Feedstock Handling (coal/petcoke) (A‐X) #REF! No N

13 Rod Mill (A‐D) 0.44 Yes N

15 Wet Sulfuric Acid Plant (WSA) (A‐B) 42.59 Yes N

16A Cooling Tower ‐ ASU 0.90 Yes N

16B Cooling Tower ‐ Main 6.65 Yes N

17 ASU Molecular Sieve Regeneration (A‐B) 0.22 Yes N

23 Slag Sump (A‐E)  ‐ ‐ n/a

24 Methanol De‐Inventory Tank  ‐ ‐ n/a

25 Fresh Methanol Storage Tank  ‐ ‐ n/a

26 Sour Water Stripper Surge Tank  ‐ ‐ n/a

27 Sulfuric Acid Storage Tank (A‐F) 0.00 Yes N

29 Diesel Fuel Storage Tank  ‐ ‐ n/a

30 Gasoline Fuel Storage Tank  ‐ ‐ n/a

31 Triethylene Glycol Storage Tank  ‐ ‐ n/a

32 ZLD Spray Dryer 0.51 Yes N

FUG Fugitive Emissions ‐ Gasification, Shift Conversion, AGR, Methanation  ‐ ‐ n/a

FUG‐WSA Fugitive Emissions ‐ WSA  ‐ ‐ n/a

FUG‐Road Fugitive Emissions ‐ Plant Haul Roads 2.63 No N

Total #REF!

Summary of Indiana Gasification Plant Total Particlate Emissions

94
95
Basis of Total PM Emissions Estiimates (Based on or differences versus PM10 estimate) Page 3 of 3 TSD A

Note 1

Note 2

Note 3

Note 4

Note 5

Note 6

Note 7 This represents the PM10 figure from the original application (see Appendix B, page H1) multiplied by a PM‐size mu

of 5. (See AP‐42, Chapter 13.2, Table 13.2.1‐1).

Combustion Sources: PM10 Emissions for combustion sources have been calculated using particulate factors for filt

condensible particulate from AP42. These factors are for total particulate, therefore their use for PM10 is conserva

total PM = PM10.

Engineered Equipment: These sources have PM10 based on vendor or design engineering estimate of total particula

assuming all PM is PM10. Therefore, estimate of total particulate equals PM10 estimate.

Baghouse controlled sources: PM10 is estimated using design total particulate grain loading on outlet of baghouse. 

conservatively assumed to be PM10, therefore total PM = PM10.

Particulate sources using various AP42 or other equations (aggregate handling, roadway, wind erosion): These sou

emissions using complex equations based on silt level, vehicle weight, wind speed and other parameters. However

"particle size multiplier" factor unique to each PM particle size range. Other than this factor, the remainder of the e

paramaters are the same for aggregate handling and wind erosion. Therefore, total PM has been calculated by mul

PM10 by the ratio of the total PM factor: PM10 factor. For dozer‐related dust, the equation also includes additiona

differ for different particle sizes. Therefore total PM has been calculated using the full equation and the applicable f

exponents. Documentation of these total PM estimates are provided on separate spreadsheets.

Sulfuric Acid Mist Sources: The WSA particulate consists predominantly of condensible sulfuric acid mist. This cond

particulate is all assumed to be PM2.5. Therefore, total PM=PM10=PM2.5. Additionally, there is a small amount of 

combustion, however, as explained above in Note 1, for combustion PM, total PM is also equal to PM10.

Cooling tower particulate: PM from cooling towers is based on total dissolved solids in the cooling water. This calc

particulate emissions. IG has conservatively assumed that all the particulate is PM10. Therefore total PM = PM10.

96
Basis: 100%w Coal with Gasifier Methanol Startups 8,339,799.29

4 Operating GE Quench Gasifiers (design capacity x 1.25) Page 1 of 3 TSD App A

10,401 STPD dry coal (design capacity x 1.25)

12,968 BTU/lb dry HHV/lb coal design 

11,240 MMBTU/hr HHV coal (design capacity x 1.25)

3.66 %wt dry sulfur in coal during normal operation

600 MMSCFD H2+CO2 Total Raw Syngas from Gasifiers (design capacity x 1.25)

154 MMSCFD SNG Gross Production (design capacity x 1.25)

302.2 MMSCFD CO2 Captured 

0 MMSCFD CO2 to EOR Pipeline

1,164 STPD 100%w H2SO4

Installed Operating Preliminary

Number of 

Stacks

Number of 

Stacks

Stack Height 

feet Rating Units lb/MMBTU lb/hr Tons/yr lb/MMBTU lb/hr Tons/yr

001 Gasifier Startup Flare Emissions (methanol fuel) - 90 per year at 90 min 1 1 300 862 MMBtu/h HHV 8760

001 Syngas Flare - Nat Gas Pilots 1 1 300 0.27 MMBtu/h HHV 8760 1.65E-06 4.376E-07 0.0000019 2.90E-06 7.69E-07 0.0000034

002 Acid Gas Flare - Nat Gas Pilots 1 1 300 0.27 MMBtu/h HHV 8760 1.65E-06 4.376E-07 0.0000019 2.90E-06 7.69E-07 0.0000034

005 Auxiliary Boiler, Full Load Operation - black plant su (nat gas fuel) 1 1 200 816 MMBtu/h HHV 8760 2.55E-07 2.081E-04 0.0009072 4.90E-07 4.00E-04 0.0017447

005 Auxiliary Boiler, Full Load Operation (SNG or Nat Gas) 1 1 200 816 MMBtu/h HHV 8760 1.65E-06 1.347E-03 0.0058725 2.90E-06 2.37E-03 0.0103217

005 Auxiliary Boiler, Half Load Operation (SNG or Nat Gas) 1 1 200 408 MMBtu/h HHV 0 1.65E-06 6.735E-04 0.0029363 2.90E-06 1.18E-03 0.0051608

008 Gasifier Preheat Burners - black plant su (nat gas fuel) 5 5 200 35 MMBtu/h HHV 8760 2.55E-07 8.922E-06 0.0000389 4.90E-07 1.72E-05 0.0000748

008 Gasifier Preheat Burners (one operating 8 months per year, SNG or NG fuel 5 1 200 18 MMBtu/h HHV 8760 1.65E-06 2.970E-05 0.0001295 2.90E-06 5.22E-05 0.0002276

009 Emergency Diesel Generators (2 units each tested 1 hour weekly) 2 1 20 1,341 hp 500

010 Diesel Fire Water Pump Engine (3 units each tested 1 hour weekly) 3 1 20 575 hp 500

011 Coal Conveying and Feed Bins Dust Control System Vents 2 1 200 8760 1.244E-06 0.0000054 2.42E-04 0.0010546

012 Coal Unloading and Storage (Barge, Rail, Truck) 0.0000000 0.0000000

013 Rod Mill Vent Stacks 4 4 125 8760 0.0000000 0.0000000

032 ZLD Spray Drier Stack 1 1 100 5.6 MMBtu/h HHV 8760 1.65E-06 9.294E-06 0.0000405 2.90E-06 1.63E-05 0.0000712

033 ZLD Inert Gas Vent 1 1 100 8760 1.404E-07 0.0000006

015 WSA Preheat 2 1 200 35.0 MMBtu/h HHV 8760 1.65E-06 5.775E-05 0.0002518 2.90E-06 1.02E-04 0.0004425

015 WSA Stack - black plant su 2 1 213 291

stpd 100% 

H2SO4 8760 8.348E-11 0.0000000

015 WSA Stack - One Unit Operation 2 1 213 582

stpd 100% 

H2SO4 8760 1.670E-10 0.0000000

015 WSA Stack - Two Unit Operation 2 2 213 1,164

stpd 100% 

H2SO4 8760 3.339E-10 0.0000000

16a Cooling Tower -ASU 6 6 65 8760

16b Cooling Tower -Main 24 24 65 8760

017 ASU Molecular Sieve Regeneration Vents 2 Int 60 8760

024 Methanol Storage Scrubber Vent Stack 1 Int 30 8760

Fugitive Emissions - Gasification, Shift Conversion, Rectisol, Methanation NA NA 8760

Fugitive Emissions - WSA NA NA 8760

Plant Totals without CO2 Venting 0.002336 0.01 0.004382 0.02

RTO Case

007 Regen Thermal Oxidizers -black plant su, one gasifier op (nat gas fuel) 1 1 200 19.4

MMBtu/h HHV 

NG 8760 1.65E-06 3.202E-05 0.0001396 2.90E-06 5.63E-05 0.0002454

007 Regen Thermal Oxidizers (Note 1, Two Units Hot Standby 80% of the year, SNG 1 1 200 10.3

MMBtu/h HHV 

SNG 0 1.65E-06 1.705E-05 0.0000743 2.90E-06 3.00E-05 0.0001307

007 Regen Thermal Oxidizers (Note 1, One Unit Op, SNG fuel) 1 1 200 38.8

MMBtu/h HHV 

SNG 8760 1.65E-06 6.404E-05 0.0002792 2.90E-06 1.13E-04 0.0004907

007 Regen Thermal Oxidizers (Note 1, Two Units with common, SNG fuel) 1 1 200 77.6

MMBtu/h HHV 

SNG 8760 1.65E-06 1.281E-04 0.0005584 2.90E-06 2.25E-04 0.0009815

007 RTO Totals 0.000241 0.00 0.000199 0.001848

Plant Totals with 100% CO2 to RTO 0.002578 0.01 0.004581 0.02

Notes:

1 Mercury and lead emissions are based on firing SNG in pilots, aux boiler and WSA preheater except for black plant su. RTO Hg and Pb emissions are based on SNG including black plant su.

Lead

Rated in terms of Plant 

Capacity

EPN # Emission Units

Estimated 

Annual 

Operating 

Hours

Operating Rate

Rated in terms of Plant 

Capacity

Mercury 

Rated in terms of Plant 

Capacity

Rated in terms of Plant 

Capacity

Rated in terms of Plant 

Capacity

Rated in terms of Plant 

Capacity

Rated in terms of Plant 

Capacity
Indiana Gasification, LLC Page 2 of 3 TSD App A

Plant Mercury Balance for 125% of design plant operating rate

Mercury in Natural Gas:

2.60E-04 lb mercury/MMSCF natural gas from EPA AP-42 Natural Gas Combustion

1.02E+03 BTU/SCF natural gas HHV from EPA AP-42 Natural Gas Combustion 

2.55E-07 lb mercury/MMBTU HHV natural gas calculated

Mercury in Solids Feed to Gasifiers:

0.11 ppm dry mercury is average reported by Indiana Geological Survey 2004 Characterization of Indiana's Coal Resource Table 24A

0.86 ppm dry mercury is maximum reported by Indiana Geological Survey 2004 Characterization of Indiana's Coal Resource Table 24A

Total Mercury max Mercury max

stph dry ppm, dry lb/hr

Coal: 433.38 0.86 0.745

Coke: 0.00 0.05

Total coal + coke 433.38 0.745

Output streams: max mercury

Slag 0% mercury in gasifier feed goes out in slag (maximum Hg to wastewater)

0.0000 lb/hr Hg in slag

Wastewater 2% mercury in gasifier feed goes out in gasification process wastewater

0.0149 lb/hr Hg in gasification process wastewater

0.5 ppbv Hg in ZLD vent gas from sulfided carbon mercury removal guaranteed

1.4 lb-mole/hour ZLD vent gas

7E-10 lb-moles/hour mercury in ZLD vent gas

200.59 lb/lb-mole mercury molecular weight

1.40E-07 lb/hr mercury in ZLD vent gas

1.49E-02 lb/hr mercury removed by sulfided carbon

Syngas to Sulfided Carbon 98% mercury in gasifier feed is in syngas to mercury removal

0.7305 lb/hr Hg in syngas to mercury removal

Syngas from Sulfided Carbon 0.5 ppbv Hg in syngas from mercury removal guaranteed

103,526 lb-moles/hr total syngas from mercury removal

5.18E-05 lb-moles/hr Hg in syngas from mercury removal

0.010 lb/hr mercury in syngas to Rectisol

98.6% mercury removal on sulfided carbon

Rectisol Treated Syngas 66,958 lb-moles/hr treated syngas from Rectisol

-27 F Treated Rectisol syngas from absorber

99.99998% Hg in syngas to Rectisol assumed to be in syngas from Rectisol (worst case no accumulation in Rectisol)

0.0104 lb/hr mercury in syngas from Rectisol

0.77 ppbv Hg in Rectisol treated syngas

SNG 0.0104 lb/hr mercury in SNG

2.94 ppbv Hg in SNG

6,293 MMBTU/hr HHV SNG rate

1.65E-06 lb Hg/MMBTU HHV SNG

Rectisol CO2 33,184 lb-moles/hr CO2 from Rectisol

-42 F CO2 Temperature from MP Flash

1.45E-08 lb Hg solubility/lb Methanol

3.28E-06 Vapor pressure of Hg, mbar

2.89E-07 ppbv Hg in CO2 from Rectisol

1.92E-09 lb/hr Hg in CO2 

Rectisol Acid Gas 3,264 lb-moles/hr acid gas from Rectisol

-31 F acid gas temperature at the acid gas separator

2.71E-08 lb Hg solubility/lb Methanol

4.98E-06 Vapor pressure of Hg, mbar at -31F

5.10E-07 ppbv Hg in acid gas from Rectisol

3.34E-10 lb/hr Hg in acid gas

Coal Particulate Emissions 1.45 lb/hr coal dust from Coal Conveying and Feed Bins Dust Control System Vents

1.24E-06 lb/hr mercury in coal dust from coal converying and feed bins dust control system vents

1.09E-02 lb/yr mercury in coal dust from coal conveying and feed bins dust control system vents

10.39 tons per year coal dust from coal unloading and storage

1.79E-02 lb/yr mercury in coal dust from coal unloading and storage

0.44 tons per year coal dust from rod mills

7.57E-04 lb/yr mercury in coal dust from rod mills
Indiana Gasification, LLC Page 3 of 3 TSD App 

Plant Lead Balance for 125% of design plant operating rate

Natural Gas Combustion

5.00E-04 lb lead/MMSCF natural gas from EPA AP-42 Natural Gas Combustion

1.02E+03 BTU/SCF natural gas HHV from EPA AP-42 Natural Gas Combustion 

4.90E-07 lb lead /MMBTU HHV natural gas calculated

SNG Combustion

Lead in Solids Feed to Gasifiers:

21.36 ppm dry lead is average reported by Indiana Geological Survey 2004 Characterization of Indiana's Coal Re

167.17 ppm dry lead is maximum reported by Indiana Geological Survey 2004 Characterization of Indiana's Coal R

Total Lead max Lead max

stph dry ppm, dry lb/hr

Coal: 433.38 167.17 144.89

Coke: 0.00 0.5

Total coal + coke 433.38 144.89

Output streams: max lead

Slag 33% lead in gasifier feed goes out in slag per LGTI Gasification Plant metal mass balances (2002 IG

47.82 lb/hr lead in slag 

SNG 2.90E-06 lb/MMBTU HHV SNG based on LGTI Gasification Plant metal mass balances (2002 IGCC Env

6,293 MMBTU/hr HHV SNG rate

0.0182 lb/hr lead in SNG

Accumulation 97.06 lb/hr lead accumulated on shift catalyst, sulfided carbon beds, sulfur guard beds, methanation c

Coal Particulate Emissions 1.45 lb/hr coal dust from Coal Conveying, Storage and Feed Bins Dust Control System Vents

2.42E-04 lb/hr lead in coal dust from coal converying, storage and feed bins dust control system vents

2.12 lb/yr lead in coal dust from coal conveying and feed bins dust control system vents

10.39 tons per year coal dust from coal unloading and storage

3.47 lb/yr lead in coal dust from coal unloading and storage

0.44 tons per year coal dust from rod mills

0.15 lb/yr lead in coal dust from rod mills

Solid particulates Emission rate:

Emission Point Source cfm dscfm

Emission 

Rate, lb/hr

11a 30,000 33,760 1.4469

11b (spare) 30,000 33,760 

Notes: 

Note 1: All sources (Coal & Coke Dust Collectors) will be fabric filter units with exhaust fans and will be specified to have a dust

emissions limit, as measured in gr/dscf, equal to: 0.005 grains per drscf
A

esource Table 46A

Resource Table 46A

GCC Environmental Assessment by SAIC & NETL)

vironmental Assessment by SAIC & NETL)

catalyst, and liquid filters
Page 1 of 40 TSD App A

Data

Calculation Basis

Tank Characteristics

Bulk Liquid Characteristics

Temperature Parameters

Vapor Pressures

Speciated Emissions

Unit ID Tank ID Tank Capacity Throughput Pva

gal gal / year psia

023 A Slag Sump 25,284 37,492,800 2.69

023 B Slag Sump 25,284 37,492,800 2.69

023 C Slag Sump 25,284 37,492,800 2.69

023 D Slag Sump 25,284 37,492,800 2.69

023 E Slag Sump 25,284 37,492,800 2.69

024 Methanol De-Inventory Tank 710,896 1,386,000 1.98

025 Fresh Methanol Storage Tank 342,005 2,000,000 1.98

026 Sour Water Stripper Surge 182,741 - 2.27

027 A Sulfuric Acid Storage Tank 881,276 13,665,600 1.3E-05

027 B Sulfuric Acid Storage Tank 881,276 13,665,600 1.3E-05

027 C Sulfuric Acid Storage Tank 881,276 13,665,600 1.3E-05

027 D Sulfuric Acid Storage Tank 881,276 13,665,600 1.3E-05

027 E Sulfuric Acid Storage Tank 881,276 13,665,600 1.3E-05

027 F Sulfuric Acid Storage Tank 881,276 13,665,600 1.3E-05

028 A Aqueous Ammonia 32,243 440,000 5.38

028 B Aqueous Ammonia 32,243 440,000 5.38

029 Diesel 9,953 10,000 6.05

030 Gasoline 1,175 8,000 6.20

NOTE: The Sour Water Stripper Surge Tank is a flow through (constant level) tank

Tank Calculation Methodology

All tank information in the Indiana Gasification data workbook was provided by B&V.

Tank emissions are calculated per AP-42, Chapter 7 (September 1997 version) and URS tank calculation methodology.

Tank color, type, height, diameter were provided by B&V. Liquid height (HI) was conservatively assumed to be 1/2 the tank shell

height. This increases the vapor space and thus the tank emissions are conservatively increased.

Riedel and Antoine constants were used to develop vapor pressure estimates for each material. Aqueous Ammonia v.p. from Perry's

6th Ed.

Annual Throughput was provided by B&V.

The Maximum pump rate was utilized to calculate the annual throughput for the Maximum hourly emissions case.

The liquid bulk temperatures were provided by B&V. If the Liquid bulk temperature (Tb) was outside of the ambient temperature range,

then the daily average liquid surface temperature was adjusted to be equivalent to the liquid bulk temperature (Tla =T
TANK TYPE: FIXED ROOF Indiana Gasification 023 A

Slag Sump

Page 2 of 40 TSD APP A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM HOURLY 

CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Slag Slag

SHELL COLOR White White

ROOF TYPE Flat Flat

CSA: 260 260 ft

Hs: 13 13 ft

Vlx: 3,380 3,380 cf

Hl: 6.5 6.5 ft

Hro: 0.00 0.00 ft

Hvo: 6.50 6.50 ft

Vv: 1,690 1,690 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 37,492,800 221,488,628 gal/yr

Q: 892,686 5,273,539 bbl/yr

N: 1482.70 8759.1 turn/year

Mv: 18.05 18.0 lb/lbmol

Tb: 647.7 671.7 R

Tla: 596.8 671.7 R

Tlx: 601.9 676.8 R

Tln: 591.7 666.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 2.6937 14.7002 psia

Pvx: 3.0707 16.2478 psia

Pvn: 2.3570 13.2768 psia

Pv: 0.71 3.0 psia

Pbp: 0.22 0.22 psia

Pbv: (0.04) (0.04) psia

Pb: 0.26 0.26 psia

: 0.17 0.17

Kn: 0.19 0.17

Kp: 1.0 1.0

Wv: 0.0076 0.0368 lb/cf

Ke: 0.0720 PRESSURE VESSEL

Ks: 0.52 0.16

Ls: 174.8158 0.00 lb/yr

Lw: 8113.7685 237741.01 lb/yr

8760 8760 hr/yr

8288.58 237,741.01 lb/yr

UNCONTROLLED TOTAL EMISSIONS (H2S and Water) 0.946 27.14 lb/hr

4.144 118.87 TPY

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

SPECIATED EMISSIONS:

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Hydrogen Sulfide (TAP) 37.584 0.048

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Hydrogen Sulfide (TAP) 0.004 0.048 0.02

ROOF OUTAGE HEIGHT

BULK LIQUID CHARACTERISTICS

AMBIENT CONDITIONS

TANK CHARACTERISTICS

INSIDE DIAMETER

Unit ID:

DESCRIPTION:

VAPOR SPACE OUTAGE HEIGHT

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

LIQUID HEIGHT

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

VAPOR SPACE VOLUME

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

AVERAGE ATMOSPHERIC PRESSURE

DAILY MAX AMBIENT TEMPERATURE

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

DAILY SOLAR INSULATION FACTOR

TURNOVERS PER YEAR

VAPOR MOLECULAR WEIGHT

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

MAX DAILY AVG LIQ. SURFACE TEMP.

DAILY VAPOR TEMPERATURE RANGE

VAPOR PRESSURE PARAMETERS

VAPOR PRESSURE AT Tln

DAILY VAPOR PRESSURE RANGE

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

FACTORS

CALCULATED FACTORS

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

STANDING LOSS
TANK TYPE: FIXED ROOF Indiana Gasification 023 B

Slag Sump

Page 3 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM HOURLY 

CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Slag Slag

SHELL COLOR White White

ROOF TYPE Flat Flat

CSA: 260 260 ft

Hs: 13 13 ft

Vlx: 3,380 3,380 cf

Hl: 6.5 6.5 ft

Hro: 0.00 0.00 ft

Hvo: 6.50 6.50 ft

Vv: 1,690 1,690 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 37,492,800 221,488,628 gal/yr

Q: 892,686 5,273,539 bbl/yr

N: 1482.70 8759.1 turn/year

Mv: 18.05 18.0 lb/lbmol

Tb: 647.7 671.7 R

Tla: 596.8 671.7 R

Tlx: 601.9 676.8 R

Tln: 591.7 666.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 2.6937 14.7002 psia

Pvx: 3.0707 16.2478 psia

Pvn: 2.3570 13.2768 psia

Pv: 0.71 3.0 psia

Pbp: 0.22 0.22 psia

Pbv: (0.04) (0.04) psia

Pb: 0.26 0.26 psia

: 0.17 0.17

Kn: 0.19 0.17

Kp: 1.0 1.0

Wv: 0.0076 0.0368 lb/cf

Ke: 0.0720 PRESSURE VESSEL

Ks: 0.52 0.16

Ls: 174.8158 0.00 lb/yr

Lw: 8113.7685 237741.01 lb/yr

8760 8760 hr/yr

8288.58 237,741.01 lb/yr

UNCONTROLLED TOTAL EMISSIONS (H2S and Water) 0.946 27.14 lb/hr

4.144 118.87 TPY

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

SPECIATED EMISSIONS:

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Hydrogen Sulfide (TAP) 37.584 0.048

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Hydrogen Sulfide (TAP) 0.004 0.048 0.02

ROOF OUTAGE HEIGHT

BULK LIQUID CHARACTERISTICS

AMBIENT CONDITIONS

TANK CHARACTERISTICS

INSIDE DIAMETER

Unit ID:

DESCRIPTION:

VAPOR SPACE OUTAGE HEIGHT

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

LIQUID HEIGHT

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

VAPOR SPACE VOLUME

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

AVERAGE ATMOSPHERIC PRESSURE

DAILY MAX AMBIENT TEMPERATURE

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

DAILY SOLAR INSULATION FACTOR

TURNOVERS PER YEAR

VAPOR MOLECULAR WEIGHT

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

MAX DAILY AVG LIQ. SURFACE TEMP.

DAILY VAPOR TEMPERATURE RANGE

VAPOR PRESSURE PARAMETERS

VAPOR PRESSURE AT Tln

DAILY VAPOR PRESSURE RANGE

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

FACTORS

CALCULATED FACTORS

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

STANDING LOSS
TANK TYPE: FIXED ROOF Indiana Gasification 023 C

Slag Sump

Page 4 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM HOURLY 

CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Slag Slag

SHELL COLOR White White

ROOF TYPE Flat Flat

CSA: 260 260 ft

Hs: 13 13 ft

Vlx: 3,380 3,380 cf

Hl: 6.5 6.5 ft

Hro: 0.00 0.00 ft

Hvo: 6.50 6.50 ft

Vv: 1,690 1,690 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 37,492,800 221,488,628 gal/yr

Q: 892,686 5,273,539 bbl/yr

N: 1482.70 8759.1 turn/year

Mv: 18.05 18.0 lb/lbmol

Tb: 647.7 671.7 R

Tla: 596.8 671.7 R

Tlx: 601.9 676.8 R

Tln: 591.7 666.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 2.6937 14.7002 psia

Pvx: 3.0707 16.2478 psia

Pvn: 2.3570 13.2768 psia

Pv: 0.71 3.0 psia

Pbp: 0.22 0.22 psia

Pbv: (0.04) (0.04) psia

Pb: 0.26 0.26 psia

: 0.17 0.17

Kn: 0.19 0.17

Kp: 1.0 1.0

Wv: 0.0076 0.0368 lb/cf

Ke: 0.0720 PRESSURE VESSEL

Ks: 0.52 0.16

Ls: 174.8158 0.00 lb/yr

Lw: 8113.7685 237741.01 lb/yr

8760 8760 hr/yr

8288.58 237,741.01 lb/yr

UNCONTROLLED TOTAL EMISSIONS (H2S and Water) 0.946 27.14 lb/hr

4.144 118.87 TPY

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

SPECIATED EMISSIONS:

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Hydrogen Sulfide (TAP) 37.584 0.048

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Hydrogen Sulfide (TAP) 0.004 0.048 0.02

ROOF OUTAGE HEIGHT

BULK LIQUID CHARACTERISTICS

AMBIENT CONDITIONS

TANK CHARACTERISTICS

INSIDE DIAMETER

Unit ID:

DESCRIPTION:

VAPOR SPACE OUTAGE HEIGHT

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

LIQUID HEIGHT

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

VAPOR SPACE VOLUME

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

AVERAGE ATMOSPHERIC PRESSURE

DAILY MAX AMBIENT TEMPERATURE

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

DAILY SOLAR INSULATION FACTOR

TURNOVERS PER YEAR

VAPOR MOLECULAR WEIGHT

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

MAX DAILY AVG LIQ. SURFACE TEMP.

DAILY VAPOR TEMPERATURE RANGE

VAPOR PRESSURE PARAMETERS

VAPOR PRESSURE AT Tln

DAILY VAPOR PRESSURE RANGE

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

FACTORS

CALCULATED FACTORS

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

STANDING LOSS
TANK TYPE: FIXED ROOF Indiana Gasification 023 D

Slag Sump

Page 5 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM HOURLY 

CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Slag Slag

SHELL COLOR White White

ROOF TYPE Flat Flat

CSA: 260 260 ft

Hs: 13 13 ft

Vlx: 3,380 3,380 cf

Hl: 6.5 6.5 ft

Hro: 0.00 0.00 ft

Hvo: 6.50 6.50 ft

Vv: 1,690 1,690 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 37,492,800 221,488,628 gal/yr

Q: 892,686 5,273,539 bbl/yr

N: 1482.70 8759.1 turn/year

Mv: 18.05 18.0 lb/lbmol

Tb: 647.7 671.7 R

Tla: 596.8 671.7 R

Tlx: 601.9 676.8 R

Tln: 591.7 666.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 2.6937 14.7002 psia

Pvx: 3.0707 16.2478 psia

Pvn: 2.3570 13.2768 psia

Pv: 0.71 3.0 psia

Pbp: 0.22 0.22 psia

Pbv: (0.04) (0.04) psia

Pb: 0.26 0.26 psia

: 0.17 0.17

Kn: 0.19 0.17

Kp: 1.0 1.0

Wv: 0.0076 0.0368 lb/cf

Ke: 0.0720 PRESSURE VESSEL

Ks: 0.52 0.16

Ls: 174.8158 0.00 lb/yr

Lw: 8113.7685 237741.01 lb/yr

8760 8760 hr/yr

8288.58 237,741.01 lb/yr

UNCONTROLLED TOTAL EMISSIONS (H2S and Water) 0.946 27.14 lb/hr

4.144 118.87 TPY

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

SPECIATED EMISSIONS:

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Hydrogen Sulfide (TAP) 37.584 0.048

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Hydrogen Sulfide (TAP) 0.004 0.048 0.02

ROOF OUTAGE HEIGHT

BULK LIQUID CHARACTERISTICS

AMBIENT CONDITIONS

TANK CHARACTERISTICS

INSIDE DIAMETER

Unit ID:

DESCRIPTION:

VAPOR SPACE OUTAGE HEIGHT

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

LIQUID HEIGHT

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

VAPOR SPACE VOLUME

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

AVERAGE ATMOSPHERIC PRESSURE

DAILY MAX AMBIENT TEMPERATURE

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

DAILY SOLAR INSULATION FACTOR

TURNOVERS PER YEAR

VAPOR MOLECULAR WEIGHT

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

MAX DAILY AVG LIQ. SURFACE TEMP.

DAILY VAPOR TEMPERATURE RANGE

VAPOR PRESSURE PARAMETERS

VAPOR PRESSURE AT Tln

DAILY VAPOR PRESSURE RANGE

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

FACTORS

CALCULATED FACTORS

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

STANDING LOSS
TANK TYPE: FIXED ROOF Indiana Gasification 023 E

Slag Sump

Page 6 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM HOURLY 

CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Slag Slag

SHELL COLOR White White

ROOF TYPE Flat Flat

CSA: 260 260 ft

Hs: 13 13 ft

Vlx: 3,380 3,380 cf

Hl: 6.5 6.5 ft

Hro: 0.00 0.00 ft

Hvo: 6.50 6.50 ft

Vv: 1,690 1,690 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 37,492,800 221,488,628 gal/yr

Q: 892,686 5,273,539 bbl/yr

N: 1482.70 8759.1 turn/year

Mv: 18.05 18.0 lb/lbmol

Tb: 647.7 671.7 R

Tla: 596.8 671.7 R

Tlx: 601.9 676.8 R

Tln: 591.7 666.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 2.6937 14.7002 psia

Pvx: 3.0707 16.2478 psia

Pvn: 2.3570 13.2768 psia

Pv: 0.71 3.0 psia

Pbp: 0.22 0.22 psia

Pbv: (0.04) (0.04) psia

Pb: 0.26 0.26 psia

: 0.17 0.17

Kn: 0.19 0.17

Kp: 1.0 1.0

Wv: 0.0076 0.0368 lb/cf

Ke: 0.0720 PRESSURE VESSEL

Ks: 0.52 0.16

Ls: 174.8158 0.00 lb/yr

Lw: 8113.7685 237741.01 lb/yr

8760 8760 hr/yr

8288.58 237,741.01 lb/yr

UNCONTROLLED TOTAL EMISSIONS (H2S and Water) 0.946 27.14 lb/hr

4.144 118.87 TPY

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

SPECIATED EMISSIONS:

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Hydrogen Sulfide (TAP) 37.584 0.048

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Hydrogen Sulfide (TAP) 0.004 0.048 0.02

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

STANDING LOSS

FACTORS

CALCULATED FACTORS

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

VAPOR PRESSURE AT Tln

DAILY VAPOR PRESSURE RANGE

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

DAILY VAPOR TEMPERATURE RANGE

VAPOR PRESSURE PARAMETERS

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

MAX DAILY AVG LIQ. SURFACE TEMP.

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

TURNOVERS PER YEAR

VAPOR MOLECULAR WEIGHT

DAILY SOLAR INSULATION FACTOR

BULK LIQUID CHARACTERISTICS

AMBIENT CONDITIONS

TANK CHARACTERISTICS

AVERAGE ATMOSPHERIC PRESSURE

DAILY MAX AMBIENT TEMPERATURE

LIQUID HEIGHT

ROOF OUTAGE HEIGHT

VAPOR SPACE OUTAGE HEIGHT

VAPOR SPACE VOLUME

Unit ID:

DESCRIPTION:

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

INSIDE DIAMETER
023

At Tla (596.8 °R)

Page 7 of 40 TSD App A

AB C D E F G H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Hydrogen Sulfide 2.0E-05 34.0759 5.9E-07 1.1E-05 612.0212 0.0065 0.0024 0.0819 0.0045

Water 1.0000 18.0150 0.0555 1.0000 2.6873 2.6872 0.9976 17.9717 0.9955

Total 1.0000 18.02 0.055509 1.0000 2.6937 1.0000 18.0536 1.0000

AB C D E F G H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Hydrogen Sulfide 2.0E-05 34.0759 5.9E-07 1.1E-05 647.4126 0.0068 0.0022 0.0760 0.0042

Water 1.0000 18.0150 0.0555 1.0000 3.0638 3.0638 0.9978 17.9748 0.9958

Total 1.0000 18.02 0.055509 1.0000 3.0707 1.0000 18.0508 1.0000

AB C D E F G H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Hydrogen Sulfide 2.0E-05 34.0759 5.9E-07 1.1E-05 578.0600 0.0061 0.0026 0.0884 0.0049

Water 1.0000 18.0150 0.0555 1.0000 2.3509 2.3509 0.9974 17.9683 0.9951

Total 1.0000 18.02 0.055509 1.0000 2.3570 1.0000 18.0566 1.0000

Calculations:

A = Liquid weight fraction H = G x B (vapor molecular weight fraction)

B = Liquid molecular weight I = H / H (vapor weight fraction)

C = A / B (liquid Lb-moles)

D = C / C (liquid mole fraction)

E = Pure component vapor pressure

F = D x E (partial pressure)

G = F / F (vapor mole fraction)

At Tln (591.7 °R)

Raoult's Law Vapor Weight Fraction Determination

At Tlx (601.9 °R)

023

Raoult's Law Vapor Weight Fraction Determination

023

Raoult's Law Vapor Weight Fraction Determination
At Max Tla (671.7 °R)

Page 8 of 40 TSD App A

A B C D E FG H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Hydrogen Sulfide 2.0E-05 34.0759 5.9E-07 1.1E-05 1297.0643 0.0137 0.0009 0.0318 0.0018

Water 1.0000 18.0150 0.0555 1.0000 14.6867 14.6865 0.9991 17.9982 0.9982

Total 1.0000 18.02 0.055509 1.0000 14.7002 1.0000 18.0300 1.0000

At Max Tlx (676.8 °R)

A B C D E FG H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Hydrogen Sulfide 2.0E-05 34.0759 5.9E-07 1.1E-05 1358.4245 0.0144 0.0009 0.0301 0.0017

Water 1.0000 18.0150 0.0555 1.0000 16.2336 16.2334 0.9991 17.9991 0.9983

Total 1.0000 18.02 0.055509 1.0000 16.2478 1.0000 18.0292 1.0000

At Max Tln (666.6 °R)

A B C D E FG H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Hydrogen Sulfide 2.0E-05 34.0759 5.9E-07 1.1E-05 1237.8070 0.0131 0.0010 0.0336 0.0019

Water 1.0000 18.0150 0.0555 1.0000 13.2639 13.2637 0.9990 17.9972 0.9981

Total 1.0000 18.02 0.055509 1.0000 13.2768 1.0000 18.0308 1.0000

Calculations:

A = Liquid weight fraction H = G x B (vapor molecular weight fraction)

B = Liquid molecular weight I = H / H (vapor weight fraction)

C = A / B (liquid Lb-moles)

D = C / C (liquid mole fraction)

E = Pure component vapor pressure

F = D x E (partial pressure)

G = F / F (vapor mole fraction)

Raoult's Law Vapor Weight Fraction Determination

023

023

Raoult's Law Vapor Weight Fraction Determination

023

Raoult's Law Vapor Weight Fraction Determination
TANK TYPE: FIXED ROOF Indiana Gasification 024

Methanol De-Inventory 

Tank

Page 9 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM HOURLY 

CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Methanol Methanol

SHELL COLOR White White

ROOF TYPE Dome Dome

D: 55 55 ft

Hs: 40 40 ft

Vlx: 95,033 95,033 cf

Hl: 20 20 ft

Hro: 3.77 3.77 ft

Hvo: 23.77 23.77 ft

Vv: 56,468 56,468 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 1,386,000 525,600,000 gal/yr

Q: 33,000 12,514,286 bbl/yr

N: 1.95 739.3 turn/year

Mv: 32.04 32.0 lb/lbmol

Tb: 527.7 559.7 R

Tla: 529.6 559.7 R

Tlx: 534.7 564.8 R

Tln: 524.5 554.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 1.9817 4.6184 psia

Pvx: 2.3055 5.2770 psia

Pvn: 1.6976 4.0306 psia

Pv: 0.61 1.2 psia

Pbp: 0.22 0.22 psia

Pbv: (0.07) (0.07) psia

Pb: 0.29 0.29 psia

: 0.17 0.17

Kn: 1.00 0.21

Kp: 1.0 1.0

Wv: 0.0112 0.0246 lb/cf

Ke: 0.0635 0.131

Ks: 0.29 0.15

Ls: 4181.9333 9780.23 lb/yr

Lw: 2095.2688 383777.38 lb/yr

8760 8760 hr/yr

6277.20 393,557.60 lb/yr

UNCONTROLLED TOTAL EMISSIONS 0.717 44.93 lb/hr

3.139 2.0E+02 TPY

VAPOR RECOVERY (CHILLER) EFFICIENCY 95 95 %

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

SPECIATED EMISSIONS:

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Methanol (TAP)(VOC) 313.860 2.246

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Methanol (TAP)(VOC) 0.04 2.25 0.16

ROOF OUTAGE HEIGHT

BULK LIQUID CHARACTERISTICS

AMBIENT CONDITIONS

TANK CHARACTERISTICS

INSIDE DIAMETER

Unit ID:

DESCRIPTION:

VAPOR SPACE OUTAGE HEIGHT

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

LIQUID HEIGHT

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

VAPOR SPACE VOLUME

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

AVERAGE ATMOSPHERIC PRESSURE

DAILY MAX AMBIENT TEMPERATURE

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

DAILY SOLAR INSULATION FACTOR

TURNOVERS PER YEAR

VAPOR MOLECULAR WEIGHT

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

MAX DAILY AVG LIQ. SURFACE TEMP.

DAILY VAPOR TEMPERATURE RANGE

VAPOR PRESSURE PARAMETERS

VAPOR PRESSURE AT Tln

DAILY VAPOR PRESSURE RANGE

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

FACTORS

CALCULATED FACTORS

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

STANDING LOSS

ALTHOUGH TANK WILL ONLY CONTAIN METHANOL DURING THE TWO (2) RECTISOL DE-INVENTORYING PERIODS, STANDING 

LOSSES ARE CONSERVATIVELY ASSUMED TO OCCUR FOR 8,760 HR/YR.

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS
TANK TYPE: FIXED ROOF Indiana Gasification 025

Fresh Methanol Storage 

Tank

Page 10 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM HOURLY 

CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Methanol Methanol

SHELL COLOR White White

ROOF TYPE Dome Dome

D: 42 42 ft

Hs: 33 33 ft

Vlx: 45,720 45,720 cf

Hl: 16.5 16.5 ft

Hro: 2.88 2.88 ft

Hvo: 19.38 19.38 ft

Vv: 26,846 26,846 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 2,000,000 94,608,000 gal/yr

Q: 47,619 2,252,571 bbl/yr

N: 5.85 276.6 turn/year

Mv: 32.04 32.0 lb/lbmol

Tb: 527.7 559.7 R

Tla: 529.6 559.7 R

Tlx: 534.7 564.8 R

Tln: 524.5 554.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 1.9817 4.6184 psia

Pvx: 2.3055 5.2770 psia

Pvn: 1.6976 4.0306 psia

Pv: 0.61 1.2 psia

Pbp: 0.22 0.22 psia

Pbv: (0.07) (0.07) psia

Pb: 0.29 0.29 psia

: 0.17 0.17

Kn: 1.00 0.28

Kp: 1.0 1.0

Wv: 0.0112 0.0246 lb/cf

Ke: 0.0635 0.131

Ks: 0.33 0.17

Ls: 2290.2320 5519.80 lb/yr

Lw: 3023.4760 91705.85 lb/yr

8760 8760 hr/yr

5313.71 97,225.65 lb/yr

UNCONTROLLED TOTAL EMISSIONS 0.607 11.10 lb/hr

2.657 4.9E+01 TPY

VAPOR RECOVERY (CHILLER) EFFICIENCY 95 95 %

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

SPECIATED EMISSIONS:

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Methanol (TAP)(VOC) 265.685 0.555

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Methanol (TAP)(VOC) 0.03 0.55 0.13

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

STANDING LOSS

FACTORS

CALCULATED FACTORS

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

VAPOR PRESSURE AT Tln

DAILY VAPOR PRESSURE RANGE

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

DAILY VAPOR TEMPERATURE RANGE

VAPOR PRESSURE PARAMETERS

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

MAX DAILY AVG LIQ. SURFACE TEMP.

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

TURNOVERS PER YEAR

VAPOR MOLECULAR WEIGHT

DAILY SOLAR INSULATION FACTOR

BULK LIQUID CHARACTERISTICS

AMBIENT CONDITIONS

TANK CHARACTERISTICS

AVERAGE ATMOSPHERIC PRESSURE

DAILY MAX AMBIENT TEMPERATURE

LIQUID HEIGHT

ROOF OUTAGE HEIGHT

VAPOR SPACE OUTAGE HEIGHT

VAPOR SPACE VOLUME

Unit ID:

DESCRIPTION:

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

INSIDE DIAMETER
TANK TYPE: FIXED ROOF Indiana Gasification 026

Sour Water Stripper Surge

Page 11 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM HOURLY 

CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Sour Water Sour Water

SHELL COLOR White White

ROOF TYPE Dome Dome

D: 36 36 ft

Hs: 24 24 ft

Vlx: 24,429 24,429 cf

Hl: 12 12 ft

Hro: 2.47 2.47 ft

Hvo: 14.47 14.47 ft

Vv: 14,725 14,725 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 97,716 371,599,200 gal/yr

Q: 2,327 8,847,600 bbl/yr

N: 4.00 2033.3 turn/year

Mv: 32.04 32.0 lb/lbmol

Tb: 553.7 609.7 R

Tla: 544.2 609.7 R

Tlx: 549.3 614.8 R

Tln: 539.1 604.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 2.2732 7.4461 psia

Pvx: 2.4955 8.1523 psia

Pvn: 2.0704 6.7986 psia

Pv: 0.43 1.4 psia

Pbp: 0.22 0.22 psia

Pbv: (0.07) (0.07) psia

Pb: 0.29 0.29 psia

: 0.17 0.17

Kn: 1.00 0.18

Kp: 1.0 1.0

Wv: 0.0125 0.0365 lb/cf

Ke: 0.0483 0.180

Ks: 0.36 0.15

Ls: 1181.4897 5260.78 lb/yr

Lw: 169.4526 382945.11 lb/yr

8760 8760 hr/yr

1350.94 388,205.89 lb/yr

UNCONTROLLED TOTAL EMISSIONS (TAPs +water) 0.154 44.32 lb/hr

0.675 194.10 TPY

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

SPECIATED EMISSIONS:

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Ammonia (TAP) 55.121 1.660

Carbonyl Sulfide (TAP)(VOC) 7.623 0.192

Hydrogen Sulfide (TAP) 1071.701 26.739

Water 216.498 15.724

TOTAL (Including TAPs) 1350.942 44.316

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Ammonia (TAP) 0.006 1.660 0.028

Carbonyl Sulfide (TAP)(VOC) 0.00087 0.192 0.0038

Hydrogen Sulfide (TAP) 0.122 26.739 0.54

TOTAL 0.130 28.592 0.57

ROOF OUTAGE HEIGHT

BULK LIQUID CHARACTERISTICS

AMBIENT CONDITIONS

TANK CHARACTERISTICS

INSIDE DIAMETER

Unit ID:

DESCRIPTION:

VAPOR SPACE OUTAGE HEIGHT

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

LIQUID HEIGHT

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

VAPOR SPACE VOLUME

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

AVERAGE ATMOSPHERIC PRESSURE

DAILY MAX AMBIENT TEMPERATURE

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

DAILY SOLAR INSULATION FACTOR

TURNOVERS PER YEAR

VAPOR MOLECULAR WEIGHT

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

MAX DAILY AVG LIQ. SURFACE TEMP.

DAILY VAPOR TEMPERATURE RANGE

VAPOR PRESSURE PARAMETERS

VAPOR PRESSURE AT Tln

DAILY VAPOR PRESSURE RANGE

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

FACTORS

CALCULATED FACTORS

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

STANDING LOSS
026

At Tla (544.2 °R)

Page 12 of 40 TSD App A

AB C D E F G H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Ammonia 0.0009 17.0299 5.3E-05 0.0010 164.5665 0.1573 0.0692 1.1787 0.0408

Carbonyl Sulfide 0.0001 132.1599 7.6E-07 1.4E-05 204.8233 0.0028 0.0012 0.1630 0.0056

Hydrogen Sulfide 0.0089 34.0759 0.0003 0.0047 323.5576 1.5289 0.6726 22.9180 0.7933

Water 0.9901 18.0150 0.0550 0.9943 0.5875 0.5842 0.2570 4.6297 0.1603

Total 1.0000 18.09 0.055275 1.0000 2.2732 1.0000 28.8895 1.0000

AB C D E F G H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Ammonia 0.0009 17.0299 5.3E-05 0.0010 178.9567 0.1711 0.0686 1.1676 0.0408

Carbonyl Sulfide 0.0001 132.1599 7.6E-07 1.4E-05 219.1708 0.0030 0.0012 0.1589 0.0056

Hydrogen Sulfide 0.0089 34.0759 0.0003 0.0047 345.9243 1.6346 0.6550 22.3195 0.7803

Water 0.9901 18.0150 0.0550 0.9943 0.6908 0.6869 0.2752 4.9584 0.1733

Total 1.0000 18.09 0.055275 1.0000 2.4955 1.0000 28.6045 1.0000

AB C D E F G H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Ammonia 0.0009 17.0299 5.3E-05 0.0010 151.0775 0.1444 0.0698 1.1881 0.0407

Carbonyl Sulfide 0.0001 132.1599 7.6E-07 1.4E-05 191.1775 0.0026 0.0013 0.1671 0.0057

Hydrogen Sulfide 0.0089 34.0759 0.0003 0.0047 302.2601 1.4282 0.6898 23.5063 0.8058

Water 0.9901 18.0150 0.0550 0.9943 0.4980 0.4951 0.2391 4.3083 0.1477

Total 1.0000 18.09 0.055275 1.0000 2.0704 1.0000 29.1697 1.0000

Calculations:

A = Liquid weight fraction H = G x B (vapor molecular weight fraction)

B = Liquid molecular weight I = H / H (vapor weight fraction)

C = A / B (liquid Lb-moles)

D = C / C (liquid mole fraction)

E = Pure component vapor pressure

F = D x E (partial pressure)

G = F / F (vapor mole fraction)

Raoult's Law Vapor Weight Fraction Determination

Raoult's Law Vapor Weight Fraction Determination

026

At Tln (539.1 °R)

Raoult's Law Vapor Weight Fraction Determination

At Tlx (549.3 °R)

026
At Max Tla (609.7 °R)

Page 13 of 40 TSD App A

A B C D E FG H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Ammonia 0.0009 17.0299 5.3E-05 0.0010 432.2444 0.4133 0.0555 0.9452 0.0375

Carbonyl Sulfide 0.0001 132.1599 7.6E-07 1.4E-05 450.8631 0.0062 0.0008 0.1095 0.0043

Hydrogen Sulfide 0.0089 34.0759 0.0003 0.0047 704.0007 3.3265 0.4467 15.2232 0.6034

Water 0.9901 18.0150 0.0550 0.9943 3.7214 3.7002 0.4969 8.9521 0.3548

Total 1.0000 18.09 0.055275 1.0000 7.4461 1.0000 25.2301 1.0000

At Max Tlx (614.8 °R)

A B C D E FG H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Ammonia 0.0009 17.0299 5.3E-05 0.0010 461.9098 0.4416 0.0542 0.9226 0.0369

Carbonyl Sulfide 0.0001 132.1599 7.6E-07 1.4E-05 476.4069 0.0065 0.0008 0.1057 0.0042

Hydrogen Sulfide 0.0089 34.0759 0.0003 0.0047 743.1684 3.5116 0.4308 14.6782 0.5878

Water 0.9901 18.0150 0.0550 0.9943 4.2165 4.1925 0.5143 9.2647 0.3710

Total 1.0000 18.09 0.055275 1.0000 8.1523 1.0000 24.9712 1.0000

At Max Tln (604.6 °R)

A B C D E FG H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Ammonia 0.0009 17.0299 5.3E-05 0.0010 404.0334 0.3863 0.0568 0.9676 0.0380

Carbonyl Sulfide 0.0001 132.1599 7.6E-07 1.4E-05 426.3513 0.0058 0.0009 0.1135 0.0045

Hydrogen Sulfide 0.0089 34.0759 0.0003 0.0047 666.3631 3.1487 0.4631 15.7818 0.6190

Water 0.9901 18.0150 0.0550 0.9943 3.2764 3.2578 0.4792 8.6325 0.3386

Total 1.0000 18.09 0.055275 1.0000 6.7986 1.0000 25.4954 1.0000

Calculations:

A = Liquid weight fraction H = G x B (vapor molecular weight fraction)

B = Liquid molecular weight I = H / H (vapor weight fraction)

C = A / B (liquid Lb-moles)

D = C / C (liquid mole fraction)

E = Pure component vapor pressure

F = D x E (partial pressure)

G = F / F (vapor mole fraction)

026

Raoult's Law Vapor Weight Fraction Determination

026

Raoult's Law Vapor Weight Fraction Determination

026

Raoult's Law Vapor Weight Fraction Determination
TANK TYPE: FIXED ROOF Indiana Gasification 027 A

Sulfuric Acid Storage 

Tank

Page 14 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM HOURLY 

CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Sulfuric Acid Sulfuric Acid

SHELL COLOR White White

ROOF TYPE Dome Dome

D: 50 50 ft

Hs: 60 60 ft

Vlx: 117,810 117,810 cf

Hl: 30 30 ft

Hro: 3.43 3.43 ft

Hvo: 33.43 33.43 ft

Vv: 65,630 65,630 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 13,665,600 814,680,000 gal/yr

Q: 325,371 19,397,143 bbl/yr

N: 15.50 924.3 turn/year

Mv: 98.07 98.1 lb/lbmol

Tb: 564.7 609.7 R

Tla: 550.3 609.7 R

Tlx: 555.4 614.8 R

Tln: 545.2 604.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 0.0000130 0.000270 psia

Pvx: 0.0000175 0.000339 psia

Pvn: 0.0000096 0.000215 psia

Pv: 0.0000079 0.000124 psia

Pbp: 0.22 0.22 psia

Pbv: (0.07) (0.07) psia

Pb: 0.29 0.29 psia

: 0.17 0.17

Kn: 1.00 0.20

Kp: 1.0 1.0

Wv: 0.000000216 0.00000405 lb/cf

Ke: 0.0173 0.014

Ks: 1.00 1.00

Ls: 0.0898 1.33 lb/yr

Lw: 0.4158 102.43 lb/yr

8760 8760 hr/yr

0.51 103.77 lb/yr

UNCONTROLLED TOTAL EMISSIONS 5.8E-05 1.2E-02 lb/hr

2.5E-04 5.2E-02 TPY

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

SPECIATED EMISSIONS:

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Sulfuric Acid (TAP) 0.506 0.012

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Sulfuric Acid (TAP) 5.8E-05 1.2E-02 2.5E-04

ROOF OUTAGE HEIGHT

BULK LIQUID CHARACTERISTICS

AMBIENT CONDITIONS

TANK CHARACTERISTICS

INSIDE DIAMETER

Unit ID:

DESCRIPTION:

VAPOR SPACE OUTAGE HEIGHT

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

LIQUID HEIGHT

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

VAPOR SPACE VOLUME

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

AVERAGE ATMOSPHERIC PRESSURE

DAILY MAX AMBIENT TEMPERATURE

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

DAILY SOLAR INSULATION FACTOR

TURNOVERS PER YEAR

VAPOR MOLECULAR WEIGHT

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

MAX DAILY AVG LIQ. SURFACE TEMP.

DAILY VAPOR TEMPERATURE RANGE

VAPOR PRESSURE PARAMETERS

VAPOR PRESSURE AT Tln

DAILY VAPOR PRESSURE RANGE

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

FACTORS

CALCULATED FACTORS

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

STANDING LOSS
TANK TYPE: FIXED ROOF Indiana Gasification 027 B

Sulfuric Acid Storage 

Tank

Page 15 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM HOURLY 

CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Sulfuric Acid Sulfuric Acid

SHELL COLOR White White

ROOF TYPE Dome Dome

D: 50 50 ft

Hs: 60 60 ft

Vlx: 117,810 117,810 cf

Hl: 30 30 ft

Hro: 3.43 3.43 ft

Hvo: 33.43 33.43 ft

Vv: 65,630 65,630 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 13,665,600 814,680,000 gal/yr

Q: 325,371 19,397,143 bbl/yr

N: 15.50 924.3 turn/year

Mv: 98.07 98.1 lb/lbmol

Tb: 564.7 609.7 R

Tla: 550.3 609.7 R

Tlx: 555.4 614.8 R

Tln: 545.2 604.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 0.0000130 0.000270 psia

Pvx: 0.0000175 0.000339 psia

Pvn: 0.0000096 0.000215 psia

Pv: 0.0000079 0.000124 psia

Pbp: 0.22 0.22 psia

Pbv: (0.07) (0.07) psia

Pb: 0.29 0.29 psia

: 0.17 0.17

Kn: 1.00 0.20

Kp: 1.0 1.0

Wv: 0.000000216 0.00000405 lb/cf

Ke: 0.0173 0.014

Ks: 1.00 1.00

Ls: 0.0898 1.33 lb/yr

Lw: 0.4158 102.43 lb/yr

8760 8760 hr/yr

0.51 103.77 lb/yr

UNCONTROLLED TOTAL EMISSIONS 5.8E-05 1.2E-02 lb/hr

2.5E-04 5.2E-02 TPY

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

SPECIATED EMISSIONS:

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Sulfuric Acid (TAP) 0.506 0.012

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Sulfuric Acid (TAP) 5.8E-05 1.2E-02 2.5E-04

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

STANDING LOSS

FACTORS

CALCULATED FACTORS

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

VAPOR PRESSURE AT Tln

DAILY VAPOR PRESSURE RANGE

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

DAILY VAPOR TEMPERATURE RANGE

VAPOR PRESSURE PARAMETERS

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

MAX DAILY AVG LIQ. SURFACE TEMP.

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

TURNOVERS PER YEAR

VAPOR MOLECULAR WEIGHT

DAILY SOLAR INSULATION FACTOR

BULK LIQUID CHARACTERISTICS

AMBIENT CONDITIONS

TANK CHARACTERISTICS

AVERAGE ATMOSPHERIC PRESSURE

DAILY MAX AMBIENT TEMPERATURE

LIQUID HEIGHT

ROOF OUTAGE HEIGHT

VAPOR SPACE OUTAGE HEIGHT

VAPOR SPACE VOLUME

Unit ID:

DESCRIPTION:

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

INSIDE DIAMETER
TANK TYPE: FIXED ROOF Indiana Gasification 027 C

Sulfuric Acid Storage 

Tank

Page 16 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM HOURLY 

CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Sulfuric Acid Sulfuric Acid

SHELL COLOR White White

ROOF TYPE Dome Dome

D: 50 50 ft

Hs: 60 60 ft

Vlx: 117,810 117,810 cf

Hl: 30 30 ft

Hro: 3.43 3.43 ft

Hvo: 33.43 33.43 ft

Vv: 65,630 65,630 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 13,665,600 814,680,000 gal/yr

Q: 325,371 19,397,143 bbl/yr

N: 15.50 924.3 turn/year

Mv: 98.07 98.1 lb/lbmol

Tb: 564.7 609.7 R

Tla: 550.3 609.7 R

Tlx: 555.4 614.8 R

Tln: 545.2 604.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 0.0000130 0.000270 psia

Pvx: 0.0000175 0.000339 psia

Pvn: 0.0000096 0.000215 psia

Pv: 0.0000079 0.000124 psia

Pbp: 0.22 0.22 psia

Pbv: (0.07) (0.07) psia

Pb: 0.29 0.29 psia

: 0.17 0.17

Kn: 1.00 0.20

Kp: 1.0 1.0

Wv: 0.000000216 0.00000405 lb/cf

Ke: 0.0173 0.014

Ks: 1.00 1.00

Ls: 0.0898 1.33 lb/yr

Lw: 0.4158 102.43 lb/yr

8760 8760 hr/yr

0.51 103.77 lb/yr

UNCONTROLLED TOTAL EMISSIONS 5.8E-05 1.2E-02 lb/hr

2.5E-04 5.2E-02 TPY

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

SPECIATED EMISSIONS:

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Sulfuric Acid (TAP) 0.506 0.012

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Sulfuric Acid (TAP) 5.8E-05 1.2E-02 2.5E-04

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

STANDING LOSS

FACTORS

CALCULATED FACTORS

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

VAPOR PRESSURE AT Tln

DAILY VAPOR PRESSURE RANGE

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

DAILY VAPOR TEMPERATURE RANGE

VAPOR PRESSURE PARAMETERS

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

MAX DAILY AVG LIQ. SURFACE TEMP.

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

TURNOVERS PER YEAR

VAPOR MOLECULAR WEIGHT

DAILY SOLAR INSULATION FACTOR

BULK LIQUID CHARACTERISTICS

AMBIENT CONDITIONS

TANK CHARACTERISTICS

AVERAGE ATMOSPHERIC PRESSURE

DAILY MAX AMBIENT TEMPERATURE

LIQUID HEIGHT

ROOF OUTAGE HEIGHT

VAPOR SPACE OUTAGE HEIGHT

VAPOR SPACE VOLUME

Unit ID:

DESCRIPTION:

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

INSIDE DIAMETER
TANK TYPE: FIXED ROOF Indiana Gasification 027 D

Sulfuric Acid Storage 

Tank

Page 17 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM HOURLY 

CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Sulfuric Acid Sulfuric Acid

SHELL COLOR White White

ROOF TYPE Dome Dome

D: 50 50 ft

Hs: 60 60 ft

Vlx: 117,810 117,810 cf

Hl: 30 30 ft

Hro: 3.43 3.43 ft

Hvo: 33.43 33.43 ft

Vv: 65,630 65,630 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 13,665,600 814,680,000 gal/yr

Q: 325,371 19,397,143 bbl/yr

N: 15.50 924.3 turn/year

Mv: 98.07 98.1 lb/lbmol

Tb: 564.7 609.7 R

Tla: 550.3 609.7 R

Tlx: 555.4 614.8 R

Tln: 545.2 604.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 0.0000130 0.000270 psia

Pvx: 0.0000175 0.000339 psia

Pvn: 0.0000096 0.000215 psia

Pv: 0.0000079 0.000124 psia

Pbp: 0.22 0.22 psia

Pbv: (0.07) (0.07) psia

Pb: 0.29 0.29 psia

: 0.17 0.17

Kn: 1.00 0.20

Kp: 1.0 1.0

Wv: 0.000000216 0.00000405 lb/cf

Ke: 0.0173 0.014

Ks: 1.00 1.00

Ls: 0.0898 1.33 lb/yr

Lw: 0.4158 102.43 lb/yr

8760 8760 hr/yr

0.51 103.77 lb/yr

UNCONTROLLED TOTAL EMISSIONS 5.8E-05 1.2E-02 lb/hr

2.5E-04 5.2E-02 TPY

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

SPECIATED EMISSIONS:

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Sulfuric Acid (TAP) 0.506 0.012

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Sulfuric Acid (TAP) 5.8E-05 1.2E-02 2.5E-04

ROOF OUTAGE HEIGHT

BULK LIQUID CHARACTERISTICS

AMBIENT CONDITIONS

TANK CHARACTERISTICS

INSIDE DIAMETER

Unit ID:

DESCRIPTION:

VAPOR SPACE OUTAGE HEIGHT

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

LIQUID HEIGHT

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

VAPOR SPACE VOLUME

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

AVERAGE ATMOSPHERIC PRESSURE

DAILY MAX AMBIENT TEMPERATURE

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

DAILY SOLAR INSULATION FACTOR

TURNOVERS PER YEAR

VAPOR MOLECULAR WEIGHT

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

MAX DAILY AVG LIQ. SURFACE TEMP.

DAILY VAPOR TEMPERATURE RANGE

VAPOR PRESSURE PARAMETERS

VAPOR PRESSURE AT Tln

DAILY VAPOR PRESSURE RANGE

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

FACTORS

CALCULATED FACTORS

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

STANDING LOSS
TANK TYPE: FIXED ROOF Indiana Gasification 027 E

Sulfuric Acid Storage 

Tank

Page 18 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM HOURLY 

CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Sulfuric Acid Sulfuric Acid

SHELL COLOR White White

ROOF TYPE Dome Dome

D: 50 50 ft

Hs: 60 60 ft

Vlx: 117,810 117,810 cf

Hl: 30 30 ft

Hro: 3.43 3.43 ft

Hvo: 33.43 33.43 ft

Vv: 65,630 65,630 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 13,665,600 814,680,000 gal/yr

Q: 325,371 19,397,143 bbl/yr

N: 15.50 924.3 turn/year

Mv: 98.07 98.1 lb/lbmol

Tb: 564.7 609.7 R

Tla: 550.3 609.7 R

Tlx: 555.4 614.8 R

Tln: 545.2 604.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 0.0000130 0.000270 psia

Pvx: 0.0000175 0.000339 psia

Pvn: 0.0000096 0.000215 psia

Pv: 0.0000079 0.000124 psia

Pbp: 0.22 0.22 psia

Pbv: (0.07) (0.07) psia

Pb: 0.29 0.29 psia

: 0.17 0.17

Kn: 1.00 0.20

Kp: 1.0 1.0

Wv: 0.000000216 0.00000405 lb/cf

Ke: 0.0173 0.014

Ks: 1.00 1.00

Ls: 0.0898 1.33 lb/yr

Lw: 0.4158 102.43 lb/yr

8760 8760 hr/yr

0.51 103.77 lb/yr

UNCONTROLLED TOTAL EMISSIONS 5.8E-05 1.2E-02 lb/hr

2.5E-04 5.2E-02 TPY

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

SPECIATED EMISSIONS:

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Sulfuric Acid (TAP) 0.506 0.012

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Sulfuric Acid (TAP) 5.8E-05 1.2E-02 2.5E-04

ROOF OUTAGE HEIGHT

BULK LIQUID CHARACTERISTICS

AMBIENT CONDITIONS

TANK CHARACTERISTICS

INSIDE DIAMETER

Unit ID:

DESCRIPTION:

VAPOR SPACE OUTAGE HEIGHT

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

LIQUID HEIGHT

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

VAPOR SPACE VOLUME

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

AVERAGE ATMOSPHERIC PRESSURE

DAILY MAX AMBIENT TEMPERATURE

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

DAILY SOLAR INSULATION FACTOR

TURNOVERS PER YEAR

VAPOR MOLECULAR WEIGHT

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

MAX DAILY AVG LIQ. SURFACE TEMP.

DAILY VAPOR TEMPERATURE RANGE

VAPOR PRESSURE PARAMETERS

VAPOR PRESSURE AT Tln

DAILY VAPOR PRESSURE RANGE

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

FACTORS

CALCULATED FACTORS

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

STANDING LOSS
TANK TYPE: FIXED ROOF Indiana Gasification 027 F

Sulfuric Acid Storage 

Tank

Page 19 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM HOURLY 

CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Sulfuric Acid Sulfuric Acid

SHELL COLOR White White

ROOF TYPE Dome Dome

D: 50 50 ft

Hs: 60 60 ft

Vlx: 117,810 117,810 cf

Hl: 30 30 ft

Hro: 3.43 3.43 ft

Hvo: 33.43 33.43 ft

Vv: 65,630 65,630 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 13,665,600 814,680,000 gal/yr

Q: 325,371 19,397,143 bbl/yr

N: 15.50 924.3 turn/year

Mv: 98.07 98.1 lb/lbmol

Tb: 564.7 609.7 R

Tla: 550.3 609.7 R

Tlx: 555.4 614.8 R

Tln: 545.2 604.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 0.0000130 0.000270 psia

Pvx: 0.0000175 0.000339 psia

Pvn: 0.0000096 0.000215 psia

Pv: 0.0000079 0.000124 psia

Pbp: 0.22 0.22 psia

Pbv: (0.07) (0.07) psia

Pb: 0.29 0.29 psia

: 0.17 0.17

Kn: 1.00 0.20

Kp: 1.0 1.0

Wv: 0.000000216 0.00000405 lb/cf

Ke: 0.0173 0.014

Ks: 1.00 1.00

Ls: 0.0898 1.33 lb/yr

Lw: 0.4158 102.43 lb/yr

8760 8760 hr/yr

0.51 103.77 lb/yr

UNCONTROLLED TOTAL EMISSIONS 5.8E-05 1.2E-02 lb/hr

2.5E-04 5.2E-02 TPY

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

SPECIATED EMISSIONS:

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Sulfuric Acid (TAP) 0.506 0.012

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Sulfuric Acid (TAP) 5.8E-05 1.2E-02 2.5E-04

ROOF OUTAGE HEIGHT

BULK LIQUID CHARACTERISTICS

AMBIENT CONDITIONS

TANK CHARACTERISTICS

INSIDE DIAMETER

Unit ID:

DESCRIPTION:

VAPOR SPACE OUTAGE HEIGHT

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

LIQUID HEIGHT

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

VAPOR SPACE VOLUME

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

AVERAGE ATMOSPHERIC PRESSURE

DAILY MAX AMBIENT TEMPERATURE

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

DAILY SOLAR INSULATION FACTOR

TURNOVERS PER YEAR

VAPOR MOLECULAR WEIGHT

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

MAX DAILY AVG LIQ. SURFACE TEMP.

DAILY VAPOR TEMPERATURE RANGE

VAPOR PRESSURE PARAMETERS

VAPOR PRESSURE AT Tln

DAILY VAPOR PRESSURE RANGE

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

FACTORS

CALCULATED FACTORS

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

STANDING LOSS
TANK TYPE: FIXED ROOF Indiana Gasification 028 A

Aqueous Ammonia

Page 20 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM 

HOURLY CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Ammonia Ammonia

SHELL COLOR White White

ROOF TYPE Dome Dome

D: 14 14 ft

Hs: 28 28 ft

Vlx: 4,310 4,310 cf

Hl: 14 14 ft

Hro: 0.96 0.96 ft

Hvo: 14.96 14.96 ft

Vv: 2,303 2,303 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 440,000 105,120,000 gal/yr

Q: 10,476 2,502,857 bbl/yr

N: 13.64 3259.9 turn/year

Mv: 17.03 17.03 lb/lbmol

Tb: 539.7 566.7 R

Tla: 536.3 566.7 R

Tlx: 541.4 571.8 R

Tln: 531.2 561.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 5.3792 10.8983 psia

Pvx: 6.0783 12.1607 psia

Pvn: 4.7256 9.7276 psia

Pv: 1.35 2.4 psia

Pbp: 0.22 0.22 psia

Pbv: (0.07) (0.07) psia

Pb: 0.29 0.29 psia

: 0.17 0.17

Kn: 1.00 0.18

Kp: 1.0 1.0

Wv: 0.0159 0.0305 lb/cf

Ke: 0.1520 0.600

Ks: 0.19 0.10

Ls: 386.3219 1595.82 lb/yr

Lw: 959.6994 81695.32 lb/yr

8760 8760 hr/yr

1346.02 83,291.14 lb/yr

UNCONTROLLED TOTAL EMISSIONS (Ammonia and Water) 0.154 9.51 lb/hr

0.673 41.65 TPY

SCRUBBER EFFICIENCY 60 60 %

SPECIATED EMISSIONS:

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Ammonia (TAP) 500.215 3.461

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Ammonia (TAP) 0.057 3.461 0.25

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

ROOF OUTAGE HEIGHT

BULK LIQUID CHARACTERISTICS

AMBIENT CONDITIONS

TANK CHARACTERISTICS

INSIDE DIAMETER

Unit ID:

DESCRIPTION:

VAPOR SPACE OUTAGE HEIGHT

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

LIQUID HEIGHT

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

VAPOR SPACE VOLUME

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

AVERAGE ATMOSPHERIC PRESSURE

DAILY MAX AMBIENT TEMPERATURE

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

DAILY SOLAR INSULATION FACTOR

TURNOVERS PER YEAR

VAPOR MOLECULAR WEIGHT

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

MAX DAILY AVG LIQ. SURFACE TEMP.

DAILY VAPOR TEMPERATURE RANGE

VAPOR PRESSURE PARAMETERS

VAPOR PRESSURE AT Tln

DAILY VAPOR PRESSURE RANGE

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

FACTORS

CALCULATED FACTORS

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

STANDING LOSS
TANK TYPE: FIXED ROOF Indiana Gasification 028 B

Aqueous Ammonia

Page 21 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM 

HOURLY CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Ammonia Ammonia

SHELL COLOR White White

ROOF TYPE Dome Dome

D: 14 14 ft

Hs: 28 28 ft

Vlx: 4,310 4,310 cf

Hl: 14 14 ft

Hro: 0.96 0.96 ft

Hvo: 14.96 14.96 ft

Vv: 2,303 2,303 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 440,000 105,120,000 gal/yr

Q: 10,476 2,502,857 bbl/yr

N: 13.64 3259.9 turn/year

Mv: 17.03 17.03 lb/lbmol

Tb: 539.7 566.7 R

Tla: 536.3 566.7 R

Tlx: 541.4 571.8 R

Tln: 531.2 561.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 5.3792 10.8983 psia

Pvx: 6.0783 12.1607 psia

Pvn: 4.7256 9.7276 psia

Pv: 1.35 2.4 psia

Pbp: 0.22 0.22 psia

Pbv: (0.07) (0.07) psia

Pb: 0.29 0.29 psia

: 0.17 0.17

Kn: 1.00 0.18

Kp: 1.0 1.0

Wv: 0.0159 0.0305 lb/cf

Ke: 0.1520 0.600

Ks: 0.19 0.10

Ls: 386.3219 1595.82 lb/yr

Lw: 959.6994 81695.32 lb/yr

8760 8760 hr/yr

1346.02 83,291.14 lb/yr

UNCONTROLLED TOTAL EMISSIONS (Ammonia and Water) 0.154 9.51 lb/hr

0.673 41.65 TPY

SCRUBBER EFFICIENCY 60 60 %

SPECIATED EMISSIONS:

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Ammonia (TAP) 500.215 3.461

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Ammonia (TAP) 0.057 3.461 0.25

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

STANDING LOSS

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS

CALCULATED FACTORS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

FACTORS

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

DAILY VAPOR PRESSURE RANGE

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

VAPOR PRESSURE PARAMETERS

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

VAPOR PRESSURE AT Tln

MAX DAILY AVG LIQ. SURFACE TEMP.

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

DAILY VAPOR TEMPERATURE RANGE

VAPOR MOLECULAR WEIGHT

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

BULK LIQUID CHARACTERISTICS

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

TURNOVERS PER YEAR

DAILY MAX AMBIENT TEMPERATURE

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

DAILY SOLAR INSULATION FACTOR

VAPOR SPACE OUTAGE HEIGHT

VAPOR SPACE VOLUME

AMBIENT CONDITIONS

AVERAGE ATMOSPHERIC PRESSURE

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

LIQUID HEIGHT

ROOF OUTAGE HEIGHT

Unit ID:

DESCRIPTION:

TANK CHARACTERISTICS

INSIDE DIAMETER
028 A&B

At Tla (536.3 °R)

Page 22 of 40 TSD App A

AB C D E F G H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Ammonia 0.1950 17.0299 0.0115 0.2040 5.0171 0.9327 15.8835 0.9291

Water 0.8050 18.0150 0.0447 0.7960 0.4549 0.3621 0.0673 1.2128 0.0709

Total 1.0000 17.81 0.056135 1.0000 5.3792 1.0000 17.0962 1.0000

AB C D E F G H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Ammonia 0.1950 17.0299 0.0115 0.2040 5.6502 0.9296 15.8305 0.9258

Water 0.8050 18.0150 0.0447 0.7960 0.5378 0.4281 0.0704 1.2688 0.0742

Total 1.0000 17.81 0.056135 1.0000 6.0783 1.0000 17.0993 1.0000

AB C D E F G H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Ammonia 0.1950 17.0299 0.0115 0.2040 4.4204 0.9354 15.9300 0.9319

Water 0.8050 18.0150 0.0447 0.7960 0.3834 0.3052 0.0646 1.1635 0.0681

Total 1.0000 17.81 0.056135 1.0000 4.7256 1.0000 17.0935 1.0000

Calculations:

A = Liquid weight fraction H = G x B (vapor molecular weight fraction)

B = Liquid molecular weight I = H / H (vapor weight fraction)

C = A / B (liquid Lb-moles)

D = C / C (liquid mole fraction)

E = Pure component vapor pressure

F = D x E (partial pressure)

G = F / F (vapor mole fraction)

At Tln (531.2 °R)

Raoult's Law Vapor Weight Fraction Determination

At Tlx (541.4 °R)

028 A&B

Raoult's Law Vapor Weight Fraction Determination

028 A&B

Raoult's Law Vapor Weight Fraction Determination
At Max Tla (566.7 °R)

Page 23 of 40 TSD App A

A B C D E FG H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Ammonia 0.1950 17.0299 0.0115 0.2040 9.9668 0.9145 15.5743 0.9100

Water 0.8050 18.0150 0.0447 0.7960 1.1702 0.9315 0.0855 1.5398 0.0900

Total 1.0000 17.81 0.056135 1.0000 10.8983 1.0000 17.1141 1.0000

At Max Tlx (571.8 °R)

A B C D E FG H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Ammonia 0.1950 17.0299 0.0115 0.2040 11.0810 0.9112 15.5179 0.9066

Water 0.8050 18.0150 0.0447 0.7960 1.3563 1.0797 0.0888 1.5995 0.0934

Total 1.0000 17.81 0.056135 1.0000 12.1607 1.0000 17.1174 1.0000

At Max Tln (561.6 °R)

A B C D E FG H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Ammonia 0.1950 17.0299 0.0115 0.2040 8.9264 0.9176 15.6273 0.9133

Water 0.8050 18.0150 0.0447 0.7960 1.0065 0.8012 0.0824 1.4838 0.0867

Total 1.0000 17.81 0.056135 1.0000 9.7276 1.0000 17.1110 1.0000

Calculations:

A = Liquid weight fraction H = G x B (vapor molecular weight fraction)

B = Liquid molecular weight I = H / H (vapor weight fraction)

C = A / B (liquid Lb-moles)

D = C / C (liquid mole fraction)

E = Pure component vapor pressure

F = D x E (partial pressure)

G = F / F (vapor mole fraction)

Raoult's Law Vapor Weight Fraction Determination

028 A&B

028 A&B

Raoult's Law Vapor Weight Fraction Determination

028 A&B

Raoult's Law Vapor Weight Fraction Determination
 URS

TANK TYPE: FIXED ROOF Indiana Gasification 029

Diesel

Page 24 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM 

HOURLY CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Diesel Diesel

SHELL COLOR White White

ROOF TYPE Dome Dome

D: 11 11 ft

Hs: 14 14 ft

Vlx: 1,330 1,330 cf

Hl: 7 7 ft

Hro: 0.75 0.75 ft

Hvo: 7.75 7.75 ft

Vv: 737 737 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 10,000 87,184,247 gal/yr

Q: 238 2,075,815 bbl/yr

N: 1.00 8759.1 turn/year

Mv: 63.83 63.5 lb/lbmol

Tb: 539.7 566.7 R

Tla: 536.3 566.7 R

Tlx: 541.4 571.8 R

Tln: 531.2 561.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 6.0453 10.5614 psia

Pvx: 6.8042 11.4923 psia

Pvn: 5.6843 9.6891 psia

Pv: 1.12 1.8 psia

Pbp: 0.22 0.22 psia

Pbv: (0.22) (0.22) psia

Pb: 0.44 0.44 psia

: 0.17 0.17

Kn: 1.00 0.17

Kp: 1.0 1.0

Wv: 0.0670 0.1103 lb/cf

Ke: 0.1166 0.365

Ks: 0.29 0.19

Ls: 603.3699 2029.83 lb/yr

Lw: 91.8799 236835.26 lb/yr

8760 8760 hr/yr

695.25 238,865.09 lb/yr

UNCONTROLLED TOTAL EMISSIONS 0.0794 27.27 lb/hr

0.3476 119.43 TPY

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

EMISSIONS:

SPECIES lb/hr (avg) lb/hr (max) TPY

2.9E-07 1.9E-04 1.3E-06

1.1E-03 0.28 4.7E-03

3.2E-06 1.8E-03 1.4E-05

5.4E-03 1.74 0.02

2.1E-04 0.10 9.0E-04

3.2E-03 0.93 0.01

6.8E-03 2.23 0.03

0.06 21.97 0.27

0.08 27.27 0.35

ANNUAL EMISSIONS

VENTED VAPOR SATURATION FACTOR

STANDING LOSS

WORKING LOSS 

OPERATING HOURS PER YEAR

WORKING LOSS PRODUCT FACTOR

CALCULATED FACTORS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

BREATHER VENT PRESSURE SETTING RANGE

FACTORS

PAINT FACTOR

TURNOVER FACTOR

VAPOR PRESSURE AT Tln

DAILY VAPOR PRESSURE RANGE

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

DAILY VAPOR TEMPERATURE RANGE

VAPOR PRESSURE PARAMETERS

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

DAILY AVG LIQ. SURFACE TEMP.

MAX DAILY AVG LIQ. SURFACE TEMP.

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

TURNOVERS PER YEAR

VAPOR MOLECULAR WEIGHT

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY SOLAR INSULATION FACTOR

BULK LIQUID CHARACTERISTICS

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

AVERAGE ATMOSPHERIC PRESSURE

DAILY MAX AMBIENT TEMPERATURE

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

ROOF OUTAGE HEIGHT

VAPOR SPACE OUTAGE HEIGHT

VAPOR SPACE VOLUME

AMBIENT CONDITIONS

anthracene

benzene

Biphenyl

Unit ID:

DESCRIPTION:

TANK CHARACTERISTICS

INSIDE DIAMETER

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

LIQUID HEIGHT

non-TAP VOC

Total

ethyl benzene

naphthalene

Toluene

Xylene
TANK TYPE: FIXED ROOF Indiana Gasification 030

Gasoline

Page 25 of 40 TSD App A

AP-42

ANNUAL 

THROUGHPUT

CASE

MAXIMUM HOURLY 

CASE

VARIABLE (lb/hr avg) (lb/hr max) UNITS

Gasoline Gasoline

SHELL COLOR White White

ROOF TYPE Dome Dome

D: 5 5 ft

Hs: 8 8 ft

Vlx: 157 157 cf

Hl: 4 4 ft

Hro: 0.34 0.34 ft

Hvo: 4.34 4.34 ft

Vv: 85 85 cf

Pa: 14.7 14.7 psia

Tax: 77.6 77.6 °F

Tan: 58.3 58.3 °F

Taa: 527.95 527.95 R

I: 1365 1365 Btu/sf day

An: 8,000 5,256,000 gal/yr

Q: 190 125,143 bbl/yr

N: 6.81 4472.6 turn/year

Mv: 66.12 66.3 lb/lbmol

Tb: 539.7 566.7 R

Tla: 536.3 566.7 R

Tlx: 541.4 571.8 R

Tln: 531.2 561.6 R

Ta: 19.3 19.3 R

Tv: 20.4 20.4 R

Pva: 6.2000 10.8800 psia

Pvx: 6.9800 11.8490 psia

Pvn: 5.8200 9.9730 psia

Pv: 1.16 1.9 psia

Pbp: 0.22 0.22 psia

Pbv: (0.07) (0.07) psia

Pb: 0.29 0.29 psia

: 0.17 0.17

Kn: 1.00 0.17

Kp: 1.0 1.0

Wv: 0.0712 0.1186 lb/cf

Ke: 0.1404 0.451

Ks: 0.41 0.29

Ls: 128.2145 475.15 lb/yr

Lw: 78.0852 15644.55 lb/yr

8760 8760 hr/yr

206.30 16,119.71 lb/yr

UNCONTROLLED TOTAL EMISSIONS 0.024 1.84 lb/hr

0.103 8.06 TPY

COMMENTS:

EMISSIONS CALCULATED PER AP-42, CHAPTER 7 (9/97), AND URS TANK METHODOLOGY. 

STANDING LOSS

WORKING LOSS 

OPERATING HOURS PER YEAR

ANNUAL EMISSIONS

CALCULATED FACTORS

VAPOR DENSITY

VAPOR EXPANSION FACTOR

VENTED VAPOR SATURATION FACTOR

FACTORS

PAINT FACTOR

TURNOVER FACTOR

WORKING LOSS PRODUCT FACTOR

DAILY VAPOR PRESSURE RANGE

BREATHER VENT PRESSURE SETTING

BREATHER VENT VACUUM PRESSURE SETTING

BREATHER VENT PRESSURE SETTING RANGE

VAPOR PRESSURE PARAMETERS

VAPOR PRESSURE AT Tla

VAPOR PRESSURE AT Tlx

VAPOR PRESSURE AT Tln

MAX DAILY AVG LIQ. SURFACE TEMP.

MIN DAILY AVG LIQ. SURFACE TEMP.

DAILY AMBIENT TEMPERATURE RANGE

DAILY VAPOR TEMPERATURE RANGE

VAPOR MOLECULAR WEIGHT

TEMPERATURE PARAMETERS

LIQUID BULK TEMPERATURE

DAILY AVG LIQ. SURFACE TEMP.

BULK LIQUID CHARACTERISTICS

ANNUAL THROUGHPUT

ANNUAL THROUGHPUT

TURNOVERS PER YEAR

DAILY MAX AMBIENT TEMPERATURE

DAILY MIN AMBIENT TEMPERATURE

AMBIENT TEMPERATURE

DAILY SOLAR INSULATION FACTOR

VAPOR SPACE OUTAGE HEIGHT

VAPOR SPACE VOLUME

AMBIENT CONDITIONS

AVERAGE ATMOSPHERIC PRESSURE

TANK SHELL HEIGHT

MAX. TANK LIQUID VOLUME

LIQUID HEIGHT

ROOF OUTAGE HEIGHT

Unit ID:

DESCRIPTION:

TANK CHARACTERISTICS

INSIDE DIAMETER
SPECIATED EMISSIONS: Page 26 of 40 TSD App A

NORMAL SERVICE MAXIMUM HOURLY

SPECIES lb/yr lb/hr

Benzene 0.49 0.005

Cumene 0.04 0.001

Ethylbenzene 0.18 0.002

n-Hexane 4.75 0.048

Toluene 1.22 0.014

Xylene 0.37 0.005

non-TAP VOC 199.24 1.766

TOTAL (Including TAPs) 206.300 1.840

EMISSIONS TO BE PERMITTED:

SPECIES lb/hr (avg) lb/hr (max) TPY

Benzene (TAP)(VOC) 5.6E-05 0.01 2.5E-04

Cumene (TAP)(VOC) 4.6E-06 5.5E-04 2.0E-05

Ethylbenzene (TAP)(VOC) 2.1E-05 2.3E-03 9.1E-05

n-Hexane (TAP)(VOC) 5.4E-04 0.05 2.4E-03

Toluene (TAP)(VOC) 1.4E-04 0.01 6.1E-04

Xylene (TAP)(VOC) 4.3E-05 4.7E-03 1.9E-04

non-TAP VOC 0.02 1.77 0.10

Total TAP VOC 0.02 1.84 0.10

ALL LB/HR AND TPY LESS THAN 0.01 AND GREATER THAN ZERO WILL BE REPRESENTED AS "< 0.01" ON THE EIQ AND AAE FORMS.
At Tla (535.0 °R)

Page 27 of 40 TSD App A

ABC D E F GH I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

anthracene 0.00250 #NAME? #NAME? #NAME? #VALUE! #NAME? #NAME? #NAME? #NAME?

benzene 0.00010 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

Biphenyl 0.00100 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

ethyl benzene 0.0050 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

naphthalene 0.0100 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

Toluene 0.0010 92.14 1.1E-05 #NAME? 0.5201 #NAME? #NAME? #NAME? #NAME?

Xylene 0.0070 318.50 2.2E-05 #NAME? 0.1587 #NAME? #NAME? #NAME? #NAME?

non-TAP VOC 0.9734 142.11 0.0068 #NAME? #NAME? #NAME? #NAME? #NAME? #NAME?

Total 1.0000 #NAME? #NAME? #NAME? 0.0130 #NAME? #NAME? #NAME?

Calculations:

A = Liquid weight fraction H = G x B (vapor molecular weight fraction)

B = Liquid molecular weight I = H / H (vapor weight fraction)

C = A / B (liquid Lb-moles)

D = C / C (liquid mole fraction)

E = Pure component vapor pressure

F = D x E (partial pressure)

G = F / F (vapor mole fraction)

At Tlx (540.0 °R)

ABC D E F GH I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

anthracene 0.00250 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

benzene 0.00010 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

Biphenyl 0.00100 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

ethyl benzene 0.0050 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

naphthalene 0.0100 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

Toluene 0.0010 92.14 1.1E-05 #N/A 0.6002 #N/A #N/A #N/A #N/A

Xylene 0.0070 318.50 2.2E-05 #N/A 0.1864 #N/A #N/A #N/A #N/A

non-TAP VOC 0.9734 142.11 0.0068 #N/A #N/A #N/A #N/A #N/A #N/A

Total 1.0000 #N/A #N/A #N/A 0.0150 #N/A #N/A #N/A

At Tln (525.0 °R)

ABC D E F GH I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

anthracene 0.00250 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

benzene 0.00010 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

Biphenyl 0.00100 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

ethyl benzene 0.00500 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

naphthalene 0.01000 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

Toluene 0.00100 92.14 1.1E-05 #N/A 3.9E-01 #N/A #N/A #N/A #N/A

Xylene 0.00700 318.50 2.2E-05 #N/A 1.1E-01 #N/A #N/A #N/A #N/A

non-TAP VOC 0.9734 142.11 0.0068 #N/A #N/A #N/A #N/A #N/A #N/A

Total 1.0000 #N/A #N/A #N/A 0.0098 #N/A #N/A #N/A

Raoult's Law Vapor Weight Fraction Determination

Heavy Fuels

Raoult's Law Vapor Weight Fraction Determination

Heavy Fuels

Raoult's Law Vapor Weight Fraction Determination

Heavy Fuels
At Max Tla (570.0 °R)

Page 28 of 40 TSD App A

ABCDEFG H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

anthracene 0.00250 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

benzene 0.00010 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

Biphenyl 0.00100 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

ethyl benzene 0.00500 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

naphthalene 0.01000 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

Toluene 0.00100 92.14 1.1E-05 #N/A 1.3E+00 #N/A #N/A #N/A #N/A

Xylene 0.00700 318.50 2.2E-05 #N/A 4.5E-01 #N/A #N/A #N/A #N/A

non-TAP VOC 0.9734 142.11 0.0068 #N/A #N/A #N/A #N/A #N/A #N/A

Total 1.0000 #N/A #N/A #N/A 0.0390 #N/A #N/A #N/A

Calculations:

A = Liquid weight fraction H = G x B (vapor molecular weight fraction)

B = Liquid molecular weight I = H / H (vapor weight fraction)

C = A / B (liquid Lb-moles)

D = C / C (liquid mole fraction)

E = Pure component vapor pressure

F = D x E (partial pressure)

G = F / F (vapor mole fraction)

At Max Tlx (575.0 °R)

ABCDEFG H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

anthracene 0.00250 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

benzene 0.00010 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

Biphenyl 0.00100 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

ethyl benzene 0.00500 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

naphthalene 0.01000 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

Toluene 0.00100 92.14 1.1E-05 #N/A 1.5E+00 #N/A #N/A #N/A #N/A

Xylene 0.00700 318.50 2.2E-05 #N/A 5.2E-01 #N/A #N/A #N/A #N/A

non-TAP VOC 0.9734 142.11 0.0068 #N/A #N/A #N/A #N/A #N/A #N/A

Total 1.0000 #N/A #N/A #N/A 0.0450 #N/A #N/A #N/A

ABCDEFG H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

anthracene 0.00250 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

benzene 0.00010 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

Biphenyl 0.00100 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

ethyl benzene 0.00500 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

naphthalene 0.01000 #N/A #N/A #N/A #VALUE! #N/A #N/A #N/A #N/A

Toluene 0.00100 92.1409 1.1E-05 #N/A 1.03231 #N/A #N/A #N/A #N/A

Xylene 0.00700 318.5010 2.2E-05 #N/A 0.34201 #N/A #N/A #N/A #N/A

non-TAP VOC 0.9734 142.11 0.00685 #N/A #N/A #N/A #N/A #N/A #N/A

Total 1.0000 #N/A #N/A #N/A 0.0290 #N/A #N/A #N/A

Heavy Fuels

At Max Tln (560.0 °R)

Heavy Fuels

Raoult's Law Vapor Weight Fraction Determination

Raoult's Law Vapor Weight Fraction Determination

Raoult's Law Vapor Weight Fraction Determination

Heavy Fuels
30

Page 29 of 40 TSD App A

AB C DEF G H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Benzene 0.0074 78.11 9.5E-05 0.0069 1.8181 0.0125 0.0020 0.1570 0.0024

Cumene 0.0128 120.19 1.1E-04 0.0077 0.0873 0.0007 0.0001 0.0130 0.0002

Ethylbenzene 0.0271 106.17 2.6E-04 0.0185 0.1835 0.0034 0.0005 0.0580 0.0009

n-Hexane 0.0452 86.18 5.2E-04 0.0380 2.8843 0.1095 0.0177 1.5217 0.0230

Toluene 0.0614 92.14 6.7E-04 0.0482 0.5466 0.0264 0.0043 0.3917 0.0059

Xylene 0.0618 318.50 1.9E-04 0.0140 0.1658 0.0023 0.0004 0.1196 0.0018

non-TAP VOC 0.7843 65.48 0.0120 0.8667 6.9747 6.0453 0.9750 63.8494 0.9658

Total 1.0000 72.37 0.013819 1.0000 6.2000 1.0000 66.1105 1.0000

AB C DEF G H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Benzene 0.0074 78.11 9.47E-05 0.0069 2.0697 1.4E-02 0.00203 0.15879 0.00240

Cumene 0.0128 120.19 1.06E-04 0.0077 0.1038 8.0E-04 0.00011 0.01378 0.00021

Ethylbenzene 0.0271 106.17 2.55E-04 0.0185 0.2155 4.0E-03 0.00057 0.06054 0.00092

n-Hexane 0.0452 86.18 5.24E-04 0.0380 3.2576 1.2E-01 0.01771 1.52656 0.02309

Toluene 0.0614 92.14 6.66E-04 0.0482 0.6315 3.0E-02 0.00436 0.40198 0.00608

Xylene 0.0618 318.50 1.94E-04 0.0140 0.1951 2.7E-03 0.00039 0.12499 0.00189

non-TAP VOC 0.7843 65.48 1.20E-02 0.8667 7.8503 6.8042 0.97481 63.83389 0.96542

Total 1.0000 72.37 0.013819 1.0000 6.98000 1.0000 66.1205 1.0000

AB C DEF G H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Benzene 0.0074 78.11 9.47E-05 0.00686 1.5924 1.1E-02 0.00188 0.14652 0.00222

Cumene 0.0128 120.19 1.06E-04 0.00771 0.0731 5.6E-04 0.00010 0.01164 0.00018

Ethylbenzene 0.0271 106.17 2.55E-04 0.01847 0.1556 2.9E-03 0.00049 0.05245 0.00079

n-Hexane 0.0452 86.18 5.24E-04 0.03796 2.5466 9.7E-02 0.01661 1.43127 0.02166

Toluene 0.0614 92.14 6.66E-04 0.04822 0.4716 2.3E-02 0.00391 0.36008 0.00545

Xylene 0.0618 318.50 1.94E-04 0.01404 0.1403 2.0E-03 0.00034 0.10784 0.00163

non-TAP VOC 0.7843 65.48 1.20E-02 0.86674 6.5582 5.6843 0.97668 63.95605 0.96807

Total 1.0000 72.37 0.013819 1.0000 5.82000 1.0000 66.0658 1.0000

Calculations:

A = Liquid weight fraction H = G x B (vapor molecular weight fraction)

B = Liquid molecular weight I = H / H (vapor weight fraction)

C = A / B (liquid Lb-moles)

D = C / C (liquid mole fraction)

E = Pure component vapor pressure

F = D x E (partial pressure)

G = F / F (vapor mole fraction)

Raoult's Law Vapor Weight Fraction Determination

Raoult's Law Vapor Weight Fraction Determination

At Tla (536.3 °R)

30

At Tln (531.2 °R)

At Tlx (541.4 °R)

30

Raoult's Law Vapor Weight Fraction Determination
At Max Tla (566.7 °R)

Page 30 of 40 TSD App A

A B C DEFG H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Benzene 0.0074 78.11 9.5E-05 0.0069 3.7724 2.6E-02 0.00238 0.18568 0.00280

Cumene 0.0128 120.19 1.1E-04 0.0077 0.2313 1.8E-03 0.00016 0.01969 0.00030

Ethylbenzene 0.0271 106.17 2.6E-04 0.0185 0.4536 8.4E-03 0.00077 0.08177 0.00123

n-Hexane 0.0452 86.18 5.2E-04 0.0380 5.7257 2.2E-01 0.01997 1.72137 0.02598

Toluene 0.0614 92.14 6.7E-04 0.0482 1.2331 5.9E-02 0.00547 0.50358 0.00760

Xylene 0.0618 318.50 1.9E-04 0.0140 0.4139 5.8E-03 0.00053 0.17014 0.00257

non-TAP VOC 0.7843 65.48 1.2E-02 0.8667 12.1851 10.5614 0.97071 63.56551 0.95951

Total 1.0000 72.37 0.013819 1.0000 10.8800 1.0000 66.2477 1.0000

At Max Tlx (571.8 °R)

A B C DEFG H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Benzene 0.0074 78.11 9.5E-05 0.0069 4.2264 2.9E-02 0.00245 0.19101 0.00288

Cumene 0.0128 120.19 1.1E-04 0.0077 0.2692 2.1E-03 0.00018 0.02104 0.00032

Ethylbenzene 0.0271 106.17 2.6E-04 0.0185 0.5223 9.6E-03 0.00081 0.08645 0.00130

n-Hexane 0.0452 86.18 5.2E-04 0.0380 6.3712 2.4E-01 0.02041 1.75881 0.02654

Toluene 0.0614 92.14 6.7E-04 0.0482 1.3999 6.8E-02 0.00570 0.52494 0.00792

Xylene 0.0618 318.50 1.9E-04 0.0140 0.4772 6.7E-03 0.00057 0.18010 0.00272

non-TAP VOC 0.7843 65.48 1.2E-02 0.8667 13.2591 11.4923 0.96989 63.51174 0.95832

Total 1.0000 72.37 0.013819 1.0000 11.84900 1.0000 66.274 1.0000

At Max Tln (561.6 °R)

A B C DEFG H I

Liquid Liquid Liquid Liquid Vapor Partial Vapor G x B Vapor

Weight Molecular Lb-Moles Mole Pressure Pressure Mole Weight

Species Fraction Weight Fraction psia psia Fraction Fraction

Benzene 0.0074 78.11 9.5E-05 0.0069 3.3588 2.3E-02 0.00231 0.18035 0.00272

Cumene 0.0128 120.19 1.1E-04 0.0077 0.1981 1.5E-03 0.00015 0.01840 0.00028

Ethylbenzene 0.0271 106.17 2.6E-04 0.0185 0.3928 7.3E-03 0.00073 0.07724 0.00117

n-Hexane 0.0452 86.18 5.2E-04 0.0380 5.1337 1.9E-01 0.01954 1.68376 0.02543

Toluene 0.0614 92.14 6.7E-04 0.0482 1.0832 5.2E-02 0.00524 0.48262 0.00729

Xylene 0.0618 318.50 1.9E-04 0.0140 0.3579 5.0E-03 0.00050 0.16051 0.00242

non-TAP VOC 0.7843 65.48 1.2E-02 0.8667 11.1787 9.6891 0.97153 63.61893 0.96069

Total 1.0000 72.37 0.013819 1.0000 9.97300 1.00000 66.2218 1.00000

Calculations:

A = Liquid weight fraction H = G x B (vapor molecular weight fraction)

B = Liquid molecular weight I = H / H (vapor weight fraction)

C = A / B (liquid Lb-moles)

D = C / C (liquid mole fraction)

E = Pure component vapor pressure

F = D x E (partial pressure)

G = F / F (vapor mole fraction)

30

Raoult's Law Vapor Weight Fraction Determination

30

Raoult's Law Vapor Weight Fraction Determination

30

Raoult's Law Vapor Weight Fraction Determination
CAS MOLECULAR Page 31 of 40 TSD

CHEMICAL NAME NUMBER WEIGHT A B C D E

Ammonia 7664-41-7 17.03 90.483 4669.7 -11.607 0.017194 1

Carbon Dioxide 124-38-9 44.01 140.54 4735 -21.268 0.040909 1

Carbon Monoxide 630-08-0 28.01 45.698 1076.6 -4.8814 7.567E-05 2

Benzene 71-43-2 78.11 83.107 6486.2 -9.2194 6.984E-06 2

Cumene 98-82-8 120.19 102.81 8674.6 -11.922 7.005E-06 2

Ethylbenzene 100-41-4 106.17 89.063 7733.7 -9.917 5.986E-06 2

Toluene 108-88-3 92.14 76.945 6729.8 -8.179 5.302E-06 2

Carbonyl Sulfide 463-58-1 132.16 89.756 3957.4 -12.036 0.020634 1

Hydrogen Sulfide 7783-06-4 34.08 85.584 3839.9 -11.199 0.018848 1

Methanol 67-56-1 32.04 82.718 6904.5 -8.8622 7.47E-06 2

Glycol 112-27-6 150.17 152.480 16449.0 -17.6700 6.45E-18 6

Water 7732-18-5 18.01 73.649 7258.2 -7.3037 4.165E-06 2

Vinyl Acetate 108-05-4 86.09 57.406 5702.8 -5.0307 1.10E-17 6

Comments:

Riedel Equation & Constants are from UCC's Database

Riedel Equation:

ln(P)=A-B/T+Cln(T)+DT^E

P is in PA

T is Temperature in degrees Kelvin

Note:

For VPRiedel() Function; Use Rankin as second variable. The function will convert Rankin into Kelvin.

Example:

VPRiedel("Methanol",527.4)

Or 

VPRiedel(A12,J1)

Where A12 is the Chemical and J1 is the Temperature in Rankin

PW32 Reidel ln(P)=A-B/T+Cln(T)+DT^E

Used the decene constants for alkene.

Used the triethylene glycol constants for polyethylene glycol.

RIEDEL CONSTANTS
Page 32 of 40 TSD App A

CAS MOLECULAR ANTOINE CONSTANTS VP@20°C

CHEMICAL NAME NUMBER WEIGHT A B C (mmHg)

TOLUENE 108-88-3 92.14 6.9866 1363.4762 221.4790 21.88991

n-hexane 110-54-3 86.18 6.8702 1168.7199 224.2099 121.47341

Xylene 1330-20-7 318.50 6.99052 1453.43 215.307 6.51299

Sulfuric Acid 7664-93-9 98.07 7.3456 2421.1499 197.798 0.00017

Notes:

Antoines Equation: Log10(P) = A - (B / (T +C)) P as mmHg; T as °C

Antoines Constants from the UCC's Chemical database.

Glycol Ethers (II): Methyl Cellosolve

Glycol Ethers (II-S): Methyl Carbitol (Glycol Ethers (II-S) vapor pressure will be utilized for all glycol ethers Supl. List (table 51.3). 

ANTOINES CONSTANTS FOR VARIOUS COMPONENTS 
Page 33 of 40 TSD App A

Unit ID Tank ID Tank Common Name

Shell 

Color

Paint 

Condition

Roof 

Type

Bottom 

Type

Inside 

Diameter

Tank 

Shell 

Height

Annual 

Thruput

Annual 

Throughput

(ft) (ft) lb/yr Gal/yr

023 A Slag Sump White Good Flat Flat 260 13 400,048,176 37,492,800

023 B Slag Sump White Good Flat Flat 260 13 400,048,176 37,492,800

023 C Slag Sump White Good Flat Flat 260 13 400,048,176 37,492,800

023 D Slag Sump White Good Flat Flat 260 13 400,048,176 37,492,800

023 E Slag Sump White Good Flat Flat 260 13 400,048,176 37,492,800

024 Methanol De-Inventory Tank White Good Dome flat 55 40 9,203,040 1,386,000

025 Fresh Methanol Storage Tank White Good Dome flat 42 33 13,280,000 2,000,000

027 A Sulfuric Acid Storage Tank White Good Dome flat 50 60 206,350,560 13,665,600

027 B Sulfuric Acid Storage Tank White Good Dome flat 50 60 206,350,560 13,665,600

027 C Sulfuric Acid Storage Tank White Good Dome flat 50 60 206,350,560 13,665,600

027 D Sulfuric Acid Storage Tank White Good Dome flat 50 60 206,350,560 13,665,600

027 E Sulfuric Acid Storage Tank White Good Dome flat 50 60 206,350,560 13,665,600

027 F Sulfuric Acid Storage Tank White Good Dome flat 50 60 206,350,560 13,665,600

028 A Aqueous Ammonia White Good Dome flat 14 28 3,388,000 440,000

028 B Aqueous Ammonia White Good Dome flat 14 28 3,388,000 440,000

029 Diesel White Good Dome flat 11 14 71,000 10,000

030 Gasoline White Good Dome flat 5 8 48,800 8,000

026 Sour Water Stripper Surge White Good Dome flat 36 24 0 0

TANK CHARACTERISTICS BULK LIQUID CHARACTERI

STORAGE TANK PARAMETERS

TANK IDENTIFICATION
Unit ID Tank ID Tank Common Name

023 A Slag Sump

023 B Slag Sump

023 C Slag Sump

023 D Slag Sump

023 E Slag Sump

024 Methanol De-Inventory Tank

025 Fresh Methanol Storage Tank

027 A Sulfuric Acid Storage Tank

027 B Sulfuric Acid Storage Tank

027 C Sulfuric Acid Storage Tank

027 D Sulfuric Acid Storage Tank

027 E Sulfuric Acid Storage Tank

027 F Sulfuric Acid Storage Tank

028 A Aqueous Ammonia

028 B Aqueous Ammonia

029 Diesel

030 Gasoline

026 Sour Water Stripper Surge

STORAGE TANK PARAMETERS

TANK IDENTIFICATION

Page 34 of 40 TSD App A

Max 

Pump 

Rate

Horiz/ 

Vert

Vapor 

Molecular 

Weight

Max Vapor 

Molecular 

Weight Ts (°F)

 Max Ts 

(°F) Ts (°C)

Gal/hr (Mv) (Mv)

33,540 Vertical 18.0536 18.0300

33,540 Vertical 18.0536 18.0300

33,540 Vertical 18.0536 18.0300

33,540 Vertical 18.0536 18.0300

33,540 Vertical 18.0536 18.0300

60,000 Vertical 32.0399 32.0399

10,800 Vertical 32.0399 32.0399

93,000 Vertical 98.0700 98.0700

93,000 Vertical 98.0700 98.0700

93,000 Vertical 98.0700 98.0700

93,000 Vertical 98.0700 98.0700

93,000 Vertical 98.0700 98.0700

93,000 Vertical 98.0700 98.0700

12,000 Vertical 17.0299 17.0299

12,000 Vertical 17.0299 17.0299

6,000 Vertical 63.8339 63.5117

600 Vertical 66.1205 66.2741

42,420 Vertical 32.0399 32.0399

ISTICS BULK LIQUID CHARACTERISTICS
Unit ID Tank ID Tank Common Name

023 A Slag Sump

023 B Slag Sump

023 C Slag Sump

023 D Slag Sump

023 E Slag Sump

024 Methanol De-Inventory Tank

025 Fresh Methanol Storage Tank

027 A Sulfuric Acid Storage Tank

027 B Sulfuric Acid Storage Tank

027 C Sulfuric Acid Storage Tank

027 D Sulfuric Acid Storage Tank

027 E Sulfuric Acid Storage Tank

027 F Sulfuric Acid Storage Tank

028 A Aqueous Ammonia

028 B Aqueous Ammonia

029 Diesel

030 Gasoline

026 Sour Water Stripper Surge

STORAGE TANK PARAMETERS

TANK IDENTIFICATION

Page 35 of 40 TSD App A

 Max Ts (°C)

Liquid Bulk 

Temperature

Maximum 

Liquid Bulk 

Temperature Tla Tlx Tln

(R) (R)

648 672

648 672

648 672

648 672

648 672

528 560

528 560

565 610

565 610

565 610

565 610

565 610

565 610

540 567

540 567

540 567

540 567

554 610

TEMPERATURES
Unit ID Tank ID Tank Common Name

023 A Slag Sump

023 B Slag Sump

023 C Slag Sump

023 D Slag Sump

023 E Slag Sump

024 Methanol De-Inventory Tank

025 Fresh Methanol Storage Tank

027 A Sulfuric Acid Storage Tank

027 B Sulfuric Acid Storage Tank

027 C Sulfuric Acid Storage Tank

027 D Sulfuric Acid Storage Tank

027 E Sulfuric Acid Storage Tank

027 F Sulfuric Acid Storage Tank

028 A Aqueous Ammonia

028 B Aqueous Ammonia

029 Diesel

030 Gasoline

026 Sour Water Stripper Surge

STORAGE TANK PARAMETERS

TANK IDENTIFICATION

Page 36 of 40 TSD App A

Pva Pvx Pvn

2.6937 3.0707 2.3570

2.6937 3.0707 2.3570

2.6937 3.0707 2.3570

2.6937 3.0707 2.3570

2.6937 3.0707 2.3570

1.9817 2.3055 1.6976

1.9817 2.3055 1.6976

0.00001 0.00002 0.00001

0.00001 0.00002 0.00001

0.00001 0.00002 0.00001

0.00001 0.00002 0.00001

0.00001 0.00002 0.00001

0.00001 0.00002 0.00001

5.37923 6.07829 4.72561

5.37923 6.07829 4.72561

6.04531 6.80420 5.68427

6.20000 6.98000 5.82000

2.2732 2.4955 2.0704

VAPOR PRE
Unit ID Tank ID Tank Common Name

023 A Slag Sump

023 B Slag Sump

023 C Slag Sump

023 D Slag Sump

023 E Slag Sump

024 Methanol De-Inventory Tank

025 Fresh Methanol Storage Tank

027 A Sulfuric Acid Storage Tank

027 B Sulfuric Acid Storage Tank

027 C Sulfuric Acid Storage Tank

027 D Sulfuric Acid Storage Tank

027 E Sulfuric Acid Storage Tank

027 F Sulfuric Acid Storage Tank

028 A Aqueous Ammonia

028 B Aqueous Ammonia

029 Diesel

030 Gasoline

026 Sour Water Stripper Surge

STORAGE TANK PARAMETERS

TANK IDENTIFICATION

Page 37 of 40 TSD App A

Max Pva Max Pvx Max Pvn

Breather 

Vent 

Pressure 

Setting

Breather 

Vent 

Vacuum 

Pressure 

Setting

Constant Inert 

Purge Flow Rate

(SCFH)

Composition 

ID

(psia) (psia)

14.7002 16.2478 13.2768 0.22 -0.04

14.7002 16.2478 13.2768 0.22 -0.04

14.7002 16.2478 13.2768 0.22 -0.04 C

14.7002 16.2478 13.2768 0.22 -0.04

14.7002 16.2478 13.2768 0.22 -0.04

4.6184 5.2770 4.0306 0.22 -0.07

4.6184 5.2770 4.0306 0.22 -0.07

0.00027 0.00034 0.00021 0.22 -0.07

0.00027 0.00034 0.00021 0.22 -0.07

0.00027 0.00034 0.00021 0.22 -0.07

0.00027 0.00034 0.00021 0.22 -0.07

0.00027 0.00034 0.00021 0.22 -0.07

0.00027 0.00034 0.00021 0.22 -0.07

10.89830 12.16068 9.72759 0.22 -0.07

10.89830 12.16068 9.72759 0.22 -0.07

10.56138 11.49227 9.68907 0.22 -0.22

10.88000 11.84900 9.97300 0.22 -0.07

7.4461 8.1523 6.7986 0.22 -0.07

SSURE PARAMETERS
Unit ID Tank ID Tank Common Name

023 A Slag Sump

023 B Slag Sump

023 C Slag Sump

023 D Slag Sump

023 E Slag Sump

024 Methanol De-Inventory Tank

025 Fresh Methanol Storage Tank

027 A Sulfuric Acid Storage Tank

027 B Sulfuric Acid Storage Tank

027 C Sulfuric Acid Storage Tank

027 D Sulfuric Acid Storage Tank

027 E Sulfuric Acid Storage Tank

027 F Sulfuric Acid Storage Tank

028 A Aqueous Ammonia

028 B Aqueous Ammonia

029 Diesel

030 Gasoline

026 Sour Water Stripper Surge

STORAGE TANK PARAMETERS

TANK IDENTIFICATION

Page 38 of 40 TSD App A

Constant 

Level?

Bottom 

Shape

Dome 

Height (ft.)

Seal 

Type

Insulated

?

Heated 

?

Refrigerated 

?

Breathing 

Loss 

Evaluation

#REF! No No No 3

0.00 No No No 3

onstant Level? No No No 3

0.00 No No No 3

No No No 3

No No No No 3

No No No No 3

No No No 3

No No No 3

No No No 3

No No No 3

No No No 3

No No No No 3

No No No 3

No No No 3

No No No 3

No No No 3

No No No No 3

Additional Tank Characteristics
Unit ID Tank ID Tank Common Name

023 A Slag Sump

023 B Slag Sump

023 C Slag Sump

023 D Slag Sump

023 E Slag Sump

024 Methanol De-Inventory Tank

025 Fresh Methanol Storage Tank

027 A Sulfuric Acid Storage Tank

027 B Sulfuric Acid Storage Tank

027 C Sulfuric Acid Storage Tank

027 D Sulfuric Acid Storage Tank

027 E Sulfuric Acid Storage Tank

027 F Sulfuric Acid Storage Tank

028 A Aqueous Ammonia

028 B Aqueous Ammonia

029 Diesel

030 Gasoline

026 Sour Water Stripper Surge

STORAGE TANK PARAMETERS

TANK IDENTIFICATION

Page 39 of 40 TSD App A

Service

Sp. 

Gravity

Density 

lb/gal MM Gal Gallons Lbs

Slag 1.22 10.67 0.0253 25,284 269,781

Slag 1.22 10.67 0.0253 25,284 269,781

Slag 1.22 10.67 0.0253 25,284 269,781

Slag 1.22 10.67 0.0253 25,284 269,781

Slag 1.22 10.67 0.0253 25,284 269,781

Methanol 6.64 0.7109 710,896 4,720,347

Methanol 6.64 0.3420 342,005 2,270,916

Sulfuric Acid 15.10 0.8813 881,276 13,307,262

Sulfuric Acid 15.10 0.8813 881,276 13,307,262

Sulfuric Acid 15.10 0.8813 881,276 13,307,262

Sulfuric Acid 15.10 0.8813 881,276 13,307,262

Sulfuric Acid 15.10 0.8813 881,276 13,307,262

Sulfuric Acid 15.10 0.8813 881,276 13,307,262

Ammonia 7.70 0.0322 32,243 248,271

Ammonia 7.70 0.0322 32,243 248,271

Diesel 7.10 0.0100 9,953 70,663

Gasoline 6.10 0.0012 1,175 7,168

Sour Water 8.25 0.1827 182,741 1,507,616

Volume
Page 40 of 40 TSD App A

COMPONENT A B C Max Temp. Min. Temp.

VP@300K

(Psia)

1,3-BUTADIENE 15.7727 2142.66 -34.30

ACETALDEHYDE 7.0564 1070.60 236.10

ACETIC ACID 7.2996 1479.02 216.81

ACETONE 16.6513 2940.46 -35.93 350 241

ACRYLIC ACID 7.5311 1656.57 215.03

BENZENE 15.9008 2788.51 -52.36 377 280

BENZOIC ACID 17.1634 4190.70 -125.20 560 405

BUTANOL 17.2160 3137.02 -94.43 404 288

ETHANOL 18.9119 3803.98 -41.68 369 270

ETHYL ACETATE 16.1516 2790.50 -57.15 385 260

ETHYL ACRYLATE 16.0890 2974.94 -58.15 409 274

ETHYL ETHER 16.0828 2511.29 -41.95 30 225 11.08433552

ETHYL PROPIONATE 16.1620 2935.11 -64.17 396 276

FORMIC ACID 7.3778 1563.28 247.06

ISOBUTANOL 16.8712 2874.73 -100.30 388 293

ISOBUTYRALDEHYDE 15.9888 2676.98 -51.15 370 247

ISOPROPYL ETHER 6.9332 1181.30 223.00

METHANOL 18.5875 3626.55 -34.29 364 257

METHYL ACETATE 16.1295 2601.92 -56.15 360 245

METHYL FORMATE 16.5104 2590.87 -42.60 324 225

MONOETHANOLAMINE 17.8174 3988.33 -86.93 477 344

NAPHTHALENE 16.1426 3992.01 -71.29 525 360

N-BUTYRALDEHYDE 16.1668 2839.09 -50.15 380 255

PHENOL 16.4270 3490.89 -98.59 481 345

PHTHALIC ANHYDRIDE 15.9984 4467.01 -83.15 615 409

PROPANE 15.7260 1872.46 -25.16 249 164

PROPIONALDEHYDE 16.2315 2659.02 -44.15 350 235

PROPYLENE 15.7027 1807.53 -26.15 240 160

SULFURIC ACID 7.3456 2421.15 197.80

VCH -10.0000 0.00 1.00

WATER 7.9683 1669.30 228.00

XYLENE 6.9905 1453.43 215.31

FUNCTION SYNTAX: VP1("COMPONENT",TEMPERATURE(°R))

ANTOINE VAPOR PRESSURE EQUATION: LN(P)=A-B/(T+C) P as mmHg Exp(A - B / (T + C)) / 760 * 14.7

T as Kelvin

Antoines Constants from "The Properties of Gases and Liquids, 3rd Edition", by Reid, Prausnitz and Sherwood, McGraw Hill, 1977. 

Chemical A B C

Benzene 6.9050 1211.033 220.790 1.7634140 1.7459220

Ethyl acrylate 7.9645 1897.011 273.160

Ethylbenzene 6.9750 1424.255 213.210

Hexane (-n) 6.8760 1171.170 224.410

Styrene 7.1400 1574.510 224.090

Toluene 6.9540 1344.800 219.480

Xylene 7.0090 1462.266 215.110

Antoines Equation Log10(P) = A - (B / T +C)

P as mmHg

T as °C

Antoines Constants from the Chemical database of Tanks 3.1 program.

FUNCTION SYNTAX: VP2("CHEMICAL",TEMPERATURE(R))

Chemical 1 mm Hg 10 mm Hg 40 mm Hg 100 mm Hg 400 mm Hg 760 mm Hg

Phenylenediamine 671.64 756.6 819.6 868.2 958.2 1005.9

Hydroquinone 730.32 786.3 837.6 881.7 963.6 1007.16

Vapor Pressures and Temperatures from "Handbook of Chemistry and Physics" 64th edition

FUNCTION SYNTAX: Interp("CHEMICAL",TEMPERATURE(R))

Temperature (R)

Interpolations

ANTOINES CONSTANTS FOR VARIOUS COMPONENTS (Properties of Gases and Vapor Pressures)

ANTOINES CONSTANTS FOR VARIOUS CHEMICALS (TANKS 3.1 CHEMICAL DATABASE)
Baghouse Cost Analysis: ZLD Spray Dryer ‐  Cost Effectiveness to achieve 0.001 gr/dscf

PM/PM10 

Emissions

Emissions Reduction

Control Capital 

Cost

Control Operating 

Cost/yr

Total Annualized 

Costs

Cost Effectiveness

Tons/yr tons/yr $ $/yr $/yr $/Ton PM/PM10

Teflon Fabric Baghouse 

achieving 0.001 gr/dscf 0.102 0.408 $0 4,381 $ 4,381 $ $10,700 Marginal increased energy for increased delta P Assumptions:

Baseline - Baghouse 

controlling to 0.005 gr/dscf 0.5 (proposed) ZLD Spray Dryer

ZLD Spray Dryer ‐  Cost Effectiveness to achieve 0.001 gr/dscf (only considering increased bag costs) EU‐032 Basis (page 

Exhaust Flow dscf/m 2735 One UnitGas to Cloth Ratio cfm/net ft2 6 page I‐22

Net Cloth Requir. net ft2 455.8Gross vs Net cloth ratio 2 page I‐23

Gross cloth requir. total ft2 911.7

Teflon Fabric cost 1998$/ft $ 10.958 page I‐42 (a

Ave. Conv. Fabric 1998$/ft 0.639 $ page I‐42, p

Increased Cost 1998$/ft $ 10.319

Increased Cost 2011$/ft $ 13.348 assume 2% 

Increased cost for bags Total $ 12,169 $ material prIncreased cost for bags Total $ 13,143 $ Price plus 8Changeout Frequency years 3 page I‐46 (a

Average annual incremental cost $ 4,381

Emissions @0.005gr/dscf tons/yr 0.51

Emissions decrease at 0.001 ton/yr 0.408

$ 10,738 $/ton contr

Incremental Cost Analysi

For a baghouse to achieve 0.001 gr/dscf versus co

(increased bag costs only

Control Alternative Other Impacts

Cost Effectiveness of Teflon Bags and

0.001 gr/dscfNote 1: EPA AIR POLLUTION CONTROL COST MANUAL, Sixth Edition, EPA/

Chapter 1 Baghouse and Filters

Note: these costs do not include 

larger baghouses, or other enhan
Incremental Cost Analysis for a Baghouse to achieve 0.001 gr/dscf versus  baghouse at 0.003 gr/dscf

Process Material Handling EU‐011A&B Cost Effectiveness to achieve 0.001 gr/dscf

PM/PM10 

Emissions

Emissions 

Reduction

Control 

Capital Cost

Control 

Operating 

Cost/yr

Total 

Annualized 

Costs

Cost 

Effectiveness

Tons/yr tons/yr $ $/yr $/yr $/Ton

 Baghouse achieving 

0.001 gr/dscf 1.27 2.53 $33,760 $68,027 $72,753 $28,701

Increased energy for 

increased delta P, avoid 

condensation

Baseline - Baghouse 

controlling to 0.003 

gr/dscf

3.8 (proposed)

Incoming Material Handling EU‐012 R&S (each 6000 acfm units) Cost Effectiveness to achieve 0.001 gr/dscf

PM/PM10 

Emissions 

(if 8760 

hr/yr)

Emissions 

Reduction

Control 

Capital Cost

Control 

Operating 

Cost/yr

Total 

Annualized 

Costs

Cost 

Effectiveness

Tons/yr tons/yr $ $/yr $/yr $/Ton

 Baghouse achieving 

0.001 gr/dscf 0.23 0.45 $6,000 $12,090 $12,930 $28,701

Increased energy for 

increased delta P, avoid 

condensation

Baseline - Baghouse 

controlling to 0.003 

gr/dscf

0.68 (proposed)

(Note: unit will not operate 8760 hr/yr, so estimated emissions are overstated and cost/ton controlled will actually be higher.  )

Incoming  Material Handling EU‐012 B‐O, T‐AC (each 1500 acf/m units) Cost Effectiveness to achieve 0.001 gr/dscf

PM/PM10 

Emissions 

(if 8760 

hr/yr)

Emissions 

Reduction

Control 

Capital Cost

Control 

Operating 

Cost/yr

Total 

Annualized 

Costs

Cost 

Effectiveness

Tons/yr tons/yr $ $/yr $/yr $/Ton

 Baghouse achieving 

0.001 gr/dscf 0.06 0.11 $1,500 $12,090 $3,233 $28,701

Increased energy for 

increased delta P, avoid 

condensation

Baseline - Baghouse 

controlling to 0.003 

gr/dscf

0.17 (proposed)

(Note: unit will not operate 8760 hr/yr, so estimated emissions are overstated and cost/ton controlled will actually be higher.  )

Control Alternative Other Impacts

To achieve 0.001 gr/dscf requires several changes to the baghouse design versus a conventional baghouse, all of which are

more expensive.   Based on discussions with vendor, Capital costs increase 10%, operating costs increase 15‐25%, and the air

needs to be heated to avoid condensation on the filter media.  These costs are reflected in below incremental capital and

operating cost estimates.   Baseline Capital and operating costs estimated from EPA's pollution control fact sheet for jet pulse

fabric filters.  Incremental costs based on above vendor estimated factors.

Control Alternative Other Impacts

Control Alternative Other Impacts
Costs for Fabric Filters Upgrade from 0.003 to 0.001 gr/dscf PM10 Performance

Emissions Unit

Air Flow Rate (ACF/M)

0.003

gr/dscf

0.001

gr/dscf Delta

0.003

gr/dscf

0.001

gr/dscf Delta

0.003

gr/dscf

0.001

gr/dscf Delta

Total Capital Investment (Note 1, Note 2) $337,600 $371,360 $33,760 $15,000 $16,500 $1,500 $60,000 $66,000 $6,000Annual Costs

Total Direct Costs Delta Delta Delta

Labor, Maintenance, Replacement Bags, etc. (Note 3, Note 4) $303,840 $349,416 $45,576 $13,500 $15,525 $2,025 $54,000 $62,100 $8,100

Energy to keep air above dew point (prevent condensation) (Note 5) $22,451 $22,451 $998 $998 $3,990 $3,990

Subtotal Annual Direct Costs

Indirect CostsCapital Recovery (Capital * 0.14 assuming 7% interest and 10 yr life) $47,264 $51,990 $4,726 $2,100 $2,310 $210 $8,400 $9,240 $840

Total Annual Costs $351,104 $423,857 $72,753 $15,600 $18,833 $3,233 $62,400 $75,330 $12,930

Emissions (tons/yr) if run 8760hr/yr at design outlet grain loading 3.80 1.27 2.53 0.17 0.06 0.11 0.68 0.23 0.45Incremental Cost Effectiveness ($/Ton to improve control from 0.003 to 0.001 gr/dscf) $28,701 $28,701 $28,701

Note 1 Capital to achieve 0.003 gr/dscf based on $10/acfm conservatively based on lower end of range of costs from EPA Pollution Control Fact Sheet for Jet Pulse Fabric Filters (Sixth Edition, EPA/452/B‐02‐001, January 2002

Note 2 Capital costs estimated to increase at least 10% to achieve 0.001 gr/dscf per vendorNote 3 Annual costs (excluding capital recovery) for 0.003 gr/dscf based on 9$/acfm conservatively based on lower end of range of costs from EPA Fact Sheet for Jet Pulse FiltersNote 4 Annual costs estimated to increase at least 15% to achieve 0.001 gr/dscf per vendorNote 5 Energy costs to keep filtered air above dew point assume 10 degF temperature rise, energy costs $7/MMBtu, air heat capacity of 0.241 btu/lb‐F, and air density 0.075 lb/ft3General Explaintion of Above Calculations: To achieve 0.001 gr/dscf requires several changes to the baghouse design versus a conventional baghouse, all of which are more expensive. Based on discussions with vendor, Capital co

increase 15‐25%, and the air needs to be heated to avoid condensation on the filter media. These costs are reflected in below incremental capital and operating cost estimates. Baseline Capital and operating costs estimated from 

jet pulse fabric filters. Incremental costs based on above vendor estimated factors.

EU‐011a/b

33760

EU‐012 B‐0, T‐AC

1500

EU‐012 R/S

6000
 

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: Indiana Gasification, LLC

Source Location: CR 200 N and Base Road, Rockport, IN 47635

County: Spencer

SIC Code: 4925, 2819

Operation Permit No.: T 147-30464-00060

Operation Permit Issuance Date: Yet to be Issued

Permit Reviewer: Josiah Balogun

Proposed Construction

Indiana Gasification, LLC is proposing to install a new source in Spencer County, the proposed 

facility is designed to convert Illinois Basin coal and petroleum coke into pipeline-quality SNG and 

liquefied CO2. The project will produce up to 48 billion standard cubic feet (Bscf) of SNG annually 

utilizing approximately 3.5 million tons of feedstock. About 39 Bscf will be sold to the Indiana Finance 

Authority (“IFA”) for use by Indiana natural gas consumers with the remaining sold in the natural gas 

marketplace. The project will also produce annually up to approximately 6.43 million tons of liquefied CO2

that will be sold to third parties for use in Enhanced Oil Recovery (“EOR”) where it is estimated to produce 

approximately 10,000,000 barrels per year of additional domestic oil in the Gulf Coast region. 

The facility will have several products in addition to SNG and liquefied CO2. Sulfur compounds in 

the feedstocks will be processed into sulfuric acid, which IG plans to sell into the industrial market. Argon 

will be recovered from the air separation unit and sold to one or more industrial gas companies. Heat 

generated during the gasification process will be used to produce steam for steam turbines that can 

produce approximately 300 MW, primarily to meet on-site power needs. Depending on process and 

ambient conditions, a small amount of power will be exported into or imported from the nearby electrical 

transmission system. Indiana Gasification, LLC is required to undergo a review of control technology for 

pollutants above PSD threshold and significant levels under Federal and State Prevention of Significant 

Deterioration (PSD) regulations.

Indiana Gasification, LLC, located at CR 200 N and Base Road, Rockport, Indiana in Spencer 

County submitted a PSD and Title V operating permit application to IDEM, OAQ on April 20, 2011, 

Requirement for Best Available Control Technology (BACT)

326 IAC 2-2 requires a best available control technology (BACT) review to be performed on the proposed 

New Source review because the new construction has the potential to emit of CO emissions greater than 

100 tons per year, which exceed the PSD threshold and significant levels for this pollutant. The BACT 

review also addressed the following pollutants PM, PM10, PM2.5, SO2, NOx, H2SO4 and GHGs that 

exceeded the PSD significant levels. 
Indiana Gasification LLC Page 2 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

See Appendix A – Emission Calculations – of this TSD for detailed Potential to Emit (PTE) calculations.

Proposed New Emission Units

326 IAC 2-2 requires a best available control technology (BACT) review to be performed on the proposed 

modification for the following emission units:

(A) Incoming solid feedstock materials handling system, transferring material from the barge 

unloading facility and railcar unloading facility to storage piles and day bins, consisting of: 

[Under 40 CFR 60, Subpart Y, the incoming solid feedstock materials handling system, 

transferring material from the barge unloading facility and railcar unloading facility to 

storage piles and day bins are new affected sources.]

(1) One (1) barge unloading to hopper transfer point, to be permitted in 2012, 

nominally rated at 750 tons per hour, identified as EU-012A, with particulate 

emissions controlled by wet suppression.

(2) The following twenty (20) transfer points, each with particulate emissions 

controlled with a dust extraction system or baghouse nominally rated at 1,500 

acfm: 

(a) One (1) barge unloading from the hopper to the belt, identified as EU012B, to be permitted in 2012, with one (1) control device, identified as 

C-012B, exhausting through one (1) vent, identified as S-012B; 

(b) Four (4) barge conveyor transfer points, identified as EU-012C through 

EU-012F, to be permitted in 2012, with four (4) control devices, identified 

as C-012C through C-012F, respectively, exhausting through four (4) 

vents, identified as S-012C through S-012F, respectively; 

(c) Two (2) rail unloading to rail hoppers, identified as EU-012G and EU012H, to be permitted in 2012, with two (2) control devices, identified as 

C-012G through C-012H, respectively, exhausting through two (2) vents, 

identified as S-012G through S-012H, respectively;

(d) Two (2) rail hoppers unloading to the conveyor belts, identified as EU012I and EU-012J, to be permitted in 2012, with two (2) control devices, 

identified as C-012I and C-012J, respectively, exhausting through two 

(2) vents, identified as S-012I through S-012J, respectively; 

(e) One (1) rail conveyor belt to the stacker, identified as EU-012K, to be 

permitted in 2012, with one (1) control device, identified as C-012K, 

exhausting through one (1) vent, identified as S-012K; 

(f) Two (2) stacker belts to the radial stacker, identified as EU-012L and EU012M, to be permitted in 2012, with two (2) control devices, identified as 

C-012L and C-012M, respectively, exhausting through two (2) vents, 

identified as S-012L through S-012M, respectively; 

(g) Two (2) classification towers, identified as EU-012T and EU-012U, to be 

permitted in 2012, with two (2) control devices, identified as C-012T and 

C-012U, respectively, exhausting through two (2) vents, identified as S012T through S-012U, respectively; and 
Indiana Gasification LLC Page 3 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

(h) One (1) classification tower to a day bin, identified as EU-012V, to be 

permitted in 2012, with one (1) control device, identified as C-012V, 

exhausting through one (1) vent, identified as S-012V;

(i) Three (3) truck stations unloading to a truck hopper, identified as EU012Z, EU-012AB and EU-012AC, to be permitted in 2012, with three (3) 

control devices, identified as C-012Z, C-012AB and C-012AC, 

respectively, exhausting through three (3) vents, identified as S-012Z, S012AB and S-012AC, respectively;

(j) One (1) truck hopper unloading to the conveyor belts, identified as EU012AA, to be permitted in 2012, with one (1) control device, identified as 

C-012AA exhausting through one (1) vent, identified as S-012AA; and 

(k) One (1) truck/rail conveyor transfer tower, identified as EU-012Y, to be 

permitted in 2012, with one (1) control device, identified as C-012Y, 

exhausting through one (1) vent, identified as S-012Y;

(3) Two (2) radial stackers to the pile, nominally rated at 3,000 tons per hour each, to 

be permitted in 2012, with particulate emissions controlled by telescoping chutes 

with two (2) fabric filters identified as C-012N and C-012O, exhausting through 

two (2) stacks, identified as S-012N and S-012O.

(4) Two (2) transfer systems consisting of hoppers and conveyor belts transferring 

feed stock from the piles to classification towers, identified as EU-012R and EU012S, to be permitted in 2012, with particulate emissions controlled with two (2) 

dust extraction systems or baghouses, identified as C-012R and C-012S, 

respectively, each nominally rated at 6,000 acfm, exhausting through two (2) 

vents, identified as S-012R and S-012S, respectively.

(5) Two (2) dozer activities on the piles, nominally rated at 1,500 tons per hour each, 

identified as EU-012P and EU-012Q, to be permitted in 2012, with particulate 

emissions controlled by wet suppression. 

(6) Two (2) storage piles with a nominal capacity of 300,000 tons each, identified as 

EU-012W and EU-012X, to be permitted in 2012, with particulate emissions 

controlled by wet suppression and compaction. 

(B) Two (2) process area solid feedstock conveying, storage, and feed bins (main and 

spare), identified as EU-011A and EU-011B, to be permitted in 2012, with particulate 

emissions controlled by two (2) baghouses identified as C-011A and C-011B, 

respectively, each nominally rated at 33,760 dscfm, exhausting through two (2) stacks, 

identified as S-011A and S-011B, respectively. [Under 40 CFR 60, Subpart Y, the 

process area solid feedstock conveying, storage, and feed bins (main and spare) are new 

affected sources.]

(C) One (1) syngas hydrocarbon flare, with a pilot nominally rated at 0.27 MMBtu/hr HHV and 

identified as EU-001, to be permitted in 2012, exhausting through one (1) tip, identified as 

S-001.

(D) One (1) acid gas flare, with a pilot nominally rated at 0.27 MMBtu/hr HHV and identified 

as EU-002, to be permitted in 2012, exhausting through one (1) tip, identified as S-002. 

(E) Two (2) Acid Gas Removal (AGR) Unit vents, identified as EU-007A and EU-007B, to be 

permitted in 2012, with methanol, H2S, COS, and CO emissions controlled by two (2) 
Indiana Gasification LLC Page 4 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

regenerative thermal oxidizers (RTO) identified as C-007A and C-007B, respectively, 

each nominally rated at 38.8 MMBtu/hr HHV fuel input, exhausting through two (2) 

stacks, identified as S-007A and S-007B.

(F) Two (2) Wet Sulfuric Acid (WSA) plant trains, each nominally rated at 800 stpd H2SO4

and identified as EU-015A and EU-015B, to be permitted in 2012, with NOx, SO2, H2SO4

emissions controlled by two (2) selective catalytic reduction (SCR) systems identified as 

C-015-1A and C-015-1B, respectively, and two (2) hydrogen peroxide scrubbers 

identified as C-015-2A and C-015-2B, respectively, exhausting through two (2) stacks, 

identified as S-015A and S-015B respectively. These emissions units also include two 

(2) preheat burners (one for each train), each nominally rated at 35.00 MMBtu/hr HHV, 

venting through the same stacks.

(G) Two (2) natural gas-fired auxiliary boilers, nominally rated at 408 MMBtu/hr HHV each, 

identified as EU-005A and EU-005B, to be permitted in 2012, with NOx emissions 

controlled by ultra-low NOx burners/Flue Gas Recirculation (ULNB/FGR), with both 

boilers exhausting through one (1) stack, identified as S-005. [Under 40 CFR 60, Subpart 

Db, the natural gas-fired auxiliary boilers are new affected sources.]

(H) Five (5) natural gas-fired and SNG fuel-fired gasifier preheat burners, each nominally 

rated with a heat input of 35.00 MMBtu/hr HHV, and identified as EU-008A through EU008E, to be permitted in 2012, exhausting through five (5) vents, identified as S-008A 

through S-008E, respectively. 

(I) One (1) ZLD-Spray Dryer, to be permitted in 2012, nominally rated at 5.6 MMBtu/hr with 

PM emissions controlled by a baghouse identified as C-032, nominally rated at 2,735 

dscfm, and identified as EU-032, with low NOx burners (LNB), exhausting through one 

(1) stack, identified as S-014.

(J) Methanol Tanks:

(1) One (1) Methanol De-Inventory Tank, with a nominal capacity of 700,000 gallons, 

identified as EU-024, to be permitted in 2012, with emissions controlled by a 

vapor recovery system and exhausting through one (1) vent, identified as S-024. 

[40 CFR 60 Subpart Kb]. 

(2) One (1) Fresh Methanol Storage Tank, with a nominal capacity of 332,000 

gallons, identified as EU-025, to be permitted in 2012, with emissions controlled 

by a vapor recovery system and exhausting through one (1) vent, identified as S025. [40 CFR 60 Subpart Kb]

(k) Paved Plant Haul Roads are identified as emissions unit FUG-ROAD. 

(L) Electrical Circuit Breakers (approximately six) containing sulfur hexafluoride (SF6) 

identified as emissions unit FUG-SF6, to be permitted in 2012, with fugitive GHG 

emissions controlled by full enclosure.

(M) Fugitive Equipment Leaks from the gasification, shift conversion, gas cooling, AGR, CO2

compression, WSA, and methanation are identified as emissions units FUG and FUGWSA and will be controlled by a Leak Detection and Repair (LDAR) program.

(N) Two (2) emergency diesel generators, each nominally rated at 1,341 horsepower, 

identified as EU-009A and EU-009B, to be permitted in 2012, exhausting through two (2) 

vents, identified as S-009A and S-009B, respectively. [Under 40 CFR 60, Subpart IIII, 

each, emergency diesel fired generator is considered a new affected source.][Under 40 
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CFR 63, Subpart ZZZZ, each, emergency diesel fired generator is considered a new 

affected source.]

(O) Three (3) firewater pump diesel engines, each nominally rated at 575 horsepower and 

identified as EU-010A through EU-010C, to be permitted in 2012, exhausting through 

three (3) vents, identified as S-010A through S-010C, respectively. [Under 40 CFR 60, 

Subpart IIII, each firewater pump diesel engine is considered a new affected 

source.][Under 40 CFR 63, Subpart ZZZZ, each firewater pump diesel engine is 

considered a new affected source.]

(P) Four (4) rod mill eductor vent stacks, to be permitted in 2012, nominally rated at 180 cfm 

and identified as EU-013A through EU-013D, and exhausting through four (4) vents, 

identified as S-013A through S-013D, respectively. 

(Q) One (1) six (6) cell ASU cooling tower, nominally rated with a circulation rate of 54,960

gpm and identified as EU-016A, to be permitted in 2012, with high efficiency drift/mist 

eliminators, and exhausting through six (6) vents, identified as S-016A-A through 

S-016A-F.

(R) One (1) twenty-four (24) cell main cooling tower, nominally rated with a circulation rate of 

404,700 gpm and identified as EU-016B, to be permitted in 2012, with high efficiency 

drift/mist eliminators, and exhausting through twenty-four (24) vents, identified as S016B-A through S-016B-X.

(S) Two (2) Air Separation Unit (ASU) molecular sieve regeneration train vent, which each 

vent a nominal 187,000 cubic feet per minute during regenerations, identified as EU017A and EU-017B, to be permitted in 2012, exhausting through two (2) vents, identified 

as S-017A andS-017B, respectively.

(T) One (1) slag handling storage pad, to be permitted in 2012, nominally rated at 43 tons 

per hour, identified as EU-034A, with fugitive particulate emissions controlled by wet 

suppression. 

(U) One (1) front-end loader activity on the slag storage pad, to be permitted in 2012, 

nominally rated at 1,440 tons per day, identified as EU-034C, with fugitive particulate 

emissions controlled by wet suppression. 

(V) Six (6) fixed roof sulfuric acid storage tanks, to be permitted in 2012, each with a nominal 

capacity of 866,500 gallons - identified as EU-027A through EU-027F.

(X) One (1) ZLD Inert Gas Vent identified as EU-033, to be permitted in 2012, with mercury 

(Hg) emissions controlled by a sulfided carbon adsorbent identified as C-033, exhausting 

through one (1) stack, identified as S-033.

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 achievable on a case-by-case basis. BACT analysis takes into account the energy, 

environmental, and economic impacts on the source. These reductions may be determined 

through the application of available control techniques, process design, work practices, and 

operational limitations. There will still be air pollution from this project; however, Indiana 

Gasification, LLC will be required to demonstrate that the emissions will be reduced to maximum 

extent.

Federal EPA generally requires an evaluation that follows a “top down” process. In this 

approach, the applicant identifies the best controlled similar source on the basis of controls 
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required by regulation or permit, or controls achieved in practice. The highest level of control is 

then evaluated for technical feasibility. IDEM evaluates BACT based on a "top down" approach. 

The five (5) basic steps of a top-down BACT analysis used by the Office of Air Quality (OAQ) to 

make BACT determinations are listed below:

Step 1: Identify Potential Control Technologies

The first step is to identify potentially “available” control options for each emission unit and for 

each pollutant under review. Available options should consist of a comprehensive list of those 

technologies with a potentially practical application to the emissions unit in question. The list 

should include lowest achievable emission rate (LAER) technologies and controls applied to 

similar source categories. 

Step 2: Eliminate Technically Infeasible Options

The second step is to eliminate technically infeasible options from further consideration. To be 

considered feasible, a technology must be both available and applicable. It is important in this 

step that any presentation of a technical argument for eliminating a technology from further 

consideration be clearly documented based on physical, chemical, engineering, and source 

specific factors related to safe and successful use of the controls. Innovative control means a 

control that has not been demonstrated in a commercial application on similar units. Innovative 

controls are normally given a waiver from the BACT requirements due to the uncertainty of 

actual control efficiency. IDEM evaluates any innovative controls if proposed by the source. 

Indiana Gasification, LLC has not submitted any innovative control technology. Only available 

and proven control technologies are evaluated. A control technology is considered available 

when there are sufficient data indicating that the technology results in a reduction in emissions of 

regulated pollutants.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The third step is to rank the technologies not eliminated in Step 2 in order of descending 

control effectiveness for each pollutant of concern. The ranked alternatives are reviewed in 

terms of control effectiveness (percent pollutant removed). If the highest ranked technology 

is proposed as BACT, it is not necessary to perform any further technical or economic 

evaluation, except, for the environmental analyses.

Step 4: Evaluate the Most Effective Controls and Document the Results

The fourth step begins with an evaluation of the remaining technologies under 

consideration for each pollutant of concern in regards to energy, environmental, and 

economic impacts for determining a final control technology. The highest ranked alternative 

is evaluated for environmental, energy and economic impacts specific to the proposed 

modification. If the analysis determines that the highest ranked control is not appropriate 

as BACT, due to any of the energy, environmental, and economic impacts, then the next 

most effective control is evaluated. The evaluation continues until a technology under 

consideration cannot be eliminated based on adverse energy, environmental, or economic 

impacts. If the highest ranked technology is proposed as BACT, it is not necessary to 

perform any further technical, economic or environmental analysis for a greenhouse gas 

BACT. An Air Quality Impact Analysis would be required for a non-greenhouse gas BACT.

Step 5: Select BACT

The most effective option not eliminated in step 4 is BACT.
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Particulate (PM, PM10 and PM2.5) BACT – Syngas Hydrocarbon Flare (EU-001) 

Step 1: Identify Potential Control Technologies

In evaluating BACT for flare PM, PM10 and PM2.5 emissions, there are limited process and/or 

add-on control alternatives available. Based on a review of the RBLC, as well as other permits 

and sources, the list of potential control and process alternatives includes the following:

(1) Flare design and proper operation;

(2) Process flaring minimization practices (Flare Minimization Plan); and

(3) Flare gas recovery.

Add-on PM, PM10 and PM2.5 controls that may be used on other types of sources, such as 

cyclones, baghouses, ESPs, or scrubbers are not applicable to flares because the outlet exhaust 

of an elevated process flare is not enclosed or contained. Therefore, the emissions or flue gases 

cannot be routed to an add-on control device, and such add-on controls have not been utilized on 

flares.

Step 2: Eliminate Technically Infeasible Options

Each option listed above is evaluated as follows:

Flare design and proper operation

Flare design and operation are key elements in the emissions performance of flares. The IG 

syngas hydrocarbon flare will be designed and operated to be smoke-free, thereby minimizing 

emissions. The fact that all gases vented to the flare will be low molecular weight helps assure 

low particulate creation. The flare’s natural draft will draw in sufficient oxygen to ensure complete 

combustion of the flared gases.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Flare design and proper operation is a technically feasible option for the Syngas 

Hydrocarbon Flare (EU-001) at this source.

Process flaring minimization practices 

To the extent actions can be taken to minimize the volume of gas going to the flare, emissions of 

PM, PM10 and PM2.5 will be less. Flaring minimization practices are feasible and are evaluated in 

the analysis of BACT.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Process flaring minimization practices is a technically feasible option for the Syngas 

Hydrocarbon Flare (EU-001) at this source.

Flare gas recovery 

Flare gas recovery has been implemented at certain types of facilities that produce and use 

internally generated fuel gas streams such as petroleum refineries. However, flare gas recovery 

for this facility is not feasible for the following reasons. 

(1) First, unlike a refinery’s nearly continuous supply of flared gases, flaring at the proposed 

IG facility will be an infrequent occurrence. 

(2) Another significant difference is that the process off gas flows in refineries are frequent 

enough to justify a fuel gas cleanup system and it operates at less than 100 psig. In 

contrast, the IG facility’s syngas flaring will be infrequent and the analogous gas cleanup 

system, the AGR, operates at the much higher pressure of about 900 psig. 
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(3) Another difference is that during some of the IG flaring events, the flared material may 

not be suitable to allow it to be routed to the AGR system or the AGR system itself may 

be in the process of being started up, in an upset, or otherwise not ready to receive the 

flared gases. 

(4) Given the extremely infrequent nature of flared gases being available for recovery, and 

given the lack of a reasonably compatible outlet for recovered gases at the time of flaring 

events, flare gas recovery compression is judged to be not feasible for the IG facility.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Flare gas recovery is not a technically feasible option for the Syngas Hydrocarbon 

Flare (EU-001) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The remaining technically feasible control technologies for flares are:

(1) Proper flare design and operation;

(2) Process flaring minimization practices (Flare Minimization Plan).

These two controls listed above are proposed to be implemented by the source, therefore, no 

ranking of control technologies are needed. 

Flare Design and Operation

The flare design will be inherently efficient at ensuring complete combustion and minimizing PM/

PM10/PM2.5 emissions. The flares will be designed for and operated with no visible emissions, 

except for periods not to exceed 5 minutes during any 2 consecutive hours.

Process flaring minimization practices (Flare Minimization Plan)

There are a number of steps that can be taken in the operation of the facility that will reduce the 

volume of gases flared and thereby the emissions of particulates. During a planned shutdown of 

a gasifier, the contents of the gasifier (gasifier vessel, quench chamber, scrubber vessel) can be 

routed, during initial depressurization, to one of the Wet Sulfuric Acid (WSA) plants. Also, the 

feed rate to the gasifiers can be reduced such that all syngas can be processed through one gas 

treatment train prior to a scheduled gas treatment train outage. This limits the amount of syngas 

that will have to be sent to the syngas hydrocarbon flare. Also, the permittee can investigate the 

“root cause” of malfunction events that cause gases to be sent to the flare and determine whether 

there are additional preventative measures that can be implemented to minimize re-occurrence of 

these events. 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for similar plants. All data in the table is 

based on the information obtained from the permit application submitted by Indiana Gasification, 

LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits 

available at the websites of other permitting agencies.

BACT ID or Permit 

#

Facility Issued 

Date

Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 

147-30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Syngas 

Hydrocarbon 

Flare

(EU-001)

10,400 T

dry

coal/day, 

48

BSCF/yr 

SNG

PM/PM10

3.21 

lbs/hr (3 

hr ave); 

PM2.5 

3.01 

Proper design 

and 

Operation, 

Flare 

Minimization 

Plan
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BACT ID or Permit 

#

Facility Issued 

Date

Process 

Description

Rating 

(TPH)

Limitation Control 

Method

lbs/hr (3 

hr ave),

PSD-LA-742(M1)

Louisiana

Lake Charles 

Cogeneration, LLC

12/30/2010 001 Gasifier 

Flare *

9, 413 T 

coke/day

6.42

lb/hour 

Good Design 

and monitoring 

to ensure the 

presence of a 

flame at the 

flare tip at all 

the time.

Permit V-09-006

Kentucky

Cash Creek 

**Gasification

05/05/2010 Flare * 770 MW

(36.8 

BSCF/yr 

SNG)

0.24 lb/hr 

PM10 at 

startup, 

0.0302 

lb/MMBtu 

standby

(3 hr ave)

No control

V-09-006

Kentucky

Ky Syngas, Kentucky 09/24/2010 Flare 70 Billion 

SCF/yr 

SNG

NA NA

28.0701-PSD

South Dakota

Hyperion Energy 08/20/2009 Flare * 400,000 

bbl/day

None Written Flare 

minimization 

plan, 

compliance 

with 40 CFR 

60.18

081801 AAF 

(Application No. 

07100063) Illinois

Power Holdings of 

Illinois Gasification

10/26/2009 Flare * 13,700 T 

coal per 

day

15.4 

lb/SSM 

event

Flare 

minimization 

plan,

T083-23529-00003

Indiana

Duke Energy 

Indiana -

Edwardsport

01/25/2008 Flare * 618 MW ~

5000 tons 

coal/day

1.5 lb/hr 

during 

peak of 

startup

Must be 

operated with 

a flame 

present at all 

time

NOTE: * These emission units have not been built yet.

**The Cash Creek Permit does not require testing of the emission limit.

The low emissions rate for PM of 0.24 lb/hr in Cash Creek’s permit appears to be an artifact of the 

emissions factor used, not a meaningful difference in flared gases. Cash Creek emissions of other 

criteria pollutants from flaring besides PM are consistent with other facilities. The Cash Creek PM 

estimate is listed in their application as based on “vendor provided” emissions. This may only include 

pilot emissions since AP-42 lists no factor for PM/soot from non-smoking flare (see Ap-42 Chapter 13.5, 

Table 13.5-1). In contrast, IDEM, OAQ conservatively estimated PM using AP-42 natural gas external 

combustion PM factor of 0.0075 lb total PM/mmbtu (AP-42 Chapter 1.4, Table 1.4-2).

Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Syngas 

Hydrocarbon Flare (EU-001):

(1) Comply with the following Flare Minimization Plan to reduce PM, PM10 and PM2.5 emissions 

during startups, shutdowns, and other flaring events.

During a planned shutdown of a gasifier, the permittee shall route the contents of each gasifier

unit (gasifier vessel, quench chamber, scrubber vessel) during initial depressurization to one of 

the Wet Sulfuric Acid (WSA) plants. 
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The permittee shall reduce gasifier feed rates such that all syngas can be processed through one 

gas treatment train prior to a scheduled gas treatment train outage. This limits the amount of 

syngas that will have to be sent to the syngas hydrocarbon flare. 

The permittee shall have written procedures for the above operations and the permittee shall train 

the operators on these procedures.

The permittee shall investigate the “root cause” of malfunction events that cause gases to be sent 

to a flare and determine whether there are additional preventative measures that can be 

implemented to minimize re-occurrence of these events. Such identified measures shall be 

implemented and documented.

(2) Comply with the following best practices for flare design and operation: 

(A) Flares shall be designed for and operated with no visible emissions, except for periods 

not to exceed 5 minutes during any 2 consecutive hours.

(B) Flares shall be operated with a flame present at all times.

(C) Flares shall be continuously monitored to assure the presence of a pilot flame with a 

thermocouple, infrared monitor, or other approved device. 

(3) The Syngas Hydrocarbon Flare PM/PM10 emissions shall not exceed 3.21 lb/hour during startup 

or shutdown, based on a 3-hour average.

(4) Based on the ratio of PM2.5 to total PM from the EPA PM calculator, the Syngas Hydrocarbon 

Flare PM2.5 emissions shall not exceed 3.01 lb/hour during startup or shutdown, based on a 3-

hour 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 PM, PM10 and PM2.5 for Syngas Hydrocarbon Flare (EU-001).

(1) Comply with the following Flare Minimization Plan to reduce PM, PM10 and PM2.5

emissions during startups, shutdowns, and other flaring events.

During a planned shutdown of a gasifier, the permittee shall route the contents of each 

gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during initial 

depressurization to one of the Wet Sulfuric Acid (WSA) plants. 

The permittee shall reduce gasifier feed rates such that all syngas can be processed 

through one gas treatment train prior to a scheduled gas treatment train outage. This 

limits the amount of syngas that will have to be sent to the syngas hydrocarbon flare. 

The permittee shall have written procedures for the above operations and the permittee 

shall train the operators on these procedures.

The permittee shall investigate the “root cause” of malfunction events that cause gases to 

be sent to a flare and determine whether there are additional preventative measures that 

can be implemented to minimize re-occurrence of these events. Such identified 

measures shall be implemented and documented.

(2) Comply with the following best practices for flare design and operation: 
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(A) Flares shall be designed for and operated with no visible emissions, except for 

periods not to exceed 5 minutes during any 2 consecutive hours.

(B) Flares shall be operated with a flame present at all times.

(C) Flares shall be continuously monitored to assure the presence of a pilot flame 

with a thermocouple, infrared monitor, or other approved device. 

(3) The Syngas Hydrocarbon Flare PM/PM10 emissions shall not exceed 3.21 lb/hour during 

startup or shutdown, based on a 3-hour average.

(4) The Syngas Hydrocarbon Flare PM2.5 emissions shall not exceed 3.01 lb/hour during 

startup or shutdown, based on a 3-hour average.

Carbon Monoxide (CO) BACT – Syngas Hydrocarbon Flare (EU-001)

Step 1: Identify Potential Control Technologies

In evaluating BACT for flare CO emissions, there are limited process and/or add-on control 

alternatives available. Based on a review of the RBLC, as well as other permits and sources, the 

list of potential control and process alternatives includes the following:

(1) Flare design and proper operation;

(2) Process flaring minimization practices (Flare Minimization Plan); and

(3) Flare gas recovery.

CO controls that may be used on other types of sources, such as catalytic oxidation are not 

applicable to flares because the outlet exhaust of an elevated process flare is not enclosed or 

contained. Therefore, the emissions cannot be routed to an add-on control device, and such addon controls have not been utilized on flares.

Step 2: Eliminate Technically Infeasible Options

Flare design and proper operation 

Flare design and proper operation– Flare design and operation are key elements in the emissions 

performance of flares. The source is proposing the use of elevated flares which have very high 

combustion efficiency. These are the most commonly used type of flares for emergency release 

control. Elevated flares are capable of extremely effective control of vented gases. 

A potential alternative flare design is an enclosed or ground flare. However, enclosed or ground 

flares are no more effective in destruction. Additionally, enclosed flares are not typically 

considered for high flow rate situations. An evaluation of typical enclosed flare designs indicates 

that the commercial designs that have been demonstrated are for landfill gas (low flow rates and 

low heating value) and upstream oil and gas operations (low flow rates and high heating values). 

These flare designs and controls are not technically feasible for this high gas flow, lower heating 

value application.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flare design and proper operation is a technically feasible option for the Syngas 

Hydrocarbon Flare (EU-001) at this source.
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Process flaring minimization practices (Flare Minimization Plan)

Process flaring minimization practices – To the extent actions can be taken to minimize the 

volume of gas going to the flare, emissions of CO will be less. Flaring minimization practices are 

feasible and are evaluated in the analysis of BACT.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a process flaring minimization practices is a technically feasible option for the Syngas 

Hydrocarbon Flare (EU-001) at this source.

Flare gas recovery

Flare gas recovery – Flare gas recovery has been implemented at some facilities that produce 

and use internally generated fuel gas streams such as petroleum refineries. However, flare gas 

recovery is not feasible for the following reasons. 

(1) First, unlike a refinery’s nearly continuous supply of flared gases, flaring at the proposed 

IG facility will be an infrequent occurrence. 

(2) Another significant difference is that refineries can recover flare gas into their fuel gas 

cleanup system which operates at less than 100 psig. In contrast, the IG facility’s 

analogous gas cleanup system, the AGR, operates at the much higher pressure of about 

900 psig. This would significantly increase the equipment and operating costs of a flare 

gas recovery compressor versus those at refineries. 

 

(3) Another difference is that during some of the IG flaring events, the flared material may 

not be suitable to allow it to be routed to the AGR system or the AGR system itself may 

be in the process of being started up, in an upset, or otherwise not ready to receive the 

flared gases. 

(4) Given the extremely infrequent nature of flared gases being available for recovery, and 

given the lack of a reasonably compatible outlet for recovered gases at the time of flaring 

events, flare gas recovery compression is judged to be not feasible for the IG facility.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Flare Gas Recovery is not a technically feasible option for the syngas hydrocarbon 

flare at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The remaining technically feasible control technologies for flares are:

(1) Flare design and proper operation

(2) Process flaring minimization practices 

These two controls listed above are proposed to be implemented by the source, therefore, no 

ranking of control technologies are needed. 

Flare Design and Operation

The design of the flares is specific for the process stream that will be controlled and includes the following 

considerations:

(1) The flares are designed specifically for use during startup, shutdown or upset conditions; 

therefore, they will be optimized for potential gas flow and gas compositions with ample pilot 

burners to ensure very high combustion efficiency. 

(2) The raw syngas stream contains CO, NH3 and HCN that require oxidation for control. US EPA 

research indicates that 99.5% oxidation efficiency (CO) is achievable in well-designed flares 
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(Flare Efficiency Study, USEPA, EPA-600-83-052, July 1983.) The stream also contains H2S 

and COS that require conversion to SO2, as well as NH3 and HCN that require conversion to N2, 

H2O and CO2 for control. Ninety eight percent (98%) oxidation efficiency of H2S and COS and 

NH3 are reasonable given the oxidation efficiency of the main fuel components H2 and CO. 

(3) In the event of an SNG compressor trip, the flared stream will be predominantly methane and will 

have a constant flow. The flare will destroy the methane with a control efficiency of 98%.

(4) Flare Best Practices:

- Flares will be designed for and operated with no visible emissions, except for periods 

not to exceed 5 minutes during any 2 consecutive hours.

- Flares will be operated with a flame present at all times.

- Flares will be monitored to ensure that operation and maintenance is in conformance 

with the above designs.

- Flares will be operated at all times when emissions are vented to them.

Process flaring minimization practices 

There are a number of steps that can be taken in the operation of the facility that will reduce the volume 

of gases flared and thereby the emissions. During a planned shutdown of a gasifier, the contents of the 

gasifier (gasifier vessel, quench chamber, scrubber vessel) can be vented, during initial depressurization, 

to one of the Wet Sulfuric Acid (WSA) plants. Also, the feed rate to the gasifiers can be reduced such 

that all syngas can be processed through one gas treatment train prior to a scheduled gas treatment train 

outage. This limits the amount of syngas that will have to be sent to the syngas hydrocarbon flare. Also, 

the permittee can investigate the “root cause” of malfunction events that cause gases to be sent to the 

flare and determine whether there are additional preventative measures that can be implemented to 

minimize re-occurrence of these events.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed CO BACT determination along with the existing CO BACT 

determinations for similar plants. All data in the table is based on the information obtained from 

the permit application submitted by Indiana Gasification, LLC, the U.S. EPA RACT/BACT/LAER 

Clearinghouse (RBLC), and electronic versions of permits available at the websites of other 

permitting agencies.

BACT ID or Permit # Facility Issued 

Date

Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Syngas 

Hydrocarbon 

Flare

(EU-001)

10,400 T

dry

coal/day, 

48

BSCF/yr 

SNG

172.4 

lb/hr (3 hr 

ave) 

Proper design 

and 

Operation, 

Flare 

Minimization 

Plan

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, LLC

12/30/2010 001 Gasifier 

Flare *

9, 413 T 

coke/day

44.7 lb/hr Good Design 

and monitoring 

to ensure the 

presence of a 

flame at the 

flare tip at all 

the time.

Permit V-09-006 -

Kentucky

Cash Creek 

Gasification

05/05/2010 Flare * 770 MW

(36.8 

BSCF/yr 

SNG)

352.96

lb/hr CO 

at startup, 

0.3345 

lb/MMBtu 

None
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BACT ID or Permit # Facility Issued 

Date

Process 

Description

Rating 

(TPH)

Limitation Control 

Method

standby

(3 hr ave)

V-09-006 -

Kentucky

Ky Syngas, Kentucky 09/24/2010 Flare 70 Billion 

SCF/yr 

SNG

14,951 

lb/hr 

(8 hr ave) 

604.5 

ton/yr

NA

28.0701-PSD Hyperion Energy 08/20/2009 Flare * 400,000 

bbl/day

None Written Flare 

minimization 

plan, 

compliance 

with 40 CFR 

60.18

081801 AAF 

(Application No. 

07100063)

Power Holdings of 

Illinois Gasification

10/26/2009 Flare * 13,700 T 

coal per 

day

1,279 

lb/SSM 

event

Flare 

minimization 

plan,

T083-23529-00003 Duke Energy 

Indiana -

Edwardsport

01/25/2008 Flare * 618 MW ~ 

5000 tons 

coal/day

898 lb/hr 

during 

peak of 

startup, 

72.9 

tons/yr

Must be 

operated with 

a flame 

present at all 

time

NOTE: * These emission units have not been built yet.

Syngas from gasifier startup and shutdown will contain a high CO and H2 concentration and very low 

concentrations of hydrocarbons. Syngas combustion at the flare tip will be oxidizing CO to CO2 with 

negligible CO generated by combustion of hydrocarbon compounds. CO oxidation will be facilitated by 

the high syngas hydrogen concentration. Hydrogen has a low ignition energy so it will readily ignite and 

completely combust. The resulting uniform high temperature will promote CO combustion resulting in 

99.5% oxidation efficiency.

Proposal: Indiana Gasification, LLC – Rockport, IN

1. Comply with the following Flare Minimization Plan to reduce CO emissions during startups, 

shutdowns, and other flaring events.

During a planned shutdown of a gasifier, the permittee shall route the contents of each 

gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during initial 

depressurization to one of the Wet Sulfuric Acid (WSA) plants. 

The permittee shall reduce gasifier feed rates such that all syngas can be processed 

through one gas treatment train prior to a scheduled gas treatment train outage. This 

limits the amount of syngas that will have to be sent to the syngas hydrocarbon flare. 

The permittee shall have written procedures for the above operations and the permittee 

shall train the operators on these procedures.

The permittee shall investigate the “root cause” of malfunction events that cause gases to 

be sent to a flare and determine whether there are additional preventative measures that 

can be implemented to minimize re-occurrence of these events. Such identified 

measures shall be implemented and documented.

2. Comply with the following flare best practices: 
Indiana Gasification LLC Page 15 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

A. Flares shall be designed for and operated with no visible emissions, except for 

periods not to exceed 5 minutes during any 2 consecutive hours.

B. Flares shall be operated with a flame present at all times.

C. Flares shall be continuously monitored to assure the presence of a pilot flame 

with a thermocouple, infrared monitor, or other approved device. 

3. The Syngas Hydrocarbon Flare CO emissions shall not exceed 172.4 lb/hour during 

startup or shutdown, based on a 3 hour 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 CO for Syngas Hydrocarbon Flare (EU-001).

1. Comply with the following Flare Minimization Plan to reduce CO emissions during 

startups, shutdowns, and other flaring events.

During a planned shutdown of a gasifier, the permittee shall route the contents of each 

gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during initial 

depressurization to one of the Wet Sulfuric Acid (WSA) plants. 

The permittee shall reduce gasifier feed rates such that all syngas can be processed 

through one gas treatment train prior to a scheduled gas treatment train outage. This 

limits the amount of syngas that will have to be sent to the syngas hydrocarbon flare. 

The permittee shall have written procedures for the above operations and the permittee 

shall train the operators on these procedures.

The permittee shall investigate the “root cause” of malfunction events that cause gases to 

be sent to a flare and determine whether there are additional preventative measures that 

can be implemented to minimize re-occurrence of these events. Such identified 

measures shall be implemented and documented.

2. Comply with the following flare best practices: 

A. Flares shall be designed for and operated with no visible emissions, except for 

periods not to exceed 5 minutes during any 2 consecutive hours.

B. Flares shall be operated with a flame present at all times.

C. Flares shall be continuously monitored to assure the presence of a pilot flame 

with a thermocouple, infrared monitor, or other approved device. 

3. The Syngas Hydrocarbon Flare CO emissions shall not exceed 172.4 lb/hour during 

startup or shutdown, based on a 3 hour average.

Sulfur Dioxide (SO2) BACT - Syngas Hydrocarbon Flare (EU-001)

Step 1: Identify Potential Control Technologies

In evaluating BACT for flare SO2 emissions, there are limited process and/or add-on control 

alternatives available. Based on a review of the RBLC, as well as other permits and sources, the 

list of potential control and process alternatives includes the following:

(1) Flare design and proper operation;
Indiana Gasification LLC Page 16 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

(2) Process flaring minimization practices (Flare Minimization Plan); and

(3) Flare gas recovery.

Add-on SO2 controls that may be used on other types of sources, such as scrubbers, are not 

applicable to flares because the outlet exhaust of an elevated process flare is not enclosed or 

contained. Therefore, the emissions cannot be routed to an add-on control device, and such addon controls have not been utilized on flares.

Step 2: Eliminate Technically Infeasible Options

Flare design and proper operation

Flare design and proper operation – Flare design and monitoring are key elements in the 

emissions performance of flares. However, SO2 emissions are merely a function of the amount 

of sulfur compounds in the gases vented to the flare and are unrelated to flare design. Therefore, 

for SO2 purposes, flare design is not considered further.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flare design and proper operation is not a technically feasible option for the Syngas 

Hydrocarbon Flare (EU-001) at this source.

Process flaring minimization practices (Flare Minimization Plan)

To the extent actions can be taken to minimize the volume of gas going to the flare, whatever its 

sulfur content, emissions of SO2 will be less. Also, there are steps that can be taken to reduce 

the sulfur compounds in the gas going to the flare during certain situations. Flaring minimization 

practices are feasible and are evaluated in the analysis of BACT.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Process flaring minimization practices is a technically feasible option for the Syngas 

Hydrocarbon Flare (EU-001) at this source.

Flare gas recovery

Flare gas recovery – Flare gas recovery has been implemented at some facilities that produce 

and use internally generated fuel gas streams such as petroleum refineries. However, flare gas 

recovery for the IG facility is not feasible for the following reasons. 

(1) First, unlike a refinery’s nearly continuous supply of flared gases, flaring at the proposed 

IG facility will be an infrequent occurrence. 

(2) Another significant difference is that refineries can recover flare gas into their fuel gas 

cleanup system which operates at less than 100 psig. In contrast, the IG facility’s 

analogous gas cleanup system, the AGR, operates at the much higher pressure of about 

900 psig. This would significantly increase the equipment and operating costs of a flare 

gas recovery compressor versus those at refineries. 

 

(3) Another difference is that during some of the IG flaring events, the flared material may 

not be suitable to allow it to be routed to the AGR system or the AGR system itself may 

be in the process of being started up, in an upset, or otherwise not ready to receive the 

flared gases. 

(4) Given the extremely infrequent nature of flared gases being available for recovery, and 

given the lack of a reasonably compatible outlet for recovered gases at the time of flaring 

events, flare gas recovery compression is judged to be not feasible for the IG facility.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Flare gas recovery is not a technically feasible option for the Syngas Hydrocarbon 

Flare (EU-001) at this source.
Indiana Gasification LLC Page 17 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The remaining technically feasible control technologies for flares are:

(1) Process flaring minimization practices (Flare Minimization Plan)

The control listed above is proposed to be implemented by the source and only one option has 

been identified, therefore, no ranking of control technologies is needed. 

Process flaring minimization practices 

There are a number of steps that can be taken in the operation of the facility that will reduce the 

volume of gases flared and thereby the emissions of SO2. First, the gasifiers can be started on a 

low sulfur feedstock rather than coal or coke, thereby reducing the sulfur compounds in the gas 

going to the flare during startup. During a planned shutdown of a gasifier, the contents of the 

gasifier (gasifier vessel, quench chamber, scrubber vessel) can be vented, during initial 

depressurization, to one of the Wet Sulfuric Acid (WSA) plants. Also, the feed rate to the 

gasifiers can be reduced such that all syngas can be processed through one gas treatment train 

prior to a scheduled gas treatment train outage. This limits the amount of syngas that will have to 

be sent to the syngas hydrocarbon flare. Also, the permittee can investigate the “root cause” of 

malfunction events that cause gases to be sent to the flare and determine whether there are 

additional preventative measures that can be implemented to minimize re-occurrence of these 

events.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed SO2 BACT determination along with the existing SO2

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by Indiana Gasification, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or Permit 

#

Facility Issued 

Date

Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 

147-30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Syngas 

Hydrocarbon 

Flare

(EU-001)

10,400 T 

dry 

coal/day, 

48 

BSCF/yr 

SNG

0.35 lb/hr (3 hr ave) 

startup on sulfur 

free fuel 85.21 lb/hr 

(3 hr ave) for shut 

down 

Flare 

Minimization 

Plan

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 001 Gasifier 

Flare *

9, 413 T 

coke/day

0.7 lb/hr (applies to 

startup emissions) 

no control

Permit V-09-006 -

Kentucky

Cash Creek 

Gasification

05/05/2010 Flare * 770 MW

(36.8 

BSCF/yr 

SNG)

1.0 lb/hr SO2 at 

startup, 0.0024 

lb/MMBtu standby

None

V-09-006

Kentucky

Ky Syngas, 

Kentucky

09/24/2010 Flare 70 Billion 

SCF/yr 

SNG

33.8 lb/hr 

(24 hr ave)

NA

28.0701-PSD Hyperion 

Energy

08/20/2009 Flare * 400,000 

bbl/day

None Written Flare 

minimization 

plan, 

compliance 

with 40 CFR 

60.18

081801 AAF 

(Application No. 

07100063)

Power 

Holdings of 

10/26/2009 Flare * 13,700 T 

coal per 

day

9510lb/SSM event Flare 

minimization 

plan,
Indiana Gasification LLC Page 18 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID or Permit 

#

Facility Issued 

Date

Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Illinois 

Gasification

T083-23529-00003 Duke Energy

Indiana -

Edwardsport

01/25/2008 Flare * 618 MW ~ 

5000 tons 

coal/day

1396.7 lb/hr during 

peak of startup

Must be 

operated with 

a flame 

present at all 

time

NOTE: * These emission units have not been built yet.

Indiana Gasification and Cash Creek have proposed the use of sulfur-free fuel for startup, resulting in 

minimal SO2 emissions from Startup flaring. The other above facilities, which show significantly higher 

emissions, likely propose to use coal or other sulfur-containing fuel for startup. 

Proposal: Indiana Gasification, LLC – Rockport, IN

1. Comply with the following Flare Minimization Plan to reduce SO2 emissions during 

startups, shutdowns, and other flaring events.

The use of methanol, rather than coal or pet coke, as the feedstock in each gasifier 

during startup conditions requiring syngas flaring, thereby reducing emissions of sulfur 

dioxide at the syngas hydrocarbon flare

During a planned shutdown of a gasifier, routing the contents of each gasifier unit 

(gasifier vessel, quench chamber, scrubber vessel), during initial depressurization to one 

of the Wet Sulfuric Acid (WSA) plants. 

Reduce gasifier feed rates such that all syngas can be processed through one gas 

treatment train prior to a scheduled gas treatment train outage. This limits the amount of 

syngas that will have to be sent to the syngas hydrocarbon flare. 

 

Investigate the “root cause” of malfunction events that cause gases to be sent to a flare 

and determine whether there are additional preventative measures that can be 

implemented to minimize re-occurrence of these events. Such identified measures would 

be implemented and documented.

The SO2 emissions from the Syngas Hydrocarbon Flare during a shutdown event shall not 

exceed 85.21 lb/hr based on a 3-hour average and shall not exceed 255.6 lb per 24 hours. The 

SO2 emissions from the Syngas Hydrocarbon Flare shall not exceed 0.35 lb/hour during startup, 

based on a 3 hour 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 SO2 for Syngas Hydrocarbon Flare (EU-001).

1. Comply with the following Flare Minimization Plan to reduce SO2 emissions during 

startups, shutdowns, and other flaring events.
Indiana Gasification LLC Page 19 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

The permittee will use methanol, rather than coal or pet coke, as the feedstock in each 

gasifier during startup conditions requiring syngas flaring, thereby reducing emissions of 

sulfur dioxide at the syngas hydrocarbon flare

During a planned shutdown of a gasifier, the permittee shall route the contents of each 

gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during initial 

depressurization to one of the Wet Sulfuric Acid (WSA) plants. 

The permittee shall reduce gasifier feed rates such that all syngas can be processed 

through one gas treatment train prior to a scheduled gas treatment train outage. This 

limits the amount of syngas that will have to be sent to the syngas hydrocarbon flare. 

The permittee shall have written procedures for the above operations and the permittee 

shall train the operators on these procedures.

 

The permittee shall investigate the “root cause” of malfunction events that cause gases to 

be sent to a flare and determine whether there are additional preventative measures that 

can be implemented to minimize re-occurrence of these events. Such identified 

measures shall be implemented and documented.

2. The SO2 emissions from the Syngas Hydrocarbon Flare during a shutdown event shall 

not exceed 85.21 lb/hr based on a 3-hour average and shall not exceed 255.6 lb per 24 

hours. The SO2 emissions from the Syngas Hydrocarbon Flare shall not exceed 0.35

lb/hour during startup, based on a 3 hour average.

Nitrogen Oxide (NOX) BACT - Syngas Hydrocarbon Flare (EU-001) 

Step 1: Identify Potential Control Technologies

In evaluating BACT for flare NOx emissions, there are limited process and/or add-on control 

alternatives available. Based on a review of the RBLC, as well as other permits and sources, the 

list of potential control and process alternatives includes the following:

(1) Flare design and proper operation;

(2) Process flaring minimization practices (Flare Minimization Plan); and

(3) Flare gas recovery.

Certain NOx controls that may be used on other types of sources, such as selective catalytic 

reduction (SCR), selective non-catalytic reduction (SNCR), and flue gas recirculation (FGR) are 

not applicable to flares because the outlet exhaust of an elevated process flare is not enclosed or 

contained. Therefore, the emissions or flue gases cannot be routed to an add-on control device, 

and such add-on controls have not been utilized on flares.

Step 2: Eliminate Technically Infeasible Options

Flare design and proper operation

Flare design and proper operation – Flare design and monitoring are key elements in emissions 

performance of flares. However, NOx emissions are not greatly affected by flare design. Instead, 

flare NOx is primarily a function of the amount of material flared and its nitrogen content. The 

open-flame nature of a flare results in inherently good NOx performance and prohibits the use of 

design features used on conventional low NOx or ultra - low NOx gas burners in heaters and 

boilers. There are no flare burner tips available for low NOx performance on a high volume

emergency flare.
Indiana Gasification LLC Page 20 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

The source is proposing the use of elevated flares. These are the most commonly used type of 

flares for emergency release control. Elevated flares are capable of extremely effective control of 

vented gases. A potential alternative flare design is an enclosed or ground flare. However, 

enclosed flares are not typically considered for high flow rate situations. An evaluation of typical 

enclosed flare designs indicates that the commercial designs that have been demonstrated are 

for landfill gas (low flow rates and low heating value) and upstream oil and gas operations (low 

flow rates and high heating values). These flare designs and controls are not technically feasible 

for this high gas flow, lower heating value application.

Therefore, no flare design or operational features were identified as applicable for NOx control. 

Therefore, these flare designs and controls are not technically feasible for this, high gas flow, 

lower heating value application.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Flare design and proper operation is not a technically feasible option for the Syngas 

Hydrocarbon Flare (EU-001) at this source.

Process flaring minimization practices (Flare Minimization Plan)

Process flaring minimization practices – To the extent actions can be taken to minimize the 

volume of gas going to the flare, emissions of NOx will be less. Flaring minimization practices are 

feasible and are evaluated in the analysis of BACT.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Process flaring minimization practices is a technically feasible option for the Syngas 

Hydrocarbon Flare (EU-001) at this source.

Flare gas recovery

Flare gas recovery – Flare gas recovery has been implemented at some facilities that produce 

and use internally generated fuel gas streams such as petroleum refineries. However, flare gas 

recovery for the IG facility is not feasible for the following reasons. 

(1) First, unlike a refinery’s nearly continuous supply of flared gases, flaring at the proposed 

IG facility will be an infrequent occurrence. 

(2) Another significant difference is that refineries can recover flare gas into their fuel gas 

cleanup system which operates at less than 100 psig. In contrast, the IG facility’s 

analogous gas cleanup system, the AGR, operates at the much higher pressure of about 

900 psig. This would significantly increase the equipment and operating costs of a flare 

gas recovery compressor versus those at refineries. 

 

(3) Another difference is that during some of the IG flaring events, the flared material may 

not be suitable to allow it to be routed to the AGR system or the AGR system itself may 

be in the process of being started up, in an upset, or otherwise not ready to receive the 

flared gases. 

(4) Given the extremely infrequent nature of flared gases being available for recovery, and 

given the lack of a reasonably compatible outlet for recovered gases at the time of flaring 

events, flare gas recovery compression is judged to be not feasible for the IG facility.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Flare gas recovery is not a technically feasible option for the Syngas Hydrocarbon 

Flare (EU-001) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The remaining technically feasible control technology for the flare is:
Indiana Gasification LLC Page 21 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

(1) Process flaring minimization practices (Flare Minimization Plan)

Process flaring minimization practices 

There are a number of steps that can be taken in the operation of the facility that will reduce the 

volume of gases flared and thereby the emissions. During a planned shutdown of a gasifier, the 

contents of the gasifier (gasifier vessel, quench chamber, scrubber vessel) can be vented, during 

initial depressurization, to one of the Wet Sulfuric Acid (WSA) plants. Also, the feed rate to the 

gasifiers can be reduced such that all syngas can be processed through one gas treatment train 

prior to a scheduled gas treatment train outage. This limits the amount of syngas that will have to 

be sent to the syngas hydrocarbon flare. Also, the permittee can investigate the “root cause” of 

malfunction events that cause gases to be sent to the flare and determine whether there are 

additional preventative measures that can be implemented to minimize re-occurrence of these 

events.

The only control listed above is proposed to be implemented by the source; therefore, no ranking 

of any control technology is needed. 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed NOx BACT determination along with the existing NOx 

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by Indiana Gasification, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control Method

Draft Permit 

No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Syngas 

Hydrocarbon

Flare

(EU-001)

10,400 T 

coal/day, 

48

BSCF/yr 

SNG

43.09 lb/hr (3 

hr ave) 

Flaring 

Minimization 

Plan

PSD-LA742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 001 Gasifier 

Flare *

9, 413 T 

coke/day

86.28 lb/hr No control.

Permit V-09-

006- Kentucky

Cash Creek 

Gasification

05/05/2010 Flare * 770 MW

(36.8 

BSCF/yr 

SNG)

51.0 lb/hr 

NOx at 

startup (3 hr 

ave)

None

V-09-006

Kentucky

Ky Syngas, 

Kentucky

09/24/2010 Flare 70 Billion 

SCF/yr 

SNG

324.1 lb/hr 

(24 hr ave) 

19.5 tons/yr

NA

28.0701-PSD Hyperion Energy 08/20/2009 Flare * 400,000 

bbl/day

None Written Flare 

minimization plan, 

compliance with 

40 CFR 60.18

081801 AAF 

(Application 

No. 07100063)

Power Holdings of 

Illinois Gasification

10/26/2009 Flare * 13,700 T 

coal per 

day

513 lb per 

SSM event

Flare Minimization 

Plan,

T083-23529-

00003

Duke Energy 

Indiana -

Edwardsport

01/25/2008 Flare * 618 MW ~ 

5000 tons 

coal/day

182.4 lb/hr 

during peak 

of startup, 

22.1 tons/yr

Must be operated 

with a flame 

present at all time

NOTE: * These emission units have not been built yet.

Proposal: Indiana Gasification, LLC – Rockport, IN
Indiana Gasification LLC Page 22 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Process flaring minimization practices 

1. Comply with the following Flare Minimization Plan to reduce NOx emissions during 

startups, shutdowns, and other flaring events.

During a planned shutdown of a gasifier, route the contents of each gasifier unit (gasifier 

vessel, quench chamber, scrubber vessel) during initial depressurization to one of the 

Wet Sulfuric Acid (WSA) plants. 

Reduce gasifier feed rates such that all syngas can be processed through one gas 

treatment train prior to a scheduled gas treatment train outage. This limits the amount of 

syngas that will have to be sent to the syngas hydrocarbon flare. 

 Investigate the “root cause” of malfunction events that cause gases to be sent to a flare 

and determine whether there are additional preventative measures that can be 

implemented to minimize re-occurrence of these events. Such identified measures can 

then be implemented.

2. The Syngas Hydrocarbon Flare NOx emissions shall not exceed 43.09 lb/hour during 

startup or shutdown, based on a 3 hour 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 Syngas Hydrocarbon Flare (EU-001).

1. Comply with the following Flare Minimization Plan to reduce NOx emissions during 

startups, shutdowns, and other flaring events.

During a planned shutdown of a gasifier, the permittee shall route the contents of each 

gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during initial 

depressurization to one of the Wet Sulfuric Acid (WSA) plants. 

The permittee shall reduce gasifier feed rates such that all syngas can be processed 

through one gas treatment train prior to a scheduled gas treatment train outage. This 

limits the amount of syngas that will have to be sent to the syngas hydrocarbon flare. 

The permittee shall have written procedures for the above operations and the permittee 

shall train the operators on these procedures.

 The permittee shall investigate the “root cause” of malfunction events that cause gases to 

be sent to a flare and determine whether there are additional preventative measures that 

can be implemented to minimize re-occurrence of these events. Such identified 

measures shall be implemented and documented.

2. The Syngas Hydrocarbon Flare NOx emissions shall not exceed 43.09 lb/hour during 

startup or shutdown, based on a 3 hour average.

Particulate (PM, PM10 and PM2.5) BACT –Acid Gas Flare (EU-002)

Step 1: Identify Potential Control Technologies

In evaluating BACT for flare PM, PM10 and PM2.5 emissions, there are limited process and/or 

add-on control alternatives available. Based on a review of the RBLC, as well as other permits 

and sources, the list of potential control and process alternatives includes the following:
Indiana Gasification LLC Page 23 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

(1) Flare design and proper operation;

(2) Process flaring minimization practices (Flare Minimization Plan); and

(3) Flare gas recovery.

Add-on PM, PM10 and PM2.5 controls that may be used on other types of sources, such as 

cyclones, baghouses, ESPs, or scrubbers are not applicable to flares because the outlet exhaust 

of an elevated process flare is not enclosed or contained. Therefore, the emissions or flue gases 

cannot be routed to an add-on control device, and such add-on controls have not been utilized on 

flares.

Step 2: Eliminate Technically Infeasible Options

Flare design and proper operation

Flare design and operation are key elements in the emissions performance of flares. The 

source's acid gas flare will be designed and operated to be smoke-free, thereby minimizing 

emissions. The flare’s natural draft will draw in sufficient oxygen to ensure complete combustion 

of the flared gases.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Flare design and proper operation is a technically feasible option for the Acid Gas 

Flare (EU-002) at this source.

Process flaring minimization practices (Flare Minimization Plan)

To the extent actions can be taken to minimize the volume of gas going to the flare, emissions of 

PM/PM10 will be less. Flaring minimization practices are feasible and are evaluated in the 

analysis of BACT.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a process flaring minimization practices is a technically feasible option for the Acid Gas 

Flare (EU-002) at this source.

Flare gas recovery 

Flare gas recovery has been implemented at certain types of facilities that produce and use 

internally generated fuel gas streams such as petroleum refineries. However, flare gas recovery 

for this facility is not feasible for the following reasons. 

(1) First, unlike a refinery’s nearly continuous supply of flared gases, flaring at the Acid Gas 

Flare will be extremely infrequent. No non-emergency flaring is anticipated.

(2) Another issue is that during most upset scenarios of the IG acid gas flares, the WSA itself 

(the normal disposition of the acid gas) is likely either in the process of being started up, 

in an upset, or otherwise not ready to receive the acid gases.

(3) Given the extremely infrequent nature of acid gas flaring, and given the likely lack of a 

reasonably compatible outlet for recovered gases at the time of acid gas flaring events, 

flare gas recovery is judged to be not feasible for the IG facility.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Flare Gas Recovery is not a technically feasible option for the Acid Gas Flare (EU002) at this source.
Indiana Gasification LLC Page 24 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The remaining technically feasible control technologies for flares are:

(1) Flare design and proper operation

(2) Process flaring minimization practices (Flare Minimization Plan)

These two controls listed above are proposed to be implemented by the source, therefore, no 

ranking of control technologies are needed. 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for similar plants. All data in the table is 

based on the information obtained from the permit application submitted by Indiana Gasification, 

LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits 

available at the websites of other permitting agencies.

BACT ID or Permit # Facility Issued 

Date

Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Acid Gas 

Flare

(EU-002)

10,400 T 

dry 

coal/day 

None Proper design 

and 

Operation, 

Flare 

Minimization 

Plan

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, LLC

12/30/2010 002 Acid Gas 

Flare *

9, 413 T 

coke/day

None Good Design 

and monitoring 

to ensure the 

presence of a 

flame at the 

flare tip at all 

the time.

28.0701-PSD Hyperion Energy 08/20/2009 Flare * 400,000 

bbl/day

None Written Flare 

minimization

plan, 

compliance 

with 40 CFR 

60.18

081801 AAF 

(Application No. 

07100063)

Power Holdings of 

Illinois Gasification

10/26/2009 Flare * 13,722 T 

coal per 

day

None Flare 

minimization 

plan,

T083-23529-00003 Duke Energy 

Indiana -

Edwardsport

01/25/2008 Flare * 630 MW None Must be 

operated with 

a flame 

present at all 

time

NOTE: * These emission units have not been built yet.

Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Acid Gas Flare 

(EU-002):

(1) The permittee shall comply with the following Flare Minimization Plan to reduce emissions during 

flaring events. The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional preventative measures that 
Indiana Gasification LLC Page 25 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

can be implemented to minimize re-occurrence of these events. Such identified measures shall 

be implemented and documented.

(2) Comply with the following best practices for flare design and operation: 

(A) Flares shall be designed for and operated with no visible emissions, except for periods 

not to exceed 5 minutes during any 2 consecutive hours.

(B) Flares shall be operated with a flame present at all times.

(C) Flares shall be continuously monitored to assure the presence of a pilot flame with a 

thermocouple, infrared monitor, or other approved device. 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for Acid Gas Flare (EU-002).

1. The permittee shall comply with the following Flare Minimization Plan to reduce emissions 

during flaring events. The permittee shall investigate the “root cause” of malfunction events 

that cause gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of these events. 

Such identified measures shall be implemented and documented

2. Comply with the following flare best practices: 

A. Flares shall be designed for and operated with no visible emissions, except for 

periods not to exceed 5 minutes during any 2 consecutive hours.

B. Flares shall be operated with a flame present at all times.

C. Flares shall be continuously monitored to assure the presence of a pilot flame with a 

thermocouple, infrared monitor, or other approved device. 

Carbon Monoxide (CO) BACT – Acid Gas Flare (EU-002)

Step 1: Identify Potential Control Technologies

In evaluating BACT for flare CO emissions, there are limited process and/or add-on control 

alternatives available. Based on a review of the RBLC, as well as other permits and sources, the 

list of potential control and process alternatives includes the following:

(1) Flare design and Proper Operation;

(2) Process flaring minimization practices (Flare Minimization Plan); and

(3) Flare gas recovery.

CO controls that may be used on other types of sources, such as catalytic oxidation are not 

applicable to flares because the outlet exhaust of an elevated process flare is not enclosed or 

contained. Therefore, the emissions cannot be routed to an add-on control device, and such addon controls have not been utilized on flares.

Step 2: Eliminate Technically Infeasible Options

Flare design and proper operation 

Flare design and proper operation– Flare design and monitoring are key elements in the 

emissions performance of flares. The source is proposing the use of elevated flares which have 

very high combustion efficiency. These are the most commonly used type of flares for 

emergency release control. Elevated flares are capable of extremely effective control of vented 
Indiana Gasification LLC Page 26 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

gases. Maintaining the presence of a flame and operating the flare without visible emissions will 

ensure efficient combustion and minimization of CO emissions.

A potential alternative flare design is an enclosed or ground flare. However, enclosed or ground 

flares are no more effective in destruction. Additionally, enclosed flares are not typically 

considered for high flow rate situations. An evaluation of typical enclosed flare designs indicates 

that the commercial designs that have been demonstrated are for landfill gas (low flow rates and 

low heating value) and upstream oil and gas operations (low flow rates and high heating values). 

These flare designs and controls are not technically feasible for this high gas flow, lower heating 

value application.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of flare design and proper operation is a technically feasible option for the Acid Gas Flare 

(EU-002) at this source.

Process flaring minimization practices (Flare Minimization Plan)

Process flaring minimization practices – To the extent actions can be taken to minimize the 

volume of gas going to the flare, emissions of CO will be less. Flaring minimization practices are 

feasible and are evaluated in the analysis of BACT.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of process flaring minimization practices is a technically feasible option for the Acid Gas 

Flare (EU-002) at this source.

Flare gas recovery

Flare gas recovery – Flare gas recovery has been implemented at some facilities that produce 

and use internally generated fuel gas streams such as petroleum refineries. However, flare gas 

recovery is not feasible for the following reasons. 

(1) First, unlike a refinery’s nearly continuous supply of flared gases, flaring at the Acid Gas 

Flare will be extremely infrequent. No non-emergency flaring is anticipated. 

(2) Another issue is that during most upset scenarios of the IG acid gas flares, the WSA itself 

(the normal disposition of the acid gas) is likely either in the process of being started up, 

in an upset, or otherwise not ready to receive the acid gases.

 

(3) Given the extremely infrequent nature of acid gas flaring, and given the likely lack of a 

reasonably compatible outlet for recovered gases at the time of acid gas flaring events, 

flare gas recovery is judged to be not feasible for the IG facility.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Flare gas recovery is not a technically feasible option for the Acid Gas Flare (EU002) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The remaining technically feasible control technologies for flares are:

(1) Flare design and proper operation

(2) Process flaring minimization practices (Flare Minimization Plan)

These two controls listed above are proposed to be implemented by the source, therefore, no 

ranking of control technologies are needed. 
Indiana Gasification LLC Page 27 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Flare Design and Proper Operation

The design of the IG flares is specific for the process stream that will be controlled and will result 

in high combustion efficiency. Proper operation of the flares will be implemented through the 

following Flare Best Practices:

1. Flares shall be designed for and operated with no visible emissions, except for periods 

not to exceed 5 minutes during any 2 consecutive hours.

2. Flares shall be operated with a flame present at all times.

3. Flares shall be continuously monitored to assure the presence of a pilot flame with a 

thermocouple, infrared monitor, or other approved device. 

Process flaring minimization practices (Flare Minimization Plan)

Because the Acid Gas Flare is expected to be used in upset, malfunction and emergency 

conditions only, measures that might apply to flaring during normal start up and shutdown do not 

apply. Instead, the Flare Minimization Plan to reduce emissions will logically address the conduct 

of a root cause analysis and the consideration of corrective actions whenever flaring occurs. 

Therefore, the measure would be for the permittee to investigate the “root cause” of malfunction 

events that cause gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of these events. 

Such identified measures would be implemented and documented.

 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed CO BACT determination along with the existing CO BACT 

determinations for similar plants. All data in the table is based on the information obtained from 

the permit application submitted by Indiana Gasification, LLC, the U.S. EPA RACT/BACT/LAER 

Clearinghouse (RBLC), and electronic versions of permits available at the websites of other 

permitting agencies.

BACT ID or Permit # Facility Issued 

Date

Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Acid Gas 

Flare

(EU-002)

10,400 T 

dry 

coal/day 

None Flare 

Design/Ops: 

Flare 

Minimization 

Plan

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, LLC

12/30/2010 002 Acid Gas 

Flare *

9, 413 T 

coke/day

None Good Design 

and monitoring 

to ensure the 

presence of a 

flame at the 

flare tip at all 

the time.

28.0701-PSD Hyperion Energy 08/20/2009 Flare * 400,000

bbl/day

None Written Flare 

minimization 

plan, 

compliance 

with 40 CFR 

60.18

081801 AAF 

(Application No. 

07100063)

Power Holdings of 

Illinois Gasification

10/26/2009 Flare * 13,722 T 

coal per 

day

None Flare 

minimization 

plan,

T083-23529-00003 Duke Energy 

Indiana -

Edwardsport

01/25/2008 Flare * 630 MW None Must be 

operated with 

a flame 

present at all 

time
Indiana Gasification LLC Page 28 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

NOTE: * These emission units have not been built yet.

The acid gas flare will generate very little CO because the acid gas will contain less than 1%v COS, CO, 

and hydrocarbons. Small amounts of CO will be produced from partial combustion of COS and 

hydrocarbons. Most of the CO in the acid gas will be combusted to CO2. Flares are inherently efficient at 

combustion and the amount of CO emitted will primarily depend on the amount and duration of the acid 

gases flared. 

Proposal: Indiana Gasification, LLC – Rockport, IN

Process flaring minimization practices 

IG proposes the following as BACT from the Acid Gas Flare vent for CO:

(1) The permittee shall comply with the following Flare Minimization Plan to reduce 

emissions during flaring events. The permittee shall investigate the “root cause” of 

malfunction events that cause gases to be sent to a flare and determine whether there 

are additional preventative measures that can be implemented to minimize re-occurrence 

of these events. Such identified measures shall be implemented and documented.

(2) Comply with the following flare best practices: 

A. Flares shall be designed for and operated with no visible emissions, except for 

periods not to exceed 5 minutes during any 2 consecutive hours.

B. Flares shall be operated with a flame present at all times.

C. Flares shall be continuously monitored to assure the presence of a pilot flame

with a thermocouple, infrared monitor, or other approved device. 

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 Acid Gas Flare (EU-002).

(1) The permittee shall comply with the following Flare Minimization Plan to reduce 

emissions during flaring events. The permittee shall investigate the “root cause” of 

malfunction events that cause gases to be sent to a flare and determine whether there 

are additional preventative measures that can be implemented to minimize re-occurrence 

of these events. Such identified measures shall be implemented and documented.

(2) Comply with the following flare best practices: 

A. Flares shall be designed for and operated with no visible emissions, except for 

periods not to exceed 5 minutes during any 2 consecutive hours.

B. Flares shall be operated with a flame present at all times.

C. Flares shall be continuously monitored to assure the presence of a pilot flame

with a thermocouple, infrared monitor, or other approved device. 

Sulfur Dioxide (SO2) BACT - Acid Gas Flare (EU-002)

Step 1: Identify Potential Control Technologies
Indiana Gasification LLC Page 29 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

In evaluating BACT for flare SO2 emissions, there are limited process and/or add-on control 

alternatives available. Based on a review of the RBLC, as well as other permits and sources, the 

list of potential control and process alternatives includes the following:

(1) Flare design and proper operation;

(2) Process flaring minimization practices (Flare Minimization Plan); and

(3) Flare gas recovery.

Add-on SO2 controls that may be used on other types of sources, such as scrubbers, are not 

applicable to flares because the outlet exhaust of an elevated process flare is not enclosed or 

contained. Therefore, the emissions cannot be routed to an add-on control device, and such addon controls have not been utilized on flares

Step 2: Eliminate Technically Infeasible Options

Flare design and proper operation

Flare design and proper operation – Flare design and monitoring are key elements in the 

emissions performance of flares. However, SO2 emissions are merely a function of the amount 

of sulfur compounds in the gases vented to the flare and are unrelated to flare design. Therefore, 

for SO2 purposes, flare design is not considered further.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Flare design and proper operation is not a technically feasible option for the Acid Gas 

Flare (EU-002) at this source.

Process flaring minimization practices (Flare Minimization Plan)

To the extent actions can be taken to minimize the volume of gas going to the flare, whatever its 

sulfur content, emissions of SO2 will be less. Flaring minimization practices are feasible and are 

evaluated in the analysis of BACT.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of process flaring minimization practices is a technically feasible option for the Acid Gas 

Flare (EU-002) at this source.

Flare gas recovery

Flare gas recovery – Flare gas recovery has been implemented at some facilities that produce 

and use internally generated fuel gas streams such as petroleum refineries. However, flare gas 

recovery for the IG facility is not feasible for the following reasons. 

(1) First, unlike a refinery’s nearly continuous supply of flared gases, flaring at the Acid Gas 

Flare will be extremely infrequent. No non-emergency flaring is anticipated.

(2) Another issue is that during most upset scenarios of the IG acid gas flares, the WSA itself 

(the normal disposition of the acid gas) is likely either in the process of being started up, 

in an upset, or otherwise not ready to receive the acid gases.

(3) Given the extremely infrequent nature of acid gas flaring, and given the likely lack of a 

reasonably compatible outlet for recovered gases at the time of acid gas flaring events, 

flare gas recovery is judged to be not feasible for the IG facility.
Indiana Gasification LLC Page 30 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Flare Gas Recovery is not a technically feasible option for the Acid Gas Flare (EU002) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The remaining technically feasible control technologies for flares are:

(1) Process flaring minimization practices (Flare Minimization Plan) 

Because the Acid Gas Flare is expected to be used in upset, malfunction and emergency 

conditions only, measures that might apply to flaring during normal start up and shutdown do not 

apply. Instead, the Flare Minimization Plan to reduce SO2 emissions will logically address the 

conduct of a root cause analysis and the consideration of corrective actions whenever flaring 

occurs. Therefore, the measure would be for the permittee to investigate the “root cause” of 

malfunction events that cause gases to be sent to a flare and determine whether there are 

additional preventative measures that can be implemented to minimize re-occurrence of these 

events. Such identified measures would be implemented and documented.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed SO2 BACT determination along with the existing SO2

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by Indiana Gasification, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or Permit 

#

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 

147-30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Acid Gas Flare

(EU-002)

10,400 T

dry 

coal/day 

None Flare

Minimization 

Plan

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 002 Acid Gas 

Flare *

9, 413 T 

coke/day

None No control

28.0701-PSD Hyperion Energy 08/20/2009 Flare * 400,000 

bbl/day

None Written Flare 

minimization 

plan, 

compliance 

with 40 CFR 

60.18

081801 AAF 

(Application No. 

07100063)

Power Holdings 

of Illinois 

Gasification

10/26/2009 Flare * 13,722 T 

coal per 

day

None Flare 

minimization 

plan,

T083-23529-00003 Duke Energy 

Indiana -

Edwardsport

01/25/2008 Flare * 630 MW None Must be 

operated with 

a flame 

present at all 

time

NOTE: * These emission units have not been built yet.

Proposal: Indiana Gasification, LLC – Rockport, IN

Process flaring minimization practices 
Indiana Gasification LLC Page 31 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

The Source is proposing the following as BACT from the Acid Gas Flare vents for SO2:

The permittee shall comply with the following Flare Minimization Plan to reduce emissions during 

flaring events. The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional preventative measures that 

can be implemented to minimize re-occurrence of these events. Such identified measures shall 

be implemented and documented.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for SO2 for Acid Gas Flare (EU-002).

The permittee shall comply with the following Flare Minimization Plan to reduce emissions during 

flaring events. The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional preventative measures that 

can be implemented to minimize re-occurrence of these events. Such identified measures shall 

be implemented and documented.

Nitrogen Oxide (NOX) BACT - Acid Gas Flare (EU-002)

Step 1: Identify Potential Control Technologies

In evaluating BACT for flare NOx emissions, there are limited process and/or add-on control 

alternatives available. Based on a review of the RBLC, as well as other permits and sources, the 

list of potential control and process alternatives includes the following:

(1) Flare design and proper operation;

(2) Process flaring minimization practices (Flare Minimization Plan); and

(3) Flare gas recovery.

Certain NOx controls that may be used on other types of sources, such as selective catalytic 

reduction (SCR), selective non-catalytic reduction (SNCR), and flue gas recirculation (FGR) are 

not applicable to flares because the outlet exhaust of an elevated process flare is not enclosed or 

contained. Therefore, the emissions or flue gases cannot be routed to an add-on control device, 

and such add-on controls have not been utilized on flares.

Step 2: Eliminate Technically Infeasible Options

Flare design and proper operation

Flare design and proper operation – Flare design and monitoring are key elements in emissions 

performance of flares. However, NOx emissions are not greatly affected by flare design. Instead, 

flare NOx is primarily a function of the amount of material flared and its nitrogen content. The 

open-flame nature of a flare results in inherently good NOx performance and prohibits the use of 

design features used on conventional low NOx or ultra low NOx gas burners in heaters and 

boilers. There are no flare burner tips available for low NOx performance on a high volume 

emergency flare.

The source is proposing the use of elevated flares. These are the most commonly used type of 

flares for emergency release control. Elevated flares are capable of extremely effective control of 

vented gases. A potential alternative flare design is an enclosed or ground flare. However, 

enclosed flares are not typically considered for high flow rate situations. An evaluation of typical

enclosed flare designs indicates that the commercial designs that have been demonstrated are 

for landfill gas (low flow rates and low heating value) and upstream oil and gas operations (low 
Indiana Gasification LLC Page 32 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

flow rates and high heating values). These flare designs and controls are not technically feasible 

for this high gas flow, lower heating value application.

Therefore, no flare design or operational features were identified as applicable for NOx control. 

Therefore, these flare designs and controls are not technically feasible for this, high gas flow, 

lower heating value application.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of flare design and proper operation is not a technically feasible option for the Acid Gas 

Flare (EU-002) at this source.

Process flaring minimization practices (Flare Minimization Plan)

Process flaring minimization practices – To the extent actions can be taken to minimize the 

volume of gas going to the flare, emissions of NOx will be less. Flaring minimization practices are 

feasible and are evaluated in the analysis of BACT.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Process flaring minimization practices is a technically feasible option for the Acid Gas 

Flare (EU-002) at this source.

Flare gas recovery

Flare gas recovery – Flare gas recovery has been implemented at certain types of facilities that 

produce and use internally generated fuel gas streams such as petroleum refineries. However, 

acid gas flare gas recovery for this facility is not feasible for the following reasons. 

(1) First, unlike a refinery’s nearly continuous supply of flared gases, flaring at the Acid Gas 

Flare will be extremely infrequent. No non-emergency flaring is anticipated.

(2) Another issue is that during most upset scenarios of the IG acid gas flares, the WSA itself 

(the normal disposition of the acid gas) is likely either in the process of being started up, 

in an upset, or otherwise not ready to receive the acid gases.

(3) Given the extremely infrequent nature of acid gas flaring, and given the likely lack of a 

reasonably compatible outlet for recovered gases at the time of acid gas flaring events, 

flare gas recovery is judged to be not feasible for the IG facility.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Flare gas recovery practices is not a technically feasible option for the Acid Gas 

Flare (EU-002) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Process flaring minimization practices (Flare Minimization Plan)

Because the Acid Gas Flare is expected to be used in upset, malfunction and emergency 

conditions only, measures that might apply to flaring during normal start up and shutdown do not 

apply. Instead, the Flare Minimization Plan to reduce emissions will logically address the conduct 

of a root cause analysis and the consideration of corrective actions whenever flaring occurs. 

Therefore, the measure would be for the permittee to investigate the “root cause” of malfunction 

events that cause gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of these events. 

Such identified measures would be implemented and documented.
Indiana Gasification LLC Page 33 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed NOx BACT determination along with the existing NOx 

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by Indiana Gasification, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control Method

Draft Permit 

No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Acid Gas 

Flare

(EU-002)

10,400 T 

coal/day 

None Process Flaring 

Minimization 

Practices

PSD-LA742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 002 Acid 

Gas Flare *

9, 413 T 

coke/day

None No control

28.0701-PSD Hyperion Energy 08/20/2009 Flare * 400,000 

bbl/day

None Written Flare 

minimization plan, 

compliance with 40 

CFR 60.18

081801 AAF 

(Application 

No. 07100063)

Power Holdings of 

Illinois Gasification

10/26/2009 Flare * 13,722 T 

coal per 

day

None Flare Minimization 

Plan,

T083-23529-

00003

Duke Energy 

Indiana -

Edwardsport

01/25/2008 Flare * 630 MW None Must be operated 

with a flame present 

at all time

NOTE: * These emission units have not been built yet.

Proposal: Indiana Gasification, LLC – Rockport, IN

Process flaring minimization practices 

The source is proposing the following as BACT from the Acid Gas Flare vent for NOx:

The permittee shall comply with the following Flare Minimization Plan to reduce emissions during 

flaring events. The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional preventative measures that 

can be implemented to minimize re-occurrence of these events. Such identified measures shall 

be implemented and documented.

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 Acid Gas Flare (EU-002).

The permittee shall comply with the following Flare Minimization Plan to reduce emissions during 

flaring events. The permittee shall investigate the “root cause” of malfunction events that cause 

gases to be sent to a flare and determine whether there are additional preventative measures that 

can be implemented to minimize re-occurrence of these events. Such identified measures shall 

be implemented and documented.
Indiana Gasification LLC Page 34 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Particulate Matter (PM/PM10/PM2.5) BACT – Auxiliary Boilers (EU-005 A and B)

Step 1: Identify Potential Control Technologies

Emissions of particulate matter (PM), particulate matter with an aerodynamic diameter less than 

or equal to ten (10) micrometers (PM10) and particulate matter with an aerodynamic diameter less 

than or equal to 2.5 micrometers (PM2.5) are generally controlled with add-on control equipment 

designed to capture the emissions prior to the time they are exhausted to the atmosphere. The 

available technologies include:

(1) Cyclones;

 (2) Wet Scrubbers;

(3) Electrostatic Precipitators (ESP); and 

(4) Fabric Filter Dust Collectors (Baghouses).

The choice of which technology is most appropriate for a specific application depends upon 

several factors, including particle size to be collected, particle loading, stack gas flow rate, stack 

gas physical characteristics (e.g., temperature, moisture content, presence of reactive materials), 

and desired collection efficiency.

If add-on control technology is not feasible, an alternate method of control may be implemented. 

Alternate Control Methods:

One or more alternate methods of control may be considered when they are more cost-effective

than add-on controls or when add-on control technology may not be feasible. For this source, the 

following alternate control methods were evaluated:

(1) Fuel Specifications – Clean Burning Fuel; and

(2) Good Combustion Practices / Combustion Controls.

Step 2: Eliminate Technically Infeasible Options

(a) Cyclone 

Cyclones mechanically separate particulates through centrifugal and inertial forces, by 

forcing a particulate-laden stream to change direction, with the particles falling out as 

they hit the walls of a typically cone-shaped cyclone. Cyclones are used in applications 

with waste gas pollutant loadings of 1 – 100 gr/scf. Since the concentration of PM/PM10

in the Auxiliary Boilers exhaust is very low (~0.005 gr/cf), a cyclone would not be effective 

at this source.

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the cyclone is not a technically feasible option for the Auxiliary Boilers 

(EU-005A/B) at this source.

(b) Wet Scrubber 

Wet scrubbers use a flow or spray of liquid in a tower to contact particulate-laden exhaust 

gas stream and absorb particles in the liquid, either physically, or in combination with a 

chemical reaction. Wet scrubbing towers are not typically used for fine particulate 

applications because high liquid to gas ratios are required, and typical pollutant loadings 

are 250-10,000 ppmv. (EPA-452/F-03-016, Air Pollution Control Technology Fact Sheet 

for Spray Tower Wet Scrubber). For fine particulate control, a venturi scrubber can be 
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Permit Reviewer: Josiah Balogun

used but typical loadings for such a scrubber are 0.1-50 grains/scf (EPA-452/F-03-017, 

Air Pollution Control Technology Fact Sheet for Venturi Scrubber). Since the 

concentration of this stream (0.005 gr/cf) is already orders of magnitude lower, a wet 

scrubber would not achieve any appreciable particulate control. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the wet scrubber is not a technically feasible option for the Auxiliary 

Boilers (EU-005A/B) at this source.

(c) Electrostatic Precipitators

An electrostatic precipitator is a particulate control device that uses electrical forces to 

move particles entrained in an exhaust stream onto collector plates. The design inlet 

pollutant loadings for an ESP typically range from 0.5 – 50 gr/ft3

. Since the pollutant 

concentration of the Auxiliary Boilers exhaust is already orders of magnitude lower, an 

ESP would not achieve any appreciable additional particulate control. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the electrostatic precipitator is not a technically feasible option for the 

Auxiliary Boilers (EU-005A/B) at this source.

(d) Fabric Filter Dust Collectors (Baghouse) 

A baghouse uses a fabric filter to capture particles as the gas stream flow through the 

fabric. Typical baghouse outlet design concentration is 0.005 gr/cf and relies, in part on 

the filtering properties of a layer of particulate that first accumulates on the filter media. 

Since the emission concentration from this source is already extremely low, a baghouse 

would not be effective in providing further particulate control. Therefore, a baghouse is 

rejected as an ineffective and not technically feasible control device for this source.

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the fabric filter dust collector is not a technically feasible option for the 

Auxiliary Boilers (EU-005A/B) at this source.

(e) Fuel Specifications – Clean Burning Fuel: Clean burning natural gas and SNG have a 

very low potential for generating PM, PM10 and PM2.5 emissions. 

(f) Good Combustion Practices / Combustion Controls: Good combustion practices as 

well as operation and maintenance of the Auxiliary Boilers to keep them in good working 

order per the manufacturer's specifications will minimize PM, PM10 and PM2.5 emissions. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of PM, PM10 and PM2.5 resulting from the 

operation of the Auxiliary Boilers (EU-005A/B). 

(1) Fuel Specifications – Clean Burning Fuel

(2) Good Combustion Practices / Combustion Controls
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Permit Reviewer: Josiah Balogun

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination for IG along with 

the existing PM, PM10 and PM2.5 BACT determinations for similar plants. All data in the table is 

based on the information obtained from the permit application submitted by Indiana Gasification, 

LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits 

available at the websites of other permitting agencies.

BACT ID or Permit 

#

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 

147-30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Auxiliary 

Boiler (EU005A/B)

408 

MMBtu/hr

0.0075 

lb/MMBtu

(filterable and 

condensable)

Use of 

clean 

burning 

gaseous 

fuel

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, LLC

12/30/2010 Auxiliary 

Boiler *

938.30MM

Btu/hour

6.99 pounds 

per hour 

Good design 

and proper 

operation

2001-205-CM1 

PSD

Energetix Lawton 

Energy Cogen Facility

12/12/2006 Auxiliary 

Boiler *

None None None

07-00534 Biomass Energy 

South Point Biomass 

Generation

04/04/2006 Auxiliary 

Boiler *

247 

MMBtu/Hr

0.007 

lb/MMBtu

None

PSD TX - 943 Corpus Christi 

Energy Center

02/04/2000 (3) Auxiliary 

Boilers 1-3, 

AB1-3 *

315 

MMBtu/Hr

0.005 

lb/MMBtu

(filterable)

None

97019 Grays Ferry Cogen 

Partnership

03/21/2001 Auxiliary 

Boiler , 

Natural Gas*

1119 

MMBtu/Hr

0.005 

lb/MMBtu 

(filterable)

Good 

Combustion 

Practices

Compliance determination is unknown for all these sources.

NOTE: * These emission units have not been built yet.

The PM, PM10 and PM2.5 emissions from the Auxiliary Boilers result only from fuel combustion 

(natural gas or SNG). Total PM/PM10 emissions from the boilers are estimated to be 5.62 tons/yr 

with the particulate concentration in the exhaust of only about 0.005 grains/dscf. This low 

concentration renders add-on controls infeasible as described below. 

Generally add-on controls for PM, PM10 and PM2.5 are not applied to a combustion source firing 

only clean gaseous fuel. This is because the PM, PM10 and PM2.5 emissions are already 

extremely low (~0.005 gr/dscf ), and are below levels that would be feasible for effective use of 

conventional particulate control devices (which are used on solid fuel fired combustion devices or 

other large particulate sources.) 

A search of the USEPA’s RACT/BACT/LAER Clearinghouse database did not indicate control 

technologies for PM/ PM10/PM2.5 emissions from gas-fired boilers. The combustion of clean 

gaseous fuel is inherently low in particulate (PM, PM10 and PM2.5) emissions and add-on controls 

are not feasible. Gas fired sources have expected emissions of 0.0075 lb/MMBtu PM, PM10 and 

PM2.5 (based on the AP-42 emission factor of 7.6 lb/MMscf for natural gas). The Corpus Christi 

Energy Center and Grays Ferry Cogen Partnership have BACT limits that appear lower but these 

limits are on the emissions of filterable PM only. AP-42 filterable PM is at this level, so these 

figures are consistent with the IG proposal.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for Auxiliary Boilers (EU-005A/B).
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Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

The PM, PM10 and PM2.5 emissions from the Auxiliary Boilers (EU-005A/B) operation shall not 

exceed 0.0075 lb per MMBtu, each through the use of natural gas or SNG.

Carbon Monoxide (CO) BACT – Auxiliary Boilers (EU-005 A and B)

Step 1: Identify Potential Control Technologies

Emissions of carbon monoxide (CO) are generally controlled by oxidation. CO control 

technologies include:

(a) Regenerative thermal oxidation; 

(b) Catalytic oxidation; 

(c) Flares

(d) Combustion Control

If add-on control technology is not feasible, an alternate method of control may be implemented. 

Step 2: Eliminate Technically Infeasible Options

Regenerative Thermal Oxidizers

The thermal oxidizer has a stabilized flame 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 gas containing CO is heated from 

its inlet temperature to its ignition temperature (It is the temperature at which the combustion 

reaction rate (and consequently the energy production rate) exceeds the rate of heat losses, 

thereby raising the temperature of the gases to some higher value). Thus, any CO/air mixture will 

ignite if its temperature is raised to a sufficiently high level. The CO-containing mixture ignites at 

some temperature between the preheat temperature and the reaction temperature. The ignition 

occurs at some point during the heating of a waste stream. The mixture continues to react as it 

flows through the combustion chamber.

Most thermal units are designed to provide no more than 1 second of residence time to the waste 

gas with typical temperatures of 1,200 to 2,000o

F. Once the unit is designed and built, the 

residence time is not easily changed, so that the required reaction temperature becomes a 

function of the particular gaseous species and the level of control. 

Regenerative Thermal Oxidizer consists 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 to the combustion 

chamber outlet temperature. The process flows are then switched, feeding the inlet stream to the 

hot bed. This cyclic process affords 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 auxiliary fuel savings to make such a system economical. 
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Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a regenerative thermal oxidizer is a technically feasible option for the Auxiliary Boilers

at this source.

Catalytic Oxidizers

Catalytic oxidation is also a widely used control technology to control pollutants where the waste 

gas is passed through a flame area and then through a catalyst bed for complete combustion of 

the waste in the gas. This technology is typically applied for destruction of organic vapors, 

nevertheless it is considered as a technology for controlling CO emissions. A catalyst is an 

element or compound that speeds up a reaction at lower temperatures (compared to thermal 

oxidation) without the catalyst undergoing change itself. Catalytic oxidizers operate at 650°F to 

1000°F and approximately require 1.5 to 2.0 ft3 of catalyst per 1000 standard ft3 per gas flow rate. 

Emissions from some emission units may contain significant amount of particulates. These 

particulates can poison the catalyst resulting in the failure of catalytic oxidation.

For some fuels, such as coal and residual oil, contaminants would likely be present in such 

concentrations so as to foul catalysts quickly thereby making such systems infeasible due to the 

need to constantly replace catalyst materials. In addition, the use of oxidation catalysts on units 

with high sulfur fuels can also result in the creation of sulfuric acid mist through the conversion of 

SO2 to SO3 and subsequent combination with moisture in the exhaust gas. The use of an 

oxidation catalyst to control carbon monoxide emissions is feasible for gas fired units because the 

fuel is a low sulfur fuel with relatively low concentrations of other contaminants, such as metals.

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

The low heating value of the Auxiliary Boiler exhaust is too low for flaring. As there are insufficient 

organics in this vent stream to support combustion, use of a flare would require a significant 

addition of supplementary fuel. Therefore, a secondary impact of the use of flare for this stream 

would be the creation of additional emissions from burning supplemental fuel, including NOx. 

Flares have not been utilized or demonstrated as a control device for CO from this type of highvolume process stream. In addition, the flare would have no additional control versus the thermal 

oxidizers. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flare is a technically infeasible option for the Auxiliary Boilers at this source.

Combustion Control 

Because CO is essentially a by-product of incomplete or inefficient combustion, combustion 

control constitutes the primary mode of reduction of CO emissions. This type of control is 

appropriate for any type of fuel combustion source. Combustion process controls involve 

combustion chamber designs and operating practices that improve the oxidation process and 

minimize incomplete combustion. CO emissions result from the incomplete combustion of carbon 

and organic compounds. Factors affecting CO emissions include firing temperatures, residence 

time in the combustion zone and combustion chamber mixing characteristics. Combustion control 

is a technically feasible control option for the Auxiliary Boilers.
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Permit Reviewer: Josiah Balogun

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Regenerative Thermal Oxidizer - 99 % destruction efficiency

(2) Oxidation Catalyst - 75 % destruction efficiency

(3) Combustion Control

CO emissions are generally controlled by good combustion practices (GCP). Therefore, the 

source has proposed good combustion practices as the BACT for the CO emissions of these 

boilers.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed CO BACT determination along with the existing CO BACT 

determinations for similar plants. All data in the table is based on the information obtained from 

the permit application submitted by Indiana Gasification, LLC, the U.S. EPA RACT/BACT/LAER 

Clearinghouse (RBLC), and electronic versions of permits available at the websites of other 

permitting agencies.

BACT ID or Permit 

#

Facility Issued 

Date

Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 

147-30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Auxiliary 

Boiler (EU005A/B)

408 

MMBtu/hr

0.036 

lb/MMBtu 

based on 3 -

hour average

Good 

Combustion 

Practices

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Auxiliary

Boiler *

938.30MM

Btu/hour

33.78 pounds 

per hour 

Good design 

and proper 

operation

2001-205-CM1 PSD Energetix Lawton 

Energy Cogen 

Facility

12/12/2006 Auxiliary 

Boiler *

None None None

07-00534 Biomass Energy 

South Point 

Biomass 

Generation

04/04/2006 Auxiliary 

Boiler *

247 

MMBtu/Hr

0.11 

lb/MMBtu

None

PSD TX - 943 Corpus Christi 

Energy Center

02/04/2000 (3) 

Auxiliary 

Boilers 1-3, 

AB1-3 *

315 

MMBtu/Hr

0.09 

lb/MMBtu

None

97019 Grays Ferry 

Cogen 

Partnership

03/21/2001 Auxiliary 

Boiler , 

Natural 

Gas*

1119 

MMBtu/Hr

0.04 

lb/MMBtu 

Good 

Combustion 

Practices

Compliance determination is unknown for all these sources.

NOTE: * These emission units have not been built yet.

Carbon monoxide emissions from boilers are the result of incomplete fuel combustion. A search 

of the USEPA’s RACT/BACT/LAER Clearinghouse indicates the use of good combustion practice 

and engineering design for gas-fired boilers is the best control for CO emissions. Natural gas (or 

SNG) combustion is already so efficient that add-on oxidation controls for such sources are not 

feasible (not to mention the limited-use nature of the IG boilers).

It is theoretically possible that further CO reductions could be achieved with an add-on thermal or 

catalytic oxidizer. However, any add-on oxidation control technology would not be cost effective 

since the CO concentration in this stream is already low. A rough perspective of costs for an addon oxidizer can be obtained using cost ranges from US EPA’s Air Pollution Control Technology 
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Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Fact Sheet for Regenerative Incinerators (EPA-452/F-03-021). It lists the range of annualized 

cost of a regenerative thermal oxidizer as $8 - $33 per cfm and a regenerative catalytic oxidizer 

as $11 to $41 per cfm. Since the Auxiliary Boilers have a large exhaust flow rate (although low 

concentration of CO), we have conservatively assumed that the use of an oxidizer might have a 

cost at the lowest cost per cfm presented in this range ($8/cfm). Based on the emissions rate of 

about 27 tons/yr CO and an exhaust flow rate of 280,000 cfm, the cost-effectiveness of further 

controlling CO with an add-on oxidizer is conservatively estimated to be at least $80,000/ton. 

This clearly exceeds BACT for this type of CO source. 

Costs Effectiveness for use of RTO on Auxiliary Boiler Exhaust

Control 

Alternative

CO 

Emissions

Emissions 

Reduction

Control 

Capital 

Cost

Control 

Operating 

Cost

Total 

Annualized 

Costs

Cost 

Effectiveness Other 

Tons/yr tons/yr $ $/yr $/yr $/Ton CO Impacts

RTO 0.27 26.73 $9,800,000 $1,120,000 $2,240,000 $83,800

Additional

energy 

use & CO 

Emissions

Baseline 27.0 (proposed)

Note: Source exhaust (cfm) = 280000

Thermal Oxidation Costs based on lower - range costs for control from USEPA fact sheet for regenerative Thermal 

Oxidizer (EPA-452/F-03-021)

$35.0 capital cost $/cfm

$4.0 operating cost $/cfm

$8.0 Annualized $/cfm

99% Control efficiency for CO (Assumed) 

In addition, the use of a thermal or catalytic oxidizer for CO control would require the use of a 

significant amount of supplemental fuel (to heat the exhaust gas to the required operating 

temperature to achieve destruction). This supplemental fuel firing will create additional 

combustion pollutant emissions (particularly NOx) which will at least partially offset any benefits of 

additional CO control. 

Therefore, BACT for this source for CO is proposed to be good engineering design of the boilers 

at 0.036 lb/MMBtu (based on vendor provided data of boiler operation using natural gas or SNG). 

This emissions performance is consistent with the lowest CO emission rates from any gas fired 

boilers found in the RBLC of this size regardless of operating rates. 

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-005A/B).

The CO emissions from the Auxiliary Boilers (EU-005A/B) operation shall not exceed 0.036 

lb/MMBtu based on a 3 - hour average through the use of good combustion practices.

Sulfur Dioxide (SO2) BACT - Auxiliary Boilers (EU-005 A and B)

Step 1: Identify Potential Control Technologies

Emissions of Sulfur dioxide (SO2) from Auxiliary Boilers are generally controlled by; 

1. Flue Gas Desulfurization
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Permit Reviewer: Josiah Balogun

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 SO2 emissions from the Auxiliary Boilers.

Flue Gas Desulfurization (FGD) System (Wet or Dry Scrubber)

A flue gas desulfurization system (FGD) is comprised either of a spray dryer that uses lime as a 

reagent followed by particulate control or a wet scrubber that uses limestone as a reagent. FGD 

is an established technology. The concentration of SO2 in the exhaust gas is the driving force for 

the reaction between SO2 and the reagent. Therefore, removal efficiencies are significantly 

reduced with lower inlet concentrations of SO2. FGD systems are listed in the RBLC as BACT for 

sources higher concentrations of SO2 emissions. Even though the SO2 concentrations in the 

exhaust gases are very low, and the airflow volume is large, the scrubbing systems are 

technically feasible. Wet scrubbing FGD system is considerably cheaper than dry scrubbing.

Caustic scrubbing system that controls emissions by 90% at a higher inlet concentration is a 

proven system which operates at or below 2500°F.

Add-on SO2 controls such as flue gas desulfurization described above, a common control in coal 

combustion, is not feasible for further control of SO2 emissions because of inherently low SO2

emissions from a clean gas fired boiler. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flue gas desulfurization system (FGD) is not a technically feasible option for the 

Auxiliary Boilers at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

there is no viable technology for controlling the SO2 emissions resulting from the Auxiliary 

Boilers.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed SO2 BACT determination along with the existing SO2

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by Indiana Gasification, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued 

Date

Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 

147-30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Auxiliary 

Boiler (EU005A/B)

408 

MMBtu/hr

0.0006 

lbs/MMBtu

Use of 

natural gas 

or SNG 

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Auxiliary 

Boiler *

938.30MM

Btu/hour

0.28 pounds 

per hour 

Fueled by 

natural gas or 

substitute 

natural gas 

(SNG)

2001-205-CM1 

PSD

Energetix Lawton 

Energy Cogen 

Facility

12/12/2006 Auxiliary 

Boiler *

None None None

07-00534 Biomass Energy 

South Point 

Biomass 

04/04/2006 Auxiliary 

Boiler *

247 

MMBtu/Hr

0.60 lb/MMscf None
Indiana Gasification LLC Page 42 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued 

Date

Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Generation

PSD TX - 943 Corpus Christi 

Energy Center

02/04/2000 (3) 

Auxiliary 

Boilers 1-3, 

AB1-3 *

315 

MMBtu/Hr

0.093 

lb/MMBtu

Fuel sulfur 

content limits

97019 Grays Ferry 

Cogen 

Partnership

03/21/2001 Auxiliary 

Boiler , 

Natural 

Gas*

1119 

MMBtu/Hr

0.008 

lb/MMBtu 

Good 

Combustion 

Practices, low 

sulfur fuel

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for SO2 for Auxiliary Boilers (EU-005A/B).

The SO2 emissions from the Auxiliary Boilers (EU-005A/B) operation shall not exceed 0.0006 

lb/MMBtu and shall use only natural gas or SNG.

Nitrogen Oxide (NOX) BACT - Auxiliary Boilers (EU-005 A and B)

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) Flue Gas Recirculation (FGR)

(d) Low NOx Burner (LNB)

(e) Low NOx Burner with Flue Gas Recirculation (LNB/FGR) or Ultra Low NOx Burner 

(UNLB)

Add-on control technologies and combustion control approaches are discussed below.

Step 2: Eliminate Technically Infeasible Options

Selective Catalytic Reduction (SCR)

Selective Catalytic Reduction (SCR) process involves the mixing of anhydrous or aqueous 

ammonia vapor with flue gas and passing the mixture through a catalytic reactor to reduce NOX

to N2 and water. Under optimal conditions, SCR has a removal efficiency up to 90% when used 

on steady state processes. The efficiency of removal will be reduced for processes that are not 

stable or require frequent changes in the mode of operation.

The most important factor affecting SCR efficiency is temperature. SCR can operate in a flue gas 

window ranging from 500°F to 1100°F, although the optimum temperature range depends on the 

type of catalyst and the flue gas composition. Temperatures below the optimum decrease catalyst 

activity and allow NH3 to slip through; above the optimum range, ammonia will oxidize to form 
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Permit Reviewer: Josiah Balogun

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%. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

selective catalytic reduction (SCR) is a technically feasible option for the Auxiliary Boilers at this 

source.

Selective Non-Catalytic Reduction (SNCR)

With selective non-catalytic reduction (SNCR), NOX is selectively removed by the injection of 

ammonia or urea into the flue gas at an appropriate temperature window of 1600°F to 2000°F 

and without employing a catalyst. Similar to SCR without a catalyst bed, the injected chemicals 

selectively reduce the NOX to molecular nitrogen and water. This approach avoids the problem 

related to catalyst fouling but the temperature window and reagent mixing residence time is

critical for conducting the necessary chemical reaction. 

At the proper temperature, urea decomposes to produce ammonia which is responsible for NOX

reduction. At a higher temperature, the rate of a competing reaction for the direct oxidation of 

ammonia that actually forms NOx becomes significant. At a lower temperature, the rates of NOX

reduction reactions become too slow resulting in urea slip (i.e. emissions of unreacted urea).

Optimal implementation of SNCR requires the employment of an injection system that can 

accomplish thorough reagent/gas mixing within the temperature window while accommodating 

spatial and production rate temperature variability in the gas stream. The attainment of maximum 

NOx control performance therefore requires that the furnace exhibit a favorable opportunity for the 

application of this technology relative to the location of the reaction temperature range and steady 

operation within that temperature window. Given the standby nature of the operation of these 

boilers steady operating conditions cannot be expected.

.

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 Auxiliary 

Boilers at this source.

Low NOx Burner (LNB)

Using LNB can reduce formation of NOx through careful control of the fuel-air mixture during 

combustion. Control techniques used in LNBs includes staged air, and staged fuel, as well as 

other methods that effectively lower the flame temperature. 

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 installation to another. Typical reductions range 

from 40% - 50% but under certain conditions, higher reductions are possible.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a low NOx burner is a technically feasible option for the Auxiliary Boilers at this source.

Flue Gas Recirculation (FGR)

Recirculating a portion of the flue gas to the combustion zone can lower the peak flame 

temperature and result in reduced thermal NOx production. The flue gas recirculation (FGR) can 

be highly effective technique for lowering NOx emissions from burners and it's relatively 

inexpensive to apply. Most of the early FGR work was done on boilers, and investigators found 

that recirculating up to 25% of the flue gases through the burner could lower NOx emissions to as 

little as 25% of their normal levels. FGR lowers NOx emissions in two ways; the cooler, relatively 

inert, recirculated flue gases act as heat sink, absorbing heat from the flame and lowering peak 

flame temperatures and when mixed with the combustion air, recirculated flue gases lower the 

average oxygen content of the air, starving the NOx-forming reactions for one of the needed 

ingredients.
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Permit Reviewer: Josiah Balogun

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Flue Gas Recirculation (FGR) is a technically feasible option for the Auxiliary Boilers 

at this source.

FGR and LNB Combined

LNB and FGR can be used in combination to achieve a higher overall emissions reduction.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of FGR with LNB is a technically feasible option for the Auxiliary Boilers at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Selective Catalytic Reduction — (up to 90% NOx Reduction)

(2) Low NOx Burner with Flue Gas Recirculation (LNB/FGR)-- (55% — 60% NOx Reduction)

(3) Low NOx Burner (LNB) — (40% — 50% NOx Reduction)

(4) Flue Gas Recirculation (FGR) — (25% NOx Reduction)

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed NOx BACT determination along with the existing NOx

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by Indiana Gasification, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 

147-30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Auxiliary 

Boiler (EU005A/B)

408 

MMBtu/hr

0.0125 

lb/MMBtu 

based on 

24-hr block 

daily 

average

basis

Ultra Low 

NOx Burner

with FGR

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Auxiliary 

Boiler *

938.30MM

Btu/hour

0.035 

lb/MMBtu

Ultra low 

NOx Burners 

or SCR

2001-205-CM1 

PSD

Energetix Lawton 

Energy Cogen 

Facility

12/12/2006 Auxiliary 

Boiler *

None 0.036 

lb/MMBtu

Dry - low 

NOx Burners

07-00534 Biomass Energy 

South Point 

Biomass 

Generation

04/04/2006 Auxiliary 

Boiler *

247 

MMBtu/Hr

0.06 

lb/MMBtu 

Using

Natural 

Gas

PSD TX - 943 Corpus Christi 

Energy Center

02/04/2000 (3) Auxiliary 

Boilers 1-3, 

AB1-3 *

315 

MMBtu/Hr

0.06 

lb/MMBtu

None

97019 Grays Ferry 

Cogen 

Partnership

03/21/2001 Auxiliary 

Boiler , 

Natural Gas*

1119 

MMBtu/Hr

0.10 

lb/MMBtu 

Low NOx 

Burners

Compliance determination is unknown for all these sources.
Indiana Gasification LLC Page 45 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

NOTE: * These emission units have not been built yet.

The following table summarizes the estimated cost and emissions reduction benefit for installing 

SCR on these boilers. The estimated cost-effectiveness shown below of more than $80,000/ton 

NOx reduced is too high to be considered reasonable. Consequently, SCR is rejected as BACT.

SCR Costs Analysis for IG Auxiliary Boilers

(Cost/Benefit Total for both Boilers)

Control 

Alternative

Emissions

Emissions 

Reduction

Control 

Capital 

Cost

Control 

Operatin

g Cost/yr

Total 

Annualiz

ed Costs

Cost 

Effectivene

ss Other 

Tons/yr tons/yr $ $/yr $/yr $/Ton NOx Impacts

SCR 4.96 3.97 $1,468,000 $115,700 $321,300 $80,900

Insignif. 

Ammonia 

Emissions

ULNB/FGR 8.94 (proposed)

Note: SCR costs shown are further detailed in Appendix C.

NSPS Subpart Db requires these boilers to achieve NOx performance of at least 0.1 lb 

NOx/MMBtu. A review of the RBLC for limited-use auxiliary boilers indicates the use of Low-NOx

(LNB) or Ultra Low NOx burners (ULNB) with NOx performance ranging from 0.035 to 0.10 lb 

NOx/MMBtu. No further controls are indicated in the RBLC for limited-use auxiliary boilers. 

Standard low NOx burners for the proposed boilers would achieve approximately 0.035 

lb/MMBtu. This level of performance is consistent with BACT determination for other similar 

boilers – and should be sufficient as BACT. However, Indiana Gasification proposes to go 

beyond BACT by using Ultra Low-NOx burners with Flue Gas Recirculation (ULNB/FGR) capable 

of achieving 0.0125 lb/MMBtu. This level is one eighth the applicable NSPS standard and is 

better than the limits set for other auxiliary boilers. This is also the lowest NOx emissions rate for 

any recently permitted boilers of this size regardless of operating rates. 

Even further reduction of NOx is possible using selective catalytic reduction (SCR) which can be 

designed to reduce NOx to approximately 0.0069 lb/MMBtu (5 ppm in the exhaust). SCR is 

sometimes specified as BACT for very large heaters where the economies of scale help justify 

the costs. However, SCR is not cost effective for the auxiliary boilers, in part because the boilers 

will only have an annual utilization of 20% or less (decreasing the emissions reduction value of 

SCR). There is also a technical difficulty associated with SCR use for this boiler. In auxiliary 

service the boiler will need to ramp up and shutdown quickly and SCR performance will be 

compromised during those significant swings in load. 

(a) Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for NOx from the proposed Auxiliary Boilers

(EU-005):

Based on this analysis, BACT for the auxiliary boilers is proposed to be NOx emissions 

performance of 0.0125 lb/MMBtu to be assessed on a 24-hr block daily average basis. . 

IG anticipates using ULNB with FGR to achieve this level. The NOx emissions rate will be 

demonstrated with a continuous emissions monitor installed for NSPS Db. 
Indiana Gasification LLC Page 46 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for NOx for Auxiliary Boilers (EU-005A/B).

The NOx emissions from the Auxiliary Boilers (EU-005A/B) operation shall not exceed 0.0125 

lb/MMBtu based on a 24-hour block daily average basis and shall use Ultra Low NOx burners

with FGR.

Particulate Matter (PM/PM10/PM2.5) BACT – Regenerative Thermal Oxidizer (RTO) on the Acid Gas 

Removal Unit Vents (AGR) (EU-007A and B)

The acid gas removal (AGR) units remove CO2 from the syngas and it will normally be

compressed to a liquid and sold. Whenever it is instead vented, it will be sent to one of two 

Regenerative Thermal Oxidizers (RTOs), one serving each AGR. The RTOs will oxidize small 

amounts of CO, COS, methane and VOCs (methanol) in the vent gas. Because the heating 

value of the CO2 stream to be vented is very low (it contains mostly non-combustible CO2), a 

supplemental fuel is required to maintain the RTO at its operating temperature. As such, the 

RTO is both a control device and a source of emissions. 

Although their emissions are combined out the same vent point, a separate BACT analysis has 

been prepared for the RTO and the AGR. The BACT analysis for the RTO addresses SO2, NOx 

and PM from this vent, none of which are present in the AGR vent upstream of the RTO. The 

RTO BACT also addresses GHG emissions. The separate BACT analysis for the AGR vent also 

covers GHG’s, addresses CO and includes a non-PSD State-only VOC BACT analysis. The 

AGR vent stream upstream of the RTO is responsible for the vast majority. A separate BACT 

analysis for the AGR is not presented for SO2, NOx or PM, none of which are present in this 

stream upstream of RTO. 

Step 1: Identify Potential Control Technologies

The particulate matter emissions from the AGR vent result from the fuel combustion in the 

regenerative thermal oxidizer (RTO). The use of clean burning natural gas or SNG will minimize 

these emissions.

From some processes, emissions of particulate matter (PM) and particulate matter with an 

aerodynamic diameter less than or equal to ten (10) micrometers (PM10) and PM2.5 are controlled 

with add-on control equipment designed to capture the emissions prior to the time they are 

exhausted to the atmosphere. 

(1) Cyclones;

 (2) Wet Scrubber;

(3) Electrostatic Precipitators (ESP);

(4) Fabric Filter Dust Collectors (Baghouses); 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.

If add-on control technology is not feasible, an alternate method of control may be implemented. 
Indiana Gasification LLC Page 47 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Alternate Control Methods:

One or more alternate methods of control may be considered when more cost-effective than 

add-on controls or when add-on control technology may not be feasible. For the particulate 

emission sources at the proposed IG Plant, the following alternate control methods were 

evaluated:

(1) Fuel Specifications – Clean Burning Fuel; and

(2) Good Combustion Practices / Combustion Controls.

Step 2: Eliminate Technically Infeasible Options

(a) Cyclone 

Cyclones mechanically separate particulates through centrifugal and inertial forces, by 

forcing a particulate-laden stream to change direction, with the particles falling out as 

they hit the walls of a typically cone-shaped cyclone. Cyclones are used in applications 

with waste gas pollutant loadings of 1 – 100 gr/scf. Since the concentration of PM/PM10

in the RTO vent stream is very low (~0.001 gr/acf), a cyclone would not be effective in 

this plant.

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the cyclone is not a technically feasible option for the Acid Gas Removal 

Unit Vents (EU-007A/B) at this source.

(b) Wet Scrubber

Wet scrubbers use a flow or spray of liquid in a tower to contact a particulate-laden 

exhaust gas stream and absorb particles in the liquid, either physically, or in combination 

with a chemical reaction. Wet scrubbing towers are not typically used for fine particulate 

applications because high liquid to gas ratios are required, and typical pollutant loadings 

are 250-10,000 ppmv. (EPA-452/F-03-016, Air Pollution Control Technology Fact Sheet 

for Spray Tower Wet Scrubber). For fine particulate control, a venturi scrubber can be 

used but typical loadings for such a scrubber are 0.1-50 grains/scf (EPA-452/F-03-017, 

Air Pollution Control Technology Fact Sheet for Venturi Scrubber). Since the 

concentration of this stream (0.001 gr/acf) is already orders of magnitude lower, a wet 

scrubber would not achieve any appreciable particulate control. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the wet scrubber is not a technically feasible option for the Acid Gas 

Removal Unit Vents (EU-007A/B) at this source.

(c) Electrostatic Precipitators (ESP)

An electrostatic precipitator is a particulate control device that uses electrical forces to 

move particles entrained in an exhaust stream onto collector plates. The design inlet 

pollutant loadings for an ESP typically range from 0.5 – 50 gr/ft3

. Since the pollutant 

concentration on this stream is already orders of magnitude lower, an ESP would not 

achieve any appreciable additional particulate control. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the electrostatic precipitator is not a technically feasible option for the 

Acid Gas Removal Unit Vents (EU-007A/B) at this source.

(d) Fabric Filter Dust Collectors (Baghouses)

A baghouse uses a fabric filter to capture particles as the gas stream flows through the 

fabric. Typical baghouse outlet design concentration is 0.005 gr/scf. Since the emission 

concentration from this source is already less than this level, a baghouse would not be 

effective in providing further particulate control. 
Indiana Gasification LLC Page 48 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the fabric filter dust collector is not a technically feasible option for the 

Acid Gas Removal Unit Vents (EU-007A/B) at this source.

(e) Fuel Specifications – Clean Burning Fuel: Clean burning natural gas or SNG fuel such 

as syngas and natural gas have a very low potential for generating PM/PM10/PM2.5 

emissions. This technology is technically feasible and will be ranked for evaluation as 

BACT for controlling PM, PM10 and PM2.5 emissions from the Acid Gas Removal Unit 

RTO Vents (EU-007A/B).

(f) Good Combustion Practices / Combustion Controls: Good combustion practices as 

well as operation and maintenance of the Acid Gas Removal Unit Vents to keep them in 

good working order per the manufacturer's specifications will minimize PM, PM10 and 

PM2.5 emissions. This technology is technically feasible and will be ranked for evaluation 

as BACT for controlling PM emissions from Acid Gas Removal Unit Vents.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The above control technologies have been identified for control of PM, PM10 and PM2.5 resulting 

from operation of the AGR Regenerative Thermal Oxidizer (EU-007A/B). 

(1) Fuel Specifications – Clean Burning Fuel

(2) Good Combustion Practices 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for similar plants. All data in the table is 

based on the information obtained from the permit application submitted by Indiana Gasification, 

LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits 

available at the websites of other permitting agencies.

BACT ID or Permit # Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Acid Gas 

Removal 

Unit Vents 

(EU-007A/B)

10,400 T 

dry 

coal/day 

0.58 

pounds 

per hour

Use of clean 

burning 

gaseous fuel, 

Good 

Combustion 

Practices

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Acid Gas 

Recovery 

Vents *

9,413 T/D 0.36 

lb/MMBtu 

and 0.3 

lb/hr

None

Permit V-09-006 Cash Creek 

Gasification

05/05/2010 Acid Gas 

Recovery 

Vents *

770 MW None None

28.0701-PSD Hyperion Energy 08/20/2009 Acid Gas 

Recovery 

Vents *

400,000 

bbl/day

11.2 

lb/hour, 

0.13 

lb/long T S 

loaded

None

081801 AAF 

(Application No. 

07100063)

Power Holdings 

of Illinois 

Gasification

10/26/2009 Acid Gas 

Recovery 

Vents *

13,722 T 

coal per 

day

0.5 

pounds 

per hr and 

None
Indiana Gasification LLC Page 49 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID or Permit # Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

1.9 tpy

T083-23529-00003 Duke Energy 

Indiana -

Edwardsport

01/25/2008 Acid Gas 

Recovery 

Vents *

630 MW 0.0075 

lb/MMBtu 

None

NOTE: * These emission units have not been built yet.

The PM, PM10 and PM2.5 emissions from the AGR vent result from the supplemental fuel 

combustion (natural gas or SNG) in the Regenerative Thermal Oxidizer (RTO) that is used to 

control CO, H2S, COS and methanol in the AGR unit vent stream. The vented material 

(upstream of the RTO) contains no PM/PM10. The RTO itself has inherently low PM/PM10

emissions due to the use of only clean fuel in the RTO. In addition, the use of an RTO rather 

than a conventional Thermal Oxidizer further limits PM/PM10 emissions because it recovers heat 

and preheats the exhaust before it enters the combustion chamber. In this way it lessens the 

amount of supplemental fuel fired. 

No add-on controls for PM, PM10 and PM2.5 have ever been applied to a similar RTO or other 

gas-only fired combustion source. The lack of post-combustion controls on an RTO is due to the 

fact that emissions are already at extremely low concentrations (~0.001 gr/acf ), and, therefore, 

they are below levels that would be feasible using conventional particulate control devices that 

are normally used on solid fuel fired combustion devices or other large particulate sources. 

Only one similar source was located in the RBLC (Lake Charles Gasification), however, the 

above comparison also includes the recently permitted and similar SNG facilities. The table 

shows their recently permitted PM, PM10 and PM2.5 limits. The emission rates for PM, PM10 and 

PM2.5 are comparable to other permitted emission of these similar facilities. 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for AGR Regenerative Thermal Oxidizer (EU007A/B).

The PM, PM10 and PM2.5 emissions from the AGR Regenerative Thermal Oxidizer (EU-007A/B)

operation shall not exceed 0.29 pounds per hour, each, through the use of clean burning gaseous 

fuel and good combustion practices.

Carbon Monoxide (CO) BACT - AGR Regenerative Thermal Oxidizer (EU-007A and B)

The carbon monoxide emissions from the AGR vent result primarily from the CO in the AGR vent 

stream. Only a very small portion of the CO emissions come from supplemental fuel combustion 

in the RTO, which uses clean burning natural gas or SNG. Carbon Monoxide BACT for this 

stream is discussed under the Acid Gas Recovery Vent BACT analysis. 
Indiana Gasification LLC Page 50 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Sulfur Dioxide (SO2) BACT - AGR Regenerative Thermal Oxidizer (EU-007A and B)

The acid gas removal (AGR) units remove CO2 from the syngas and it will normally be

compressed to a liquid and sold. Whenever it is instead vented, it will be sent to one of two 

Regenerative Thermal Oxidizers (RTOs), one serving each AGR. The AGR vent stream 

upstream of the RTO does not contain SO2, but the RTOs will oxidize small amounts of COS and

H2S in the vent gas. The sulfur dioxide emissions from the AGR vent result almost entirely from 

the oxidation of the sulfur that was in the AGR vent stream. Because the heating value of the 

CO2 stream to be vented is very low, supplemental natural gas or NSG fuel will be used and will 

also contribute a very small amount of SO2 to the emissions. However, less than 1% of the total 

SO2 in this vent comes from the supplemental fuel. 

Step 1: Identify Potential Control Technologies

Emissions of sulfur dioxide (SO2) from this vent are primarily controlled by the inherent efficient 

design of the Rectisol acid gas removal system which results in a CO2 stream with very low sulfur 

content. The use of an add-on scrubber was also considered.

Step 2: Eliminate Technically Infeasible Options

Rectisol

The IG facility will use the Rectisol process for removal of acid gases (principally H2S and COS) 

from the syngas stream and subsequent conversion to sulfuric acid product. SO2 emissions from 

the AGR vent are a function of the effectiveness of the AGR system in separating these sulfurbearing streams out of the syngas and out of the captured CO2 stream. 

Physical solvent systems such as Selexol and Rectisol provide the highest level of control for this 

type of source. The IG selected Rectisol system is considered to be as good or better at removing 

sulfur bearing compounds than Selexol. Less effective technologies include solvent scrubbing, 

such as amine systems. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Rectisol system is a technically feasible option for the Acid Gas Removal Unit Vents 

(EU-007A/B) at this source

Scrubber

The SO2 emissions from the AGR vent are at very low levels as a result of the inherent design of 

the Rectisol Acid Gas Removal (AGR) system which is very effective in absorbing sulfur 

compounds and separating them into the acid gas stream sent to the wet sulfuric acid unit. The 

small amount of residual sulfur contained in the AGR vent stream, in the form of H2S and COS, is 

converted in the thermal oxidizer to SO2 emissions. The SO2 emitted at the AGR Vent 

corresponds to only about 2 ppmv. This is too low a level of emissions for further scrubbing to be 

effective, as described below. As a result, there is no feasible add-on control for SO2 from the 

AGR.

The EPA Air Pollution Control Technology Fact Sheet for Flue Gas Desulfurizatoin (FGD) - Wet, 

Spray Dry and Dry Scrubbers (EPA-452/F03-034) states that these scrubbers are typically only 

installed on coal- and oil-fired units, with an inlet pollutant loading of approximately 250 - 2000 

ppm SO2. In the very best cases, wet scrubbing systems reduce SO2 to single digit ppm levels. 

However, the AGR vent is already 2 ppm SO2 (because it is the product of an extremely effective 

sulfur scrubbing system – Rectisol). Because further exhaust gas sulfur scrubbing systems 

would not be effective or applicable as an add-on control in this service, scrubbing is not 

considered feasible for this source.
Indiana Gasification LLC Page 51 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a scrubber is not a technically feasible option for the Acid Gas Removal Unit Vents 

(EU-007A/B) at this source

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The most effective method for control of SO2 emissions resulting from operation of the Acid Gas 

Removal Unit Vents at this source is the use of a Rectisol to convert acid gases to sulfuric acid.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed SO2 BACT determination along with the existing SO2

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by Indiana Gasification, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or Permit # Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Acid Gas 

Removal 

Unit Vents 

(EU-007A/B)

10,400 T 

dry 

coal/day 

6.33

pounds per 

hour based 

on 24 hour

block daily

average

Rectisol, 

Proper 

design of 

AGR and 

Limit on 

Sulfur to 

RTO

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Acid Gas 

Recovery 

Vents *

9,413 T/D 22.92 

pounds per 

hour 

Rec tisol

Permit V-09-006 Cash Creek 

Gasification

05/05/2010 Acid Gas 

Recovery 

Vents *

770 MW 43.2 pounds 

per hour

Selexol

28.0701-PSD Hyperion 

Gasification - South 

Dakota

08/20/2009 Acid Gas 

Recovery 

Vents *

400,000 

bbl/day

114.2pounds 

per hour

Rec tisol

081801 AAF 

(Application No. 

07100063)

Power Holdings 

of Illinois 

Gasification

10/26/2009 Acid Gas 

Recovery 

Vents *

13,722 T 

coal per 

day

11.0 pounds 

per hr and 

48.3 tpy

Rec tisol

T083-23529-00003 Duke Energy 

Indiana -

Edwardsport

01/25/2008 Acid Gas 

Recovery 

Vents *

630 MW 19.86 

pounds per 

hour

None

NOTE: * These emission units have not been built yet.

Proper design of the Rectisol Unit will keep the concentration of sulfur compounds in the CO2 stream to 

the RTO to very low levels. The small residual sulfur in the AGR vent stream, in the form of H2S and 

COS, is converted in the thermal oxidizer to SO2 emissions. IG expects potential SO2 emissions from the 

AGR vent of 6.33 lb/hr and 26.27 tpy (total for both AGR vents). The very low level of sulfur compounds 

expected in the AGR Vent corresponds to only about 2 ppmv SO2 in the exhaust. This is too low for 

further scrubbing to be effective and there is no feasible add-on control for SO2 from the AGR. 

The proposed performance level for the IG facility compares very favorably with other facilities. The 

Rectisol unit at the IG facility has the lowest mass emission rate of SO2 compared to the above similar 

permitted facilities. Given the relative size of each facility and the proposed SO2 emission rate, IG is 

achieving the lowest SO2 emission rate among similar facilities. 
Indiana Gasification LLC Page 52 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for SO2 for Acid Gas Removal Unit Vents (EU-007A/B).

The SO2 emissions shall be reduced by the use of a Rectisol process and the SO2 emissions 

shall not exceed 3.17 pounds per hour for each Acid Gas Removal Unit Vent (EU-007A/B), based 

on a 3-hour average.

Nitrogen Oxide (NOX) BACT - AGR Regenerative Thermal Oxidizer (EU-007A and B)

The acid gas removal (AGR) units remove CO2 from the syngas and it will normally be

compressed to a liquid and sold. Whenever it is instead vented, it will be sent to one of two 

Regenerative Thermal Oxidizers (RTOs), one serving each AGR. The RTOs will oxidize small 

amounts of CO, COS, methane and VOCs (methanol) in the vent gas. Because the heating 

value of the CO2 stream to be vented is very low, a supplemental fuel is required to maintain the 

RTO at its operating temperature. As such, it is both a control device and a source of emissions.

The NOx emissions from the AGR vent result from the fuel combustion in the regenerative 

thermal oxidizer (RTO). Low NOx performance of the RTO is provided by use of a natural gas 

injection system.

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) Flue Gas Recirculation (FGR)

(d) Low NOx Burner (LNB) or other combustion control designed for Low NOx performance.

Add-on control technologies and combustion control approaches are discussed below.

Step 2: Eliminate Technically Infeasible Options

Low NOx Combustion Controls

The NOx emissions from the AGR vent result from the supplemental fuel combustion (natural gas 

or SNG) in the Regenerative Thermal Oxidizer used to thermally destroy CO, organic and sulfur 

compounds in the vent stream. The vented material upstream of the RTO contains no NOx. (NOx

emissions from supplemental fuel combustion are estimated to result in NOx emissions equal to 

0.05 lb NOx/MMBtu which equates to 3.95 lbs/hr (total from both RTOs)). 

The supplemental fuel combustion products from the RTO are reduced by the following 

techniques:

(1) Use of a regenerative thermal oxidizer – Using an RTO instead of other thermal 

oxidation devices reduces the supplemental fuel used for combustion by maximizing heat 

recovery.

(2) Use of only clean burning natural gas or SNG fuel – Inherently clean fuels.
Indiana Gasification LLC Page 53 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

(3) Fuel injection into the RTO ceramic beds - The ceramic bed will be above the autoignition temperature of natural gas. Designing the RTO to provide for the majority of the 

natural gas injection in these beds will allow natural gas combustion to occur at lower 

temperatures than in traditional burners thereby reducing the NOx generated. (Note: 

Conventional NG burners are used to initially bring the RTO up to temperature.)The 

amount of NOx formed increases with the peak temperature and the duration of that peak 

temperature in the combustion process. Because there is a direct correlation between 

temperature of combustion and NOx formation, this design reduces NOx emissions 

versus conventional regenerative thermal oxidizers

All three of the above techniques are technically feasible and reduce NOx emissions. 

Add-on Controls

Add-on controls for NOx, such as SCR, SNCR and FGR are not feasible because the 

exhaust/vent stream is already extremely low in NOx concentration and flow to the RTO will be 

intermittent. The combustion stream that exits the RTO is diluted with the high-volume process 

stream making the NOx concentrations extremely dilute. NOx emissions at the stack outlet will be 

less than 2 ppm. This low concentration and low total mass of NOx emissions do not allow 

additional reductions through the use of any further add-on controls to be technically feasible. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, the source has elected the use 

of a low NOx performance with natural gas injection for controlling the NOx emissions resulting 

from the Acid Gas Removal Unit Vents.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed NOx BACT determination along with the existing NOx 

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by Indiana Gasification, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 

147-30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Acid Gas 

Removal 

Unit Vents 

(EU-007A/B)

10,400 T 

dry 

coal/day 

3.95

pounds per 

hour based 

on 24 -hr 

block daily 

average

Low NOx 

Performance 

with natural 

gas injection

system

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Acid Gas 

Recovery 

Vents *

9,413 T/D 2.89 pounds 

per hour

No 

additional 

control

Permit V-09-006 Cash Creek 

Gasification

05/05/2010 Acid Gas 

Recovery 

Vents *

770 MW None None

28.0701-PSD Hyperion 

Gasification - South 

Dakota

08/20/2009 Acid Gas 

Recovery 

Vents *

400,000 

bbl/day

0.06 

lb/MMBtu 

and 6.1 

pounds per 

Low NOx 

Burners
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Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

hour

081801 AAF 

(Application No. 

07100063)

Power Holdings 

of Illinois 

Gasification

10/26/2009 Acid Gas 

Recovery 

Vents *

13,722 T 

coal per 

day

2.7 pounds 

per hr and 

11.7 tpy

Good 

Operating 

Practices

T083-23529-

00003

Duke Energy 

Indiana -

Edwardsport

01/25/2008 Acid Gas 

Recovery 

Vents *

630 MW None None

NOTE: * These emission units have not been built yet.

Only one similar source was located in the RBLC (Lake Charles Gasification), however, the comparison 

also includes the recently permitted and similar SNG facilities. The table shows their recently permitted 

NOx limits. 

The emission rates for NOx are comparable to, or lower than, the lowest permitted emission of these 

similar facilities after accounting for difference in the sizes of the units. 

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 Acid Gas Removal Unit Vents (EU-007A/B).

The NOx emissions from the Acid Gas Removal Unit Vents (EU-007A/B) shall be controlled by 

Low NOx Performance with natural gas injection and the NOx emissions shall not exceed 1.98

pounds per hour from each AGR/RTO unit based on a 3-hour average. 

Carbon Monoxide (CO) BACT – Acid Gas Removal Unit Vents (EU-007A and B)

The AGR vent stream contains over 4000 lbs/hr of CO and will be routed through an RTO 

providing 99% control of the CO in the vented gases. The carbon monoxide emissions from the 

AGR vent result primarily from the 1% of uncontrolled CO in the AGR vent stream. Only a very 

small portion of the CO emissions come from supplemental fuel combustion in the RTO, which 

uses clean burning natural gas or SNG. 

Step 1: Identify Potential Control Technologies

Emissions of carbon monoxide (CO) are generally controlled by efficient oxidation. Possible 

combustion control technologies include: 

(a) Regenerative Thermal oxidizer;

(b) Conventional Thermal oxidizer;

(c) Flare; and

(d) Catalytic Oxidation.

Step 2: Eliminate Technically Infeasible Options

Regenerative Thermal Oxidizers 

Thermal oxidizers destroy air toxics and organic compounds that are discharged in industrial 

process exhausts. Thermal oxidizers achieve destruction through the process of high 

temperature thermal oxidation, converting combustible compounds to carbon dioxide and water 
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vapor, and oxidizing toxic compounds to non-toxic compounds. Some thermal oxidizers preheat 

the incoming air by capturing heat from the outgoing air stream to reduce operating costs. 

Regenerative thermal oxidizers use ceramic heat transfer beds to recover thermal energy from 

the oxidation process. The heat transfer beds act as heat exchangers. The heat recovery can be 

as much as 90 to 95%. Process gas enters the RTO through an inlet manifold. The gas is 

directed into an energy recovery chamber which preheats the process gas. The process gas and 

contaminants are progressively heated in the ceramic bed as they move toward the combustion 

chamber. 

Thermal oxidation of CO to CO2 is the most effective treatment for this AGR Vent stream prior to 

venting to the atmosphere. Thermal oxidation will also control other contaminants in this stream 

by converting methanol to CO2 and water, H2S to SO2 and water and COS to SO2 and CO2. To 

achieve thermal oxidation, air must be added and the combined stream heated to approximately 

1600 degrees F. 

The heating value of the CO2 stream to the RTO is very low because it contains mostly noncombustible CO2 (98%). Consequently, each RTO will have a natural gas/SNG burner to raise 

the temperature in the combustion chamber of the RTO to 1600 degrees F. This ensures a high 

oxidation efficiency of the CO (99%), CH3OH (99%), H2S (98%), and COS (98%). Most of this 

heat is recovered by heating one of the heat transfer beds which will be used subsequently to 

preheat the incoming gas stream (i.e.; the two beds are alternated between incoming gas and 

exhaust gas.) This reduces the supplementary fuel firing rate and associated combustion 

emissions.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a regenerative thermal oxidizer (RTO) is a technically feasible option for the Acid Gas 

Removal Unit Vents (EU-007A/B) at this source.

Conventional Thermal oxidizer

A conventional thermal oxidizer would be technically feasible for this stream. The control 

efficiency of a conventional Thermal Oxidizer is the same as the Regenerative Thermal Oxidizer, 

and provides a 99% oxidation efficiency for CO and 98% oxidation efficiency of H2S and COS. 

However, a Conventional Thermal Oxidizer does not provide for heat recovery.

There is very little heating value inherent in the AGR Vent stream which has an approximate 

concentration of 98%v CO2. Consequently, a conventional Thermal Oxidizer without heat 

recovery would have a very high supplemental fuel requirement (more than 10 times higher than 

a regenerative TO) to reach a 1600 F gas temperature. Therefore, a conventional TO would 

have higher operating costs and much higher combustion pollutant emissions (NOx, VOC, PM10). 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a conventional thermal oxidizer is a technically feasible option for the Acid Gas 

Removal Unit Vents (EU-007A/B) at this source

Flare

Although the pollutants (CO, methanol, H2S, and COS) concentrations are low to very low, the 

stream flow rate is very high. The low heating value of the CO2 stream is too low for flaring. As 

there are insufficient organics in this vent stream to support combustion, use of a flare would 

require a significant addition of supplementary fuel. Therefore, a secondary impact of the use of 

flare for this stream would be the creation of additional emissions from burning supplemental fuel, 

including NOx. Flares have not been utilized or demonstrated as a control device for CO from 

this type of high-volume process stream. In addition, the flare would have no additional control 

versus the thermal oxidizers. 
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Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flare is a technically infeasible option for the Acid Gas Removal Unit Vents (EU007A/B) at this source

Catalytic Oxidation

A catalytic oxidizer is an add-on control device to control VOC emissions by using a bed of 

catalyst that facilitates the oxidation of combustible gases. The catalyst increases the reaction 

rate and allows the conversion of VOC at lower temperature than a thermal incinerator. Typical 

problems encountered when using a catalytic incinerator is that the contaminants in the exhaust 

stream can poison or foul the catalyst bed. 

A catalytic oxidizer converts the CO in the combustion gases to CO2 at temperatures ranging 

from 500 degrees F to 700 degrees F in the presence of a catalyst. Catalytic oxidation is 

proposed for the Cash Creek Generation gasification AGR Vent Stream at a control level of at 

least 90%. 

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 the Acid Gas Removal Unit Vents 

(EU-007A/B) at this source

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the technical feasibility analysis in Step 2, the remaining control technologies may be 

ranked as follows for controlling VOC emissions from these operations.

(1) Regenerative thermal oxidation (99 % CO Reduction)

(2) Conventional thermal oxidation (99 % CO Reduction)

(3) Catalytic oxidizer (over 90 % CO Reduction)

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed CO BACT determination along with the existing CO BACT 

determinations for similar plants. All data in the table is based on the information obtained from 

the permit application submitted by Indiana Gasification, LLC, the U.S. EPA RACT/BACT/LAER 

Clearinghouse (RBLC), and electronic versions of permits available at the websites of other 

permitting agencies.

BACT ID or Permit # Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Acid Gas 

Removal 

Unit Vents 

(EU007A/B)

10,400 T 

dry 

coal/day 

48 pounds 

per hour 

based on 3 

hour 

average, 

each

Regenerative

Thermal 

Oxidizer

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Acid Gas 

Recovery 

Vents *

9,413 T/D 43.97 pounds 

per hour Max

Regenerative 

Thermal 

Oxidizer

Permit V-09-006 Cash Creek 

Gasification

05/05/2010 Acid Gas 

Recovery 

Vents *

770 MW 126 pounds 

per hour

Catalytic 

Oxidizer
Indiana Gasification LLC Page 57 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID or Permit # Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

28.0701-PSD Hyperion Energy 08/20/2009 Acid Gas 

Recovery 

Vents *

400,000 

bbl/day

0.08 

lb/MMBtu and 

8.1 lb/hr

Thermal 

Oxidizer

081801 AAF 

(Application No. 

07100063)

Power Holdings 

of Illinois 

Gasification

10/26/2009 Acid Gas 

Recovery 

Vents *

13,722 T 

coal per 

day

61 pounds 

per hr and 

266.2 tpy

Thermal 

Oxidizer

T083-23529-00003 Duke Energy 

Indiana -

Edwardsport

01/25/2008 Acid Gas 

Recovery 

Vents *

630 MW 0.08 

lb/MMBtu

Thermal 

Oxidizer

NOTE: * These emission units have not been built yet. 

A regenerative thermal oxidizer will provide the highest degree of control of CO for this source. It 

should be noted that there are a small amount of additional energy requirements and generated 

pollutants (NOx and PM10) through the supplemental fuel combustion from using a thermal control 

device. However, these impacts are lower with an RTO than with a conventional TO because the 

supplemental fuel demand is less.

The regenerative thermal oxidizer and the conventional thermal oxidation control options both 

provide the same level of performance regarding CO destruction efficiency (99% control). 

However, the RTO generates lower CO emissions due to the lower incremental fuel use than the 

conventional thermal oxidizer. 

The oxidation efficiency of CO from both the Regenerative and Conventional Thermal Oxidizers 

are the same (99%). Overall CO emissions generated from the AGR Vent stream are higher from 

the Conventional Thermal Oxidizer since it would require significantly more supplemental fuel 

firing (over 500 MMBtu/hr). The extra CO from the additional fuel combustion will roughly double 

the emissions of CO. Thus, the regenerative thermal oxidizer will provide a superior CO control 

performance compared to the conventional thermal oxidizer. Likewise, a catalytic oxidizer would 

perform no better.

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 Acid Gas Removal Unit Vents (EU-007A/B).

The IDEM agrees that the CO BACT for Acid Gas Removal Unit Vents (EU-007A/B) shall be 

established as follows: 

The CO emissions shall be controlled by a the use of regenerative thermal oxidizer (RTO) and 

the CO emissions shall not exceed 48 pounds per hour for the Acid Gas Removal Unit Vents 

(EU-007A/B), each, based on a 3-hour average.

Particulate Matter (PM/PM10/PM2.5) BACT – Gasifier Preheat Burners (EU-008A-E)

Step 1: Identify Potential Control Technologies

PM, PM10 and PM2.5 are generally controlled with add-on control equipment designed to capture 

the emissions prior to the time they are exhausted to the atmosphere. Generally, PM, PM10 and 

PM2.5 emissions are controlled through one of the following mechanisms:

(1) Mechanical Collectors (such as Cyclones or Multiclones);

(2) Wet Scrubbers;
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(3) Electrostatic Precipitators (ESP); and

(4) Fabric Filter Dust Collectors (Baghouses).

The choice of which technology is most appropriate for a specific application depends upon 

several factors, including particle size to be collected, particle loading, stack gas flow rate, stack 

gas physical characteristics (e.g., temperature, moisture content, presence of reactive materials), 

and desired collection efficiency.

Step 2: Eliminate Technically Infeasible Options

Add - on - Controls

The PM, PM10 and PM2.5 emissions from this source result only from the small amount of natural 

gas or SNG that are used. These emissions are very low due to the clean fuel used and because 

the exhaust also passes through the water quench section of the gasifier where the quench water 

may serve to remove some of the PM. The resultant PM/PM10/PM2.5 emissions are less than 

0.01 tons/yr per preheat burner. This emissions level is so low that it would not be feasible for any 

add-on controls such as cyclones, baghouses, ESPs or wet scrubbers to effectively further 

reduce emissions. Also, regardless of the emissions rate, because a steam eductor draws the 

exhaust out of the gasifier, the resultant very high moisture content of the exhaust would render 

the more effective of these controls – an ESP or baghouse – technically infeasible. For these 

reasons, the above-listed add-on particulate controls are not considered feasible in this BACT 

analysis. There is no evidence that any of these add-on controls have ever been used to control 

natural gas combustion particulate.

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 Gasifier Preheater Burners at 

this source

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

there is no viable technology for controlling the PM, PM10 and PM2.5 emissions resulting from the 

Gasifier Preheater Burners (EU-008).

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for similar plants. All data in the table is 

based on the information obtained from the permit application submitted by Indiana Gasification, 

LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits 

available at the websites of other permitting agencies.

BACT ID or Permit # Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Gasifier 

Preheat 

Burners 

(EU-008A-E)

35 

MMBtu/hr

0.0007 

lb/MMBtu 

Use of Clean 

burning 

gaseous fuel

28.0701 - PSD Hyperion Energy 8/20/2009 Gasifier 

Startup 

Burners*

400,000 

bbl/day

None No Control

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Gasifier 

Startup

Preheat 

9,413.0 T/D 0.01 

lbs/hour, 

each

Good design 

and proper 

operation
Indiana Gasification LLC Page 59 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID or Permit # Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Burners (5)*

9923 -AC010 TESORO ALASKA 

COMPANY -

KENAI REFINERY

03/21/2000 #1 Preheat 

Startup

Burners, 

H1102*

1.65 

MMBtu/Hr

None None 

Indicated

081801 AAF 

(Application No. 

07100063)

Power Holdings 

of Illinois 

Gasification

10/26/2009 Gasifier 

Startup 

Burners*

13,722 T 

coal per 

day

0.01 

lb/MMBtu

None

Compliance determination is unknown for all these sources.

NOTE: * These emission units have not been built yet.

(a) Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for the PM, PM10 and PM2.5 emissions from the 

Gasifier Preheat Burners (EU-008A-E):

The PM, PM10 and PM2.5 emissions from the Gasifier Preheat Burners (EU-008A-E) operation 

shall be the use of clean burning gaseous fuel and the PM, PM10 and PM2.5 emissions shall not 

exceed 0.0007 lb /MMBtu.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for Gasifier Preheat Burners (EU-008A-E).

The PM, PM10 and PM2.5 emissions from the Gasifier Preheat Burners (EU-008A-E) operation 

shall not exceed 0.0007 lb /MMBtu and shall use only natural gas or SNG. 

Carbon Monoxide (CO) BACT – Gasifier Preheat Burners (EU - 008A-E)

Step 1: Identify Potential Control Technologies

Emissions of carbon monoxide (CO) are generally controlled by combustion control. Oxidation in 

an add-on control is also an option in some cases. Oxidation technologies include regenerative 

thermal oxidation, catalytic oxidation, and flares. The list of identified technologies includes:

(a) Regenerative thermal oxidation; 

(b) Catalytic oxidation; 

(c) Flares

(d) Combustion Control

If add-on control technology is not feasible, an alternate method of control may be implemented. 

Step 2: Eliminate Technically Infeasible Options

Regenerative Thermal Oxidizers

The thermal oxidizer is a high temperature process maintained by a combustion 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. As it is passing through the high temperature zone, the waste gas, 
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containing CO is heated to its ignition temperature. The mixture continues to react as it flows 

through the combustion chamber.

The required level of CO destruction of the waste gas that must be achieved within the time

that it spends in the thermal combustion chamber dictates the reactor temperature. The shorter 

the residence time, the higher the reactor temperature must be. Most thermal oxidizer units are 

designed to provide no more than 1 second of residence time to the waste gas with typical 

temperatures of 1,200 to 2,000o

F. Once the unit is designed and built, the residence time is not 

easily changed, so that the required reaction temperature becomes a function of the particular 

gaseous species and the desired level of control. 

Regenerative Thermal Oxidizer is supplemented with 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). 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. Given the fact that these burners are used intermittently, are relatively small 

and vent through a wet quench, it is not feasible to operate them in combination with an RTO.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a regenerative thermal oxidizer is a technically infeasible option for the Gasifier 

Preheat Burners at this source.

Catalytic Oxidizers

Catalytic oxidation is also a widely used control technology. 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 650°F to 1000°F and approximately require 1.5 to 2.0 ft3 of catalyst 

per 1000 standard ft3 per gas flow rate. Emissions from emission units may contain significant 

amount of particulates. These particulates can poison the catalyst resulting in the failure of 

catalytic oxidation. Given the intermittent operation of these burners, their size and the use of a 

wet quench, catalytic oxidation is not likely to work in this application and it has never been used 

on this type of equipment.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a catalytic oxidizer is a technically infeasible option for Gasifier Preheat Burners at this 

source.

Flare

Although the pollutants (CO, methanol, H2S, and COS) concentrations are low to very low, the 

stream flow rate is very high. The low heating value of the CO2 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. Flaring is normally applied to a gas stream 

that is capable of maintaining combustion. The exhaust from the preheat burners, is very low in 

CO and wet and cannot support combustion. Flares have not been utilized or demonstrated as a 

control device for CO from this type of gas fired combustion source. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flare is a technically infeasible option for the Gasifier Preheat Burners at this source.
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Permit Reviewer: Josiah Balogun

Combustion Control 

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. Factors affecting CO emissions include firing temperatures, 

residence time in the combustion zone and combustion chamber mixing characteristics.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The only viable control for the control of CO emissions from the Gasifier Preheat Burners is a 

combustion control.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed CO BACT determination along with the existing CO BACT 

determinations for similar plants. All data in the table is based on the information obtained from 

the permit application submitted by Indiana Gasification, LLC, the U.S. EPA RACT/BACT/LAER 

Clearinghouse (RBLC), and electronic versions of permits available at the websites of other 

permitting agencies.

BACT ID or 

Permit #

Facility Issued 

Date

Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 

147-30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Gasifier 

Preheat 

Burners (EU008A-E)

35 

MMBtu/hr

0.056 lb CO 

/MMBtu

Good 

Combustion 

Practices

28.0701 - PSD Hyperion Energy 8/20/2009 Gasifier 

Startup 

Burners*

400,000 

bbl/day

0.1 

lb/MMBtu

No Control

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Gasifier 

Startup

Preheat 

Burners (5)*

9,413.0 T/D 1.01 lb/hr Good design 

and proper 

operation

9923 -AC010 TESORO 

ALASKA 

COMPANY -

KENAI 

REFINERY

03/21/2000 #1 Preheat 

Startup

Burners, 

H1102*

1.65 

MMBtu/Hr

0.035 

lb/MMBtu

(Post -BACT 

limit)

None 

081801 AAF 

(Application No. 

07100063)

Power Holdings 

of Illinois 

Gasification

10/26/2009 Gasifier 

Startup 

Burners*

13,722 T 

coal per 

day

0.1 

lb/MMBtu

None

Compliance determination is unknown for all these sources.

NOTE: * These emission units have not been built yet.

Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for the CO emissions from the Gasifier Preheat 

Burners (EU-008A-E):

The CO emissions from the Gasifier Preheat Burners (EU-008A-E) operation shall be limited to 

less than 0.056 lb CO/MMBtu through the use of good combustion practices. 
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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 Gasifier Preheat Burners (EU-008A-E).

The CO emissions from the Gasifier Preheat Burners (EU-008A-E) operation shall not exceed

0.056 lb CO/MMBtu and shall use good combustion practices. 

Sulfur Dioxide (SO2) BACT - Gasifier Preheat Burners (EU - 008A-E)

Step 1: Identify Potential Control Technologies

Emissions of Sulfur dioxide (SO2) are generally controlled by the use of either; 

1. Flue Gas Desulfurization

2. Low sulfur fuel

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 SO2 emissions from the Gasifier Preheat Burners (EU-008A-E).

Low sulfur fuel

These burners are proposed to use only natural gas or SNG. As a low-sulfur fuel source, this will 

minimize SO2 emissions.

Flue Gas Desulfurization (FGD) System (Wet or Dry Scrubber)

A flue gas desulfurization system (FGD) is comprised of a spray dryer that uses lime as a reagent 

followed by particulate control or wet scrubber that uses limestone as a reagent. FGD is an 

established technology. The concentration of SO2 in the exhaust gas is the driving force for the 

reaction between SO2 and the reagent. Therefore, removal efficiencies are significantly reduced 

with lower inlet concentrations of SO2. FGD systems are listed in the RBLC as BACT for sources 

high in SO2 emissions. Wet scrubbing FGD system is considerably cheaper than dry scrubbing.

Add-on SO2 controls such as flue gas desulfurization described above, a common control in coal 

combustion, is not feasible for further control of SO2 emissions because of inherently low SO2

emissions from a clean gas fired operation. 

The SO2 emissions are inherently very low through the use of natural gas or SNG. Clean natural 

gas combustion exhaust contains less than 2 ppm SO2. This is too low for any add-on control 

technology such as a wet scrubber to be feasible. Wet scrubbing systems are typically only 

installed on exhaust streams of coal and oil fired units, with an inlet pollutant loading of 

approximately 250 - 2000 ppm SO2. In the very best cases, wet scrubbing systems can achieve 

up to as high as 98% control and reduce SO2 to single digit ppm levels. However, this vent is 

already less than 2 ppm SO2 (because of the clean fuel used). Therefore, further exhaust gas 

sulfur scrubbing systems would not be effective or applicable as an add-on control in this service. 

Accordingly, FGD for SO2 control was not considered feasible as BACT.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flue gas desulfurization system (FGD) is not a technically feasible option for the 

Gasifier Preheat Burners at this source.
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Step 3: Rank the Remaining Control Technologies by Control Effectiveness

1. Low sulfur fuel

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed SO2 BACT determination along with the existing SO2

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by Indiana Gasification, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or Permit # Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Gasifier 

Preheat 

Burners 

(EU-008A-E)

35 

MMBtu/hr

0.0006 

lb/MMBtu

Use of Clean 

burning 

gaseous fuel

28.0701 - PSD Hyperion Energy 8/20/2009 Gasifier 

Startup 

Burners*

400,000 

bbl/day

0.006 

lb/MMBtu

No Control

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Gasifier 

Startup

Preheat 

Burners (5)*

9,413.0 T/D 0.01 lb/hr Natural gas

9923 -AC010 TESORO ALASKA 

COMPANY -

KENAI REFINERY

03/21/2000 #1 Preheat 

Startup

Burners, 

H1102*

1.65 

MMBtu/Hr

None None 

Indicated

081801 AAF 

(Application No. 

07100063)

Power Holdings 

of Illinois 

Gasification

10/26/2009 Gasifier 

Startup 

Burners*

13,722 T 

coal per 

day

0.0013 

lb/MMBtu

None

Compliance determination is unknown for all these sources.

NOTE: * These emission units have not been built yet.

(a) Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for the SO2 emissions from the Gasifier Preheat 

Burners (EU-008A-E):

The SO2 emissions from the Gasifier Preheat Burners (EU-008A-E) operation shall be Use of 

Clean burning gaseous fuel and the SO2 emissions shall not exceed 0.0006 lb SO2/MMBtu.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for SO2 for Gasifier Flare (EU-008A-E).

The SO2 emissions from the Gasifier Preheat Burners (EU-008A-E) operation shall not exceed

0.0006 lb SO2/MMBtu and shall use natural gas or SNG.
Indiana Gasification LLC Page 64 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Nitrogen Oxide (NOX) BACT - Gasifier Preheat Burners (EU - 008A-E)

Step 1: Identify Potential Control Technologies

The nitrogen oxide (NOx) emissions can be controlled by the following techniques: 

(a) Selective Catalytic Reduction (SCR)

(b) Flue Gas Recirculation (FGR)

(c) Low NOx Burner (LNB)

Step 2: Eliminate Technically Infeasible Options

Selective Catalytic Reduction (SCR)

Selective Catalytic Reduction (SCR) process involves the mixing of anhydrous or aqueous 

ammonia vapor with flue gas and passing the mixture through a catalytic reactor to reduce NOX

to water and nitrogen (N2). Under optimal conditions, SCR has removal efficiency up to 90% 

when used on steady state processes. The efficiency of removal will be reduced for processes 

that are not stable or require frequent changes in the mode of operation.

NOx add-on controls such as SCR would not be effective in this service because SCR requires a 

specific narrow operating temperature range (about 480o

F to 800oF) to be effective. There is no 

location in the exhaust path of the gasifier preheat burners that has this required temperature 

range. The gasifier itself is operated much higher than this temperature (target temperature 

2500o

F). The preheat burner exhaust gases exit the hot gasifier through the quench section of 

the gasifier and through a steam eductor in route to the stack. The stack temperature is only 

about 232o

F. Therefore, SCR is technically infeasible. 

Besides the temperature incompatibility, SCR is not typically used on combustion sources smaller 

than about 250 MMBtu/hr because its high capital and operating costs are not justified. The 

preheat burners design capacity is only 35 MMBtu/hr and their average annual operating rate is 

much lower.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

selective catalytic reduction (SCR) is not a technically feasible option for the Gasifier Preheat 

Burner 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. 

The LNBs are specially designed pieces of combustion equipment that reduce NOx formation 

through careful control of the fuel-air mixture during combustion. In a stage air combustion LNB, 

either air or fuel is added downstream of the primary combustion zone. Depending on which of 

this NOx reduction technique is used, LNBs with stage combustion are subdivided into staged air 

burners and staged fuel burners. 
Indiana Gasification LLC Page 65 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Low NOx designs are not feasible for the preheat burners due to the design of the burners and 

the extremely high gasifier temperature required (2500 F). The burners are designed similar to a 

lance, or fuel nozzle, and are only used during preheat. The burners fire into the gasifiers which 

do not include tubes or other heat absorbing material. This results in the temperature being much 

higher than many applications that incorporate low NOx burner technology. The extreme desired 

operating temperature is above the temperature that nitrogen breaks apart making NOx reduction 

not effective. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a low NOx burner is not a technically feasible option for the Gasifier Preheat Burner at 

this source.

Flue Gas Recirculation (FGR)

Recirculating a portion of the flue gas to the combustion zone can lower the peak flame 

temperature and result in reduced thermal NOx production. The flue gas recirculation (FGR) can 

be highly effective technique for lowering NOx emissions from burners and it's relatively 

inexpensive to apply. Most of the early FGR work was done on boilers, and investigators found 

that recirculating up to 25% of the flue gases through the burner could lower NOx emissions to as 

little as 25% of their normal levels. FGR can lower NOx emissions on two ways; 

The cooled, relatively inert, recirculated flue gases act as heat sink, absorbing heat from the 

flame and lowering peak flame temperatures and when mixed with the combustion air, 

recirculated flue gases lower the average oxygen content of the air, starving the NOx-forming 

reaction for one of the ingredients they need.

External flue gas recirculation is also not feasible because there is no way to return the flue gas 

to the burner. The burner is inserted and removed during each start up and cannot be connected 

to the flue exhaust. Additionally, the preheat burners have limited use and overall very low 

annual emissions are expected from each burner. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Flue Gas Recirculation (FGR) is not a technically feasible option for the Gasifier 

Preheat Burner at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

there is no viable technology for controlling the NOx emissions resulting from the Gasifier Preheat 

Burners (EU-008A-E).

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed NOx BACT determination along with the existing NOx

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by Indiana Gasification, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or Permit # Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Gasifier 

Preheat 

Burners 

(EU-008A-E)

35 

MMBtu/hr

0.10 lb 

NOx 

/MMBtu

Good 

Combustion 

Practices

28.0701 - PSD Hyperion Energy 8/20/2009 Gasifier 

Startup 

Burners*

400,000 

bbl/day

0.07 

lb/MMBtu

low NOx 

Burners
Indiana Gasification LLC Page 66 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID or Permit # Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

PSD-LA-742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Gasifier 

Startup

Preheat 

Burners (5)*

9,413.0 T/D 1.80 lb/hr , 

each

Good Design 

and Proper 

Operation

9923 -AC010 TESORO ALASKA 

COMPANY -

KENAI REFINERY

03/21/2000 #1 Preheat 

Startup

Burners, 

H1102*

1.65 

MMBtu/Hr

0.14 

lb/MMBtu

None 

Indicated

081801 AAF 

(Application No. 

07100063)

Power Holdings 

of Illinois 

Gasification

10/26/2009 Gasifier 

Startup 

Burners*

13,722 T 

coal per 

day

0.2 

lb/MMBtu

None

Compliance determination is unknown for all these sources.

NOTE: * These emission units have not been built yet.

IDEM notes that the emissions limit for the Hyperion Plant gasifier preheaters is somewhat lower 

than the limit proposed by IG. IG has indicated that communications with the burner vendors 

indicate that the lower number would be achievable during the time that a preheater is used to 

keep a gasifier in standby and this is the most frequent mode of burner operation. However, 

when the gasifier needs to be heated to 2500 deg F, just before startup, the emissions increase 

to the figure IG has proposed. IDEM has decided to recognize this difference and accept the IG 

proposal, as it covers the worst case mode.

(a) Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for the NOx emissions from the Gasifier Preheat 

Burners (EU-008A-E):

The NOx emissions from the Gasifier Preheat Burners (EU-008A-E) operation shall be good 

combustion practices and the NOx emissions shall not exceed 0.10 lb NOx /MMBtu. 

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 Gasifier Preheat Burners (EU-008A-E).

The NOx emissions from the Gasifier Preheat Burners (EU-008A-E) operation shall not exceed 

0.10 lb NOx /MMBtu and shall use good combustion practices.

NOx, CO, SO2 and PM/PM10/PM2.5 BACT – Emergency Generators (EU-009A/B)

Step 1: Identify Potential Control Technologies

These generators are used in emergencies only and operate about 50 hours a year to ensure that 

they will start when needed. They will be designed to meet the applicable NSPS and NESHAP 

limited discussed below. Combustion design will be used by the manufacturer to meet those 

limits. These units will be operated on low sulfur diesel. Diesel has been chosen over natural 

gas and SNG for safety reasons. Should an incident affect the gas system, an independent 

source of fuel, in the form of a localized dedicated fuel tank, is available. Beyond the use of low 

sulfur diesel, which has beneficial impacts on both the SO2 and particulate emissions of the unit, 

the emissions of Nitrogen oxide (NOx), CO, SO2, PM, PM10 and PM2.5 from emergency 

generators are not generally controlled. 
Indiana Gasification LLC Page 67 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

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 emissions from the Emergency Generators. No additional controls have been 

identified.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

there is no viable technology for controlling the NOx, CO, SO2 PM, PM10 and PM2.5 emissions 

resulting from the Emergency Generators.

Step 4: Evaluate the Most Effective Controls and Document the Results

In its review of the RACT/BACT/LAER Clearinghouse (RBLC) and similar permits, no facilities 

were identified where controls were required on an emergency generator. 

The nature of an emergency generator is to provide electricity to the site only in an emergency 

situation that arises when the normal operating falls into an emergency status. 

The emergency diesel-fired generators are not expected to be used in normal operation. Outside 

of emergency situations, these engines will only operate for testing and maintenance purposes –

which should average no more than one hour per week for each engine (i.e.; 52 hours per year 

each).

These emergency diesel engines are subject to federal NSPS and NESHAPS standards: Part 60 

Subpart IIII and Part 63 Subpart ZZZZ. These standards are applicable to stationary compression 

ignition internal combustion engines. They establish emissions standards that must be met by 

the manufacturer and owner/operator regarding NOx, CO, PM, hydrocarbon (VOC) emissions 

and fuel sulfur content. The proposed emergency engines of IG will meet these standards. 

A search of the RACT/BACT/LAER Clearinghouse indicates good engineering design meeting 

the above standards and burning low sulfur diesel fuel (15 ppm sulfur) have been considered 

BACT for emergency diesel engines / generators for all pollutants. The use of further add-on 

controls would not be justified given the infrequent use of this equipment. IG proposes to limit 

each engine to no more than 52 hours per year of non-emergency operation (consistent with the 

basis of the annual emissions air dispersion modeling.)

Therefore, the IG Facility proposes that BACT for these emergency engines is compliance with 

NSPS Subpart IIII, NESHAPS Subpart ZZZZ and the burning of fuels with no more than 15 ppm 

sulfur for all BACT pollutants. IG will also limit the non-emergency operation of these engines to 

no more than 52 hours per year each.

(a) Proposal: Indiana Gasification, LLC - Rockport, IN

The following has been proposed as BACT for the NOx, CO, SO2 PM, PM10 and PM2.5

emissions from the emergency generators:

(1) NOx: emissions shall be limited through the implementation of good combustion 

practices and limited hours of non-emergency operation;

(2) CO: emissions shall be limited through the implementation of good combustion 

practices and limited hours of non-emergency operation; 
Indiana Gasification LLC Page 68 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

(3) PM, PM10 and PM2.5: emissions shall be limited through the use of low-S diesel 

(less than15ppm sulfur) and limited hours of non-emergency operation;

(4) SO2: emissions shall be limited through the use of low-S diesel (less than15ppm 

sulfur) and limited hours of non-emergency operation; and

(5) Each emergency generator shall not exceed 52 hours per year of nonemergency operation.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM, OAQ has 

approved the proposed NOx, CO, SO2 PM, PM10 and PM2.5 BACT for the Emergency 

Generators. 

The BACT for Emergency Generators shall be established as follows:

(1) NOx: emissions shall be limited through the implementation of good combustion 

practices and limited hours of non-emergency operation;

(2) CO: emissions shall be limited through the implementation of good combustion 

practices and limited hours of non-emergency operation; 

(3) PM, PM10 and PM2.5: emissions shall be limited through the use of low-S diesel 

(less than15ppm sulfur l) and limited hours of non-emergency operation;

(4) SO2: emissions shall be limited through the use of low-S diesel (less than15ppm 

sulfur) and limited hours of non-emergency operation; and

(5) Each emergency generator shall not exceed 52 hours per year of nonemergency operation.

Nitrogen Oxide (NOX), CO, SO2, PM/PM10/PM2.5 BACT - Firewater Pump Engines (EU-010A-C)

Step 1: Identify Potential Control Technologies

These engines are used in emergencies only and operate about 50 hours a year to ensure that 

they will start when needed. They will be designed to meet the applicable NSPS and NESHAP 

limited discussed below. Combustion design will be used by the manufacturer to meet those 

limits. These units will be operated on low sulfur diesel. Diesel has been chosen over natural gas 

and SNG for safety reasons. Should an incident affect the gas system, an independent source of 

fuel, in the form of a localized dedicated fuel tank, is available. Beyond the use of low sulfur 

diesel, which has beneficial impacts on both the SO2 and particulate emissions of the unit, the 

emissions of Nitrogen oxide (NOx), CO, SO2, PM, PM10 and PM2.5 from firewater pump engines 

are not generally controlled. 

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 NOx, CO, SO2, PM, PM10 and PM2.5 emissions from the Firewater Pump Engines. No 

additional controls have been identified.
Indiana Gasification LLC Page 69 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

there is no viable technology for controlling the NOx, CO, SO2 PM, PM10 and PM2.5 emissions 

resulting from the Firewater Pump Engines.

Step 4: Evaluate the Most Effective Controls and Document the Results

In its review of the RACT/BACT/LAER Clearinghouse (RBLC) and similar permits, no facilities 

were identified where controls were required on the Firewater Pump Engines. 

The firewater pumps are not expected to be used in normal operation. Outside of emergency 

situations, these engines will only operate for testing and maintenance purposes – which should 

average no more than one hour per week for each engine (i.e.; 52 hours per year each).

These firewater pumps are subject to federal NSPS and NESHAPS standards: Part 60 Subpart 

IIII and Part 63 Subpart ZZZZ. These standards are applicable to stationary compression ignition 

internal combustion engines. They establish emissions standards that must be met by the 

manufacturer and owner/operator regarding NOx, CO, PM, hydrocarbon (VOC) emissions and 

fuel sulfur content. The proposed emergency engines will meet these standards. 

A search of the RACT/BACT/LAER Clearinghouse indicates good engineering design meeting 

the above standards and burning low sulfur diesel fuel (15 ppm sulfur) have been considered 

BACT for emergency diesel engines/generators for all pollutants. The use of further add-on 

controls would not be justified given the infrequent use of this equipment. IG proposes to limit 

each engine to no more than 52 hours per year of non-emergency operation (consistent with the 

basis of the annual emissions air dispersion modeling.)

Therefore, BACT for these emergency engines is compliance with NSPS Subpart IIII, NESHAPS 

Subpart ZZZZ and the burning of fuels with no more than 15 ppm sulfur for all BACT pollutants. 

The non-emergency operation of these engines will be limited to no more than 52 hours per year 

each.

(a) Proposal: Indiana Gasification, LLC - Rockport, IN

The following has been proposed as BACT for the NOx, CO, SO2 PM, PM10 and PM2.5

emissions from the firewater pump engines:

(1) NOx: emissions shall be limited through the implementation of good combustion 

practices and limited hours of non-emergency operation;

(2) CO: emissions shall be limited through the implementation of good combustion 

practices and limited hours of non-emergency operation; 

(3) PM, PM10 and PM2.5: emissions shall be limited through the use of low-S diesel 

(less than15ppm sulfurl) and limited hours of non-emergency operation;

(4) SO2: emissions shall be limited through the use of low-S diesel (less than15ppm 

sulfur) and limited hours of non-emergency operation; and

(5) Each emergency generator shall not exceed 52 hours per year of nonemergency operation.
Indiana Gasification LLC Page 70 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM, OAQ has 

approved the proposed NOx, CO, SO2 PM, PM10 and PM2.5 BACT for the Firewater Pump 

Engines. 

The BACT for firewater pump engines shall be established as follows:

(1) NOx: emissions shall be limited through the implementation of good combustion 

practices and limited hours of non-emergency operation;

(2) CO: emissions shall be limited through the implementation of good combustion 

practices and limited hours of non-emergency operation; 

(3) PM, PM10 and PM2.5: emissions shall be limited through the use of low-S diesel (less 

than15ppm sulfur) and limited hours of non-emergency operation;

(4) SO2: emissions shall be limited through the use of low-S diesel (less than15ppm sulfur) 

and limited hours of non-emergency operation; and

(5) Each emergency generator shall not exceed 52 hours per year of nonemergency operation.

Particulate Matter (PM/PM10/PM2.5) BACT – Process Area Solid Feedstock Conveying, storage and 

feedbin (EU-011 A and B)

Step 1: Identify Potential Control Technologies

The emissions of PM, PM10 and PM2.5 are generally controlled by the following add-on control 

equipment designed to capture the emissions prior to the time they are exhausted to the 

atmosphere:

(1) Fabric Filter Dust Collectors (Baghouses);

 (2) Wet Scrubber;

 (3) Cyclones; and 

 (4) Wet Suppression.

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.
Indiana Gasification LLC Page 71 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Step 2: Eliminate Technically Infeasible Options

(a) Fabric Filtration (Baghouses):

A fabric filter unit consists of one or more isolated compartments containing rows of fabric 

bags in the form of round, flat, or shaped tubes, or pleated cartridges. Particle laden gas 

passes up (usually) along the surface of the bags then radially through the fabric. 

Particles are retained on the upstream face of the bags, and the cleaned gas stream is 

vented to the atmosphere. The filter is operated cyclically, alternating between relatively 

long periods of filtering and short periods of cleaning. During cleaning, dust that has 

accumulated on the bags is removed from the fabric surface and deposited in a hopper 

for subsequent disposal. Fabric filters collect particles with sizes ranging from submicron 

to several hundred microns in diameter at efficiencies generally in excess of 99%. 

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 1 to 20 inches of 

water. 

Fabric filters are used where high efficiency particle collection is required. Limitations are 

imposed by gas characteristics (temperature and corrosivity) and particle characteristics 

(primarily stickiness) that affect the fabric or its operation and that cannot be 

economically accommodated. Important process variables include particle 

characteristics, gas characteristics, and fabric properties. 

The most important design parameter is the air- or gas-to-cloth ratio (the amount of gas 

in ft3

/min that penetrates one ft2 of fabric) and the usual operating parameter of interest is 

pressure drop across the filter system. The major operating feature of fabric filters that 

distinguishes them from other gas filters is the ability to renew the filtering surface 

periodically by cleaning. Common furnace filters, high efficiency particulate air (HEPA) 

filters, high efficiency air filters (HEAFs), and automotive induction air filters are examples 

of filters that must be discarded after a significant layer of dust accumulates on the 

surface. These filters are typically made of matted fibers, mounted in supporting frames, 

and used where dust concentrations are relatively low. Fabric filters are usually made of 

woven or (more commonly) needle-punched felts sewn to the desired shape, mounted in 

a plenum with special hardware, and used across a wide range of dust concentrations.

The Process Area Coal/Coke Feed to Gasifier material handling step includes coal and 

coke handling systems inside the process block that deliver coal and/or coke to the 

gasifiers. There are two systems (one plus a spare). This system is smaller than the 

large conveyance system from the docks to the coal pile and is proposed to be controlled 

by a baghouse. The dry dust collected by the baghouse will be fed directly to the 

rodmills. Whereas the wastewater from a wet scrubbing system would have to be treated 

to increase the solids concentration before it could be fed to the rod mills in order to 

maintain the required high solids concentration in the slurry from the rod mill.

The ability to directly feed the collected dust to the rodmills minimizes the handling and 

storage of fine combustible dust and decreases the fire and explosion risk of a dry 

collection system. In some other instances, a dry collection system would be judged to 

be too high a safety risk for combustible dust control. However, in this service, with an 

available process outlet (the wet rodmill), the fire and explosion risk is significantly 

decreased. 
Indiana Gasification LLC Page 72 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

All of the material handling steps are ducted to the top of the feedstock silos (day bins) 

and have a single emissions point from the top/outlet of the silos. Only one dust 

collection system is in use at a time. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the use of a fabric filter is a technically feasible option for the Process 

Area Solid Feedstock Conveying, storage and feedbin (EU-011A/B) at this source.

(b) Wet Scrubber

A wet scrubber is an air pollution control device that removes particulates 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 particulates. 

Collection efficiencies for wet scrubbers vary with the particle size distribution of the 

waste gas stream. 

In general, collection efficiency decreases as the particulates size decreases. Collection 

efficiencies also vary with scrubber type. Collection efficiencies range from greater than 

90% 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 particulates with the following characteristics:

(1) Sticky and/or hygroscopic materials (materials that readily absorb water);

(2) Combustible, corrosive and explosive materials;

(3) Particles that are difficult to remove in their dry form;

(4) Particulates in the presence of soluble gases; and

(5) Particulates in waste gas streams with high moisture content.

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the use of a wet scrubber is a technically feasible option for the Process 

Area Solid Feedstock Conveying, storage and feedbin (EU-011A/B) at this source.

(c) Cyclones:

Cyclones are simple mechanical devices commonly used to remove relatively large 

particles from gas streams. In industrial applications, cyclones are often used as 

precleaners for the more sophisticated air pollution control equipment such as ESPs or 

baghouses. Cyclones are less efficient than wet scrubbers, baghouses, or ESPs. 

Cyclones used as pre-cleaners are often designed to remove more than 80% of the 

particles that are greater than 20 microns in diameter. Smaller particles that escape the 

cyclone can then be collected by more efficient control equipment. This control 

technology may be more commonly used in industrial sites that generate a considerable 

amount of particulate matter, such as lumber companies, feed mills, cement plants, and 

smelters.

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the use of a cyclone is a technically feasible option for the Process 

Area Solid Feedstock Conveying, storage and feedbin (EU-011A/B) at this source.
Indiana Gasification LLC Page 73 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

(d) Wet Suppression:

Wet suppression systems use liquid sprays or foam to suppress the formation of airborne 

dust. The primary control mechanisms are those that prevent emissions through 

agglomerate formation by combining small dust particles with larger aggregate or with 

liquid droplets. The key factors that affect the degree of agglomeration and, hence, the 

performance of the system are the coverage of the material by the liquid and the ability of 

the liquid to wet small particles. There are two types of wet suppression systems: liquid 

sprays which use water or water/surfactant mixtures as the wetting agent and systems 

which supply foams as the wetting agent. Wet suppression systems typically achieve PM

control efficiencies of greater than 85%

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the use of a wet suppression is a technically feasible option for the 

Process Area Solid Feedstock Conveying, storage and feedbin (EU-011A/B) at this 

source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The above control technologies have been identified for control of PM, PM10 and PM2.5 resulting 

from operation of a coal and coke handling system. 

(1) Fabric Filtration (≥ 99% PM/PM10/PM2.5 Reduction);

(2) Wet Scrubber (> 90% PM/PM10/PM2.5 Reduction);

(3) Wet Suppression (90% PM/PM10/PM2.5 Reduction); and 

(4) Cyclones (80% PM/PM10/PM2.5 Reduction). 

As shown above, baghouse achieves a control efficiency of greater than 99% versus the wet 

scrubber, wet suppression and cyclone control efficiency of 90%, 85% and 80%, respectively. 

Thus, the use of a baghouse is the top ranked control alternative for control of particulate matter 

emissions from the Process Area Solid Feedstock Conveying, storage and feedbin (EU-011A/B).

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for similar plants. All data in the table is 

based on the information obtained from the permit application submitted by Indiana Gasification, 

LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits 

available at the websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Process 

Area Solid 

Feedstock 

Conveying, 

storage and 

feedbin

10,400 T 

dry 

coal/day 

PM/PM10/: 

0.003 

gr/dscf

PM2.5: 

0.0015

gr/dscf

Baghouse

081801 AAF 

(Application 

No. 07100063)

Power Holdings of 

Illinois Gasification

10/26/2009 Coal-Coke 

Handling 

System (2 

identical 

facilities) *

13,722 T 

coal per 

day

0.001 

gr/dscf

Baghouse or 

similar 

control
Indiana Gasification LLC Page 74 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

T083-23529-

00003

Duke Energy 

Indiana -

Edwardsport

01/25/2008 Coal-Coke 

Handling 

System (2 

identical 

facilities)*

630 MW 0.003 

gr/dscf 

Baghouse

PSD-LA742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Coal-Coke 

Handling 

System (2 

identical 

facilities)*

9,413 T/D 0.005 

gr/dscf

Baghouse

28.0701-PSD Hyperion Energy 08/20/2009 Coal-Coke 

Handling 

System (2 

identical 

facilities)*

400,000 

bbl/day

0.005 

gr/dscf

Baghouse

Permit V-09-

006

Cash Creek 

Gasification

05/05/2010 Coal-Coke 

Handling 

System (2 

identical 

facilities)*

770 MW 0.005 

gr/dscf

Baghouse

NOTE: * These emission units have not been built yet.

The majority of the above baghouse systems are permitted with a performance specification of 

0.005 gr/dscf. This is consistent with almost all entries found in the RBLC database for 

baghouses and is standard design for an efficient baghouse. In special circumstances, 

baghouses can be designed to achieve even lower outlet PM, PM10 and PM2.5 emissions. 

Evidently, as shown in the above table, the Power Holdings and Duke Edwardsport gasification 

plants intend to have such systems for at least some of their material handling operations. 

However, this higher control efficiency comes at a significant additional cost.

According to IG’s engineering design firm, achieving 0.001 gr/dscf is very difficult and expensive 

for a bulk material handling baghouse. It is generally achievable with PTFE (Teflon) bags, very 

low air-to-cloth ratio (i.e.: requiring a large unit), a low pressure/high volume bag cleaning-type 

unit, bag cleaning on demand, and other such special features. It also critical that the air going 

through the dust collector always be above the dew point (PTFE bags will pass moisture vapor 

but condensed water droplets will blind the bags), so it can require heated structures, insulated 

ductwork, and heated and insulated dust collectors. All these elements come at additional 

expense. 

For this specific emissions source, the incremental costs to achieve 0.001 gr/dscf are 

unreasonably high for the small benefit obtained. This is illustrated in the below cost analysis 

which considers the estimated incremental capital and operating cost for each baghouse to 

achieve this extremely low emissions and shows that the cost-effectiveness is greater than 

$10,000/ton of PM controlled for this emission unit.
Indiana Gasification LLC Page 75 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Process Material Handling EU-011A&B Cost Effectiveness to achieve 0.001 gr/dscf

PM/PM10 

Emissions

Emissions 

Reduction

Control 

Capital Cost

Control 

Operating 

Cost/yr

Total 

Annualized 

Costs

Cost 

Effectiveness

Tons/yr tons/yr $ $/yr $/yr $/Ton

 Baghouse achieving 

0.001 gr/dscf 1.27 2.53 $33,760 $68,027 $72,753 $28,701

Increased energy for 

increased delta P, 

avoid condensation

Baseline - Baghouse 

controlling to 0.003 

gr/dscf

3.8 (proposed)

Control Alternative Other Impacts

(a) Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Process 

Area Solid Feedstock Conveying, storage and feedbin (EU-011A/B):

(1) The construction of a baghouse for control of PM, PM10 and PM2.5 emissions.

(2) The PM and PM10 maximum outlet concentration of 0.003 gr/dscf.

(3) The PM2.5 maximum outlet concentration of 0.0015 gr/dscf.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for Process Area Solid Feedstock Conveying, 

storage and feedbin (EU-011A/B).

(1) The PM, PM10 and PM2.5 emissions from the Process Area Solid Feedstock Conveying, 

storage and feedbin (EU-011A/B) shall be limited through a baghouse.

(2) The PM and PM10 maximum outlet concentration of 0.003 gr/dscf.

(3) The PM2.5 maximum outlet concentration of 0.0015 gr/dscf.

Particulate Matter (PM/PM10/PM2.5) BACT – Incoming Solid Feedstock Material Handling System -

Barge Unloading to Hopper Transfer Point (EU-012A)

Step 1: Identify Potential Control Technologies

The emissions of PM, PM10 and PM2.5 are generally controlled by the following add-on control 

equipment designed to capture the emissions prior to the time they are exhausted to the 

atmosphere:

(1) Fabric Filter Dust Collectors (Baghouses);

 (2) Wet Scrubber;

 (3) Cyclones; and

 (4) Wet Suppression.
Indiana Gasification LLC Page 76 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

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

The barge unloading operation handles bulk quantities of coal and coke unloading. Unloading of 

barges will be by clamshell crane from the shipping compartment to the hopper of the transfer 

conveyor. These unloading operations cannot reasonably be enclosed and vented to a control 

device due to the location outside and due to the extreme size involved. This eliminates the 

applicability of a collection (Baghouse, Wet Scrubber and Cyclone) and filtration equipment or 

other “add-on” controls.

The only remaining control for this material handling that is technically feasible is wet or chemical 

suppression. 

Wet Suppression:

Wet suppression systems use liquid sprays or foam to suppress the formation of airborne dust. 

The primary control mechanisms are those that prevent emissions through agglomerate formation 

by combining small dust particles with larger aggregate or with liquid droplets. The key factors 

that affect the degree of agglomeration and, hence, the performance of the system are the 

coverage of the material by the liquid and the ability of the liquid to wet small particles. There are 

two types of wet suppression systems: liquid sprays which use water or water/surfactant mixtures 

as the wetting agent and systems which supply foams as the wetting agent. Wet suppression 

systems typically achieve PM control efficiencies of greater than 85%

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a wet suppression is a technically feasible option for the Barge Unloading (EU-012A) at 

this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Wet Suppression (90% PM/PM10/PM2.5 Reduction). 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for coal handling facilities. All data in the 

table is based on the information obtained from the permit application submitted by Indiana 

Gasification, LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic 

versions of permits available at the websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued 

Date

Process Description Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification 

- proposed

Proposed Coal/Coke Barge 

Unloading 

10,400 T

dry 

coal/day 

90% control Wet or 

Chemical 

Suppression

IA-0089- Iowa Homeland 

Energy 

Solutions 

08/08/2007 Coal Receiving and 

handling

200 

tons/hr

None 

specified for 

unenclosed 

unloading 

area

water fogging 

to eliminate 

particulate in 

unloading 

area
Indiana Gasification LLC Page 77 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued 

Date

Process Description Rating 

(TPH)

Limitation Control 

Method

IA - 0086 -

Iowa

University of 

Northern Iowa

05/3/2007 Coal Pile 50,565 

tons/hr

PM/PM10: 

Must use dust 

suppressant 

to reduce 

fugitive 

emissions by 

95%

Chemical 

suppressant 

with 95% 

control

CO-0057 -

Colorado

Public Service 

Company of 

Colorado 

Comanche 

Station

07/05/2005 Coal handling and storage 

(includes open storage 

piles with lowering well, 

rail-car unloading, transfer 

from unloading to pile and 

transfer from pile to bunker)

NA None 

specified for 

unenclosed 

unloading 

area

Control 

include water 

spray, lower 

well, dust 

suppressant, 

enclosures 

where 

baghouse are 

not feasible

KY-0100 East Kentucky 

Power Coop. 

04/09/2010 Coal Pile, Rail Unloading 

Egress to Conveyor

3000 

tons per 

hr

10% opacity 

(3min)

Wet 

Suppression, 

Dust 

suppressant 

Lowering well 

and 

compaction

OH-0317 Ohio River 

Clean Fuels

11/20/2008 Coal Storage Piles 5500 

tons/hr

PM10:12.3 

tons per year. 

with 75% 

control.

3-sided 

windscreen 

barrier. 

Reduced drop 

heights. Use 

of chemical 

stabilization 

dust 

suppressants 

and/or 

watering to 

reduce any 

visible 

emissions.

NOTE: * These emission units have not been built yet.

Note: ** Compliance with the limit at this facility has not been demonstrated through stack testing.

The table above shows recent permit conditions for comparable facilities for material handling activities 

that can’t be enclosed. All these permits specify wet or chemical suppression, consistent with the 

source's proposal. Although most of the database entries do not specify the level of control, two of the 

listed entries specify 75% and 95%. Dependent on the amount and frequency of the application of wet 

suppression, various levels of control can theoretically be achieved by wet suppression. Control of 

greater than 90% is not normally considered practicable. 

(a) Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Barge 

Unloading to hopper transfer point (EU-012A):

(1) The PM, PM10 and PM2.5 emissions from the barge unloading to hopper transfer point 

shall be controlled by the use of wet suppression with a control efficiency of 90%.
Indiana Gasification LLC Page 78 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for barge unloading (EU-012A).

The PM, PM10 and PM2.5 emissions from the barge unloading to hopper transfer point (EU-012A)

operation shall be controlled by a wet suppression with a control efficiency of 90%.

Particulate Matter (PM/PM10/PM2.5) BACT – Rail Unloading to Rail Hoppers (EU-012G/H)

Step 1: Identify Potential Control Technologies

The emissions of PM, PM10 and PM2.5 are generally controlled by the following add-on control 

equipment, designed to capture the emissions prior to the time they are exhausted to the 

atmosphere:

(1) Fabric Filter Dust Collectors (Baghouses);

 (2) Electrostatic Precipitator (ESP);

 (3) Cyclones; and 

 (4) Wet Dust Extraction.

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

These material handling steps are fully enclosed and proposed to be vented through a dust 

control system. 

Fabric Filter (Baghouse)

 A baghouse fabric filter unit consists of one or more isolated compartments containing rows of 

fabric bags in the form of round, flat, or shaped tubes, or pleated cartridges. Particle laden gas 

passes up (usually) along the surface of the bags then radially through the fabric. Particles are 

retained on the upstream face of the bags, and the cleaned gas stream is vented to the 

atmosphere. The filter is operated cyclically, alternating between relatively long periods of filtering 

and short periods of cleaning. During cleaning, dust that has accumulated on the bags is 

removed from the fabric surface and deposited in a hopper for subsequent disposal. Fabric filters 

collect particles with sizes ranging from submicron to several hundred microns in diameter at 

efficiencies generally in excess of 99%. 

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 1 to 20 inches of water. 
Indiana Gasification LLC Page 79 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Fabric filters are used where high efficiency particle collection is required. Limitations are 

imposed by gas characteristics (temperature and corrosivity) and particle characteristics 

(primarily stickiness) that affect the fabric or its operation and that cannot be economically 

accommodated. Important process variables include particle characteristics, gas characteristics, 

and fabric properties. 

The most important design parameter is the air- or gas-to-cloth ratio (the amount of gas in ft3

/min 

that penetrates one 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 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.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a baghouse is a technically feasible option for the Railcar Unloading to Rail Hoppers 

(EU-012G/H) at this source.

Cyclones or ESPs

Use of add-on controls such as cyclones or electrostatic precipitators (ESP) is theoretically 

feasible, but they are not as effective as a baghouse or a wet extraction system, which is 

described next. Since they are no more effective than these control strategies, they are not 

considered further in this BACT analysis. 

Wet Dust Extraction

An alternative effective control system, is a wet extraction system. Such dust extraction systems 

are designed specifically for high-efficiency dust control. The design accomplishes this by 

spraying water into the air stream at the suction of a high volume fan. Using a combination of the 

energy of the fan and the water, the dust particles are trapped into finely atomized water droplets 

which are removed from the fan exhaust in an extractor panel and demister. Dust is expected to 

be controlled to the high efficiency of 99.7% for the IG facility. This alternative technology 

achieves a similar level of control as baghouses. However wastewater treatment and water 

freezing in cold weather result in higher maintenance and operating costs versus baghouses. 

Wet Dust Extraction System Technical Description

1. Stage 1: Water Injection: Dust laden air is drawn into the dust extractor fan where it is 

mixed with water that is discharged from the water spray nozzles. The dust-laden air is 

‘wetted’ by a mechanical action as it passes through the impeller, which is rotating at 

approx. 3600 rpm. The dust/water and air mixture then passes around the motor to an 

extractor panel.

2. Stage 2: Extractor Panel: The dust/water and air mixture passes through a woven mesh 

extractor panel. The mesh contains multiple layers knitmesh. The dust particle laden 

water is separated from the airstream within the panel and drains away. Additionally, the 

panel is periodically washed as needed by the action of a multi-nozzle spray bank. 

3. Stage 3: Demister Vanes: The ‘catchment’ or ‘demister’ vanes collect excess water and 

dust mixture that has not drained away in the extractor panel, so that there is little water 

carried through the unit ensuring only dry, clean air is exhausted.
Indiana Gasification LLC Page 80 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Wet Dust Extraction is a technically feasible option for the Railcar Unloading to Rail 

Hoppers (EU-012G/H) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Fabric Filter Dust Collectors (Baghouses) (>99% PM/PM10/PM2.5 Reduction);

 

(2) Wet Dust Extraction (>99% PM/PM10/PM2.5 Reduction). 

The two systems offer comparable control. IG proposes to use one or the other system to meet 

BACT for this source.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for coal handling operations. All data in the 

table is based on the information obtained from the permit application submitted by Indiana 

Gasification, LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic 

versions of permits available at the websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Coal/Coke 

Unloading and 

Conveyance

10,400 T 

dry 

coal/day 

PM/PM10: 

0.003 

gr/dscf

PM2.5: 

0.0015 

gr/dscf

Baghouse 

or Wet 

Dust 

Extraction

081801 AAF 

(Application 

No. 

07100063)

Power 

Holdings of 

Illinois 

Gasification

10/26/2009 Coal-Coke Handling 

System (2 identical 

facilities) *

13,722 T 

coal per 

day

0.001 gr/dscf Baghouse or 

similar 

control

T083-23529-

00003

Duke Energy 

Indiana -

Edwardsport

01/25/2008 Coal-Coke Handling 

System (2 identical 

facilities)*

630 MW 0.003 gr/dscf Baghouse

PSD-LA742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Coal-Coke Handling 

System (2 identical 

facilities)*

9,413 

T/D

0.005 gr/dscf Baghouse

28.0701-PSD Hyperion 

Energy

08/20/2009 Coal-Coke Handling 

System (2 identical 

facilities)*

400,000 

bbl/day

0.005 gr/dscf Baghouse

Permit V-09-

006

Cash Creek 

Gasification

05/05/2010 Coal-Coke Handling 

System (2 identical 

facilities)*

770 MW 0.005 gr/dscf Baghouse

NOTE: * These emission units have not been built yet.

The majority of the above baghouse systems are permitted with a performance specification of 

0.005 gr/dscf. This is consistent with almost all entries found in the RBLC database for 

baghouses and is standard design for an efficient baghouse. In special circumstances, 

baghouses can be designed to achieve even lower outlet PM, PM10 and PM2.5 emissions. 

Evidently, as shown in the above table, the Power Holdings and Duke Edwardsport gasification 

plants intend to have such systems for at least some of their material handling operations. 

However, this higher control efficiency comes at a significant additional cost.
Indiana Gasification LLC Page 81 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

According to IG’s engineering design firm, achieving 0.001 gr/dscf is very difficult and expensive 

for a bulk material handling baghouse. It is generally achievable with PTFE (Teflon) bags, very 

low air-to-cloth ratio (i.e.: requiring a large unit), a low pressure/high volume bag cleaning-type 

unit, bag cleaning on demand, and other such special features. It also critical that the air going 

through the dust collector always be above the dew point (PTFE bags will pass moisture vapor 

but condensed water droplets will blind the bags), so it can require heated structures, insulated 

ductwork, and heated and insulated dust collectors. All these elements come at additional 

expense. 

For this specific emissions source, the incremental costs to achieve 0.001 gr/dscf are 

unreasonably high for the small benefit obtained. This is illustrated in the below cost analysis 

which considers the estimated incremental capital and operating cost for each baghouse to 

achieve this extremely low emissions and shows that the cost-effectiveness is greater than 

$10,000/ton of PM controlled for this emission unit.

Incoming Material Handling EU-012 B-O, T-AC (each 1500 acf/m units) Cost Effectiveness to achieve 0.001 gr/dscf

PM/PM10 

Emissions 

(if 8760 

hr/yr)

Emissions 

Reduction

Control 

Capital Cost

Control 

Operating 

Cost/yr

Total 

Annualized 

Costs

Cost 

Effectiveness

Tons/yr tons/yr $ $/yr $/yr $/Ton

 Baghouse achieving 

0.001 gr/dscf 0.06 0.11 $1,500 $12,090 $3,233 $28,701

Increased energy for 

increased delta P, 

avoid condensation

Baseline - Baghouse 

controlling to 0.003 

gr/dscf

0.17 (proposed)

(Note: unit will not operate 8760 hr/yr, so estimated emissions are overstated and cost/ton controlled will actually be higher. )

Control Alternative Other Impacts

(a) Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Rail

Unloading to Rail Hoppers (EU-012G/H):

(1) The PM, PM10 and PM2.5 emissions from the railcar unloading to rail hoppers shall be 

controlled by either wet dust extraction or a baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for the Railcar Unloading (EU-012G/H).

(1) The PM, PM10 and PM2.5 emissions from the railcar unloading to rail hoppers shall be 

controlled by wet dust extraction or a baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.
Indiana Gasification LLC Page 82 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Particulate Matter (PM/PM10/PM2.5) BACT –Barge Unloading from the Hopper to the Belt (EU-012B) 

and Barge Conveyor Transfer Points (EU-012C-F)

Step 1: Identify Potential Control Technologies

The emissions of PM, PM10 and PM2.5 are generally controlled by the following add-on control 

equipment designed to capture the emissions prior to the time they are exhausted to the 

atmosphere:

(1) Fabric Filter Dust Collectors (Baghouses);

 (2) Electrostatic Precipitator (ESP);

 (3) Cyclones; and 

 (4) Wet Dust Extraction.

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

These material handling steps are fully enclosed and proposed to be vented through a dust 

control system.

 

Fabric Filter (Baghouse)

 A baghouse fabric filter unit consists of one or more isolated compartments containing rows of 

fabric bags in the form of round, flat, or shaped tubes, or pleated cartridges. Particle laden gas 

passes up (usually) along the surface of the bags then radially through the fabric. Particles are 

retained on the upstream face of the bags, and the cleaned gas stream is vented to the 

atmosphere. The filter is operated cyclically, alternating between relatively long periods of filtering 

and short periods of cleaning. During cleaning, dust that has accumulated on the bags is 

removed from the fabric surface and deposited in a hopper for subsequent disposal. Fabric filters 

collect particles with sizes ranging from submicron to several hundred microns in diameter at 

efficiencies generally in excess of 99%. 

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 1 to 20 inches of water. 

Fabric filters are used where high efficiency particle collection is required. Limitations are 

imposed by gas characteristics (temperature and corrosivity) and particle characteristics 

(primarily stickiness) that affect the fabric or its operation and that cannot be economically 

accommodated. Important process variables include particle characteristics, gas characteristics, 

and fabric properties. 

The most important design parameter is the air- or gas-to-cloth ratio (the amount of gas in ft3

/min 

that penetrates one ft2 of fabric) and the usual operating parameter of interest is pressure drop 

across the filter system. The major operating feature of fabric filters that distinguishes them from 

other gas filters is the ability to renew the filtering surface periodically by cleaning. Common 

furnace filters, high efficiency particulate air (HEPA) filters, high efficiency air filters (HEAFs), and 

automotive induction air filters are examples of filters that must be discarded after a significant 
Indiana Gasification LLC Page 83 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

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.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a baghouse is a technically feasible option for the Conveyance from Barge Hopper to 

pile Stacker (EU-012B-F) at this source.

Cyclones or ESPs

Use of add-on controls such as cyclones or electrostatic precipitators (ESP) is theoretically 

feasible, but they are not as effective as a baghouse or wet extraction system, which is described 

next. Since they are no more effective than the proposed control strategy, they are not 

considered further in this BACT analysis. 

Wet Dust Extraction

Wet dust extraction systems are designed specifically for high-efficiency dust control. The design 

accomplishes this by spraying water into the air stream at the suction of a high volume fan. Using 

a combination of the energy of the fan and the water, the dust particles are trapped into finely 

atomized water droplets which are removed from the fan exhaust in an extractor panel and 

demister. Dust is expected to be controlled to the high efficiency of 99.7% for the IG facility. This 

alternative technology achieves a similar level of control as baghouses. However wastewater 

treatment and water freezing in cold weather result in higher maintenance and operating costs 

versus baghouses. 

Wet Dust Extraction System Technical Description

1. Stage 1: Water Injection: Dust laden air is drawn into the dust extractor fan where it is 

mixed with water that is discharged from the water spray nozzles. The dust-laden air is 

‘wetted’ by a mechanical action as it passes through the impeller, which is rotating at 

approx. 3600 rpm. The dust/water and air mixture then passes around the motor to an 

extractor panel.

2. Stage 2: Extractor Panel: The dust/water and air mixture passes through a woven mesh 

extractor panel. The mesh contains multiple layers knitmesh. The dust particle laden 

water is separated from the airstream within the panel and drains away. Additionally, the 

panel is periodically washed as needed by the action of a multi-nozzle spray bank. 

3. Stage 3: Demister Vanes: The ‘catchment’ or ‘demister’ vanes collect excess water and 

dust mixture that has not drained away in the extractor panel, so that there is little water 

carried through the unit ensuring only dry, clean air is exhausted.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Wet Dust Extraction is a technically feasible option for the Conveyance from Barge 

Hopper to pile Stacker (EU-012B-F) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Baghouse fabric filter (>99% PM/PM10/PM2.5 Reduction)

(2) Wet Dust Extraction (≥ 99% PM/PM10/PM2.5 Reduction). 
Indiana Gasification LLC Page 84 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for coal handling operations. All data in the 

table is based on the information obtained from the permit application submitted by Indiana 

Gasification, LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic 

versions of permits available at the websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Coal/Coke 

Conveyance

10,400 T 

dry 

coal/day

PM/PM10: 

0.003 

gr/dscf

PM2.5: 

0.0015 

gr/dscf

Baghouse or 

Wet Dust 

Extraction

081801 AAF 

(Application 

No. 

07100063)

Power 

Holdings of 

Illinois 

Gasification

10/26/2009 Coal-Coke Handling 

System (2 identical 

facilities) *

13,722 T 

coal per 

day

0.001 gr/dscf Baghouse or 

similar control

T083-23529-

00003

Duke Energy 

Indiana -

Edwardsport

01/25/2008 Coal-Coke Handling 

System (2 identical 

facilities)*

630 MW 0.003 gr/dscf Baghouse

PSD-LA742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Coal-Coke Handling 

System (2 identical 

facilities)*

9,413 

T/D

0.005 gr/dscf Baghouse

28.0701-PSD Hyperion 

Energy

08/20/2009 Coal-Coke Handling 

System (2 identical 

facilities)*

400,000 

bbl/day

0.005 gr/dscf Baghouse

Permit V-09-

006

Cash Creek 

Gasification

05/05/2010 Coal-Coke Handling 

System (2 identical 

facilities)*

770 MW 0.005 gr/dscf Baghouse

NOTE: * These emission units have not been built yet.

The majority of the above baghouse systems are permitted with a performance specification of 

0.005 gr/dscf. This is consistent with almost all entries found in the RBLC database for 

baghouses and is standard design for an efficient baghouse. In special circumstances, 

baghouses can be designed to achieve even lower outlet PM, PM10 and PM2.5 emissions. 

Evidently, as shown in the above table, the Power Holdings and Duke Edwardsport gasification 

plants intend to have such systems for at least some of their material handling operations. 

However, this higher control efficiency comes at a significant additional cost.

According to IG’s engineering design firm, achieving 0.001 gr/dscf is very difficult and expensive 

for a bulk material handling baghouse. It is generally achievable with PTFE (Teflon) bags, very 

low air-to-cloth ratio (i.e.: requiring a large unit), a low pressure/high volume bag cleaning-type 

unit, bag cleaning on demand, and other such special features. It also critical that the air going 

through the dust collector always be above the dew point (PTFE bags will pass moisture vapor 

but condensed water droplets will blind the bags), so it can require heated structures, insulated 

ductwork, and heated and insulated dust collectors. All these elements come at additional 

expense. 

For this specific emissions source, the incremental costs to achieve 0.001 gr/dscf are 

unreasonably high for the small benefit obtained. This is illustrated in the below cost analysis 

which considers the estimated incremental capital and operating costs for each baghouse to 

achieve this extremely low emissions and shows that the cost-effectiveness is greater than 

$10,000/ton of PM controlled for this emission unit.
Indiana Gasification LLC Page 85 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Incoming Material Handling EU-012 B-O, T-AC (each 1500 acf/m units) Cost Effectiveness to achieve 0.001 gr/dscf

PM/PM10 

Emissions 

(if 8760 

hr/yr)

Emissions 

Reduction

Control 

Capital Cost

Control 

Operating 

Cost/yr

Total 

Annualized 

Costs

Cost 

Effectiveness

Tons/yr tons/yr $ $/yr $/yr $/Ton

 Baghouse achieving 

0.001 gr/dscf 0.06 0.11 $1,500 $12,090 $3,233 $28,701

Increased energy for 

increased delta P, 

avoid condensation

Baseline - Baghouse 

controlling to 0.003 

gr/dscf

0.17 (proposed)

(Note: unit will not operate 8760 hr/yr, so estimated emissions are overstated and cost/ton controlled will actually be higher. )

Control Alternative Other Impacts

(a) Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Barge 

Unloading from the Hopper to the Belt (EU-012B) and Barge Conveyor Transfer Points (EU012C-F):

(1) The PM, PM10 and PM2.5 emissions from the Barge Unloading from the Hopper to the 

Belt (EU-012B) and Barge Conveyor Transfer Points (EU-012C-F) shall be controlled by 

a wet dust extraction or a baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for the Conveyance from barge Hopper to Pile 

Stacker (EU-012B-F).

(1) The PM, PM10 and PM2.5 emissions from the Barge Unloading from the Hopper to the 

Belt (EU-012B) and Barge Conveyor Transfer Points (EU-012C-F) shall be controlled by 

a wet dust extraction or a baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Particulate Matter (PM/PM10/PM2.5) BACT –Rail Hoppers Unloading to the Conveyor Belts 

(EU-012I-J) and Rail Conveyor Belt to the Stacker (EU-012K)

Step 1: Identify Potential Control Technologies

The emissions of PM, PM10 and PM2.5 are generally controlled by the following add-on control 

equipment designed to capture the emissions prior to the time they are exhausted to the 

atmosphere:

(1) Fabric Filter Dust Collectors (Baghouses);

 (2) Electrostatic Precipitator (ESP);
Indiana Gasification LLC Page 86 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

 (3) Cyclones; and 

 (4) Wet Dust Extraction.

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

These material handling steps are fully enclosed and proposed to be vented through a dust 

control system. 

Fabric Filter (Baghouse)

 A baghouse fabric filter unit consists of one or more isolated compartments containing rows of 

fabric bags in the form of round, flat, or shaped tubes, or pleated cartridges. Particle laden gas 

passes up (usually) along the surface of the bags then radially through the fabric. Particles are 

retained on the upstream face of the bags, and the cleaned gas stream is vented to the 

atmosphere. The filter is operated cyclically, alternating between relatively long periods of filtering 

and short periods of cleaning. During cleaning, dust that has accumulated on the bags is 

removed from the fabric surface and deposited in a hopper for subsequent disposal. Fabric filters 

collect particles with sizes ranging from submicron to several hundred microns in diameter at 

efficiencies generally in excess of 99%. 

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 1 to 20 inches of water. 

Fabric filters are used where high efficiency particle collection is required. Limitations are 

imposed by gas characteristics (temperature and corrosivity) and particle characteristics 

(primarily stickiness) that affect the fabric or its operation and that cannot be economically 

accommodated. Important process variables include particle characteristics, gas characteristics, 

and fabric properties. 

The most important design parameter is the air- or gas-to-cloth ratio (the amount of gas in ft3

/min 

that penetrates one ft2 of fabric) and the usual operating parameter of interest is pressure drop 

across the filter system. The major operating feature of fabric filters that distinguishes them from 

other gas filters is the ability to renew the filtering surface periodically by cleaning. Common 

furnace filters, high efficiency particulate air (HEPA) filters, high efficiency air filters (HEAFs), and 

automotive induction air filters are examples of filters that must be discarded after a significant 

layer of dust accumulates on the surface. These filters are typically made of matted fibers, 

mounted in supporting frames, and used where dust concentrations are relatively low. Fabric 

filters are usually made of woven or (more commonly) needle-punched felts sewn to the desired 

shape, mounted in a plenum with special hardware, and used across a wide range of dust 

concentrations.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a baghouse is a technically feasible option for the Conveyance from Rail Hopper to pile 

Stacker (EU-012I-K) at this source.
Indiana Gasification LLC Page 87 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Cyclones or ESPs

Use of add-on controls such as cyclones or electrostatic precipitators (ESP) is theoretically 

feasible, but they are not as effective as proposed baghouse or a wet extraction system, which is 

described next. Since they are no more effective than the proposed control strategy, they are not 

considered further in this BACT analysis. 

Wet Dust Extraction

Wet dust extraction systems are designed specifically for high-efficiency dust control. The design 

accomplishes this by spraying water into the air stream at the suction of a high volume fan. Using 

a combination of the energy of the fan and the water, the dust particles are trapped into finely 

atomized water droplets which are removed from the fan exhaust in an extractor panel and 

demister. Dust is expected to be controlled to the high efficiency of 99.7% for the IG facility. This 

alternative technology achieves a similar level of control as baghouses. However wastewater 

treatment and water freezing in cold weather result in higher maintenance and operating costs 

versus baghouses. 

Wet Dust Extraction System Technical Description

1. Stage 1: Water Injection: Dust laden air is drawn into the dust extractor fan where it is 

mixed with water that is discharged from the water spray nozzles. The dust-laden air is 

‘wetted’ by a mechanical action as it passes through the impeller, which is rotating at 

approx. 3600 rpm. The dust/water and air mixture then passes around the motor to an 

extractor panel.

2. Stage 2: Extractor Panel: The dust/water and air mixture passes through a woven mesh 

extractor panel. The mesh contains multiple layers knitmesh. The dust particle laden 

water is separated from the airstream within the panel and drains away. Additionally, the 

panel is periodically washed as needed by the action of a multi-nozzle spray bank. 

3. Stage 3: Demister Vanes: The ‘catchment’ or ‘demister’ vanes collect excess water and 

dust mixture that has not drained away in the extractor panel, so that there is little water 

carried through the unit ensuring only dry, clean air is exhausted.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Wet Dust Extraction is a technically feasible option for the Conveyance from Rail 

Hopper to pile Stacker (EU-012I-K) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Baghouse fabric filter (>99% PM/PM10/PM2.5 Reduction)

(2) Wet Dust Extraction (≥ 99% PM/PM10/PM2.5 Reduction). 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for coal handling operations. All data in the 

table is based on the information obtained from the permit application submitted by Indiana 

Gasification, LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic 

versions of permits available at the websites of other permitting agencies.
Indiana Gasification LLC Page 88 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Coal/Coke 

Conveyance

10,400 T 

dry 

coal/day

PM/PM10:

0.003 gr/dscf

PM2.5: 

0.0015 

gr/dscf

Baghouse 

or Wet Dust 

Extraction

081801 AAF 

(Application 

No. 

07100063)

Power 

Holdings of 

Illinois 

Gasification

10/26/2009 Coal-Coke 

Handling System 

(2 identical 

facilities) *

13,722 T 

coal per 

day

0.001 gr/dscf Baghouse or 

similar control

T083-23529-

00003

Duke Energy 

Indiana -

Edwardsport

01/25/2008 Coal-Coke 

Handling System 

(2 identical 

facilities)*

630 MW 0.003 gr/dscf Baghouse

PSD-LA742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Coal-Coke 

Handling System 

(2 identical 

facilities)*

9,413 T/D 0.005 gr/dscf Baghouse

28.0701-PSD Hyperion 

Energy

08/20/2009 Coal-Coke 

Handling System 

(2 identical 

facilities)*

400,000 

bbl/day

0.005 gr/dscf Baghouse

Permit V-09-

006

Cash Creek 

Gasification

05/05/2010 Coal-Coke 

Handling System 

(2 identical 

facilities)*

770 MW 0.005 gr/dscf Baghouse

NOTE: * These emission units have not been built yet.

The majority of the above baghouse systems are permitted with a performance specification of 

0.005 gr/dscf. This is consistent with almost all entries found in the RBLC database for 

baghouses and is standard design for an efficient baghouse. In special circumstances, 

baghouses can be designed to achieve even lower outlet PM, PM10 and PM2.5 emissions. 

Evidently, as shown in the above table, the Power Holdings and Duke Edwardsport gasification 

plants intend to have such systems for at least some of their material handling operations. 

However, this higher control efficiency comes at a significant additional cost.

According to IG’s engineering design firm, achieving 0.001 gr/dscf is very difficult and expensive 

for a bulk material handling baghouse. It is generally achievable with PTFE (Teflon) bags, very 

low air-to-cloth ratio (i.e.: requiring a large unit), a low pressure/high volume bag cleaning-type 

unit, bag cleaning on demand, and other such special features. It also critical that the air going 

through the dust collector always be above the dew point (PTFE bags will pass moisture vapor 

but condensed water droplets will blind the bags), so it can require heated structures, insulated 

ductwork, and heated and insulated dust collectors. All these elements come at additional 

expense. 

For this specific emissions source, the incremental costs to achieve 0.001 gr/dscf are 

unreasonably high for the small benefit obtained. This is illustrated in the below cost analysis 

which considers the estimated incremental capital and operating costs for each baghouse to 

achieve this extremely low emissions and shows that the cost-effectiveness is greater than 

$10,000/ton of PM controlled for this emission unit.
Indiana Gasification LLC Page 89 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Incoming Material Handling EU-012 B-O, T-AC (each 1500 acf/m units) Cost Effectiveness to achieve 0.001 gr/dscf

PM/PM10 

Emissions 

(if 8760 

hr/yr)

Emissions 

Reduction

Control 

Capital Cost

Control 

Operating 

Cost/yr

Total 

Annualized 

Costs

Cost 

Effectiveness

Tons/yr tons/yr $ $/yr $/yr $/Ton

 Baghouse achieving 

0.001 gr/dscf 0.06 0.11 $1,500 $12,090 $3,233 $28,701

Increased energy for 

increased delta P, 

avoid condensation

Baseline - Baghouse 

controlling to 0.003 

gr/dscf

0.17 (proposed)

(Note: unit will not operate 8760 hr/yr, so estimated emissions are overstated and cost/ton controlled will actually be higher. )

Control Alternative Other Impacts

(a) Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Rail 

Hopper Unloading to the Conveyor Belts (EU-012I-J) and Rail Conveyor Belt to the Stacker (EU012K):

(1) The PM, PM10 and PM2.5 emissions shall be controlled by a wet dust extraction or a 

baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for the Rail Hopper Unloading to the Conveyor 

Belts (EU-012I-J) and Rail Conveyor Belt to the Stacker (EU-012K):

(1) The PM, PM10 and PM2.5 emissions shall be controlled by a wet dust extraction or 

baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Particulate Matter (PM/PM10/PM2.5) BACT – Stacker Belts to the Radial Stacker (EU-012 L- M)

Step 1: Identify Potential Control Technologies

The emissions of PM, PM10 and PM2.5 are generally controlled by the following add-on control 

equipment designed to capture the emissions prior to the time they are exhausted to the 

atmosphere:

(1) Fabric Filter Dust Collectors (Baghouses);

 (2) Electrostatic Precipitator (ESP);

 (3) Cyclones; and 

 (4) Wet Dust Extraction.
Indiana Gasification LLC Page 90 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

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

These material handling steps are fully enclosed and proposed to be vented through a dust 

control system. 

Fabric Filter (Baghouse)

 A baghouse fabric filter unit consists of one or more isolated compartments containing rows of 

fabric bags in the form of round, flat, or shaped tubes, or pleated cartridges. Particle laden gas 

passes up (usually) along the surface of the bags then radially through the fabric. Particles are 

retained on the upstream face of the bags, and the cleaned gas stream is vented to the 

atmosphere. The filter is operated cyclically, alternating between relatively long periods of filtering 

and short periods of cleaning. During cleaning, dust that has accumulated on the bags is 

removed from the fabric surface and deposited in a hopper for subsequent disposal. Fabric filters 

collect particles with sizes ranging from submicron to several hundred microns in diameter at 

efficiencies generally in excess of 99%. 

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 1 to 20 inches of water. 

Fabric filters are used where high efficiency particle collection is required. Limitations are 

imposed by gas characteristics (temperature and corrosivity) and particle characteristics 

(primarily stickiness) that affect the fabric or its operation and that cannot be economically 

accommodated. Important process variables include particle characteristics, gas characteristics, 

and fabric properties. 

The most important design parameter is the air- or gas-to-cloth ratio (the amount of gas in ft3

/min 

that penetrates one ft2 of fabric) and the usual operating parameter of interest is pressure drop 

across the filter system. The major operating feature of fabric filters that distinguishes them from 

other gas filters is the ability to renew the filtering surface periodically by cleaning. Common 

furnace filters, high efficiency particulate air (HEPA) filters, high efficiency air filters (HEAFs), and 

automotive induction air filters are examples of filters that must be discarded after a significant 

layer of dust accumulates on the surface. These filters are typically made of matted fibers, 

mounted in supporting frames, and used where dust concentrations are relatively low. Fabric 

filters are usually made of woven or (more commonly) needle-punched felts sewn to the desired 

shape, mounted in a plenum with special hardware, and used across a wide range of dust 

concentrations.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a baghouse is a technically feasible option for the Conveyance from Stacker Belt to 

Stacker (EU-012 L-M) at this source.

Cyclones or ESPs

Use of add-on controls such as cyclones or electrostatic precipitators (ESP) is theoretically 

feasible, but they are not as effective as the proposed baghouse or wet extraction system, which 

is described next. Since they are no more effective than the proposed control strategy, they are 

not considered further in this BACT analysis. 
Indiana Gasification LLC Page 91 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Wet Dust Extraction

Wet dust extraction systems are designed specifically for high-efficiency dust control. The design 

accomplishes this by spraying water into the air stream at the suction of a high volume fan. Using 

a combination of the energy of the fan and the water, the dust particles are trapped into finely 

atomized water droplets which are removed from the fan exhaust in an extractor panel and 

demister. Dust is expected to be controlled to the high efficiency of 99.7% for the IG facility. This 

alternative technology achieves a similar level of control as baghouses. However wastewater 

treatment and water freezing in cold weather result in higher maintenance and operating costs 

versus baghouses. 

Wet Dust Extraction System Technical Description

1. Stage 1: Water Injection: Dust laden air is drawn into the dust extractor fan where it is 

mixed with water that is discharged from the water spray nozzles. The dust-laden air is 

‘wetted’ by a mechanical action as it passes through the impeller, which is rotating at 

approx. 3600 rpm. The dust/water and air mixture then passes around the motor to an 

extractor panel.

2. Stage 2: Extractor Panel: The dust/water and air mixture passes through a woven mesh 

extractor panel. The mesh contains multiple layers knitmesh. The dust particle laden 

water is separated from the airstream within the panel and drains away. Additionally, the 

panel is periodically washed as needed by the action of a multi-nozzle spray bank. 

3. Stage 3: Demister Vanes: The ‘catchment’ or ‘demister’ vanes collect excess water and 

dust mixture that has not drained away in the extractor panel, so that there is little water 

carried through the unit ensuring only dry, clean air is exhausted.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Wet Dust Extraction is a technically feasible option for the Conveyance from Stacker 

Belt to Stacker (EU-012 L-M) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Baghouse fabric filter (>99% PM/PM10/PM2.5 Reduction)

(2) Wet Dust Extraction (≥ 99% PM/PM10/PM2.5 Reduction). 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for coal handling operations. All data in the 

table is based on the information obtained from the permit application submitted by Indiana 

Gasification, LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic 

versions of permits available at the websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued 

Date

Process Description Rating (TPH) Limitation Control 

Method

Draft Permit 

No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification 

- proposed

Proposed Coal/Coke 

Conveyance

10,400 T dry 

coal/day

PM/PM10: 

0.003 gr/dscf

PM2.5: 

0.0015 

gr/dscf

Baghouse 

or Wet 

Dust 

Extraction

081801 AAF 

(Application 

No. 

Power 

Holdings of 

Illinois 

10/26/2009 Coal-Coke Handling 

System (2 identical 

facilities) *

13,722 T coal 

per day

0.001 gr/dscf Baghouse or 

similar 

control
Indiana Gasification LLC Page 92 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued 

Date

Process Description Rating (TPH) Limitation Control 

Method

07100063) Gasification

T083-23529-

00003

Duke Energy 

Indiana -

Edwardsport

01/25/2008 Coal-Coke Handling 

System (2 identical 

facilities)*

630 MW 0.003 gr/dscf Baghouse

PSD-LA742(M1) 

Louisiana

Lake Charles 

Cogeneration

, LLC

12/30/2010 Coal-Coke Handling 

System (2 identical 

facilities)*

9,413 T/D 0.005 gr/dscf Baghouse

28.0701-PSD Hyperion 

Energy

08/20/2009 Coal-Coke Handling 

System (2 identical 

facilities)*

400,000 

bbl/day

0.005 gr/dscf Baghouse

Permit V-09-

006

Cash Creek 

Gasification

05/05/2010 Coal-Coke Handling 

System (2 identical 

facilities)*

770 MW 0.005 gr/dscf Baghouse

NOTE: * These emission units have not been built yet.

The majority of the above baghouse systems are permitted with a performance specification of 

0.005 gr/dscf. This is consistent with almost all entries found in the RBLC database for 

baghouses and is standard design for an efficient baghouse. In special circumstances, 

baghouses can be designed to achieve even lower outlet PM, PM10 and PM2.5 emissions. 

Evidently, as shown in the above table, the Power Holdings and Duke Edwardsport gasification 

plants intend to have such systems for at least some of their material handling operations. 

However, this higher control efficiency comes at a significant additional cost.

According to IG’s engineering design firm, achieving 0.001 gr/dscf is very difficult and expensive 

for a bulk material handling baghouse. It is generally achievable with PTFE (Teflon) bags, very 

low air-to-cloth ratio (i.e.: requiring a large unit), a low pressure/high volume bag cleaning-type 

unit, bag cleaning on demand, and other such special features. It also critical that the air going 

through the dust collector always be above the dew point (PTFE bags will pass moisture vapor 

but condensed water droplets will blind the bags), so it can require heated structures, insulated 

ductwork, and heated and insulated dust collectors. All these elements come at additional 

expense. 

For this specific emissions source, the incremental costs to achieve 0.001 gr/dscf are 

unreasonably high for the small benefit obtained. This is illustrated in the below cost analysis 

which considers the estimated incremental capital and operating costs for each baghouse to 

achieve this extremely low emissions and shows that the cost-effectiveness is greater than 

$10,000/ton of PM controlled for this emission unit.

Incoming Material Handling EU-012 B-O, T-AC (each 1500 acf/m units) Cost Effectiveness to achieve 0.001 gr/dscf

PM/PM10 

Emissions 

(if 8760 

hr/yr)

Emissions 

Reduction

Control 

Capital Cost

Control 

Operating 

Cost/yr

Total 

Annualized 

Costs

Cost 

Effectiveness

Tons/yr tons/yr $ $/yr $/yr $/Ton

 Baghouse achieving 

0.001 gr/dscf 0.06 0.11 $1,500 $12,090 $3,233 $28,701

Increased energy for 

increased delta P, 

avoid condensation

Baseline - Baghouse 

controlling to 0.003 

gr/dscf

0.17 (proposed)

(Note: unit will not operate 8760 hr/yr, so estimated emissions are overstated and cost/ton controlled will actually be higher. )

Control Alternative Other Impacts

(a)
Indiana Gasification LLC Page 93 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Stacker 

Belts to the Radial Stacker (EU-012 L-M):

(1) The PM, PM10 and PM2.5 emissions from the Stacker Belts to the Radial Stacker shall be 

controlled by a wet dust extraction or a baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for the Stacker Belt to Stacker (EU-012L-M).

(1) The PM, PM10 and PM2.5 emissions from the Stacker Belts to the Radial Stacker shall be 

controlled by a wet dust extraction or a baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Particulate Matter (PM/PM10/PM2.5) BACT – Transfer systems consisting of hoppers and conveyor 

belts transferring feed stock from the piles to classification towers (EU – 012R-S); Classification 

towers (EU-012T-U); and Classification tower to a day bin (EU-012V)

Step 1: Identify Potential Control Technologies

The emissions of PM, PM10 and PM2.5 are generally controlled by the following add-on control 

equipment designed to capture the emissions prior to the time they are exhausted to the 

atmosphere:

(1) Fabric Filter Dust Collectors (Baghouses);

 (2) Electrostatic Precipitator (ESP);

 (3) Cyclones; and 

 (4) Wet Dust Extraction.

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

These material handling steps are fully enclosed and proposed to be vented through a dust 

control system. 
Indiana Gasification LLC Page 94 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Fabric Filter (Baghouse)

 A baghouse fabric filter unit consists of one or more isolated compartments containing rows of 

fabric bags in the form of round, flat, or shaped tubes, or pleated cartridges. Particle laden gas 

passes up (usually) along the surface of the bags then radially through the fabric. Particles are 

retained on the upstream face of the bags, and the cleaned gas stream is vented to the 

atmosphere. The filter is operated cyclically, alternating between relatively long periods of filtering 

and short periods of cleaning. During cleaning, dust that has accumulated on the bags is 

removed from the fabric surface and deposited in a hopper for subsequent disposal. Fabric filters 

collect particles with sizes ranging from submicron to several hundred microns in diameter at 

efficiencies generally in excess of 99%. 

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 1 to 20 inches of water. 

Fabric filters are used where high efficiency particle collection is required. Limitations are 

imposed by gas characteristics (temperature and corrosivity) and particle characteristics 

(primarily stickiness) that affect the fabric or its operation and that cannot be economically 

accommodated. Important process variables include particle characteristics, gas characteristics, 

and fabric properties. 

The most important design parameter is the air- or gas-to-cloth ratio (the amount of gas in ft3

/min 

that penetrates one ft2 of fabric) and the usual operating parameter of interest is pressure drop 

across the filter system. The major operating feature of fabric filters that distinguishes them from 

other gas filters is the ability to renew the filtering surface periodically by cleaning. Common 

furnace filters, high efficiency particulate air (HEPA) filters, high efficiency air filters (HEAFs), and 

automotive induction air filters are examples of filters that must be discarded after a significant 

layer of dust accumulates on the surface. These filters are typically made of matted fibers, 

mounted in supporting frames, and used where dust concentrations are relatively low. Fabric 

filters are usually made of woven or (more commonly) needle-punched felts sewn to the desired 

shape, mounted in a plenum with special hardware, and used across a wide range of dust 

concentrations.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a baghouse is a technically feasible option for the Transfer systems consisting of 

hoppers and conveyor belts transferring feed stock from the piles to classification towers (EU –

012R-S); Classification towers (EU-012T-U); and Classification tower to a day bin (EU-012V) at 

this source.

Cyclones or ESPs

Use of add-on controls such as cyclones or electrostatic precipitators (ESP) is theoretically 

feasible, but they are not as effective as a baghouse or a wet extraction system, which is 

described next. Since they are no more effective than the proposed control strategy, they are not 

considered further in this BACT analysis. 

Wet Dust Extraction

Wet dust extraction systems are designed specifically for high-efficiency dust control. The design 

accomplishes this by spraying water into the air stream at the suction of a high volume fan. Using 

a combination of the energy of the fan and the water, the dust particles are trapped into finely 

atomized water droplets which are removed from the fan exhaust in an extractor panel and 

demister. Dust is expected to be controlled to the high efficiency of 99.7% for the IG facility. This 

alternative technology achieves a similar level of control as baghouses. However wastewater 
Indiana Gasification LLC Page 95 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

treatment and water freezing in cold weather result in higher maintenance and operating costs 

versus baghouses. 

Wet Dust Extraction System Technical Description:

1. Stage 1: Water Injection: Dust laden air is drawn into the dust extractor fan where it is 

mixed with water that is discharged from the water spray nozzles. The dust-laden air is 

‘wetted’ by a mechanical action as it passes through the impeller, which is rotating at 

approx. 3600 rpm. The dust/water and air mixture then passes around the motor to an 

extractor panel.

2. Stage 2: Extractor Panel: The dust/water and air mixture passes through a woven mesh 

extractor panel. The mesh contains multiple layers knitmesh. The dust particle laden 

water is separated from the airstream within the panel and drains away. Additionally, the 

panel is periodically washed as needed by the action of a multi-nozzle spray bank. 

3. Stage 3: Demister Vanes: The ‘catchment’ or ‘demister’ vanes collect excess water and 

dust mixture that has not drained away in the extractor panel, so that there is little water 

carried through the unit ensuring only dry, clean air is exhausted.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Wet Dust Extraction is a technically feasible option for the Transfer systems 

consisting of hoppers and conveyor belts transferring feed stock from the piles to classification 

towers (EU – 012R-S); Classification towers (EU-012T-U); and Classification tower to a day bin

(EU-012V) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Baghouse fabric filter (>99% PM/PM10/PM2.5 Reduction)

(2) Wet Dust Extraction (≥ 99% PM/PM10/PM2.5 Reduction). 

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for coal handling operations. All data in the 

table is based on the information obtained from the permit application submitted by Indiana 

Gasification, LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic 

versions of permits available at the websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Coal/Coke 

Conveyance

10,400 T 

dry 

coal/day

PM/PM10: 

0.003 

gr/dscf

PM2.5: 

0.0015 

gr/dscf

Baaghouse 

or Wet Dust 

Extraction

081801 AAF 

(Application 

No. 

07100063)

Power 

Holdings of 

Illinois 

Gasification

10/26/2009 Coal-Coke 

Handling System 

(2 identical 

facilities) *

13,722 T 

coal per 

day

0.001 gr/dscf Baghouse or 

similar control

T083-23529-

00003

Duke Energy 

Indiana -

Edwardsport

01/25/2008 Coal-Coke 

Handling System 

(2 identical 

630 MW 0.003 gr/dscf Baghouse
Indiana Gasification LLC Page 96 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

facilities)*

PSD-LA742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Coal-Coke 

Handling System 

(2 identical 

facilities)*

9,413 T/D 0.005 gr/dscf Baghouse

28.0701-PSD Hyperion 

Energy

08/20/2009 Coal-Coke 

Handling System 

(2 identical 

facilities)*

400,000 

bbl/day

0.005 gr/dscf Baghouse

Permit V-09-

006

Cash Creek 

Gasification

05/05/2010 Coal-Coke 

Handling System 

(2 identical 

facilities)*

770 MW 0.005 gr/dscf Baghouse

NOTE: * These emission units have not been built yet.

The majority of the above baghouse systems are permitted with a performance specification of 

0.005 gr/dscf. This is consistent with almost all entries found in the RBLC database for 

baghouses and is standard design for an efficient baghouse. In special circumstances, 

baghouses can be designed to achieve even lower outlet PM, PM10 and PM2.5 emissions. 

Evidently, as shown in the above table, the Power Holdings and Duke Edwardsport gasification 

plants intend to have such systems for at least some of their material handling operations. 

However, this higher control efficiency comes at a significant additional cost.

According to IG’s engineering design firm, achieving 0.001 gr/dscf is very difficult and expensive 

for a bulk material handling baghouse. It is generally achievable with PTFE (Teflon) bags, very 

low air-to-cloth ratio (i.e.: requiring a large unit), a low pressure/high volume bag cleaning-type 

unit, bag cleaning on demand, and other such special features. It also critical that the air going 

through the dust collector always be above the dew point (PTFE bags will pass moisture vapor 

but condensed water droplets will blind the bags), so it can require heated structures, insulated 

ductwork, and heated and insulated dust collectors. All these elements come at additional 

expense. 

For this specific emissions source, the incremental costs to achieve 0.001 gr/dscf are 

unreasonably high for the small benefit obtained. This is illustrated in the below cost analysis 

which considers the estimated incremental capital and operating costs for each baghouse to 

achieve this extremely low emissions and shows that the cost-effectiveness is greater than 

$10,000/ton of PM controlled for this emission unit.
Indiana Gasification LLC Page 97 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Incoming Material Handling EU-012 R&S (each 6000 acfm units) Cost Effectiveness to achieve 0.001 gr/dscf

PM/PM10 

Emissions 

(if 8760 

hr/yr)

Emissions 

Reduction

Control 

Capital Cost

Control 

Operating 

Cost/yr

Total 

Annualized 

Costs

Cost 

Effectiveness

Tons/yr tons/yr $ $/yr $/yr $/Ton

 Baghouse achieving 

0.001 gr/dscf 0.23 0.45 $6,000 $12,090 $12,930 $28,701

Increased energy for 

increased delta P, 

avoid condensation

Baseline - Baghouse 

controlling to 0.003 

gr/dscf

0.68 (proposed)

(Note: unit will not operate 8760 hr/yr, so estimated emissions are overstated and cost/ton controlled will actually be higher. )

Incoming Material Handling EU-012 B-O, T-AC (each 1500 acf/m units) Cost Effectiveness to achieve 0.001 gr/dscf

PM/PM10 

Emissions 

(if 8760 

hr/yr)

Emissions 

Reduction

Control 

Capital Cost

Control 

Operating 

Cost/yr

Total 

Annualized 

Costs

Cost 

Effectiveness

Tons/yr tons/yr $ $/yr $/yr $/Ton

 Baghouse achieving 

0.001 gr/dscf 0.06 0.11 $1,500 $12,090 $3,233 $28,701

Increased energy for 

increased delta P, 

avoid condensation

Baseline - Baghouse 

controlling to 0.003 

gr/dscf

0.17 (proposed)

(Note: unit will not operate 8760 hr/yr, so estimated emissions are overstated and cost/ton controlled will actually be higher. )

Control Alternative Other Impacts

Control Alternative Other Impacts

(a) Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Transfer 

systems consisting of hoppers and conveyor belts transferring feed stock from the piles to 

classification towers (EU – 012R-S); Classification towers (EU-012T-U); and Classification tower 

to a day bin (EU-012V):

(1) The PM, PM10 and PM2.5 emissions shall be controlled by a wet dust extraction or a 

baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for the Transfer systems consisting of hoppers 

and conveyor belts transferring feed stock from the piles to classification towers (EU – 012R-S); 

Classification towers (EU-012T-U); and Classification tower to a day bin (EU-012V).

(1) The PM, PM10 and PM2.5 emissions shall be controlled by a wet dust extraction or a 

baghouse.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.
Indiana Gasification LLC Page 98 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Particulate Matter (PM/PM10/PM2.5) BACT – Radial Stackers to the Pile (EU-012 N-O)

Step 1: Identify Potential Control Technologies

The emissions of PM, PM10 and PM2.5 are generally controlled by the following add-on control 

equipment designed to capture the emissions prior to the time they are exhausted to the 

atmosphere:

(1) Fabric Filter Dust Collectors (Baghouses);

 (2) Cyclones;

 (3) Wet Suppression; and 

 (4) Telescoping Chutes.

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

(a) Fabric Filtration (Baghouses):

A fabric filtration system is not feasible for an operation that cannot reasonably be 

enclosed with the emissions routed to a control device. The nature of pile loading does 

not naturally lend itself to enclosure. However, through the use of telescoping loading 

chutes (discussed below) the loading emissions can be routed to an add-on control 

device. Therefore, although a fabric filter would not normally be feasible, in combination 

with a suitable enclosure, it is a feasible control for this operation.

A fabric filter unit consists of one or more isolated compartments containing rows of fabric 

bags in the form of round, flat, or shaped tubes, or pleated cartridges. Particle laden gas 

passes up (usually) along the surface of the bags then radially through the fabric. 

Particles are retained on the upstream face of the bags, and the cleaned gas stream is 

vented to the atmosphere. The filter is operated cyclically, alternating between relatively 

long periods of filtering and short periods of cleaning. During cleaning, dust that has 

accumulated on the bags is removed from the fabric surface and deposited in a hopper 

for subsequent disposal. Fabric filters collect particles with sizes ranging from submicron 

to several hundred microns in diameter at efficiencies generally in excess of 99%. 

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 1 to 20 inches of 

water. 
Indiana Gasification LLC Page 99 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Fabric filters are used where high efficiency particle collection is required. Limitations are 

imposed by gas characteristics (temperature and corrosivity) and particle characteristics 

(primarily stickiness) that affect the fabric or its operation and that cannot be 

economically accommodated. Important process variables include particle 

characteristics, gas characteristics, and fabric properties. 

The most important design parameter is the air- or gas-to-cloth ratio (the amount of gas 

in ft3

/min that penetrates one ft2 of fabric) and the usual operating parameter of interest is 

pressure drop across the filter system. The major operating feature of fabric filters that 

distinguishes them from other gas filters is the ability to renew the filtering surface 

periodically by cleaning. Common furnace filters, high efficiency particulate air (HEPA) 

filters, high efficiency air filters (HEAFs), and automotive induction air filters are examples 

of filters that must be discarded after a significant layer of dust accumulates on the 

surface. These filters are typically made of matted fibers, mounted in supporting frames, 

and used where dust concentrations are relatively low. Fabric filters are usually made of 

woven or (more commonly) needle-punched felts sewn to the desired shape, mounted in 

a plenum with special hardware, and used across a wide range of dust concentrations.

The use of a filter that is incorporated into the loading chute allows the collected dust to 

be deposited with the material being loaded. This avoids the separate accumulation of 

combustible dust, lengthy ductwork, or separate systems to transport combustible dusts 

back to the process. These features make a dry filter use in this application less 

hazardous than in the other material transfer operations at this plant.

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the use of a fabric filter alone is not technically feasible option for the 

Process Coal/Petcoke Radial Stacker to Pile (EU-012N-O) at this source but it could be 

used as part of a system that includes enclosure of the emissions.

(b) Cyclones:

Cyclones are simple mechanical devices commonly used to remove relatively large 

particles from gas streams. In industrial applications, cyclones are often used as 

precleaners for the more sophisticated air pollution control equipment such as ESPs or 

baghouses. Cyclones are less efficient than wet scrubbers, baghouses, or ESPs. 

Cyclones used as pre-cleaners are often designed to remove more than 80% of the 

particles that are greater than 20 microns in diameter. Smaller particles that escape the 

cyclone can then be collected by more efficient control equipment. This control 

technology may be more commonly used in industrial sites that generate a considerable 

amount of particulate matter, such as lumber companies, feed mills, cement plants, and 

smelters.

Based on the information reviewed for this BACT determination, IDEM, OAQ has

determined that the use of a cyclone is a technically feasible option for the Process 

Radial Stackers to the Pile (EU-012N-O) at this source if used as part of a system that 

includes enclosure of the emissions
Indiana Gasification LLC Page 100 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

(c) Wet Suppression:

Wet suppression systems use liquid sprays or foam to suppress the formation of airborne 

dust. The primary control mechanisms are those that prevent emissions through 

agglomerate formation by combining small dust particles with larger aggregate or with 

liquid droplets. The key factors that affect the degree of agglomeration and, hence, the 

performance of the system are the coverage of the material by the liquid and the ability of 

the liquid to wet small particles. There are two types of wet suppression systems: liquid 

sprays which use water or water/surfactant mixtures as the wetting agent and systems 

which supply foams as the wetting agent. Wet suppression systems typically achieve PM

control efficiencies of greater than 85%

Based on the information reviewed for this BACT determination, IDEM, OAQ has

determined that the use of a wet suppression is a technically feasible option for the 

Process Radial Stackers to the Pile (EU-012N-O) at this source.

(d) Telescoping Chutes

In this process, the incoming feedstocks are dropped from the end of the transfer 

conveyor onto the storage pile. Typical controls for loading materials onto a pile include 

the use of wet suppression and or the use of telescoping chutes that reduce the distance 

of, and enclose, the drop. These controls can provide greater than 85% control. 

To achieve significantly higher levels of control, firms such as DCL, Inc. provide 

telescoping chutes for bulk material pile loading coupled with a dust collector system. 

This type of system allows coal/petcoke to flow down through a central telescoping flow 

tube onto the pile while dust is captured and drawn upward through an outer telescoping 

tube with a fan vented to a dust collector filter system. This system guarantees 99.9% 

dust collector control efficiency with an outlet loading comparable to other baghouses 

0.005 gr/dscf particulates. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the use of a telescoping chute is a technically feasible option for the 

Process Radial Stackers to the Pile (EU-012N-O) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The above control technologies have been identified for control of PM, PM10 and PM2.5 resulting 

from operation of the Process Radial Stackers to the Pile (EU-012N-O) at this source.

(1) Telescoping Chute with dust collection filtration system (≥99% PM/PM10/PM2.5 

Reduction);

(2) Wet Suppression (90% PM/PM10/PM2.5 Reduction); and 

(3) Cyclones (80% PM/PM10/PM2.5 Reduction). 

As shown above, baghouse and the telescoping chute with dust collection filtration system

achieves a control efficiency of greater than 99% versus the wet suppression and cyclone control 

efficiency of 90% and 80%, respectively. Therefore, the source has decided to use the 

telescoping chute with dust collection filtration system which is one of the top ranked control

alternatives for control of particulate matter emissions from the Radial Stackers to the Pile (EU012N-O).
Indiana Gasification LLC Page 101 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for similar plants. All data in the table is 

based on the information obtained from the permit application submitted by Indiana Gasification, 

LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits 

available at the websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Coal/Coke Barge 

Unloading and 

Storage

10,400 T 

dry 

coal/day

PM/PM10: 

0.003

gr/dscf

PM2.5: 

0.0015 

gr/dscf

Telescoping 

Chute with 

dust 

collection or 

Baghouse

081801 AAF 

(Application 

No. 

07100063)

Power 

Holdings of 

Illinois 

Gasification

10/26/2009 Coal-Coke Handling 

System (2 identical 

facilities) *

13,722 T 

coal per 

day

0.001 gr/dscf Baghouse or 

similar control

T083-23529-

00003

Duke Energy 

Indiana -

Edwardsport

01/25/2008 Coal-Coke Handling 

System (2 identical 

facilities)*

630 MW 0.003 gr/dscf Baghouse

PSD-LA742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Coal-Coke Handling 

System (2 identical 

facilities)*

9,413 

T/D

0.005 gr/dscf Baghouse

28.0701-PSD Hyperion 

Energy

08/20/2009 Coal-Coke Handling 

System (2 identical 

facilities)*

400,000 

bbl/day

0.005 gr/dscf Baghouse

Permit V-09-

006

Cash Creek 

Gasification

05/05/2010 Coal-Coke Handling 

System (2 identical 

facilities)*

770 MW 0.005 gr/dscf Baghouse

NOTE: * These emission units have not been built yet.

The majority of the above baghouse systems are permitted with a performance specification of 

0.005 gr/dscf. This is consistent with almost all entries found in the RBLC database for 

baghouses and is standard design for an efficient baghouse. In special circumstances, 

baghouses can be designed to achieve even lower outlet PM, PM10 and PM2.5 emissions. 

Evidently, as shown in the above table, the Power Holdings and Duke Edwardsport gasification 

plants intend to have such systems for at least some of their material handling operations. 

However, this higher control efficiency comes at a significant additional cost.

According to IG’s engineering design firm, achieving 0.001 gr/dscf is very difficult and expensive 

for a bulk material handling baghouse. It is generally achievable with PTFE (Teflon) bags, very 

low air-to-cloth ratio (i.e.: requiring a large unit), a low pressure/high volume bag cleaning-type 

unit, bag cleaning on demand, and other such special features. It also critical that the air going 

through the dust collector always be above the dew point (PTFE bags will pass moisture vapor 

but condensed water droplets will blind the bags), so it can require heated structures, insulated 

ductwork, and heated and insulated dust collectors. All these elements come at additional 

expense. 

For this specific emissions source, the incremental costs to achieve 0.001 gr/dscf are 

unreasonably high for the small benefit obtained. This is illustrated in the below cost analysis 

which considers the estimated incremental capital and operating costs for each baghouse to 

achieve this extremely low emissions and shows that the cost-effectiveness is greater than 

$10,000/ton of PM controlled for this emission unit.
Indiana Gasification LLC Page 102 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Incoming Material Handling EU-012 B-O, T-AC (each 1500 acf/m units) Cost Effectiveness to achieve 0.001 gr/dscf

PM/PM10 

Emissions 

(if 8760 

hr/yr)

Emissions 

Reduction

Control 

Capital Cost

Control 

Operating 

Cost/yr

Total 

Annualized 

Costs

Cost 

Effectiveness

Tons/yr tons/yr $ $/yr $/yr $/Ton

 Baghouse achieving 

0.001 gr/dscf 0.06 0.11 $1,500 $12,090 $3,233 $28,701

Increased energy for 

increased delta P, 

avoid condensation

Baseline - Baghouse 

controlling to 0.003 

gr/dscf

0.17 (proposed)

(Note: unit will not operate 8760 hr/yr, so estimated emissions are overstated and cost/ton controlled will actually be higher. )

Control Alternative Other Impacts

(a) Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Radial 

Stackers to the Pile (EU-012 N-O):

(1) The PM, PM10 and PM2.5 emissions shall be controlled by a Telescoping chute with dust 

collection.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf, each.

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for Radial Stackers to the Pile (EU-012N-O).

(1) The PM, PM10 and PM2.5 emissions shall be controlled by a Telescoping chute with dust 

collection.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf, each.

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Particulate Matter (PM/PM10/PM2.5) BACT – Storage Piles (EU-012W/X)

Step 1: Identify Potential Control Technologies

The emissions of PM, PM10 and PM2.5 are often controlled by the following controls designed to 

prevent or capture the emissions prior to the time they are exhausted to the atmosphere:

(1) Fabric Filter Dust Collectors (Baghouses);

 (2) Wet Scrubber;

 (3) Cyclones; and 

 (4) Wet Suppression.
Indiana Gasification LLC Page 103 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

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

The coal pile wind erosion and dozer operations cannot reasonably be enclosed and vented to a 

control device due to the location outside and due to the extreme size involved. This eliminates 

the applicability of collection and filtration equipment or other add-on controls. 

The only remaining controls for this material handling that is technically feasible for these sources 

is wet or chemical suppression and the use of pile compaction. Frequent use of water or chemical 

surfactants can significantly reduce airborne dust from transfer operations. 

Wet Suppression:

Wet suppression systems use liquid sprays or foam to suppress the formation of airborne dust. 

The primary control mechanisms are those that prevent emissions through agglomerate formation 

by combining small dust particles with larger aggregate or with liquid droplets. The key factors 

that affect the degree of agglomeration and, hence, the performance of the system are the 

coverage of the material by the liquid and the ability of the liquid to wet small particles. 

There are two types of wet suppression systems: liquid sprays which use water or 

water/surfactant mixtures as the wetting agent and systems which supply foams as the wetting 

agent. Wet suppression systems typically achieve PM control efficiencies of greater than 85%

The source will use pile compaction and apply wet or chemical suppression to achieve reduction 

of 90% particulate matter (PM10). (Note: The use of either plain water or water with chemical 

surfactants added can provide equally effective control, given adequate application rate and 

frequency. The use of chemical additives primarily allows a decrease in frequency of application, 

but it increases the cost of each application.)

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a wet suppression and Pile compaction are technically feasible option for the Storage 

Piles (EU-012W/X) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Wet Suppression and Pile Compaction (90% PM/PM10/PM2.5 Reduction). 

These operations cannot reasonably be enclosed and vented to a control device due to the 

location outside and due to the extreme size involved. This eliminates the applicability of 

collection and filtration equipment. The only remaining controls for this material handling that is 

technically feasible for these sources is wet or chemical suppression and the use of pile 

compaction. Frequent use of water or chemical surfactants can significantly reduce airborne dust 

from transfer operations. IG will use pile compaction and apply wet or chemical suppression to 

achieve reduction of 90% particulate matter (PM10).
Indiana Gasification LLC Page 104 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for coal handling facilities. All data in the table 

is based on the information obtained from the permit application submitted by Indiana 

Gasification, LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic 

versions of permits available at the websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued 

Date

Process Description Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification 

- proposed

Proposed Coal/Coke Pile 10,400 T 

dry 

coal/day

90% control Wet 

Suppression

with Pile 

Compaction

IA-0089- Iowa Homeland 

Energy 

Solutions 

08/08/2007 Coal Receiving and 

handling

200 

tons/hr

None 

specified for 

unenclosed 

unloading 

area

water fogging 

to eliminate 

particulate in 

unloading 

area

IA - 0086 -

Iowa

University of 

Northern Iowa

05/3/2007 Coal Pile 50,565 

tons/hr

PM/PM10: 

Must use dust 

suppressant 

to reduce 

fugitive 

emissions by 

95%

Chemical 

suppressant 

with 95% 

control

CO-0057 -

Colorado

Public Service 

Company of 

Colorado 

Comanche 

Station

07/05/2005 Coal handling and storage 

(includes open storage 

piles with lowering well, 

rail-car unloading, transfer 

from unloading to pile and 

transfer from pile to bunker)

NA None 

specified for 

unenclosed 

unloading 

area

Control 

include water 

spray, lower 

well, dust 

suppressant, 

enclosures 

where 

baghouse are 

not feasible

KY-0100 East Kentucky 

Power Coop. 

04/09/2010 Coal Pile, Rail Unloading 

Egress to Conveyor

3000 

tons per 

hr

10% opacity 

(3min)

Wet 

Suppression, 

Dust 

suppressant 

Lowering well 

and 

compaction

OH-0317 Ohio River 

Clean Fuels

11/20/2008 Coal Storage Piles 5500 

tons/hr

PM10:12.3 

tons per year. 

with 75% 

control.

3-sided 

windscreen 

barrier. 

Reduced drop 

heights. Use 

of chemical 

stabilization 

dust 

suppressants 

and/or 

watering to 

reduce any 

visible 

emissions.

NOTE: * These emission units have not been built yet.

Note: ** Compliance with the limit at this facility has not been demonstrated through stack testing.
Indiana Gasification LLC Page 105 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

The table above shows recent entries in the RACT/BACT/LAER Clearinghouse (RBLC) database for 

material handling activities that can’t be enclosed. All these permits specify wet or chemical suppression, 

consistent with the source's proposal. Although most of the database entries do not specify the level of 

control, two of the listed entries specify 75% and 95%. Dependent on the amount and frequency of the 

application of wet suppression, various levels of control can theoretically be achieved by wet suppression. 

Control of greater than 90% is not normally considered practicable. 

(a) Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Storage 

Piles (EU-012W/X):

(1) The PM, PM10 and PM2.5 emissions shall be controlled by wet suppression with pile 

compaction with a control efficiency of 90 %.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for Storage Piles (EU-012W/X).

The PM, PM10 and PM2.5 emissions from the Storage Piles (EU-012W/X) operation shall be 

controlled by wet suppression with pile compaction with a control efficiency of 90 %.

Particulate Matter (PM/PM10/PM2.5) BACT – Dozer Activities (EU-012P/Q)

Step 1: Identify Potential Control Technologies

The emissions of PM, PM10 and PM2.5 are generally controlled by the following controls designed 

to prevent or capture the emissions prior to the time they are exhausted to the atmosphere:

(1) Fabric Filter Dust Collectors (Baghouses);

 (2) Wet Scrubber;

 (3) Cyclones; and 

 (4) Wet Suppression.

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

The coal pile wind erosion and dozer operations cannot reasonably be enclosed and vented to a

control device due to the location outside and due to the extreme size involved. This eliminates 

the applicability of collection and filtration equipment or other add-on controls. 

The only remaining controls for this material handling that is technically feasible for these sources 

is wet or chemical suppression and the use of pile compaction. Frequent use of water or chemical 

surfactants can significantly reduce airborne dust from transfer operations. 
Indiana Gasification LLC Page 106 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Wet Suppression:

Wet suppression systems use liquid sprays or foam to suppress the formation of airborne dust. 

The primary control mechanisms are those that prevent emissions through agglomerate formation 

by combining small dust particles with larger aggregate or with liquid droplets. The key factors 

that affect the degree of agglomeration and, hence, the performance of the system are the 

coverage of the material by the liquid and the ability of the liquid to wet small particles. 

There are two types of wet suppression systems: liquid sprays which use water or 

water/surfactant mixtures as the wetting agent and systems which supply foams as the wetting 

agent. Wet suppression systems typically achieve PM control efficiencies of greater than 85%

The source will use pile compaction and apply wet or chemical suppression to achieve reduction 

of 90% particulate matter (PM10). (Note: The use of either plain water or water with chemical 

surfactants added can provide equally effective control, given adequate application rate and 

frequency. The use of chemical additives primarily allows a decrease in frequency of application, 

but it increases the cost of each application.)

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a wet suppression and Pile compaction is a technically feasible option for the Dozer 

Activity (EU-012P/Q) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Wet Suppression and Pile Compaction (90% PM/PM10/PM2.5 Reduction). 

These operations cannot reasonably be enclosed and vented to a control device due to 

the location outside and due to the extreme size involved. This eliminates the 

applicability of collection and filtration equipment. The only remaining controls for this 

material handling that is technically feasible for these sources is wet or chemical 

suppression and the use of pile compaction. Frequent use of water or chemical 

surfactants can significantly reduce airborne dust from transfer operations. IG will use 

pile compaction and apply wet or chemical suppression to achieve reduction of 90% 

particulate matter (PM10).

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for coal handling facilities. All data in the 

table is based on the information obtained from the permit application submitted by Indiana 

Gasification, LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic 

versions of permits available at the websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued 

Date

Process Description Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification 

- proposed

Proposed Coal/Coke Pile 10,400 T 

coal/day 

90% control Wet 

Suppression 

with Pile 

Compaction

IA-0089- Iowa Homeland 

Energy 

Solutions 

08/08/2007 Coal Receiving and 

handling

200 

tons/hr

None 

specified for 

unenclosed 

unloading 

area

water fogging 

to eliminate 

particulate in 

unloading 

area
Indiana Gasification LLC Page 107 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued 

Date

Process Description Rating 

(TPH)

Limitation Control 

Method

IA - 0086 -

Iowa

University of 

Northern Iowa

05/3/2007 Coal Pile 50,565 

tons/hr

PM/PM10: 

Must use dust 

suppressant 

to reduce 

fugitive 

emissions by 

95%

Chemical 

suppressant 

with 95% 

control

CO-0057 -

Colorado

Public Service 

Company of 

Colorado 

Comanche 

Station

07/05/2005 Coal handling and storage 

(includes open storage 

piles with lowering well, 

rail-car unloading, transfer 

from unloading to pile and 

transfer from pile to bunker)

NA None 

specified for 

unenclosed 

unloading 

area

Control 

include water 

spray, lower 

well, dust 

suppressant, 

enclosures 

where 

baghouse are 

not feasible

KY-0100 East Kentucky 

Power Coop. 

04/09/2010 Coal Pile, Rail Unloading 

Egress to Conveyor

3000 

tons per 

hr

10% opacity 

(3min)

Wet 

Suppression, 

Dust 

suppressant 

Lowering well 

and 

compaction

OH-0317 Ohio River 

Clean Fuels

11/20/2008 Coal Storage Piles 5500 

tons/hr

PM10:12.3 

tons per year. 

with 75% 

control.

3-sided 

windscreen 

barrier. 

Reduced drop 

heights. Use 

of chemical 

stabilization 

dust 

suppressants 

and/or 

watering to 

reduce any 

visible 

emissions.

NOTE: * These emission units have not been built yet.

Note: ** Compliance with the limit at this facility has not been demonstrated through stack testing.

The table above shows recent entries in the RACT/BACT/LAER Clearinghouse (RBLC) database for 

material handling activities that can’t be enclosed. All these permits specify wet or chemical suppression, 

consistent with the source's proposal. Although most of the database entries do not specify the level of 

control, two of the listed entries specify 75% and 95%. Dependent on the amount and frequency of the 

application of wet suppression, various levels of control can theoretically be achieved by wet suppression. 

Control of greater than 90% is not normally considered practicable. 

(a) Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Dozer 

Activities (EU-012P/Q):

(1) The PM, PM10 and PM2.5 emissions from the Dozer Activities (EU-012P/Q) shall be 

controlled by wet suppression with pile compaction with a control efficiency of 90 %.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for Dozer Activities (EU-012P/Q).
Indiana Gasification LLC Page 108 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

The PM, PM10 and PM2.5 emissions from the Dozer Activities (EU-012P/Q) operation shall be 

controlled by wet suppression with pile compaction with a control efficiency of 90 %.

Particulate Matter (PM/PM10/PM2.5) BACT – Truck/rail conveyor transfer tower (EU-012Y); truck 

stations unloading to a truck hopper (EU-012AB-AC); and truck hopper unloading to the conveyor 

belts (EU-012AA)

Step 1: Identify Potential Control Technologies

The emissions of PM, PM10 and PM2.5 are generally controlled by the following add-on control 

equipment designed to capture the emissions prior to the time they are exhausted to the 

atmosphere:

(1) Filtration

(a) Baghouse,

(b) Wet Extraction System (fan/water sprays/extraction/demister), and

(2) Other Add-on Controls (Cyclone, ESP)

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

Cyclone/Electrostatic Precipitator

Use of add-on controls such as cyclones or electrostatic precipitators (ESP) is not good technical 

choices in this service because of the relatively low flow rates. Additionally, for this service, they 

are not as effective as the proposed baghouse or wet extraction system and are therefore not

considered further in this BACT analysis. 

Fabric Filter (Baghouse)

 A baghouse fabric filter unit consists of one or more isolated compartments containing rows of 

fabric bags in the form of round, flat, or shaped tubes, or pleated cartridges. Particle laden gas 

passes up (usually) along the surface of the bags then radially through the fabric. Particles are 

retained on the upstream face of the bags, and the cleaned gas stream is vented to the 

atmosphere. The filter is operated cyclically, alternating between relatively long periods of filtering 

and short periods of cleaning. During cleaning, dust that has accumulated on the bags is 

removed from the fabric surface and deposited in a hopper for subsequent disposal. Fabric filters 

collect particles with sizes ranging from submicron to several hundred microns in diameter at 

efficiencies generally in excess of 99%. 

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 1 to 20 inches of water. 

Fabric filters are used where high efficiency particle collection is required. Limitations are 

imposed by gas characteristics (temperature and corrosivity) and particle characteristics 

(primarily stickiness) that affect the fabric or its operation and that cannot be economically 

accommodated. Important process variables include particle characteristics, gas characteristics, 

and fabric properties. 
Indiana Gasification LLC Page 109 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

The most important design parameter is the air- or gas-to-cloth ratio (the amount of gas in ft3/min 

that penetrates one ft2 of fabric) and the usual operating parameter of interest is pressure drop 

across the filter system. The major operating feature of fabric filters that distinguishes them from 

other gas filters is the ability to renew the filtering surface periodically by cleaning. Common 

furnace filters, high efficiency particulate air (HEPA) filters, high efficiency air filters (HEAFs), and 

automotive induction air filters are examples of filters that must be discarded after a significant 

layer of dust accumulates on the surface. These filters are typically made of matted fibers, 

mounted in supporting frames, and used where dust concentrations are relatively low. Fabric 

filters are usually made of woven or (more commonly) needle-punched felts sewn to the desired 

shape, mounted in a plenum with special hardware, and used across a wide range of dust 

concentrations.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a baghouse is a technically feasible option for the Truck unloading (EU-012Y-AC) at 

this source.

Wet Extraction System 

Wet extraction systems are designed specifically for high-efficiency dust control. The design 

accomplishes this by spraying water into the air stream at the suction of a high volume fan. Using 

a combination of the energy of the fan and the water, the dust particles are trapped into finely 

atomized water droplets which are removed from the fan exhaust in an extractor panel and 

demister. Dust is expected to be controlled for the IG facility at an efficiency rate of 99% (at 

maximum design loading). The below figure shows the major components of this control system 

and is followed by a further technical explanation of how each stage of the system works. 

Wet extraction System Technical Description

Stage 1 Water Injection: Dust laden air is drawn into the dust extractor fan where it is mixed with 

water that is discharged from the water spray nozzles. The dust-laden air is ‘wetted’ by a 

mechanical action as it passes through the impeller, which is rotating at approx. 3600 rpm. The 

dust/water and air mixture then passes around the motor to an extractor panel.

Stage 2 Extractor Panel: The dust/water and air mixture passes through a woven mesh extractor 

panel. The mesh contains multiple layers of knit mesh. The dust particle laden water is separated 

from the airstream within the panel and drains away. Additionally, the panel is periodically 

washed as needed by a multi-nozzle spray bank. 

Stage 3 Demister Vanes: The ‘catchment’ or ‘demister’ vanes collect excess water and dust 

mixture that has not drained away in the extractor panel, so that there is little water carried 

through the unit ensuring only dry, clean air is exhausted.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Wet extraction system is a technically feasible option for the Truck unloading (EU012 Y-AC) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Baghouse (> 99% PM/PM10/PM2.5 Reduction)

(2) Wet Dust Extraction System (≥ 99% PM/PM10/PM2.5 Reduction). 

These systems provide comparable control effectiveness.
Indiana Gasification LLC Page 110 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for coal handling operations. All data in the 

table is based on the information obtained from the permit application submitted by Indiana 

Gasification, LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic 

versions of permits available at the websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 147-

30464-

00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Coal/Coke Truck

Unloading and 

Conveyance

10,400 T 

dry 

coal/day

PM/PM10: 

0.003gr/dscf 

PM2.5: 0.0015 

gr/dscf

Baghouse 

or Wet Dust 

Extraction 

System

081801 AAF 

(Application 

No. 

07100063)

Power 

Holdings of 

Illinois 

Gasification

10/26/2009 Coal-Coke Handling 

System (2 identical 

facilities) *

13,722 T 

coal per 

day

0.001 gr/dscf Baghouse or 

similar control

T083-23529-

00003

Duke Energy 

Indiana -

Edwardsport

01/25/2008 Coal-Coke Handling 

System (2 identical 

facilities)*

630 MW 0.003 gr/dscf Baghouse

PSD-LA742(M1) 

Louisiana

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Coal-Coke Handling 

System (2 identical 

facilities)*

9,413 T/D 0.005 gr/dscf Baghouse

28.0701-

PSD

Hyperion 

Energy

08/20/2009 Coal-Coke Handling 

System (2 identical 

facilities)*

400,000 

bbl/day

0.005 gr/dscf Baghouse

Permit V-09-

006

Cash Creek 

Gasification

05/05/2010 Coal-Coke Handling 

System (2 identical 

facilities)*

770 MW 0.005 gr/dscf Baghouse

NOTE: * These emission units have not been built yet.

The majority of the above baghouse systems are permitted with a performance specification of 

0.005 gr/dscf. This is consistent with almost all entries found in the RBLC database for 

baghouses and is standard design for an efficient baghouse. In special circumstances, 

baghouses can be designed to achieve even lower outlet PM, PM10 and PM2.5 emissions. 

Evidently, as shown in the above table, the Power Holdings and Duke Edwardsport gasification 

plants intend to have such systems for at least some of their material handling operations. 

However, this higher control efficiency comes at a significant additional cost.

According to IG’s engineering design firm, achieving 0.001 gr/dscf is very difficult and expensive 

for a bulk material handling baghouse. It is generally achievable with PTFE (Teflon) bags, very 

low air-to-cloth ratio (i.e.: requiring a large unit), a low pressure/high volume bag cleaning-type 

unit, bag cleaning on demand, and other such special features. It also critical that the air going 

through the dust collector always be above the dew point (PTFE bags will pass moisture vapor 

but condensed water droplets will blind the bags), so it can require heated structures, insulated 

ductwork, and heated and insulated dust collectors. All these elements come at additional 

expense. 

For this specific emissions source, the incremental costs to achieve 0.001 gr/dscf are 

unreasonably high for the small benefit obtained. This is illustrated in the below cost analysis 

which considers the estimated incremental capital and operating costs for each baghouse to 

achieve this extremely low emissions and shows that the cost-effectiveness is greater than 

$10,000/ton of PM controlled for this emission unit
Indiana Gasification LLC Page 111 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Incoming Material Handling EU-012 B-O, T-AC (each 1500 acf/m units) Cost Effectiveness to achieve 0.001 gr/dscf

PM/PM10 

Emissions 

(if 8760 

hr/yr)

Emissions 

Reduction

Control 

Capital Cost

Control 

Operating 

Cost/yr

Total 

Annualized 

Costs

Cost 

Effectiveness

Tons/yr tons/yr $ $/yr $/yr $/Ton

 Baghouse achieving 

0.001 gr/dscf 0.06 0.11 $1,500 $12,090 $3,233 $28,701

Increased energy for 

increased delta P, 

avoid condensation

Baseline - Baghouse 

controlling to 0.003 

gr/dscf

0.17 (proposed)

(Note: unit will not operate 8760 hr/yr, so estimated emissions are overstated and cost/ton controlled will actually be higher. )

Control Alternative Other Impacts

(a) Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Truck/rail 

conveyor transfer tower (EU-012Y); truck stations unloading to a truck hopper (EU-012AB-AC); 

and truck hopper unloading to the conveyor belts (EU-012AA):

(1) An enclosed vent to a wet dust extraction system or a baghouse for control of PM, PM10 

and PM2.5 emissions.

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015gr/dscf.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for the Truck/rail conveyor transfer tower (EU012Y); truck stations unloading to a truck hopper (EU-012AB-AC); and truck hopper unloading to 

the conveyor belts (EU-012AA).

(1) The PM, PM10 and PM2.5 emissions from the Truck/rail conveyor transfer tower (EU012Y); truck stations unloading to a truck hopper (EU-012AB-AC); and truck hopper 

unloading to the conveyor belts (EU-012AA) shall be controlled by an enclosed vent to a 

wet dust extraction system or baghouse. 

(2) The PM and PM10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM2.5 maximum outlet concentration shall not exceed 0.0015gr/dscf.

Particulate Matter (PM/PM10/PM2.5) BACT– Rod Mill Vent (EU-013A-D)

Step 1: Identify Potential Control Technologies

Emissions PM, PM10 and PM2.5 are generally controlled with add-on control equipment designed 

to capture the emissions prior to the time they are exhausted to the atmosphere. In cases where 

the material being emitted is organic, particulate matter may be controlled through a combustion 

process. Generally, PM and PM10 emissions are controlled through one of the following 

mechanisms:

(1) Mechanical Collectors (such as Cyclones or Multiclones);

(2) Wet Scrubbers;

(3) Electrostatic Precipitators (ESP); and
Indiana Gasification LLC Page 112 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

(4) Fabric Filter Dust Collectors (Baghouses).

The choice of which technology is most appropriate for a specific application depends upon 

several factors, including particle size to be collected, particle loading, stack gas flow rate, stack 

gas physical characteristics (e.g., temperature, moisture content, presence of reactive materials), 

and desired collection efficiency.

Step 2: Eliminate Technically Infeasible Options

(a) Add-on Control Technology: The rod-mill eductor has a small amount of particulate 

(PM10 emissions are estimated to be 0.44 tons per year total for four rod mills). This low 

emissions rate is due to the fact that the rod-mill is a wet grinding operation. The high 

moisture content effectively minimizes the particulate emissions and results in an exhaust 

particulate concentration of about 0.015 grains/dscf PM/PM10, which is equivalent to 

0.025 pounds per hour at permitted capacity, and 0.0047 grains/dscf PM2.5, which is 

equivalent to 0.0074 pounds per hour at permitted capacity.This emissions level is so low 

that it would not be feasible for any add-on controls such as cyclones, baghouses, ESPs 

or wet scrubbers to effectively further reduce emissions. These control devices are 

generally not used on streams with less than 1 grain/scf. Also, regardless of the 

emissions rate, the high moisture content of this exhaust would create technical 

difficulties using the more effective of these add-on control devices, the ESP and the 

baghouses. For these reasons, the above listed add-on particulate controls are not 

considered feasible in the BACT analysis. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

there is no viable technology for controlling the PM/PM10/PM2.5 emissions resulting from the Rod 

Mill Vent (EU-013A-D).

Step 4: Evaluate the Most Effective Controls and Document the Results

Proposal: Indiana Gasification, LLC 

The following has been proposed as BACT for PM/PM10/PM2.5 from each proposed Rod Mill Vent 

at the Indiana Gasification Plant.

For each Rod Mill Vent, BACT for PM/PM10 is proposed to be 0.025 pounds per hour based on a 

3-hour average and for PM2.5 is proposed to be 0.0074 pounds per hour based on a 3-hour 

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 PM/PM10/PM2.5 for the Rod Mill Vents.

(a) The PM and PM10 emissions from each Rod Mill Vents shall not exceed 0.025 pounds 

per hour based on a 3-hour average.

(b) The PM2.5 emissions from each Rod Mill Vent shall not exceed 0.0074 pounds per hour 

based on a 3-hour average.
Indiana Gasification LLC Page 113 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Particulate Matter (PM/PM10/PM2.5) BACT – ASU Regeneration Vent (EU-017A and B)

Step 1: Identify Potential Control Technologies

Emissions of PM, PM10 and PM2.5 are generally controlled with add-on control equipment 

designed to capture the emissions prior to the time they are exhausted to the atmosphere. In 

cases where the material being emitted is organic, particulate matter may be controlled through a 

combustion process. Generally, PM/PM10/ PM2.5 emissions are controlled through one of the 

following mechanisms:

(1) Mechanical Collectors (such as Cyclones or Multiclones);

(2) Wet Scrubbers;

(3) Electrostatic Precipitators (ESP); and

(4) Fabric Filter Dust Collectors (Baghouses).

The choice of which technology is most appropriate for a specific application depends upon 

several factors, including particle size to be collected, particle loading, stack gas flow rate, stack 

gas physical characteristics (e.g., temperature, moisture content, presence of reactive materials), 

and desired collection efficiency.

Step 2: Eliminate Technically Infeasible Options

(a) Add-on Control Technology: The air separation unit molecular sieve regeneration vent 

is a very small particulate source (PM10 emissions are estimated to be 0.22 tons/yr.) that 

operates intermittently throughout the day. These low emissions are merely dust filtered 

out of the ambient air used in the air separation unit and represent less than 0.00005 

grain/dscf PM/PM10// PM2.5 concentration in the exhaust. This emissions level is so low 

that it would not be feasible for any add-on controls such as cyclones, baghouses, ESPs 

or wet scrubbers to effectively further reduce emissions. These control devices are 

generally not used on streams with less than 1 grain/scf. For this reason, the above 

listed add-on particulate controls were not considered feasible in the BACT analysis. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that

there is no viable technology for controlling the PM/PM10/PM2.5 emissions resulting from the Air 

Separation Unit (ASU) (EU-017A/B).

Step 4: Evaluate the Most Effective Controls and Document the Results

Proposal: Indiana Gasification, LLC 

The following has been proposed as BACT for PM/PM10/PM2.5 from the proposed Air Separation 

Unit (ASU) at the Indiana Gasification Plant.

For each ASU, BACT for PM/PM10 is proposed to be 0.026 pounds per hour based on a daily 

average and for PM2.5 is proposed to be 0.009 pounds per hour based on a daily 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 PM/PM10/PM2.5 for the Air Separation Unit (ASU).
Indiana Gasification LLC Page 114 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

(a) The PM and PM10 emissions from each Air Separation Unit (ASU) shall not exceed 0.026 

pounds per hour based on a daily average. 

(b) The PM2.5 emissions from the Air Separation Unit (ASU) shall not exceed 0.0009 pounds 

per hour based on a daily average. 

PM, PM10 and PM2.5 BACT – Wet Sulfuric Acid Plants (EU-015 A and B)

Step 1: Identify Potential Control Technologies

Emissions of PM, PM10 and PM2.5 are generally controlled with add-on control equipment 

designed to capture the emissions prior to the time they are exhausted to the atmosphere. 

(1) Cyclones;

 (2) Wet Scrubber;

(3) Electrostatic Precipitators (ESP);

(4) Fabric Filter Dust Collectors (Baghouses); 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.

If add-on control technology is not feasible, an alternate method of control may be implemented. 

Alternate Control Methods:

One or more alternate methods of control may be considered when they are more cost-effective 

than the conventional add-on controls or when add-on control technology may not be feasible. 

For the particulate emission sources from the WSA, the following alternate control methods were 

evaluated:

(1) Mist eliminators and Hydrogen peroxide (H2O2) scrubber

Step 2: Eliminate Technically Infeasible Options

(a) Add-on Control Technology: Add on control devices such as fabric filters and 

electrostatic precipitators (ESPs) are not technically feasible for this source, because the 

particulates are wet condensable, corrosive acid mist. Based on availability and 

applicability, the conventional add-on control technology was eliminated from 

consideration due to technical infeasibility.

(b) Mist eliminators and Hydrogen peroxide (H2O2) scrubber

The final step in the WSA process involves absorbing and recovering the produced 

sulfuric acid. A small amount of sulfuric acid mist can carry out with the tail gas. This 

sulfuric acid mist (H2SO4) is also considered PM/PM10/PM2.5 for BACT review purposes. 

To control these emissions, a high efficiency mist elimination filter is installed 

downstream of the hydrogen peroxide scrubber that captures 75 percent of the fine acid 

mist. This removal percentage is guaranteed by the equipment vendor. This is the most 

efficient mist filter available. While the peroxide scrubber that is located upstream of the 

mist eliminator is installed primarily to control SO2, it is also estimated to remove 10% of 

the acid mist prior to the high efficiency mist eliminator filter. The peroxide scrubber uses
Indiana Gasification LLC Page 115 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

a 50% hydrogen peroxide (H2O2) solution which flows counter current to the flow of the 

gas stream from the WSA process.

The source is proposing to install high efficiency mist eliminators and hydrogen peroxide 

(H2O2) scrubbers to control H2SO4 emissions from the process. These controls would 

be sufficient to comply with the sulfuric acid mist limit of the NSPS Subpart H, although, 

NSPS Subpart H does not apply to the project’s WSA plant. 

Subpart H regulates sulfuric acid production plants such as those that burn elemental 

sulfur. It does not regulate WSA units “where conversion to sulfuric acid is utilized 

primarily as a means of preventing emissions to the atmosphere of sulfur dioxide or other 

sulfur compounds” (40 CFR 60.81(a)) such as the IG WSA plant. Nevertheless, the IG 

facility emissions will be at or below the Subpart H sulfuric acid mist limit of 0.15 lbs 

H2SO4 mist/ton of Acid produced. For practical purposes, all of the particulates from this 

source are this acid mist.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The above control technologies have been identified for control of PM, PM10 and PM2.5 resulting 

from operation of the WSA (EU-015A/B). 

(1) High efficiency mist eliminators and hydrogen peroxide (H2O2) scrubbers

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed H2SO4 BACT determination along with the existing H2SO4

BACT determinations for similar plants. For this source, the emissions of PM, PM10 and PM2.5

equal those of H2SO4. All data in the table is based on the information obtained from the permit 

application submitted by Indiana Gasification, LLC, the U.S. EPA RACT/BACT/LAER 

Clearinghouse (RBLC), and electronic versions of permits available at the websites of other 

permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 

147-30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Wet Sulfuric 

Acid Plants

(EU-015A/B)

10,400 T 

dry 

coal/day

0.15 lb/ton and

5 lbs/hour based 

on 3-hr average

High Effi. 

Mist 

Eliminator, 

H2O2

scrubber

PSD-LA-742(M1) Lake Charles 

Cogeneration, 

LLC

12/30/2010 Wet Sulfuric 

Acid Plants 

(2)*

9,413 T/D 0.15 lb/ton acid 

produced

High Effi. 

Mist 

Eliminator, 

H2O2

scrubber

081801 AAF 

(Application No. 

07100063)

Power Holdings 

of Illinois 

Gasification

10/26/2009 Sulfuric Acid 

Plants *

13,722 T 

coal per 

day

0.15 lb/ton, 0.06 

lb/ton (24-hr) 

(permit lists two 

conflicting limits on 

different pages)

High Effi. 

Mist 

Eliminator, 

H2O2

scrubber

NOTE: * These emission units have not been built yet.

All three of the above facilities have designed their WSA plants with the best possible control -

using similar technologies. All three facilities have a performance of 0.15 lb/tons acid produced. 

However, the Power Holdings of Illinois facility permit lists two conflicting emissions limits. In two 

places it lists 0.15 lb/ton acid produced, which is consistent with the NSPS standard and 

consistent with almost every other WSA in the RBLC (including those that burn elemental sulfur). 
Indiana Gasification LLC Page 116 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

However, it also, separately lists an emission rate of 0.06 lb/ton H2SO4. Based on discussions 

with their WSA vendor, IG reports that there is not any confidence that the lower level of 0.06 

lb/ton can be achieved. Also, the Power Holdings facility has not been built, and has not 

demonstrated this level of performance. Based on this information, this lower level is not an 

appropriate BACT precedent. Therefore, based on vendor input specific to IG, the lowest 

achievable rate for this source is proposed to be 0.15 lb/ton using H2O2 scrubbers and high 

efficiency mist eliminators. This equates to emissions of 5.0 lbs/hr for each WSA at design 

capacity.

It is noted that there are a few other sulfuric acid plants in the RBLC which are NSPS Subpart H 

applicable plants that burn elemental sulfur to produce sulfuric acid. BACT levels for these plants 

were also all set at 0.15 lb/ton of acid produced except for one facility which was permitted at 

0.10 lb/ton. However, these types of plants are not appropriate for comparison to IG due to the 

process and equipment differences between the two operations. Plants that use elemental sulfur 

as their feedstock produce a smaller volume of tailgas for each per ton of sulfur produced –

because the “feed” has virtually no diluents (i.e.; it is pure sulfur). In contrast, plants such as the 

IG facility, which burn acid gas streams with significant non-sulfur content, have higher volume 

tail gas streams per ton of sulfur produced. A higher tail gas flow rate results in higher mass 

emission of acid mist particulates at the same exhaust concentration. 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for Wet Sulfuric Acid Plants (EU-015A/B).

The PM, PM10 and PM2.5 emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall be 

controlled by a high Efficiency Mist Eliminator and H2O2 scrubber and the PM, PM10 and PM2.5

emissions shall not exceed 0.15 pounds per ton and 5 lb/hour, each, based on a 3-hr average.

Sulfuric Acid (H2SO4) BACT – Wet Sulfuric Acid Plants (EU-015 A and B)

Step 1: Identify Potential Control Technologies

Emissions of Sulfuric Acid (H2S04) are particulates. Particulates are generally controlled with 

add-on control equipment designed to capture the emissions prior to the time they are exhausted 

to the atmosphere. 

(1) Cyclones;

 (2) Wet Scrubber;

(3) Electrostatic Precipitators (ESP);

(4) Fabric Filter Dust Collectors (Baghouses); 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.

If add-on control technology is not feasible, an alternate method of control may be implemented. 

Alternate Control Methods:
Indiana Gasification LLC Page 117 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

One or more alternate methods of control may be considered when more cost-effective than 

conventional add-on controls or when conventional add-on control technology may not be 

feasible. For the H2SO4 sources from the proposed WSAs, the following alternate control 

methods were evaluated:

(1) Mist eliminators and Hydrogen peroxide (H2O2) scrubbers;

Step 2: Eliminate Technically Infeasible Options

(a) Add-on Control Technology: Add on control devices such as fabric filters and 

electrostatic precipitators (ESPs) are not suitable for wet condensable, corrosive acid 

mist. Based on availability and applicability, conventional particulate add-on control 

technology was eliminated from consideration due to technical infeasibility.

(b) Mist eliminators and Hydrogen peroxide (H2O2) scrubber

The final step in the WSA process involves absorbing and recovering the produced 

sulfuric acid. A small amount of sulfuric acid mist can carry out with the tail gas. To 

control these emissions, a high efficiency mist elimination filter is installed downstream of 

the hydrogen peroxide scrubber that captures 75 percent of the fine acid mist. This 

removal percentage is guaranteed by the equipment vendor. This is the most efficient 

mist filter available. While the peroxide scrubber that is located upstream of the mist 

eliminator is installed primarily to control SO2, it is also estimated to remove 10% of the 

acid mist prior to the high efficiency mist eliminator filter. The peroxide scrubber uses a 

50% hydrogen peroxide (H2O2) solution which flows counter current to the flow of the gas 

stream from the WSA process.

The source is proposing to install high efficiency mist eliminators and hydrogen peroxide 

(H2O2) scrubbers to control H2SO4 emissions from the process. These controls would 

be sufficient to comply with the sulfuric acid mist limit of the NSPS Subpart H, although, 

NSPS Subpart H does not apply to the project’s WSA plant. 

Subpart H regulates sulfuric acid production plants such as those that burn elemental 

sulfur. It does not regulate WSA units “where conversion to sulfuric acid is utilized 

primarily as a means of preventing emissions to the atmosphere of sulfur dioxide or other 

sulfur compounds” (40 CFR 60.81(a)) such as the IG WSA plant. Nevertheless, the IG 

facility emissions will be at or below the Subpart H sulfuric acid mist limit of 0.15 lbs 

H2SO4 mist/ton of Acid produced.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The above control technologies have been identified for control of H2SO4 resulting from 

operation of the WSA (EU-015A/B). 

(1) High efficiency mist eliminators and hydrogen peroxide (H2O2) scrubbers

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed H2SO4 BACT determination along with the existing H2SO4

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by Indiana Gasification, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method
Indiana Gasification LLC Page 118 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 

147-30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Wet Sulfuric 

Acid Plants

(EU-015A/B)

10,400 T

dry 

coal/day 

0.15 lb/ton acid 

produced) and 

5 lbs/hour based 

on 3-hr average

High Effi. 

Mist 

Eliminator, 

H2O2

scrubber

PSD-LA-742(M1) Lake Charles 

Cogeneration, 

LLC

12/30/2010 Wet Sulfuric 

Acid Plants 

(2)*

9,413 T/D 0.15 lb/ton acid 

produced

High Effi. 

Mist 

Eliminator, 

H2O2

scrubber

081801 AAF 

(Application No. 

07100063)

Power Holdings 

of Illinois 

Gasification

10/26/2009 Sulfuric Acid 

Plants *

13,722 T 

coal per 

day

0.15 lb/ton, 0.06 

lb/ton (24-hr) 

(permit lists two 

conflicting limits on 

different pages)

High Effi. 

Mist 

Eliminator, 

H2O2

scrubber

NOTE: * These emission units have not been built yet.

All three of the above facilities have designed their WSA plants with the best possible control -

using similar technologies. All three facilities have a performance of 0.15 lb/tons acid produced. 

However, the Power Holdings of Illinois facility permit lists two conflicting emissions limits. In two 

places it lists 0.15 lb/ton acid produced, which is consistent with the NSPS standard and 

consistent with almost every other WSA in the RBLC (including those that burn elemental sulfur). 

However, it also, separately lists an emission rate of 0.06 lb/T H2SO4. IG has indicated that 

based on discussions with their WSA vendor, there is not any confidence that this low of a limit 

can be achieved. Also, the Power Holdings facility has not been built, and has not demonstrated

this level of performance. Based on this information, this lower level is not an appropriate BACT 

precedent. Therefore, based on vendor input specific to IG, the lowest achievable rate for this 

source is proposed to be 0.15 lb/T H2SO4 emissions rate using H2O2 scrubbers and high 

efficiency mist eliminators. This equates to emissions of 5.0 lbs/hr of H2SO4 for each WSA at 

design capacity.

It is noted that there are a few other sulfuric acid plants in the RBLC which are NSPS Subpart H 

applicable plants that burn elemental sulfur to produce sulfuric acid. BACT levels for these plants 

were also all set at 0.15 lb/ton of acid produced except for one facility which was permitted at 

0.10 lb/ton. However, these types of plants are not appropriate for comparison to IG due to the 

process and equipment differences between the two operations. Plants that use elemental sulfur 

as their feedstock produce a smaller volume of tailgas per ton of sulfur produced – because the 

“feed” has virtually no diluents (it is pure sulfur). In contrast, plants such as the IG facility, which 

burn acid gas streams with significant non-sulfur content, have higher volume tail gas streams per 

ton of sulfur produced. A higher tail gas flow rate results in higher mass emission of acid mist at 

the same exhaust concentration. 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for H2SO4 for Wet Sulfuric Acid Plants (EU-015A/B).

The H2SO4 emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall be controlled by a 

high Efficiency Mist Eliminator and H2O2 scrubber and the H2SO4 emissions shall not exceed 

0.15 pounds per ton acid produced and 5 lb/hour, each, based on a 3-hr average.
Indiana Gasification LLC Page 119 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Carbon Monoxide (CO) BACT – Wet Sulfuric Acid Plants (EU-015 A and B)

Step 1: Identify Potential Control Technologies

Emissions of carbon monoxide (CO) are generally controlled by oxidation. Oxidation technologies 

include regenerative thermal oxidation, catalytic oxidation, and flares.

(a) Regenerative thermal oxidation; 

(b) Catalytic oxidation; 

(c) Flares

If add-on control technology is not feasible, an alternate method of control may be implemented. 

Step 2: Eliminate Technically Infeasible Options

The RACT/BACT/LAER (RBLC) Clearinghouse and review of other New Source Review (NSR) 

permits reveal that similar gas plants sources do not use any control device to control carbon 

monoxide emissions from the Wet Sulfuric Acid Plants.

Regenerative Thermal Oxidizers

The thermal oxidizer has a nigh temperature combustion chamber that is maintained by a 

combination of auxiliary fuel, waste gas compounds, and supplemental air added when 

necessary. This technology is typically applied for destruction of organic vapors, nevertheless it is 

also considered as a technology for controlling CO emissions. Upon passing through the flame, 

the waste gas containing CO is heated. The mixture continues to react as it flows through the 

combustion chamber.

The required level of CO destruction of the waste gas that must be achieved within the time that it 

spends in the thermal combustion chamber dictates the reactor temperature. The shorter the 

residence time, the higher the reactor temperature must be. Most thermal units are designed to 

provide no more than 1 second of residence time to the waste gas with typical temperatures of 

1,200 to 2,000o

F. Once the unit is designed and built, the residence time is not easily changed, 

so that the required reaction temperature becomes a function of the particular gaseous species 

and the desired level of control. 

A Regenerative Thermal Oxidizer incorporates heat recovery and greater thermal efficiency 

through the use of direct contact heat exchangers constructed of a ceramic material that can 

tolerate the high temperatures needed to achieve ignition of the waste stream.

The inlet gas first passes through a hot ceramic bed thereby heating the stream (and cooling the 

bed) to its ignition temperature. The hot gases then react (releasing energy) in the combustion 

chamber and while passing through another ceramic bed, thereby heating it. The process flows 

are then switched, feeding the inlet stream to the hot bed. This cyclic process affords very high 

energy recovery (up to 95%). The higher capital costs associated with these high-performance 

heat exchangers and combustion chambers may be offset by the increased auxiliary fuel savings 

to make such a system economical. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a regenerative thermal oxidizer is a technically feasible option for the Wet Sulfuric Acid 

Plants at this source.

Catalytic Oxidizers
Indiana Gasification LLC Page 120 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

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 650°F to 1000°F and 

approximately require 1.5 to 2.0 ft3 of catalyst per 1000 standard ft3 per gas flow rate. 

Emissions from emission units may contain significant amount of particulates. These particulates 

can poison the catalyst resulting in the failure of catalytic oxidation. It is not known whether the 

acid mist in the WSA exhaust would poison the oxidation catalyst in this potential application.

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 Wet Sulfuric Acid Plants at this 

source.

Flare

Although the CO concentration is very low, the stream flow rate is very high. The low heating 

value of the WSA stream is too low for flaring. As there are insufficient organics in this vent 

stream to support combustion, use of a flare would require a significant addition of supplementary 

fuel. Therefore, a secondary impact of the use of flare for this stream would be the creation of 

additional emissions from burning supplemental fuel, including NOx. Flares have not been 

utilized or demonstrated as a control device for CO from this type of high-volume process stream. 

In addition, the flare would have no additional control versus the thermal oxidizers. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flare is technically infeasible option for the Wet Sulfuric Acid Plants at this source

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Regenerative Thermal Oxidizer - 99 % destruction efficiency

(2) Oxidation Catalyst - 75 % destruction efficiency

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed CO BACT determination along with the existing CO BACT 

determinations for similar plants. All data in the table is based on the information obtained from 

the permit application submitted by Indiana Gasification, LLC, the U.S. EPA RACT/BACT/LAER 

Clearinghouse (RBLC), and electronic versions of permits available at the websites of other 

permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Wet Sulfuric 

Acid Plants

(EU-015A/B)

10,400 T 

dry 

coal/day 

18.72 pounds 

per hour 

based on 3 -

hour average, 

each

None

PSD-LA742(M1)

Lake Charles 

Cogeneration, 

LLC

12/30/2010 Wet Sulfuric 

Acid Plants 

(2)*

9,413 T/D 26.33 lbs/hr, 

each

Good 

design 

and 

proper 

operation

081801 AAF 

(Application 

Power 

Holdings of 

10/26/2009 Sulfuric Acid 

Plants *

13,722 T 

coal per 

None Good Air 

pollution 
Indiana Gasification LLC Page 121 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

No. 

07100063)

Illinois 

Gasification

day control 

practices

NOTE: * These emission units have not been built yet.

Costs Effectiveness for use of RTO on the Wet Sulfuric Acid Unit Exhaust

Control 

Alternative

CO 

Emissions

Emissions 

Reduction

Control 

Capital Cost

Control 

Operating 

Cost

Total 

Annualized 

Costs

Cost 

Effectiveness Other 

Tons/yr tons/yr $ $/yr $/yr $/Ton CO Impacts

RTO 0.8 79.2 $4,270,000 $488,000 $976,000 $12,300

Additional

energy 

use & CO 

Emissions

Baseline 80.0 (proposed)

Note: Source exhaust (cfm) = 122000

Thermal Oxidation Costs based on lower - range costs for control from USEPA fact sheet for regenerative Thermal 

Oxidizer (EPA-452/F-03-021)

$35.0 capital cost $/cfm

$4.0 operating cost $/cfm

$8.0 Annualized $/cfm

99% Control efficiency for CO (Assumed) 

It is theoretically possible that further destruction of CO could be achieved with an add-on thermal 

or catalytic oxidizer. However, an add-on oxidation control technology would not be cost effective 

since the CO concentration in this stream is already low. A rough perspective of costs for an addon oxidizer can be obtained using cost ranges from US EPA’s Air Pollution Control Technology 

Fact Sheet for Regenerative Incinerators (EPA-452/F-03-021). It lists the range of annualized 

cost of a regenerative thermal oxidizer as $8 - $33 per cfm and a regenerative catalytic oxidizer 

as $11 to $41 per cfm. Since the WSA stack has a relatively large flow (even though it has a low 

concentration of CO), IG has conservatively assumed that the use of an oxidizer might have a 

cost at the lowest cost per cfm presented in this range ($8/cfm). Based on the WSA emissions 

rate of about 80 tons/yr CO and an exhaust flow rate of 122,000 cfm, the cost-effectiveness of 

controlling CO with an add-on oxidizer is conservatively estimated to be at least $12,300/ton. 

This is prohibitively expensive for a CO control device.

In addition, the use of a thermal or catalytic oxidizer for CO control will require the use of a 

significant amount of supplemental fuel (to heat the exhaust gas to the required operating 

temperature to achieve destruction). This supplemental fuel firing will create additional 

combustion pollutant emissions (particularly NOx) which will at least partially offset any benefit of 

additional CO 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 CO for Wet Sulfuric Acid Plants (EU-015A/B).

The CO emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall not exceed 18.7 pounds 

per hour based on 3 - hour average for each Wet Sulfuric Acid unit.
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Sulfur Dioxide (SO2) BACT - Wet Sulfuric Acid Plants (EU-015 A and B)

Step 1: Identify Potential Control Technologies

Sulfur dioxide (SO2) can be controlled by the use of a scrubber. In many applications, the 

scrubber is either a FGD or a dry scrubber. In those applications, the SO2 is reacted with lime, or 

limestone or caustic and converted to a sulfate or sulfite mixture which is managed as a sludge. 

In this application a peroxide based scrubber is proposed. With a hydrogen peroxide scrubber, 

the SO2 is converted to H2SO4 and the waste stream is eliminated. A more conventional 

scrubber does not provide any improved efficiency and is therefore not reviewed in the 

subsequent steps. 

Step 2: Eliminate Technically Infeasible Options

Peroxide Scrubber

The purpose of the Wet Sulfuric Acid unit is to recover sulfur that has been separated out of the 

syngas stream by the Acid Gas Recovery unit. It does this by converting the sulfur first to SO2, 

then to sulfuric acid. The WSA is very efficient in this recovery process and its inherent design 

achieves a sulfur recovery of 99.977% to sulfuric acid. Inert gases and CO2 in the unit are 

vented out the WSA stack and will contain a very small amount of SO2. The proposed control for 

SO2 from the WSA is a hydrogen peroxide scrubber. In the hydrogen peroxide scrubber, the gas 

stream from the WSA is scrubbed with a 50% solution of peroxide (H2O2). SO2 is absorbed and 

converted to acid through a chemical reaction that takes place as follows:

SO2 + H2O2 = H2SO4

The technology provider guarantees that 95% of the SO2 in the gas stream will be removed in the 

peroxide scrubber. The SO2 in the gas stream entering the scrubber is also minimized by 

inherent design of the WSA.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of peroxide Scrubber is a technically feasible option for the Wet Sulfuric Acid plants at 

this source. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Peroxide Scrubber (95 % reduction of SO2)

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed SO2 BACT determination along with the existing SO2

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by Indiana Gasification, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued 

Date

Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 147-

30464-00060

Proposed

Limit

Indiana 

Gasification 

- proposed

Proposed Wet Sulfuric 

Acid Plants

(EU-015A/B)

10,400 T

dry

coal/day 

0.25 lb/ton acid 

produced and 

8.3 pounds per 

hour, each (24-

hr avg)

peroxide 

scrubber

PSD-LA742(M1)

Lake Charles 

Cogeneration

, LLC

12/30/2010 Wet Sulfuric 

Acid Plants 

(2)*

9,413 T/D 0.5 lb/ton acid 

produced

Hydrogen 

peroxide 

scrubbing
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Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued 

Date

Process 

Description

Rating 

(TPH)

Limitation Control 

Method

081801 AAF 

(Application 

No. 

07100063)

Power 

Holdings of 

Illinois 

Gasification

10/26/2009 Sulfuric Acid 

Plants *

13,722 T 

coal per 

day

1.41 lb/ton, (30-

day), 4.0 lb/ton 

NSPS limit 90 

lb/hr and 342.4 

tons per yr

SO2 

Oxidation 

Catalyst and 

Hydrogen 

peroxide 

scrubbing

NOTE: * These emission units have not been built yet.

The Lake Charles Gasification Plant, was identified as having a non-elemental sulfur burning wet 

sulfuric acid plant. The RBLC shows the Lake Charles WSA SO2 limit of 0.5 lb SO2/Ton acid 

produced. This limit, for comparison, is well below the NSPS Subpart H limit of 4 lbs SO2/Ton 

acid produced. A recently permitted facility, the Power Holdings of Illinois facility, is also 

proposing a similar WSA plant to the IG plant. The Power Holdings facility is permitted with an 

SO2 emissions limits of 1.41 lb/T (30 Day) and 4.0 lb/T. Including sulfur-burning sulfuric acid 

plants, since 2006 there are a total of eight WSA plants in the RBLC with SO2 emissions ranging 

from a low of 0.5 lb/ton SO2 (Lake Charles) to a high of 3.0 lb/ton. SO2 emissions from all 

facilities are controlled by scrubbing the tailgas with hydrogen peroxide. 

Based on the RBLC review, a limit of 0.5 lbs SO2 / ton acid produced is judged to be BACT. 

However, IG proposes to go beyond BACT to achieve SO2 emissions of 8.3 lbs SO2/hr 

(equivalent to 0.25 lb/ton acid produced) for each WSA. This is being done to help demonstrate 

compliance with the SO2 National Ambient Air Quality Standards. This is lower than the Lake 

Charles RBLC limit, lower than indicated in Power Holdings permit, and lower than any other 

recent RBLC determination. Compliance with the lb/ton and lb/hr limits will be based on 24-hr 

block daily average because they are based on acid production rate which cannot be accurately 

calculated on an hourly 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 SO2 for Wet Sulfuric Acid Plants (EU-015A/B).

The SO2 emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall be controlled by a 

peroxide scrubber, the SO2 emissions shall not exceed 0.25 lb/ton acid produced and 8.3 lbs 

SO2/hr based on a 24-hour block daily average for each Wet Sulfuric Acid unit. 

Nitrogen Oxide (NOX) BACT - Wet Sulfuric Acid Plants (EU-015 A and B)

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) Flue Gas Recirculation (FGR)

(d) Low NOx Burner (LNB)

Add-on control technologies and combustion control approaches are discussed below.

Step 2: Eliminate Technically Infeasible Options
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Selective Catalytic Reduction (SCR)

Selective Catalytic Reduction (SCR) process involves the mixing of anhydrous or aqueous 

ammonia vapor with flue gas and passing the mixture through a catalytic reactor to reduce NOX

to water and N2. Under optimal conditions, SCR has a removal efficiency up to 90% when used 

on steady state processes. The efficiency of removal will be reduced for processes that are not 

stable or require frequent changes in the mode of operation.

The most important factor affecting SCR efficiency is temperature. SCR can operate in a flue gas 

window ranging from 500°F to 1100°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. Temperatures below the optimum decrease catalyst activity 

and allow NH3 to slip through; above the optimum range, ammonia will oxidize to form additional 

NOx. SCR efficiency is also largely dependent on the stoichiometric molar ratio of NH3:NOx; 

variation of the ideal 1:1 ratio to 0.5:1 ratio can reduce the removal efficiency to 50%.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

selective catalytic reduction (SCR) is a technically feasible option for the Wet Sulfuric Acid Plants 

at this source.

Selective Non-Catalytic Reduction (SNCR)

With selective non-catalytic reduction (SNCR), NOX is selectively removed by the injection of 

ammonia or urea into the flue gas at an appropriate temperature window of 1600°F to 2000°F 

and without employing a catalyst. Similar to SCR without a catalyst bed, the injected chemicals 

selectively reduce the NOX to molecular nitrogen and water. This approach avoids the problem 

related to catalyst fouling but the temperature window and reagent mixing residence time is 

critical for conducting the necessary chemical reaction. At the proper temperature, urea 

decomposes to produce ammonia which is responsible for NOX reduction. 

At a higher temperature, the rate of a competing reaction for the direct oxidation of ammonia that 

actually forms NOx becomes significant. At a lower temperature, the rates of NOX reduction 

reactions become too slow resulting in urea slip (i.e. emissions of unreacted urea).

Optimal implementation of SNCR requires the employment of an injection system that can 

accomplish thorough reagent/gas mixing within the temperature window while accommodating 

spatial and production rate temperature variability in the gas stream. The attainment of maximum 

NOx control performance therefore requires that the source exhibit a favorable opportunity for the 

application of this technology relative to the location of the reaction temperature range.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

selective non-catalytic reduction (SNCR) is a technically feasible option for the Wet Sulfuric Acid 

Plants 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 LNBs are specially designed pieces of combustion equipment that reduce NOx formation 

through careful control of the fuel-air mixture during combustion. In a staged air combustion LNB, 

either air or fuel is added downstream of the primary combustion zone. Depending on which of 

this NOx reduction technique is used, LNBs with staged combustion are subdivided into staged 

air burners and staged fuel burners. 
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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 other NOx reduction technique is used in conjunction with LNBs.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a low NOx burner is a technically feasible option for the Wet Sulfuric Acid Plants at this 

source

Flue Gas Recirculation (FGR)

Recirculating a portion of the flue gas to the combustion zone can lower the peak flame 

temperature and result in reduced thermal NOx production. The flue gas recirculation (FGR) can 

be highly effective technique for lowering NOx emissions from burners and it's relatively 

inexpensive to apply. Most of the early FGR work was done on boilers, and investigators found 

that recirculating up to 25% of the flue gases through the burner could lower NOx emissions to as 

little as 25% of their normal levels. FGR can lower NOx emissions on two ways; the cooled, 

relatively inert, recirculated flue gases act as heat sink, absorbing heat from the flame and 

lowering peak flame temperatures and when mixed with the combustion air, recirculated flue 

gases lower the average oxygen content of the air, starving the NOx-forming reaction for one of 

the ingredients they need.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Flue Gas Recirculation (FGR) is a technically feasible option for the Wet Sulfuric Acid 

Plants at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following control technologies have been identified for control of NOx resulting from operation 

of the Wet Sulfuric Acid Plants. The source has chosen SCR as their control for NOx emissions 

and no further analysis will be performed on the remaining less effective control devices.

(1) Selective Catalytic Reduction — (up to 90% NOx Reduction)

(2) Selective Noncatalytic Reduction (50% NOx Reduction)

(3) Low NOx Burner (LNB) — (40% — 50% NOx Reduction)

(4) Flue Gas Recirculation (FGR) — (25% NOx Reduction)

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed NOx BACT determination along with the existing NOx

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by Indiana Gasification, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or Permit 

#

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

Draft Permit No. 

147-30464-00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Wet Sulfuric 

Acid Plants

(EU-015A/B)

10,400 T 

dry 

coal/day 

10.2 lb/hr 

NOx based 

on 24-hr 

block daily 

average, 

Selective 

Catalytic 

Reduction
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Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID or Permit 

#

Facility Issued Date Process 

Description

Rating 

(TPH)

Limitation Control 

Method

each

PSD-LA-742(M1) Lake Charles 

Cogeneration, 

LLC

12/30/2010 Wet Sulfuric 

Acid Plants 

(2)*

9,413 T/D 14.305 

pounds per 

hour (each)

Selective 

Catalytic 

Reduction

081801 AAF 

(Application No. 

07100063)

Power Holdings 

of Illinois 

Gasification

10/26/2009 Sulfuric Acid 

Plants *

13,722 T 

coal per 

day

11.0 pounds 

per hour and 

38.6 tons 

per yr

Selective 

Catalytic 

Reduction

NOTE: * These emission units have not been built yet.

NOx emissions are created during the combustion of acid gases in the WSA Plant. There are a 

number of WSA facilities in the RACT/BACT/LAER Clearinghouse, but only one, the Lake 

Charles Gasification Facility, lists the use of any add-on control technology. The Lake Charles 

facility lists selective catalytic reduction (SCR) for NOx emissions with a permitted NOx emission 

rate of 13.5 lb/hr maximum emissions from each of its two WSA units. Indiana Gasification is 

also proposing to use SCR for control of NOx emissions from the WSA at an emissions rate of 

10.2 lb/hr from each WSA. Both IG and Lake Charles have the same emission rate for NOx 

based on the vendor supplied NOx lb/ton acid produced emissions factor. The IG WSA vendor 

indicates that 10.2 lb/hr is the lowest achievable emissions rate for this facility. 

Therefore, IG is proposing BACT for this source to be 10.2 lb/hr NOx (24-hr block daily average) 

from each WSA using SCR control technology when the flow to the SCR at or above a 

temperature of 750 degrees F. While IG is proposing a 24-hour average, the Lake Charles 

Gasification Facility has a one-hour limit. The Lake Charles permit indicates that compliance will 

be based on a stack test whereas IDEM is requiring that IG install a NOx CEMS on this unit. 

IDEM believes that the use of CEMS to determine compliance for 24-hour periods is a more 

stringent compliance requirement for a source with an SCR unit than a stack test with the 

average of three one-hour runs being used to determine compliance and, therefore, has 

determined that the IG limit is equivalent or more stringent than the Lake Charles limit due to the 

method of compliance determination. 

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 Wet Sulfuric Acid Plants (EU-015A/B).

The NOx emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall be limited by the use of 

a selective catalytic reduction (SCR) when the flow to the SCR is at or above a temperature of 

750 degrees F and the NOx emissions shall not exceed 10.2 pounds per hour NOx based on a 

24-hour block daily average for each Wet Sulfuric Acid unit.

Particulate Matter (PM/PM10/PM2.5) BACT – ASU and Main Cooling Tower (EU-016A and 016B)

Step 1: Identify Potential Control Technologies

Emissions of Particulate matter (PM, PM10 and PM2.5) from cooling towers are generally 

controlled by a drift elimination system. 

Step 2: Eliminate Technically Infeasible Options

The test for technical feasibility of any control option is whether it is both available and applicable 

to reducing the PM/PM10/PM2.5 emissions from the Cooling Tower.
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Drift Elimination System

Cooling towers are a source of particulate matter (PM/PM10/PM2.5) emissions from the small 

amount of water mist that is entrained with the cooling air as “drift”. The cooling water contains 

small amounts of dissolved solids which become particulate (PM/PM10/PM2.5) emissions once the 

water mist evaporates. To reduce the drift from cooling towers, drift eliminators are typically 

incorporated into the tower design to remove as many droplets as practical from the air stream 

before exiting the tower. 

Particulate matter emissions occur from cooling towers when suspended solids contained in 

water used in the cooling tower becomes airborne as the water is circulated and cooled. Drift 

eliminators contain packing which is used to limit the amount of this particulate matter which 

becomes airborne during the cooling process. As mist passes through the packing, the particles 

in the air contact and adhere to the surface of the packing. As condensed water flows down this 

packing, these particles are removed. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a drift elimination system is technically feasible option for the Main Cooling Tower and 

ASU Cooling Tower at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

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.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with other

PM, PM10 and PM2.5 BACT determinations for cooling towers. All data in the table is based on 

the information obtained from the U.S. EPA database of proposed gasification projects, the U.S. 

EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at 

the websites of other permitting agencies.

Existing PM/PM10/PM2.5 BACT Limits – Cooling Tower

Company Name / Operation RBLC ID Date of 

Permit

Control Technology & 

Compliance Methods and 

BACT Limit

Indiana Gasification -

proposed – Draft Permit No. 147-

30464-00060

Proposed

Limit

N/A N/A High efficiency drift 

eliminators designed to 

0.0005% maximum drift 

Gainesville Renewable Energy 

Center

FL-0323 12/28/2010 0.0005% Drift

Warren County Biomass Energy GA-0141 12/17/2010 0.0005% Drift

Specialty Minerals Inc. –

Superior

WI-0252 7/22/2010 0.0005% Drift

Wolf Hollow Power Plant #2 TX-0552 3/3/2010 0.0005% Drift

Panda Sherman Power LLC TX-0551 2/3/2010 0.0005% Drift

Power Holdings of Illinois N/A 10/26/2009 0.0005% Drift

Lake Charles Gasification LA-0231 12/30/2010 0.0005 % Drift 

USEPA’s RACT/BACT/LAER Clearinghouse shows BACT determinations specifying the use of 

drift/mist eliminators for controlling PM, PM10 and PM2.5 emissions, with drift rates ranging from 

0.003% – 0.0005%. A design drift rate of 0.0005% appears in the most recent permit 

determinations and it represents the best performing of all cooling towers in the RBLC and the 
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highest efficiency mist eliminators available in the cooling tower design. Additionally, cooling 

tower particulate can be reduced by effective management of the total dissolved solids (TDS) 

content in the cooling water. IG has indicated that the TDS level in the cooling water will be 

monitored and maintained at a no more than 1500 ppm TDS based on a daily average by 

adjustment of the cooling tower blowdown (purge) rate. 

Proposal: Indiana Gasification, LLC, Rockport, IN

The following has been proposed as BACT by for PM, PM10 and PM2.5 emissions from the ASU 

Cooling Tower EU-016A and Main Cooling Tower EU-016B operations:

Therefore, a 0.0005% drift/mist eliminator system along with a maximum TDS of 1500 ppm based 

on a daily average is proposed as BACT for PM, PM10 and PM2.5 emissions from both the Main 

and ASU Cooling Towers. 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM, OAQ has 

approved the proposed PM, PM10 and PM2.5 BACT for the ASU Cooling Tower EU-016A and 

Main Cooling Tower EU-016B. 

The PM, PM10 and PM2.5 emissions from the ASU Cooling Tower (EU-016A) and the Main 

Cooling Tower (EU-016B) shall be controlled by High efficiency drift eliminators designed with a 

drift loss rate of less than 0.0005% and total dissolved solids shall not exceed 1500 ppm based 

on a daily average.

Sulfuric Acid (H2S04) BACT – Sulfuric Acid Tanks (EU-027A - F)

Step 1: Identify Potential Control Technologies

Emissions of Sulfuric Acid (H2S04) are generally controlled with add-on control equipment 

designed to capture the emissions prior to the time they are exhausted to the atmosphere. 

(1) Cyclones;

 (2) Wet Scrubber;

(3) Electrostatic Precipitators (ESP);

(4) Fabric Filter Dust Collectors (Baghouses); and

(5) Cartridge Collectors.

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.

If add-on control technology is not feasible, an alternate method of control may be implemented. 

Alternate Control Methods:

One or more alternate methods of control may be considered when more cost-effective than 

add-on controls or when add-on control technology may not be feasible. For the Sulfuric Acid 

(H2S04) emission sources at the proposed Gas Plant, the following alternate control methods 

were evaluated:
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(1) Fixed roof tanks with a pressure/vacuum vent and submerged fill pipes

Step 2: Eliminate Technically Infeasible Options

These control alternatives are further described as follows.

(a) Add-on Control Technology: Add on control devices such as fabric filters, electrostatic 

precipitators (ESPs), and scrubbers are not technically feasible for this source's very low 

PM emission rates(<0.001 ton/yr). Based on availability and applicability, add-on control 

technology was eliminated from consideration due to technical infeasibility.

(b) Fixed roof tanks with a pressure/vacuum vent and submerged fill pipes

The sulfuric acid tanks will have very little acid mist emissions (<0.001 ton/yr, for each 

tank). The tanks vent will be fitted with a pressure/vacuum control and the fill pipe shall 

be placed below the normal liquid level (submerged fill pipe). The vent should open to 

the atmosphere only as needed when the tank is up-gauging – to relieve the displaced 

vapors. The sulfuric acid tanks will be equipped with a nitrogen blanket which is 

necessary to keep oxygen and moisture out of the tanks. The nitrogen blanket is 

designed to keep a slight pressure on the vacuum vent and is not designed as a nitrogen 

“sweep”. The nitrogen blanket does not cause or change the emissions of H2SO4 from 

the tanks. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The above control technologies have been identified for control of H2SO4 resulting from operation 

of the Sulfuric Acid tanks (EU-027A-F). 

(1) Fixed roof tanks with a pressure/vacuum vent and submerged fill pipes.

Step 4: Evaluate the Most Effective Controls and Document the Results

The sulfuric acid storage tanks are fixed roof tanks with a Pressure Vacuum (PV) vent. This is 

standard storage technology for low vapor pressure materials, less than about 1 psia. The vapor 

pressure of the sulfuric acid is extremely low (less than 0.001 psia) at maximum ambient 

conditions, so any vapor releases will be very small (estimated emissions from all sulfuric acid 

tanks are 0.0011 tons/yr.) Also, because of the very small emissions rate and dilute 

concentration, add-on controls such as a “mist eliminator” would not be effective.

The tanks also will operate with a nitrogen “blanket”. This means that when the tank level drops, 

that nitrogen will be introduced to fill the new vapor space rather than letting air be drawn in 

through the PV vent. This is to avoid tank corrosion or fire hazards from air in the tank. This inert 

“blanket” is not a nitrogen “sweep”, and will not increase emissions from the tank.

Proposal: Indiana Gasification, LLC 

The following has been proposed as BACT for H2SO4 from the proposed Sulfuric Acid tanks at 

the Indiana Gasification Plant.

BACT for H2SO4 is proposed to be a fixed roof tank and submerged fill.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for H2SO4 for the Sulfuric Acid tanks.

The H2SO4 emissions from the Sulfuric Acid tanks shall be limited by the use of a fixed roof tank 

and submerged fill.
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Particulate Matter (PM/PM10/PM2.5) BACT – ZLD Spray Dryer (EU-032)

Step 1: Identify Potential Control Technologies

Emissions of PM, PM10 and PM2.5 are generally controlled with add-on control equipment 

designed to capture the emissions prior to the time they are exhausted to the atmosphere. In the 

case of a spray dryer, the material being dried is entrained and the control of PM is coincident 

with the recovery of dried material. Generally, PM, PM10 and PM2.5 emissions are controlled 

through one of the following mechanisms:

(1) Cyclones;

 (2) Wet Scrubber;

(3) Electrostatic Precipitators (ESP); and

(4) Fabric Filter Dust Collectors (Baghouses).

The choice of which technology is most appropriate for a specific application depends upon 

several factors, including particle size to be collected, particle loading, stack gas flow rate, stack 

gas physical characteristics (e.g., temperature, moisture content, presence of reactive materials), 

and desired collection efficiency.

Step 2: Eliminate Technically Infeasible Options

(a) Cyclones:

Cyclones are simple mechanical devices commonly used to remove relatively large 

particles from gas streams. In industrial applications, cyclones are often used as 

precleaners for the more sophisticated air pollution control equipment such as ESPs or 

baghouses. Cyclones are less efficient than wet scrubbers, baghouses, or ESPs. 

Cyclones used as pre-cleaners are often designed to remove more than 80% of the 

particles that are greater than 20 microns in diameter. Smaller particles that escape the 

cyclone can then be collected by more efficient control equipment. This control 

technology may be more commonly used in industrial sites that generate a considerable 

amount of particulate matter, such as lumber companies, feed mills, cement plants, and 

smelters.

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the use of a cyclone is a technically feasible option for the spray dryer 

associated with the Zero Liquid Discharge (ZLD) at this source.

(b) Wet Scrubber

A wet scrubber is an air pollution control device that removes particulates 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 particulates. 

Collection efficiencies for wet scrubbers vary with the particle size distribution of the 

waste gas stream. In general, collection efficiency decreases as the particulates 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 particulates with the following characteristics:

(1) Sticky and/or hygroscopic materials (materials that readily absorb water);
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(2) Combustible, corrosive and explosive materials;

(3) Particles that are difficult to remove in their dry form;

(4) Particulates in the presence of soluble gases; and

(5) Particulates in waste gas streams with high moisture content.

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the use of a wet scrubber is a technically feasible option for the collection 

of material from the spray dryer associated with the Zero Liquid Discharge (ZLD) at this 

source.

(c) Electrostatic Precipitators:

An electrostatic precipitator (ESP) is a particle control device that uses electrical forces to 

move the particles out of the flowing gas stream and onto collector plates. The particles 

are given an electrical charge by forcing them to pass through a corona, a region in which 

gaseous ions flow. The electrical field that forces the charged particles to the walls comes 

from electrodes maintained at high voltage in the center of the flow lane.

Once the particles are collected on the plates, they must be removed from the plates 

without re-entraining them into the gas stream. This is usually accomplished by knocking 

them loose from the plates, allowing the collected layer of particles to slide down into a 

hopper from which they are evacuated. Some precipitators remove the particles by 

intermittent or continuous washing with water. ESP control efficiencies can range from 

99% to 99.9%.

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the use of an Electrostatic Precipitator is a technically feasible option for 

the collection of PM from the spray dryer associated with the Zero Liquid Discharge 

(ZLD) at this source.

(d) Fabric Filtration:

A fabric filter unit consists of one or more isolated compartments containing rows of fabric 

bags in the form of round, flat, or shaped tubes, or pleated cartridges. Particle laden gas

passes up (usually) along the surface of the bags then radially through the fabric. 

Particles are retained on the upstream face of the bags, and the cleaned gas stream is 

vented to the atmosphere. The filter is operated cyclically, alternating between relatively 

long periods of filtering and short periods of cleaning. During cleaning, dust that has 

accumulated on the bags is removed from the fabric surface and deposited in a hopper 

for subsequent disposal. Fabric filters collect particles with sizes ranging from submicron 

to several hundred microns in diameter at efficiencies generally in excess of 99%. 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. 
Indiana Gasification LLC Page 132 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Typical values of system pressure drop range from about 1 to 20 inches of water. Fabric 

filters are used where high efficiency particle collection is required. Limitations are 

imposed by gas characteristics (temperature and corrosivity) and particle characteristics 

(primarily stickiness) that affect the fabric or its operation and that cannot be 

economically accommodated. Important process variables include particle 

characteristics, gas characteristics, and fabric properties. The most important design 

parameter is the air- or gas-to-cloth ratio (the amount of gas in ft3

/min that penetrates one 

ft2 of fabric) and the usual operating parameter of interest is pressure drop across the 

filter system. 

The major operating feature of fabric filters that distinguishes them from other gas filters 

is the ability to renew the filtering surface periodically by cleaning. Common furnace 

filters, high efficiency particulate air (HEPA) filters, high efficiency air filters (HEAFs), and 

automotive induction air filters are examples of filters that must be discarded after a 

significant layer of dust accumulates on the surface. These filters are typically made of 

matted fibers, mounted in supporting frames, and used where dust concentrations are 

relatively low. Fabric filters are usually made of woven or (more commonly) 

needle-punched felts sewn to the desired shape, mounted in a plenum with special 

hardware, and used across a wide range of dust concentrations.

Based on the information reviewed for this BACT determination, IDEM, OAQ has 

determined that the use of a fabric filter is a technically feasible option for the control of 

PM from the spray dryer associated with the Zero Liquid Discharge (ZLD) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The above control technologies have been identified for control of PM, PM10 and PM2.5 resulting 

from operation of the Spray dryer associated with the Zero Liquid Discharge (ZLD) Spray Dryer. 

(1) Fabric Filtration (99% - 99.9% PM/PM10/PM2.5 Reduction)

(2) Electrostatic Precipitator (99% - 99.9% PM/PM10/PM2.5 Reduction)

(3) Wet Scrubber (99% PM/PM10/PM2.5 Reduction)

(4) Cyclones (80% PM/PM10/PM2.5 Reduction)

Both the Electrostatic Precipitator and the Fabric Filtration have the same control efficiencies, 99% -

99.9%. The source has selected the Fabric Filtration for this unit which is the highest efficiency 

alternative.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with other 

PM, PM10 and PM2.5 BACT determinations for similar but larger spray dryers. All data in the table 

is based on the information obtained from the U.S. EPA database of proposed gasification 

projects, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of 

permits available at the websites of other permitting agencies.

BACT ID 

or Permit 

#

Facility Issued 

Date

Process 

Description

Rating Limitation Control 

Method

Estimated 

Control 

Efficiency

Draft 

Permit 

No. 147-

30464-

Indiana 

Gasification -

proposed

Proposed ZLD spray 

dryer

5.6 

MMBtu/hr

0.005

gr/dscf

Baghouse Not 

specified
Indiana Gasification LLC Page 133 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

BACT ID 

or Permit 

#

Facility Issued 

Date

Process 

Description

Rating Limitation Control 

Method

Estimated 

Control 

Efficiency

00060

Proposed

Limit

OK-0118 Western 

Farmers 

Electric Coop 

Hugo 

Generating 

Station

2/9/2007 Wastewater 

(brine) spray 

dryer

20 

MMBtu/hr

PM10: 

0.20 lb/hr

Good 

combustion 

control 

Not 

specified

OK-0111* Dal Italia LLC 

Muskogee 

Porcelain Floor 

Tile Plant

10/14/2005 Spray Dryers 49.1 

MMBtu/hr

PM10: 

0.018 

gr/dscf

Baghouse Not 

specified

AZ-0046 Arizona Clean 

Fuels Yuma

4/14/2005 Spray Dryer 

Heater

44 

MMBtu/hr

PM10: 

0.0075 

lb/MMBTU

Not 

specified

Not 

specified

OH-282 Cargill Oilseeds 

Division

11/28/2003 Isolate Plant 

Soy Protein 

Spray Dryer

114 

MMBtu/hr

PM10: 

0.003 

gr/dscf; 

4.68 lbs/hr; 

20.5 tons 

per rolling 

12 months

Baghouse 

and 

separation 

cyclone

Not 

specified

*BACT/LAER clearinghouse for this determination lists a PM10 limit of 0.0.017 gr/dscf and an estimated efficiency of 99.0%. The 

above PM10 limit is from the permit 2004-198-C (M-1).

One of the listed BACT limits is lower than what has been proposed by IG. However, this unit is drying 

soy protein rather than inorganic salt and thereby, the particle characteristics and size distributions are 

not comparable. In addition, this unit is 20 times larger (in firing rate) than the IG spray dryer. Therefore, 

this lower grain loading number is not a relevant precedent for this BACT determination.

Proposal: Indiana Gasification, LLC, Rockport, IN

The following has been proposed as BACT by for PM, PM10 and PM2.5 emissions from the Zero Liquid 

Discharge (ZLD) operations:

(1) A fabric filter baghouse.

(2) The PM, PM10 and PM2.5 emissions shall not exceed 0.005 gr/dscf based on 3 hour average. 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM, OAQ has 

established PM, PM10 and PM2.5 BACT for the Zero Liquid Discharge (ZLD) Spray Dryer:

The PM, PM10 and PM2.5 emissions from the Zero Liquid Discharge (ZLD) spray dryer shall be 

controlled by a fabric filter baghouse and the PM, PM10 and PM2.5 emissions shall not exceed 

0.005 gr/dscf based on a 3 hour average.
Indiana Gasification LLC Page 134 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Carbon Monoxide (CO) BACT – ZLD Spray Dryer (EU-032)

Step 1: Identify Potential Control Technologies

Emissions of carbon monoxide (CO) are generally controlled by combustion control or add on 

oxidation systems. Such add-on control technologies include regenerative thermal oxidation, 

catalytic oxidation, and flares.

(a) Regenerative thermal oxidation; 

(b) Catalytic oxidation; 

(c) Flares

(d) Combustion Control

If add-on control technology is not feasible, an alternate method of control may be implemented. 

Step 2: Eliminate Technically Infeasible Options

Regenerative Thermal Oxidizers

The thermal oxidizer is a high temperature process 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. The ignition occurs at some point during the heating of a waste stream 

as it passes through the combustion chamber. The mixture continues to react as it flows through 

the combustion chamber.

The level of CO destruction within the time that it spends in the thermal combustion chamber 

dictates the reactor temperature. The shorter the residence time, the higher the reactor 

temperature must be. Most thermal units are designed to provide no more than 1 second of 

residence time to the waste gas with typical temperatures of 1,200 to 2,000o

F. Once the unit is 

designed and built, the residence time is not easily changed, so that the required reaction 

temperature becomes a function of the particular gaseous species and the desired level of 

control. 

Regenerative Thermal Oxidizers achieve high 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). 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, now 

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. 
Indiana Gasification LLC Page 135 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a regenerative thermal oxidizer is a technically feasible option for the Zero Liquid 

Discharge (ZLD) Spray Dryer 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 650°F to 1000°F and 

approximately require 1.5 to 2.0 ft3 of catalyst per 1000 standard ft3 per gas flow rate. 

Emissions from emission units may contain significant amount of particulates. These particulates 

can poison the catalyst resulting in the failure of catalytic oxidation.

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 Zero Liquid Discharge (ZLD) 

Spray Dryer at this source.

Flare

The low heating value of the spray dryer exhaust is too low for flaring. As there are insufficient 

organics in this vent stream to support combustion, use of a flare would require a significant 

addition of supplementary fuel. Therefore, a secondary impact of the use of flare for this stream 

would be the creation of additional emissions from burning supplemental fuel, including NOx. 

Flares have not been utilized or demonstrated as a control device for CO from this type of 

process stream. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flare is a technically infeasible option for the Zero Liquid Discharge (ZLD) Spray 

Dryer at this source.

Combustion Control 

Because CO is essentially a by-product of incomplete or inefficient combustion, combustion 

control constitutes the primary mode of reduction of CO emissions. This type of control is 

appropriate for any type of fuel combustion source. Combustion process controls involve 

combustion chamber designs and operating practices that improve the oxidation process and 

minimize incomplete combustion. CO emissions result from the incomplete combustion of carbon 

and organic compounds. Factors affecting CO emissions include firing temperatures, residence 

time in the combustion zone and combustion chamber mixing characteristics.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Combustion Control is a technically feasible option for the Zero Liquid Discharge 

(ZLD) Spray Dryer at this source.
Indiana Gasification LLC Page 136 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Regenerative Thermal Oxidizer - 99 % destruction efficiency

(2) Oxidation Catalyst - 75 % destruction efficiency

(3) Combustion Control

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed CO BACT determination along with other CO BACT 

determinations for similar but lager spray dryers. All data in the table is based on the information 

obtained from the U.S. EPA database of proposed gasification projects, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating Limitation Control 

Method

Estimated 

Control 

Efficiency

Draft 

Permit No. 

147-30464-

00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed 5.6

MMBtu/hr

5.6 MMBtu/hr 0.036 

lb/MMBtu

Good 

Combustion

Not specified

OK-0118 Western Farmers 

Electric Coop 

Hugo Generating 

Station

2/9/2007 Wastewater 

(brine) spray 

dryer

20 MMBTU/hr 0.70 lb/hr Good 

combustion 

control 

Not specified

OK-0111* Dal Italia LLC 

Muskogee 

Porcelain Floor 

Tile Plant

10/14/2005 Spray Dryers 49.1 MMBT/hr 13.77 lb/hr Good 

combustion

Not specified

AZ-0046 Arizona Clean 

Fuels Yuma

4/14/2005 Spray Dryer 

Heater

44 MMBTU/hr 0.04 

lb/MMBTU

Not specified Not specified

LA-0184 Louisiana 

Pigment 

Company 

Titanium Dioxide 

Facility

5/13/2003 Spray Dryer 

Dust 

Collectors

25.5 

MMBTU/hr

2.31 lb/hr Good 

equipment 

design and 

proper 

combustion 

techniques.

Not specified

*BACT/LAER clearinghouse for this determination lists a CO limit of 0.23 lb/ton and an estimated efficiency of 99.5%, but this 

information could not be found in the permit. The above information is from the permit 2004-198-C (M-1).

This review indicates that the proposed limit is consistent with recent BACT determinations for similar

Costs Effectiveness for use of RTO on Zero Liquid Discharge Dryer

Control 

Alternative

CO 

Emissions

Emissions 

Reduction

Control 

Capital Cost

Control 

Operating 

Cost

Total 

Annualized 

Costs

Cost 

Effectiveness Other 

Tons/yr tons/yr $ $/yr $/yr $/Ton CO Impacts

RTO 0.0089 0.8811 $233,800 $16,700 $55,110 $62,500

Additional

energy 

use & CO 

Emissions

Baseline 0.9 (proposed)

Note: Source exhaust (cfm) = 1670
Indiana Gasification LLC Page 137 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Thermal Oxidation Costs based on lower - range costs for control from USEPA fact sheet for regenerative Thermal 

Oxidizer (EPA-452/F-03-021)

$140.0 capital cost $/cfm

$10.0 operating cost $/cfm

$33.0 Annualized $/cfm

99% Control efficiency for CO (Assumed) 

It is theoretically possible that further destruction of CO could be achieved using an add-on 

thermal or catalytic oxidizer. However, an add-on oxidation control technology would not be cost 

effective since the CO concentration and overall emissions in this stream is already low. A rough 

perspective of costs for an add-on oxidizer can be obtained using cost ranges from US EPA’s Air 

Pollution Control Technology Fact Sheet for Regenerative Incinerators (EPA-452/F-03-021). It 

lists the range of annualized cost of a regenerative thermal oxidizer as $8 - $33 per cfm and a 

regenerative catalytic oxidizer as $11 to $41 per cfm. Since the ZLD dryer is an extremely small 

combustion source, it has been assumed that the use of an oxidizer might have a cost at the 

higher end of the cost per cfm range for an RTO ($33/cfm). Based on the WSA emissions rate of 

about 0.89 tons/yr CO and an exhaust flow rate of 1670 cfm, the cost-effectiveness of controlling 

CO with an add-on oxidizer is estimated to be at over $60,000/ton. This cost is clearly excessive 

for CO BACT. 

Besides the cost issues, use of a thermal or catalytic oxidizer for CO control will require the use of 

a significant amount of supplemental fuel (to heat the exhaust gas to the required operating 

temperature to achieve destruction). This supplemental fuel firing will create additional 

combustion pollutant emissions (especially NOx) which will at least partially offset any benefit of 

additional CO control.

Proposal: Indiana Gasification, LLC, IN

The following has been proposed as BACT for CO from the proposed Zero Liquid Discharge 

(ZLD) Spray Dryer;

(1) Good Combustion Practices

(2) Emission limitation of 0.036 lb/MMBtu of CO based on 3 hour 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 CO for Zero Liquid Discharge (ZLD) Spray Dryer.

The CO emissions from the Zero Liquid Discharge (ZLD) Spray Dryer shall not exceed 0.036 

lb/MMBtu and shall use good combustion practices.

Sulfur Dioxide (SO2) BACT - ZLD Spray Dryer (EU-032)

Step 1: Identify Potential Control Technologies

Emissions of Sulfur dioxide (SO2) from gas fired spray dryers such as the Zero Liquid Discharge 

(ZLD) Spray Dryer proposed here are generally not controlled. Much larger sources of SO2 are 

generally controlled by; 

1. Flue Gas Desulfurization

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 SO2 emissions from the Zero Liquid Discharge (ZLD).
Indiana Gasification LLC Page 138 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

The test for technical feasibility of any control option is whether it is both available and applicable 

to reducing SO2 emissions from the gas-fired Zero Liquid Discharge (ZLD) Spray Dryer.

Flue Gas Desulfurization (FGD) System (Wet or Dry Scrubber)

A flue gas desulfurization system (FGD) is comprised of a spray dryer that uses lime as a reagent 

followed by particulate control or wet scrubber that uses limestone as a reagent. FGD is an 

established technology. The concentration of SO2 in the exhaust gas is the driving force for the 

reaction between SO2 and the reagent. 

Therefore, removal efficiencies are significantly reduced with lower inlet concentrations of SO2. 

FGD systems are listed in the RBLC as BACT for sources high in SO2 emissions. Even though 

the SO2 concentrations in the exhaust gases are very low, and the airflow volume is large, the 

scrubbing systems are technically feasible. Wet scrubbing FGD system is considerably cheaper 

than dry scrubbing.

SO2 emissions result only from the trace levels of sulfur present in the small amount of natural 

gas or SNG used. Clean natural gas combustion exhaust contains less than 2 ppm SO2. This is 

too low for any add-on control technology such as a wet scrubber to be feasible. Wet scrubbing 

systems are typically only installed on exhaust streams of coal and oil fired units, with an inlet 

pollutant loading of approximately 250 - 2000 ppm SO2. In the very best cases, wet scrubbing 

systems can achieve up to as high as 98% control and reduce SO2 to single digit ppm levels. 

However, this vent is already less than 2 ppm SO2 (because of the clean fuel used).

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a flue gas desulfurization system (FGD) is not a technically feasible option for the Zero 

Liquid Discharge (ZLD) Spray Dryer at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

there is no viable technology for controlling the SO2 emissions resulting from the Zero Liquid 

Discharge (ZLD) Spray Dryer.

Step 4: Evaluate the Most Effective Controls and Document the Results

No BACT determinations for SO2 from Spray Dryers were located in the RBLC data base. Based 

on the information reviewed for this BACT determination, IDEM, OAQ has determined that there 

is no viable technology for controlling the SO2 emissions resulting from the Zero Liquid Discharge 

(ZLD) spray dryer.

Proposal: Indiana Gasification, LLC, - Rockport, IN

The following has been proposed as BACT for SO2 from the proposed Zero Liquid Discharge 

(ZLD) Spray Dryer;

(1) The use of a clean burning gaseous fuel.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for SO2 for Zero Liquid Discharge (ZLD) Spray Dryer.

The SO2 emissions from the Zero Liquid Discharge (ZLD) Spray Dryer shall be limited through

the use of a clean burning gaseous fuel.
Indiana Gasification LLC Page 139 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Nitrogen Oxide (NOX) BACT - ZLD Spray Dryer (EU-032)

Step 1: Identify Potential Control Technologies

The nitrogen oxide (NOx) emissions can be controlled by the followings: 

(a) Selective Catalytic Reduction (SCR)

(b) Selective Non-Catalytic Reduction (SNCR)

(c) Flue Gas Recirculation (FGR)

(d) Low NOx Burner (LNB)

Add-on control technologies and combustion control approaches are discussed below.

Step 2: Eliminate Technically Infeasible Options

Selective Catalytic Reduction (SCR)

Selective Catalytic Reduction (SCR) process involves the mixing of anhydrous or aqueous 

ammonia vapor with flue gas and passing the mixture through a catalytic reactor to reduce NOX

to water and N2. Under optimal conditions, SCR has removal efficiency up to 90% when used on 

steady state processes. The efficiency of removal will be reduced for processes that are not 

stable or require frequent changes in the mode of operation.

The most important factor affecting SCR efficiency is temperature. SCR can operate in a flue gas 

window ranging from 500°F to 1100°F, although the optimum temperature range depends on the 

type of catalyst and the flue gas composition. Temperatures below the optimum decrease catalyst 

activity and allow NH3 to slip through; above the optimum range, ammonia will oxidize to form 

additional NOx. SCR efficiency is also largely dependent on the stoichiometric molar ratio of 

NH3:NOx; variation of the ideal 1:1 ratio to 0.5:1 ratio can reduce the removal efficiency to 50%. 

The Zero Liquid Discharge (ZLD) Spray Dryer emits less than 1.0 ton per year of NOx emissions. 

The burner size for the ZLD spray dryer is 5.6 MMBtu/hr total. The spray dryer will fire natural gas 

during startup operations and fire SNG during normal operations. The baseline emission level of 

NOx from this size burner is sufficiently low that no further, quantifiable emission reduction would 

be achieved by add-on technologies. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

selective catalytic reduction (SCR) is not a technically feasible option for the Zero Liquid 

Discharge (ZLD) Spray Dryer at this source.

Selective Non-Catalytic Reduction (SNCR)

With selective non-catalytic reduction (SNCR), NOX is selectively removed by the injection of 

ammonia or urea into the flue gas at an appropriate temperature window of 1600°F to 2000°F 

and without employing a catalyst. Similar to SCR without a catalyst bed, the injected chemicals 

selectively reduce the NOX to molecular nitrogen and water. This approach avoids the problem 

related to catalyst fouling but the temperature window and reagent mixing residence time is 

critical for conducting the necessary chemical reaction. At the proper temperature, urea 

decomposes to produce ammonia which is responsible for NOX reduction. At a higher 

temperature, the rate of a competing reaction for the direct oxidation of ammonia that actually 

forms NOx becomes significant. At a lower temperature, the rates of NOX reduction reactions 

become too slow resulting in urea slip (i.e. emissions of unreacted urea).
Indiana Gasification LLC Page 140 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Optimal implementation of SNCR requires the employment of an injection system that can 

accomplish thorough reagent/gas mixing within the temperature window while accommodating 

spatial and production rate temperature variability in the gas stream. The attainment of maximum 

NOx control performance therefore requires that the furnace exhibit a favorable opportunity for the 

application of this technology relative to the location of the reaction temperature range.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

selective non-catalytic reduction (SNCR) is not a technically feasible option for the Zero Liquid 

Discharge (ZLD) Spray Dryer 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 technique were implemented to lower peak flame temperature and oxygen availability.

The LNBs are specially designed pieces of combustion equipment that reduce NOx formation 

through careful control of the fuel-air mixture during combustion. In a stage air combustion LNB, 

either air or fuel is added downstream of the primary combustion zone. 

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 other NOx reduction technique is used in conjunction with LNBs.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Low NOx Burner is a technically feasible option for the Zero Liquid Discharge (ZLD) 

Spray Dryer at this source.

Flue Gas Recirculation (FGR)

Recirculating a portion of the flue gas to the combustion zone can lower the peak flame 

temperature and result in reduced thermal NOx production. The flue gas recirculation (FGR) can 

be an effective technique for lowering NOx emissions from burners.

Most of the early FGR work was done on boilers, and investigators found that recirculating up to 

25% of the flue gases through the burner could lower NOx emissions to as little as 25% of their 

normal levels. FGR can lower NOx emissions on two ways; The cooled, relatively inert, 

recirculated flue gases act as heat sink, absorbing heat from the flame and lowering peak flame 

temperatures and when mixed with the combustion air, recirculated flue gases lower the average 

oxygen content of the air, starving the NOx-forming reaction for one of the ingredients they need.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Flue Gas Recirculation (FGR) is technically feasible option for the Zero Liquid 

Discharge (ZLD) Spray Dryer at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The above control technologies have been identified for control of NOx resulting from operation of 

the Zero Liquid Discharge (ZLD). Based on the technical feasibility analysis in Step 2, the 

source has chosen Low NOx Burner (LNB) as their control for NOx emissions and no further 

analysis will be performed on the remaining control devices.

(1) Low NOx Burner (LNB) — (40% — 50% NOx Reduction)

(2) Flue Gas Recirculation (FGR) — (25% NOx Reduction)
Indiana Gasification LLC Page 141 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed NOx BACT determination along with other NOx BACT 

determinations for similar but spray dryers. All data in the table is based on the information 

obtained from the U.S. EPA database of proposed gasification projects, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process 

Description

Rating Limitation Control 

Method

Estimated 

Control 

Efficiency

Draft Permit 

No. 147-30464-

00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed ZLD Spray 

Dryer

5.6 

MMBtu/hr

0.035 

lb/MMBtu

Low 

NOx 

burners.

AZ-0046 Arizona Clean 

Fuels Yuma

4/14/2005 Spray Dryer 

Heater

44 

MMBTU/hr

0.03 

lb/MMBTU

Low NOx 

burners

Not 

specified

OH-282 Cargill 

Oilseeds 

Division

11/28/2003 Isolate Plant 

Soy Protein 

Spray Dryer

114 

MMBTU/hr

0.065 

lb/MMBTU

; 7.41 

lbs/hr; 

32.46 tons 

per rolling 

12 months

Low NOx 

burners

Not 

specified

A review of the RBLC indicates that the best control for NOx emissions from such a source is the use of 

low NOx burners (LNB). It is noted that one of the past BACT determinations has a slightly lower emission 

rate limit. However, that unit is eight times larger. It is recognized that low NOx burner technology can be 

more sophisticated and effective with larger units. Therefore, the limit proposed by IG is consistent with 

and in comparison to prior BACT determinations

Proposal: Indiana Gasification, LLC, IN

The following has been proposed as BACT for NOx from the proposed Zero Liquid Discharge 

(ZLD) Spray Dryer;

(1) The use of a Low NOx Burner

(2) Emission limitation of 0.035 lb/MMBtu of NOx based on a 3 hour 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 Zero Liquid Discharge (ZLD) Spray Dryer.

The NOx emissions from the Zero Liquid Discharge (ZLD) Spray Dryer shall not exceed 0.035 

lb/MMBtu and shall use a Low NOx Burner (LNB).
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Permit Reviewer: Josiah Balogun

Sulfur Dioxide (SO2) BACT - Fugitive Leaks from piping (FUG & FUG-WSA)

Step 1: Identify Potential Control Technologies

The SO2 emissions from fugitive leaks can be controlled by;

(a) Leak detection and Repair (LDAR)

Step 2: Eliminate Technically Infeasible Options

There are small amounts of SO2 emissions from fugitive leaks from equipment and pipe 

components such as pumps, valves, flanges and compressors. IG plans to implement a Leak 

Detection and Repair (LDAR) program on select streams. Specifically, LDAR is proposed for the 

piping components in VOC service (methanol & propylene) and for WSA piping in SO2 service. 

The selected LDAR program is primarily for the purpose of controlling organic HAPs and VOC. 

Additionally, SO2 is being controlled in the section of WSA piping between the combustor and 

oxidation. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(a) Leak Detection and Repair (LDAR) 

Step 4: Evaluate the Most Effective Controls and Document the Results

Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for SO2 from the Fugitive Leaks from Equipment 

(FUG and FUG-WSA).

The BACT for fugitive leaks of SO2 in the WSA is proposed as the use of a Leak Detection and 

Repair (LDAR) program.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for SO2 for the Fugitives Leaks from piping (FUG and FUG - WSA).

The BACT for the fugitive leaks of SO2 in the WSA is the use of a Leak Detection and Repair 

(LDAR) program.

CO and H2SO4 BACT - Fugitive Leaks from piping (FUG & FUG-WSA)

Step 1: Identify Potential Control Technologies

The emissions such as CO and H2SO4 from fugitive leaks can be controlled by;

(a) Leak detection and Repair (LDAR)

(b) No Controls

Step 2: Eliminate Technically Infeasible Options

There is a very small amount of emissions of CO and H2SO4 from fugitive leaks from equipment 

and pipe components such as pumps, valves, flanges and compressors. The source plans to 
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Permit Reviewer: Josiah Balogun

implement a Leak Detection and Repair (LDAR) program on select streams. Specifically, LDAR

is proposed for the piping components in VOC service (methanol & propylene). The selected

LDAR program is primarily for the purpose of controlling organic HAPs and VOC. The use of an 

LDAR program to control CO or H2SO4 would be extremely unusual and would require use of 

different instrumentation than a conventional organic LDAR program. Consequently, IG has not 

proposed use of LDAR for the other syngas or WSA acid gas streams.

The table below shows the typical expected concentration of each of the main process streams 

from the IG facility that contain non-trace levels of CO and H2SO4 and the very small amount of 

their emissions from the facility.

Table 1

Concentrations of Pollutants in each Process Stream

BACT Pollutants Other 

Process Streams CO H2SO4 Pollutants

Raw Syngas 20.4% H2S, COS

Shifted Syngas 3.7% H2S, COS

Mixed Syngas 14.8% H2S, COS

Sweet Syngas 22.5% H2S, COS

Acid Gas 3.6% H2S, COS, 

SO2

Fugitive Emissions tons/yr tons/yr

Total Uncontrolled 9.45 0.09

Note: Compounds not listed for a stream are negligible for that 

stream

Note: The above streams are all included in the IG facility emissions estimates. Fugitive Equipment Leaks 

designated as emissions unit “FUG” reflect emissions of syngas streams as well as the methanol and 

propylene streams. The acid gas streams are included in Fugitive Equipment Leaks from the WSA 

designated as “FUG-WSA”.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(a) Leak Detection and Repair (LDAR)

(b) No control (for CO and H2SO4)

Step 4: Evaluate the Most Effective Controls and Document the Results

Given the low concentration of CO and H2SO4 in the process streams, the relatively low fugitive 

emissions rate of these pollutants, and the fact that use of an LDAR program for these pollutants 

would be unusual, the use of an LDAR program eliminated from BACT consideration. 

 

Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for CO and H2S04 from the Fugitive Leaks from 

Equipment (FUG and FUG-WSA).

(1) The BACT for fugitive leaks of CO and H2SO4 is proposed as no-controls. 
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Permit Reviewer: Josiah Balogun

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for CO and H2S04 for the Fugitives Leaks from piping (FUG and FUG -

WSA).

(1) The BACT for fugitive leaks of CO and H2SO4 is no-controls. 

Particulate Matter (PM/PM10/PM2.5) BACT – Fugitive Dust From Paved Roads (FUG-ROAD)

Step 1: Identify Potential Control Technologies

Emissions of particulate matter (PM), particulate matter with an aerodynamic diameter less than 

or equal to ten (10) micrometers (PM10) and PM2.5 from fugitive sources are generally controlled 

with measures to prevent the emissions from occuring. Generally, fugitive PM, PM10 and PM2.5

emissions from roadways are controlled through one of the following mechanisms:

(1) Paving of Roadways

(2) Wet Suppression or Chemical suppression

(3) Good Housekeeping (cleanup spilled material)

Add-on particulate control devices such as cyclones, scrubbers, baghouses or ESP’s are not 

possible alternatives because the roadways cannot be enclosed and vented to a point source 

control device.

Step 2: Eliminate Technically Infeasible Options

Add-on Control Technology:

Add-on particulate control devices such as cyclones, scrubbers, baghouses or ESP’s are not 

possible alternatives because the roadways cannot be enclosed and vented to a point source 

control device.

Wet Suppression or Chemical suppression:

Wet suppression systems use liquid sprays or foam to suppress the formation of airborne dust. 

The primary control mechanisms are those that prevent emissions through agglomerate formation 

by combining small dust particles with larger aggregate or with liquid droplets. The key factors 

that affect the degree of agglomeration and, hence, the performance of the system are the 

coverage of the material by the liquid and the ability of the liquid to wet small particles. There are 

two types of wet suppression systems: liquid sprays which use water or water/surfactant mixtures 

as the wetting agent and systems which supply foams as the wetting agent. Wet suppression 

systems typically achieve PM control efficiencies of greater than 85%.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Wet Suppression or Chemical suppression is a technically feasible option for the 

Plant Haul Roads (FUG-ROAD) at this source.

Paving Roadways and Good Housekeeping

Paving all haul roads and prompt cleanup of any spilled or eroded materials are effective at 

minimizing dust emissions from vehicle traffic.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

1. Paving haul roads reduces vehicle dust emissions versus unpaved surfaces and is 

feasible.
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Permit Reviewer: Josiah Balogun

2. Wet or chemical suppression (frequent use of water or chemical surfactants) can 

significantly reduce airborne dust emissions from both paved and unpaved roadways. 

3. Particulate emission from paved roadways can also be minimized with good

housekeeping, i.e. cleaning up spills of solid material or dirt eroded onto the road 

surfaces.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for related operations. All data in the table is 

based on the information obtained from the permit application submitted by Indiana Gasification, 

LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits 

available at the websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control Method

Draft Permit 

No. 147-

30464-

00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Haul Road fugitive 

dust from vehicle 

traffic

10,400 T 

dry 

coal/day 

90% control Wet or Chemical 

Suppression

LA-0240 FLOPAM, Inc 06/14/2010 Roadway Fugitives Not 

Specified

0.04 lb/hr BACT for road dust 

is to pave 

roadways where 

practicable. 

Unpaved roads 

shall utilize water 

spray or dust 

suppression 

chemicals and 

speed limits of 15 

mph on unpaved 

road.

KY-0100 East Kentucky 

Power Coop. 

04/09/2010 Haul Roads Not 

Specified

Not 

Specified

Paved Roadways 

Cleaning or promt 

removal of material, 

and the application of 

wet suppression as 

applicable

OH-0332 Sun Coke 

Energy

2/9/2010 Roadways and 

Parking areas

Not 

Specified

PM 1.08TPY Control measures 

(Watering etc) when 

necessary.

OH-0317 Ohio River 

Clean Fuels

11/20/2008 Raodways and 

parking areas

736 

KVMT/yr

15.39 tpy 

PM10

Reduce Speed Limit, 

Sweeping, Watering 

and good 

Housekeeping 

measures.

The table above shows recent entries in the RACT/BACT/LAER Clearinghouse (RBLC) database for Haul 

Roads. The proposed control level of 90% is the highest specified in the RBLC for such sources. Some 

BACT determinations specify reduced speed as part of their control strategy. Given the short in-plant 

distances, nature of the roadways, and the large vehicle sizes, the source haul vehicles will naturally 

travel at low speeds in the IG plant. 
Indiana Gasification LLC Page 146 of 181

Rockport, Indiana PSD /TV Permit No: 147-30464-00060

Permit Reviewer: Josiah Balogun

Proposal: Indiana Gasification, LLC 

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Plant Haul Road 

at the Indiana Gasification Plant.

BACT for PM, PM10 and PM2.5 for the Fugitive Dust from Plant Haul Roads (FUG-ROAD)

is proposed to be: 

1. Paving all plant haul roads,

2. Use of wet or chemical suppression for control by 90%,

3. Prompt cleanup of any spilled materials.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for the Fugitive Dust from Plant Haul Roads 

(FUG-ROAD).

The PM, PM10 and PM2.5 emissions from the paved road (FUG-ROAD) shall be controlled by 

90 % by the use of:

1. Paving all plant haul roads,

2. Use of wet or chemical suppression

3. Prompt cleanup of any spilled materials.

Particulate Matter (PM/PM10/PM2.5) BACT – Front-End Loader Slag Handling (EU-034A) and Vehicle 

Dust on Slag Pile (EU-034C)

Step 1: Identify Potential Control Technologies

Emissions of particulate matter (PM) and particulate matter with an aerodynamic diameter less 

than or equal to ten (10) micrometers (PM10) and PM2.5 are generally controlled with controls

designed to prevent or capture the emissions prior to the time they are exhausted to the 

atmosphere. In cases where the material being emitted is organic, particulate matter may be 

controlled through a combustion process. Generally, PM and PM10 emissions are controlled 

through one of the following mechanisms:

(1) Wet Suppression or Chemical suppression;

(2) Filtration;

(a) Baghouse;

(b) Wet Extraction System;

(3) Other Add-on Controls (cyclone, ESP).

Step 2: Eliminate Technically Infeasible Options

The slag pile operations cannot reasonably be enclosed and vented to a control device due to the

potential size of the pile and its location outside. This eliminates the applicability of collection and 

filtration equipment or other add-on controls.

The only remaining controls for this material handling that is technically feasible for these sources 

is wet or chemical suppression. Frequent use of water or chemical surfactants can significantly 
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reduce airborne dust from these types of open material handling operations. This is the most 

commonly utilized control for these types of sources.

Wet Suppression or Chemical suppression:

Wet suppression systems use liquid sprays or foam to suppress the formation of airborne dust. 

The primary control mechanisms are those that prevent emissions through agglomerate formation 

by combining small dust particles with larger aggregate or with liquid droplets. The key factors 

that affect the degree of agglomeration and, hence, the performance of the system are the 

coverage of the material by the liquid and the ability of the liquid to wet small particles. There are 

two types of wet suppression systems: liquid sprays which use water or water/surfactant mixtures 

as the wetting agent and systems which supply foams as the wetting agent. Wet suppression 

systems typically achieve PM control efficiencies of greater than 85%.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a Wet Suppression or Chemical suppression is a technically feasible option for the 

Front-end Loader Slag Handling (EU-034A) and Vehicle Dust on Slag Pile (EU-034C) at this 

source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Wet Suppression or Chemical suppression (up to 90% PM, PM10 and PM2.5

Reduction)

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM10 and PM2.5 BACT determination along with the 

existing PM, PM10 and PM2.5 BACT determinations for relevant operations. All data in the table is 

based on the information obtained from the permit application submitted by Indiana Gasification, 

LLC, the U.S. EPA RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits 

available at the websites of other permitting agencies.

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

Draft Permit 

No. 147-

30464-

00060

Proposed

Limit

Indiana 

Gasification -

proposed

Proposed Slag Pile 

Operations

10,400 T 

dry 

coal/day 

90% control Wet or 

Chemical 

Suppression

IA-0089-

Iowa

Homeland 

Energy 

Solutions 

08/08/2007 Coal Receiving and 

handling

200 tons/hr None specified for 

unenclosed 

unloading area

water fogging 

to eliminate 

particulate in 

unloading area

IA-0086-

Iowa

Homeland 

Energy 

Solutions 

05/03/2007 Coal Pile 50,565 

tons/hr

PM/PM10: Must 

use dust 

suppressant to 

reduce fugitive 

emissions by 95%

Chemical dust 

Suppressant 

with 95% 

control

CO-0057 -

Colorado

Public Service 

Company of 

Colorado 

Comanche 

Station

07/05/2005 Coal handling and

storage (includes 

open storage piles 

with lowering well, 

rail-car unloading, 

transfer from 

unloading to pile and 

NA None specified for 

unenclosed 

unloading area

Control include 

water spray, 

lower well, 

dust 

suppressant, 

enclosures 

where 
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Permit Reviewer: Josiah Balogun

BACT ID or 

Permit #

Facility Issued Date Process Description Rating 

(TPH)

Limitation Control 

Method

transfer from pile to 

bunker)

baghouse are 

not feasible

KY-0100 East Kentucky 

Power Coop. 

04/09/2010 Coal Pile, Rail 

Unloading Egress to 

Conveyor

3000 tons 

per hr

10% opacity (3min) Wet 

Suppression, 

Dust 

suppressant 

Lowering well 

and 

compaction

OH-0317 Ohio River 

Clean Fuels

11/20/2008 Coal Storage Piles 5500 

tons/hr

PM10:12.3 tons per 

year. with 75% 

control.

3-sided 

windscreen 

barrier. 

Reduced drop 

heights. Use of 

chemical 

stabilization 

dust 

suppressants 

and/or 

watering to 

reduce any 

visible 

emissions.

NOTE: * These emission units have not been built yet.

Note: ** Compliance with the limit at this facility has not been demonstrated through stack testing.

The table above shows recent entries in the RACT/BACT/LAER Clearinghouse (RBLC) database for 

material handling activities that can’t be enclosed. All these permits specify wet or chemical suppression, 

consistent with the source's proposal. Although most of the database entries do not specify the level of 

control, two of the listed entries specify 75% and 95%. Dependent on the amount and frequency of the 

application of wet suppression, various levels of control can theoretically be achieved by wet suppression. 

Control of greater than 90% is not normally considered practicable. 

(a) Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for PM, PM10 and PM2.5 from the proposed Front-end 

Loader Slag Handling (EU-034A) and Vehicle Dust on Slag Pile (EU-034C):

(1) A Wet Suppression or Chemical suppression providing 90% control efficiency.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for PM, PM10 and PM2.5 for the Front-end Loader Slag Handling (EU034A) and Vehicle Dust on Slag Pile (EU-034C).

The PM, PM10 and PM2.5 emissions from the Front-end Loader Slag Handling (EU-034A) and 

Vehicle Dust on Slag Pile (EU-034C) shall be controlled by a Wet Suppression or Chemical 

suppression with 90% control efficiency.

Greenhouse Gases (GHG) BACT – RTOs (EU-007A/B)

Step 1: Identify Potential Control Technologies

The acid gas removal (AGR) units remove CO2 from the syngas and produce a stream which is 

98% pure CO2. This stream will be compressed to a liquid and sold. Whenever it is instead 
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vented, it will be sent to one of two Regenerative Thermal Oxidizers (RTOs), one serving each 

AGR. The RTOs will oxidize small amounts of CO, COS, methane and VOCs (methanol) in the 

vent gas. 

The heating value of the CO2 stream to be vented is very low because it contains mostly noncombustible CO2. As a result, supplemental fuel is required to maintain the RTO at its operating 

temperature, when it is in standby and during its operation, to sustain the necessary temperature 

for oxidation to occur. As such, it is both a control device and a source of emissions.

The RTOs will be fired with SNG or natural gas. The amount of fuel that is needed is minimized 

by the units’ design. RTOs provide heat recovery and reduce the fuel needed to control 

emissions of trace components in this stream. A conventional thermal oxidizer would also be 

technically feasible for this stream. It is estimated that a conventional thermal oxidizer would 

require more than ten times the supplemental fuel required for an RTO. Therefore, RTOs are 

technically feasible, they will reduce supplemental fuel use and, thereby, reduce the associated 

emissions of CO2. The use of the RTOs will increase the CO2 emissions of this vent slightly 

(about 1% versus direct venting). This is due primarily to the conversion of trace quantities of 

CO, COS, methane, and methanol in this stream to CO2 during the combustion process. 

Although the RTO slightly increases CO2 emissions, its use is appropriate to reduce the 

emissions of other compounds as is further discussed in the BACT analysis for CO for the AGR 

vent. 

This analysis focuses on the emissions of CO2 only. While other GHGs, such as methane and 

N2O, are present in trace quantities, there are no known add on control technologies for these 

pollutants coming from combustion sources such as the RTOs. To the extent measures are 

identified that reduce fuel use and thereby CO2, the other GHGs will be reduced accordingly. 

Therefore, CO2 serves as a useful surrogate for other GHGs in this regard. 

The source is proposing to use a regenerative thermal oxidizer (RTO) that is fired with SNG and 

natural gas. An RTO is the most energy efficient technology that could be used in this service. 

No higher level of control for CO2 emissions has been identified.

(1) No Control

Step 2: Eliminate Technically Infeasible Options

No technically feasible measures have been identified to control CO2 emissions associated with 

the operation of the RTOs.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

There are no viable control technologies for the control of CO2 emissions from the RTO.

Step 4: Evaluate the Most Effective Controls and Document the Results

No technically feasible measures have been identified to control CO2 emissions associated with 

the operation of the RTOs. 
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Step 5: Select BACT

No technically feasible measures have been identified to control GHG emissions associated with 

the operation of the RTOs. 

Greenhouse Gases (GHG) BACT – Acid Gas Recovery (AGR) Unit Vent (EU-007A/B)

Step 1: Identify Potential Control Technologies

This analysis focuses on the emissions of CO2 only. While other GHGs are present in trace 

quantities, there are no known add on control technologies for these pollutants coming from this 

kind of source. To the extent measures are identified that reduce CO2 emissions, the other 

GHGs will be reduced accordingly. Therefore, CO2 serves as a useful surrogate for other GHGs 

in this regard. One option was identified for this source:

1. Sequestration of the AGR Vent CO2.

Step 2: Eliminate Technically Infeasible Options

Sequestration of the AGR Vent CO2

In any situation when the sale of liquefied CO2 via the pipeline will not occur, geological 

sequestration in lieu of venting has been considered. 

In EPA’s recent guidance on GHG BACT EPA has taken the position that capture and 

sequestration of CO2 as an add-on pollution control technology is ‘available’ for “large CO2-

emitting facilities including fossil fuel-fired power plants and industrial facilities with high-purity 

CO2 streams . . . .” In particular, EPA cites the report of the Interagency Task Force on Carbon 

Capture and Storage for the proposition that “current technologies could be used to capture CO2

from new and existing fossil energy power plants . . .” 

IDEM does not necessarily agree that sequestration must be considered to be ‘available.’ 

However, because this BACT analysis concludes that sequestration is technically infeasible, the 

BACT determination is not affected by that designation and, therefore, the remainder of this 

analysis will presume sequestration to meet the criteria as an ‘available’ technology.

In Step 2 of the top-down BACT process, a permit applicant is instructed to analyze all “available” 

and “applicable” control technologies. Control technologies that are “available” but not 

“applicable” are not technically feasible for the project and need not further be analyzed. EPA 

defines an “applicable” control technology as follows:

EPA considers an available technology to be “applicable” if it can reasonably 

be installed and operated on the source type under consideration. Where a 

control technology has been applied on one type of source, this is largely a 

question of the transferability of the technology to another source type. A 

control technique should remain under consideration if it has been applied to 

a pollutant-bearing gas stream with similar chemical and physical 

characteristics. The control technology would not be applicable if it can be 

shown that there are significant differences that preclude the successful 
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operation of the control device. For example, the temperature, pressure, 

pollutant concentration, or volume of the gas stream to be controlled, may 

differ so significantly from previous applications that it is uncertain the control

device will work in the situation currently undergoing review.

The volume of CO2 that may be emitted from the AGR vent, though a small percentage of the 

CO2 to be delivered as product to the product pipeline over the life of the facility, is a critically 

important aspect of whether sequestration is “applicable” to the proposed plant. Accordingly, 

EPA states that:

CCS may be eliminated from a BACT analysis in Step 2 if it can be shown 

that there are significant differences pertinent to the successful operation for 

each of these three main components [capture and/or compression, 

transport, and storage] from what has already been applied to a differing 

source type . . . [or] if the three components working together are deemed 

technically infeasible for the proposed source taking into account the 

integration of the CCS components with the base facility and site-specific 

considerations . . . .

EPA identifies four elements to consider when assessing whether there exist “significant 

differences,” “integration,” and “site-specific characteristics” that might lead a permitting authority 

to a finding of inapplicability of sequestration: (1) whether the proposed project has access to or 

can develop a suitable sequestration site; (2) whether government funding will be required to 

implement transportation or sequestration solutions; (3) whether the timing of access to or 

construction of CO2 transportation infrastructure is consistent with the proposed project; and (4) 

whether contracts or rights of way for offsite land use for transportation and storage will be 

required. After considering these factors, “a permitting authority may conclude that CCS is not 

applicable to a particular source, and consequently not technically feasible, even if the type of 

equipment needed to accomplish the compression, capture, and storage of GHGs [is] determined 

to be generally available from commercial vendors.” IDEM has addressed each of these 

elements and concluded that sequestration is inapplicable to this project for the disposition of 

CO2 that will otherwise be vented.

Access to or development of a suitable sequestration site. The source has neither access to, 

nor can develop, a suitable sequestration site for the volume of CO2 that may be vented from the 

AGR vents. As indicated above, there is an ongoing potential to emit 1,290,000 tons/yr of CO2

from the AGR vents. This venting is not predictable even on a daily or weekly basis. Rather such 

venting will occur intermittently. 

While sequestration is being studied for use in the region where the plant will be located, there is 

presently no practical option. Department of Energy (DOE) funding is currently supporting a 

substantial research and demonstration initiative called the Regional Carbon Sequestration 

Partnership (RCSP) program. This program is just now beginning several large-scale CO2

injection research projects targeting injection of over 1 million tons of CO2 (a scale that is about 

the same as would be needed by the IG facility). In the Illinois Basin where IG’s project is 

located, the regional partnership is the Midwest Geologic Sequestration Consortium (MGSC). 

That group has a large-scale sequestration demonstration underway at the ADM plant in Decatur, 

Illinois (about 200 miles from Rockport). That project expects to inject 1 million tons of CO2
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beginning in 2011 to “further understanding of carbon sequestration technology around the 

world.” The results of this demonstration won’t be known for some time. 

FutureGen 2.0 is a DOE supported power plant project in Illinois that will incorporate carbon 

capture and develop geologic sequestration. Part of the plan for FutureGen 2.0 is the 

development of a regional sequestration site where CO2 from the FutureGen project, and 

potentially other projects, could be stored. FutureGen issued an RFP for proposed sites and 

identified four finalist locations in Illinois. The site is to be designed to accept at least 1.3 million 

metric tons of CO2 per year over 30 years (the amount expected to be captured by the 

FutureGen plant), but could be expanded at some point in the future to accept additional CO2

from other power plant or industrial facilities. 

On February 28, 2011, FutureGen 2.0 announced the tentative selection of a site in Morgan 

County, IL. However, selecting this site merely begins the process of further geologic 

characterization and it triggers the beginning of the environmental review required under the 

National Environmental Policy Act (NEPA) that will afford opportunities for public participation and 

comments. Given the unprecedented nature of the proposed sequestration, many technical and 

legal issues remain to be addressed including the public acceptability of the proposed site. 

These issues make the ultimate development of this site uncertain. It is also not clear whether or 

by how much it will be sized to accept CO2 beyond that produced by the FutureGen power plant, 

what criteria will be used to determine who can potentially use the site for CO2 storage, or when 

the site might actually be completed and begin CO2 storage operations. The FutureGen 2.0 

initiative does not represent an available sequestration site for the IG facility.

Another carbon injection demonstration closer to Rockport is in Hancock County, Kentucky 

across the Ohio River from Indiana Gasification’s site. That project, being conducted by the 

Kentucky Geologic Survey with funding from Kentucky and DOE, drilled an 8,216 foot well and 

injected 18,454 barrels of brine and 323 tons of CO2 in 2009. Limited information is available 

regarding the results of this research, but the small scale of the injection—a total CO2 injection 

that was less CO2 than the Indiana Gasification project will produce every hour—makes clear that 

significant additional research is needed to demonstrate the viability of large-scale sequestration 

in this region.

The necessity of government funding for CCS infrastructure. As summarized below, 

significant and sustained government research will be required for many years to develop a 

reliable and accessible sequestration infrastructure that will accommodate the volume of CO2

emitted from the AGR vent. The government research and development is needed to address 

the many critical challenges of applying many geologic sequestration options.

The DOE National Energy Technology Laboratory (NETL) issued a Carbon Dioxide Capture and 

Storage R&D Roadmap in December 2010. The NETL report outlines critical challenges to 

carbon storage technology (see following figure) and outlines a research initiative that runs 

through 2025 for developing needed technologies and understanding. This RD&D roadmap 

makes clear that geologic sequestration is an important research initiative of the federal 

government and that CCS has many risks without significant additional government research, 

development and demonstration of sequestration methods.
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Figure F-1 from DOE/NETL Carbon Dioxide Capture and Storage RD&D 

Roadmap

Timing of and access to available transportation infrastructure. IDEM is unaware of any 

CO2 transportation infrastructure—aside from the EOR pipeline contemplated for use by this 

project—that would have the capacity to transport the volume of CO2 emitted by the AGR vent to 

a sequestration site, in any timeframe relevant to the commencement of operation of the facility. 

Acquisition of land for transportation infrastructure. The logistical challenges of constructing 

a second pipeline as a “backup” to the EOR pipeline make this option infeasible. First, the fact 

that any pipeline infrastructure would only be used when liquefied CO2 is not sold for EOR, a 

circumstance the project will take steps to avoid, means any pipeline constructed will lay idle 

most of the time. Second, and more important, to make a second pipeline available, IG would 

need to establish a pipeline route, find right of way opportunities, and then construct whatever 

pipelines would be needed to transport CO2 for sequestration, all in light of the fact that there will 

not exist in the near future any suitable sites for the sequestration of CO2 from the facility. 

Moreover, IDEM cannot today identify where pipeline infrastructure should be built and, therefore, 

cannot even begin the process of trying to engineer or build it. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of sequestration of the AGR vent is not a technically feasible option for the Acid Gas 

Recovery Unit Vent at this source. 
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Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the technical feasibility analysis in Step 2, there are no viable control technologies for 

the control of GHG emissions from the Acid Gas Recovery Unit Vent.

Step 4: Evaluate the Most Effective Controls and Document the Results

In its review of the RACT/BACT/LAER Clearinghouse (RBLC) and similar permits, no facilities 

were identified where controls were required for an Acid Gas Recovery (AGR) Vents. 

The acid gas removal (AGR) units remove CO2 from the syngas and produce a stream which is 

98% pure CO2. This stream will be compressed to a liquid and sold. It will be transported to the 

Gulf Region where it will be used in Enhanced Oil Recovery (EOR) operations. 

IG expects to be the first project designed to supply CO2 to the Gulf Coast EOR market from a 

coal-based facility in the Midwest. There are, however, certain challenges to producing and 

selling CO2 product. In particular, a pipeline is needed to transport the CO2 from the plant site to 

the Gulf Region. No such pipeline currently exists. The present implementation plan for the 

project would finance the pipeline coincident with financing of the gasification project. IG will not 

begin construction of this facility without a fully financed project agreement for the pipeline that 

provides for the pipeline to be in place and ready to receive liquefied CO2 at the point when 

pipeline quality CO2 is available. It is in IG’s interest to have the pipeline available for shipments 

as early as possible, as IG will receive significant income from the sale of CO2. Nevertheless, IG 

cannot be 100% certain that the pipeline will be operating and ready to receive CO2 at the time 

the IG facility begins operation. 

A number of factors may lead to delays in the construction and operation of the pipeline: 

1. Building this pipeline, which will run several hundred miles through several states, will 

require securing many rights-of-way and obtaining numerous federal, state, and local 

approvals. Delays in this approval process may also extend the pipeline schedule.

2. At present, the pipeline arrangement contemplates serving only the IG facility. However, 

other parties are considering the production and sale of CO2 to the same market. 

Therefore, as this project goes forward, it may become economically beneficial and 

appropriate under developing regulatory programs to change the plans for the pipeline to 

accommodate one or more other CO2 producers in the region. Doing this may result in a 

change in the capacity and route of the pipeline and may delay the current schedule.

While the greatest risk of delay relates to the pipeline being ready, securing and meeting the 

requirements of customers for the CO2 may also cause a delay in shipping CO2, even if the 

pipeline is ready to receive CO2.

1. A customer committed to purchasing IG’s CO2 may need to build and commission new 

CO2 infrastructure which may create delays in the sale of CO2 for the customer.

2. There may be delays as shipping schedules for the various customers are sorted out. 

On those occasions when CO2 is not sold as product, the CO2 is vented from the AGRs. The 

CO2 stream will first be directed to a regenerative thermal oxidizer (RTO) to oxidize small 

amounts of methane, VOCs (methanol), H2S, CO and COS that are present in it. Because the 

RTOs will combust SNG or natural gas to support oxidation of these trace components, the RTOs 
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are both control devices and emissions sources. As a result, a separate GHG BACT review of 

the fuel used in the RTO has been completed. 

In light of the difficulties of plant start up and the potential for a delay in the start of shipments of 

CO2 through the pipeline from this facility to the CO2 customers, IG is anticipating that CO2

emissions at the facility may be higher in the first two years than for the remaining project life. 

Over the life of the project most of the CO2 will be sold and shipped to the Gulf Region for EOR 

use. 

With the nature of facility start up and the risk of a pipeline delay, the source is proposing different 

limits on the CO2 emissions from the AGR/RTO vents for each of the first two years of operation, 

and a different, lower limit that will be applicable thereafter. 

Proposal: Indiana Gasification, LLC

The following has been proposed as BACT for GHG from the proposed Acid Gas Recovery 

(AGR/RTO) Vents: 

1. The proposed limit for the first year of operation is 4.69 million tons. This figure reflects 

the impact of startup on operating rates and resulting CO2. 

2. The second year, IG proposes a limit of 6.43 million tons, which is reflective of the 

permitted capacity of the plant. 

3. The proposed limit thereafter is 1.29 million tons per year, starting with the third year of 

operation. After the third full year, it would apply on a 12-month rolling basis, with 

compliance determined at the end of each month, based on the total of the prior 12 

months. 

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 Acid Gas Recovery (AGR/RTO) Vents.

(1) The CO2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed

4,690,000 tons of CO2 during the first 12 months of operation.

(2) The CO2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed

6,430,000 tons of CO2 during the second 12 months of operation.

(3) The CO2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed 

1, 290,000 tons of CO2 during the third 12 months of operation.

(4) Thereafter, the CO2 emissions from the Acid Gas Recovery (AGR) Vents shall not 

exceed 1,290,000 tons CO2 per twelve (12) consecutive month period with compliance 

determined at the end of each month.
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Greenhouse Gases (GHG) BACT – Wet Sulfuric Acid Plants (EU - 015A/B)

Step 1: Identify Potential Control Technologies

This analysis focuses on the emissions of CO2 only. While other GHGs, such as methane and 

N2O, may be present in trace quantities due to upstream combustion processes, there are no 

known add on control technologies for these pollutants coming from WSAs. To the extent 

measures are identified that reduce CO2, the other GHGs may be also reduced accordingly. 

Therefore, CO2 serves as a useful surrogate for other GHGs in this regard when a measure 

reduces the overall discharge from this source. Three options were identified for this source:

(1) No Control; 

(2) Recycling the WSA stack gas back to the AGR (which would require pure oxygen use in 

the WSA combustor instead of air); and

(3) Carbon (CO2) Capture in WSA Tailgas.

Step 2: Eliminate Technically Infeasible Options

No Control 

Most of the CO2 in the WSA exhaust comes from the Acid Gas Recovery (AGR) units as a 

constituent in the acid gas stream. The AGR generated acid gas is the feed to the WSA unit. 

Through its inherent design, the AGR unit will remove at least 90% of the CO2 in the syngas for 

liquefaction and sale. 

This percent capture results from the relative solubilities of CO2, COS and H2S in the Rectisol 

solution and by the need for the AGR unit to be designed and optimized to balance its three 

critical AGR operating requirements: 1) assuring SNG product quality; 2) assuring liquid CO2

product quality; and 3) assuring acceptable acid gas quality to the WSA. 

The high CO2 capture in the AGR incidentally results in relatively modest levels of CO2 in the 

acid gas stream to the WSA. WSA emissions of CO2 are estimated to not exceed 474,000 tons 

per year at maximum design rates. This is approximately 7% of the syngas CO2 at maximum 

design. Below is a further brief discussion of how the AGR captures CO2, H2S and COS. 

Cold methanol is used to physically absorb CO2, H2S and COS at high pressures. Absorption in 

the methanol solvent for each compound is affected by its concentration, the methanol solvent 

temperature and pressure, and the compounds relative solubility in methanol. The CO2, H2S and 

COS are significantly more soluble than other syngas components (CO, H2, CH4, and N2). This 

solubility difference allows CO2, H2S and COS to be removed from the syngas in the AGR 

systems. However, their similar solubility makes it difficult to separate the H2S, COS, and CO2 

from each other.

H2S, COS, and CO2 are removed from the loaded methanol solvent when it is depressurized 

because they are less soluble at lower pressures and higher temperatures. Among these 

compounds, H2S and COS are more soluble than CO2. To achieve effective separation, the 

loaded methanol solvent is depressurized in multiple stages – at progressively lower pressures. 
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After an initial pressure reduction to flash off any absorbed syngas product, CO2 is next flashed 

out of the solvent (in three stages) generating what becomes the facility’s liquefied product CO2

stream (98% pure). In a final step, the methanol solvent, having been stripped of more than 90% 

of its CO2, is then heated in a hot regenerator, to strip out the H2S and COS. The sulfur-rich acid 

gas stream from the regenerator, which is then sent to the WSA, will also contain some remaining 

CO2. It is very difficult to further reduce the CO2 content of the acid gas stream because of the 

relatively close solubility of the acid gases and CO2.

Because of this inherently efficient AGR system, baseline emission from the WSA will be 

modestly low, even without additional controls.

Recycling WSA Tailgas

Recycling WSA tailgas back to the AGR to recover the CO2 using the existing/expanded AGR 

unit was identified as a theoretical option to reduce GHG emissions. If this were possible, it could 

reduce or eliminate WSA CO2 emissions. However, this option is not commercially demonstrated 

and is not considered technically feasible as discussed below. 

The major technical hurdle to recycling WSA tail gas back to the inlet of the acid gas unit (AGR) is 

the fact that it contains a high nitrogen content (approximately 79% by volume) This nitrogen 

comes from the use of air for the combustion of H2S and COS necessary for the production of 

sulfuric acid. If this tail gas stream were recycled to the AGR, this nitrogen would 

contaminate/dilute the product SNG. The resulting SNG would contain greater than 40% 

nitrogen, which would not meet product quality specifications for its sale and use. The only 

potential remedy would be to use pure oxygen in place of air in the WSA. While theoretically 

possible, IDEM knows of no instance where ‘oxyfiring’ of a WSA has never been done, and it 

would involve a number of significant technical challenges. Given that it has not been done in 

WSA service, and is not commercially offered, the use of pure oxygen and recycle of the WSA is 

considered technically infeasible. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of pure oxygen and recycle is not a technically feasible option for the Wet Sulfuric Acid 

Plants at this source. 

Carbon (CO2) Capture in WSA Tailgas 

Another theoretical option is capturing the CO2 in the WSA exhaust in a separate solvent 

scrubbing system (not the AGR Rectisol system). Such a control would, theoretically, be similar 

to post-combustion carbon capture systems as are beginning to be contemplated for 

consideration for large fossil-fuel fired power plants. Although the WSA tail gas is not the product 

of conventional fuel combustion, from a CO2 capture perspective it has similar technical and 

economic issues to those of post-combustion carbon capture for a medium sized industrial boiler. 

The following highlights the similarities between the WSA tailgas and a typical boiler exhaust. 

(1) Low CO2 concentration – The WSA tail gas exhaust will contain about 6.6% CO2

concentration. This is on the lower end of the range of the typical exhaust concentrations 

for natural gas boilers which range from 6-9% CO2. 

(2) Low Pressure – The WSA tail gas is at atmospheric pressure as are boiler exhaust 

stacks. 
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(3) Low quantity of CO2 – The annual CO2 emissions from each WSA unit are orders of 

magnitude smaller than are emitted from large fossil-fuel fired power plants and 

concentrated industrial CO2 sources for which carbon capture is being considered. For 

example, each WSA has the CO2 equivalent emissions of a boiler of only about 360 

MMBTU/hr. 

The post-combustion carbon capture of CO2 from the Auxiliary Boilers is discussed elsewhere in 

this document and determined to not be an applicable and available control option because of the 

low CO2 concentration, low exhaust pressure and limited CO2 available for capture (i.e.: small 

size of the Aux boilers). For these same reasons, carbon capture of the CO2 in the exhaust of 

the WSA units is not an applicable and available technology. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of carbon capture of CO2 is not a technically feasible option for the Wet Sulfuric Acid 

Plants at this source. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

there is no viable technology for controlling the GHG emissions resulting from the Wet Sulfuric 

Acid; however, emissions will be inherently low due to the highly efficient design of the proposed 

facility

Step 4: Evaluate the Most Effective Controls and Document the Results

In its review of the RACT/BACT/LAER Clearinghouse (RBLC) and similar permits, no facilities 

were identified where controls for CO2 were required on the Wet Sulfuric Acid Plant. 

Proposal: Indiana Gasification, LLC

The following limit has been proposed for CO2 from the proposed Wet Sulfuric Acid: 

The WSA CO2 emissions shall be limited to 474,000 tons per year, as a rolling 12-month total. 

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 Wet Sulfuric Acid Plant.

The CO2 emissions from the Wet Sulfuric Acid Plant operation shall not exceed 474,000 tons per 

year as a rolling 12-month total.

Greenhouse Gases (GHG) BACT – Auxiliary Boilers (EU-005A/B)

Step 1: Identify Potential Control Technologies

(1) Use of low-carbon gaseous fuel (NG or SNG);

(2) Energy efficient boiler design (features considered: inlet air controls, economizer, 

condensate recovery, and blowdown heat recovery); and 

(3) Post-combustion CO2 capture.
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This analysis focuses on the emissions of CO2 only. While other GHGs, such as methane and 

N2O, are present in trace quantities, there are no known add on control technologies for these

pollutants coming from combustion sources. To the extent measures are identified that reduce 

fuel use and thereby CO2, the other GHGs will be reduced accordingly. Therefore, CO2 serves 

as a useful surrogate for other GHGs in this regard. 

Step 2: Eliminate Technically Infeasible Options

Low Carbon Fuel

Carbon dioxide (CO2) is a product of combustion generated with any carbon-containing fuel. 

The preferential use of natural gas (or substitute natural gas), a low-carbon fuel, is a method of 

lowering CO2 emissions versus use of solid or other fuels available at the IG site. The table below 

illustrates the CO2 emission factors for combustion of a variety of fuels.

Typical CO2 Emission Factors

Fuel Pounds CO2 per Million Btu

Petroleum Coke* 225

Coal** 210

Distillate Oil** 161

Natural Gas (or SNG)* 117

* Source GHG MRR Rule, Subpart C, Table C-1

**Source: US Energy Information Administration, 

http://www.eia.doe.gov/oiaf/1605/coefficients.html

The IG Project auxiliary boilers will fire natural gas/SNG as a low-carbon fuel, despite the fact that 

coal is available on the site. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of low carbon fuel is a technically feasible option for the Auxiliary Boilers at this source. 

Boiler Energy Efficiency

Another opportunity for reducing GHG emissions is to increase the energy efficiency of the 

boilers. Because CO2 emissions are a direct result of the amount of fuel fired (for a given fuel), 

the more efficient the process, the less fuel that is required and the less greenhouse gas 

emissions that result. (Note: Auxiliary boiler firing is also reduced through the high degree of heatintegration of the overall process which reduces supplementary steam requirements.)

Specific energy efficiency measures that may be applied to boilers include the following:

Inlet air controls (such as O2 monitor and inlet air flow control) limit excess air. Limiting the 

excess air enhances efficiency and reduces emissions through reduction of the volume of air that 

needs to be heated in the combustion process. An oxygen monitor and control of inlet air will be 

included in the IG auxiliary boilers design. This measure helps assure ongoing optimization of the 

boiler tuning. This, along with a NOx emissions limits and continuous emissions monitor required 

by NSPS Db, will help keep the boilers tuned for efficient operation (making periodic boiler tuning 

unnecessary).
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Heat Recovery of heat in the stack gas can be accomplished with either an economizer or an air 

preheater. An economizer recovers this heat by preheating boiler feed water. This reduces the 

heat energy required from fuel combustion to generate steam. An air preheater uses this heat to 

preheat the combustion air, thereby decreasing fuel firing requirements. The source will use an 

economizer, but will not use an air preheater because there is insufficient heat available in the 

stack gas to do both types of heat recovery. 

Condensate Recovery returns the hot steam condensate from the process as feedwater, 

thereby decreasing the boiler heat load. All of the IG process steam condensate and condensed 

steam from the steam turbine generator are combined and preheated to 250oF in the low 

temperature gas cooling section of the plant after CO Shift conversion. This is the source of 

feedwater for the boilers.

Recover Heat from the Blowdown is accomplished by sending blowdown water from the boiler 

steam drum to a low pressure flash drum. The pressure drop in the flash drum produces low 

pressure steam which is captured and used in the process by low pressure steam users. Further 

recovery of the small amount of residual heat in the condensate is not practical.

The combination of these measures is expected to result in a thermal efficiency, when at full 

design rate, of at least 81% (HHV basis).

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of energy efficiency is a technically feasible option for the Auxiliary Boilers at this source. 

Post-combustion CO2 Capture

Post-combustion CO2 capture is a relatively new concept. In EPA’s recent GHG BACT guidance, 

EPA takes the position that, “for the purpose of a BACT analysis for GHGs, EPA classifies CCS 

as an add-on pollution control technology that is “available” for large CO2-emitting facilities 

including fossil fuel-fired power plants and industrial facilities with high-purity CO2 streams”.

However, the IG auxiliary boilers do not fit into either of these categories. The EPA guidance 

document provides little specific guidance on whether or how to consider CCS in situations 

outside of the above quoted examples. However, some guidance specific to medium-sized 

natural gas boilers appears in its guidance document which presents an example GHG BACT 

analysis for a 250 MMBtu/hr natural gas fired boiler. In this EPA boiler example, carbon capture 

isn’t listed or considered in the BACT analysis as a potentially available option. The IG Project 

auxiliary boilers, with combined average annual utilization of 172 MMBTU/hr, are smaller than this 

EPA example. 

Based on EPA’s guidance, a CO2 capture system for small to medium size combustion systems, 

such as the IG auxiliary boilers, is not a reasonable BACT option. This is understandable 

because the capture of the CO2 from the IG auxiliary boiler exhaust 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 predominant factors: the auxiliary boiler exhaust’s low CO2

concentration, low pressure, low quantity of CO2 available for capture, and the high variability of 

load for these two boilers. 
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CO2 Capture Difficulty

Natural gas combustion boiler exhaust streams have relatively low CO2 concentrations (6-9% 

versus 12-15% for coal-boilers and >30% for high concentration industrial gas streams). This 

means that for a natural gas boiler a very large volume of gas needs to be treated to recover the 

CO2. Additionally, the low concentration and low pressure complicate the absorption and 

desorption of the CO2, which increases the energy required. Also, a low pressure absorption 

system creates a low pressure CO2 stream which requires a very high energy demand for 

compression prior to transport. All these factors make the application of CO2 capture on any 

natural gas combustion exhaust extremely difficult and expensive. Additionally, the cost of 

capturing CO2 for smaller sources is more expensive due to the lack of economy-of-scale. The 

average annual firing rate of the auxiliary boilers of 172 MMBTU/hr is less than 1/20th the size of a 

typical fossil fuel fired power plant boilers that EPA contemplates having to consider the potential 

for CCS. Additionally, rapid swings in the load of this auxiliary boiler would complicate use of 

post-combustion capture. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of post-combustion CO2 capture is not a technically feasible option for the Auxiliary 

Boilers at this source. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the technical feasibility analysis in Step 2, the remaining control technologies may be 

ranked as follows for controlling GHG emissions from the Auxiliary Boilers.

(1) Use of low-carbon gaseous fuel (natural gas or SNG); and 

(2) Energy efficient boiler design (utilizing an economizer, condensate recovery, inlet air 

controls and blowdown heat recovery.) 

Step 4: Evaluate the Most Effective Controls and Document the Results

In its review of the RACT/BACT/LAER Clearinghouse (RBLC) and similar permits, no facilities 

were identified where CO2 controls were required on Auxiliary Boilers. 

Proposal: Indiana Gasification, LLC

The following has been proposed as BACT for GHG from the proposed Auxiliary Boilers: 

(1) Use of low-carbon gaseous fuel (natural gas or SNG); and 

(2) Energy efficient boiler design (utilizing an economizer, condensate recovery, inlet air 

controls and blowdown heat recovery.) 

(3) Boiler designed for 81% thermal efficiency (HHV).

(4) An annual limit on the CO2 emissions of the boilers, combined, of 88,167 tons per year.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for the GHGs for the Auxiliary Boilers.

(1) Use of natural gas or SNG; 
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(2) Energy efficient boiler design (utilizing an economizer, condensate recovery, inlet air 

controls and blowdown heat recovery.) 

(3) Boiler designed for 81% thermal efficiency (HHV);

(4) The total CO2 emissions from the auxiliary boilers shall not exceed 88,167 tons per 

twelve (12) consecutive month period, with compliance determined at the end of each 

month.

Greenhouse Gases (GHG) BACT – Syngas Hydrocarbon Flare (EU-001) 

Step 1: Identify Potential Control Technologies

In evaluating BACT for flare Greenhouse Gases (GHG) emissions, there are limited process 

and/or add-on control alternatives available. Based on a review of the RBLC, as well as other 

permits and sources, the list of potential control and process alternatives includes the following:

(1) Flare design and proper operation;

(2) Process flaring minimization practices (Flare Minimization Plan); and

(3) Flare gas recovery.

This analysis focuses on the emissions of CO2 only. While other GHGs, such as methane and 

N2O, are present in trace quantities, there are no known add on control technologies for these 

pollutants coming from combustion sources. To the extent measures are identified that reduce 

fuel and flare combustion and thereby CO2, the other GHGs will be reduced accordingly. 

Therefore, CO2 serves as a useful surrogate for other GHGs in this regard.

Step 2: Eliminate Technically Infeasible Options

Flare design and proper operation

Flare design and operating are key elements in emissions performance of flares. However, 

Greenhouse Gases (GHG) emissions are not greatly affected by flare design. Instead, flare 

Greenhouse Gases (GHG) are primarily a function of the amount of material flared. The openflame nature of a flare results in inherently good Greenhouse Gases (GHG) performance (the 

oxidation of any methane) and prohibits the use of design features. 

The source is proposing the use of elevated flares. These are the most commonly used type of 

flares for emergency release control. Elevated flares are capable of extremely effective control of 

vented gases. A potential alternative flare design is an enclosed or ground flare. However,

enclosed flares are not typically considered for high flow rate situations Nevertheless, regardless 

of the type of flare used, there are no flare design or operational features were identified as 

applicable for Greenhouse Gases (GHG) control.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Flare design and proper operation is not a technically feasible way to control GHGs 

from the Syngas Hydrocarbon flare at this source. 

Process flaring minimization practices (including operating procedures in the Flare 

Minimization Plan

To the extent actions can be taken to minimize the volume of gas going to the flare, emissions of 

Greenhouse Gases (GHG) will be less. Flaring minimization practices are feasible.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Process flaring minimization practices is a technically feasible option for the control of 

GHG emissions from the Syngas Hydrocarbon flare at this source. 
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Flare gas recovery

Flare gas recovery – Flare gas recovery has been implemented at some facilities that produce 

and use internally generated fuel gas streams such as petroleum refineries. However, flare gas 

recovery for the IG facility is not feasible for the following reasons. 

(1) First, unlike a refinery’s nearly continuous supply of flared gases, flaring at the proposed 

IG facility will be an infrequent occurrence. 

(2) Another significant difference is that refineries can recover flare gas into their fuel gas 

cleanup system which operates at less than 100 psig. In contrast, the IG facility’s 

analogous gas cleanup system, the AGR, operates at the much higher pressure of about 

900 psig. This would significantly increase the equipment and operating costs of a flare 

gas recovery compressor versus those at refineries. 

 

(3) Another difference is that during some of the IG flaring events, the flared material may 

not be suitable to allow it to be routed to the AGR system or the AGR system itself may 

be in the process of being started up, in an upset, or otherwise not ready to receive the 

flared gases. 

(4) Given the extremely infrequent nature of flared gases being available for recovery, and 

given the lack of a reasonably compatible outlet for recovered gases at the time of flaring 

events, flare gas recovery compression is judged to be not feasible for the IG facility.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Flare gas recovery is not a technically feasible option for the control of GHG emissions 

from the Syngas Hydrocarbon flare at this source. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The remaining technically feasible control technology for flares is:

(1) Process flaring minimization practices (Flare Minimization Plan)

Process flaring minimization practices (Flare Minimization Plan)

There are a number of steps that can be taken in the operation of the facility that will reduce the 

volume of gases flared and thereby the emissions of particulates. During a planned shutdown of 

a gasifier, the contents of the gasifier (gasifier vessel, quench chamber, scrubber vessel) can be 

routed, during initial depressurization, to one of the Wet Sulfuric Acid (WSA) plants. Also, the 

feed rate to the gasifiers can be reduced such that all syngas can be processed through one gas 

treatment train prior to a scheduled gas treatment train outage. This limits the amount of syngas 

that will have to be sent to the syngas hydrocarbon flare. Also, the permittee can investigate the 

“root cause” of malfunction events that cause gases to be sent to the flare and determine whether 

there are additional preventative measures that can be implemented to minimize re-occurrence of 

these events. 

Step 4: Evaluate the Most Effective Controls and Document the Results

Proposal: Indiana Gasification, LLC – Rockport, IN

Process flaring minimization practices (Flare Minimization Plan)

Features of the IG facility design that affect the ultimate use of the flares include the following:

A. The permittee shall comply with the following Flare Minimization Plan to reduce GHG 

emissions during startups, shutdowns, and other flaring events.
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During a planned shutdown of a gasifier, the permittee shall route the contents of each 

gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during initial 

depressurization to one of the Wet Sulfuric Acid (WSA) plants. 

The permittee shall reduce gasifier feed rates such that all syngas can be processed 

through one gas treatment train prior to a scheduled gas treatment train outage. This 

limits the amount of syngas that will have to be sent to the syngas hydrocarbon flare. 

In addition, the permittee shall have written procedures for the above operations and the 

permittee shall train the operators on these procedures.

The permittee shall investigate the “root cause” of malfunction events that cause gases to 

be sent to a flare and determine whether there are additional preventative measures that 

can be implemented to minimize re-occurrence of these events. Such identified 

measures shall be implemented and documented.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for Greenhouse Gases (GHG) for Syngas Hydrocarbon Flare (EU-001)

and Acid Gas Flare (EU-002).

A. The permittee shall comply with the following Flare Minimization Plan to reduce GHG 

emissions during startups, shutdowns, and other flaring events.

During a planned shutdown of a gasifier, the permittee shall route the contents of each 

gasifier unit (gasifier vessel, quench chamber, scrubber vessel) during initial 

depressurization to one of the Wet Sulfuric Acid (WSA) plants. 

The permittee shall reduce gasifier feed rates such that all syngas can be processed 

through one gas treatment train prior to a scheduled gas treatment train outage. This 

limits the amount of syngas that will have to be sent to the syngas hydrocarbon flare. 

In addition, the permittee shall have written procedures for the above operations and the 

permittee shall train the operators on these procedures.

The permittee shall investigate the “root cause” of malfunction events that cause gases to 

be sent to a flare and determine whether there are additional preventative measures that 

can be implemented to minimize re-occurrence of these events. Such identified 

measures shall be implemented and documented.

Greenhouse Gases (GHG) BACT –Acid Gas Flare (EU-002)

Step 1: Identify Potential Control Technologies

In evaluating BACT for flare Greenhouse Gases (GHG) emissions, there are limited process 

and/or add-on control alternatives available. Based on a review of the RBLC, as well as other 

permits and sources, the list of potential control and process alternatives includes the following:

(1) Flare design and proper operation;

(2) Process flaring minimization practices (Flare Minimization Plan); and

(3) Flare gas recovery.
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This analysis focuses on the emissions of CO2 only. While other GHGs, such as methane and 

N2O, are present in trace quantities, there are no known add on control technologies for these 

pollutants coming from combustion sources. To the extent measures are identified that reduce 

fuel and flare combustion and thereby CO2, the other GHGs will be reduced accordingly. 

Therefore, CO2 serves as a useful surrogate for other GHGs in this regard.

Step 2: Eliminate Technically Infeasible Options

Flare design and proper operation

Flare design and operating are key elements in emissions performance of flares. However, 

Greenhouse Gases (GHG) emissions are not greatly affected by flare design. Instead, flare 

Greenhouse Gases (GHG) are primarily a function of the amount of material flared. The openflame nature of a flare results in inherently good Greenhouse Gases (GHG) performance (the 

oxidation of any methane) and prohibits the use of design features. 

The source is proposing the use of elevated flares. These are the most commonly used type of 

flares for emergency release control. Elevated flares are capable of extremely effective control of 

vented gases. A potential alternative flare design is an enclosed or ground flare. However,

enclosed flares are not typically considered for high flow rate situations Nevertheless, regardless 

of the type of flare used, there are no flare design or operational features were identified as 

applicable for Greenhouse Gases (GHG) control.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Flare design and proper operation is not a technically feasible way to control GHGs 

from the Acid gas flare at this source. 

Process flaring minimization practices (including operating procedures in the Flare 

Minimization Plan

To the extent actions can be taken to minimize the volume of gas going to the flare, emissions of 

Greenhouse Gases (GHG) will be less. Flaring minimization practices are feasible.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Process flaring minimization practices is a technically feasible option for the control of 

GHG emissions from the Acid gas flare at this source. 

Flare gas recovery

Flare gas recovery – Flare gas recovery has been implemented at some facilities that produce 

and use internally generated fuel gas streams such as petroleum refineries. However, flare gas 

recovery for the IG facility is not feasible for the following reasons. 

(1) First, unlike a refinery’s nearly continuous supply of flared gases, flaring at the proposed 

IG facility will be an infrequent occurrence. 

(2) Another significant difference is that refineries can recover flare gas into their fuel gas 

cleanup system which operates at less than 100 psig. In contrast, the IG facility’s 

analogous gas cleanup system, the AGR, operates at the much higher pressure of about 

900 psig. This would significantly increase the equipment and operating costs of a flare 

gas recovery compressor versus those at refineries. 

 

(3) Another difference is that during some of the IG flaring events, the flared material may 

not be suitable to allow it to be routed to the AGR system or the AGR system itself may 

be in the process of being started up, in an upset, or otherwise not ready to receive the 

flared gases. 
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(4) Given the extremely infrequent nature of flared gases being available for recovery, and 

given the lack of a reasonably compatible outlet for recovered gases at the time of flaring 

events, flare gas recovery compression is judged to be not feasible for the IG facility.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of Flare gas recovery is not a technically feasible option for the control of GHG emissions 

from the Acid gas flare at this source. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The remaining technically feasible control technology for flares is:

(1) Process flaring minimization practices (Flare Minimization Plan)

Process flaring minimization practices (Flare Minimization Plan)

Because the Acid Gas Flare is expected to be used in upset, malfunction and emergency 

conditions only, measures that might apply to flaring during normal start up and shutdown do not 

apply. Instead, the Flare Minimization Plan to reduce emissions will logically address the conduct 

of a root cause analysis and the consideration of corrective actions whenever flaring occurs. 

Therefore, the measure would be for the permittee to investigate the “root cause” of malfunction 

events that cause gases to be sent to a flare and determine whether there are additional 

preventative measures that can be implemented to minimize re-occurrence of these events. 

Such identified measures would be implemented and documented.

Step 4: Evaluate the Most Effective Controls and Document the Results

Proposal: Indiana Gasification, LLC – Rockport, IN

Process flaring minimization practices (Flare Minimization Plan)

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

emissions during flaring events.

The permittee shall investigate the “root cause” of malfunction events that cause gases to 

be sent to a flare and determine whether there are additional preventative measures that 

can be implemented to minimize re-occurrence of these events. Such identified 

measures shall be implemented and documented.

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for Greenhouse Gases (GHG) for Syngas Hydrocarbon Flare (EU-001) 

and Acid Gas Flare (EU-002).

A. The permittee shall comply with the following Flare Minimization Plan to reduce 

emissions during flaring events.

The permittee shall investigate the “root cause” of malfunction events that cause gases to 

be sent to a flare and determine whether there are additional preventative measures that 

can be implemented to minimize re-occurrence of these events. Such identified 

measures shall be implemented and documented.
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Greenhouse Gases (GHG) BACT – Gasifier Preheater Burners (EU-008A-E)

Step 1: Identify Potential Control Technologies

The CO2 is by far the dominant GHG from this source. CH4 and N2O are present only in very 

small amounts, are incidental to combustion, and trend with the CO2 emissions. There are no 

known supplemental controls for N2O or methane emissions from gas-fired units. To the extent 

measures are identified that reduce CO2, the other GHGs may be also reduced accordingly. 

Therefore, this BACT analysis focused on CO2 as a surrogate for all GHG emissions. GHG 

control possibilities identified and addressed in this BACT analysis for these small burners are:

(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

These burners are proposed to use only natural gas or the comparable substitute natural gas. As 

a low-carbon fuel source, this will minimize greenhouse gas emissions.

Good Engineering Design

These burners fire natural gas or SNG. They are relatively simple devices that are placed in the 

gasifier to heat it up or keep it hot when in standby. When the gasifier is about to be placed in 

service the burner is removed from the gasifier. An efficient design of the burner will minimize 

GHG impacts in two ways. First, the methane in the fuel will be efficiently burned and very little 

methane will remain in the combustion gases that are vented to the atmosphere. Second, 

efficient design is needed to achieve high temperatures. A low temperature will mean more gas 

is needed to preheat the gasifier.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of good engineering design is a technically feasible option for the Gasifier preheater 

burners at this source. 

Carbon Capture

Post-combustion CO2 capture is a relatively new concept. In EPA’s recent GHG BACT guidance, 

EPA takes the position that, “for the purpose of a BACT analysis for GHGs, EPA classifies CCS 

as an add-on pollution control technology that is “available” for large CO2-emitting facilities 

including fossil fuel-fired power plants and industrial facilities with high-purity CO2 streams”. The 

small IG combustion sources such as the preheat burners do not fit into either of the above 

categories called out by EPA’s guidance document as appropriate for consideration of carbon 

capture and storage (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 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.
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The absence of a discussion of carbon capture in this 250 MMBtu/hr boiler example is consistent 

with the fact that carbon capture is extremely expensive, has numerous technical challenges, and 

is currently only being contemplated on very large or very concentrated CO2 sources. In stark 

contrast, the five IG Project gasifier preheat burners have a combined average annual utilization 

of less than 18 MMBtu/hr. As such they are an order of magnitude smaller than EPA’s boiler 

example, and significantly smaller still than the categories that US EPA’s guidance document 

suggests should consider CCS. 

A CO2 capture system for the IG gasifier preheat burners is not a reasonable BACT option 

because the capture of the CO2 from combustion exhaust of small sources is significantly more 

difficult than from the types of industrial gas streams that EPA references as having potential for 

CCS. The increased difficulty is due to four factors: low CO2 concentration, low pressure, low 

quantity of CO2 available for capture, and the variability of load for these units. 

The low concentration and low pressure of the exhausts from these processes complicate the 

absorption and desorption of the CO2, which increases the energy required. Also, a low pressure 

absorption system creates a low pressure CO2 stream which requires a very high energy demand 

for compression prior to transport. All these factors make the application of CO2 capture on any 

small combustion exhaust extremely difficult and expensive. Additionally, the cost of capturing 

CO2 for smaller sources is more expensive due to the lack of economy-of-scale. Further, the 

gasifier preheat burners are intermittent sources, which would further increase the cost and 

difficulty of implementing any control.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of post-combustion capture of CO2 is not a technically feasible option for the Gasifier 

preheater burners at this source. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The only feasible, applicable and available control technologies identified are 1) the use of good 

burner design and 2) use of only natural gas or SNG. Both are proposed so no ranking is 

required.

Step 4: Evaluate the Most Effective Controls and Document the Results

Proposal: Indiana Gasification, LLC

The following has been proposed as BACT for GHG from the proposed Gasifier preheater 

burners: 

(1) The use of good burner design; and 

(2) The use of only natural gas or SNG. 

The Gasifier Preheat Burners are used during the start-up of a gasifier unit. The preheat burners 

are portable 35 MMBtu/hr gas fired removable lance-type burners. One is utilized for each 

gasifier, for a total of five burners. The preheat burners combust natural gas (NG) or substitute 

natural gas (SNG) to generate heat to cure the refractory and to warm up a gasifier that has been 

down for maintenance. They are expected to operate only a small portion of the year. Once the 

startup preheat sequence is complete, these burners are removed from the gasifier. In addition, 
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one burner is estimated to operate throughout the year at 18 MMBtu/hr (for approximately 5840 

hr/yr) to maintain operability status of an extra gasifier when on stand-by. The reason the spare 

gasifier is preheated when in standby mode is to significantly shorten the time it would take to get 

the spare gasifier into normal operation producing syngas from coal/coke feedstock. Having to 

bring a spare gasifier into operation from a cold standby mode would add 24-48 hours to the time 

needed to achieve normal operation. 

Emission Unit GHG Emissions (tons/yr)

CO2 CH4 N2O CO2e

Gasifier Preheat Burners 

(total for 5, EU-008A-E) 6,438 0.12 0.01 6,444

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 Gasifier Preheater Burners.

1. The use of good engineering design; and 

2. The use of natural gas or SNG.

3. The total CO2 emissions from all five Gasifier Preheater Burners shall not exceed 6,438

tons CO2 per twelve (12) consecutive month period with compliance determined at the 

end of the month.

Greenhouse Gases (GHG) BACT – Emergency Generators and Firewater Pumps

Step 1: Identify Potential Control Technologies

The CO2 is by far the dominant GHG from this source. CH4 and N2O are present only in very 

small amounts, are incidental to combustion, and trend with the CO2 emissions. There are no 

known supplemental controls for N2O or methane emissions from diesel engines. To the extent 

measures are identified that reduce CO2, the other GHGs may be also reduced accordingly. 

Therefore, this BACT analysis focused on CO2 as a surrogate for all GHG emissions.

Diesel fuel is used instead of SNG or NG 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. For this 

reason, it is the most common fuel used for these type of emergency backup applications. 

GHG control possibilities identified and addressed in this BACT analysis for these small engines

are:

(1) Good engineering design 

(2) Post combustion carbon capture
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Step 2: Eliminate Technically Infeasible Options

Good Engineering Design and Efficient Operation

The source will install engines meeting the latest efficiency and pollutant performance standards 

specified in NSPS Part 60 Subpart IIII and NESHAP Part 63 Subpart ZZZZ. These Diesel engines 

are built with automatic control of the air to fuel ratio that ensures that they operate when needed

and meet the applicable standards. 

Carbon Capture

Post-combustion CO2 capture is a relatively new concept. In EPA’s recent GHG BACT guidance, 

EPA takes the position that, “for the purpose of a BACT analysis for GHGs, EPA classifies CCS 

as an add-on pollution control technology that is “available” for large CO2-emitting facilities 

including fossil fuel-fired power plants and industrial facilities with high-purity CO2 streams”. The 

small IG combustion sources such as the emergency engines do not fit into either of the above 

categories called out by EPA’s guidance document as appropriate for consideration of CCS. The 

EPA guidance document provides little specific guidance on whether or how to consider CCS in 

situations outside of the above examples. However, relevant guidance can be discerned from the 

Appendix F to the above referenced US EPA guidance document, which presents an example 

GHG BACT analysis for a 250 MMBtu/hr natural gas fired boiler. In this US EPA boiler example, 

carbon capture isn’t listed or considered in the BACT analysis as a potentially available option.

The absence of a discussion of carbon capture in this 250 MMBtu/hr boiler example is consistent 

with the fact that carbon capture is extremely expensive, has numerous technical challenges, and 

is currently only being contemplated on very large or very concentrated CO2 sources. In stark 

contrast, these IG Project miscellaneous combustion sources are an order of magnitude smaller 

than EPA’s boiler example, and significantly smaller still than the categories that US EPA’s 

guidance document suggests should consider CCS. 

A CO2 capture system for the IG gasifier emergency diesel engines is not a reasonable BACT 

option because the capture of the CO2 from combustion exhaust of small sources is significantly 

more difficult than from the types of industrial gas streams that EPA references as having 

potential for CCS. The increased difficulty is due to four factors: low CO2 concentration, low 

pressure, low quantity of CO2 available for capture, and the variability of load for these units. 

The low concentration and low pressure of the exhausts from these processes complicate the 

absorption and desorption of the CO2, which increases the energy required. Also, a low pressure 

absorption system creates a low pressure CO2 stream which requires a very high energy demand 

for compression prior to transport. All these factors make the application of CO2 capture on any 

small combustion exhaust extremely difficult and expensive. Additionally, the cost of capturing 

CO2 for smaller sources is more expensive due to the lack of economy-of-scale. Further, the 

emergency engines are intermittent sources, which would further increase the cost and difficulty 

of implementing any control.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of post-combustion capture of CO2 is not a technically feasible option for the Emergency 

generators and firewater pumps at this source. 
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Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The only feasible, applicable and available control technology identified to reduce greenhouse 

gases from the emergency diesel generators and firewater pump diesel engines is to utilize 

efficient engines with good engineering design. 

Step 4: Evaluate the Most Effective Controls and Document the Results

Proposal: Indiana Gasification, LLC

The following has been proposed as BACT for GHG emissions from the proposed Emergency 

generators and fire pump diesel engines: the selection and use of efficient engines with good 

engineering design.

This project includes two diesel-fired 1341 hp standby emergency generators (EU-009A/B) and 

three diesel-fired 575 hp standby fire water pumps (EU-010A-C). These engines are required for 

safety reasons. Each engine is expected to operate less than 52 hours per year each. That use 

is associated with assuring their readiness in an emergency. These emergency diesel engines 

will have the potential to emit greenhouse gases (CO2, CH4, and N2O) because they will combust 

a hydrocarbon fuel. However, because their normal use is limited to routine maintenance, 

inspection and testing, their total emissions are very small (less than 100 tons CO2e/yr). Their 

annual emissions in non-emergency use are as follows

Emission Units GHG Emissions (tons/yr)

CO2 CH4 N2O CO2e

Emergency Diesel Engines 

(total for 5, EU-009A/B, 

EU-010A-C)

84 0 0 84

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for the GHG for the Emergency diesel Engines.

The BACT shall be the use of good engineering design and efficient engines meeting applicable 

NSPS and MACT standards. 

The total CO2 emissions from all these emergency diesel engines, under non-emergency 

conditions, shall not exceed 84 tons CO2 per twelve (12) consecutive month period with 

compliance determined at the end of the month.

Greenhouse Gases (GHG) BACT – ZLD Spray Dryer (EU-032)

Step 1: Identify Potential Control Technologies

The CO2 is by far the dominant GHG from this source. CH4 and N2O are present only in very 

small amounts, are incidental to combustion, and trend with the CO2 emissions. There are no 

known supplemental controls for N2O or methane emissions from gas-fired units. To the extent 

measures are identified that reduce CO2, the other GHGs may be also reduced accordingly. 

Therefore, this BACT analysis focused on CO2 as a surrogate for all GHG emissions.
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GHG control possibilities identified and addressed in this BACT analysis for the small burner of 

the ZLD spray dryer are:

(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

These burners are proposed to use only natural gas or SNG. 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 (or SNG) as 

previously mentioned, no additional applicable good combustion practices have been identified. 

Carbon Capture

Post-combustion CO2 capture is a relatively new concept. In EPA’s recent GHG BACT guidance, 

EPA takes the position that, “for the purpose of a BACT analysis for GHGs, EPA classifies CCS 

as an add-on pollution control technology that is “available” for large CO2-emitting facilities 

including fossil fuel-fired power plants and industrial facilities with high-purity CO2 streams”. The 

small IG combustion sources such as the ZLD dryer do not fit into either of the above categories 

called out by EPA’s guidance document as appropriate for consideration of CCS. The EPA 

guidance document provides little specific guidance on whether or how to consider CCS in 

situations outside of the above examples. However, relevant guidance can be discerned from the 

Appendix F to the above referenced US EPA guidance document, which presents an example 

GHG BACT analysis for a 250 MMBtu/hr natural gas fired boiler. In this US EPA boiler example, 

carbon capture isn’t listed or considered in the BACT analysis as a potentially available option.

The absence of a discussion of carbon capture in this 250 MMBtu/hr boiler example is consistent 

with the fact that carbon capture is extremely expensive, has numerous technical challenges, and 

is currently only being contemplated on very large or very concentrated CO2 sources. In stark 

contrast, this IG Project miscellaneous combustion source only uses 5.2 MMBtu/hr. As such it is 

two orders of magnitude smaller than EPA’s boiler example, and significantly smaller still than the 

categories that US EPA’s guidance document suggests should consider CCS. 

A CO2 capture system for the IG ZLD spray dryer is not a reasonable BACT option because the 

capture of the CO2 from combustion exhaust of small sources is significantly more difficult than 

from the types of industrial gas streams that EPA references as having potential for CCS. The 

increased difficulty is due to four factors: low CO2 concentration, low pressure, low quantity of 

CO2 available for capture, and the variability of load for these units. 
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The low concentration and low pressure of the exhausts from these processes complicate the 

absorption and desorption of the CO2, which increases the energy required. Also, a low pressure 

absorption system creates a low pressure CO2 stream which requires a very high energy demand 

for compression prior to transport. All these factors make the application of CO2 capture on any 

small combustion exhaust extremely difficult and expensive. Additionally, the cost of capturing 

CO2 for smaller sources is more expensive due to the lack of economy-of-scale. 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of post-combustion capture of CO2 is not a technically feasible option for the ZLD Spray 

dryer at this source. 

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The only feasible, applicable and available control technologies identified are 

(1) The good engineering design and 

(2) The use of only natural gas or SNG. 

Step 4: Evaluate the Most Effective Controls and Document the Results

Proposal: Indiana Gasification, LLC

The following has been proposed as BACT for GHG from the proposed Zero Liquid Discharge 

(ZLD): 

The only feasible, applicable and available control technologies identified are;

(1) The good engineering design; and 

(2) The use of only natural gas or the comparable SNG. 

The Zero Liquid Discharge (ZLD) system is used to process the gasification scrubber blowdown 

water on a continuous basis, to control the level of chlorides in the circulation loop to a safe level 

due to corrosion considerations. The ZLD unit processes this stream and returns the liquid back 

to the process as makeup water for the scrubber. The dissolved solids/salts in the blowdown 

water are concentrated and removed by centrifuges. The majority of the concentrate from the 

centrifuges is returned back to the gasification process for conversion, except for a small purge 

stream that removes impurities from the process.

This purge stream is dried in a spray dryer where natural gas/SNG is combusted to generate heat 

to evaporate the water. The solids are collected and sent to a landfill for disposal. This spray 

dryer is an integral part of the process that must operate on a continuous basis. Through the use 

of natural gas, GHGs from the fuel is limited. Fuel use in this small source is only 5.2 

MMBtu/hour, generating only a small amount of GHGs.

Emission Units GHG Emissions (tons/yr)

CO2 CH4 N2O CO2e

ZLD Spray Dryer (EU-032) 2,884 0.05 0.01 2,887
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Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for the GHGs for the ZLD Spray Dryer.

1. The GHG BACT for the Zero Liquid Discharge (ZLD) Spray Dryer shall be the use of 

good engineering design and the use of natural gas (or SNG). 

2. The CO2 emissions from the ZLD Spray Dryer shall not exceed 2,884 tons CO2 per

twelve (12) consecutive month period with compliance determined at the end of the 

month.

Greenhouse Gases (GHG) BACT – Fugitive Equipment Leaks (FUG & FUG-WSA)

Step 1: Identify Potential Control Technologies

The GHG emissions from fugitive equipments leaks can be controlled by;

(a) Leak detection and Repair (LDAR)

Step 2: Eliminate Technically Infeasible Options

The source estimates there will be a small amount of GHG emissions from equipment and pipe 

component leaks, such as pumps, valves, flanges and compressors. This includes both CO2 and 

CH4. These fugitive emissions are so small relative to the overall facility emissions and in an 

absolute sense that further control of fugitive emissions would have minimal additional benefit. 

Nevertheless, IDEM has considered the implementation of a Leak Detection and Repair (LDAR) 

program as technically feasible.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(a) Leak Detection and Repair (LDAR) 

Step 4: Evaluate the Most Effective Controls and Document the Results

The source plans to implement a Leak Detection and Repair (LDAR) program for the fugitive 

components of process piping that primarily contain Hazardous Air Pollutants (HAPs) or VOC. 

IDEM considered whether it is feasible and cost-effective to extend this program to include LDAR 

for piping components containing GHGs. IDEM has concluded that extending the VOC LDAR 

program to also include the IG facility natural gas and SNG piping components is feasible and 

reasonably cost-effective, costing approximately $5/ton CO2e. However, extending the LDAR 

program to include CO2 streams would affect even less emissions on a CO2e basis, less than a 

tenth in comparison to methane, and it would not be cost effective. This is primarily because the 

global warming potential of CO2 is 21 times less than methane. Consequently, on a CO2e basis, 

controlling CO2 through an LDAR program is much less effective and less cost-effective than 

implementing an LDAR program for methane (natural gas and SNG).

The IG facility has three categories of CO2 containing streams:

1. The product CO2 stream – 98% CO2;

2. The acid gas stream from the AGR to the WSA – approx. 50% CO2; and 

3. The various syngas streams – 6-32% CO2.
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The table below shows the relative costs of controlling the above piping components with an LDAR 

program. 

Costs of a NESHAPS LDAR Program for IG GHG Containing Streams

Process Streams

IG Number 

of 

Components

Uncontrolled 

Emissions 

tons/yr 

CO2e

LDAR 

Controlled 

tons/yr 

CO2e

IG 

Estimated 

LDAR Costs 

per year 

(Note 1)

LDAR CostEffectiveness 

$/ton CO2e

Primary 

Pollutant 

Controlled

NG/SNG piping 

(methane) 93 276 2.09 $1,488 $5 CO2e

Acid Gas 

piping.(~50% 

CO2)

232 3.6 0.058 $3,712 $1,035 CO2

Product CO2

Piping (exclude. 

compressor)

95 5.2 0.08 $1,520 $298 CO2

Syngas (6-32% 

CO2) 964 8.5 0.14 $15,424 $1,840 CO2

Note 1. LDAR program costs assumed to be $16/yr/component per US EPA 2001 Refinery Tier 2 BACT report (see 

separate summary in Appendix C). Costs do not include separate extra cost for purchase/maintenance of unique 

monitor that would be needed for CO2 monitoring (FID not responsive to CO2) .

As stated above, extending the planned VOC LDAR program to also include natural gas and 

SNG piping is a reasonably cost-effective measure on a CO2e basis. However, the cost shown 

above for control of the CO2 streams is not cost-effective. It should be noted that the above 

estimates for the product CO2 piping excludes emissions from the seals of the CO2 compressors. 

Compressor shaft seals can be one of the larger fugitive leak points, especially for very high 

pressure systems. Consequently, IG proposes to conduct monthly audio/visual inspection of the 

compressors. A high pressure leak of CO2 would be both audibly detected and visible, due to 

condensation or ice formation from the auto-refrigeration of the leak.

Proposal: Indiana Gasification, LLC, IN

The following has been proposed as BACT for GHGs from the proposed Fugitives Equipment 

Leaks (FUG&FUG-WSA):

The BACT for fugitive GHG emissions is proposed to be use of a leak detection and repair 

(LDAR) program for the natural gas and SNG piping and weekly audio/visual inspection of the 

CO2 compressors while they are in operation. 

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 (FUG&FUG-WSA).

The BACT for fugitive GHG emissions is the use of a leak detection and repair (LDAR) program 

for the natural gas and SNG piping and weekly audio/visual inspection of the CO2 compressors 

while they are in operation in any week in which there are at least twenty-four (24) hours of 

operation of the CO2 compressor to be inspected. 
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Permit Reviewer: Josiah Balogun

Greenhouse Gases (GHG) BACT – Electric Circuit Breaker (FUG-SF6)

Step 1: Identify Potential Control Technologies

GHG control possibilities identified and addressed in this BACT analysis for these small potential 

sources are:

(1) The use of totally enclosed and pressurized circuit breakers with leak detection.

(2) The use of breakers without SF6 dielectric.

Step 2: Eliminate Technically Infeasible Options

Pressurized and enclosed breakers

The use of fully enclosed circuit breakers with leak detection (low pressure alarm) is state-of-theart for circuit breakers and is proposed by IG. A low pressure alarm is installed on each breaker 

to alert operators of a loss of SF6 gas. Operators will investigate the cause of any alarm and take 

corrective measures to stop the leak if one exists. 

Alternative breakers without SF6

There is no practical alternative to the use of SF6 as the insulator and arc quenching substance in 

IG’s circuit breakers. The unique performance qualities of SF6 breakers is further supported by 

the most recent report released by the EPA SF6 Partnership, which states: “no clear alternative 

exists for this gas that is used extensively in circuit breakers, gas-insulated substations, and 

switch gear, due to its inertness and dielectric properties.” Research and development efforts 

have focused on finding substitutes for SF6 that have comparable insulating and arc quenching 

properties in high-voltage applications. While some progress has reportedly been made in 

medium- or low-voltage applications, most studies have concluded, “that there is no replacement 

gas immediately available to use as an SF6 substitute” for high-voltage applications. Therefore, 

the use of a breaker that doesn’t contain SF6 is judged as not feasible for this application.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) The use of totally enclosed and pressurized circuit breakers with leak detection.

Step 4: Evaluate the Most Effective Controls and Document the Results

Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for GHGs from the proposed Electric Circuit Breaker 

(FUG-SF6): the use of fully enclosed pressurized SF6 circuit breakers with leak detection (low 

pressure alarm). 

Step 5: Select BACT

Pursuant to 326 IAC 2-2-3 (Prevention of Significant Deterioration (PSD), IDEM has established 

the following as BACT for GHGs for Electrical Circuit Breaker (FUG-SF6).

The GHGs BACT for the Electrical Circuit Breaker (FUG-SF6) shall be the use of fully enclosed 

pressurized SF6 circuit breakers with leak detection (low pressure alarm). 
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Greenhouse Gases (GHG) BACT – ZLD Inert Gas Vent (EU-033)

Step 1: Identify Potential Control Technologies

This very small inert gas vent stream from the wastewater system is primarily CO2 and water 

vapor. The CO2 in this vent is CO2 that dissolved into the process water in the high pressure 

environment of the gasification system. It is released in the Zero Liquid Discharge wastewater 

treatment system as the pressure is dropped. The total flow rate of this vent stream is only10.4 

acf/m and it contains only 204 tons/yr of CO2 emissions. There are no known GHG controls 

applicable to this extremely small process vent stream. 

Step 2: Eliminate Technically Infeasible Options

No technically feasible measures have been identified to control CO2 emissions in this small vent.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

No technically feasible measures have been identified to control CO2 emissions in this small vent.

Step 4: Evaluate the Most Effective Controls and Document the Results

No technically feasible measures have been identified to control CO2 emissions in this small vent.

Step 5: Select BACT

No technically feasible measures have been identified to control GHG emissions in this small 

vent.
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Indiana Department of Environmental Management

Office of Air Quality

Appendix B – BACT Analyses

Technical Support Document (TSD)

Requirement for Best Available Control Technology (BACT), 326 IAC 8-1-6

The requirements of 326 IAC 8-1-6 (New Facilities, General Reduction Requirements) applies to facilities 

located anywhere in the state that are constructed on or after January 1, 1980, which have potential 

volatile organic compounds (VOC) emissions greater than 25 tons per year, and which are not otherwise 

regulated by other provisions of 326 IAC 8 rule, and requires the reduction of VOC emissions using Best 

Available Control Technology (BACT). The proposed Acid Gas Removal Units, identified as EU-007A and 

EU-007B has potential VOC emissions of greater than 25 tons per year and are therefore subject to the 

requirements of this rule. 

326 IAC 8-1-6 requires a best available control technology (BACT) review to be performed on the 

proposed new emission units:

(1) Two (2) Acid Gas Removal (AGR) Unit vents, identified as EU-007A and EU-007B, to be 

permitted in 2012, with methanol, H2S, COS, and CO emissions controlled by two (2) 

regenerative thermal oxidizers (RTO) identified as C-007A and C-007B, respectively, each 

nominally rated at 38.8 MMBtu/hr HHV fuel input, exhausting through two (2) stacks, identified as 

S-007A and S-007B.

Volatile Organic Compounds (VOCs) BACT - Acid Gas Removal Unit Vents (EU-007A and B)

Step 1: Identify Potential Control Technologies

The volatile organic compounds (VOC) emissions can be controlled by the following methods: 

(1) Regenerative Thermal Oxidizer; 

(2) Conventional Thermal Oxidizer;

(3) Flare; and 

(3) Catalytic Oxidizer.

The Rectisol equipment will be designed to ensure that the CO2 stream is of sufficient purity for 

sale, without additional purification equipment. Thus, contaminants in the AGR Vent stream, such 

as methanol (VOC), will have already been reduced through the inherent process design. The 

use of additional add-on controls to control the VOC in the AGR Vent is possible. Destruction 

technologies reduce VOC concentration by high temperature oxidation into carbon dioxide and 

water vapor.

Step 2: Eliminate Technically Infeasible Options

The test for technical feasibility of any control option is whether it is both available and applicable 

in reducing VOC emissions. The control technologies listed in the previous section are 

discussed and evaluated below for their technical feasibility.
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Regenerative Thermal Oxidizer

Thermal oxidizers destroy air toxics and organic compounds that are discharged in industrial 

process exhausts. Thermal oxidizers achieve destruction through the process of high 

temperature thermal oxidation, converting combustible compounds to carbon dioxide and water 

vapor, and oxidizing toxic compounds to non-toxic compounds. Some thermal oxidizers preheat 

the incoming air by capturing heat from the outgoing air stream to reduce operating costs. 

Regenerative thermal oxidizers use ceramic heat transfer beds to recover thermal energy from 

the oxidation process. The heat transfer beds act as heat exchangers. The heat recovery can be 

as much as 90 to 95%. Process gas enters the RTO through an inlet manifold. The gas is 

directed into an energy recovery chamber which preheats the process gas. The process gas and 

contaminants are progressively heated in the ceramic bed as they move toward the combustion 

chamber. 

Thermal oxidation of VOC is the most effective treatment for this AGR Vent stream prior to 

venting to the atmosphere. Thermal oxidation will also control other contaminants in this stream 

by converting methanol to CO2 and water and COS to SO2 and CO2. To achieve thermal 

oxidation, air must be added and the combined stream heated to approximately 1600 degrees F. 

The heating value of the stream to the RTO is very low because it contains mostly noncombustible CO2 (98%). Consequently, each RTO will have a natural gas/SNG burner to raise 

the temperature in the combustion chamber of the RTO to approximately 1600 degrees F. This 

ensures a high oxidation efficiency of the CO (99%), CH3OH (99%), H2S (98%), and COS (98%). 

Most of this heat is recovered by heating one of the heat transfer beds which will be used 

subsequently to preheat the incoming gas stream (i.e.; the two beds are alternated between 

incoming gas and exhaust gas). This reduces the supplementary fuel firing rate and associated 

combustion emissions.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a regenerative thermal oxidizer (RTO) is a technically feasible option for Acid Gas 

Recovery Unit Vent (EU-007A/B) at this source.

Conventional Thermal Oxidizer

A conventional thermal oxidizer would be technically feasible for this stream. The control 

efficiency of a conventional Thermal Oxidizer is the same as the Regenerative Thermal Oxidizer, 

and provides 99% oxidation efficiency for methanol and 98% oxidation efficiency for COS. 

However, a Conventional Thermal Oxidizer does not provide for heat recovery.

There is very little heating value inherent in the AGR Vent stream which has an approximate 

concentration of 98%v CO2. Consequently, a conventional Thermal Oxidizer without heat 

recovery would have a very high supplemental fuel requirement (more than 10 times higher than 

a RTO) to reach a 1600 F gas temperature. Therefore, a conventional Thermal Oxidizer would 

have higher operating costs and higher combustion generated pollutant emissions (NOx, VOC, 

PM10). 

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that 

the use of a conventional thermal oxidizer is a technically feasible option for Acid Gas Recovery 

Unit Vent (EU-007A/B) at this source.

Catalytic Oxidation

A catalytic oxidizer converts the VOC in the combustion gases to CO2 at temperatures ranging 

from 500 degrees F to 700 degrees F in the presence of a catalyst. 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 approximately require 1.5 to 2.0 ft3 of catalyst per 1000 standard ft3 per gas flow rate. 

Catalytic oxidation is proposed for the Cash Creek Generation gasification AGR Vent Stream at a 
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control level of at least 90%. It is not expected to perform better than an RTO or a conventional 

thermal oxidizer.

The use of an oxidation catalyst to control VOC emissions may be more feasible for this emission 

unit than for other units because the fuel is a low sulfur fuel with relatively low concentrations of 

other contaminants, such as metals. However, the trace COS and H2S could reduce catalyst life.

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 Acid Gas Recovery Unit Vent 

(EU-007A/B) at this source.

Flare

The overall flow rate of this stream is very high, but VOC concentrations are low. As such, the 

heating value of the stream is too low for effective destruction in a flare. Since there are 

insufficient organics in this vent stream to support combustion, use of a flare would require a 

significant addition of supplementary fuel. Therefore, a secondary impact of the use of flare for 

this stream would be the creation of additional emissions from burning supplemental fuel, 

including NOx. Flares have not been utilized or demonstrated as a control device for VOC from 

this type of high-volume process stream. In addition, the flare would have no additional control 

effectiveness 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 Acid Gas Recovery Unit Vent (EU007A/B) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the technical feasibility analysis in Step 2, the remaining control technologies may be 

ranked as follows for controlling VOC emissions from the Acid Gas Recovery (AGR) Unit Vents

(EU-007 A/B).

(1) Regenerative thermal oxidation (98-99% VOC Reduction)

(2) Conventional thermal oxidation (98-99% VOC Reduction)

(3) Catalytic Oxidation (> 90% VOC Reduction)

The oxidation efficiency of VOC from both the Regenerative and Conventional Thermal Oxidizers 

is the same (98%). Overall VOC emissions generated from the AGR Vent stream are higher from 

the Conventional Thermal Oxidizer since it would require significantly more supplemental fuel 

firing (over 500 MMBtu/hr) and create additional combustion pollutant emissions. Thus, the 

regenerative thermal oxidizer will provide a superior VOC control performance compared to the 

conventional thermal oxidizer. A catalytic oxidizer is no more efficient.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed VOC BACT determination along with the existing VOC 

BACT determinations for similar plants. All data in the table is based on the information obtained 

from the permit application submitted by Indiana Gasification, LLC, the U.S. EPA 

RACT/BACT/LAER Clearinghouse (RBLC), and electronic versions of permits available at the 

websites of other permitting agencies.
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Permit Reviewer: Josiah Balogun

Facility Permit / 

Date Issued

Facility Size AGR Vent VOC Emission 

Rate

Control 

Technology 

Draft Permit No. 

147-30464-00060

Proposed

Limit

none 10,400 T dry 

coal/day

2.10 lb/hr based on 3-hr 

average (both units)

Regenerative 

Thermal Oxidizer

Lake Charles 

Gasification –

Louisiana

PSD-LA742(M1)

12/30/2009

9,413 T

coke/day

1.89 lb/hr

7.51 tons/yr

(permitted rate, no VOC 

BACT)

Regenerative 

Thermal Oxidizer

Cash Creek 

Gasification –

Kentucky

V-09-006

5/5/2010

770 MW No VOC limits listed in 

permit except facility-wide 

limit of 36 tons/yr VOC.

Catalytic Oxidizer

Power Holdings of 

Illinois Gasification

081801AAF

10/26/2009

13,700 T 

coal/day

0.81 tons/yr VOM

7.2 tons/yr methanol

Oxidizers or other 

combustion units

Hyperion Gasification 

– South Dakota

28.0701-PSD

8/20/2009

>7,400 T/day No VOC BACT or limits on 

this source

No controls 

Note: None of these facilities has been built or operated.

Compliance determination is unknown for all these sources.

None of these projects incorporate a more effective technology or represent a more stringent emissions 

limit for VOCs. All but one of these other facilities has proposed use of similar thermal or catalytic 

oxidation for control of organics from the AGR vent. The one exception is the Hyperion project in South 

Dakota which has proposed no controls. For those projects with controls, the numeric limits proposed are 

similar to that proposed by Indiana Gasification. Slight differences in ton/yr limits likely result from 

process design differences in each project’s AGR or gasification processes resulting in slightly different 

VOC amounts in the uncontrolled AGR vent stream. 

Proposal: Indiana Gasification, LLC – Rockport, IN

The following has been proposed as BACT for VOC from the proposed Acid Gas Recovery 

(AGR) Unit Vents (EU-007A/B):

The BACT for this Acid Gas Recovery (AGR) Unit Vents (EU-007 A/B) is proposed to be a 

regenerative Thermal oxidizer with a control efficiency of 98% and limiting emissions of VOC to 

1.05 pounds per hour based on a 3 hour average for each of the two AGR trains.

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 Acid Gas Recovery Unit vents (EU-007A/B).

The VOC emissions from the Acid Gas Recovery Unit vents (EU-007A/B) shall be controlled 

through the use of a Regenerative Thermal Oxidizer on each vent and the VOC emissions for 

each vent shall not exceed 1.05 pounds per hour based on a 3-hour average.
 

Air Quality Analysis

Indiana Gasification, LLC 

Rockport, Indiana (Spencer County) 

Tracking and Plant ID: 147-30464-00060 

Proposed Project 

Indiana Gasification, LLC (IG) first submitted their PSD modeling in April 2011. Revised modeling 

for NO2, SO2, and CO was sent in June 2011 to address modeling changes and new meteorological data. 

This was followed by PM10 and PM2.5 modeling sent in October 2011. The October PM10 and PM2.5

modeling was updated in November 2011 to address emission changes in the material handling sources. 

IG proposes to construct and operate a substitute natural gas (SNG) and liquefied carbon dioxide 

(CO2) production plant near the Ohio River in Spencer County, in Rockport, Indiana. The project will 

produce up to 48 billion standard cubic feet of SNG annually utilizing approximately 3.5 million tons of 

feedstock. 

URS was the consultant that prepared the modeling portion of the permit application for IG. This 

technical support document provides the air quality analysis review of the submitted modeling by URS for 

IG. 

Analysis Summary 

 Based on the potential emissions after controls, a PSD air quality analysis was triggered for 

SO2, PM10, PM2.5, CO, NO2, and sulfuric acid mist. The significant impact analysis for CO, NO2, SO2, and 

PM10 determined that modeling concentrations did not exceed the significant impact levels. A refined 

analysis was required for the 24 hour and annual PM2.5 standards. The refined modeling showed NAAQS 

violations but IG was below significance whenever the violations occurred. IG was also below the 24 

hour and annual PM2.5 increment. Pre-construction monitoring requirements were not necessary since 

existing monitoring is available and IG was below the monitoring significance levels. An additional impact 

analysis was conducted and showed no significant impact. A Hazardous Air Pollutant (HAP) analysis 

was performed. Based on the HAPs modeling results, the source will not pose a health concern. 

Air Quality Impact Objectives 

The purpose of the air quality impact analysis in the permit application is to accomplish the 

following objectives. Each objective is individually addressed in this document in each section outlined 

below. 

 

A. Establish which pollutants require an air quality analysis based on PSD significant emission 

rates. 

B. Provide analyses of actual stack heights with respect to Good Engineering Practice (GEP), 

the meteorological data used, a description of the model used in the analysis, and the 

receptor grid utilized for the analyses. 

C. Determine the significant impact level, the area impacted by the source's emissions, and 
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Permit Writer: Michael Mosier

background air quality levels. 

D. Demonstrate that the source will not cause or contribute to a violation of the National 

Ambient Air Quality Standard (NAAQS) or PSD increment if the applicant exceeds 

significant impact levels. 

E. Perform a qualitative analysis of the source's impact on general growth, soils, vegetation, 

and visibility in the impact area with emphasis on any Class I areas. The nearest Class I 

area is Kentucky's Mammoth Cave National Park. 

F. Perform a Hazardous Air Pollutant (HAP) screening for informational purposes. 

G. Summarize the Air Quality Analysis.

Section A - Pollutants Analyzed for Air Quality Impact 

Applicability 

The PSD requirements, 326 IAC 2-2, apply in attainment and unclassifiable areas and require an 

air quality impact analysis of each regulated pollutant emitted in significant amounts by a major stationary 

source or modification. Significant emission levels for each pollutant are defined in 326 IAC 2-2-1 and in 

the Code of Federal Regulations (CFR) 52.21(b) (23) (i). 

Proposed Project Emissions

PM10, PM2.5, NO2, SO2, CO, and sulfuric acid mist are the main pollutants that will be emitted from 

IG and are summarized below in Table 1. PM10, PM2.5, NO2, SO2, CO, and sulfuric acid mist potential 

emissions after controls exceed the PSD significant emission rates and require an air quality analysis, 

except for sulfuric acid mist. 

TABLE 1 

Significant Emission Rates for PSD

POLLUTANT SOURCE EMISSION RATE

(Facility totals in tons/year) 

SIGNIFICANT EMISSION 

RATE (tons/year)

PRELIMINARY AQ ANALYSIS 

REQUIRED

VOC1 15.9 40 No1

PM10 67.1 15 Yes 

PM2.5 60.5 10 Yes 

NO2 127 40 Yes 

SO2 <1002 40 Yes 

CO 634 100 Yes 

Sulfuric Acid Mist3 42.7 7 No3

1

An air quality analysis is not performed for VOCs because they are photochemically reactive. Photochemical models like UAM-V 

are used in regulatory or policy assessments to stimulate the impacts from all sources by estimating pollutant concentrations and 

deposition of both inert and chemically reactive pollutants over large spatial scales. Currently, U.S. EPA has no regulatory 

photochemical models which can take into account small spatial scales or single source PSD modeling for ozone. AERMOD is not 

a photochemical model. 

2 A source wide limit for the plant will keep it below 100 tpy. All maximum operating SO2 emission rates cannot happen at one time. 
Indiana Gasification, LLC Page 3 of 49 

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Permit Writer: Michael Mosier

3

Sulfuric Acid Mist has no monitoring threshold or National Ambient Air Quality Standard. No AQ analysis is required for Sulfuric 

Acid Mist under the PSD regulations. 

 IG’s emission rates were taken from Table 3-2 of their application and applicable supplemental 

submittals. 

Section B – Good Engineering Practice (GEP), Met Data, Model Used, Receptor 

Grid and Terrain 

Stack Height Compliance with Good Engineering Practice (GEP)

 Applicability

Stacks should comply with GEP requirements established in 326 IAC 1-7-4. If stacks are lower 

than GEP, excessive ambient concentrations due to aerodynamic downwash may occur. Dispersion 

modeling credit for stacks taller than 65 meters (213 feet) is limited to GEP for the purpose of establishing 

emission limitations. The GEP stack height takes into account the distance and dimensions of nearby 

structures, which affects the downwind wake of the stack. The downwind wake is considered to extend 

five times the lesser of the structure's height or width. A GEP stack height is determined for each nearby 

structure by the following formula: 

Hg = H + 1.5L 

Where: Hg is the GEP stack height 

H is the structure height 

L is the structure's lesser dimension (height or width) 

New Stacks

Since some of the new stack heights for IG are below GEP stack height, the effect of 

aerodynamic downwash is accounted for in the air quality analysis for the project. 

Meteorological Data 

The National Weather Service (NWS) 1-minute Automated Surface Observation Station (ASOS) 

meteorological data used in AERMOD consisted of 2006 through 2010 surface data from Evansville, 

Indiana and upper air measurements taken at Lincoln, Illinois. The meteorological data was 

preprocessed using the latest versions of AERMINUTE, AERSURFACE, and AERMET. 

Model Description 

URS used AERMOD Version 11103. The Office of Air Quality (OAQ) used the same model 

version in their air quality analysis review to determine maximum off-property concentrations or impacts 

for each pollutant. All regulatory default options were utilized in the U.S. EPA approved model, as listed 

in the 40 Code of Federal Register Part 51, Appendix W “Guideline on Air Quality Models”. 

Receptor Grid 

OAQ modeling used the same receptor grids generated by URS. The receptor grid is outlined 

below: 

 100 meter spacing along the facility’s property boundary, 

 100 meter spacing from the property boundary to 1500 meters, 

 1000 meters spacing from 1500 meters to 10000 meters. 
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If a maximum predicted concentration for a particular pollutant and averaging time was located within a 

portion of the receptor grid spacing greater than 100 meters, a supplemental 100 meter hot spot grid was 

utilized. 

Treatment of Terrain

Receptor terrain elevation inputs were interpolated from DEM (Digital Elevation Model) data 

obtained from the USGS. DEM terrain data was preprocessed using AERMAP. 

Section C - Significant Impact Level/Area (SIA) and Background Air Quality Levels

 A significant impact analysis was conducted to determine if the source would exceed the PSD 

significant impact levels (concentrations). If the source's concentrations exceed these levels, further air 

quality analysis is required. Refined modeling for PM10, SO2, NO2, and CO was not required because the 

results did not exceed significant impact levels. The 24-hour and annual PM2.5 values exceeded their 

significant impact levels and require refined modeling. URS modeled a variety of operating scenarios to 

predict maximum concentrations. A complete discussion of the different operating scenarios can be 

found in their application and in the November 2011 particulate modeling supplemental submittal. 

Significant impact levels are defined by the following time periods in Table 2 below with all maximummodeled concentrations from the worst case operating scenarios. A Tier II 80% conversion of NO to NO2

was assumed based on the March 01, 2011, Tyler Fox memorandum. 

TABLE 2 

Significant Impact Analysis3

POLLUTANT TIME AVERAGING 

PERIOD 

MAXIMUM MODELED 

IMPACTS (μg/m3

) 

SIGNIFICANT IMPACT 

LEVEL (μg/m3) 

REFINED AQ ANALYSIS 

REQUIRED 

NO2 Annual1 .64 1 No 

NO2 1 hour2 7.4 7.55 No 

PM10 Annual1 .986 1 No 

PM10 24 hour1 4.25 5 No 

PM2.5 Annual2 .30 .3 Yes 

PM2.5 24 hour2 1.66 1.2 Yes 

SO2 3 hour1 22.8 25 No 

SO2 24 hour1 2.5 5 No 

SO2 Annual1 .21 1 No 

SO2 1 hour2 7.04 7.80 No 

CO 1 hour1 454 2000 No 

CO 8 hour1 207 500 No 

1 The first highest values per the EPA NSR manual dated October 1990. 2 In accordance with recent U.S. EPA guidance, the highest modeled concentration may be averaged over the five years modeled 

for comparison with the 1 hour NO2, 1 hour SO2, 24 hour PM2.5 and the annual PM2.5 SIL. See the March 01, 2011, and the March 

23, 2010, memorandums

3 Impacts are from IG only. 
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Pre-construction Monitoring Analysis 

 Applicability 

 

 The PSD rule, 326 IAC 2-2-4, requires an air quality analysis of the new source or the major 

modification to determine if the pre-construction monitoring threshold is triggered. In most cases, 

monitoring data taken from a similar geographic location can satisfy this requirement if the preconstruction monitoring threshold has been exceeded. Also, post construction monitoring could be 

required if the air quality in that area could be adversely impacted by applicant’s emissions. 

 

Modeling Results 

 

 The modeling results were compared to the PSD preconstruction monitoring thresholds. The 

results are shown in the table below. 

TABLE 3 

Preconstruction Monitoring Analysis

POLLUTANT TIME 

AVERAGING 

PERIOD 

MAXIMUM 

MODELED 

IMPACTS (μg/m3

)

DEMINIMIS LEVEL 

(μg/m3) 

ABOVE DE MINIMIS LEVEL 

NO2 Annual1 .64 14 No 

PM10 24 hour1

4.25 10 No 

PM2.5 24 hour2 1.66 4 No 

SO2 24 hour1 2.5 13 No 

1

 The first highest values per the EPA NSR manual dated October 1990. Maximum modeled impacts are from IG only. 2 In accordance with recent U.S. EPA guidance, the highest modeled concentration may be averaged over the five years. See the 

March 01, 2011, and the March 23, 2010, memorandums from EPA.

 PM10, PM2.5, NO2 and SO2 did not trigger the preconstruction monitoring threshold level. IG can 

satisfy the preconstruction monitoring requirement since there is air quality monitoring data representative 

of the area in other counties. 

Background Concentrations 

Applicability 

 

 EPA’s “Ambient Monitoring Guidelines for Prevention of Significant Deterioration” (EPA-450/4-87-

007) Section 2.4.1 is cited for approval of the monitoring sites chosen for this area. 

Background Monitors 

 

Background data was taken from representative monitoring stations for IG. The background design value 

was used for PM2.5. It was agreed between IG and OAQ that this approach is taken in place of the 

preconstruction monitoring requirement. 

TABLE 4 

Existing Monitoring Data Used For Background Concentrations *
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Pollutant Location Monitoring Site Annual 

Concentration (μg/m3) 

24 hr 

Concentration (μg/m3) 

PM2.5 Owensboro, Kentucky 210590005 12.2 26 

*PM2.5 used the design value. 

Section D - NAAQS and PSD Increment 

 OAQ supplied emission inventories of all point sources in Indiana within a 50-kilometer radius of 

IG. The NAAQS inventories are generated from EMITS (Emission Inventory Tracking System) in 

accordance with 326 IAC 2-6. The PSD increment inventories include sources that affect the increment 

and are compiled from permits issued by OAQ. Kentucky supplied emission inventories for their state. 

All sources with the potential to cause a significant concentration gradient in the vicinity of the proposed 

facility were explicitly included in the modeling. 

 

NAAQS Compliance Analysis and Results for PM2.5 24 hour 

 NAAQS modeling for the 24-hour time-averaging period for PM2.5was conducted and compared 

to the respective NAAQS limit. For the 24-hour modeling, two scenarios were examined and had to do 

with feedstock deliveries both by truck or train. These operations cannot occur at the same time due to 

equipment and logistical constraints. OAQ modeling results are shown in Table 5a. All maximummodeled concentrations were compared to the respective NAAQS limit. All maximum-modeled 

concentrations during the five years plus background were not below the NAAQS limit and a culpability 

analysis was required and is shown in Table 5b and Table 5c. 

TABLE 5a1 

24-Hour NAAQS Analysis

Pollutant Year Time-Averaging 

Period 

Maximum 

Concentration 

μg/m3 

Background 

Concentration ug/m3 

Total 

μg/m3 

NAAQS Limit 

μg/m3 

NAAQS 

Violation 

PM2.5

(Truck 

Scenario) 

2006-

2010 24 hour 17.832

 26 43.83 35 Yes 

PM2.5

(Train 

Scenario) 

2006-

2010 24 hour 17.822

 26 43.82 35 Yes 

1

Any differences between the maximum concentration numbers in Tables 5 and 6 are due to different sources used for the NAAQS 

and the increment inventories and different averaging techniques to obtain maximum concentrations. Tables 3 and 6 maximum 

concentrations are from IG only. 

2

In accordance with recent U.S. EPA guidance, the highest modeled concentration may be averaged over the five years. See the 

March 23, 2010, memorandum from EPA.

Table 5b1 

24-Hour Culpability Analysis For Truck Delivery
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 Highest Predicted 24-hour PM2.5 Concentration from Cumulative Analysis for the Truck Delivery Scenario (μg/m3) 

Maximum 

Modeled 

Concentration IG 

Truck Scenario + 

Inventory 

Sources 

Background 

Design Value 

Owensboro Ky. 

Concentration 

(modeled + 

background) 

Contribution 

from Modeled 

Nearby 

Sources to 

Total 

Contribution 

from Modeled 

IG Truck 

Scenario to 

Total 

Is the Total 

Concentration ≥

NAAQS of 

35μg/m3? 

Is the IG 

contribution ≥

SIL of 

1.2μg/m3? 

17.83 26 43.83 17.68 0.15 yes no 

1

This follows the recent U.S. EPA guidance in the March 23, 2010, memorandum on page 8 which explains how to determine 

significant contributions to modeled violations. 

Table 5c1 

24-Hour Culpability Analysis For Train Delivery

 Highest Predicted 24-hour PM2.5 Concentration from Cumulative Analysis for the Train Delivery Scenario (μg/m3) 

Maximum 

Modeled 

Concentration 

IG train 

scenario + 

Nearby Sources 

Background 

Design Value 

Owensboro Ky. 

Total Tier I 

Concentration 

(modeled + 

background) 

Contribution 

from Modeled 

Nearby 

Sources to 

Total 

Contribution 

from Modeled 

IG train 

scenario to 

Total 

Is the Total 

Concentration ≥

NAAQS of 

35μg/m3? 

Is the IG 

contribution ≥

SIL of 

1.2μg/m3? 

17.82 26 43.82 17.68 0.14 yes no 1

This follows the recent U.S. EPA guidance in the March 23, 2010, memorandum on page 8 which explains how to determine 

significant contributions to modeled violations. 

Even though the model predicts a NAAQS violation, IG was not significant at the same receptor 

and time period. Therefore, IG does not cause or contribute to a violation of the NAAQS. 

 Every receptor over the standard was evaluated below the maximum modeled concentration for 

each scenario until there was no longer a NAAQS violation and showed IG was below significance and 

did not cause or contribute to a violation of the NAAQS. A table of these values can be found in the 

Appendix. 

NAAQS Compliance Analysis and Results for PM2.5 Annual 

 NAAQS modeling for the annual time period for PM2.5 was conducted and compared to the 

respective NAAQS limit. OAQ modeling results are shown in Table 5d. All maximum-modeled 

concentrations were compared to the respective NAAQS limit. All maximum-modeled concentrations 

during the five years plus background were below the NAAQS limit. A culpability analysis was also 

performed and is shown in Table 5e. 

TABLE 5d1 

Annual NAAQS Analysis

Pollutant Year Time-Averaging Maximum Background Total NAAQS Limit NAAQS 
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Period Concentration 

μg/m3 

Concentration μg/m3 μg/m3 μg/m3 Violation 

PM2.5

2006-

2010 Annual 2.662

 12.2 14.86 15 No 

1 Any differences between the maximum concentration numbers in Tables 5 and 6 are due to different sources used for the NAAQS 

and the increment inventories, and different averaging techniques to obtain maximum concentrations. Tables 3 and 6 maximum 

concentrations are from IG only. 

2

In accordance with recent U.S. EPA guidance, the annual concentrations may be averaged over the five years. See the March 23, 

2010, memorandum from EPA.

Table 5e 

Annual Culpability Analysis

 Highest Predicted Annual PM2.5 Concentration from Cumulative Analysis (μg/m3) 

Maximum 

Modeled 

Concentration IG 

+ Inventory 

Sources 

Background 

Design Value 

Owensboro Ky. 

Concentration 

(modeled + 

background) 

Contribution 

from Modeled 

Nearby 

Sources to 

Total 

Contribution 

from Modeled 

IG to Total 

Is the Total 

Concentration ≥

NAAQS of 

35μg/m3? 

Is the IG 

contribution ≥

SIL of .3 

μg/m3? 

2.66 12.2 14.86 2.36 0.3 no yes 

Even though the maximum 5-year annual average concentration for IG was greater than or equal 

to the significant impact level at a few receptors, the NAAQS was not violated at the same receptors or 

time period. Therefore, IG does not cause or contribute to a violation of the NAAQS. 

 URS also performed a further analysis to evaluate how much of the background value used in 

this analysis may already account for emissions from modeled nearby sources. That analysis is 

presented in the applicant’s November 2011 particulate modeling supplemental report. The analysis 

showed that the nearby sources’ modeled emissions are estimated to have an annual impact at the 

location of the background monitor of over 4 μg/m3

. This illustrates the potential double counting of the 

nearby source impacts and the conservatism of the analysis.

Analysis and Results of Source Impact on the PSD Increment 

 Applicability 

 Maximum allowable increases (PSD increments) are established by 326 IAC 2-2 for PM2.5. This 

rule also limits a source to no more than 80 percent of the available PSD increment to allow for future 

growth. 

Source Impact

 Since IG impacts for 24-hour and annual PM2.5 modeled greater than or equal to significant 

impact levels, a PSD increment analysis for IG was required for both averaging times. Because PM2.5

increment values were established in 2010 and the PM10 surrogacy policy was removed, the baseline 

date for the increment would be within the last few years. No sources surrounding IG are presumed to 

have been built in that time frame, therefore IG was the only facility modeled for comparison to the 

increments.

Results of the increment modeling are summarized in Table 6 below. 
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TABLE 61 

 Increment Analysis

Pollutant Year Time-Averaging 

Period 

Maximum 

Concentration 

μg/m3 

PSD Increment 

μg/m3 

Percent Impact on 

the PSD 

Increment 

Increment 

Violation

PM2.5(Train 

Scenario) 2006-2010 24-hour2

 1.64 9 18% No 

PM2.5(Truck 

Scenario) 2006-2010 24-hour2

 1.67 9 19% No 

PM2.5 (Truck 

Scenario) 2006-2010 Annual3

 0.33 4 8% No 

1

Any differences between the maximum concentration numbers in Tables 5 and 6 are due to different sources used for the NAAQS 

and the increment inventories, and different averaging techniques to obtain maximum concentrations. Tables 3 and 6 maximum 

concentrations are from IG only. 

2

In accordance with the Federal Register dated October 20, 2010; the high 2nd high is used. 3

In accordance with the Federal Register dated October 20, 2010; the highest annual average is used from any of the years 

modeled. 

 The results of the increment analysis show all pollutants for all averaging periods were below 

80% of the available increment. No further analysis is required. 

Analysis and Results of PM2.5 secondary formation 

In addition to direct emissions of PM2.5, other pollutants, chiefly NOx and SO2, can lead to 

formation of PM2.5 further downwind. The photochemical reactions that transform these pollutants into 

nitrates and sulfates, which become the major species of PM2.5, take place over hours or days. Potentials 

to emit after controls for IG are 127 tpy NOx and < 100 tpy SO2. 

The modeling for these two primary pollutants shows that receptor concentrations are below 

Significant Impact Levels (SIL) for their respective NAAQS and further diminish within the modeling 

domain out to 10 km to ensure the maximum concentrations are modeled. 

 

NOx SO2 
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Since the NO2 and SO2 standards are extremely restrictive, being below the SILs would likely 

prevent the pollutants from impacting secondary formation significantly enough to result in a violation of 

the PM2.5 standards. 

However, it is possible that some transformation into nitrates and sulfates from this source may 

occur and be transported downwind. No peer-reviewed regulatory model presently exists to examine the 

impacts of an individual source of SO2 or NOx. All photochemical models are regional scale and a source 

of this size would not show any measurable impact. Therefore, other available information from 

emissions inventories, meteorological analyses, and other modeling projects can be used to estimate the 

impact from this source. 

 The wind rose shows the general directions that emissions from this source would impact. 

 

 Evansville 2008 Evansville 2009 Evansville 2010 
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Design values from 2008 – 2010 at all Kentucky PM2.5 monitors in the area and Indiana PM2.5 

monitors meet the annual and 24-hour NAAQS. 

Because of the well established relationship between NOx and SO2, regional transport, and the 

formation of PM2.5, to assist states to meet the PM2.5 NAAQS, U.S. EPA recently finalized the Cross State 

Air Pollution Rule (CSAPR). This rule included extensive modeling to support the emissions reductions 

necessary in each state to achieve the PM2.5 NAAQS in the eastern U.S. The source category 

responsible for these reductions is Electric Generating Units (EGUs). 

U.S. EPA used a regional model, CAMx, and the Air Quality Assessment Tool (AQAT) to 

determine levels of reduction from EGUs necessary to achieve the NAAQS at every site. The 

documentation includes extensive tables showing impacts at all PM2.5 monitoring sites in the eastern U.S. 

and emission reduction levels necessary to achieve those results. 

To examine the possible impact of IG, modeling U.S. EPA used to establish the final 2014 

budgets in CSAPR is used for this analysis. The CSAPR website is located at 

http://www.epa.gov/airtransport/. 

Tables showing projected base case 2014 PM2.5 concentrations at existing monitoring sites 

versus control strategy PM2.5 concentrations are located in CSAPR_AQModeling.pdf, Appendix B, pages 

B-41 and B-42 for annual design values and pages B-70 to B-72 for 24-hour design values. 

Information regarding SO2 emission reductions necessary to achieve the future year modeled 

design values can be found in the “Significant Contribution Assessment TSD”, Table 1, page 9. This 

table shows the base case annual SO2 emissions for Indiana by 2014 were projected to be 727,786 tons, 

and remedy control scenario annual SO2 emissions by 2014 to be 195,046 tons. The difference between 

these is 532,740 tons. All surrounding states make similar significant reductions. 

EPA’s Cross-State Air Pollution Rule Emission Summary for Indiana 

 Pollutant 

2014 

Base 

(tons) 

2014 

Remedy 

(tons) 

EGU 

Reduction 

(tons) 

Indiana SO2 727,786 195,046 532,740 

Indiana NOx 117,832 110,740 7,092 

As an example, the maximum annual modeled concentrations for Spencer County are 12.66 

μg/m3

 for the 2014 base case and 9.95 μg/m3 for the 2014 control scenario. This is a reduction of 2.71 

μg/m3

. In order for this modeled annual concentration reduction to occur, Indiana EGUs modeled annual 

SO2 emissions by 2014 were reduced by 532,740 tons and annual NOx emissions by 2014 were reduced 

by 7,092 for a total of 539,833 tons of SO2 and NOx. This particular monitoring site is not necessarily 

impacted by every EGU in Indiana, but in the surrounding states, hundreds of thousands of tons of annual 

SO2 emission reductions have also occurred by 2014, many of which would impact this site. Therefore, to 

estimate the impact of IG on modeled concentrations, the ratio of IG SO2 and NOx emissions / 539,833 

tons of SO2 and NOx can be compared to the ratio of IG PM2.5 impact / 2.71 μg/m3

 of PM2.5. 

The calculation to estimate secondary formation is as follows: 

227 tons SO2 & NOx/539,833 tons SO2 & NOx = (IG PM2.5 impact) .00042* 2.71 μg/m3

 of PM2.5 = 0.00114

μg/m3

 of PM2.5

EPA’s Cross-State Air Pollution Rule Modeling Results & Estimated IG Impact 

 Anticipated Anticipated 
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Monitor ID County 

2014 

Base 

2014 

Remedy 

2014 

Base-Remedy 

(μg/m3) 

Source Impact 

(μg/m3) 

Source Impact 

(%) 

181470009 Spencer 12.66 9.95 2.71 0.00114 0.114% 

Since this concentration is well below measurable values, there would be no change in projected 

modeled PM2.5 concentrations at this site. 

EPA’s Cross-State Air Pollution Rule Annual PM2.5 Modeling Results & Estimated IG Impact 

Monitor ID County 

2014 

Base 

2014 

Remedy 

2014 

Base-Remedy 

(μg/m3) 

Anticipated 

Source Impact 

(μg/m3) 

Anticipated 

Source Impact 

(%) 

180372001 Dubois 13.72 11.04 2.68 0.00113 0.113% 

181630006 Vanderburgh 13.19 11.13 2.06 0.00087 0.087% 

181630012 Vanderburgh 13.25 11.23 2.02 0.00085 0.085% 

181630016 Vanderburgh 13.43 11.36 2.07 0.00087 0.087% 

Part E – Qualitative Analysis 

Additional Impact Analysis 

All PSD permit applicants must prepare an additional impact analysis for each pollutant subject to 

regulation under the Act. This analysis assesses the impacts on growth, soils and vegetation, 

endangered species, and visibility caused by any increase in emissions of any regulated pollutant from 

the source. The IG modeling submittal provided an additional impact analysis performed by URS. 

Economic Growth 

The purpose of the growth analysis is to quantify project associated growth and estimate the air 

quality impacts from this growth either quantitatively or qualitatively. 

 It is estimated that approximately 200 additional jobs will be created as a result of the proposed 

project. Most of the employees will be drawn from surrounding areas. Since the area is predominately 

rural, it is not expected the growth impacts will cause a violation of the NAAQS or the PSD increment. 

Soils and Vegetation Analysis 

 A list of soil types present in the general area was determined. Soil types include the following: 

Moderately thick loess over weathered loamy glacial till, discontinuous loess over weathered sandstone 

and shale, and discontinuous loess over weathered limestone and shale. 

 

 Due to the agricultural nature of the land, crops in the Spencer County area consist mainly of 

corn, sorghum, wheat, soybeans, and oats (2002 Agricultural Census for Spencer County). The 

maximum modeled concentrations for IG are well below the threshold limits necessary to have adverse 

impacts on the surrounding vegetation such as autumn bent, nimblewill, barnyard grass, bishop’s cap, 

horsetail, and milkweed (Flora of Indiana – Charles Deam). Livestock in Spencer County consist mainly 

of hogs, cattle, and sheep (2002 Agricultural Census for Spencer County) and will not be adversely 

impacted from the facility. Trees in the area are mainly hardwoods. These are hardy trees and no 

significant adverse impacts are expected due to modeled concentrations. 

Federal and State Endangered Species Analysis 
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 Federal and state endangered species are listed by the U.S. Fish and Wildlife Service, Division of 

Endangered Species for Indiana, and include 5 amphibians, 27 birds, 10 fishes, 6 mammals, 15 mollusks, 

and 15 reptiles. Of the federal and state endangered species on the list, 1 reptile, 3 mollusks, 1 fish, 4 

birds, and 2 mammals have habitat within Spencer County. The mollusks, fish, amphibians, and certain 

species of birds and mammals are found along rivers and lakes while the other species of birds and 

mammals are found in forested areas. The facility is not expected to have any additional adverse effects 

on the habitats of the species than what has already occurred from the industrial, farming, and residential 

activities in the area. 

 Federal and state endangered plants are listed by the U.S. Fish and Wildlife Service, Division of 

Endangered Species for Indiana. At this time 8 state endangered plant species are found in Spencer 

County. The endangered plants do not thrive in industrialized and residential areas. The facility is not 

expected to adversely affect any plant on the endangered species list. 

Visibility Analysis 

 The Federal Class I areas include national parks and national wilderness areas and are 

considered environments for which minimal air quality degradation is allowed. 

 The nearest Class 1 area to IG is Mammoth Cave National Park which is approximately 100 km 

from the plant. Pursuant to a new federal guidance document (Federal Land Managers’ Air Quality 

Related Values Work Group (FLAG) Phase 1 Report – Revised November 2010), the IG facility would not 

be required to conduct a Class 1 area analysis since the combined emissions of visibility impairing 

pollutants are less the screening threshold. The threshold is calculated by dividing the emissions by 

distance for sources more than 50 km from a Class 1 area. If the number is less than 10 then a visibility 

analysis is not required. IG did a visibility analysis anyway to show that the proposed project would not 

degrade visibility at Mammoth Cave National Park. 

 The primary visibility impairment pollutants are PM10, SO2, and NOx. Proposed potential 

emissions of these pollutants from IG were examined for source contribution to visibility impairment. 

 The CALPUFF model was used to estimate visibility impairment from the source. CALPUFF was 

run for 3 annual simulations, covering calendar years 2002 to 2004. The receptors used to determine 

visibility impacts were taken from the National Park Service’s Class I receptor index (NPS, 2005). 

CALPUFF requires the input of ozone and ammonia concentrations as a monthly background value 

applicable for the entire modeling domain. Annual background concentrations for the eastern United 

States are given in the Guidance for Estimating Natural Visibility Conditions (EPA 2003). 

 The visibility degradation beyond natural conditions is expressed in atmospheric light extinction 

(beta extinction = Bext) and also in deciviews. A 5% change in light extinction (Bext) equates to 

approximately 0.5 deciviews. The criteria used to determine if a source is contributing to visibility 

impairment is the 98th percentile that is equal to 0.5 deciviews using a maximum 24-hr emission rate. 

 The modeling results show that the highest change in light extinction for all years is well below 

0.5 deciview threshold. Therefore, IG will not contribute to visibility impairment at Mammoth Cave 

National Park. 

Additional Analysis Conclusions 

 Finally, the results of the additional impact analysis conclude the operation of the facility will have 

no significant impact on economic growth, soils, vegetation, or visibility in the immediate vicinity or on any 

Class I area.
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Part F – HAPs Analysis 

 OAQ currently requests data concerning the emission of 189 HAPs listed in the 1990 Clean Air 

Act Amendments (CAAA) that are either carcinogenic or otherwise considered toxic and may be used by 

industries in the State of Indiana. These substances are listed as air toxic compounds on the State of 

Indiana, Department of Environmental Management, Office of Air Quality's construction permit application 

Form GSD-08. 

The single HAP with the highest emissions is methanol, with estimated annual emissions of 7.5 

tons per year. Potential emissions of aggregate HAPs are estimated not to be over 10.1tons per year. 

 

 For IG, a full HAP analysis was completed comparing the maximum estimated concentrations of 

each pollutant with the Unit Risk Factor (URF) or the Inhalation Unit Risk, and the Reference 

Concentration (RfC). This analysis offers a refined, up to date site specific analysis that takes into 

account the different potencies and health effects that each pollutant presents to the public. 

The URF is the upper-bound excess lifetime cancer risk estimated to result from continuous 

inhalation exposure to a pollutant over a 70 year lifetime. Multiplying the estimated concentration by the 

URF will produce a cancer risk estimate. The cancer risk estimate is the conservative probability of 

developing cancer from exposure to a pollutant or a mixture of pollutants over a 70 year lifetime, usually 

expressed as the number of additional cancer cases in a given number of people, e.g., one in a million. 

For screening purposes at IG, the cancer estimates for each pollutant are considered to be additive when 

deriving the cumulative maximum individual cancer risk. 

Non-cancer health effects are determined using the Reference Concentration (RfC). The RfC is 

an estimate of a continuous inhalation exposure to the human population (including sensitive subgroups) 

that is likely to be without an appreciable risk of deleterious effects during a lifetime. Dividing the 

estimated pollutant concentration by the RfC will determine the pollutant’s Hazard Quotient (HQ). All of 

the HAPs’ Hazard Quotients were added together to determine IG’s Hazard Index (HI). 

This HAP screening analysis uses health protective assumptions that overestimate the actual risk 

associated with emissions from IG. Estimates 1) assume a 70 year exposure time, 2) assume that all 

carcinogens cause the same type of cancer, 3) assume that all non-carcinogens have additive health 

effects, 4) assume maximum permit allowable emissions from the facility, and 5) use conservatively 

derived dose-response information. The risk analysis cannot accurately predict whether there will be 

observed health problems around IG; rather it identifies possible avenues of risk. 

The results of the HAP modeling are in Table 7. 

TABLE 7

Hazardous Air Pollutant Modeling Results 

Compound 

CAS 

Number 

 Annual 

Concentration 

(μg/m3) 

 Cancer 

URF, 

(μg/m3)-1 Source 

Cancer 

Risk 

NonCancer 

Chronic 

RfC, 

μg/m3 

Source 

of IDEM 

RfC 

Hazard 

Quotient 

Ammonia 7664417 0.39 100.00 IRIS 0.004 

Carbonyl Sulfide 463581 0.02 12.00 TRI 0.002 

Hydrogen 

Sulfide 7783064 0.17 2.00 IRIS 0.085 

Mercury 

compounds 0 0.00001 0.09 CAL 0.000 
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Methanol 67561 1.74 4000.00 CAL 0.000 

 

∑ Cancer 

Risk 0.0000 

Hazard 

Index 

(HI) 

0.0911 

 

IDEM 

Standard 

1.0000E06 IDEM 

Standard 1.00+00 

 Comparison Below Below 

* Further information on URFs and RfCs can be found at the following EPA web site: http://www.epa.gov/ttn/atw/toxsource/chronicsources.html

 

 The Hazard Index for the project does not exceed 1. Pollutants with a Hazard Quotient (HQ) 

greater than 1 are considered to be at concentrations that could represent a health concern. Hazard 

Quotients above 1 do not represent areas where adverse health effects will be observed but indicate that 

the potential exists. 

 

 The additive cancer risk estimate from all HAPs is 0 additional cancer causes in ten million 

people. None of the HAPs evaluated are carcinogens. This means if an individual was exposed to these 

HAPs continuously for 70 years, the risk of getting cancer from this exposure would be 0 in ten million. 

The US EPA considers one in ten thousand (1.0E-04) excess cancer risks to be the upper range of 

acceptability with an ample margin of safety. The probability for the general public to be exposed to these 

HAPs for 24 hours a day, seven days a week, and 52 weeks a year for 70 years is minimal. 

Part H - Summary of Air Quality Analysis 

 URS prepared the modeling portion of the PSD application. Spencer County is designated as 

attainment for all criteria pollutants. PM10, NO2, SO2, CO, PM2.5, and sulfuric acid mist emission rates 

associated with the proposed facility exceeded the respective significant emission rates. Modeling results 

taken from AERMOD model showed PM2.5 impacts were predicted to be greater than the significant 

impact levels for the 24-hour and annual averaging periods. IG did not trigger the preconstruction 

monitoring threshold level but can satisfy the preconstruction monitoring requirement since there is 

existing air quality monitoring data representative of the area. The NAAQS modeling for 24-hour 

PM2.5showed violations of the standard, but IG was not significant during those violations. Though IG 

was significant for annual PM2.5, the NAAQS modeling did not show violations of the standard. IG was 

below the PM2.5 increment modeling. Secondary PM2.5 formation will be below measureable values. The 

nearest Class I area is Mammoth Cave National Park in Kentucky, just under 100 kilometers away from 

the source, but emissions are below the Federal Land Manager guidance screening threshold. An 

additional impact analysis was performed and the operation of the proposed facility will have no 

significant impact. A Hazardous Air Pollutant (HAP) analysis was performed and showed no likely 

adverse impact. 
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Appendix 

24-Hour PM2.5 Culpability Analysis For Truck Delivery
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X Y AVERAGE 

CONC AVE RANK IG TRUCK INVENTORY IG TRUCK+ 

INVENTORY 

494100 4196600 16.33782 24-HR 1ST 0.22071 16.11712 16.33782 

494200 4196400 17.2889 24-HR 1ST 0.28825 17.00065 17.2889 

494200 4196500 17.0064 24-HR 1ST 0.27175 16.73465 17.0064 

494200 4196600 16.55326 24-HR 1ST 0.2356 16.31766 16.55326 

494200 4196700 16.18085 24-HR 1ST 0.22418 15.95668 16.18085 

494200 4196800 15.76415 24-HR 1ST 0.32961 15.43454 15.76415 

494300 4196400 17.54035 24-HR 1ST 0.2972 17.24315 17.54035 

494300 4196500 17.23232 24-HR 1ST 0.31668 16.91563 17.23232 

494300 4196600 16.70711 24-HR 1ST 0.30664 16.40047 16.70711 

494300 4196700 16.33084 24-HR 1ST 0.25681 16.07404 16.33084 

494300 4196800 16.01257 24-HR 1ST 0.34462 15.66795 16.01257 

494300 4196900 16.03167 24-HR 1ST 0.40039 15.63128 16.03167 

494400 4196400 17.69597 24-HR 1ST 0.26769 17.42828 17.69597 

494400 4196500 17.42485 24-HR 1ST 0.33606 17.08879 17.42485 

494400 4196600 16.92255 24-HR 1ST 0.35381 16.56875 16.92255 

494400 4196700 16.47253 24-HR 1ST 0.27993 16.19261 16.47253 

494400 4196800 16.20112 24-HR 1ST 0.36009 15.84103 16.20112 

494400 4196900 16.11488 24-HR 1ST 0.39841 15.71647 16.11488 

494400 4197000 16.2765 24-HR 1ST 0.42783 15.84867 16.2765 

494500 4196400 17.76407 24-HR 1ST 0.20262 17.56146 17.76407 

494500 4196500 17.52322 24-HR 1ST 0.30239 17.22084 17.52322 

494500 4196600 17.09376 24-HR 1ST 0.38405 16.70971 17.09376 

494500 4196700 16.56606 24-HR 1ST 0.30366 16.26239 16.56606 

494500 4196800 16.35886 24-HR 1ST 0.38747 15.97139 16.35886 

494500 4196900 16.19497 24-HR 1ST 0.39323 15.80174 16.19497 

494500 4197000 16.31792 24-HR 1ST 0.42845 15.88947 16.31792 

494600 4196400 17.82506 24-HR 1ST 0.14993 17.67514 17.82506 Max IG Truck + Inventory 

494600 4196500 17.57066 24-HR 1ST 0.22428 17.34639 17.57066 

494600 4196600 17.18705 24-HR 1ST 0.33017 16.85689 17.18705 

494600 4196700 16.66645 24-HR 1ST 0.36746 16.29899 16.66645 

494600 4196800 16.49839 24-HR 1ST 0.41868 16.07971 16.49839 

494600 4196900 16.29663 24-HR 1ST 0.38033 15.9163 16.29663 

494600 4197000 16.30522 24-HR 1ST 0.40673 15.89848 16.30522 

494600 4197100 16.4703 24-HR 1ST 0.40428 16.06602 16.4703 

494700 4196500 17.64888 24-HR 1ST 0.15631 17.49257 17.64888 

494700 4196600 17.26526 24-HR 1ST 0.23582 17.02943 17.26526 

494700 4196700 16.7373 24-HR 1ST 0.30259 16.43472 16.7373 

494700 4196800 16.60647 24-HR 1ST 0.48872 16.11775 16.60647 

494700 4196900 16.37319 24-HR 1ST 0.36325 16.00994 16.37319 

494700 4197000 16.25425 24-HR 1ST 0.39032 15.86393 16.25425 

494700 4197100 16.47006 24-HR 1ST 0.40566 16.06439 16.47006 

494800 4196700 16.80138 24-HR 1ST 0.33863 16.46276 16.80138 

494800 4196800 16.73707 24-HR 1ST 0.45876 16.27831 16.73707 

494800 4197200 16.7471 24-HR 1ST 0.37676 16.37034 16.7471 

494806 4196692.8 16.84714 24-HR 1ST 0.2153 16.63184 16.84714 

494806 4196791.2 16.79548 24-HR 1ST 0.48673 16.30875 16.79548 

494806 4197184.8 16.71355 24-HR 1ST 0.38218 16.33137 16.71355 
Indiana Gasification, LLC Page 18 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494968.8 4197480 17.27565 24-HR 1ST 0.44108 16.83457 17.27565 

495050.2 4197480 17.4518 24-HR 1ST 0.61875 16.83305 17.4518 

495100 4197500 17.55386 24-HR 1ST 0.69133 16.86254 17.55386 

495131.6 4197480 17.58039 24-HR 1ST 0.73667 16.84373 17.58039 

495200 4197600 17.63595 24-HR 1ST 0.66417 16.97178 17.63595 

495221.2 4197567.4 17.66499 24-HR 1ST 0.71968 16.94532 17.66499 

495221.3 4197656.9 17.61131 24-HR 1ST 0.6139 16.99742 17.61131 

495221.3 4197746.4 17.46202 24-HR 1ST 0.52282 16.9392 17.46202 

494100 4196500 16.78272 24-HR 1ST 0.29003 16.49269 16.78272 

495100 4197600 17.54473 24-HR 1ST 0.59343 16.95131 17.54473 

495200 4197500 17.67248 24-HR 1ST 0.80501 16.86747 17.67248 Max IG Truck 

495200 4197700 17.51409 24-HR 1ST 0.52982 16.98427 17.51409 

495213 4197480 17.67524 24-HR 1ST 0.72179 16.95345 17.67524 

495221.2 4197478 17.68165 24-HR 1ST 0.72352 16.95814 17.68165 

494100 4196600 14.31551 24-HR 2ND 0.25411 14.0614 14.31551 

494200 4196400 14.31916 24-HR 2ND 0.20193 14.11723 14.31916 

494200 4196500 14.4389 24-HR 2ND 0.2218 14.21711 14.4389 

494200 4196600 14.46668 24-HR 2ND 0.25653 14.21015 14.46668 

494200 4196700 14.0762 24-HR 2ND 0.36783 13.70837 14.0762 

494200 4196800 13.98417 24-HR 2ND 0.34162 13.64255 13.98417 

494300 4196400 14.34622 24-HR 2ND 0.19384 14.15238 14.34622 

494300 4196500 14.50741 24-HR 2ND 0.22865 14.27875 14.50741 

494300 4196600 14.58693 24-HR 2ND 0.24103 14.3459 14.58693 

494300 4196700 14.12922 24-HR 2ND 0.29787 13.83135 14.12922 

494300 4196800 13.95006 24-HR 2ND 0.35487 13.5952 13.95006 

494300 4196900 13.38277 24-HR 2ND 0.38208 13.00069 13.38277 

494400 4196400 14.2302 24-HR 2ND 0.16938 14.06082 14.2302 

494400 4196500 14.40677 24-HR 2ND 0.23877 14.168 14.40677 

494400 4196600 14.48656 24-HR 2ND 0.25579 14.23077 14.48656 

494400 4196700 14.09709 24-HR 2ND 0.33907 13.75803 14.09709 

494400 4196800 13.80623 24-HR 2ND 0.28428 13.52195 13.80623 

494400 4196900 13.31014 24-HR 2ND 0.35276 12.95738 13.31014 

494400 4197000 12.65316 24-HR 2ND 0.40943 12.24373 12.65316 

494500 4196400 14.1193 24-HR 2ND 0.1481 13.9712 14.1193 

494500 4196500 14.30732 24-HR 2ND 0.24454 14.06278 14.30732 

494500 4196600 14.41094 24-HR 2ND 0.31372 14.09722 14.41094 

494500 4196700 14.15072 24-HR 2ND 0.51433 13.63639 14.15072 

494500 4196800 13.75197 24-HR 2ND 0.37065 13.38132 13.75197 

494500 4196900 13.20924 24-HR 2ND 0.40486 12.80439 13.20924 

494500 4197000 12.6494 24-HR 2ND 0.50093 12.14847 12.6494 

494600 4196400 14.06843 24-HR 2ND 0.13404 13.9344 14.06843 

494600 4196500 14.21584 24-HR 2ND 0.20438 14.01145 14.21584 

494600 4196600 14.31308 24-HR 2ND 0.26436 14.04872 14.31308 

494600 4196700 14.15993 24-HR 2ND 0.43515 13.72479 14.15993 

494600 4196800 13.82507 24-HR 2ND 0.41557 13.4095 13.82507 

494600 4196900 13.22822 24-HR 2ND 0.35944 12.86878 13.22822 

494600 4197000 12.73397 24-HR 2ND 0.35519 12.37879 12.73397 

494600 4197100 12.89124 24-HR 2ND 0.37936 12.51187 12.89124 

494700 4196500 14.13924 24-HR 2ND 0.18533 13.95391 14.13924 
Indiana Gasification, LLC Page 19 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494700 4196600 14.19846 24-HR 2ND 0.20517 13.99329 14.19846 

494700 4196700 14.08638 24-HR 2ND 0.38199 13.70439 14.08638 

494700 4196800 13.85841 24-HR 2ND 0.4138 13.44461 13.85841 

494700 4196900 13.27187 24-HR 2ND 0.36364 12.90823 13.27187 

494700 4197000 12.85438 24-HR 2ND 0.32591 12.52847 12.85438 

494700 4197100 12.94516 24-HR 2ND 0.33802 12.60715 12.94516 

494800 4196700 13.9976 24-HR 2ND 0.22719 13.77041 13.9976 

494800 4196800 13.74875 24-HR 2ND 0.30218 13.44657 13.74875 

494800 4197200 13.02753 24-HR 2ND 0.33903 12.6885 13.02753 

494806 4196692.8 14.00234 24-HR 2ND 0.19806 13.80429 14.00234 

494806 4196791.2 13.79075 24-HR 2ND 0.31155 13.47921 13.79075 

494806 4197184.8 13.03107 24-HR 2ND 0.35031 12.68077 13.03107 

494968.8 4197480 13.47443 24-HR 2ND 0.29057 13.18386 13.47443 

495050.2 4197480 13.71857 24-HR 2ND 0.44475 13.27381 13.71857 

495100 4197500 13.84187 24-HR 2ND 0.51763 13.32425 13.84187 

495131.6 4197480 13.80785 24-HR 2ND 0.52308 13.28477 13.80785 

495200 4197600 13.91961 24-HR 2ND 0.47516 13.44444 13.91961 

495221.2 4197567.4 13.93646 24-HR 2ND 0.48943 13.44703 13.93646 

495221.3 4197656.9 13.8942 24-HR 2ND 0.47682 13.41738 13.8942 

495221.3 4197746.4 13.65376 24-HR 2ND 0.41541 13.23836 13.65376 

494100 4196500 14.36332 24-HR 2ND 0.20502 14.1583 14.36332 

495100 4197600 13.89354 24-HR 2ND 0.47623 13.41731 13.89354 

495200 4197500 13.86455 24-HR 2ND 0.50359 13.36097 13.86455 

495200 4197700 13.78167 24-HR 2ND 0.47656 13.3051 13.78167 

495213 4197480 13.81793 24-HR 2ND 0.60012 13.21781 13.81793 

495221.2 4197478 13.80858 24-HR 2ND 0.60043 13.20816 13.80858 

494100 4196600 12.20418 24-HR 3RD 0.308 11.89618 12.20418 

494200 4196400 12.09741 24-HR 3RD 0.35293 11.74448 12.09741 

494200 4196500 12.2457 24-HR 3RD 0.37689 11.86881 12.2457 

494200 4196600 12.35309 24-HR 3RD 0.43354 11.91955 12.35309 

494200 4196700 12.70046 24-HR 3RD 0.3546 12.34587 12.70046 

494200 4196800 12.60959 24-HR 3RD 0.27931 12.33029 12.60959 

494300 4196400 12.04414 24-HR 3RD 0.34088 11.70326 12.04414 

494300 4196500 12.23606 24-HR 3RD 0.39803 11.83802 12.23606 

494300 4196600 12.43202 24-HR 3RD 0.48414 11.94787 12.43202 

494300 4196700 12.86684 24-HR 3RD 0.48764 12.3792 12.86684 

494300 4196800 12.59382 24-HR 3RD 0.38427 12.20955 12.59382 

494300 4196900 12.58355 24-HR 3RD 0.22934 12.35421 12.58355 

494400 4196400 11.93231 24-HR 3RD 0.30923 11.62308 11.93231 

494400 4196500 12.13707 24-HR 3RD 0.43965 11.69741 12.13707 

494400 4196600 12.47988 24-HR 3RD 0.5591 11.92078 12.47988 

494400 4196700 12.96966 24-HR 3RD 0.5539 12.41577 12.96966 

494400 4196800 12.65778 24-HR 3RD 0.46248 12.1953 12.65778 

494400 4196900 12.55397 24-HR 3RD 0.45213 12.10185 12.55397 

494400 4197000 12.47548 24-HR 3RD 0.41948 12.05601 12.47548 

494500 4196400 11.84322 24-HR 3RD 0.28625 11.55697 11.84322 

494500 4196500 11.97751 24-HR 3RD 0.40225 11.57526 11.97751 

494500 4196600 12.36587 24-HR 3RD 0.43458 11.93129 12.36587 

494500 4196700 12.95306 24-HR 3RD 0.40724 12.54582 12.95306 
Indiana Gasification, LLC Page 20 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494500 4196800 12.70821 24-HR 3RD 0.38635 12.32186 12.70821 

494500 4196900 12.60461 24-HR 3RD 0.3264 12.27821 12.60461 

494500 4197000 12.50288 24-HR 3RD 0.28539 12.21748 12.50288 

494600 4196400 11.81092 24-HR 3RD 0.2214 11.58952 11.81092 

494600 4196500 11.85048 24-HR 3RD 0.38948 11.461 11.85048 

494600 4196600 12.24279 24-HR 3RD 0.35328 11.8895 12.24279 

494600 4196700 12.86145 24-HR 3RD 0.37628 12.48516 12.86145 

494600 4196800 12.70722 24-HR 3RD 0.41482 12.2924 12.70722 

494600 4196900 12.5946 24-HR 3RD 0.37736 12.21724 12.5946 

494600 4197000 12.58916 24-HR 3RD 0.46618 12.12297 12.58916 

494600 4197100 12.2716 24-HR 3RD 0.46158 11.81002 12.2716 

494700 4196500 11.9865 24-HR 3RD 0.13145 11.85504 11.9865 

494700 4196600 12.35013 24-HR 3RD 0.25704 12.09309 12.35013 

494700 4196700 12.86745 24-HR 3RD 0.22783 12.63962 12.86745 

494700 4196800 12.7499 24-HR 3RD 0.27944 12.47046 12.7499 

494700 4196900 12.64118 24-HR 3RD 0.32613 12.31505 12.64118 

494700 4197000 12.60937 24-HR 3RD 0.35889 12.25048 12.60937 

494700 4197100 12.38265 24-HR 3RD 0.47773 11.90491 12.38265 

494800 4196700 13.06513 24-HR 3RD 0.15818 12.90695 13.06513 

494800 4196800 12.90494 24-HR 3RD 0.25395 12.65099 12.90494 

494800 4197200 12.12955 24-HR 3RD 0.20594 11.92361 12.12955 

494806 4196692.8 13.034 24-HR 3RD 0.26935 12.76465 13.034 

494806 4196791.2 12.97781 24-HR 3RD 0.38293 12.59488 12.97781 

494806 4197184.8 12.1591 24-HR 3RD 0.20389 11.95521 12.1591 

494968.8 4197480 11.95197 24-HR 3RD 0.43121 11.52076 11.95197 

495050.2 4197480 12.26537 24-HR 3RD 0.45242 11.81295 12.26537 

495100 4197500 12.36822 24-HR 3RD 0.47714 11.89109 12.36822 

495131.6 4197480 12.50605 24-HR 3RD 0.51638 11.98967 12.50605 

495200 4197600 12.35635 24-HR 3RD 0.53489 11.82146 12.35635 

495221.2 4197567.4 12.45341 24-HR 3RD 0.56911 11.8843 12.45341 

495221.3 4197656.9 12.22747 24-HR 3RD 0.50961 11.71786 12.22747 

495221.3 4197746.4 12.02651 24-HR 3RD 0.43945 11.58706 12.02651 

494100 4196500 12.05131 24-HR 3RD 0.29291 11.7584 12.05131 

495100 4197600 12.06222 24-HR 3RD 0.37994 11.68228 12.06222 

495200 4197500 12.57467 24-HR 3RD 0.57671 11.99796 12.57467 

495200 4197700 12.06348 24-HR 3RD 0.40459 11.6589 12.06348 

495213 4197480 12.61493 24-HR 3RD 0.58739 12.02754 12.61493 

495221.2 4197478 12.62201 24-HR 3RD 0.59223 12.02979 12.62201 

494100 4196600 11.77262 24-HR 4TH 0.28139 11.49122 11.77262 

494200 4196400 11.08252 24-HR 4TH 0.1277 10.95483 11.08252 

494200 4196500 11.43195 24-HR 4TH 0.19015 11.24181 11.43195 

494200 4196600 11.76516 24-HR 4TH 0.24436 11.5208 11.76516 

494200 4196700 11.80757 24-HR 4TH 0.18334 11.62424 11.80757 

494200 4196800 11.9681 24-HR 4TH 0.19214 11.77596 11.9681 

494300 4196400 11.26167 24-HR 4TH 0.24111 11.02056 11.26167 

494300 4196500 11.47287 24-HR 4TH 0.1867 11.28618 11.47287 

494300 4196600 11.79559 24-HR 4TH 0.25646 11.53913 11.79559 

494300 4196700 11.77902 24-HR 4TH 0.18388 11.59514 11.77902 

494300 4196800 11.96871 24-HR 4TH 0.13024 11.83846 11.96871 
Indiana Gasification, LLC Page 21 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494300 4196900 11.97394 24-HR 4TH 0.31623 11.65771 11.97394 

494400 4196400 11.38455 24-HR 4TH 0.15771 11.22684 11.38455 

494400 4196500 11.45313 24-HR 4TH 0.13014 11.32299 11.45313 

494400 4196600 11.77043 24-HR 4TH 0.23301 11.53742 11.77043 

494400 4196700 11.76351 24-HR 4TH 0.19559 11.56792 11.76351 

494400 4196800 11.91192 24-HR 4TH 0.16579 11.74613 11.91192 

494400 4196900 11.94932 24-HR 4TH 0.15527 11.79405 11.94932 

494400 4197000 12.09748 24-HR 4TH 0.22246 11.87502 12.09748 

494500 4196400 11.39801 24-HR 4TH 0.10376 11.29425 11.39801 

494500 4196500 11.31113 24-HR 4TH 0.05841 11.25272 11.31113 

494500 4196600 11.64559 24-HR 4TH 0.26624 11.37935 11.64559 

494500 4196700 11.6493 24-HR 4TH 0.2157 11.4336 11.6493 

494500 4196800 11.80521 24-HR 4TH 0.30376 11.50145 11.80521 

494500 4196900 11.87297 24-HR 4TH 0.22298 11.64998 11.87297 

494500 4197000 12.05947 24-HR 4TH 0.38792 11.67155 12.05947 

494600 4196400 11.45132 24-HR 4TH 0.14376 11.30756 11.45132 

494600 4196500 11.42298 24-HR 4TH 0.05979 11.36319 11.42298 

494600 4196600 11.59289 24-HR 4TH 0.18219 11.4107 11.59289 

494600 4196700 11.50347 24-HR 4TH 0.1844 11.31906 11.50347 

494600 4196800 11.73607 24-HR 4TH 0.3188 11.41727 11.73607 

494600 4196900 11.85941 24-HR 4TH 0.10078 11.75863 11.85941 

494600 4197000 11.99254 24-HR 4TH 0.24376 11.74878 11.99254 

494600 4197100 11.86579 24-HR 4TH 0.48526 11.38052 11.86579 

494700 4196500 11.5332 24-HR 4TH 0.31658 11.21661 11.5332 

494700 4196600 11.64623 24-HR 4TH 0.23168 11.41455 11.64623 

494700 4196700 11.59425 24-HR 4TH 0.08651 11.50774 11.59425 

494700 4196800 11.80148 24-HR 4TH 0.23156 11.56993 11.80148 

494700 4196900 11.83701 24-HR 4TH 0.15079 11.68622 11.83701 

494700 4197000 12.05373 24-HR 4TH 0.31906 11.73467 12.05373 

494700 4197100 11.95247 24-HR 4TH 0.34353 11.60894 11.95247 

494800 4196700 11.6856 24-HR 4TH 0.07525 11.61035 11.6856 

494800 4196800 12.08367 24-HR 4TH 0.31104 11.77263 12.08367 

494800 4197200 11.64281 24-HR 4TH 0.33681 11.306 11.64281 

494806 4196692.8 11.6785 24-HR 4TH 0.07026 11.60824 11.6785 

494806 4196791.2 12.11341 24-HR 4TH 0.24423 11.86918 12.11341 

494806 4197184.8 11.73643 24-HR 4TH 0.34283 11.3936 11.73643 

494968.8 4197480 11.07207 24-HR 4TH 0.23424 10.83783 11.07207 

495050.2 4197480 11.17667 24-HR 4TH 0.53954 10.63713 11.17667 

495100 4197500 11.246 24-HR 4TH 0.4045 10.8415 11.246 

495131.6 4197480 11.36659 24-HR 4TH 0.56813 10.79846 11.36659 

495200 4197600 11.43739 24-HR 4TH 0.38423 11.05317 11.43739 

495221.2 4197567.4 11.48812 24-HR 4TH 0.44889 11.03923 11.48812 

495221.3 4197656.9 11.38437 24-HR 4TH 0.32079 11.06358 11.38437 

495221.3 4197746.4 11.27551 24-HR 4TH 0.40708 10.86843 11.27551 

494100 4196500 11.43289 24-HR 4TH 0.19611 11.23678 11.43289 

495100 4197600 11.28655 24-HR 4TH 0.2884 10.99815 11.28655 

495200 4197500 11.5069 24-HR 4TH 0.62518 10.88172 11.5069 

495200 4197700 11.30136 24-HR 4TH 0.30033 11.00103 11.30136 

495213 4197480 11.54423 24-HR 4TH 0.62715 10.91708 11.54423 
Indiana Gasification, LLC Page 22 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

495221.2 4197478 11.55223 24-HR 4TH 0.6214 10.93083 11.55223 

494100 4196600 11.00226 24-HR 5TH 0.0778 10.92446 11.00226 

494200 4196400 10.61941 24-HR 5TH 0.20399 10.41542 10.61941 

494200 4196500 10.70599 24-HR 5TH 0.13713 10.56886 10.70599 

494200 4196600 11.04175 24-HR 5TH 0.08276 10.95899 11.04175 

494200 4196700 11.34827 24-HR 5TH 0.166 11.18227 11.34827 

494200 4196800 11.1347 24-HR 5TH 0.14832 10.98638 11.1347 

494300 4196400 10.72349 24-HR 5TH 0.10757 10.61591 10.72349 

494300 4196500 10.85526 24-HR 5TH 0.14119 10.71407 10.85526 

494300 4196600 11.04264 24-HR 5TH 0.07998 10.96265 11.04264 

494300 4196700 11.31622 24-HR 5TH 0.17946 11.13676 11.31622 

494300 4196800 11.14768 24-HR 5TH 0.16528 10.9824 11.14768 

494300 4196900 11.00503 24-HR 5TH 0.18203 10.823 11.00503 

494400 4196400 10.76863 24-HR 5TH 0.20086 10.56777 10.76863 

494400 4196500 10.99649 24-HR 5TH 0.11382 10.88267 10.99649 

494400 4196600 10.99472 24-HR 5TH 0.05462 10.9401 10.99472 

494400 4196700 11.30376 24-HR 5TH 0.20312 11.10064 11.30376 

494400 4196800 11.10934 24-HR 5TH 0.16777 10.94157 11.10934 

494400 4196900 10.99394 24-HR 5TH 0.18738 10.80656 10.99394 

494400 4197000 11.09134 24-HR 5TH 0.23419 10.85716 11.09134 

494500 4196400 10.68692 24-HR 5TH 0.23683 10.4501 10.68692 

494500 4196500 11.10713 24-HR 5TH 0.18035 10.92678 11.10713 

494500 4196600 11.10894 24-HR 5TH 0.05178 11.05716 11.10894 

494500 4196700 11.26602 24-HR 5TH 0.29132 10.9747 11.26602 

494500 4196800 11.11737 24-HR 5TH 0.19604 10.92134 11.11737 

494500 4196900 11.00747 24-HR 5TH 0.29857 10.7089 11.00747 

494500 4197000 11.03903 24-HR 5TH 0.13456 10.90447 11.03903 

494600 4196400 10.68009 24-HR 5TH 0.14657 10.53352 10.68009 

494600 4196500 11.06682 24-HR 5TH 0.109 10.95783 11.06682 

494600 4196600 11.13745 24-HR 5TH 0.10969 11.02776 11.13745 

494600 4196700 11.31948 24-HR 5TH 0.2512 11.06828 11.31948 

494600 4196800 11.16299 24-HR 5TH 0.25218 10.91081 11.16299 

494600 4196900 10.97449 24-HR 5TH 0.42393 10.55055 10.97449 

494600 4197000 10.98154 24-HR 5TH 0.23653 10.74501 10.98154 

494600 4197100 10.89352 24-HR 5TH 0.16978 10.72375 10.89352 

494700 4196500 11.03022 24-HR 5TH 0.08284 10.94737 11.03022 

494700 4196600 11.21783 24-HR 5TH 0.08888 11.12895 11.21783 

494700 4196700 11.40912 24-HR 5TH 0.28018 11.12893 11.40912 

494700 4196800 11.27083 24-HR 5TH 0.26479 11.00604 11.27083 

494700 4196900 11.16957 24-HR 5TH 0.29907 10.8705 11.16957 

494700 4197000 11.15088 24-HR 5TH 0.17969 10.97119 11.15088 

494700 4197100 10.98248 24-HR 5TH 0.18163 10.80084 10.98248 

494800 4196700 11.46297 24-HR 5TH 0.24151 11.22146 11.46297 

494800 4196800 11.3087 24-HR 5TH 0.28967 11.01902 11.3087 

494800 4197200 10.84332 24-HR 5TH 0.28375 10.55957 10.84332 

494806 4196692.8 11.47414 24-HR 5TH 0.23682 11.23733 11.47414 

494806 4196791.2 11.34511 24-HR 5TH 0.31352 11.03159 11.34511 

494806 4197184.8 10.91783 24-HR 5TH 0.29082 10.62701 10.91783 

494968.8 4197480 10.70951 24-HR 5TH 0.43641 10.2731 10.70951 
Indiana Gasification, LLC Page 23 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

495050.2 4197480 10.84379 24-HR 5TH 0.42402 10.41977 10.84379 

495100 4197500 10.73801 24-HR 5TH 0.55118 10.18683 10.73801 

495131.6 4197480 10.82144 24-HR 5TH 0.48621 10.33523 10.82144 

495200 4197600 10.50026 24-HR 5TH 0.49114 10.00912 10.50026 

495221.2 4197567.4 10.61319 24-HR 5TH 0.47434 10.13885 10.61319 

495221.3 4197656.9 10.54261 24-HR 5TH 0.45249 10.09011 10.54261 

495221.3 4197746.4 10.45707 24-HR 5TH 0.45024 10.00683 10.45707 

494100 4196500 10.59021 24-HR 5TH 0.11961 10.4706 10.59021 

495100 4197600 10.24728 24-HR 5TH 0.43484 9.81244 10.24728 

495200 4197500 10.91201 24-HR 5TH 0.40472 10.50728 10.91201 

495200 4197700 10.46275 24-HR 5TH 0.39993 10.06282 10.46275 

495213 4197480 10.98889 24-HR 5TH 0.4906 10.49829 10.98889 

495221.2 4197478 11.00357 24-HR 5TH 0.49073 10.51284 11.00357 

494100 4196600 10.43503 24-HR 6TH 0.17194 10.26308 10.43503 

494200 4196400 10.06684 24-HR 6TH 0.31327 9.75357 10.06684 

494200 4196500 10.325 24-HR 6TH 0.1839 10.14111 10.325 

494200 4196600 10.45199 24-HR 6TH 0.20418 10.24781 10.45199 

494200 4196700 10.61364 24-HR 6TH 0.20745 10.40619 10.61364 

494200 4196800 10.61749 24-HR 6TH 0.16142 10.45607 10.61749 

494300 4196400 9.92545 24-HR 6TH 0.37149 9.55396 9.92545 

494300 4196500 10.23881 24-HR 6TH 0.32435 9.91447 10.23881 

494300 4196600 10.40825 24-HR 6TH 0.24852 10.15973 10.40825 

494300 4196700 10.60858 24-HR 6TH 0.27114 10.33744 10.60858 

494300 4196800 10.6382 24-HR 6TH 0.19221 10.44599 10.6382 

494300 4196900 10.48275 24-HR 6TH 0.16232 10.32043 10.48275 

494400 4196400 9.81696 24-HR 6TH 0.14751 9.66944 9.81696 

494400 4196500 10.17807 24-HR 6TH 0.29791 9.88016 10.17807 

494400 4196600 10.48171 24-HR 6TH 0.23144 10.25026 10.48171 

494400 4196700 10.52178 24-HR 6TH 0.3175 10.20427 10.52178 

494400 4196800 10.63506 24-HR 6TH 0.34418 10.29088 10.63506 

494400 4196900 10.48673 24-HR 6TH 0.29572 10.19101 10.48673 

494400 4197000 10.49082 24-HR 6TH 0.26477 10.22605 10.49082 

494500 4196400 9.92146 24-HR 6TH 0.10712 9.81434 9.92146 

494500 4196500 10.17766 24-HR 6TH 0.2308 9.94687 10.17766 

494500 4196600 10.50669 24-HR 6TH 0.16017 10.34652 10.50669 

494500 4196700 10.58648 24-HR 6TH 0.16774 10.41874 10.58648 

494500 4196800 10.65598 24-HR 6TH 0.19797 10.45801 10.65598 

494500 4196900 10.54822 24-HR 6TH 0.09252 10.4557 10.54822 

494500 4197000 10.55933 24-HR 6TH 0.20902 10.35032 10.55933 

494600 4196400 9.7835 24-HR 6TH 0.1617 9.6218 9.7835 

494600 4196500 10.14394 24-HR 6TH 0.20256 9.94138 10.14394 

494600 4196600 10.63389 24-HR 6TH 0.17836 10.45553 10.63389 

494600 4196700 10.68026 24-HR 6TH 0.20703 10.47323 10.68026 

494600 4196800 10.75745 24-HR 6TH 0.30357 10.45387 10.75745 

494600 4196900 10.67112 24-HR 6TH 0.10751 10.56361 10.67112 

494600 4197000 10.65727 24-HR 6TH 0.22281 10.43446 10.65727 

494600 4197100 10.45308 24-HR 6TH 0.22392 10.22916 10.45308 

494700 4196500 10.0032 24-HR 6TH 0.0695 9.9337 10.0032 

494700 4196600 10.46156 24-HR 6TH 0.12521 10.33635 10.46156 
Indiana Gasification, LLC Page 24 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494700 4196700 10.61766 24-HR 6TH 0.21382 10.40384 10.61766 

494700 4196800 10.6995 24-HR 6TH 0.36281 10.33669 10.6995 

494700 4196900 10.53244 24-HR 6TH 0.22061 10.31183 10.53244 

494700 4197000 10.47529 24-HR 6TH 0.23441 10.24089 10.47529 

494700 4197100 10.35373 24-HR 6TH 0.36432 9.98941 10.35373 

494800 4196700 10.49609 24-HR 6TH 0.13601 10.36008 10.49609 

494800 4196800 10.55259 24-HR 6TH 0.32645 10.22614 10.55259 

494800 4197200 10.20984 24-HR 6TH 0.17165 10.03819 10.20984 

494806 4196692.8 10.4823 24-HR 6TH 0.1175 10.36479 10.4823 

494806 4196791.2 10.53585 24-HR 6TH 0.30948 10.22637 10.53585 

494806 4197184.8 10.20213 24-HR 6TH 0.18084 10.02128 10.20213 

494968.8 4197480 9.82878 24-HR 6TH 0.42642 9.40236 9.82878 

495050.2 4197480 9.94048 24-HR 6TH 0.60826 9.33222 9.94048 

495100 4197500 9.95025 24-HR 6TH 0.63496 9.31529 9.95025 

495131.6 4197480 9.99759 24-HR 6TH 0.68857 9.30902 9.99759 

495200 4197600 9.89595 24-HR 6TH 0.57901 9.31694 9.89595 

495221.2 4197567.4 10.01585 24-HR 6TH 0.67595 9.33991 10.01585 

495221.3 4197656.9 9.81034 24-HR 6TH 0.70121 9.10913 9.81034 

495221.3 4197746.4 9.88026 24-HR 6TH 0.33561 9.54465 9.88026 

494100 4196500 10.3738 24-HR 6TH 0.33337 10.04043 10.3738 

495100 4197600 9.80357 24-HR 6TH 0.41398 9.38959 9.80357 

495200 4197500 10.09163 24-HR 6TH 0.74265 9.34898 10.09163 

495200 4197700 9.83211 24-HR 6TH 0.5564 9.27571 9.83211 

495213 4197480 10.11688 24-HR 6TH 0.73464 9.38224 10.11688 

495221.2 4197478 10.11869 24-HR 6TH 0.72559 9.3931 10.11869 

494100 4196600 9.83479 24-HR 7TH 0.27835 9.55644 9.83479 

494200 4196400 9.79916 24-HR 7TH 0.30962 9.48953 9.79916 

494200 4196500 9.93565 24-HR 7TH 0.53839 9.39727 9.93565 

494200 4196600 9.88404 24-HR 7TH 0.14481 9.73923 9.88404 

494200 4196700 9.71365 24-HR 7TH 0.14203 9.57162 9.71365 

494200 4196800 9.92425 24-HR 7TH 0.28507 9.63918 9.92425 

494300 4196400 9.65346 24-HR 7TH 0.17264 9.48083 9.65346 

494300 4196500 9.95767 24-HR 7TH 0.29985 9.65782 9.95767 

494300 4196600 9.95148 24-HR 7TH 0.14852 9.80297 9.95148 

494300 4196700 9.87433 24-HR 7TH 0.11538 9.75895 9.87433 

494300 4196800 10.04267 24-HR 7TH 0.27245 9.77022 10.04267 

494300 4196900 10.02676 24-HR 7TH 0.3493 9.67746 10.02676 

494400 4196400 9.49775 24-HR 7TH 0.29337 9.20438 9.49775 

494400 4196500 9.88254 24-HR 7TH 0.28202 9.60052 9.88254 

494400 4196600 9.9725 24-HR 7TH 0.44727 9.52523 9.9725 

494400 4196700 10.0757 24-HR 7TH 0.11445 9.96124 10.0757 

494400 4196800 10.25759 24-HR 7TH 0.27242 9.98517 10.25759 

494400 4196900 10.14502 24-HR 7TH 0.22054 9.92448 10.14502 

494400 4197000 10.09082 24-HR 7TH 0.30443 9.78639 10.09082 

494500 4196400 9.44396 24-HR 7TH 0.17683 9.26713 9.44396 

494500 4196500 9.81471 24-HR 7TH 0.10196 9.71275 9.81471 

494500 4196600 9.87534 24-HR 7TH 0.31412 9.56122 9.87534 

494500 4196700 10.12714 24-HR 7TH 0.2566 9.87053 10.12714 

494500 4196800 10.3388 24-HR 7TH 0.39301 9.94579 10.3388 
Indiana Gasification, LLC Page 25 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494500 4196900 10.23015 24-HR 7TH 0.43665 9.7935 10.23015 

494500 4197000 10.099 24-HR 7TH 0.32265 9.77635 10.099 

494600 4196400 9.44932 24-HR 7TH 0.03723 9.4121 9.44932 

494600 4196500 9.79008 24-HR 7TH 0.05461 9.73547 9.79008 

494600 4196600 9.82503 24-HR 7TH 0.21305 9.61198 9.82503 

494600 4196700 10.13098 24-HR 7TH 0.39987 9.73111 10.13098 

494600 4196800 10.24888 24-HR 7TH 0.33174 9.91714 10.24888 

494600 4196900 10.14365 24-HR 7TH 0.45535 9.6883 10.14365 

494600 4197000 10.08972 24-HR 7TH 0.32098 9.76874 10.08972 

494600 4197100 10.02869 24-HR 7TH 0.2511 9.77759 10.02869 

494700 4196500 9.72484 24-HR 7TH 0.08603 9.63881 9.72484 

494700 4196600 9.8169 24-HR 7TH 0.14758 9.66933 9.8169 

494700 4196700 9.96981 24-HR 7TH 0.2742 9.69561 9.96981 

494700 4196800 9.99381 24-HR 7TH 0.415 9.57882 9.99381 

494700 4196900 10.09474 24-HR 7TH 0.40543 9.6893 10.09474 

494700 4197000 10.03234 24-HR 7TH 0.27475 9.75758 10.03234 

494700 4197100 9.96722 24-HR 7TH 0.24131 9.72591 9.96722 

494800 4196700 9.84648 24-HR 7TH 0.19832 9.64817 9.84648 

494800 4196800 9.8946 24-HR 7TH 0.23427 9.66032 9.8946 

494800 4197200 9.77508 24-HR 7TH 0.41337 9.36171 9.77508 

494806 4196692.8 9.79291 24-HR 7TH 0.17369 9.61922 9.79291 

494806 4196791.2 9.98754 24-HR 7TH 0.30117 9.68637 9.98754 

494806 4197184.8 9.76922 24-HR 7TH 0.42156 9.34766 9.76922 

494968.8 4197480 9.49304 24-HR 7TH 0.39142 9.10161 9.49304 

495050.2 4197480 9.60238 24-HR 7TH 0.37056 9.23181 9.60238 

495100 4197500 9.65555 24-HR 7TH 0.37233 9.28322 9.65555 

495131.6 4197480 9.73231 24-HR 7TH 0.44075 9.29155 9.73231 

495200 4197600 9.61915 24-HR 7TH 0.43354 9.18562 9.61915 

495221.2 4197567.4 9.70958 24-HR 7TH 0.39331 9.31628 9.70958 

495221.3 4197656.9 9.49476 24-HR 7TH 0.21256 9.28221 9.49476 

495221.3 4197746.4 9.279 24-HR 7TH 0.44856 8.83044 9.279 

494100 4196500 9.85909 24-HR 7TH 0.13344 9.72565 9.85909 

495100 4197600 9.49488 24-HR 7TH 0.38351 9.11137 9.49488 

495200 4197500 9.79168 24-HR 7TH 0.51256 9.27912 9.79168 

495200 4197700 9.29635 24-HR 7TH 0.23303 9.06332 9.29635 

495213 4197480 9.79573 24-HR 7TH 0.45006 9.34567 9.79573 

495221.2 4197478 9.79756 24-HR 7TH 0.45114 9.34643 9.79756 

494100 4196600 9.39381 24-HR 8TH 0.1562 9.23762 9.39381 

494200 4196400 9.25345 24-HR 8TH 0.2392 9.01425 9.25345 

494200 4196500 9.61968 24-HR 8TH 0.17891 9.44077 9.61968 

494200 4196600 9.5625 24-HR 8TH 0.40475 9.15775 9.5625 

494200 4196700 9.52076 24-HR 8TH 0.40246 9.1183 9.52076 

494200 4196800 9.5181 24-HR 8TH 0.35052 9.16757 9.5181 

494300 4196400 9.34767 24-HR 8TH 0.26036 9.08732 9.34767 

494300 4196500 9.58448 24-HR 8TH 0.26322 9.32126 9.58448 

494300 4196600 9.66669 24-HR 8TH 0.40763 9.25906 9.66669 

494300 4196700 9.52297 24-HR 8TH 0.16933 9.35365 9.52297 

494300 4196800 9.6653 24-HR 8TH 0.38848 9.27681 9.6653 

494300 4196900 9.75128 24-HR 8TH 0.27479 9.47649 9.75128 
Indiana Gasification, LLC Page 26 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494400 4196400 9.33795 24-HR 8TH 0.26623 9.07171 9.33795 

494400 4196500 9.50232 24-HR 8TH 0.20175 9.30058 9.50232 

494400 4196600 9.66308 24-HR 8TH 0.16938 9.4937 9.66308 

494400 4196700 9.51898 24-HR 8TH 0.31489 9.20409 9.51898 

494400 4196800 9.67081 24-HR 8TH 0.35128 9.31953 9.67081 

494400 4196900 9.90889 24-HR 8TH 0.35901 9.54989 9.90889 

494400 4197000 9.59134 24-HR 8TH 0.4904 9.10094 9.59134 

494500 4196400 9.28688 24-HR 8TH 0.11837 9.16851 9.28688 

494500 4196500 9.52061 24-HR 8TH 0.20885 9.31177 9.52061 

494500 4196600 9.64716 24-HR 8TH 0.39633 9.25083 9.64716 

494500 4196700 9.59351 24-HR 8TH 0.50124 9.09227 9.59351 

494500 4196800 9.64239 24-HR 8TH 0.53211 9.11028 9.64239 

494500 4196900 9.90753 24-HR 8TH 0.34052 9.56701 9.90753 

494500 4197000 9.71942 24-HR 8TH 0.63452 9.0849 9.71942 

494600 4196400 9.21758 24-HR 8TH 0.1302 9.08738 9.21758 

494600 4196500 9.28379 24-HR 8TH 0.23446 9.04933 9.28379 

494600 4196600 9.44796 24-HR 8TH 0.38186 9.0661 9.44796 

494600 4196700 9.54581 24-HR 8TH 0.36576 9.18004 9.54581 

494600 4196800 9.61937 24-HR 8TH 0.55847 9.0609 9.61937 

494600 4196900 9.85634 24-HR 8TH 0.32562 9.53072 9.85634 

494600 4197000 9.69151 24-HR 8TH 0.51704 9.17448 9.69151 

494600 4197100 9.66401 24-HR 8TH 0.6277 9.03631 9.66401 

494700 4196500 9.22139 24-HR 8TH 0.12701 9.09438 9.22139 

494700 4196600 9.18356 24-HR 8TH 0.25011 8.93344 9.18356 

494700 4196700 9.43439 24-HR 8TH 0.28332 9.15107 9.43439 

494700 4196800 9.56668 24-HR 8TH 0.22798 9.3387 9.56668 

494700 4196900 9.73457 24-HR 8TH 0.33582 9.39874 9.73457 

494700 4197000 9.57887 24-HR 8TH 0.53692 9.04195 9.57887 

494700 4197100 9.56524 24-HR 8TH 0.53745 9.02778 9.56524 

494800 4196700 9.28995 24-HR 8TH 0.26688 9.02306 9.28995 

494800 4196800 9.4667 24-HR 8TH 0.26154 9.20516 9.4667 

494800 4197200 9.41162 24-HR 8TH 0.34795 9.06366 9.41162 

494806 4196692.8 9.27293 24-HR 8TH 0.2633 9.00963 9.27293 

494806 4196791.2 9.4873 24-HR 8TH 0.39924 9.08806 9.4873 

494806 4197184.8 9.41205 24-HR 8TH 0.34758 9.06447 9.41205 

494968.8 4197480 9.1192 24-HR 8TH 0.21292 8.90628 9.1192 

495050.2 4197480 9.17914 24-HR 8TH 0.53515 8.644 9.17914 

495100 4197500 9.23284 24-HR 8TH 0.65732 8.57552 9.23284 

495131.6 4197480 9.37836 24-HR 8TH 0.64061 8.73774 9.37836 

495200 4197600 9.18494 24-HR 8TH 0.59846 8.58648 9.18494 

495221.2 4197567.4 9.21643 24-HR 8TH 0.64881 8.56763 9.21643 

495221.3 4197656.9 9.17158 24-HR 8TH 0.50069 8.67088 9.17158 

495221.3 4197746.4 9.02184 24-HR 8TH 0.29306 8.72878 9.02184 

494100 4196500 9.46595 24-HR 8TH 0.38602 9.07993 9.46595 

495100 4197600 8.9731 24-HR 8TH 0 0 0 

495200 4197500 9.35293 24-HR 8TH 0.73494 8.61799 9.35293 

495200 4197700 9.04817 24-HR 8TH 0.36276 8.68541 9.04817 

495213 4197480 9.46262 24-HR 8TH 0.73651 8.72611 9.46262 

495221.2 4197478 9.48093 24-HR 8TH 0.68023 8.8007 9.48093 
Indiana Gasification, LLC Page 27 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494100 4196600 9.06823 24-HR 9TH 0.28369 8.78454 9.06823 

494200 4196400 9.12416 24-HR 9TH 0.10535 9.01881 9.12416 

494200 4196500 9.06315 24-HR 9TH 0.14764 8.91551 9.06315 

494200 4196600 9.23736 24-HR 9TH 0.2653 8.97206 9.23736 

494200 4196700 9.24582 24-HR 9TH 0.28375 8.96207 9.24582 

494200 4196800 9.27318 24-HR 9TH 0.17697 9.09621 9.27318 

494300 4196400 9.12592 24-HR 9TH 0.10517 9.02075 9.12592 

494300 4196500 9.13533 24-HR 9TH 0.10079 9.03454 9.13533 

494300 4196600 9.37315 24-HR 9TH 0.33367 9.03948 9.37315 

494300 4196700 9.27595 24-HR 9TH 0.60147 8.67448 9.27595 

494300 4196800 9.31188 24-HR 9TH 0.26505 9.04682 9.31188 

494300 4196900 9.24515 24-HR 9TH 0.42325 8.8219 9.24515 

494400 4196400 9.10449 24-HR 9TH 0.05188 9.05261 9.10449 

494400 4196500 9.20361 24-HR 9TH 0.13171 9.07189 9.20361 

494400 4196600 9.39488 24-HR 9TH 0.34115 9.05373 9.39488 

494400 4196700 9.35251 24-HR 9TH 0.52469 8.82782 9.35251 

494400 4196800 9.354 24-HR 9TH 0.44493 8.90907 9.354 

494400 4196900 9.26571 24-HR 9TH 0.46215 8.80356 9.26571 

494400 4197000 9.10257 24-HR 9TH 0.53214 8.57042 9.10257 

494500 4196400 8.99521 24-HR 9TH 0 0 0 

494500 4196500 9.03538 24-HR 9TH 0.23015 8.80524 9.03538 

494500 4196600 9.28678 24-HR 9TH 0.14797 9.13881 9.28678 

494500 4196700 9.32474 24-HR 9TH 0.36596 8.95878 9.32474 

494500 4196800 9.39251 24-HR 9TH 0.22737 9.16514 9.39251 

494500 4196900 9.26238 24-HR 9TH 0.47765 8.78473 9.26238 

494500 4197000 9.16267 24-HR 9TH 0.556 8.60667 9.16267 

494600 4196400 9.02271 24-HR 9TH 0.22093 8.80178 9.02271 

494600 4196500 8.94489 24-HR 9TH 0 0 0 

494600 4196600 9.12104 24-HR 9TH 0.11005 9.01099 9.12104 

494600 4196700 9.26174 24-HR 9TH 0.18277 9.07897 9.26174 

494600 4196800 9.35386 24-HR 9TH 0.21138 9.14248 9.35386 

494600 4196900 9.24196 24-HR 9TH 0.5462 8.69576 9.24196 

494600 4197000 9.15994 24-HR 9TH 0.73263 8.42731 9.15994 

494600 4197100 9.03102 24-HR 9TH 0.44415 8.58687 9.03102 

494700 4196500 8.85425 24-HR 9TH 0 0 0 

494700 4196600 8.96874 24-HR 9TH 0 0 0 

494700 4196700 9.05443 24-HR 9TH 0.3524 8.70203 9.05443 

494700 4196800 9.41018 24-HR 9TH 0.42242 8.98775 9.41018 

494700 4196900 9.1703 24-HR 9TH 0.51039 8.6599 9.1703 

494700 4197000 9.11981 24-HR 9TH 0.52214 8.59766 9.11981 

494700 4197100 9.05359 24-HR 9TH 0.54077 8.51282 9.05359 

494800 4196700 8.98918 24-HR 9TH 0 0 0 

494800 4196800 9.38112 24-HR 9TH 0.39785 8.98328 9.38112 

494800 4197200 9.16899 24-HR 9TH 0.47719 8.6918 9.16899 

494806 4196692.8 8.97381 24-HR 9TH 0 0 0 

494806 4196791.2 9.36007 24-HR 9TH 0.29974 9.06032 9.36007 

494806 4197184.8 9.14956 24-HR 9TH 0.42512 8.72444 9.14956 

494968.8 4197480 8.89985 24-HR 9TH 0 0 0 

495050.2 4197480 8.98251 24-HR 9TH 0 0 0 
Indiana Gasification, LLC Page 28 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

495100 4197500 8.89358 24-HR 9TH 0 0 0 

495131.6 4197480 8.96444 24-HR 9TH 0 0 0 

495200 4197600 8.86424 24-HR 9TH 0 0 0 

495221.2 4197567.4 8.88013 24-HR 9TH 0 0 0 

495221.3 4197656.9 8.90986 24-HR 9TH 0 0 0 

495221.3 4197746.4 8.94973 24-HR 9TH 0 0 0 

494100 4196500 9.06815 24-HR 9TH 0.11546 8.95269 9.06815 

495100 4197600 8.81395 24-HR 9TH 0 0 0 

495200 4197500 8.98716 24-HR 9TH 0 0 0 

495200 4197700 8.91279 24-HR 9TH 0 0 0 

495213 4197480 9.07066 24-HR 9TH 0.53122 8.53944 9.07066 

495221.2 4197478 9.08735 24-HR 9TH 0.59984 8.48751 9.08735 

494100 4196600 8.95659 24-HR 10TH 0 0 0 

494200 4196400 8.83141 24-HR 10TH 0 0 0 

494200 4196500 8.79282 24-HR 10TH 0 0 0 

494200 4196600 8.87061 24-HR 10TH 0 0 0 

494200 4196700 8.93739 24-HR 10TH 0 0 0 

494200 4196800 8.88375 24-HR 10TH 0 0 0 

494300 4196400 8.8421 24-HR 10TH 0 0 0 

494300 4196500 8.85875 24-HR 10TH 0 0 0 

494300 4196600 8.86142 24-HR 10TH 0 0 0 

494300 4196700 9.12429 24-HR 10TH 0.38522 8.73907 9.12429 

494300 4196800 8.72706 24-HR 10TH 0 0 0 

494300 4196900 8.80363 24-HR 10TH 0 0 0 

494400 4196400 8.94305 24-HR 10TH 0 0 0 

494400 4196500 8.96759 24-HR 10TH 0 0 0 

494400 4196600 8.92346 24-HR 10TH 0 0 0 

494400 4196700 9.14497 24-HR 10TH 0.46304 8.68193 9.14497 

494400 4196800 8.75819 24-HR 10TH 0 0 0 

494400 4196900 8.7838 24-HR 10TH 0 0 0 

494400 4197000 8.82504 24-HR 10TH 0 0 0 

494500 4196400 8.91349 24-HR 10TH 0 0 0 

494500 4196500 8.91191 24-HR 10TH 0 0 0 

494500 4196600 9.00773 24-HR 10TH 0.53182 8.47591 9.00773 

494500 4196700 9.12407 24-HR 10TH 0.49679 8.62728 9.12407 

494500 4196800 8.97004 24-HR 10TH 0 0 0 

494500 4196900 8.8204 24-HR 10TH 0 0 0 

494500 4197000 8.7503 24-HR 10TH 0 0 0 

494600 4196400 8.81745 24-HR 10TH 0 0 0 

494600 4196500 8.81021 24-HR 10TH 0 0 0 

494600 4196600 8.94622 24-HR 10TH 0 0 0 

494600 4196700 8.96808 24-HR 10TH 0 0 0 

494600 4196800 9.14564 24-HR 10TH 0.38337 8.76227 9.14564 

494600 4196900 8.86308 24-HR 10TH 0 0 0 

494600 4197000 8.81715 24-HR 10TH 0 0 0 

494600 4197100 8.83069 24-HR 10TH 0 0 0 

494700 4196500 8.67215 24-HR 10TH 0 0 0 

494700 4196600 8.7352 24-HR 10TH 0 0 0 

494700 4196700 8.84716 24-HR 10TH 0 0 0 
Indiana Gasification, LLC Page 29 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494700 4196800 9.15604 24-HR 10TH 0.34038 8.81566 9.15604 

494700 4196900 8.96071 24-HR 10TH 0 0 0 

494700 4197000 8.969 24-HR 10TH 0 0 0 

494700 4197100 8.90759 24-HR 10TH 0 0 0 

494800 4196700 8.7653 24-HR 10TH 0 0 0 

494800 4196800 9.19998 24-HR 10TH 0.23359 8.96639 9.19998 

494800 4197200 8.86378 24-HR 10TH 0 0 0 

494806 4196692.8 8.74318 24-HR 10TH 0 0 0 

494806 4196791.2 9.21306 24-HR 10TH 0.23581 8.97725 9.21306 

494806 4197184.8 8.88152 24-HR 10TH 0 0 0 

494968.8 4197480 8.49226 24-HR 10TH 0 0 0 

495050.2 4197480 8.74213 24-HR 10TH 0 0 0 

495100 4197500 8.81201 24-HR 10TH 0 0 0 

495131.6 4197480 8.85392 24-HR 10TH 0 0 0 

495200 4197600 8.49797 24-HR 10TH 0 0 0 

495221.2 4197567.4 8.56186 24-HR 10TH 0 0 0 

495221.3 4197656.9 8.61056 24-HR 10TH 0 0 0 

495221.3 4197746.4 8.71244 24-HR 10TH 0 0 0 

494100 4196500 8.76839 24-HR 10TH 0 0 0 

495100 4197600 8.50646 24-HR 10TH 0 0 0 

495200 4197500 8.82096 24-HR 10TH 0 0 0 

495200 4197700 8.64734 24-HR 10TH 0 0 0 

495213 4197480 8.84547 24-HR 10TH 0 0 0 

495221.2 4197478 8.84295 24-HR 10TH 0 0 0 

494100 4196600 8.68247 24-HR 11TH 0 0 0 

494200 4196400 8.5876 24-HR 11TH 0 0 0 

494200 4196500 8.53339 24-HR 11TH 0 0 0 

494200 4196600 8.65405 24-HR 11TH 0 0 0 

494200 4196700 8.73114 24-HR 11TH 0 0 0 

494200 4196800 8.43103 24-HR 11TH 0 0 0 

494300 4196400 8.68735 24-HR 11TH 0 0 0 

494300 4196500 8.63294 24-HR 11TH 0 0 0 

494300 4196600 8.63173 24-HR 11TH 0 0 0 

494300 4196700 8.66909 24-HR 11TH 0 0 0 

494300 4196800 8.56297 24-HR 11TH 0 0 0 

494300 4196900 8.35785 24-HR 11TH 0 0 0 

494400 4196400 8.77248 24-HR 11TH 0 0 0 

494400 4196500 8.63087 24-HR 11TH 0 0 0 

494400 4196600 8.62677 24-HR 11TH 0 0 0 

494400 4196700 8.77211 24-HR 11TH 0 0 0 

494400 4196800 8.60351 24-HR 11TH 0 0 0 

494400 4196900 8.36615 24-HR 11TH 0 0 0 

494400 4197000 8.32575 24-HR 11TH 0 0 0 

494500 4196400 8.72982 24-HR 11TH 0 0 0 

494500 4196500 8.61256 24-HR 11TH 0 0 0 

494500 4196600 8.58054 24-HR 11TH 0 0 0 

494500 4196700 8.82497 24-HR 11TH 0 0 0 

494500 4196800 8.67081 24-HR 11TH 0 0 0 

494500 4196900 8.53083 24-HR 11TH 0 0 0 
Indiana Gasification, LLC Page 30 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494500 4197000 8.3906 24-HR 11TH 0 0 0 

494600 4196400 8.59205 24-HR 11TH 0 0 0 

494600 4196500 8.55753 24-HR 11TH 0 0 0 

494600 4196600 8.49837 24-HR 11TH 0 0 0 

494600 4196700 8.79884 24-HR 11TH 0 0 0 

494600 4196800 8.76826 24-HR 11TH 0 0 0 

494600 4196900 8.73046 24-HR 11TH 0 0 0 

494600 4197000 8.48347 24-HR 11TH 0 0 0 

494600 4197100 8.19354 24-HR 11TH 0 0 0 

494700 4196500 8.42209 24-HR 11TH 0 0 0 

494700 4196600 8.53855 24-HR 11TH 0 0 0 

494700 4196700 8.77972 24-HR 11TH 0 0 0 

494700 4196800 8.77768 24-HR 11TH 0 0 0 

494700 4196900 8.82973 24-HR 11TH 0 0 0 

494700 4197000 8.54035 24-HR 11TH 0 0 0 

494700 4197100 8.35616 24-HR 11TH 0 0 0 

494800 4196700 8.66805 24-HR 11TH 0 0 0 

494800 4196800 8.71927 24-HR 11TH 0 0 0 

494800 4197200 8.43635 24-HR 11TH 0 0 0 

494806 4196692.8 8.60879 24-HR 11TH 0 0 0 

494806 4196791.2 8.73077 24-HR 11TH 0 0 0 

494806 4197184.8 8.46037 24-HR 11TH 0 0 0 

494968.8 4197480 8.2696 24-HR 11TH 0 0 0 

495050.2 4197480 8.41126 24-HR 11TH 0 0 0 

495100 4197500 8.52319 24-HR 11TH 0 0 0 

495131.6 4197480 8.53939 24-HR 11TH 0 0 0 

495200 4197600 8.40723 24-HR 11TH 0 0 0 

495221.2 4197567.4 8.53014 24-HR 11TH 0 0 0 

495221.3 4197656.9 8.38121 24-HR 11TH 0 0 0 

495221.3 4197746.4 8.39214 24-HR 11TH 0 0 0 

494100 4196500 8.53923 24-HR 11TH 0 0 0 

495100 4197600 8.38985 24-HR 11TH 0 0 0 

495200 4197500 8.56897 24-HR 11TH 0 0 0 

495200 4197700 8.41832 24-HR 11TH 0 0 0 

495213 4197480 8.60096 24-HR 11TH 0 0 0 

495221.2 4197478 8.6079 24-HR 11TH 0 0 0 

24-Hour PM2.5 Culpability Analysis For Train Delivery

X Y 

AVERAGE 

CONC AVE RANK 

IG 

TRAIN INVENTORY 

IG TRAIN + 

INVENTORY 

494100 4196600 16.33261 24-HR 1ST 0.21549 16.11712 16.33261 

494200 4196400 17.27766 24-HR 1ST 0.277 17.00065 17.27766 
Indiana Gasification, LLC Page 31 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494200 4196500 16.99907 24-HR 1ST 0.26442 16.73465 16.99907 

494200 4196600 16.54672 24-HR 1ST 0.22906 16.31766 16.54672 

494200 4196700 16.17611 24-HR 1ST 0.21943 15.95668 16.17611 

494200 4196800 15.75548 24-HR 1ST 0.32094 15.43454 15.75548 

494300 4196400 17.53092 24-HR 1ST 0.28777 17.24315 17.53092 

494300 4196500 17.21985 24-HR 1ST 0.30422 16.91563 17.21985 

494300 4196600 16.69266 24-HR 1ST 0.29219 16.40047 16.69266 

494300 4196700 16.32092 24-HR 1ST 0.24689 16.07404 16.32092 

494300 4196800 16.00175 24-HR 1ST 0.3338 15.66795 16.00175 

494300 4196900 16.02487 24-HR 1ST 0.39359 15.63128 16.02487 

494400 4196400 17.68864 24-HR 1ST 0.26036 17.42828 17.68864 

494400 4196500 17.41434 24-HR 1ST 0.32555 17.08879 17.41434 

494400 4196600 16.90866 24-HR 1ST 0.33991 16.56875 16.90866 

494400 4196700 16.46276 24-HR 1ST 0.27016 16.19261 16.46276 

494400 4196800 16.18832 24-HR 1ST 0.34729 15.84103 16.18832 

494400 4196900 16.10506 24-HR 1ST 0.3886 15.71647 16.10506 

494400 4197000 16.26767 24-HR 1ST 0.419 15.84867 16.26767 

494500 4196400 17.75829 24-HR 1ST 0.19683 17.56146 17.75829 

494500 4196500 17.51493 24-HR 1ST 0.29409 17.22084 17.51493 

494500 4196600 17.08197 24-HR 1ST 0.37226 16.70971 17.08197 

494500 4196700 16.55675 24-HR 1ST 0.29435 16.26239 16.55675 

494500 4196800 16.34646 24-HR 1ST 0.37506 15.97139 16.34646 

494500 4196900 16.18052 24-HR 1ST 0.37878 15.80174 16.18052 

494500 4197000 16.3069 24-HR 1ST 0.41742 15.88947 16.3069 

494600 4196400 17.82006 24-HR 1ST 0.14493 17.67514 17.82006 Max IG Train + Inventory 

494600 4196500 17.56423 24-HR 1ST 0.21785 17.34639 17.56423 

494600 4196600 17.17759 24-HR 1ST 0.32071 16.85689 17.17759 

494600 4196700 16.65675 24-HR 1ST 0.35776 16.29899 16.65675 

494600 4196800 16.48716 24-HR 1ST 0.40745 16.07971 16.48716 

494600 4196900 16.28187 24-HR 1ST 0.36557 15.9163 16.28187 

494600 4197000 16.29006 24-HR 1ST 0.39158 15.89848 16.29006 

494600 4197100 16.4561 24-HR 1ST 0.39009 16.06602 16.4561 

494700 4196500 17.64363 24-HR 1ST 0.15105 17.49257 17.64363 

494700 4196600 17.25821 24-HR 1ST 0.22877 17.02943 17.25821 

494700 4196700 16.72862 24-HR 1ST 0.2939 16.43472 16.72862 

494700 4196800 16.59493 24-HR 1ST 0.47718 16.11775 16.59493 

494700 4196900 16.35982 24-HR 1ST 0.34988 16.00994 16.35982 
Indiana Gasification, LLC Page 32 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494700 4197000 16.2366 24-HR 1ST 0.37267 15.86393 16.2366 

494700 4197100 16.45046 24-HR 1ST 0.38607 16.06439 16.45046 

494800 4196700 16.79465 24-HR 1ST 0.3319 16.46276 16.79465 

494800 4196800 16.72717 24-HR 1ST 0.44886 16.27831 16.72717 

494800 4197200 16.72129 24-HR 1ST 0.35095 16.37034 16.72129 

494806 4196693 16.83988 24-HR 1ST 0.20804 16.63184 16.83988 

494806 4196791 16.78609 24-HR 1ST 0.47734 16.30875 16.78609 

494806 4197185 16.68703 24-HR 1ST 0.35566 16.33137 16.68703 

494968.8 4197480 17.23148 24-HR 1ST 0.39692 16.83457 17.23148 

495050.2 4197480 17.40342 24-HR 1ST 0.57037 16.83305 17.40342 

495100 4197500 17.49382 24-HR 1ST 0.63128 16.86254 17.49382 

495131.6 4197480 17.48743 24-HR 1ST 0.6437 16.84373 17.48743 

495200 4197600 17.53944 24-HR 1ST 0.56766 16.97178 17.53944 

495221.2 4197567 17.52014 24-HR 1ST 0.57483 16.94532 17.52014 

495221.3 4197657 17.50817 24-HR 1ST 0.51076 16.99742 17.50817 

495221.3 4197746 17.41529 24-HR 1ST 0.47609 16.9392 17.41529 

494100 4196500 16.77294 24-HR 1ST 0.28025 16.49269 16.77294 

495100 4197600 17.50253 24-HR 1ST 0.55122 16.95131 17.50253 

495200 4197500 17.52778 24-HR 1ST 0.57191 16.95587 17.52778 

495200 4197700 17.4577 24-HR 1ST 0.47342 16.98427 17.4577 

495213 4197480 17.53493 24-HR 1ST 0.58148 16.95345 17.53493 

495221.2 4197478 17.54035 24-HR 1ST 0.58222 16.95814 17.54035 

494100 4196600 14.30483 24-HR 2ND 0.24343 14.0614 14.30483 

494200 4196400 14.31453 24-HR 2ND 0.1973 14.11723 14.31453 

494200 4196500 14.42621 24-HR 2ND 0.2091 14.21711 14.42621 

494200 4196600 14.45331 24-HR 2ND 0.24316 14.21015 14.45331 

494200 4196700 14.05961 24-HR 2ND 0.35124 13.70837 14.05961 

494200 4196800 13.9728 24-HR 2ND 0.33025 13.64255 13.9728 

494300 4196400 14.34251 24-HR 2ND 0.19013 14.15238 14.34251 

494300 4196500 14.50024 24-HR 2ND 0.22148 14.27875 14.50024 

494300 4196600 14.579 24-HR 2ND 0.2331 14.3459 14.579 

494300 4196700 14.11703 24-HR 2ND 0.28569 13.83135 14.11703 

494300 4196800 13.93663 24-HR 2ND 0.34143 13.5952 13.93663 

494300 4196900 13.36727 24-HR 2ND 0.36659 13.00069 13.36727 

494400 4196400 14.22759 24-HR 2ND 0.16677 14.06082 14.22759 

494400 4196500 14.39992 24-HR 2ND 0.23192 14.168 14.39992 

494400 4196600 14.47843 24-HR 2ND 0.24766 14.23077 14.47843 
Indiana Gasification, LLC Page 33 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494400 4196700 14.08253 24-HR 2ND 0.38844 13.69409 14.08253 

494400 4196800 13.79599 24-HR 2ND 0.27404 13.52195 13.79599 

494400 4196900 13.29593 24-HR 2ND 0.33855 12.95738 13.29593 

494400 4197000 12.63647 24-HR 2ND 0.39274 12.24373 12.63647 

494500 4196400 14.116 24-HR 2ND 0.1448 13.9712 14.116 

494500 4196500 14.30055 24-HR 2ND 0.23778 14.06278 14.30055 

494500 4196600 14.40197 24-HR 2ND 0.30475 14.09722 14.40197 

494500 4196700 14.13718 24-HR 2ND 0.50079 13.63639 14.13718 

494500 4196800 13.73617 24-HR 2ND 0.35485 13.38132 13.73617 

494500 4196900 13.18956 24-HR 2ND 0.38518 12.80439 13.18956 

494500 4197000 12.6274 24-HR 2ND 0.47893 12.14847 12.6274 

494600 4196400 14.06503 24-HR 2ND 0.13063 13.9344 14.06503 

494600 4196500 14.20937 24-HR 2ND 0.19792 14.01145 14.20937 

494600 4196600 14.30539 24-HR 2ND 0.25667 14.04872 14.30539 

494600 4196700 14.1496 24-HR 2ND 0.42481 13.72479 14.1496 

494600 4196800 13.80948 24-HR 2ND 0.39998 13.4095 13.80948 

494600 4196900 13.2103 24-HR 2ND 0.34152 12.86878 13.2103 

494600 4197000 12.71921 24-HR 2ND 0.34042 12.37879 12.71921 

494600 4197100 12.86847 24-HR 2ND 0.3566 12.51187 12.86847 

494700 4196500 14.13135 24-HR 2ND 0.17744 13.95391 14.13135 

494700 4196600 14.19066 24-HR 2ND 0.19737 13.99329 14.19066 

494700 4196700 14.07767 24-HR 2ND 0.37328 13.70439 14.07767 

494700 4196800 13.84474 24-HR 2ND 0.40013 13.44461 13.84474 

494700 4196900 13.25358 24-HR 2ND 0.34536 12.90823 13.25358 

494700 4197000 12.83966 24-HR 2ND 0.31118 12.52847 12.83966 

494700 4197100 12.91191 24-HR 2ND 0.30477 12.60715 12.91191 

494800 4196700 13.98693 24-HR 2ND 0.21652 13.77041 13.98693 

494800 4196800 13.73895 24-HR 2ND 0.29238 13.44657 13.73895 

494800 4197200 12.98592 24-HR 2ND 0.29742 12.6885 12.98592 

494806 4196693 13.99177 24-HR 2ND 0.18749 13.80429 13.99177 

494806 4196791 13.7814 24-HR 2ND 0.30219 13.47921 13.7814 

494806 4197185 12.98673 24-HR 2ND 0.30596 12.68077 12.98673 

494968.8 4197480 13.43098 24-HR 2ND 0.24711 13.18386 13.43098 

495050.2 4197480 13.66171 24-HR 2ND 0.3879 13.27381 13.66171 

495100 4197500 13.77471 24-HR 2ND 0.45046 13.32425 13.77471 

495131.6 4197480 13.72663 24-HR 2ND 0.44186 13.28477 13.72663 

495200 4197600 13.83784 24-HR 2ND 0.39339 13.44444 13.83784 
Indiana Gasification, LLC Page 34 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

495221.2 4197567 13.83893 24-HR 2ND 0.39191 13.44703 13.83893 

495221.3 4197657 13.8145 24-HR 2ND 0.39712 13.41738 13.8145 

495221.3 4197746 13.62726 24-HR 2ND 0.43403 13.19323 13.62726 

494100 4196500 14.35686 24-HR 2ND 0.19856 14.1583 14.35686 

495100 4197600 13.85808 24-HR 2ND 0.44077 13.41731 13.85808 

495200 4197500 13.76845 24-HR 2ND 0.49589 13.27257 13.76845 

495200 4197700 13.74859 24-HR 2ND 0.44349 13.3051 13.74859 

495213 4197480 13.71808 24-HR 2ND 0.50027 13.21781 13.71808 

495221.2 4197478 13.70809 24-HR 2ND 0.49993 13.20816 13.70809 

494100 4196600 12.19527 24-HR 3RD 0.29909 11.89618 12.19527 

494200 4196400 12.08965 24-HR 3RD 0.34516 11.74448 12.08965 

494200 4196500 12.23476 24-HR 3RD 0.36595 11.86881 12.23476 

494200 4196600 12.34003 24-HR 3RD 0.42048 11.91955 12.34003 

494200 4196700 12.68373 24-HR 3RD 0.33787 12.34587 12.68373 

494200 4196800 12.59656 24-HR 3RD 0.26627 12.33029 12.59656 

494300 4196400 12.03741 24-HR 3RD 0.33416 11.70326 12.03741 

494300 4196500 12.22701 24-HR 3RD 0.38899 11.83802 12.22701 

494300 4196600 12.41977 24-HR 3RD 0.47189 11.94787 12.41977 

494300 4196700 12.84515 24-HR 3RD 0.46595 12.3792 12.84515 

494300 4196800 12.57421 24-HR 3RD 0.36466 12.20955 12.57421 

494300 4196900 12.56765 24-HR 3RD 0.21344 12.35421 12.56765 

494400 4196400 11.92496 24-HR 3RD 0.30188 11.62308 11.92496 

494400 4196500 12.13147 24-HR 3RD 0.43406 11.69741 12.13147 

494400 4196600 12.46563 24-HR 3RD 0.54485 11.92078 12.46563 

494400 4196700 12.94965 24-HR 3RD 0.46995 12.4797 12.94965 

494400 4196800 12.63124 24-HR 3RD 0.43594 12.1953 12.63124 

494400 4196900 12.53058 24-HR 3RD 0.42873 12.10185 12.53058 

494400 4197000 12.45845 24-HR 3RD 0.40244 12.05601 12.45845 

494500 4196400 11.83711 24-HR 3RD 0.28014 11.55697 11.83711 

494500 4196500 11.97349 24-HR 3RD 0.39823 11.57526 11.97349 

494500 4196600 12.35728 24-HR 3RD 0.426 11.93129 12.35728 

494500 4196700 12.93815 24-HR 3RD 0.39232 12.54582 12.93815 

494500 4196800 12.68685 24-HR 3RD 0.36499 12.32186 12.68685 

494500 4196900 12.58725 24-HR 3RD 0.30905 12.27821 12.58725 

494500 4197000 12.49013 24-HR 3RD 0.27265 12.21748 12.49013 

494600 4196400 11.80741 24-HR 3RD 0.21789 11.58952 11.80741 

494600 4196500 11.84674 24-HR 3RD 0.38574 11.461 11.84674 
Indiana Gasification, LLC Page 35 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494600 4196600 12.23772 24-HR 3RD 0.34821 11.8895 12.23772 

494600 4196700 12.85001 24-HR 3RD 0.36485 12.48516 12.85001 

494600 4196800 12.6896 24-HR 3RD 0.39721 12.2924 12.6896 

494600 4196900 12.5732 24-HR 3RD 0.35595 12.21724 12.5732 

494600 4197000 12.54832 24-HR 3RD 0.42535 12.12297 12.54832 

494600 4197100 12.25398 24-HR 3RD 0.44396 11.81002 12.25398 

494700 4196500 11.98439 24-HR 3RD 0.12934 11.85504 11.98439 

494700 4196600 12.34412 24-HR 3RD 0.25103 12.09309 12.34412 

494700 4196700 12.8582 24-HR 3RD 0.21858 12.63962 12.8582 

494700 4196800 12.73726 24-HR 3RD 0.2668 12.47046 12.73726 

494700 4196900 12.62239 24-HR 3RD 0.30735 12.31505 12.62239 

494700 4197000 12.57001 24-HR 3RD 0.31953 12.25048 12.57001 

494700 4197100 12.36263 24-HR 3RD 0.45771 11.90491 12.36263 

494800 4196700 13.05741 24-HR 3RD 0.15047 12.90695 13.05741 

494800 4196800 12.89287 24-HR 3RD 0.24188 12.65099 12.89287 

494800 4197200 12.1185 24-HR 3RD 0.19489 11.92361 12.1185 

494806 4196693 13.02681 24-HR 3RD 0.26216 12.76465 13.02681 

494806 4196791 12.96579 24-HR 3RD 0.37091 12.59488 12.96579 

494806 4197185 12.14849 24-HR 3RD 0.19328 11.95521 12.14849 

494968.8 4197480 11.92474 24-HR 3RD 0.32281 11.60193 11.92474 

495050.2 4197480 12.24157 24-HR 3RD 0.42862 11.81295 12.24157 

495100 4197500 12.33894 24-HR 3RD 0.44786 11.89109 12.33894 

495131.6 4197480 12.45834 24-HR 3RD 0.46868 11.98967 12.45834 

495200 4197600 12.28834 24-HR 3RD 0.46689 11.82146 12.28834 

495221.2 4197567 12.36907 24-HR 3RD 0.48477 11.8843 12.36907 

495221.3 4197657 12.16695 24-HR 3RD 0.44908 11.71786 12.16695 

495221.3 4197746 11.99241 24-HR 3RD 0.36023 11.63218 11.99241 

494100 4196500 12.03789 24-HR 3RD 0.27949 11.7584 12.03789 

495100 4197600 12.0405 24-HR 3RD 0.35823 11.68228 12.0405 

495200 4197500 12.48732 24-HR 3RD 0.48936 11.99796 12.48732 

495200 4197700 12.03205 24-HR 3RD 0.37315 11.6589 12.03205 

495213 4197480 12.52332 24-HR 3RD 0.49578 12.02754 12.52332 

494100 4196600 11.75577 24-HR 4TH 0.26455 11.49122 11.75577 

494200 4196400 11.07522 24-HR 4TH 0.12039 10.95483 11.07522 

494200 4196500 11.42826 24-HR 4TH 0.18646 11.24181 11.42826 

494200 4196600 11.75129 24-HR 4TH 0.23049 11.5208 11.75129 

494200 4196700 11.79805 24-HR 4TH 0.17381 11.62424 11.79805 
Indiana Gasification, LLC Page 36 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494200 4196800 11.96105 24-HR 4TH 0.18509 11.77596 11.96105 

494300 4196400 11.25347 24-HR 4TH 0.2329 11.02056 11.25347 

494300 4196500 11.46984 24-HR 4TH 0.18366 11.28618 11.46984 

494300 4196600 11.78374 24-HR 4TH 0.24461 11.53913 11.78374 

494300 4196700 11.77295 24-HR 4TH 0.17781 11.59514 11.77295 

494300 4196800 11.9631 24-HR 4TH 0.12464 11.83846 11.9631 

494300 4196900 11.96871 24-HR 4TH 0.31099 11.65771 11.96871 

494400 4196400 11.37654 24-HR 4TH 0.1497 11.22684 11.37654 

494400 4196500 11.44794 24-HR 4TH 0.12495 11.32299 11.44794 

494400 4196600 11.76573 24-HR 4TH 0.22831 11.53742 11.76573 

494400 4196700 11.75785 24-HR 4TH 0.18993 11.56792 11.75785 

494400 4196800 11.90315 24-HR 4TH 0.15702 11.74613 11.90315 

494400 4196900 11.94265 24-HR 4TH 0.1486 11.79405 11.94265 

494400 4197000 12.09111 24-HR 4TH 0.21608 11.87502 12.09111 

494500 4196400 11.3906 24-HR 4TH 0.09635 11.29425 11.3906 

494500 4196500 11.30637 24-HR 4TH 0.05365 11.25272 11.30637 

494500 4196600 11.63987 24-HR 4TH 0.26052 11.37935 11.63987 

494500 4196700 11.64282 24-HR 4TH 0.20922 11.4336 11.64282 

494500 4196800 11.79559 24-HR 4TH 0.29413 11.50145 11.79559 

494500 4196900 11.85936 24-HR 4TH 0.20938 11.64998 11.85936 

494500 4197000 12.03981 24-HR 4TH 0.36826 11.67155 12.03981 

494600 4196400 11.44179 24-HR 4TH 0.13423 11.30756 11.44179 

494600 4196500 11.41863 24-HR 4TH 0.05543 11.36319 11.41863 

494600 4196600 11.58788 24-HR 4TH 0.17719 11.4107 11.58788 

494600 4196700 11.49658 24-HR 4TH 0.17752 11.31906 11.49658 

494600 4196800 11.72736 24-HR 4TH 0.31009 11.41727 11.72736 

494600 4196900 11.85134 24-HR 4TH 0.09271 11.75863 11.85134 

494600 4197000 11.98817 24-HR 4TH 0.23939 11.74878 11.98817 

494600 4197100 11.84529 24-HR 4TH 0.46477 11.38052 11.84529 

494700 4196500 11.52716 24-HR 4TH 0.31055 11.21661 11.52716 

494700 4196600 11.64389 24-HR 4TH 0.22934 11.41455 11.64389 

494700 4196700 11.58833 24-HR 4TH 0.0806 11.50774 11.58833 

494700 4196800 11.79136 24-HR 4TH 0.22144 11.56993 11.79136 

494700 4196900 11.83017 24-HR 4TH 0.14395 11.68622 11.83017 

494700 4197000 12.04433 24-HR 4TH 0.30966 11.73467 12.04433 

494700 4197100 11.93424 24-HR 4TH 0.32529 11.60894 11.93424 

494800 4196700 11.67839 24-HR 4TH 0.06804 11.61035 11.67839 
Indiana Gasification, LLC Page 37 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494800 4196800 12.07186 24-HR 4TH 0.29923 11.77263 12.07186 

494800 4197200 11.61427 24-HR 4TH 0.30827 11.306 11.61427 

494806 4196693 11.67135 24-HR 4TH 0.06311 11.60824 11.67135 

494806 4196791 12.10176 24-HR 4TH 0.23258 11.86918 12.10176 

494806 4197185 11.70831 24-HR 4TH 0.31471 11.3936 11.70831 

494968.8 4197480 11.0447 24-HR 4TH 0.29235 10.75235 11.0447 

495050.2 4197480 11.11912 24-HR 4TH 0.42346 10.69566 11.11912 

495100 4197500 11.16632 24-HR 4TH 0.32482 10.8415 11.16632 

495131.6 4197480 11.24118 24-HR 4TH 0.44272 10.79846 11.24118 

495200 4197600 11.32111 24-HR 4TH 0.26795 11.05317 11.32111 

495221.2 4197567 11.32778 24-HR 4TH 0.28855 11.03923 11.32778 

495221.3 4197657 11.29635 24-HR 4TH 0.23277 11.06358 11.29635 

495221.3 4197746 11.2488 24-HR 4TH 0.38037 10.86843 11.2488 

494100 4196500 11.42835 24-HR 4TH 0.19158 11.23678 11.42835 

495100 4197600 11.24286 24-HR 4TH 0.20073 11.04213 11.24286 

495200 4197500 11.32623 24-HR 4TH 0.44451 10.88172 11.32623 

495200 4197700 11.25317 24-HR 4TH 0.25214 11.00103 11.25317 

495213 4197480 11.36649 24-HR 4TH 0.44941 10.91708 11.36649 

495221.2 4197478 11.37776 24-HR 4TH 0.44693 10.93083 11.37776 

494100 4196600 10.99841 24-HR 5TH 0.07396 10.92446 10.99841 

494200 4196400 10.61704 24-HR 5TH 0.20162 10.41542 10.61704 

494200 4196500 10.69928 24-HR 5TH 0.13042 10.56886 10.69928 

494200 4196600 11.03739 24-HR 5TH 0.0784 10.95899 11.03739 

494200 4196700 11.34525 24-HR 5TH 0.16298 11.18227 11.34525 

494200 4196800 11.13076 24-HR 5TH 0.14438 10.98638 11.13076 

494300 4196400 10.72207 24-HR 5TH 0.10616 10.61591 10.72207 

494300 4196500 10.85008 24-HR 5TH 0.13601 10.71407 10.85008 

494300 4196600 11.03826 24-HR 5TH 0.07561 10.96265 11.03826 

494300 4196700 11.30806 24-HR 5TH 0.17131 11.13676 11.30806 

494300 4196800 11.14169 24-HR 5TH 0.15929 10.9824 11.14169 

494300 4196900 10.9998 24-HR 5TH 0.1768 10.823 10.9998 

494400 4196400 10.76656 24-HR 5TH 0.19879 10.56777 10.76656 

494400 4196500 10.99249 24-HR 5TH 0.10982 10.88267 10.99249 

494400 4196600 10.99298 24-HR 5TH 0.05288 10.9401 10.99298 

494400 4196700 11.29468 24-HR 5TH 0.19404 11.10064 11.29468 

494400 4196800 11.10083 24-HR 5TH 0.23227 10.86855 11.10083 

494400 4196900 10.98653 24-HR 5TH 0.17997 10.80656 10.98653 
Indiana Gasification, LLC Page 38 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494400 4197000 11.08021 24-HR 5TH 0.22305 10.85716 11.08021 

494500 4196400 10.68324 24-HR 5TH 0.23314 10.4501 10.68324 

494500 4196500 11.10063 24-HR 5TH 0.13325 10.96737 11.10063 

494500 4196600 11.10689 24-HR 5TH 0.04973 11.05716 11.10689 

494500 4196700 11.25839 24-HR 5TH 0.28369 10.9747 11.25839 

494500 4196800 11.10688 24-HR 5TH 0.18555 10.92134 11.10688 

494500 4196900 10.99017 24-HR 5TH 0.28127 10.7089 10.99017 

494500 4197000 11.0296 24-HR 5TH 0.12513 10.90447 11.0296 

494600 4196400 10.67762 24-HR 5TH 0.1441 10.53352 10.67762 

494600 4196500 11.05847 24-HR 5TH 0.10065 10.95783 11.05847 

494600 4196600 11.13369 24-HR 5TH 0.10593 11.02776 11.13369 

494600 4196700 11.31448 24-HR 5TH 0.2462 11.06828 11.31448 

494600 4196800 11.15466 24-HR 5TH 0.24385 10.91081 11.15466 

494600 4196900 10.95406 24-HR 5TH 0.4035 10.55055 10.95406 

494600 4197000 10.96492 24-HR 5TH 0.31181 10.65311 10.96492 

494600 4197100 10.88503 24-HR 5TH 0.16128 10.72375 10.88503 

494700 4196500 11.02185 24-HR 5TH 0.07448 10.94737 11.02185 

494700 4196600 11.20909 24-HR 5TH 0.08014 11.12895 11.20909 

494700 4196700 11.40343 24-HR 5TH 0.2745 11.12893 11.40343 

494700 4196800 11.26785 24-HR 5TH 0.26181 11.00604 11.26785 

494700 4196900 11.15262 24-HR 5TH 0.28212 10.8705 11.15262 

494700 4197000 11.13996 24-HR 5TH 0.16877 10.97119 11.13996 

494700 4197100 10.97076 24-HR 5TH 0.16992 10.80084 10.97076 

494800 4196700 11.45697 24-HR 5TH 0.2355 11.22146 11.45697 

494800 4196800 11.30657 24-HR 5TH 0.28755 11.01902 11.30657 

494800 4197200 10.82385 24-HR 5TH 0.26428 10.55957 10.82385 

494806 4196693 11.46816 24-HR 5TH 0.23083 11.23733 11.46816 

494806 4196791 11.34315 24-HR 5TH 0.31156 11.03159 11.34315 

494806 4197185 10.89714 24-HR 5TH 0.27013 10.62701 10.89714 

494968.8 4197480 10.67564 24-HR 5TH 0.42312 10.25252 10.67564 

495050.2 4197480 10.81362 24-HR 5TH 0.44981 10.3638 10.81362 

495100 4197500 10.6901 24-HR 5TH 0.50327 10.18683 10.6901 

495131.6 4197480 10.77951 24-HR 5TH 0.44429 10.33523 10.77951 

495200 4197600 10.41687 24-HR 5TH 0.40775 10.00912 10.41687 

495221.2 4197567 10.52577 24-HR 5TH 0.38692 10.13885 10.52577 

495221.3 4197657 10.45537 24-HR 5TH 0.36526 10.09011 10.45537 

495221.3 4197746 10.40365 24-HR 5TH 0.39683 10.00683 10.40365 
Indiana Gasification, LLC Page 39 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494100 4196500 10.5822 24-HR 5TH 0.05364 10.52857 10.5822 

495100 4197600 10.20484 24-HR 5TH 0.43637 9.76846 10.20484 

495200 4197500 10.84092 24-HR 5TH 0.33363 10.50728 10.84092 

495200 4197700 10.42463 24-HR 5TH 0.45565 9.96898 10.42463 

495213 4197480 10.9046 24-HR 5TH 0.33876 10.56584 10.9046 

495221.2 4197478 10.91411 24-HR 5TH 0.33291 10.5812 10.91411 

494100 4196600 10.42869 24-HR 6TH 0.1656 10.26308 10.42869 

494200 4196400 10.06307 24-HR 6TH 0.3095 9.75357 10.06307 

494200 4196500 10.31774 24-HR 6TH 0.17664 10.14111 10.31774 

494200 4196600 10.44438 24-HR 6TH 0.19657 10.24781 10.44438 

494200 4196700 10.6053 24-HR 6TH 0.19911 10.40619 10.6053 

494200 4196800 10.61068 24-HR 6TH 0.15461 10.45607 10.61068 

494300 4196400 9.91913 24-HR 6TH 0.36517 9.55396 9.91913 

494300 4196500 10.23085 24-HR 6TH 0.31638 9.91447 10.23085 

494300 4196600 10.40066 24-HR 6TH 0.24093 10.15973 10.40066 

494300 4196700 10.59782 24-HR 6TH 0.26038 10.33744 10.59782 

494300 4196800 10.62752 24-HR 6TH 0.18153 10.44599 10.62752 

494300 4196900 10.47693 24-HR 6TH 0.1565 10.32043 10.47693 

494400 4196400 9.81096 24-HR 6TH 0.14152 9.66944 9.81096 

494400 4196500 10.16909 24-HR 6TH 0.23478 9.93431 10.16909 

494400 4196600 10.47375 24-HR 6TH 0.22349 10.25026 10.47375 

494400 4196700 10.51015 24-HR 6TH 0.30588 10.20427 10.51015 

494400 4196800 10.62408 24-HR 6TH 0.26018 10.3639 10.62408 

494400 4196900 10.47289 24-HR 6TH 0.17626 10.29663 10.47289 

494400 4197000 10.48939 24-HR 6TH 0.26333 10.22605 10.48939 

494500 4196400 9.91603 24-HR 6TH 0.10169 9.81434 9.91603 

494500 4196500 10.16965 24-HR 6TH 0.26337 9.90628 10.16965 

494500 4196600 10.49954 24-HR 6TH 0.15301 10.34652 10.49954 

494500 4196700 10.57689 24-HR 6TH 0.15816 10.41874 10.57689 

494500 4196800 10.64575 24-HR 6TH 0.18774 10.45801 10.64575 

494500 4196900 10.53694 24-HR 6TH 0.08123 10.4557 10.53694 

494500 4197000 10.55166 24-HR 6TH 0.20135 10.35032 10.55166 

494600 4196400 9.77432 24-HR 6TH 0.15252 9.6218 9.77432 

494600 4196500 10.13617 24-HR 6TH 0.19479 9.94138 10.13617 

494600 4196600 10.62504 24-HR 6TH 0.16951 10.45553 10.62504 

494600 4196700 10.66918 24-HR 6TH 0.19596 10.47323 10.66918 

494600 4196800 10.74003 24-HR 6TH 0.28615 10.45387 10.74003 
Indiana Gasification, LLC Page 40 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494600 4196900 10.65483 24-HR 6TH 0.09122 10.56361 10.65483 

494600 4197000 10.64001 24-HR 6TH 0.11365 10.52636 10.64001 

494600 4197100 10.44476 24-HR 6TH 0.14132 10.30344 10.44476 

494700 4196500 9.99723 24-HR 6TH 0.06353 9.9337 9.99723 

494700 4196600 10.45493 24-HR 6TH 0.11859 10.33635 10.45493 

494700 4196700 10.60909 24-HR 6TH 0.20525 10.40384 10.60909 

494700 4196800 10.68479 24-HR 6TH 0.3481 10.33669 10.68479 

494700 4196900 10.51876 24-HR 6TH 0.09006 10.4287 10.51876 

494700 4197000 10.45025 24-HR 6TH 0.20936 10.24089 10.45025 

494700 4197100 10.31324 24-HR 6TH 0.32383 9.98941 10.31324 

494800 4196700 10.48788 24-HR 6TH 0.1278 10.36008 10.48788 

494800 4196800 10.54015 24-HR 6TH 0.31401 10.22614 10.54015 

494800 4197200 10.16846 24-HR 6TH 0.13028 10.03819 10.16846 

494806 4196693 10.47411 24-HR 6TH 0.10932 10.36479 10.47411 

494806 4196791 10.52473 24-HR 6TH 0.29835 10.22637 10.52473 

494806 4197185 10.15759 24-HR 6TH 0.13631 10.02128 10.15759 

494968.8 4197480 9.79734 24-HR 6TH 0.37008 9.42727 9.79734 

495050.2 4197480 9.89611 24-HR 6TH 0.56644 9.32967 9.89611 

495100 4197500 9.89263 24-HR 6TH 0.57735 9.31529 9.89263 

495131.6 4197480 9.92255 24-HR 6TH 0.56694 9.35561 9.92255 

495200 4197600 9.82782 24-HR 6TH 0.51088 9.31694 9.82782 

495221.2 4197567 9.89676 24-HR 6TH 0.55686 9.33991 9.89676 

495221.3 4197657 9.76418 24-HR 6TH 0.65506 9.10913 9.76418 

495221.3 4197746 9.86004 24-HR 6TH 0.31539 9.54465 9.86004 

494100 4196500 10.36386 24-HR 6TH 0.38139 9.98246 10.36386 

495100 4197600 9.79388 24-HR 6TH 0.42622 9.36765 9.79388 

495200 4197500 9.95588 24-HR 6TH 0.6781 9.27778 9.95588 

495200 4197700 9.81195 24-HR 6TH 0.44241 9.36955 9.81195 

495213 4197480 9.98368 24-HR 6TH 0.66898 9.31469 9.98368 

495221.2 4197478 9.98407 24-HR 6TH 0.65934 9.32473 9.98407 

494100 4196600 9.82291 24-HR 7TH 0.26648 9.55644 9.82291 

494200 4196400 9.78836 24-HR 7TH 0.29882 9.48953 9.78836 

494200 4196500 9.92275 24-HR 7TH 0.40574 9.517 9.92275 

494200 4196600 9.87661 24-HR 7TH 0.13738 9.73923 9.87661 

494200 4196700 9.70894 24-HR 7TH 0.13731 9.57162 9.70894 

494200 4196800 9.9129 24-HR 7TH 0.27372 9.63918 9.9129 

494300 4196400 9.64718 24-HR 7TH 0.16636 9.48083 9.64718 
Indiana Gasification, LLC Page 41 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494300 4196500 9.94523 24-HR 7TH 0.28741 9.65782 9.94523 

494300 4196600 9.9438 24-HR 7TH 0.14083 9.80297 9.9438 

494300 4196700 9.86944 24-HR 7TH 0.11049 9.75895 9.86944 

494300 4196800 10.03459 24-HR 7TH 0.26437 9.77022 10.03459 

494300 4196900 10.00531 24-HR 7TH 0.32785 9.67746 10.00531 

494400 4196400 9.49038 24-HR 7TH 0.286 9.20438 9.49038 

494400 4196500 9.87416 24-HR 7TH 0.3278 9.54636 9.87416 

494400 4196600 9.96516 24-HR 7TH 0.26016 9.705 9.96516 

494400 4196700 10.07109 24-HR 7TH 0.10984 9.96124 10.07109 

494400 4196800 10.24461 24-HR 7TH 0.25944 9.98517 10.24461 

494400 4196900 10.13356 24-HR 7TH 0.31469 9.81887 10.13356 

494400 4197000 10.0677 24-HR 7TH 0.28132 9.78639 10.0677 

494500 4196400 9.44053 24-HR 7TH 0.1734 9.26713 9.44053 

494500 4196500 9.81046 24-HR 7TH 0.09771 9.71275 9.81046 

494500 4196600 9.86912 24-HR 7TH 0.3079 9.56122 9.86912 

494500 4196700 10.12021 24-HR 7TH 0.24968 9.87053 10.12021 

494500 4196800 10.32395 24-HR 7TH 0.37816 9.94579 10.32395 

494500 4196900 10.22054 24-HR 7TH 0.42704 9.7935 10.22054 

494500 4197000 10.07379 24-HR 7TH 0.29744 9.77635 10.07379 

494600 4196400 9.44564 24-HR 7TH 0.03355 9.4121 9.44564 

494600 4196500 9.7873 24-HR 7TH 0.05183 9.73547 9.7873 

494600 4196600 9.81638 24-HR 7TH 0.20439 9.61198 9.81638 

494600 4196700 10.11988 24-HR 7TH 0.38877 9.73111 10.11988 

494600 4196800 10.24165 24-HR 7TH 0.32451 9.91714 10.24165 

494600 4196900 10.13188 24-HR 7TH 0.44358 9.6883 10.13188 

494600 4197000 10.05967 24-HR 7TH 0.27411 9.78557 10.05967 

494600 4197100 9.99583 24-HR 7TH 0.29252 9.70331 9.99583 

494700 4196500 9.71951 24-HR 7TH 0.0807 9.63881 9.71951 

494700 4196600 9.81005 24-HR 7TH 0.14072 9.66933 9.81005 

494700 4196700 9.95709 24-HR 7TH 0.26149 9.69561 9.95709 

494700 4196800 9.97954 24-HR 7TH 0.40072 9.57882 9.97954 

494700 4196900 10.07168 24-HR 7TH 0.49925 9.57244 10.07168 

494700 4197000 10.00101 24-HR 7TH 0.24343 9.75758 10.00101 

494700 4197100 9.94066 24-HR 7TH 0.21475 9.72591 9.94066 

494800 4196700 9.8375 24-HR 7TH 0.18933 9.64817 9.8375 

494800 4196800 9.88616 24-HR 7TH 0.22583 9.66032 9.88616 

494800 4197200 9.73585 24-HR 7TH 0.37414 9.36171 9.73585 
Indiana Gasification, LLC Page 42 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494806 4196693 9.78443 24-HR 7TH 0.16521 9.61922 9.78443 

494806 4196791 9.97889 24-HR 7TH 0.29251 9.68637 9.97889 

494806 4197185 9.72732 24-HR 7TH 0.37966 9.34766 9.72732 

494968.8 4197480 9.47717 24-HR 7TH 0.34296 9.13422 9.47717 

495050.2 4197480 9.58123 24-HR 7TH 0.34942 9.23181 9.58123 

495100 4197500 9.64369 24-HR 7TH 0.36465 9.27905 9.64369 

495131.6 4197480 9.68378 24-HR 7TH 0.40811 9.27567 9.68378 

495200 4197600 9.57868 24-HR 7TH 0.39306 9.18562 9.57868 

495221.2 4197567 9.6557 24-HR 7TH 0.33942 9.31628 9.6557 

495221.3 4197657 9.45133 24-HR 7TH 0.20935 9.24198 9.45133 

495221.3 4197746 9.24447 24-HR 7TH 0.41403 8.83044 9.24447 

494100 4196500 9.85009 24-HR 7TH 0.12443 9.72565 9.85009 

495100 4197600 9.48336 24-HR 7TH 0.35005 9.1333 9.48336 

495200 4197500 9.69765 24-HR 7TH 0.34733 9.35032 9.69765 

495200 4197700 9.27572 24-HR 7TH 0.2124 9.06332 9.27572 

495213 4197480 9.68258 24-HR 7TH 0.33691 9.34567 9.68258 

495221.2 4197478 9.68239 24-HR 7TH 0.33596 9.34643 9.68239 

494100 4196600 9.38665 24-HR 8TH 0.14904 9.23762 9.38665 

494200 4196400 9.24431 24-HR 8TH 0.23006 9.01425 9.24431 

494200 4196500 9.6087 24-HR 8TH 0.28767 9.32103 9.6087 

494200 4196600 9.54866 24-HR 8TH 0.39091 9.15775 9.54866 

494200 4196700 9.50424 24-HR 8TH 0.24515 9.25909 9.50424 

494200 4196800 9.5045 24-HR 8TH 0.33693 9.16757 9.5045 

494300 4196400 9.33925 24-HR 8TH 0.25194 9.08732 9.33925 

494300 4196500 9.57864 24-HR 8TH 0.25739 9.32126 9.57864 

494300 4196600 9.65704 24-HR 8TH 0.39798 9.25906 9.65704 

494300 4196700 9.51417 24-HR 8TH 0.16052 9.35365 9.51417 

494300 4196800 9.64561 24-HR 8TH 0.36879 9.27681 9.64561 

494300 4196900 9.74546 24-HR 8TH 0.26897 9.47649 9.74546 

494400 4196400 9.33125 24-HR 8TH 0.25954 9.07171 9.33125 

494400 4196500 9.4994 24-HR 8TH 0.19882 9.30058 9.4994 

494400 4196600 9.65069 24-HR 8TH 0.33676 9.31393 9.65069 

494400 4196700 9.50863 24-HR 8TH 0.31525 9.19338 9.50863 

494400 4196800 9.64602 24-HR 8TH 0.32649 9.31953 9.64602 

494400 4196900 9.89184 24-HR 8TH 0.34195 9.54989 9.89184 

494400 4197000 9.57962 24-HR 8TH 0.52004 9.05958 9.57962 

494500 4196400 9.27678 24-HR 8TH 0.10827 9.16851 9.27678 
Indiana Gasification, LLC Page 43 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494500 4196500 9.51527 24-HR 8TH 0.2035 9.31177 9.51527 

494500 4196600 9.63248 24-HR 8TH 0.38165 9.25083 9.63248 

494500 4196700 9.57331 24-HR 8TH 0.48104 9.09227 9.57331 

494500 4196800 9.61292 24-HR 8TH 0.50264 9.11028 9.61292 

494500 4196900 9.87823 24-HR 8TH 0.31123 9.56701 9.87823 

494500 4197000 9.69401 24-HR 8TH 0.60911 9.0849 9.69401 

494600 4196400 9.20974 24-HR 8TH 0.12236 9.08738 9.20974 

494600 4196500 9.27531 24-HR 8TH 0.22598 9.04933 9.27531 

494600 4196600 9.43635 24-HR 8TH 0.37025 9.0661 9.43635 

494600 4196700 9.53228 24-HR 8TH 0.35224 9.18004 9.53228 

494600 4196800 9.59335 24-HR 8TH 0.53245 9.0609 9.59335 

494600 4196900 9.82537 24-HR 8TH 0.29465 9.53072 9.82537 

494600 4197000 9.66197 24-HR 8TH 0.50433 9.15765 9.66197 

494600 4197100 9.63903 24-HR 8TH 0.60272 9.03631 9.63903 

494700 4196500 9.21608 24-HR 8TH 0.1217 9.09438 9.21608 

494700 4196600 9.17015 24-HR 8TH 0.2367 8.93344 9.17015 

494700 4196700 9.42226 24-HR 8TH 0.27119 9.15107 9.42226 

494700 4196800 9.5518 24-HR 8TH 0.2131 9.3387 9.5518 

494700 4196900 9.71807 24-HR 8TH 0.31933 9.39874 9.71807 

494700 4197000 9.54475 24-HR 8TH 0.50281 9.04195 9.54475 

494700 4197100 9.53257 24-HR 8TH 0.50478 9.02778 9.53257 

494800 4196700 9.27226 24-HR 8TH 0.2492 9.02306 9.27226 

494800 4196800 9.4497 24-HR 8TH 0.24454 9.20516 9.4497 

494800 4197200 9.38818 24-HR 8TH 0.32451 9.06366 9.38818 

494806 4196693 9.25467 24-HR 8TH 0.24504 9.00963 9.25467 

494806 4196791 9.46521 24-HR 8TH 0.33476 9.13045 9.46521 

494806 4197185 9.39034 24-HR 8TH 0.26041 9.12993 9.39034 

494968.8 4197480 9.08798 24-HR 8TH 0.21429 8.87368 9.08798 

495050.2 4197480 9.16163 24-HR 8TH 0.61314 8.54849 9.16163 

495100 4197500 9.18768 24-HR 8TH 0.60798 8.5797 9.18768 

495131.6 4197480 9.3004 24-HR 8TH 0.5291 8.7713 9.3004 

495200 4197600 9.1192 24-HR 8TH 0.54704 8.57216 9.1192 

495221.2 4197567 9.10384 24-HR 8TH 0.53621 8.56763 9.10384 

495221.3 4197657 9.10523 24-HR 8TH 0.39413 8.71111 9.10523 

495221.3 4197746 8.98747 24-HR 8TH 0 0 0 

494100 4196500 9.45024 24-HR 8TH 0.37031 9.07993 9.45024 

495100 4197600 8.93848 24-HR 8TH 0 0 0 
Indiana Gasification, LLC Page 44 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

495200 4197500 9.24407 24-HR 8TH 0.62608 8.61799 9.24407 

495200 4197700 9.00777 24-HR 8TH 0.32236 8.68541 9.00777 

495213 4197480 9.36108 24-HR 8TH 0.57547 8.78561 9.36108 

495221.2 4197478 9.37689 24-HR 8TH 0.57619 8.8007 9.37689 

494100 4196600 9.05581 24-HR 9TH 0.14964 8.90617 9.05581 

494200 4196400 9.11606 24-HR 9TH 0.09906 9.01701 9.11606 

494200 4196500 9.05766 24-HR 9TH 0.14215 8.91551 9.05766 

494200 4196600 9.22068 24-HR 9TH 0.24862 8.97206 9.22068 

494200 4196700 9.22887 24-HR 9TH 0.4076 8.82127 9.22887 

494200 4196800 9.26204 24-HR 9TH 0.16584 9.09621 9.26204 

494300 4196400 9.12052 24-HR 9TH 0.09977 9.02075 9.12052 

494300 4196500 9.13087 24-HR 9TH 0.09634 9.03454 9.13087 

494300 4196600 9.35597 24-HR 9TH 0.31649 9.03948 9.35597 

494300 4196700 9.24908 24-HR 9TH 0.42823 8.82085 9.24908 

494300 4196800 9.29729 24-HR 9TH 0.25047 9.04682 9.29729 

494300 4196900 9.22763 24-HR 9TH 0.40573 8.8219 9.22763 

494400 4196400 9.10119 24-HR 9TH 0.04858 9.05261 9.10119 

494400 4196500 9.19666 24-HR 9TH 0.12476 9.07189 9.19666 

494400 4196600 9.3851 24-HR 9TH 0.33137 9.05373 9.3851 

494400 4196700 9.32728 24-HR 9TH 0.48875 8.83853 9.32728 

494400 4196800 9.33901 24-HR 9TH 0.34127 8.99774 9.33901 

494400 4196900 9.24467 24-HR 9TH 0.44111 8.80356 9.24467 

494400 4197000 9.0879 24-HR 9TH 0.47613 8.61178 9.0879 

494500 4196400 8.98976 24-HR 9TH 0 0 0 

494500 4196500 9.02611 24-HR 9TH 0.20683 8.81928 9.02611 

494500 4196600 9.28027 24-HR 9TH 0.14145 9.13881 9.28027 

494500 4196700 9.31253 24-HR 9TH 0.46757 8.84495 9.31253 

494500 4196800 9.38218 24-HR 9TH 0.21704 9.16514 9.38218 

494500 4196900 9.24906 24-HR 9TH 0.46433 8.78473 9.24906 

494500 4197000 9.15694 24-HR 9TH 0.55027 8.60667 9.15694 

494600 4196400 9.01647 24-HR 9TH 0.21469 8.80178 9.01647 

494600 4196500 8.93339 24-HR 9TH 0 0 0 

494600 4196600 9.11408 24-HR 9TH 0.10309 9.01099 9.11408 

494600 4196700 9.25319 24-HR 9TH 0.17422 9.07897 9.25319 

494600 4196800 9.34155 24-HR 9TH 0.19907 9.14248 9.34155 

494600 4196900 9.2274 24-HR 9TH 0.53163 8.69576 9.2274 

494600 4197000 9.14592 24-HR 9TH 0.71861 8.42731 9.14592 Max IG Train 
Indiana Gasification, LLC Page 45 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494600 4197100 9.01034 24-HR 9TH 0.45764 8.5527 9.01034 

494700 4196500 8.84137 24-HR 9TH 0 0 0 

494700 4196600 8.96122 24-HR 9TH 0 0 0 

494700 4196700 9.04424 24-HR 9TH 0.1733 8.87093 9.04424 

494700 4196800 9.39168 24-HR 9TH 0.40392 8.98775 9.39168 

494700 4196900 9.15361 24-HR 9TH 0.4937 8.6599 9.15361 

494700 4197000 9.08972 24-HR 9TH 0.49206 8.59766 9.08972 

494700 4197100 9.02879 24-HR 9TH 0.51597 8.51282 9.02879 

494800 4196700 8.97784 24-HR 9TH 0 0 0 

494800 4196800 9.36126 24-HR 9TH 0.37798 8.98328 9.36126 

494800 4197200 9.12969 24-HR 9TH 0.43789 8.6918 9.12969 

494806 4196693 8.96685 24-HR 9TH 0 0 0 

494806 4196791 9.34626 24-HR 9TH 0.32833 9.01793 9.34626 

494806 4197185 9.11681 24-HR 9TH 0.43634 8.68047 9.11681 

494968.8 4197480 8.89488 24-HR 9TH 0 0 0 

495050.2 4197480 8.96009 24-HR 9TH 0 0 0 

495100 4197500 8.8661 24-HR 9TH 0 0 0 

495131.6 4197480 8.91792 24-HR 9TH 0 0 0 

495200 4197600 8.79675 24-HR 9TH 0 0 0 

495221.2 4197567 8.79006 24-HR 9TH 0 0 0 

495221.3 4197657 8.84541 24-HR 9TH 0 0 0 

495221.3 4197746 8.90953 24-HR 9TH 0 0 0 

494100 4196500 9.06109 24-HR 9TH 0.1084 8.95269 9.06109 

495100 4197600 8.79419 24-HR 9TH 0 0 0 

495200 4197500 8.8702 24-HR 9TH 0 0 0 

495200 4197700 8.85449 24-HR 9TH 0 0 0 

495213 4197480 8.95453 24-HR 9TH 0 0 0 

495221.2 4197478 8.96797 24-HR 9TH 0 0 0 

494100 4196600 8.93835 24-HR 10TH 0 0 0 

494200 4196400 8.82526 24-HR 10TH 0 0 0 

494200 4196500 8.78616 24-HR 10TH 0 0 0 

494200 4196600 8.86301 24-HR 10TH 0 0 0 

494200 4196700 8.9248 24-HR 10TH 0 0 0 

494200 4196800 8.87182 24-HR 10TH 0 0 0 

494300 4196400 8.83202 24-HR 10TH 0 0 0 

494300 4196500 8.84339 24-HR 10TH 0 0 0 

494300 4196600 8.85288 24-HR 10TH 0 0 0 
Indiana Gasification, LLC Page 46 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494300 4196700 9.09783 24-HR 10TH 0.50513 8.5927 9.09783 

494300 4196800 8.71207 24-HR 10TH 0 0 0 

494300 4196900 8.79649 24-HR 10TH 0 0 0 

494400 4196400 8.93484 24-HR 10TH 0 0 0 

494400 4196500 8.95303 24-HR 10TH 0 0 0 

494400 4196600 8.90602 24-HR 10TH 0 0 0 

494400 4196700 9.12199 24-HR 10TH 0.44007 8.68193 9.12199 

494400 4196800 8.74361 24-HR 10TH 0 0 0 

494400 4196900 8.76628 24-HR 10TH 0 0 0 

494400 4197000 8.81366 24-HR 10TH 0 0 0 

494500 4196400 8.90723 24-HR 10TH 0 0 0 

494500 4196500 8.8991 24-HR 10TH 0 0 0 

494500 4196600 8.99276 24-HR 10TH 0 0 0 

494500 4196700 9.10459 24-HR 10TH 0.36349 8.7411 9.10459 

494500 4196800 8.95969 24-HR 10TH 0 0 0 

494500 4196900 8.79919 24-HR 10TH 0 0 0 

494500 4197000 8.73742 24-HR 10TH 0 0 0 

494600 4196400 8.81135 24-HR 10TH 0 0 0 

494600 4196500 8.79965 24-HR 10TH 0 0 0 

494600 4196600 8.93031 24-HR 10TH 0 0 0 

494600 4196700 8.94705 24-HR 10TH 0 0 0 

494600 4196800 9.13698 24-HR 10TH 0.34677 8.79021 9.13698 

494600 4196900 8.85144 24-HR 10TH 0 0 0 

494600 4197000 8.79957 24-HR 10TH 0 0 0 

494600 4197100 8.821 24-HR 10TH 0 0 0 

494700 4196500 8.66093 24-HR 10TH 0 0 0 

494700 4196600 8.72645 24-HR 10TH 0 0 0 

494700 4196700 8.8313 24-HR 10TH 0 0 0 

494700 4196800 9.14283 24-HR 10TH 0.32717 8.81566 9.14283 

494700 4196900 8.93072 24-HR 10TH 0 0 0 

494700 4197000 8.96362 24-HR 10TH 0 0 0 

494700 4197100 8.89092 24-HR 10TH 0 0 0 

494800 4196700 8.75604 24-HR 10TH 0 0 0 

494800 4196800 9.18903 24-HR 10TH 0.22265 8.96639 9.18903 

494800 4197200 8.84708 24-HR 10TH 0 0 0 

494806 4196693 8.73065 24-HR 10TH 0 0 0 

494806 4196791 9.20066 24-HR 10TH 0.22341 8.97725 9.20066 
Indiana Gasification, LLC Page 47 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494806 4197185 8.85816 24-HR 10TH 0 0 0 

494968.8 4197480 8.46707 24-HR 10TH 0 0 0 

495050.2 4197480 8.7137 24-HR 10TH 0 0 0 

495100 4197500 8.75247 24-HR 10TH 0 0 0 

495131.6 4197480 8.77238 24-HR 10TH 0 0 0 

495200 4197600 8.45121 24-HR 10TH 0 0 0 

495221.2 4197567 8.47924 24-HR 10TH 0 0 0 

495221.3 4197657 8.55094 24-HR 10TH 0 0 0 

495221.3 4197746 8.67517 24-HR 10TH 0 0 0 

494100 4196500 8.76554 24-HR 10TH 0 0 0 

495100 4197600 8.50371 24-HR 10TH 0 0 0 

495200 4197500 8.71003 24-HR 10TH 0 0 0 

495200 4197700 8.61417 24-HR 10TH 0 0 0 

495213 4197480 8.7081 24-HR 10TH 0 0 0 

495221.2 4197478 8.70346 24-HR 10TH 0 0 0 

494100 4196600 8.67895 24-HR 11TH 0 0 0 

494200 4196400 8.57993 24-HR 11TH 0 0 0 

494200 4196500 8.52417 24-HR 11TH 0 0 0 

494200 4196600 8.64245 24-HR 11TH 0 0 0 

494200 4196700 8.71926 24-HR 11TH 0 0 0 

494200 4196800 8.42038 24-HR 11TH 0 0 0 

494300 4196400 8.68101 24-HR 11TH 0 0 0 

494300 4196500 8.63028 24-HR 11TH 0 0 0 

494300 4196600 8.62082 24-HR 11TH 0 0 0 

494300 4196700 8.66221 24-HR 11TH 0 0 0 

494300 4196800 8.54336 24-HR 11TH 0 0 0 

494300 4196900 8.34131 24-HR 11TH 0 0 0 

494400 4196400 8.76766 24-HR 11TH 0 0 0 

494400 4196500 8.62596 24-HR 11TH 0 0 0 

494400 4196600 8.61943 24-HR 11TH 0 0 0 

494400 4196700 8.76276 24-HR 11TH 0 0 0 

494400 4196800 8.58292 24-HR 11TH 0 0 0 

494400 4196900 8.35901 24-HR 11TH 0 0 0 

494400 4197000 8.31313 24-HR 11TH 0 0 0 

494500 4196400 8.72011 24-HR 11TH 0 0 0 

494500 4196500 8.60426 24-HR 11TH 0 0 0 

494500 4196600 8.56596 24-HR 11TH 0 0 0 
Indiana Gasification, LLC Page 48 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

494500 4196700 8.81677 24-HR 11TH 0 0 0 

494500 4196800 8.65264 24-HR 11TH 0 0 0 

494500 4196900 8.5192 24-HR 11TH 0 0 0 

494500 4197000 8.37254 24-HR 11TH 0 0 0 

494600 4196400 8.58049 24-HR 11TH 0 0 0 

494600 4196500 8.54629 24-HR 11TH 0 0 0 

494600 4196600 8.48527 24-HR 11TH 0 0 0 

494600 4196700 8.79091 24-HR 11TH 0 0 0 

494600 4196800 8.74828 24-HR 11TH 0 0 0 

494600 4196900 8.69867 24-HR 11TH 0 0 0 

494600 4197000 8.46931 24-HR 11TH 0 0 0 

494600 4197100 8.18421 24-HR 11TH 0 0 0 

494700 4196500 8.4179 24-HR 11TH 0 0 0 

494700 4196600 8.52652 24-HR 11TH 0 0 0 

494700 4196700 8.76991 24-HR 11TH 0 0 0 

494700 4196800 8.75347 24-HR 11TH 0 0 0 

494700 4196900 8.81855 24-HR 11TH 0 0 0 

494700 4197000 8.52139 24-HR 11TH 0 0 0 

494700 4197100 8.34491 24-HR 11TH 0 0 0 

494800 4196700 8.65895 24-HR 11TH 0 0 0 

494800 4196800 8.69947 24-HR 11TH 0 0 0 

494800 4197200 8.40308 24-HR 11TH 0 0 0 

494806 4196693 8.60108 24-HR 11TH 0 0 0 

494806 4196791 8.71311 24-HR 11TH 0 0 0 

494806 4197185 8.42523 24-HR 11TH 0 0 0 

494968.8 4197480 8.24248 24-HR 11TH 0 0 0 

495050.2 4197480 8.36795 24-HR 11TH 0 0 0 

495100 4197500 8.48109 24-HR 11TH 0 0 0 

495131.6 4197480 8.49111 24-HR 11TH 0 0 0 

495200 4197600 8.33568 24-HR 11TH 0 0 0 

495221.2 4197567 8.41789 24-HR 11TH 0 0 0 

495221.3 4197657 8.30612 24-HR 11TH 0 0 0 

495221.3 4197746 8.3422 24-HR 11TH 0 0 0 

494100 4196500 8.52916 24-HR 11TH 0 0 0 

495100 4197600 8.35273 24-HR 11TH 0 0 0 

495200 4197500 8.47736 24-HR 11TH 0 0 0 

495200 4197700 8.38329 24-HR 11TH 0 0 0 
Indiana Gasification, LLC Page 49 of 49 

Rockport, Indiana PSD/TV Permit No. T147-30464-00060 

Permit Writer: Michael Mosier

495213 4197480 8.48245 24-HR 11TH 0 0 0 

495221.2 4197478 8.49396 24-HR 11TH 0 0 0 
Indiana Department of Environmental Management

Office of Air Quality

Technical Support Document (TSD) for a PSD/Part 70 Operating Permit:

Appendix D: Compliance Assurance Monitoring (CAM) Plan

Source Background and Description

Source Name: Indiana Gasification LLC

Source Location: CR 200 N and Base Road, Rockport, IN 47635

County: Spencer

SIC Code: 4925, 2819

Operation Permit No.: T 147-30464-00060

Operation Permit Issuance Date: Yet to be Issued

Permit Reviewer: Josiah Balogun

INTRODUCTION

This Compliance Assurance Monitoring (CAM) Plan has been developed for the following two emissions 

sources at the Indiana Gasification Facility.

• The Regenerative Thermal Oxidizer (RTO) on the Acid Gas Removal (AGR) System (CO); and 

• The Wet Sulfuric Acid (WSA) Plant (NOx, H2SO4 & SO2)

These sources are subject to the Compliance Assurance Monitoring (CAM) Rule (40 CFR 64) because 

they meet the following three criteria for applicability per 40 CFR 64.2:

(1) Are subject to an emission limitation or standard, 

(2) Use a control device to achieve compliance with an emission limitation or standard, and 

(3) Have the potential to emit pre-control device emissions equal to or greater than 100% of the 

amount to be classified as a major source.

This CAM regulation establishes criteria that define the monitoring, reporting, and recordkeeping that must 

be conducted by regulated emission sources to demonstrate continuous compliance with emission 

limitations and standards for applicable sources.

CAM PLAN for Regenerative Thermal Oxidizer for AGR system 

Background on Affected Emission Units

Emission Units

Cooled syngas, produced by gasifying coal and/or petcoke, is sent to the AGR system that utilizes a 

Rectisol process to remove primarily H2S and COS. The AGR system, which will have two Rectisol trains, 

will have two resultant intermediate process streams (cleaned syngas and acid gas) and one waste off-gas 

stream. While the waste off-gas stream will primarily contain CO2, potential pre-control device emissions 

of Carbon Monoxide (CO) will be greater than 100 tons per year, the major source threshold. Two natural 

gas-fired Regenerative Thermal Oxidizers (RTOs) that share a common stack will be used to abate 

emissions of CO from the Acid Gas Removal (AGR) system (IDEM Emissions Unit ID 07).
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Rockport, Indiana Appendix D PSD and TV Permit No.:147-30464-00060

Permit Reviewer: Josiah Balogun

Applicable Regulations

Indiana State regulation 326 IAC 2-2-3 requires an analysis of Best Available Control Technology (BACT) 

to determine an appropriate limitation for the emissions of PSD-applicable pollutants from a new major 

source. As an emission limit, BACT for this emission unit is defined as 65 pounds of CO emissions per 

hour at the RTO exhaust. CO emissions are controlled to this level through the design of the RTOs, which 

are proposed as BACT.

Control Devices

A regenerative thermal oxidizer is an abatement device that converts CO from process gas streams into 

CO2 using high temperature thermal oxidation and a system to recover a portion of the sensible heat prior 

to venting the exhaust gases to the atmosphere to improve energy efficiency. 

Description of Monitoring Procedures

The parameters to be monitored are as follows:

(a) Combustion chamber temperature

(b) Annual burner inspection

Combustion Chamber Temperature

The combustion chamber temperature from the RTOs will be monitored continuously with a thermocouple 

located at the outlet of the combustion chamber. Temperature data will be recorded continuously (i.e. 

once every 15 minutes). 

Annual Burner Inspection

The RTO burner will be inspected at least once per calendar year (minimum). The following information 

will be noted on a log form.

 Emission Unit ID

 Observer’s Name

 Date and Time

 Burner Condition

 Adjustments performed, if any

Emission Unit Performance Criteria

The performance criteria for the emission unit in terms of allowable ranges for the monitored parameters, 

corrective action time periods, maximum number of discrepancies and data availability are summarized 

below:

Performance Range for Monitored Criteria

1. Combustion Chamber Temperature. The established performance range for the RTO shall be a 

recommended minimum temperature from the manufacturer, 1600o

F, or from the design or 

operating engineers. This minimum temperature may be determined and/or confirmed during the 

shakedown period of the initial plant start up.

2. Annual Burner Inspection. The RTO burners will be inspected once per calendar year.

Corrective Action Periods

Corrective Action will be initiated according to the following schedule:
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Rockport, Indiana Appendix D PSD and TV Permit No.:147-30464-00060

Permit Reviewer: Josiah Balogun

Corrective action will be initiated as soon as practically possible using controlled shutdown procedures. 

The deficiency will be rectified before operation of the unit resumes.

Maximum Number of Excursions

1. Combustion Chamber Temperature. The maximum number of allowed excursions below the 

recommended combustion chamber temperature in any reporting period from the RTO unit is five 

(5).

2. Annual Burner Inspection. No excursions are allowed.

Data Availability

The minimum data availability for each semi-annual reporting period, defined as the number of days for 

which monitoring data are available divided by the number of days during which the process operated 

(times 100), will be 90 percent. 

Quality Control Procedures

The quality control procedures to be implemented as part of the monitoring plan are described below:

Combustion Chamber Temperature 

The RTO thermocouple will be inspected and calibrated at least quarterly to ensure the thermocouple is 

functioning properly. Additionally, since thermocouples must be replaced once they fail (e.g. thermocouple 

can not be readjusted), at least one spare thermocouple will be maintained onsite. 

Annual Burner Inspection

The burner will be inspected and adjusted, if needed, annually to ensure proper operation.

Recordkeeping and Reporting

Monitoring Report

A semi-annual monitoring report will be submitted to the Indiana Department of Environmental 

Management (IDEM). The report will include the following:

1. Dates and times of any exceedance;

2. The corrective action taken for each reported discrepancy, including the time corrective action 

was initiated, the time corrective action was completed, and a description of the corrective action.

Site Record Retention

The following information will be retained at the site:

1. Continuous (i.e. every 15 minutes) combustion chamber temperature and annual inspection logs.

Quality Improvement Plan Implementation

A Quality Improvement Plan (QIP) will be initiated if the following thresholds are exceeded:

A. More than 5 excursions of minimum combustion chamber temperature are recorded in a 6-month 

period (from all units addressed under this Plan).
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Rockport, Indiana Appendix D PSD and TV Permit No.:147-30464-00060

Permit Reviewer: Josiah Balogun

If the QIP threshold is exceeded, a QIP will be developed and implemented as expeditiously as 

possible and shall notify IDEM if QIP development will require more than 180 days.

Justification for Monitoring Measurements

The design of thermal oxidation systems is dependent on pollutant concentration, type of pollutant, 

oxygen concentration, waste gas stream flow rate and the degree of control required. Important design

factors include temperature high enough to ignite the pollutant, turbulence or mixing or the combustion air 

and waste gas and sufficient residence time to allow for the combustion reaction to occur. Of these, only 

temperature and oxygen concentration can be sufficiently controlled after design and construction of the 

oxidation system.

The oxygen concentration will be controlled by the excess air flow rate to the burner and annual burner 

inspection will ensure a proper fuel to air mixture. Temperature of combustion systems can be accurately 

monitored with thermocouples or a variety of other devices. Thermocouples are highly reliable, relative 

low cost, widely used, require very little maintenance, and when functioning appropriately, very accurate 

(± 1 to 2%).

Selection of Performance (Trigger) Levels

1. Combustion Chamber Temperature. Minimum combustion chamber temperature.

2. Annual Burner Inspection. Once per calendar year inspection and adjustment, if needed, of the 

RTO burner.

CAM PLAN for Wet Sulfuric Acid Plant

Background on Affected Emission Units

Emission Units

The emission unit that is being incorporated into this plan is the WSA Plant (IDEM Emission Unit ID 15) 

which has potential pre-control device emissions of NOx, SO2, and H2SO4 greater than 100 tons per year, 

the major source threshold.

Applicable Regulations

Indiana State regulation 326 IAC 2-2-3 requires an analysis of Best Available Control Technology (BACT) 

to determine an appropriate limitation for the emissions of PSD-applicable pollutants from a new major 

source. As an emission limit, BACT for this emission unit is proposed equivalent to 0.15 pounds of H2SO4

emissions and 0.25 pounds SO2 per ton of acid produced and 10.7 pounds of NOx per hour from each of 

the two processing trains. SO2 and H2SO4 mist emissions will be controlled to this level through the 

design of the WSA unit (which includes high efficiency drift eliminators) and by using a Hydrogen Peroxide 

Scrubber, which is proposed as BACT. Similarly, NOx will be controlled to this level by employing 

Selective Catalytic Reduction (SCR) technology, which is proposed as BACT.

Control Devices

A hydrogen peroxide scrubber is a wet scrubber that uses hydrogen peroxide in solution as a scrubbing 

medium. Sulfur containing compounds (SO2/H2SO4) in the inlet gas stream are absorbed by the 

hydrogen peroxide.

SCR is a catalyst system. A reducing agent, in this case anhydrous ammonia, is injected into the exhaust 

upstream of the catalyst bed to enhance conversion of NOx into diatomic nitrogen, N2 and water.
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Rockport, Indiana Appendix D PSD and TV Permit No.:147-30464-00060

Permit Reviewer: Josiah Balogun

Description of Monitoring Procedures

The parameters to be monitored are as follows:

(a) Hydrogen Peroxide flow rate (to the hydrogen peroxide scrubber)

(b) NOx emission rate (in the final exhaust stack).

Hydrogen Peroxide Flow Rate

The Hydrogen Peroxide flow rate from the hydrogen peroxide scrubber will be recorded with a flow meter 

once per operating day (minimum). The following information will be noted on a log form.

 Emission Unit ID

 Observer’s Name

 Date and Time

 Flow rate

NOx Emission Rate

The NOx emission rate in the final exhaust stack will be directly measured by a continuous emission 

monitor (CEM). 

Emission Unit Performance Criteria

The performance criteria for the emission unit in terms of allowable ranges for the monitored parameters, 

corrective action time periods, maximum number of discrepancies and data availability are summarized 

below:

Performance Range for Monitored Criteria

1. Hydrogen Peroxide Flow Rate. The established performance range for the hydrogen peroxide 

scrubber shall be a recommended flow rate of hydrogen peroxide from the manufacturer, or from 

the design or operating engineers. The minimum flow rate may be established during the 

shakedown period during initial plant performance test.

2. NOx Emission Rate. The NOx emission rate shall not exceed 10.7 pounds per hour from each 

processing train.

Corrective Action Periods

Corrective Action will be initiated according to the following schedule:

Corrective action will be initiated as soon as practically possible using controlled shutdown procedures. 

The deficiency will be rectified before operation of the unit resumes.

Maximum Number of Excursions

1. Hydrogen Peroxide Flow Rate. The maximum number of allowed excursions below the 

recommended flow rate in any reporting period from the hydrogen peroxide scrubber is five (5).

2. NOx Emission Rate. No excursions above the NOx emission limit are allowed.
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Rockport, Indiana Appendix D PSD and TV Permit No.:147-30464-00060

Permit Reviewer: Josiah Balogun

Data Availability

For the hydrogen peroxide scrubber flow rate measurements, the minimum data availability for each semiannual reporting period, defined as the number of days for which monitoring data are available divided by 

the number of days during which the process operated (times 100), will be 90 percent.

Except for system breakdowns, repairs, calibration checks and zero and span adjustments, the NOx CEMs 

shall be in continuous operation when the process is operating. The NOx CEMs shall complete a 

minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-

minute period (except as noted above). 

Quality Control Procedures

The quality control procedures to be implemented as part of the monitoring plan are described below:

Hydrogen Peroxide Flow Rate 

The hydrogen peroxide scrubber’s flow rate will be monitored to achieve the highest removal efficiency for 

the unit. The flow meter will be inspected and calibrated at least quarterly to ensure the device is 

functioning properly. 

NOx CEMs

Although no NSPS applies to this unit, IG proposes to follow the quality control requirements of 40 CFR 

Part 60 Subpart A, 40 CFR Part 60 Appendix B performance specifications 2 and 6, and 40 CFR Part 60 

Appendix F for the NOx CEMs. 

Recordkeeping and Reporting

Monitoring Report

A semi-annual monitoring report will be submitted to the Indiana Department of Environmental 

Management (IDEM). The report will include the following:

1. Dates and times of any exceedance;

2. The corrective action taken for each reported discrepancy, including the time corrective action 

was initiated, the time corrective action was completed, and a description of the corrective action.

Site Record Retention

The following information will be retained at the site:

1. Daily flow rate check logs for the hydrogen peroxide flow rate

2. For each NOx CEM: Records of daily zero and span drift calibrations, dates and descriptions of 

repairs, and CEM readings.

Quality Improvement Plan Implementation

A Quality Improvement Plan (QIP) will be initiated if the following thresholds are exceeded:

A. More than 5 excursions of flow rate are recorded in a 6-month period.

B. More than 1 excursion of the NOx emission rate in a 6-month period.

If the QIP threshold is exceeded, a QIP will be developed and implemented as expeditiously as possible 

and shall notify IDEM if QIP development will require more than 180 days.
Indiana Gasification LLC Page 7 of 7

Rockport, Indiana Appendix D PSD and TV Permit No.:147-30464-00060

Permit Reviewer: Josiah Balogun

Justification for Monitoring Measurements

The hydrogen peroxide scrubber removes SO2 and H2SO4 from an inlet gas stream. A higher hydrogen 

peroxide flow rate is important in achieving the highest removal efficiency. 

CEMs directly measure emission rates and provide the most accurate indication of control device 

performance.

Selection of Performance (Trigger) Levels

1 Hydrogen Peroxide Flow Rate. Minimum flow rate.

2. NOx Emission Rate. Maximum emission rate.
Indiana Department of Environmental Management

Office of Air Quality

Appendix E

Source Background and Description

Source Name: Indiana Gasification, LLC

Source Location: CR 200 N and Base Road, Rockport, IN 47635

County: Spencer

SIC Code: 4925, 2819

Operation Permit No.: T 147-30464-00060

Operation Permit Issuance Date: Yet to be Issued

Permit Reviewer: Josiah Balogun
Indiana Gasification, LLC Appendix 

E Page 2 of 6

Rockport, IndianaT147-30464-00060

Permit Reviewer: Josiah Balogun
Indiana Gasification, LLC Appendix 

E Page 3 of 6

Rockport, IndianaT147-30464-00060

Permit Reviewer: Josiah Balogun
Indiana Gasification, LLC Appendix E Page 4 of 6

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

Information Sources: 

SCR costs for modest size heaters obtained from US EPA Petroleum Refinery Tier 2 BACT Analysis 

Report – Final Report at http://epa.gov/ttncaaa1/t1/memoranda/bactrpt.pdf

$1.1 Million Purchased equipment cost estimate from Power Holdings BACT analysis of their Auxiliary 

Boiler is shown on the next page of this Appendix.
Indiana Gasification, LLC Appendix E Page 5 of 6

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

Excerpt from Power Holdings of Ilinios Auxiliary Boiler BACT Analysis – Application page 4-25

(Shows estimate of Purchased Equipment Costs (PE) for SCR for 1294 MMBtu/hr Boiler. Information 

used on graph on previous page in this Appendix.)
Indiana Gasification, LLC Appendix E Page 6 of 6

Rockport, Indiana T147-30464-00060

Permit Reviewer: Josiah Balogun

Costs of LDAR Programs

Costs of Implementing LDAR Program

Source: Petroleum Refinery Tier 2 BACT Analysis Report - Final Report, US EPA, Jan. 16, 2001

EPA Example Costs VOC control with NESHAPS LDAR program (MACT Subpart CC) for various example process Units.

(A) (B) (C ) (D) (E) (F)

Example Process Units in Report

Total 

Components/

unit

Annualized 

Program 

Costs

Annual 

VOC 

tons/yr 

saved

Annual 

Product Value 

taken as Credit 

in annualized 

costs

Annualized 

LDAR costs 

w/o product 

value

Approx. 

Annual LDAR 

program 

$/component

Note 1 Note 2 Note 2 Note 3 (B+D) (E/A)

Large Refinery Hydrotreater 3566 $27,321 120 $11,703 $39,024 $11

Small Refinery Hydrotreater 1771 $10,086 70 $6,827 $16,913 $10

Large Refinery H2U 1056 $11,312 125 $12,191 $23,503 $22

Small Refinery H2U 614 $6,470 68 $6,632 $13,102 $21

Average $16

Component counts include valve, connectors, pumps, etc.

Source of above data is US EPA report "Petroleum Refinery Tier 2 BACT Analysis Report - Final Report, US EPA, Jan. 16, 2001

http://epa.gov/ttncaaa1/t1/memoranda/bactrpt.pdf

Note 1 Components for each example in EPA report shown in Appendix B, Table B-1A and B-1B.

Note 2 Annualized LDAR costs and annual VOC savings (tons/yr) shown in Table 4-3 on page 4-13.

Note 3 Annualized cost in Note 2 (Table 4-3) is reduced by credit taken for value of process fluid ($215/Mg) discussed 

on Page 4-14.

Process Streams

IG Number 

of 

Components Pollutant 

Uncontrolled 

Emissions 

tons/yr

LDAR 

Controlled 

tons/yr

IG Estimated 

LDAR Costs 

per year 

(Note 1)

LDAR CostEffectivene

ss $/ton

Pollutant 

Controlled

Acid Gas Components 88 H2SO4 0.085 0.003 $1,408 $17,005 H2SO4

Costs of a NESHAPS LDAR Program for IG Process Streams

Note 1. LDAR program costs assumed to be $16/yr/component per US EPA 2001 Refinery Tier 2 BACT report 

(see separate summary). Costs do not include separate extra cost for purchase/maintenance of unique monitor 

that would be needed for non-hydrocarbon monitoring (FID not responsive to non-hydrocarbons) 
INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

We Protect Hoosiers and Our Environment. 

Mitchell E. Daniels Jr. 100 North Senate Avenue 

Governor Indianapolis, Indiana 46204 

(317) 232-8603 

Thomas W. Easterly Toll Free (800) 451-6027 

Commissioner www.idem.IN.gov

 Recycled Paper An Equal Opportunity Employer Please Recycle 

SENT VIA U.S. MAIL: CONFIRMED DELIVERY AND SIGNATURE REQUESTED 

TO: Mark Lubbers 

Indiana Gasification LLC 

PO Box 55934 

Indianapolis, IN 46205 

DATE: June 27, 2012 

FROM: Matt Stuckey, Branch Chief 

 Permits Branch 

 Office of Air Quality 

SUBJECT: Final Decision 

 Title V 

 147-30464-00060 

Enclosed is the final decision and supporting materials for the air permit application referenced above. 

Please note that this packet contains the original, signed, permit documents. 

The final decision is being sent to you because our records indicate that you are the contact person for this 

application. However, if you are not the appropriate person within your company to receive this document, 

please forward it to the correct person. 

A copy of the final decision and supporting materials has also been sent via standard mail to: 

 James Hauck (Attorney Hatchett & Hauck)

 OAQ Permits Branch Interested Parties List 

 If you have technical questions regarding the enclosed documents, please contact the Office of Air Quality, 

 Permits Branch at (317) 233-0178, or toll-free at 1-800-451-6027 (ext. 3-0178), and ask to speak to the 

 permit reviewer who prepared the permit. If you think you have received this document in error, please 

 contact Joanne Smiddie-Brush of my staff at 1-800-451-6027 (ext 3-0185), or via e-mail at 

 jbrush@idem.IN.gov. 

Final Applicant Cover letter.dot 11/30/07 
INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

We Protect Hoosiers and Our Environment. 

Mitchell E. Daniels Jr. 100 North Senate Avenue 

Governor Indianapolis, Indiana 46204 

(317) 232-8603 

Thomas W. Easterly Toll Free (800) 451-6027 

Commissioner www.idem.IN.gov

 Recycled Paper An Equal Opportunity Employer Please Recycle 

June 27, 2012

TO: Spencer 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: Indiana Gasification LLC 

 Permit Number: 147-30464-00060 

You previously received information to make available to the public during the public comment 

period of a draft permit. Enclosed is a copy of the final decision and supporting materials for the 

same project. Please place the enclosed information along with the information you previously 

received. To ensure that your patrons have ample opportunity to review the enclosed permit, we 

ask that you retain this document for at least 60 days. 

The applicant is responsible for placing a copy of the application in your library. If the permit 

application is not on file, or if you have any questions concerning this public review process, 

please contact Joanne Smiddie-Brush, OAQ Permits Administration Section at 1-800-451-6027, 

extension 3-0185. 

Enclosures 

Final Library.dot 11/30/07 

 
INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEMENT

We Protect Hoosiers and Our Environment. 

Mitchell E. Daniels Jr. 100 North Senate Avenue 

Governor Indianapolis, Indiana 46204 

(317) 232-8603 

Thomas W. Easterly Toll Free (800) 451-6027 

Commissioner www.idem.IN.gov

 Recycled Paper An Equal Opportunity Employer Please Recycle 

TO: Interested Parties / Applicant 

DATE: June 27, 2012

RE: Indiana Gasification LLC / 147-30464-00060 

FROM: Matthew Stuckey, Branch Chief 

 Permits Branch 

 Office of Air Quality 

In order to conserve paper and reduce postage costs, IDEM’s Office of Air Quality is 

now sending many permit decisions on CDs in Adobe PDF format. The enclosed CD 

contains information regarding the company named above.

This permit is also available on the IDEM website at: 

http://www.in.gov/ai/appfiles/idem-caats/

If you would like to request a paper copy of the permit document, please contact IDEM’s 

central file room at: 

Indiana Government Center North, Room 1201 

100 North Senate Avenue, MC 50-07 

Indianapolis, IN 46204 

Phone: 1-800-451-6027 (ext. 4-0965) 

Fax (317) 232-8659 

Please Note: If you feel you have received this information in error, or would like to be 

removed from the Air Permits mailing list, please contact Patricia Pear with the Air 

Permits Administration Section at 1-800-451-6027, ext. 3-6875 or via e-mail at 

PPEAR@IDEM.IN.GOV. 

Enclosures 

CD Memo.dot 11/14/08
FACSIMILIE OF PS Form 3877 

Mail Code 61-53 

IDEM Staff CDENNY 6/26/2012 

Indiana Gasification LLC 147-30464 -00060(final) AFFIX STAMP 

HERE IF USED AS CERTIFICATE OF MAILING 

Name and address of Sender ► Indiana Department of Environmental Management Office of Air Quality – Permits Branch 

100 N. Senate Indianapolis, IN 46204 

Type of Mail: 

CERTIFICATE OF 

MAILING ONLY 

Line Article 

Number 

Name, Address, Street and Post Office Address Postage Handing 

Charges 

Act. Value (If Registered) 

Insured Value 

Due Send if COD 

RF

1 Mark Lubbers Indiana Gasification LLC PO Box 55934 Indianapolis IN 46205 (Source CAATS) 2 Thomas Mara President Indiana Gasification LLC 315 Park Ave South, 20th Floor New York NY 10010-3607 (RO CAATS)3 Mr. Wendell Hibdon Plumbers & Steam Fitters Union, Local 136 2300 St. Joe Industrial Park Dr Evansville IN 47720 (Affected Party)4 Ms. Francis Lueken 223 W. 10th Street, P.O. Box 206 Ferdinand IN 47532 (Affected Party)5 Mr. Wayne Werne 10185 E SR 62 Ferdinand IN 47532 (Affected Party)6 Ms. Donna R. Martin 1524 S Old State Road 45 Rockport IN 47635 (Affected Party)7 Rockport City Council and Mayors Office P.O. Box 151 Rockport IN 47635 (Local Official)8 Spencer Co Public Library 210 N Walnut St Rockport IN 47635-1398 (Library)9 Mr. Thomas Utter Lincolnland Economical Development Corporation PO Box 400 Santa Claus IN 47579 (Affected Party)10 Ms. Kathy Tretter Dubois-Spencer Counties Publishing Co, Inc P.O. Box 38 Ferdinand IN 47532-0038 (Affected Party)11 Mr. Rex Winchell 715 W. Old SR 45 Rockport IN 47635 (Affected Party)12 Mr. Larry E. Sigler 668 East C.R. 700 North Chrisney IN 47611-9315 (Affected Party)13 Spencer County Commissioners 200 Main St., Courthouse Rockport IN 47635 (Local Official) 14 Spencer County Health Department Main Street Courthouse, 1st Floor, Room 1 Roackport IN 47635-1492 (Health Department)15 Mr. Mark Wilson Evansville Courier & Press P.O. Box 268 Evansville IN 47702-0268 (Affected Party)Total number of pieces Listed by Sender 

Total number of Pieces Received at Post Office 

Postmaster, Per (Name of Receiving employee) 

The full declaration of value is required on all domestic anmaximum indemnity payable for the reconstruction of nonMail document reconstructing insurance is $50,000 per pioccurrence. The maximum indemnity payable on ExpresThe maximum indemnity payable is $25,000 for registereinsurance. See Domestic Mail Manual R900, S913, an

inured and COD mail. See International Mail Manual fomail. Special handling charges apply only to Standard Ma
FACSIMILIE OF PS Form 3877 

Mail Code 61-53 

IDEM Staff CDENNY 6/26/2012 

Indiana Gasification LLC 147-30464 -00060(final) AFFIX STAMP 

HERE IF USED AS CERTIFICATE OF MAILING 

Name and address of Sender ► Indiana Department of Environmental Management Office of Air Quality – Permits Branch 

100 N. Senate Indianapolis, IN 46204 

Type of Mail: 

CERTIFICATE OF 

MAILING ONLY 

Line Article 

Number 

Name, Address, Street and Post Office Address Postage Handing 

Charges 

Act. Value (If Registered) 

Insured Value 

Due Send if COD 

RF

1 James M. Hauck Hatchett & Hauck 111 Monument Circle Suite 301 Indianapolis IN 46204 (Attorney) (PICKED UP IN PERSON) 2 Mr. John Blair 800 Adams Ave Evansville IN 47713 (Affected Party)3 Eager Development PO Box 1612 Owensboro KY 42302 (Affected Party)4 Lincolnland Ecanomic Development PO Box 276 Rockport IN 47635 (Affected Party)5 Indiana Michigan Power Company P.O. Box 16428 Columbus OH 43216 (Affected Party)6 Mason & Don Foertsch P.O. Box 16 Lamar IN 47500 (Affected Party)7 Jasper Properties, LLC PO Box 162 Jasper IN 47547 (Affected Party)8 Kingdom Hall of Jehovahs Witnesses 1038 N. SR 66 Rockport IN 47635 (Affected Party)9 Gregory & Mary James 1062 N. SR 66 Rockport IN 47635 (Affected Party)10 Trustees of The Apostolic Bible Church 713 Jefferson Rockport IN 47635 (Affected Party)11 Sylvester W & Agnes R Dilger Revocatble Trust 676 N Meadowland Dr Rockport IN 47635 (Affected Party)12 Hurm Farms Inc 371 E CR 200 N Rockport IN 47635 (Affected Party)13 Miramonte Property Mgmt LLC PO Box 10 Hebron OH 43025-0010 (Affected Party) 14 Michael D & Wanda L Toler 93 E CR 200 N Rockport IN 47635 (Affected Party)15 Commonwealth Aluminum Concast 25825 Science Park Dr, Ste 400 Beachwood OH 44122-7392 (Affected Party)Total number of pieces Listed by Sender 

Total number of Pieces Received at Post Office 

Postmaster, Per (Name of Receiving employee) 

The full declaration of value is required on all domestic anmaximum indemnity payable for the reconstruction of nonMail document reconstructing insurance is $50,000 per pioccurrence. The maximum indemnity payable on ExpresThe maximum indemnity payable is $25,000 for registereinsurance. See Domestic Mail Manual R900, S913, an

inured and COD mail. See International Mail Manual fomail. Special handling charges apply only to Standard Ma
FACSIMILIE OF PS Form 3877 

Mail Code 61-53 

IDEM Staff CDENNY 6/26/2012 

Indiana Gasification LLC 147-30464 -00060(final) AFFIX STAMP 

HERE IF USED AS CERTIFICATE OF MAILING 

Name and address of Sender ► Indiana Department of Environmental Management Office of Air Quality – Permits Branch 

100 N. Senate Indianapolis, IN 46204 

Type of Mail: 

CERTIFICATE OF 

MAILING ONLY 

Line Article 

Number 

Name, Address, Street and Post Office Address Postage Handing 

Charges 

Act. Value (If Registered) 

Insured Value 

Due Send if COD 

RF

1 Nancy Shelton & Leona Matthews 418 S Lincoln Ave Rockport IN 47635 (Affected Party) 2 Raymond & Patricia L Dawson 319 E CR 250 N Rockport IN 47635 (Affected Party)3 Owen C & Katherine Robinson 419 E CR 250 N Rockport IN 47635 (Affected Party)4 State of Indiana 3650 S US Hwy 41 Vincennes IN 47759 (Affected Party)5 Crown Communications Inc 4017 Washington Rd McMurray PA 15317 (Affected Party)6 Coal Inland Inc 1111 Western Row Rd Mason OH 45040 (Affected Party)7 Reo Properties LLC PO Box 27 Handerson KY 42419 (Affected Party)8 Rainbow Development Corp 4100 N Silverdale Rd Rockport IN 47635 (Affected Party)9 Landmark Bible Church 1124 N SR 66 Rockport IN 47635 (Affected Party)10 Mulzer Crushed Stone PO Box 249 Tell City IN 47586 (Affected Party)11 Bernard J Jr. & Mary Martha Hurm 2862 N Old State Rd Rockport IN 47635 (Affected Party)12 Sidney R Lindsey Life Estate 217 Main St Rockport IN 47635 (Affected Party)13 Spencer County Sand LLC PO Box 2428 Clarksville IN 47131 (Affected Party) 14 Norfolk Southern Railroad 1200 Peachtree St, Box 7-142 Atlanta GA 30309-3579 (Affected Party)15 Kathryn Williams & Laurel Montgomery 1837 Towington Dr Raliegh NC 27615 (Affected Party)Total number of pieces Listed by Sender 

Total number of Pieces Received at Post Office 

Postmaster, Per (Name of Receiving employee) 

The full declaration of value is required on all domestic anmaximum indemnity payable for the reconstruction of nonMail document reconstructing insurance is $50,000 per pioccurrence. The maximum indemnity payable on ExpresThe maximum indemnity payable is $25,000 for registereinsurance. See Domestic Mail Manual R900, S913, an

inured and COD mail. See International Mail Manual fomail. Special handling charges apply only to Standard Ma
FACSIMILIE OF PS Form 3877 

Mail Code 61-53 

IDEM Staff CDENNY 6/26/2012 

Indiana Gasification LLC 147-30464 -00060(final) AFFIX STAMP 

HERE IF USED AS CERTIFICATE OF MAILING 

Name and address of Sender ► Indiana Department of Environmental Management Office of Air Quality – Permits Branch 

100 N. Senate Indianapolis, IN 46204 

Type of Mail: 

CERTIFICATE OF 

MAILING ONLY 

Line Article 

Number 

Name, Address, Street and Post Office Address Postage Handing 

Charges 

Act. Value (If Registered) 

Insured Value 

Due Send if COD 

RF

1 C Wayne Mastin, Sharon Greene & Darlene Richey 2611 S CR 350 W Rockport IN 47635 (Affected Party) 2 Ms. April Tuley/Gray 602 S CR 200 N Rockport IN 47635 (Affected Party)3 Larry J & Melina S Hurm 1848 N CR 200 W Rockport IN 47635 (Affected Party)4 Richard Family LLC 788 W SR 66 Rockport IN 46735 (Affected Party)5 Dan & Jessee Rininger 1001 N Silverdale Rd Rockport IN 47635 (Affected Party)6 Gilbert H Hartig Life Estate 7824 Middle Mt Vernon Rd Evansville IN 47712 (Affected Party)7 Harlan Lehr 1441 N Base Rd Rockport IN 47635 (Affected Party)8 Cleon Hurm 4127 W Eureka Rd Rockport IN 47635 (Affected Party)9 Mr. Roger Hurm 3610 N Silverdale Rd Rockport IN 47635 (Affected Party)10 Mr. Donald Schroeder 2281 W CR 350 S Rockport IN 46735 (Affected Party)11 Michael & Janice Cochenour 349 E CR 350 N Rockport IN 47635 (Affected Party)12 Paul Schulte 4100 Silverdale Rd. Rockport IN 47635 (Affected Party)13 Town Council and Town of Grandview 316 Main St. Grandview IN 47615 (Affected Party) 14 Quinn Bowden 1100 W 42nd St # 218 Indianapolis IN 46208 (Affected Party)15 Rock Blanchard 6539 W CR 400 N Richland City IN 47634 (Affected Party)Total number of pieces Listed by Sender 

Total number of Pieces Received at Post Office 

Postmaster, Per (Name of Receiving employee) 

The full declaration of value is required on all domestic anmaximum indemnity payable for the reconstruction of nonMail document reconstructing insurance is $50,000 per pioccurrence. The maximum indemnity payable on ExpresThe maximum indemnity payable is $25,000 for registereinsurance. See Domestic Mail Manual R900, S913, an

inured and COD mail. See International Mail Manual fomail. Special handling charges apply only to Standard Ma
FACSIMILIE OF PS Form 3877 

Mail Code 61-53 

IDEM Staff CDENNY 6/26/2012 

Indiana Gasification LLC 147-30464 -00060(final) AFFIX STAMP 

HERE IF USED AS CERTIFICATE OF MAILING 

Name and address of Sender ► Indiana Department of Environmental Management Office of Air Quality – Permits Branch 

100 N. Senate Indianapolis, IN 46204 

Type of Mail: 

CERTIFICATE OF 

MAILING ONLY 

Line Article 

Number 

Name, Address, Street and Post Office Address Postage Handing 

Charges 

Act. Value (If Registered) 

Insured Value 

Due Send if COD 

RF

1 Angela PO Box 213 Santa Claus IN 47579 (Affected Party) 2 Marvin Byrer 2166 E Tennessee Evansville IN 47711 (Affected Party)3 James Lacy Kamuf 117 E 18th St PMB #125 Owensboro KY 42301 (Affected Party)4 Mickey Toler 1617 N CR 312 W Rockport IN 47635 (Affected Party)5 Harold Goffinet 426 Main St Rockport IN 47635 (Affected Party)6 Alton Goodwin 2368 N Silverdale Rd Rockport IN 47635 (Affected Party)7 Ferman Yearby 313 Elm St Rockport IN 47635 (Affected Party)8 Chuck Botsko 12540 N Base Rd Gentryville IN 47537 (Affected Party)9 Jean Dolezal 8401 E SR 70 Evanston IN 47531 (Affected Party)10 N Ryan Zaricki 1001 Oliver Rd N Wadesville IN 47638 (Affected Party)11 Wallace McMullen 12907 Sunnybrook Dr Prospect KY 40059 (Affected Party)12 Ben Taylor 419 Yel-G-View Rd Maceo KY 42355 (Affected Party)13 Thomas Pearce 223 E Ornsby Ave Louisville KY 40203 (Affected Party) 14 William Rosenberg 508 Queensferry Rd Gary NC 27511 (Affected Party)15 Joseph Begle 2340 E CR 1600 N Lincoln City IN 47552 (Affected Party)Total number of pieces Listed by Sender 

Total number of Pieces Received at Post Office 

Postmaster, Per (Name of Receiving employee) 

The full declaration of value is required on all domestic anmaximum indemnity payable for the reconstruction of nonMail document reconstructing insurance is $50,000 per pioccurrence. The maximum indemnity payable on ExpresThe maximum indemnity payable is $25,000 for registereinsurance. See Domestic Mail Manual R900, S913, an

inured and COD mail. See International Mail Manual fomail. Special handling charges apply only to Standard Ma
FACSIMILIE OF PS Form 3877 

Mail Code 61-53 

IDEM Staff CDENNY 6/26/2012 

Indiana Gasification LLC 147-30464 -00060(final) AFFIX STAMP 

HERE IF USED AS CERTIFICATE OF MAILING 

Name and address of Sender ► Indiana Department of Environmental Management Office of Air Quality – Permits Branch 

100 N. Senate Indianapolis, IN 46204 

Type of Mail: 

CERTIFICATE OF 

MAILING ONLY 

Line Article 

Number 

Name, Address, Street and Post Office Address Postage Handing 

Charges 

Act. Value (If Registered) 

Insured Value 

Due Send if COD 

RF

1 Mark 11329 E SR 32 Zionsville IN 46077 (Affected Party) 2 Vicki Johnson 101 N 9th St Rockport IN 47635 (Affected Party)3 David Weber 6752 N 250 W Chrisney IN 47611 (Affected Party)4 Steve McNamara 332 S Second Rockport IN 47635 (Affected Party)5 Leslie Wiggins 5313 Old Boonville Hwy Evansville IN 47715 (Affected Party)6 Mark Osborne 5055 Jamestown Dr Newburgh IN 47630 (Affected Party)7 Becky Haaff 5341 W CR 200 S Rockport IN 47635 (Affected Party)8 Brandon Ferguson 1124 Ravenswood Dr Evansville IN 47714 (Affected Party)9 Tom Garrett 5313 Old Booneville Hwy Evansville IN 47715 (Affected Party)10 Beth Macke 4713 Housebridge Rd Corydon KY 42406 (Affected Party)11 Jim Werner 2646 N Burkhardt Rd Evansville IN 47715 (Affected Party)12 James Hunsicker 11686 US 231 S Dale IN 47523 (Affected Party)13 Paul Morsey 2437 Pleasant Valley Rd Owensboro KY 42303 (Affected Party) 14 William Bailey 841 South Rockport IN 47635 (Affected Party)15 Agnes Dilger 676 N Meadowland Dr Rockport IN 47635 (Affected Party)Total number of pieces Listed by Sender 

Total number of Pieces Received at Post Office 

Postmaster, Per (Name of Receiving employee) 

The full declaration of value is required on all domestic anmaximum indemnity payable for the reconstruction of nonMail document reconstructing insurance is $50,000 per pioccurrence. The maximum indemnity payable on ExpresThe maximum indemnity payable is $25,000 for registereinsurance. See Domestic Mail Manual R900, S913, an

inured and COD mail. See International Mail Manual fomail. Special handling charges apply only to Standard Ma
FACSIMILIE OF PS Form 3877 

Mail Code 61-53 

IDEM Staff CDENNY 6/26/2012 

Indiana Gasification LLC 147-30464 -00060(final) AFFIX STAMP 

HERE IF USED AS CERTIFICATE OF MAILING 

Name and address of Sender ► Indiana Department of Environmental Management Office of Air Quality – Permits Branch 

100 N. Senate Indianapolis, IN 46204 

Type of Mail: 

CERTIFICATE OF 

MAILING ONLY 

Line Article 

Number 

Name, Address, Street and Post Office Address Postage Handing 

Charges 

Act. Value (If Registered) 

Insured Value 

Due Send if COD 

RF

1 John 6830 Roosevelt Ave Franklin OH 45005 (Affected Party) 2 David Boggs 216 Western Hills Dr Mt Vernon IN 47620 (Affected Party)3 4 5 6 7 8 9 10 11 12 13 14 15 Total number of pieces Listed by Sender 

Total number of Pieces Received at Post Office 

Postmaster, Per (Name of Receiving employee) 

The full declaration of value is required on all domestic anmaximum indemnity payable for the reconstruction of nonMail document reconstructing insurance is $50,000 per pioccurrence. The maximum indemnity payable on ExpresThe maximum indemnity payable is $25,000 for registereinsurance. See Domestic Mail Manual R900, S913, an

inured and COD mail. See International Mail Manual fomail. Special handling charges apply only to Standard Ma