## I NDIANA 

## D EPARTMENT OF 

## E NVIRONMENTAL 

## M ANAGEMENT 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

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 

## 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 effe ctiveness 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 an d IC 13-15-6-1(b) or IC 13-15-6-1(a) require that you file a petition for administrative review. This pe tition 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 re view 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 comp lete on the earliest of the following dates that apply to the filing: (1) the date the document is delivered to the Office of Environmental Adjudication (OEA); (2) the date of the postmark on the envelope contai ning the document, if the document is mailed to OEA by U.S. mail; or (3) The date on which the document is deposited with a private carrier, as shown by receipt issued by the carrier, if the document is sent to the OEA by private carrier.

The petition must include facts demonstrating that you are either the applicant, a person aggrieved or adversely affected by the decision or otherwise entitled to review by law. Please identify the permit, decision, or other order for which you seek review by permit number, name of the applicant, location, date of this notice and all of the following:(1) the name and address of the person making the request; (2) the interest of the person making the request; (3) identification of any persons repres ented by the person making the request; (4) the reasons, with particularity, for the request; (5) the issues, with particularity, proposed for considerations at any hearing; and (6) identification of the terms and conditions wh ich, in the judgment of the person making the request, would be appropriate in the case in question to satisfy the requirements of the law governing documents of the type issued by the Commissioner.

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 modifica tion within sixty (60) days of the end of the fortyfive (45) day EPA review period. Such an objection mu st 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 iss uance 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 enclos ed documents, please contact the Office of Air Quality, Permits Branch at (317) 233-0178. Calle rs from within Indiana may call toll-free at 1-800-451- 6027, ext. 3-0178.

Enclosures FNTVOP.dot12/3/07Indiana 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 EU

012M, 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 S

012T th rough 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 EU

012Z, 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, S

012AB and S

- 012AC, respectively;

(j) One (1) truck hopper unloading to the conveyor belts, identified as EU

012AA, 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 an d 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, to be p ermitted 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, eachIndiana Gasification, LLC Page 3 of 6 Rockport, IN PSD/Part 70 Permit No. 147

- 30464

- 00060

nominally rated at 3 3 ,7 6 0 dscfm, exhausting through two (2) stacks, ident ified 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 source s .]

(C ) One (1) syngas hydrocarbon flare, with a pilot nominally rated at 0.2 7 MMBtu/hr HHV and identified as EU

- 001, to be permitted in 2012

, exhausting through o ne ( 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

, exhaust ing 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, H 2 S, 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 ) stack s , identified as S

- 007 A and S

- 007B

. (F ) Two (2) Wet Sulfuric Acid (WSA) plant trains, each nominally rated at 800 stpd H 2 S O 4 and identified as EU

- 015A and EU

- 015B, to be permitted in 2012, with NO x , SO 2 , H 2 SO 4 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 i dentified 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 NO x emissions controlled by ultra

- low NO x burners/Flue Gas Recir culation (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 sour ce s .]

(H) Five (5) natural gas

- fired and SNG fuel

- fired gasifier prehe at burners, each nominally rated with a heat input of 35.00 MMBtu/hr HHV, and identified as EU

- 008A through EU

008E, to be permitted in 2012

, exhausting through five (5) vents, identified as S

- 008A through S

- 008E, respectively.

(I) One (1) ZLD

- Spray Dry er, 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 NO x 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, ide ntified 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].

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

- ROAD. (L) Electrical Circuit Breakers (approximately six) containing sulfur hexafluoride (SF 6 )Indiana Gasification, LLC Page 4 of 6 Rockport, IN PSD/Part 70 Permit No. 147

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- 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, CO 2 compression, WSA and methanation are identified as emissions unit s FUG and FUG

W SA 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 th rough 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 ho rsepower, 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 sourc e.][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 dies el 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 ex hausting 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 E U

- 017A and EU

- 017B, to be permitted in 2012

, exhausting through two (2) vents, identified as S

017A 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 f ugitive particulate emissions controlled by wet suppression.

(h) One (1 ) front

- end loader activit y 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 control led 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) pressuri zed 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 nomi nal capacity of 866

, 5 00 gallons

- i dentified 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 s crubbers 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 pe rmitted 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 con struction 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 Indi ana 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 receip t of this approval or if construction is suspended for a continuous period of one (1) year or

more.Indiana Gasification, LLC Page 2 of 152 Rockport , Indiana T147

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

- 7

- 1(21)][326 IAC 2

- 7

- 4(c)] [326 IAC 2

- 7

- 5(1 4 )] A.4 Part 70 Permit Applicability [326 IAC 2

- 7

- 2]

B. GENERAL CON DITIONS 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 Certif ication [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(1 2 ) ] [326 IAC 1

- 6

- 3] B.13 Emergency Provisions [326 IAC 2

- 7

- 16] B.14 Permit Shield [32 6 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 Te rmination [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. S OURCE 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 Ope n Burning [326 IAC 4

- 1] [IC 13

- 17

- 9] C.4 Incineration [326 IAC 4

- 2] [326 IAC 9

- 1

- 2]Indiana Gasification, LLC Page 3 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun
C.5 Fugitive Dust Emissions [326 IAC 6

- 4] C.6 Fugitive Particulate Matter Emission Limitation s [326 IAC 6

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

- 7] C.8 Asbestos Abatement Proj ects [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 R equirements [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(1 1 )] [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 R elated 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 Req uirements [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]

Stratosph eric 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 M o dification to Co nstruction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)] D.1.4 PM, PM 10 and PM 2.5 PSD BACT [326 IAC 2

- 2

- 3 ] D.1.5 Preventive Maintenance Plan [326 IAC 1

- 6

- 3 ]Indiana Gasification, LLC Page 4 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun Compliance Determination Requirements D.1.6 PM , PM 10 and PM 2.5 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 V isible Emission Notation s 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.1.1 3 Record Keeping Requirement s

D.2 . EMISSIONS UNIT OPERATION CONDITI ONS

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 M o dification to Co nstruction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)] D.2.4 PM, PM 10 , PM 2.5 , CO, SO 2 , 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 det ermination 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 Requ irement s

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 M o dification to Co nstruction Conditions [326 IAC 2]Indiana Gasification, LLC Page 5 of 152 Rockport , Indiana T147

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Emissi on Limitations and Standards [326 IAC 2

- 7

- 5(1)] D.3.4 PM, PM 10 , PM 2.5 , CO, SO 2 , 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 Requirement s

D.4 . EMISSIONS UNIT OPERATION CONDITIONS

General Const ruction 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 M o dification to Co nstruction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)] D.4.4 PM, PM 10 an d PM 2.5 PSD BACT [326 IAC 2

- 2

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

- 2

- 3 ] D.4.6 SO 2 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 Alternat e 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, PM 10 and PM 2.5 Calculations [326 IAC 2

- 2] D.4.1 4 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 Req uirements [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]Indiana Gasification, LLC Page 6 of 152 Rockport , Indiana T147

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- 7

- 5(3)] [326 IAC 2

- 7

- 19] D.4 .2 4 Record Keeping Requirement s D.4.25 Re portin g Requirement s

D.5 . EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions D.5 .1 Permit No Defense

Effective Date of the Permit D.5 .2 Effective Da te of the Permit [IC 13

- 15

- 5

- 3 ] D.5 .3 M o dification to Co nstruction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)] D.5.4 PM, PM 10 and PM 2.5 PSD BACT [326 IAC 2

- 2

- 3 ] D.5.5 H 2 SO 4 PSD BACT [326 IAC 2

- 2

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

- 2

- 3 ] D.5.7 SO 2 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 Det ermination Requirements D.5 .1 2 Nitrogen Oxide Control D.5 .1 3 Sulfur Dioxide Control D.5 .1 4 PM, PM 10 , PM 2.5 and H 2 SO 4 Control D.5 .1 5 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

. 2 0 Record Keeping Requirement s D.5.21 Re portin g Requirement s

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 Pe rmit [IC 13

- 15

- 5

- 3 ] D.6 .3 M o dification to Co nstruction Conditions [326 IAC 2]Indiana Gasification, LLC Page 7 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)] D.6 .4 PM, PM 10 and PM 2.5 PSD BACT [326 IAC 2

- 2

- 3 ] D.6 .5 CO PSD BACT [326 IAC 2

- 2

- 3 ] D.6 .6 SO 2 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 .1 2 Nitrogen Oxi de Control D.6 .1 3 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 Requirement s D.6.18 Re portin g Requirement s

D.7 . EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions D.7 .1 Permit No Defense

Effective Date of the Per mit D.7 .2 Effective Date of the Permit [IC 13

- 15

- 5

- 3 ] D. 7 .3 M o dification to Co nstruction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)] D.7.4 PM, PM 10 and PM 2.5 PSD BACT [326 IAC 2

- 2

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

- 2

- 3 ] D.7 .6 SO 2 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

. 1 2 Record Keeping Requirement s D.7.1 3 Re portin g Requirement sIndiana Gasification, LLC Page 8 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun
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 M o dification to Co nstruction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)] D.8.4 PM, PM 10 and PM 2.5 PSD BACT [326 IAC 2

- 2

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

- 2

- 3 ] D.8.6 SO 2 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 .1 0 Nitrogen Ox ide Control D.8.11 Compliance Determination Requirements D.8 .1 2 PM, PM 10 and PM 2.5 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 Requiremen ts [326 IAC 2

- 7

- 5(1)][326 IAC 2

- 7

- 6(1)] D.8.16 Visible Emission Notation D.8 .1 7 Parametric Monitoring

Record Keeping and Reporting Requirements [326 IAC 2

- 7

- 5(3)] [326 IAC 2

- 7

- 19] D.8

. 18 Record Keeping Requirement s D.8.19 Re portin g Requirement s

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 M o dification to Co nstruction Conditions [326 IAC 2]

Emission Limitations a nd Standards [326 IAC 2

- 7

- 5(1)] D.9.4 PM, PM 10 , PM 2.5 , CO, SO 2 , 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 CalculationsIndiana Gasification, LLC Page 9 of 152 Rockport , Indiana T147

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Record Keeping a nd Reporting Requirements [326 IAC 2

- 7

- 5(3)] [326 IAC 2

- 7

- 19] D.9.7 Record Keeping Requirement s D.9.8 Re portin g Requirement s

D.1 0 . EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions D.1 0 .1 Permit No Defense Effective Date of the Permit D.1 0 .2 Effective Date of the Permit [IC 13

- 15

- 5

- 3 ] D.1 0 .3 M o dification to Co nstruction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)] D.10.4 PM, PM 10 and PM 2.5 PSD BACT [326 IAC 2

- 2

- 3 ]

Compliance Determination Requirement s D.10.5 PM, PM 10 and PM 2.5 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.1 0

. 7 Record Keeping R equirement s

D.1 1 . EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions D. 1 1.1 Permit No Defense

Effective Date of the Permit D. 1 1.2 Effective Date of the Permit [IC 13

- 15

- 5

- 3 ] D.1 1 .3 M o dification to Co nstruction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)] D.11.4 PM, PM 10 and PM 2.5 PSD BACT [326 IAC 2

- 2

- 3 ] D.11.5 PM, PM 10 and PM 2.5 PSD BACT [326 IAC 2

- 2

- 3 ]

D.1 2 . EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions D.1 2 .1 Permit No Defens e

Effective Date of the Permit D.1 2 .2 Effective Date of the Permit [IC 13

- 15

- 5

- 3 ] D.1 2 .3 M o dification to Co nstruction Conditions [326 IAC 2]Indiana Gasification, LLC Page 10 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)] D.1 2.4 PM, PM 10 and PM 2.5 PSD BACT [326 IAC 2

- 2

- 3 ]

Com pliance 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.1 2

. 7 Record Keeping Requirement s

D.1 3 . EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions D.1 3 .1 Permit No Defense

Effective Date of the Permit D.1 3 .2 Effective Date of the Permit [IC 13

- 15

- 5

- 3 ] D.1 3 .3 M o dification to Co nstruction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)] D.13.4 PM, PM 10 and PM 2.5 PSD BACT [326 IAC 2

- 2

- 3 ]

Compliance Determination Requirements D.13

. 5 Compliance Determination Requirements

Compliance Monitoring Requirements D.13.6 Ambient Temperature Mo nitoring

Record Keeping and Reporting Requirements [326 IAC 2

- 7

- 5(3)] [326 IAC 2

- 7

- 19] D.1 3

. 7 Record Keeping Requirement s

D.1 4 . EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions D.1 4 .1 Permit No Defense

Effective Date of the Permit D.1 4 .2 Effective Date of the Permit [IC 13

- 15

- 5

- 3 ] D.1 4 .3 M o dification to Co nstruction 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 ]Indiana Gasification, LLC Page 11 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
D.1 5 . EMISSIONS UNIT OPERATION CONDITIONS

Gene ral Construction Conditions D.1 5 .1 Permit No Defense

Effective Date of the Permit D.1 5 .2 Effective Date of the Permit [IC 13

- 15

- 5

- 3 ] D.1 5 .3 M o dification to Co nstruction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)] D.15. 4 CO, H 2 SO 4 and SO 2 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.1 5

. 6 Record Keeping Requirement s

D.1 6 . EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions D.1 6 .1 Permit No Defense Effective Date of the Permit D.1 6 .2 Effective Date of the Permit [IC 13

- 15

- 5

- 3 ] D.1 6 .3 M o dification to Co nstruction Conditions [326 IAC 2]

Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)] D. 16.4 H 2 SO 4 PSD BACT [326 IAC 2

- 2

- 3 ]

D.1 7 . EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions D.1 7 .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 M o dification to Co nstruction C onditions [326 IAC 2]

Compliance Determination Requirements D.1 7

. 4 Vapor Recovery System

Compliance Monitoring Requirements [326 IAC 2

- 7

- 5(1)][326 IAC 2

- 7

- 6(1)] D.1 7 .5 Vapor Recovery System Parametric Monitoring

Record Keeping and Reporting Requiremen ts [326 IAC 2

- 7

- 5(3)] [326 IAC 2

- 7

- 19] D.1 7

. 6 Record Keeping RequirementIndiana Gasification, LLC Page 12 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
D.1 8 . EMISSIONS UNIT OPERATION CONDITIONS

General Construction Conditions D.1 8 .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 M o dification to Co nstruction 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.1 8 .5 Parametr ic Monitoring

Record Keeping and Reporting Requirements [326 IAC 2

- 7

- 5(3)] [326 IAC 2

- 7

- 19] D.1 8

. 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 Gene ral 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 1 2] [40 CFR Part 60, Subpart Db ]

E.2 . EMISSIONS UNIT OPERATION CONDITIONS

N ew 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 1 2] [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 Stand ard of performance Coal Preparation and Processing Plants Requirements [326 IAC 1 2] [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 1 2] [40 CFR Part 60, Subpart IIII]Indiana Gasification, LLC Page 13 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun
E.5 . EMISSIONS UNIT OPERATION CONDITIONS

Nationa l 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 ZZZ Z]

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 D eviation 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 PlanIndiana Gasification, LLC Page 14 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun
SECTION A SOURCE SUMMARY

This permit is based on information requested by the Indiana Departmen t 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 a ware 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 3 26 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(1 4 )][ 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: 31 7

- 49 0

- 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 Categorie s

A.2 Emission Units and Pollution Control Equipment Summary [ 326 IAC 2

- 7

- 4(c)(3)] [ 326 IAC 2

- 7

- 5(1 4 )] This stationary source con sists 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 i ncoming 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 source s .]

(1) One (1) barge un loading to hopper transfer point, permitted in 201 2 , 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
cont rolled 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 EU

012B, permitted in 201 2 , 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, permitted in 201 2 , with four (4) control devices, identified as C

-Indiana Gasification, LLC Page 15 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 012C through C

- 012F, respectively, exhausting through four (4) vents, id entified as S

- 012C through S

- 012F, respectively;

(c) Two (2) rail unloading to rail hoppers, identified as EU

- 012G and EU

012H, permitted in 201 2 , 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 EU

012I and EU

- 012J, permitted in 201 2 , with two (2) control devices, identified as C

- 012I and C

- 012J, respectively, exhau sting 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 201 2 , with one (1) control device, identified as C

- 012K, exhausting through one (1) vent, i dentified as S

- 012K;

(f) Two (2) stacker belts to the radial stacker, identified as EU

- 012L and EU

012M, permitted in 201 2 , with two (2) control devices, identified as C

012L and C

- 012M, respectively, exhausting through two (2) vents, identified as S

- 01 2L through S

- 012M, respectively;

(g) Two (2) classification towers, identified as EU

- 012T and EU

- 012U, permitted in 201 2 , with two (2) control devices, identified as C

- 012T and C

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

012T t hrough 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 statio ns unloading to a truck hopper, identified as EU

012Z, 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 rat ed at 3,000 tons per h our 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.Indiana Gasification, LLC Page 16 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun

(4) Two (2) transfer systems consist ing of hoppers and conveyor belts transferring feed stock from the piles to classification towers, identified as EU

- 012R and EU

012S, permitted in 201 2 , with particulate emissions controlled with two (2) dust extraction systems or baghouse s , 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 201 2 , 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 201 2 , with particulate emissions contro lled 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 201 2 , with particulate emissions controlled by two (2) baghouses identifi ed as C

- 011A and C

- 011B, respectively, each nominally rated at 3 3 ,7 6 0 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 source s .]

(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

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

- 002, permitted in 201 2 , 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, wi th 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 H 2 SO 4 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, H 2 SO 4 , and SO 2 emissions controlled by two (2) hydrogen peroxide scrubbers identified as C

- 015

- 2A and C

- 015

- 2B, respectively, and particulate and H 2 SO 4 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 201 2 , with NO x emissions controlled by ultra

- low NO x burners/Flue Gas Recirculation (ULNB/FGR), with both boilers exhaustingIndiana Gasification, LLC Page 17 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
thro ugh 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 3 5.00 MMBtu/hr HHV, and identified as EU

- 008A through EU

008E, permitted in 201 2 , exhausting through five (5) vents, identified as S

- 008A through S

- 008E, respectively.

(I) One (1) ZLD

- Spray Dryer, permitted in 201 2 , nominally rated at 5.6 MMBtu/hr with
p articulate 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

- In ventory Tank, with a nominal capacity of 700,000 gallons, identified as EU

- 024, permitted in 201 2 , 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 M ethanol Storage Tank, with a nominal capacity of 332,000 gallons, identified as EU

- 025, permitted in 201 2 , 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 Plan t Haul Roads are identified as emissions unit FUG

- ROAD.

(L) Electrical Circuit Breakers (approximately six) containing sulfur hexafluoride (SF 6 ) identified as emissions unit FUG

- SF6, permitted in 201 2 , with fugitive GHG emissions controlled by full encl osure.

(M) Fugitive Equipment Leaks from the gasification, shift conversion, gas cooling, AGR, CO 2 compression, WSA, and methanation are identified as emissions unit FUG and FUG

WSA 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 Insignifican t Activities [ 326 IAC 2

- 7

- 1(21)] [ 326 IAC 2

- 7

- 4(c)] [ 326 IAC 2

- 7

- 5(1 4 )] This stationary source also includes the followi ng 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 CFRIndiana Gasification, LLC Page 18 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 63, Subpart ZZZZ, each, emergency diesel fired generator is considered a n ew 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. [U nder 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, permitt ed in 201 2

, 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 rat e of 5 4

, 960 gpm and identified as EU

- 016A, permitted in 201 2

, 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

, 7 00 gpm and identified as EU

- 016B, permitted in 201 2

, 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 vent s, which each vent a nominal 1 87,000 cubic feet per minute during regenerations, identified as EU

017A and EU

- 017B, permitted in 201 2

, exhausting through two (2) vents, identified as S

017A 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, permi tted 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

, 5 00 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 (Appl icability) 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).Indiana Gasification, LLC Page 19 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun
SECTION B GEN ERAL 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 approv al 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 co nstructed 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 constructio n 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 atta ch the Operation Permit Validation Letter received from t he 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

- 1 5

- 3

- 6(a)] (a) This permit, T14 7

- 3046 4

- 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

- 1 5

- 5

- 3. Sub sequent 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 tim ely 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 pro vided 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 t o 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 pursuan t to Title I of the Clean Air Act; orIndiana Gasification, LLC Page 20 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun

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

B.6 Enforceability [ 326 IAC 2

- 7

- 7] [ IC 13

- 1 7

- 12] Unless oth erwise 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 re mainder 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 p rivilege.

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 reques t 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 kep t 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 asse rt 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 c ertification 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 forme d 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 m ay 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 Per mittee 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 certific ation 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 periodIndiana Gasification, LLC Page 21 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun from January 1 to December 31 of the previous year, and shall be submitted no later th an July 1 of each year to:

Indiana Department of Environmental Management Compliance and Enforcement Branch, Office of Air Quality 100 North Senate Avenue MC 6 1

- 53 IGCN 1003 Indianapolis, Indiana 4620 4

- 2251

and

United States Environmental Protection Age ncy, Region V Air and Radiation Division, Air Enforcement Branch

- Indiana (AE

- 17J) 77 West Jackson Boulevard Chicago, Illinois 6060 4

- 3590

(b) The annual compliance certification report required by this permit shall be considered timely if the date postma rked 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 b efore 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) Whe ther 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 th is 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(1 2 )][ 326 IAC 1

- 6

- 3] (a) If required by specific condition(s) in Section D o f 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;Indiana Gasification, LLC Page 22 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (2) A description of the items or conditions that will be inspected and the inspection schedule for said items or cond itions; 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 ti me 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 6 1

- 53 IGCN 1003 Indianapolis, Indiana 4620 4

- 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 c opy 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 th e 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 ext ent 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 emergen cy, 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;Indiana Gasification, LLC Page 23 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (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 notif ied 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

- 80 0

- 45 1

- 6027 (ask for Office of Air Quality, Compliance and Enforcement Branch), or Telephone Number: 31 7

- 23 3

- 0178 (ask for Office of Air Quality, Compliance and Enforcement Branch) Facsimile Number: 31 7

- 23 3

- 6865 Southeast Regional Office phone: (812) 35 8

- 2027; fax: (812) 35 8

- 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 6 1

- 53 IGCN 1003 Indianapolis, Indiana 4620 4

- 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 th at 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 estab lish the occurrence of an emergency has the burden of proof.Indiana Gasification, LLC Page 24 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (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 Pe rmittee 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 th at 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 th is 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 em ergency 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 d ate 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 requi rements are not applicable. The Indiana statutes from IC 1 3 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 de fense 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 determination s set forth in Section D of this permit, t he IDEM, OAQ has made the following determination s 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.Indiana Gasification, LLC Page 25 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (2) 40 CFR Part 63 Subpart VVVV VV

— 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 th is 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 005 A/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 NSP S 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 n ot 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 D a becaus e 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 D a because 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 stea m 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 Genera ting 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 un its.Indiana Gasification, LLC Page 26 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (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 Subp ar ts 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 st orage tanks listed below are not subject to 40 CFR Part 60, Subpart Ka because the se tanks do not store organic materials and have capacities and maximum true vapor pressure less than 151 cubic meters (m 3 ) and 3.5 kPa

.

EU No. Tank ID Tank Capacity (Gal) M ax. 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 S lag 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 S torage 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 Ta nk 32,243 5.38 No (1) Atmosphere

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

Note: (1) Tank does not store VOCs.Indiana Gasification, LLC Page 27 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
(2) This source is not subject to NSPS Subpart Kb because the tank does not meet the capacity criteria.

(1 1) 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 supplyin g 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.

(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 )

. P ursuant 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 electric ity

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

a n 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 o f 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 tim e 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 Ai r Act; andIndiana Gasification, LLC Page 28 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (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 chang es) 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 T14 7

- 3046 4

- 00060 and issued pursuant to permitting programs approved into the state implementation plan have been either:

(1) inco rporated 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 t his 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) m onths 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 circumstan ces listed in IC 13

- 1 5

- 7

- 2 or if IDEM, OAQ determines any of the following:

(1) That this permit contains a material mistake.Indiana Gasification, LLC Page 29 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (2) That inaccurate statements were made in establishing the emissions standards or other terms or conditions.

(3) That this pe rmit 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
prescr ibed 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 li st 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 submit ted to:

Indiana Department of Environmental Management Permit Administration and Support Section, Office of Air Quality 100 North Senate Avenue MC 6 1

- 53 IGCN 1003 Indianapolis, Indiana 4620 4

- 2251

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

(1) Sub mitted 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. I f 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 spec ified, 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.Indiana Gasification, LLC Page 30 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
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 6 1

- 53 IGCN 1003 Indianapolis, Indiana 4620 4

- 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 ad ministrative 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 Par t 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 Stat e 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 t he Clean Air Act;

(2) Any preconstruction approval required by 326 IAC 2

- 7

- 10.5 has been obtained;Indiana Gasification, LLC Page 31 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (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 term s 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 6 1

- 53 IGCN 1003 Indianapolis, Indiana 4620 4

- 2251

and

Unite d States Environmental Protection Agency, Region V Air and Radiation Division, Regulation Development Branch

- Indiana (AR

- 18J) 77 West Jackson Boulevard Chicago, Illinois 6060 4

- 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 ter m 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

ce rtification that meets the requirements of 326 IAC 2

- 7

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

- 7

- 1(34)

.Indiana Gasification, LLC Page 32 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun

(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 a t 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 spec ifically 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 SO 2 or NO X under 326 IAC 21 or 326 IAC 1 0

- 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

- 1 4

- 2

- 2][ IC 13

- 3 0

- 3

- 1][ IC 13

- 1 7

- 3

- 2] Upon presentation of proper iden tification 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 a s 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 b e kept under the conditions of this permit;

(b) As authorized by the Clean Air Act, IC 13

- 1 4

- 2

- 2, IC 13

- 1 7

- 3

- 2, and IC 13

- 3 0

- 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 Ai r Act, IC 13

- 1 4

- 2

- 2, IC 13

- 1 7

- 3

- 2, and IC 13

- 3 0

- 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, I C 13

- 1 4

- 2

- 2, IC 13

- 1 7

- 3

- 2, and IC 13

- 3 0

- 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

- 1 4

- 2

- 2, IC 13

- 1 7

- 3

- 2, and IC 13

- 3 0

- 3

- 1, utilize any photographic, recording, testing, monitoring, or other equipment for the purpose of assuring compliance with this permit or applicable requirements.Indiana Gasification, LLC Page 33 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
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 th e 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 cur rent 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 6 1

- 53 IGCN 1003 Indianapolis, Indiana 4620 4

- 2251

An y 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 a dministrative 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 ye ar.

(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

- 80 0

- 45 1

- 6027 or 31 7

- 23 3

- 4230 (ask for OAQ, Billin g, 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 u se, 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.Indiana Gasification, LLC Page 34 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
SECTION C SOURCE OPERATION CO NDITIONS



### Entire Source

Emission Limitations and Standards [ 326 IAC 2

- 7

- 5(1)]

C.1 Particulate Emission Limitations For P rocesses 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 Opa city Limitations), opacity shall meet the following, unless otherwise stated in this permit:

(a) Opacity shall not exceed an average of forty perc ent ( 4 0%) 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

- 1 7

- 9] The Permittee shall not open burn any material except as provided in 326 IAC 4

- 1

- 3, 326 IAC 4

- 1

- 4 or 32 6 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 . Th e provisions of 326 IAC 6

- 5 are not federally enforceable.Indiana Gasification, LLC Page 35 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
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 e xhaust 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 1 4

- 10] [ 326 IAC 18] [40 CFR 61, Subpart M] (a) No tification 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 1 4

- 1 0

- 3 are mandatory. All demolition projects require notification whether or not asbestos is present.

(b) The Permittee shall ensure that a w ritten 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 1 4

- 1 0

- 3, and shall update such notice as necessary, including, but not limi ted 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 demo lition 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 1 4

- 1 0

- 3(2).

(d) The notice to be submitted shall include the information enumerated in 326 IAC 1 4

- 1 0

- 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 6 1

- 53 IGCN 1003 Indianapolis, Indiana 4620 4

- 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. TheIndiana Gasification, LLC Page 36 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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 emi ssion control procedures in 326 IAC 1 4

- 1 0

- 4 and 40 CFR 61.145(c). Per 326 IAC 1 4

- 1 0

- 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 fa cility 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 p resence of asbestos pursuant to 40 CFR 61.145(a).

(g) Indiana Licensed Asbestos Inspector The Permittee shall comply with 326 IAC 1 4

- 1 0

- 1(a) that requires the owner or operator, prior to a renovation/demolition, to use an Indiana Licensed Asbestos Inspect or 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, sh all be submitted to:

Indiana Department of Environmental Management Compliance and Enforcement Branch, Office of Air Quality 100 North Senate Avenue MC 6 1

- 53 IGCN 1003 Indianapolis, Indiana 4620 4

- 2251

no later than thirty

- five (35) days prior to the inte nded 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 t est 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 e xplanation not later than five (5) days prior to the end of the initial forty

- five (45) day period.Indiana Gasification, LLC Page 37 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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.

Comp liance 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 be gin 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 emiss ion 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 specifie d 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 s hall 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 require d 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 tim es 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 calc ulations, or fulfilling a minimum data availability requirement, if applicable. The ownerIndiana Gasification, LLC Page 38 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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 mal function 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 ap prove 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 paramet ers.
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 6 1

- 53 IGCN 1003 Indianapolis, Indiana 4620 4

- 2251

no later than 180 days f rom 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 Permi ttee 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 a ir 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.Indiana Gasification, LLC Page 39 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (f) Upon di rect notification by IDEM, OA Q 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(1 1 )] [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 o f 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 resp onse 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 no rmal 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 r esponse 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 s ystem);

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) Fa ilure 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.Indiana Gasification, LLC Page 40 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (1) Upon detecting an excursion or exce edance, 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 wit h 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 recurre nce 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 th rough 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) Determin ation 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 pro mptly 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 designate d 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 requireIndiana Gasification, LLC Page 41 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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 existin g 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 monitorin g 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 informa tion 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 Permitte e'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 specifie d 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 ta ke 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)

.Indiana Gasification, LLC Page 42 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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), s tarting 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 sha ll 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 onl y 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 6 1

- 50 IGCN 1003 Indianapolis, Indiana 4620 4

- 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 Requir ements [ 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 define d 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 operat ing 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.Indiana Gasification, LLC Page 43 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (b) Unless otherwise specified in this permit, fo r 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 rea sonable 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 utiliz e 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 d escription 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 sect ion 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 modificat ion” (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; andIndiana Gasification, LLC Page 44 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (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 pr oject 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 Sect ion 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 req uired 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 submi tted 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 32 6 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, t he 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 specifi ed 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 leve ls 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 Environment al ManagementIndiana Gasification, LLC Page 45 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun Compliance and Enforcement Branch, Office of Air Quality 100 North Senate Avenue MC 6 1

- 53 IGCN 1003 Indianapolis, Indiana 4620 4

- 2251

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

co nsidered 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 follo wing 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 a nd 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 t he 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 ac tual

- 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 projectio n.

Reports required in this part shall be submitted to:Indiana Gasification, LLC Page 46 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun Indiana Department of Environmental Management Compliance and Enforcement Branch, Office of Air Quality 100 North Senate Avenue MC 6 1

- 53 IGCN 1003 Indianapolis, Indiana 4620 4

- 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 2 2

- 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.Indiana Gasification, LLC Page 47 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
SECTION D.1 EMISSIONS UNIT OPERATI ON CONDITIONS

Emissions Unit Description:

(A) Incoming solid feedstock materials handling system, transferring material from the barge unloading facility and railcar unloading facility to st orage piles and day bins, consisting of: [Under 40 CFR 60, Subpart Y, the i ncoming solid feedstock materials handling system, transferring material from the barge unloading facility and railcar unloading facility to storage piles and day bins are new affec ted source s .]

(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, e ach 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 EU

012B, 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, permitted in 2012 , with four (4) control devices, identified as C

- 012C through C

- 012F, respectively, ex hausting 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 EU

012H, permitted in 2012 , with two (2) control devices, identified as C

012G through C

- 012H, resp ectively, 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 EU

012I and EU

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

- 01 2I 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 throug h two (2) vents, identified as S

- 012L through S

- 012M, respectively;Indiana Gasification, LLC Page 48 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun

Emissions Unit Description:

(g) Two (2) classification towers, ide ntified as EU

- 012T and EU

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

- 012T and C

- 012U, re spectively, 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 throug h one (1) vent, identified as S

- 012V;

(i) Three (3) truck stations unloading to a truck hopper, identified as EU

012Z, EU

- 012AB and EU

- 012AC, permitted in 2012, with three (3) control devices, identified as C

- 012Z, C

- 012AB and C

- 012AC, respectively, exhau sting 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 thro ugh 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, ident ified 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 baghouse s , 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 pile s, 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.Indiana Gasification, LLC Page 49 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun

Emissions Unit Description:

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

- 011A a nd 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 3 3, 7 6 0 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 source s .]

(The information describing the process contained in this emissions unit description box is descript ive 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 t he 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.

Ope rating Conditions

Emission Limitations and Standards [ 326 IAC 2

- 7

- 5(1)]

D.1.4 PM, PM 10 and PM 2.5 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 Pr ocess area solid feedstock conveying storage, identified as EU

- 011 A /B and EU

- 012 A

- AC shall be as follows:

(a) The PM, PM 10 and PM 2.5 emissions from the Process Area Solid Feedstock Conveying, storage and feedbin (EU

- 011A/B) operation shall be limited as f ollows:

(1) The PM, PM 10 and PM 2.5 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 PM 10 maximum outlet conc entration shall not exceed 0.003 gr/dscf

.Indiana Gasification, LLC Page 50 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (3) The PM 2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

(b) The PM, PM 10 and PM 2.5 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, PM 10 and PM 2.5 emissions from the Railcar Unloading to Rail Hoppers (EU

012G/H) operation shall be limited as follows: (1) The PM, PM 10 and PM 2.5 emissions from the railcar unloading to rail hoppers shall be controlled by a wet dust extrac tion system or the use of a baghouse

.
(2) The PM and PM 10 maximum outlet concentration shall not exceed 0.0 0 3 gr/dscf.

(3 ) The PM 2.5 maximum outlet concentration shall not exceed 0.001 5 gr/dscf.

(d) The PM, PM 10 and PM 2.5 emissions from the Barge Unl oading 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, PM 10 and PM 2.5 emissions from the Barge Unloading from the Hopper to the Belt (EU

- 012B) and Barge Conveyor Transf er Points (EU

- 012C

- F) shall be controlled by a wet dust extraction system or the use of a baghouse

. (2) The PM and PM 10 maximum outlet concentration shall not exceed 0.0 0 3 gr/dscf.

(3) The PM 2.5 maximum outlet concentration shall not exceed 0.0015 gr/d scf.

(e) The PM, PM 10 and PM 2.5 emissions from the Rail Hoppers Unloading to the Belts (EU

012I

- J) and Rail Conveyor Belt to the Stacker (EU

- 012K ) operation shall be limited as follows:

(1) The PM, PM 10 and PM 2.5 emissions shall be controlled by a wet du st extraction system or the use of a baghouse

.
(2) The PM and PM 10 maximum outlet concentration shall not exceed 0.0 0 3 gr/dscf.

(3) The PM 2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

(f) The PM, PM 10 and PM 2.5 emissions from the Stacker Belt to Radial Stacker (EU

- 012L

- M) operation shall be limited as follows: (1) The PM, PM 10 and PM 2.5 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 a nd PM 10 maximum outlet concentration shall not exceed 0.0 0 3 gr/dscf.

(3) The PM 2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.Indiana Gasification, LLC Page 51 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (g) The PM, PM 10 and PM 2.5 emissions from the Transfer systems consisting of hoppers and conveyor belts tra nsferring 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, PM 10 and PM 2.5 emissions shall be controlled by a wet dust extraction system or the use of a baghouse

.
(2) The PM and PM 10 maximum outlet concentration shall not exceed 0.0 0 3 gr/dscf.

(3) The PM 2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

(h) The PM, PM 10 and PM 2.5 emission s from the Radial Stacker to Pile (EU

- 012N

- O) operation shall be limited as follows: (1) The PM, PM 10 and PM 2.5 emissions shall be controlled by a Telescoping chute with dust collection.

(2) The PM and PM 10 maximum outlet concentration shall not exceed 0.00 3 gr/dscf

.
(3) The PM 2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

(i) The PM, PM 10 and PM 2.5 emissions from the Storage Piles (EU

- 012W/X) operation shall be controlled by wet suppression with pile compaction with a control ef ficiency of 90 %.

( j) The PM, PM 10 and PM 2.5 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, PM 10 and PM 2.5 emissions from the Truck/rail conveyor transfer tower (EU

012Y); 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, PM 10 and PM 2.5 emissions shall be controlle d by an enclosed vent to a wet dust extraction system or the use of a baghouse

.
(2) The PM and PM 10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM 2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

D.1 .5 Prevent ive Maintenance Plan [326 IAC 1

- 6

- 3] A Preventive Maintenance Plan (PMP) is required for these unit s and their control device s

. Section B

- Preventive Maintenance Plan contains the Permittee's obligations with regard to the preventive maintenance plan req uired by this condition.

Compliance Determination Requirements

D.1.6 PM, PM 10 and PM 2.5 Control [326 IAC 2

- 7

- 6(6)] (a) In order to ensure compliance with Condition D.1.4, the baghouse s , fabric filter/telescoping chute s , wet dust extraction system s , and the wet suppression for particulate control shall be in operation and control emissions from the Incoming SolidIndiana Gasification, LLC Page 52 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun feedstock material handling and the Process area solid feedstock conveying storage, identified as EU

- 011 A /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 i s 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 complia nce monitoring parameters with respect to normal, and the results of any response actions taken up to the time of notification.

(c) In order t o ensure compliance with Condition D.1.4(b) , wet suppression using water sprays or water fogging at the barge unl oading 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 32 o F

.
(d) In order to ensure compliance with Condition s D.1.4(i) and (j), wet suppression using water sprays shall be used daily on active a reas 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 32 o F

- The s ubject area is covered b y 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 th e 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, PM 10 , and PM 2.5 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 c ompliance with Condition s 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 on e of each if both are used controlling rail unloading to rail hoppers (EU

-Indiana Gasification, LLC Page 53 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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 Conve yor 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), an d 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, PM 10 , and PM 2.5 emissions limitations, utilizing methods as approved by the commissioner. These tests shall be repeated at least once every five years from the da te 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 perfor mance 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 unti l 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 sin gle 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
proc essing 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 Extract ion 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. Oper ations 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 b atch 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 con tinue 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).Indiana Gasification, LLC Page 54 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun

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

- 011 A /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 oper ated 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 an d 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. Sectio n C

- Response to Excursions or Exceedances contains the Permittee's obligation with regard to the reasonable response steps required by this condition.

D.1.1 1 P arametric Monitoring (a) In order to demonstrate the compliance status with Condition D.1.4(a ), t he 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 d rop 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 Perm ittee'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 fr om 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 Stacker s to th e 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 s hall 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 rang e 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 Condition s D.1.4(c), (d), (e), (f) and (k), the Permittee shall record the flow rate of the scrubbing water used in conjunctionIndiana Gasification, LLC Page 55 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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 un it 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 st eps 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 pre ssure 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 Permitt ee shall maintain an ambient temperature monitor when ambient temperatures may drop below 32 o F.

Record Keeping and Reporting Requirements [ 326 IAC 2

- 7

- 5(3)] [ 326 IAC 2

- 7

- 19]

D.1.13 Record Keeping Requirement s (a ) To document the compli ance status with Condition D.1.10

- Visible Emission Notation

, the Permittee shall maintain a daily recor d of the visible emission notations from the Process area solid feedstock conveying, storage and feedbins, identified as EU

- 011 A /B and Incoming Solid feedstock material handling points EU

- 012B

- O, R

- V, and Y

-- AC. The Permittee shall include in its daily re cord 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 Condition s 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 feedbinsIndiana Gasification, LLC Page 56 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun and across the fabric filter used in conjunction with the Incoming Solid Feed stock Radial Stacke rs 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 Condition s 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 EU

012 (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 Condition s D.1.4(b)

- PM, PM 10 and PM 2.5 PSD BACT and D.1.6(c)

- PM, PM 10 and PM 2.5 Contro l , 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 ba rge 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 s tatus with Condition s D.1.4(i), and (j)

- PM, PM 10 and PM 2.5 PSD BACT and D.1.6(d)

- PM, PM 10 and PM 2.5 Control

, the Permittee shall maintain the following daily records :

- The date and approximate time of each feedstock pile watering treatment.

- I f 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

- Ge neral Record Keeping Requirements contains the Permittee's obligations with regard to the record keeping required by this condition.Indiana Gasification, LLC Page 57 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun
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 th rough o ne ( 1) tip, identified as S

- 001

. (The information describing the process containe d 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 Modific ation to Construction Conditions [326 IAC 2] All requirements of these construction conditions shall remain in effect unless modified in a manner consistent with procedures e stablished for revisions pursuant to 326 IAC 2.

Operating Conditions

Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)

D.2.4 PM, PM 10 and PM 2.5 , CO, SO 2 , 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

- 0 01 shall be as follows:

(1) The PM, PM 10 and PM 2.5 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, PM 10 and PM 2.5 emissions during startups , shutdown s 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 Sulfur ic Acid (WSA) plants.Indiana Gasification, LLC Page 58 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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 th e 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 p ractices:

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 mo nitored to assu re the presence of a pilot flame with a thermocouple, infrared monitor, or other approved device.

C. The Syngas Hydrocarbon Flare PM/PM 10 emissions shall not exceed 3.21 lb/hour during startup or shutdown, based on a 3

- hour average.

D. The Syngas Hydrocarbon Flare PM 2.5 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 permit tee shall comply with the following Flare Minimization Plan to reduce CO emissions during startups , shutdown s 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 identifi ed measures shall be implemented and documented.Indiana Gasification, LLC Page 59 of 152 Rockport , Indiana T147

- 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 assu re the presence of a pilot flame with a thermocouple, infrared monitor, or other approved device.

C. The Syngas Hydrocarbon Flare CO emissi ons shall not exceed 172.4 lb s /hour during startup or shutdown based on a 3 hour average.

(3) The SO 2 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 SO 2 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 r educing 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 t o 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 wil l 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 SO 2 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 complia nce determined at the end of each month. The SO 2 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 det ermined 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.Indiana Gasification, LLC Page 60 of 152 Rockport , Indiana T147

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- 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 Sulf uric 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 Hydrocarbo n Flare NOx emissions shall not exceed 43.09 lb s /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 com ply 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 cha mber, 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 identif ied 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 SO 2 emission limit is Conditi on 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 yea r of any combination of HAPs and make the source an area source of HAPs.Indiana Gasification, LLC Page 61 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun

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 conta ins 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 compl iance with Condition D.2.4, t he flare must be operated with a flame present at all times when the Syngas H ydrocarbon 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 pil ot 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, PM 10 , PM 2.5 , and NOx:

E = F x HHV x EF + PE

Where:

E = Pollutant emissions (lb/hour)

F = Flow of flared gases (MMscf/hour)

HHV startup = 124.5 Btu/scf, or other value determined by testing

HHV shutdown = 118.6 Btu/scf, or other value determined by testing

EF PM/PM10 = 0.0075 lb/MMBtu

EF PM2.5 = 0.0070 lb/MMBtu

EF NOx = 0.010 lb/MMBtu

PE PM/PM10/PM2.5 = 0.0020 lb/hr from pilot

PE NOx = 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

Wh ere:

E = lb/hr CO

F = Flow of flared gases (scf/hour)Indiana Gasification, LLC Page 62 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
%CO startup = Percent CO in flared gas during startup = 13.5% or other value determined by testing

%CO shutdown = 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 SO 2 :

E = F x EF + PE

Where:

F = Flow of flared gases (scf/hour)

EF startup = 0.10 x 10 - 6 lbs/scf

EF shutdown = 0.001264 lbs/scf

PE = 0.0002 lb/hr SO 2 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 demonstra te 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, conti nuous 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 Requirement s (a) To 

### documen t the compliance status with Conditions D.2.4 :

(1) The Permittee shall maintain records of the monito ring required by Condition D.2.8 (a) ; and

( 2 ) The Permittee shall maintain records of the daily flare visible emissions checks by Reference Method 22Indiana Gasification, LLC Page 63 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (b ) To document the compli ance 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 rec ords 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 compli ance status with Condition D.2.4 , the Permittee shall maintain records of the date, time, and total n umber of minutes for each startup and shutdown flaring event.

(d ) To document the compliance status with Condition s 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 start up that requires flaring. ii. The routing of gas whenever a gasifier is depressur iz ed 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 s hall 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 re cords of the PM, PM 10 , PM 2.5 , NOx, CO, and SO 2 emissions.

(f ) Section C

- General Record Keeping Requirements contains the Permittee's obligations with regard to the record keeping required by this condition.Indiana Gasification, LLC Page 64 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
SECTION D.3 EMISSIONS UNI T 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 throu gh one (1) t ip, identified as S

002.

(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 responsi bility 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, sta te, 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 con ditions 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, PM 10 , PM 2.5 , CO, SO 2 , NOx and GHG s 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 Te chnologies (BACT) for the Acid Gas Flare , identified as EU

- 00 2 shall be as follows:

(1) The PM, PM 10 and PM 2.5 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 implem ented to minimize re

- occurrence of these events. Such identified measures shall be implemented and documented. B. Comply with the following flare best practices:Indiana Gasification, LLC Page 65 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun

a. Flares shall be designed for and operated with no visible emissions, except for period s 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 assu re the presence of a pilot flame with a thermocouple, infrared monitor, or other appro ved 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 inves tigate 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 impl emented 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 ass ure the presence of a pilot flame with a thermocouple, infrared monitor, or other approved device.

(3) The SO 2 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 a s (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.Indiana Gasification, LLC Page 66 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (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 P reventive 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 Determina tion Requirements

D.3 .6 Flare Pilot Flame In order to ensure compliance with Condition D.3.4, t he 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 Refer ence 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 Requirement s (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 Condition s 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 proce dures 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 onIndiana Gasification, LLC Page 67 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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.Indiana Gasification, LLC Page 68 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
SECTION D.4 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(E) Two (2) Acid Gas Removal (AGR) Unit vents, ide ntified as EU

- 007A and EU

- 007B, permi tted 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 requi rements.

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, PM 10 and PM 2.5 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 Deteriorati on (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, PM 10 and PM 2.5 emissions from operation of the AGR Regenerative Thermal Oxidizer s ( C

- 007A/B) shall no t exceed 0.29 pounds per hour, each and g ood combustion practices shall be used . Only natural gas or SNG shall be used in the AGR Regenerative Thermal Oxidizer s ( C

007A/B)

.Indiana Gasification, LLC Page 69 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
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 emi ssions 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 ave rage

.

D.4.6 SO 2 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 Availa ble Control Technologies (BACT) for the Acid Gas Removal (AGR) Unit vents, identified as EU

- 007A/B shall be as follows:

The SO 2 emissions shall be reduced by the use of a Rectisol process and SO 2 emissions shall not exceed 3.17 pounds per hour for each Ac id 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 (Pre vention 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 1.9 8 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

- hou r 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 CO 2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed 4 ,690 ,000 tons of CO 2 during the first 12 month s of operation.

(b) The CO 2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed 6 ,430 ,000 tons of CO 2 during the second 12 months of operation.

(c) The CO 2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed 1, 290,000 tons of CO 2 during the third 12 months of operation.Indiana Gasification, LLC Page 70 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun

(d) Thereafter, the CO 2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed 1,290,000 tons CO 2 per twelve (12) consecutive month period with compliance determined at the end of eac h 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 h ou r , combined

, from both AGR units (EU

- 007A/B) and s hall 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 R ecovery 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 P ermittee.

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 complian ce 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 = Ve nt 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 initialIndiana Gasification, LLC Page 71 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun compliance stack testing is performed, the engineering estimate of 0.006 2 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 Flo w 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 qua ntified 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 co mpliance stack test of the oxidizer. If no compliance stack test has been performed, the engineering estimate of 0.00 023 lbs. formaldehyde emitted/million SCF vent gas shall be used.

Additional HAPS Emissions factor = Pounds of any other HAP besides met hanol, 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 ha s beenIndiana Gasification, LLC Page 72 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun performed, the engineering estimate of 0.00004 lbs. additional HAPs emitted/million SCF vent gas shall be used.

Compliance with the above limit s and combined with the potential to emit HAP emissions from all other emission units will limit the pote ntial 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 P reventive Maintenance Plan (PMP) is required for these unit s and control device s . Section B

- Preventive Maintenance Plan contains the Permittee's obligations with regard to the preventive maintenance plan required by this condition.

Compliance Determinat ion Requirements

D.4.13 PM, PM 10 and PM 2.5 Calculations [326 IAC 2

- 2] (a) In order to ensure compliance with Condition D.4.4

- PM, PM 10 and PM 2.5 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, PM 10 and PM 2.5 PSD BACT :

E = F NG x HHV x EF

Where:

E = PM, PM 10 and PM 2.5 emis sions, pounds/hour

F NG = Flow of natural gas or SNG to RTO, MMscf/hour

HHV = higher heating value for the fuel combusted

EF = 0.0075 lb PM, PM 10 and PM 2.5 /MMBtu

D.4.1 4 Nitrogen Oxide Control (a) In order to ensure compliance with Condition s 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 emissio ns from the 

### RTO at all times that th e 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 = F ng * HHV * EF

Where:

E = Pollutant emissions (lb/hr)

F ng = flow of NG or SNG to RTO (mmscf/hr)Indiana Gasification, LLC Page 73 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
HHV = higher heating value of the fuel combusted, in Btu/scf

EF NOx = 0.05 lb/MMBtu until the initial stack test. Thereafter, use factor (lb/MMBtu) developed from most recen t 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 SO 2 limit for the Acid Gas Removal (AGR) Unit vents ( EU

- 007A/B ) in Condition D.4.6:

E SO2 = F AGR x (S ppm /1,000,000) x (1 lb mole/379.49scf) x (64.06 lbs SO2/lb mole sulfur) x (DRE/100) + F NG x EF

Where:

E SO2 = SO 2 emissions, pounds/hour

F AGR = Vent flow from AGR to RTO, scf/hour

DRE = Destruction Removal Efficiency of sulfur to SO 2 = 98%

F NG = Flow of natural gas or SNG to RTO, MMscf/hour

EF = 0.6 lb SO2/MM scf

S ppm = 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 CO 2 emission limit for the Acid Gas Removal (AGR /RTO ) Unit vents ( EU

- 007A/B ) :

E CO2 = F NG x HHV x EF CO2 x (ton/2000 lb) + F AGR x (1 lb mole/379.49 scf) * ((%CO2 + ((%CO + %C other ) x (DRE/100)))/100) x (44.01 lb CO2/lb mole) x (ton/2000lb)

Where:

E CO2 = Total CO 2 emissions, tons/month

F NG = 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

F AGR = Vent flow from AGR to RTO, scf/monthIndiana Gasification, LLC Page 74 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun %CO2 = 99% or other value determined by sampling

%CO = 1.0% or other value determined by sampling

%C other = 0.0209% (allowance for trace CH 4 , COS, and CH3OH)

DRE = Destructio n Removal Efficiency for CO, CH 3 OH, CH 4 , COS = 99%

D.4.17 T hermal Oxidizer Operation In order to ensure compliance with Conditions D.4.5

, D. 4. 8 and D.4.11

, the associated thermal oxidi zer (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 Re quirements [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 lat er 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 EU

007B that has been started up. Not later than 180 da ys 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 Commission er. 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

- Perfor mance 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 gas ifier , 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. No t 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 approv ed 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 obliga tion with regard to the performance testing required by this condition.Indiana Gasification, LLC Page 75 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (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 ini tial 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 t he 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 rep eated 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 Pe rmittee'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 gasifie r, 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 fro m 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 th e 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 Condition s D.4.5, D. 4

. 8 and D.4.11 , a continuous monitoring sy stem 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 1,6 00°F at allIndiana Gasification, LLC Page 76 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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) Se ction 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 . I n order to ensure compliance with Condition D.4.11, a continuous monitoring system shall be c alibrated, 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 avera ge. 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 resul ts 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 Exceeda nces 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 considere d a deviation from this permit.

D.4.22 Vent Flow Monitoring In order to demonstrate the compliance status with Conditions D.4.6

– SO 2 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 Ga ses (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 sh all 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.4.2 4 Record Keeping Requirements (a) In order to document the compliance status with Condition s D.4.4

- PM, PM 10 and PM 2.5 PSD BACT, D.4.6

– SO 2 PSD BACT, D.4.9

- GHGs PSD BACT, D.4.13

– PM, PM10, and PM 2.5 Calculations , D.4.15

– Sulfur Dioxide Control and Calculations , and D.4.16

– Greenhouse Gases (GHGs) Calculations , the Permittee shall maintain monthly records ofIndiana Gasification, LLC Page 77 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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 Condition s D.4.9

- GHGs PSD BACT, D.4.4

- PM, PM 10 and PM 2.5 PSD BACT, and D.4.6

- SO 2 PSD BACT the Permittee shall maintain monthly records of the CO 2 , PM, PM 10 and PM 2.5 , and SO 2 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.4.1 1 , the Permittee shall mainta in 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 condit ion D.4.1 1

. (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 stac k 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

– SO 2 PSD BACT and D.4.15

– Sulfur Dioxide Control, the Permittee shall maintain monthly r ecords 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 duri ng each hour during which a startup flaring event occurs.

(h ) In order to document the compli ance status with Condition D.4.20

- Thermal Oxidizer Parametric Monitoring , the Permittee shall maintain continuous temperature records ( on a 3

- hour average bas is) 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. 2 5 Reporting Requirements A quarterly summ ary of the information to document the compliance status with Condition s 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 e ach calendar quarter. The report submitted by the Permittee does require a certification that meets theIndiana Gasification, LLC Page 78 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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.Indiana Gasification, LLC Page 79 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
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 H 2 SO 4 and identified as EU

- 015A and EU

- 015B, permitted in 2012, with N Ox , emissions controlled by two (2) selective catalytic reduction (SCR) systems identified as C

- 015

- 1A and C

- 015

- 1B, respectively, and particulate, H 2 SO 4 , and SO 2 emissions controlled by two (2) hydrogen peroxide scrubbers identified as C

- 015

- 2A and C

- 015

- 2B, respectively, and particulate and H 2 SO 4 emissions controlled by a high efficiency mist eliminator, exhausting through two (2) sta cks, 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 conta ined 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 Modi fication to Construction Conditions [326 IAC 2] All requirements of these construction conditions shall remain in effect unless modified in a manner consistent with procedure s established for revisions pursuant to 326 IAC 2.

Operating Conditions

Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)]

D.5.4 PM, PM 10 and PM 2.5 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 t he Wet Sulfuric Acid (WSA) plant , identified as EU

- 01 5A and B shall be as follows:Indiana Gasification, LLC Page 80 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun The PM, PM 10 and PM 2.5 emissions from the Wet Sulfuric Acid Plants (EU

- 015A/B) shall be controlled by a high Efficiency Mist Eliminator and H 2 O 2 scrubber and the PM, PM 10 a nd PM 2.5 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 H 2 SO 4 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

- 01 5A and B shall be as follows:

The H 2 SO 4 emissio ns from the Wet Sulfuric Acid Plants (EU

- 015A/B) shall be controlled by a high Efficiency Mist Eliminator and H 2 O 2 scrubber and the H 2 SO 4 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 base d on a 3

- hour average.

D.5 .7 SO 2 PS D 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 Techno logies (BACT) for the Wet Sulfuric Acid (WSA) plant , identified as EU

- 015A and B shall be as follows:

The SO 2 emissions from the Wet Sulfuric Acid Plants (EU

- 015A/B) shall be controlled by a peroxide scrubber, the SO 2 emissions shall not exceed 0.25 lb/to n acid produced and 8.3 lbs SO 2 per hour , each based o n 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 ho ur 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 (S CR).

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 Availa ble Control Technologies (BACT) for the Wet Sulfuric Acid (WSA) plant , identified as EU

- 015A and B shall be as follows:

The CO 2 emissions from the Wet Sulfuric Acid Plant operation shall not exceed 474,000 tons per twelve (12) consecutive month period, wi th compliance determined at the end of each month.Indiana Gasification, LLC Page 81 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
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.5.1 1 Preventive M aintenance Plan [326 IAC 1

- 6

- 3]
A Preventive Maintenanc e Plan (PMP) is required for the s e unit s and control device s . Section B

- Preventive Maintenance Plan contains the Permittee's obligations with regard to the preventive maintenance plan required by th is condition.

Compliance Determination Requirements

D.5.1 2 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 al l times that acid gases are being fed to the unit

.

D.5.1 3 Sulfur dioxide Control In order to ensure complianc e with Condi tion D.5. 7 , the peroxide scrubber for SO 2 removal shall be in operation and control emissions from each WSA at all times that t he WSA is in operation.

D.5.1 4 PM, PM 10 , PM 2.5 and H 2 SO 4 Control In order to ensure compliance with Conditions D.5

. 4 and D.5.5

, the high Efficiency Mist Eliminator and H 2 O 2 scrubber shall be in operation and control emissions from each WSA at all times when the WSA is in operation.

D.5

. 1 5 Maintenance of Continuous Emission Monitoring Equipment [326 IAC 3

- 5 ][326 IAC

- 2

- 2

- 3] (a) T he Permittee shall install, calibrate, maintain, and operate all necessary continuous emission monitoring systems (CEMS) and related equipment for NOx, CO 2 and SO 2 emissions

.
(b) All CEMS required by this permit shall meet all applicable performance sp ecifications 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 syste m 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 , SO 2 , or CO 2 CEM is down for more than twenty

- four (24) hours, the Permittee shall follow good air pollution control pra ctice s

.
(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

. 1 6 Testing Requirements [326 IAC 2

- 1.1

- 11] (a) In order to demonstrate compliance with C ondition D.5.4

– PM, PM 10 and PM 2.5 PSD BACT, not later than 180 days after initial startup of the second gasifier but not later thanIndiana Gasification, LLC Page 82 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 365 days after the initial startup of the first gasifier, the Permittee shall conduct PM, PM 10 and PM 2.5 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

s tartup of the fourth gasifier, the Permittee shall conduct PM, PM 10 and PM 2.5 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 s hall 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

con tains the Permittee's obligation with regard to the performance testing required by this condition.

(b) In order to demonstrate compliance with C ondition D.5.5

– H 2 SO 4 PSD BACT, not later than 180 days after initial startup of the second gasifier but not l ater than 365 days after the initial startup of the first gasifier, the Permittee shall conduct H 2 SO 4 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 aft er initial startup of the fourth gasifier, the Permittee shall conduct H 2 SO 4 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 sh all 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 cont ains 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 late r 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 aft er 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

. 1 7 Scrubber Parametric Monitoring (a) In order to demonstrate the compliance status with Conditions D.5.4 and D.5.5, t he 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.Indiana Gasification, LLC Page 83 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (b) In order to demonstrate the compliance status with Conditions D.5.4 and D.5.5, t he Permittee shall monitor the flow rate of the scrubbing li quid 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 deter mining the pressure and flow rate shall comply w ith 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 re cords 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 control ling 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 li ne. 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 NO x , H 2 SO 4 and SO 2 emissions

. Compliance with the CA M plan attached as Appendix D satisfies 40 CFR 64, Compliance Assurance Monitoring (CAM) for the Wet Sulfuric Acid (WSA) Plant for NO x , H 2 SO 4 and SO 2 emissions.

Record Keep ing and Reporting Requirements [326 IAC 2

- 7

- 5(3)] [326 IAC 2

- 7

- 19]

D.5.2 0 Record Keeping Requirements (a) To document the compliance status with Condition D.5.1 5 , t he Permittee shall record the output of the continuous monitoring syste ms 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 ev ent that a breakdown of the NOx, SO 2 , or CO 2 continuous emission monitoring system (CEMS) occurs in Condition D.5.1 5 , 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

. 1 7 (a), the Permittee shall maintain records of the pressur e 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).Indiana Gasification, LLC Page 84 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (d) To docume nt compliance with Condition D.5.1 7 (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

- Ge neral 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) , reporti ng 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 th e 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 Permitte e 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 requir ed by this condition.Indiana Gasification, LLC Page 85 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
SECTION D.6 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(G) Two (2) natural gas

- fired auxiliary boilers, nominally rated at 408 MMBt u/hr HHV each, identified as EU

- 005A and EU

- 005B, permitted in 2012 , with NO x emissions controlled by ultra

- low NO x burners/Flue Gas Recirculation (ULNB/FGR), with both boilers exhausting through one (1) stack, identified as S

- 005. [Under 40 CFR 60, Subpar t 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 C onditions

General Construction Conditions

D.6 .1 Permit No Defense This permit to construct does not r elieve 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 re quirements 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, PM 10 and PM 2.5 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, PM 10 and PM 2.5 emissions from the Auxil iary 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:Indiana Gasification, LLC Page 86 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
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 p ractices shall be used

.

D.6 .6 SO 2 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 SO 2 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 s hall 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 basi s and Ultra Low NOx burner s 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 Auxili ary 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 recover y, inlet air controls and blowdown heat recovery.)

(c) Boiler designed for 81% thermal efficiency (HHV).

(d) The total CO 2 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 HAP s from the natural gas

- fired auxiliary boilers identified as EU

- 005A and EU

- 005B shall be limit ed by compliance with Condition D.6.10

- Ope rational 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 EU

005A/B

, shall not exceed a total firing rate of 1430 bil lion Btu per twelve (12) consecutive month period, with compliance determined at the end of each month.Indiana Gasification, LLC Page 87 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
D.6 .11 Preventive Maintenance Plan [326 IAC 1

- 6

- 3]
A Preventive Maintenanc e Plan (PMP) is required for the s e unit s and control device s . Section B

- P reventive Maintenance Plan contains the Permittee's obligations with regard to the preventive maintenance plan required by this condition.

Compliance Determination Requirements

D.6 .1 2 Nitrogen Oxide Control In order to ensure compliance with Condi tion D.6.7 , the Ultra Low NOx burner with FGR shall be in stalled and utilized at all times that th e auxiliary boiler s are in operati on.

D.6

. 13 Maintenance of Continuous Emission Monitoring Equipment [326 IAC 3

- 5 ][326 IAC

- 2

- 2

- 3] (a) The Permittee shall install, calibrate, m aintain, 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 rea sons of the breakdown and efforts made to correct the problem.

(d) Whenever a NOx CEM S 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 comp lying 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 orde r 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 met hods 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 test ing 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 test ing required by this condition.Indiana Gasification, LLC Page 88 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
D. 6

. 15 Compliance Determination Requirements [326 IAC 2

- 2] In order to determine compliance status with Conditions D.6.4

- PM, PM 10 and PM 2.5 PSD BACT and D.6.6

- SO 2 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 equ ation shall be used to determine the CO 2 emission limit for the Auxiliary Boilers :

E CO2 = F x HHV x EF CO2 x (ton/2000 lb)

Where:

E CO2 = Total CO 2 emissions, tons/month

F = Total amount of natural gas or SNG combusted in the auxiliary boilers, MMscf/mo nth

HHV = higher heating value for the fuel combusted , in Btu/scf

EF CO2 = 116.89 lb CO 2 /MMBtu

Record Keeping and Reporting Requirements [ 326 IAC 2

- 7

- 5(3)] [ 326 IAC 2

- 7

- 19]

D.6 .1 7 Record Keeping Requirements (a) To document the compliance status with Condition D.6.1 3 , t he Permittee shall record the output of the continuous monitoring systems and shall perform the required record keeping and reportin g, 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

. 6.1 3 , 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.6.1 6 , the Permittee shall maintain monthly records of the type and

am ount 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 CO 2 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 b e reported separately, shall include the following:Indiana Gasification, LLC Page 89 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (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 s D.6.8(d) and D.6

. 10 shall be submitted, using the reporting forms loc ated 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 “respo nsible 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.Indiana Gasification, LLC Page 90 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
SECTION D.7 EMISSIONS UNIT OPERATION CON DITIONS

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 d oes 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 Con trol 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

E mission Limitations and Standards [326 IAC 2

- 7

- 5(1)]

D. 7 .4 PM, PM 10 and PM 2.5 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, PM 10 and PM 2.5 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:Indiana Gasification, LLC Page 91 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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 SO 2 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 SO 2 emissions from the Gasifier Preheat Burners (EU

- 008A

- E) operation shall be not exceed 0.0006 lb SO 2 /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 , ide ntified 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 Prehea t 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 CO 2 emissions from the Gasifier Preheater Burners shall not exceed 6,438 tons CO 2 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 Maintenanc e Plan (PMP) is required for the s e unit s and it s 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 compl iance status with Conditions D.7 .4

- PM, PM 10 and PM 2.5 PSD BACT

, D.7.5

- CO PSD BACT, D.7.6

- SO 2 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 (EU

008 A

- 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 CO 2 emission limit for the Gasifier Preheat Burners (E U

- 008A

- E) :Indiana Gasification, LLC Page 92 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
E CO2 = F x HHV x EF CO2 x (ton/2000 lb)

Where:

E CO2 = Total CO 2 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 = 1 1 6 .89 lb CO 2 /MMBtu



### Record Keep ing and Reporting Requirements [326 IAC 2

- 7

- 5(3)] [326 IAC 2

- 7

- 19]

D. 7.1 2 Record Keeping Requirement (a) In order to document the compliance status with Condition s 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 Gas ifier Preheat Burners

.
( b ) To document the compliance status with Condition D. 7 .8 (c) , the Permittee shall maintain the monthly records of the CO 2 emissions from the Gasifier Preheat Burners

.
(c ) Section C

- General Record Keeping Requirements contains th e 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 Con ditions 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 certifi cation that meets the requirements of 326 IAC 2

- 7

- 6(1) by a “responsible official” as defined by 326 IAC 2

- 7

- 1(34). Section C

- General Reporting Requirements contains the Permittee's obligations with regard to the reporting required by this condition.Indiana Gasification, LLC Page 93 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
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 throug h 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 C onstruction 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, PM 10 and PM 2.5 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 ZLD

Spray Dryer , identified as EU

- 0 32 shall be as follows:

The PM, PM 10 and PM 2.5 emissions from t he Zero Liquid Discharge (ZLD) Spray Dry er shall be controlled by a fabric filter baghouse and the PM, PM 10 and PM 2.5 em issions 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 ZLD

Spray Dryer , identified as EU

- 032 shall be as follows:Indiana Gasification, LLC Page 94 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun The CO emissions from the Zero Liquid Discharge (ZLD) Spray Dryer shall not excee d 0.036 lb/MMBtu and good combustion practices shall be used

.

D

. 8 .6 SO 2 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 Con trol Technologies (BACT) for the ZLD

Spray Dryer , identified as EU

- 032 shall be as follows:

The SO 2 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 ZLD

Sp ray 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 ZLD

Spray Dryer , identifie d 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 CO 2 emissions from the ZLD Spray Dryer shall be not exceed 2,884 tons CO 2 per twelve (12) consecutive month period with compliance dete rmined at the end of each month

.

D.8 .9 Preventive Maintenance Plan [326 IAC 1

- 6

- 3]
A Preventive Maintenanc e P lan (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 Condi tion D.8.7 , the low NOx burner shall be in stalled and util ized 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

- SO 2 PSD BACT

, D.8.7

– NOx PSD BACT and D.8.8(a)

- GHGs PSD B ACT, the Permittee shall only use natural gas or SNG in the ZLD

- Spray Dryer (EU

- 032).Indiana Gasification, LLC Page 95 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
D.8

. 12 PM, PM 10 and PM 2.5 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 a nd 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 observ ed 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 moni toring 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 demons trate the compliance status with Condition D.8. 4

- PM, PM 10 and PM 2.5 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 s tack testing on the ba ghouse controlling emissions from the ZLD

- Spray Dryer, identified as EU

- 032 to determine compliance with the PM, PM 10 and PM 2.5 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 CO 2 emission limi t for the ZLD Spray Dryer :

E CO2 = F x HHV x EF CO2 x (ton/2000 lb)

Where:

E CO2 = Total CO 2 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 .1 5 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 th e 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 theIndiana Gasification, LLC Page 96 of 1 52 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun processi ng 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 ind icated 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 Requir ements [ 326 IAC 2

- 7

- 5(1)][ 326 IAC 2

- 7

- 6(1)]

D. 8

. 1 6 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

ex pected 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 proc ess.

(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 st atus with Condition D.8 .4, t he 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 tes t, 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 ab ove 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 pe rmit, shall be subject to approval by IDEM, OAQ, and shall be calibrated at least once every six (6) months.Indiana Gasification, LLC Page 97 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun Record Keeping and Reporting Requirements [ 326 IAC 2

- 7

- 5(3)] [ 326 IAC 2

- 7

- 19]

D.8 .1 8 Record Keeping Requirement s (a) In order to document the compliance status with Condition s D.8.5, D.8.6 and D.8 .7, D.8.8, and D.8.14, the Permittee s hall 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 CO 2 emissions from each o f ZLD

Spray Dryer

.
(c ) To document the comp liance status with Condition D.8

. 1 6

- Visible Emission Notation, the Permittee shall maintain a daily record of visible emission notations from the ZLD

Spray 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

. 1 7

- Parametric Monitoring, the Permittee shall maintain a daily record of the pressure drop across the baghouse controlling the ZLD

- Spray Dryer w hen 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 pres sure 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

. 1 9 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 t han 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

- G eneral Reporting Requirements contains the Permittee's obligations with regard to the reporting required by this condition.Indiana Gasification, LLC Page 98 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
SECTION D.9 EMISSIONS UNIT OPERATION CONDITIONS

Emissions U nit 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, S ubpart 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 nominall y 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 c onstitute 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 Li mitations and Standards [326 IAC 2

- 7

- 5(1)]

D. 9 .4 PM, PM 10 , PM 2.5 , NOx, CO, SO 2 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;Indiana Gasification, LLC Page 99 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (b ) CO: emiss ions shall be limited through the implementation of good combustion practices and limited hours of non

- emergency operation;

(c ) PM, PM 10 and PM 2.5 : emissions shall be limited through the use of low

- S diesel (less than15ppm sulfur ) and limited hours of non

- emergency operation;

(d ) SO 2 : 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 o f non

- emergency opera tion; and

(f ) The total CO 2 emissions from the emergency e ngines (EU

- 009A/B and EU

- 010A/B/C) shall not exceed 84 tons CO 2 per twelve (12) consecutive month period from non

emergency operation , with compliance determined at the end of each month.

D.9. 5 Oper a ting Restrictions Durin g Gasifier Startup Flaring During startup flaring of the gasifiers, the Permittee shall not test an emergency engine (EU

009A/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 Greenh ouse Gases (GHGs) Calculations
To determine the compliance status with Condition D.9.4(f), the following equation shall be used to determine the CO 2 emission limit for the emergency engines (EU

- 009A/B and EU

- 010A/B/C) :

E CO2 (tons/month) = F D x HHV x EF C O2 x (ton/2000 lb)

Where:

E CO2 = Total CO 2 emissions, tons/month

F D = 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 CO 2 = 163.05 lb CO 2 /MMBtu

Record Keeping and Reporting Requirements [ 326 IAC 2

- 7

- 5(3)] [ 326 IAC 2

- 7

- 19]

D.9

. 7 Record Keeping Requirement s (a) In order to document the compliance status with Condition s 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 e ngines and the firewater pump diesel en gines

.
(b ) To docume nt compliance with Condition D.9

. 4(e) , the Permittee shall maintain monthly

r ecords of hours of operation of the emergency diesel e ngines and the firewater pump diesel engines

.Indiana Gasification, LLC Page 100 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun

( c ) To document the compliance status with Condition s 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 CO 2 emissions from the emergency e ngines (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 kee ping required by this condition

D.9

. 8 Reporting Requirements A quarterly summary of the informatio n to document the compliance status with Condition s 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 repo rt 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 re gard to the reporting required by this condition.Indiana Gasification, LLC Page 101 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
SECTION D.1 0 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) tw enty

- 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.

(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 0 .1 Permit No Defense This permit to construct does not relieve the Permittee of the responsibility to comply w ith 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 re quirements.

Effective Date of the Permit

D. 1 0 .2 Effective Date of the Permit [IC 13

- 15

- 5

- 3] Pursuant to IC 13

- 15

- 5

- 3, this sect ion of this permit becomes effective upon its issuance.

D. 1 0 .3 Modification to Construction Conditions [326 IAC 2] All requirements of these construction conditions shall re main 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 0 .4 PM, PM 10 and PM 2.5 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 Deter ioration (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:Indiana Gasification, LLC Page 102 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun The PM, PM 10 and PM 2.5 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 dissolve d solids shall not exceed 1500 ppm based on a daily average.

Compliance Determination

D.10.5 PM, PM 10 and PM 2.5 Contr ol
In order to ensure compliance wit h 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 Monit oring 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 sha ll 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.1 0

. 7 Record Keeping Requirement s (a) In order to document the compliance status with Condition D.1 0 .4, the Permittee shall maintain weekly records of the total dissolve d solids (T D S ) sampling from the ASU and M ain cooling towers

.
(b ) Section C

- General Record Keeping Requirements contains the Permittee's obligations with regard to the record keeping required by this condition.Indiana Gasification, LLC Page 103 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
SEC TION 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, respectivel y.
(The information describing the process contained in this emissions unit description box is descriptive information and does not constitute enforceable conditions.)

Construction Conditions

General Cons truction Conditions

D.1 1 .1 Permit No Defense This permit to construct does not relieve the Permittee of the responsibility to comply with the provision s 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.

Effe ctive Date of the Permit

D.1 1 .2 Effective Date of the Permit [IC 13

- 15

- 5

- 3] Pursuant to IC 13

- 15

- 5

- 3, this section of this permi t becomes effective upon its issuance.

D.1 1 .3 Modification to Construction Conditions [326 IAC 2] All requirements of these construction conditions shall remain in effect un less 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 1 .4 PM, PM 10 and PM 2.5 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)), t he Best Available Control Technologies (BACT) for the 

### Rod Mill
Vent , identified as EU

- 01 3 A

- D shall be as follows:

(1) The PM and PM 10 emissions from each Rod Mill Vents shall not exceed 0.025 pounds per hour based on a 3

- hour average.

(2) The PM 2.5 emi ssions from each Rod Mill Vent shall not exceed 0.0074 pounds per hour based on a 3

- hour average.Indiana Gasification, LLC Page 104 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun

D.1 1

. 5 PM, PM 10 and PM 2.5 PSD BACT [326 IAC 2

- 2

- 3] Pursuant to PSD/Operatin g 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 PM 10 emissions from each Air Separation Unit (ASU) shall not exceed 0.026 pounds per hour based on a daily average.

(2) The PM 2.5 emissions from the Air Separation Unit (ASU) shall not exceed 0.0 09 pounds per hour based on a daily average.Indiana Gasification, LLC Page 105 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
SECTION D.12 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

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

- ROAD.

(The information describin g 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 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 Environmenta l 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 .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 2 .3 Modification to Construction Conditions [326 IAC 2] All requirements of these construction conditions shall remain in effect unless modified in a

manner con sistent 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, PM 10 and PM 2.5 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 Tec hnologies (BACT) for the Paved Plant Haul Roads ( FUG

- ROAD ) shall be as follows:

The PM, PM 10 and PM 2.5 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 clean up of any spilled materials ; and

with a control efficiency of 90%.

Compliance Determination Requirements

D.12.5 Compliance Determination Requirements To demonstrate complia nce status with Condition D.12.4

- PM, PM 10 and PM 2.5 PSD BACT:Indiana Gasification, LLC Page 106 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (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 32 o F 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 freque ncy 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 th an 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 r oadway (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 32 o F.

Record Keeping and Reporting R equirements [326 IAC 2

- 7

- 5(3)] [326 IAC 2

- 7

- 19]

D.12.7 Record Keeping Requirements To document the compliance status with Condition s D.12.4

- PM, PM 10 and PM 2.5 PSD BACT and Condition D.12.5

– Comp liance 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.Indiana Gasification, LLC Page 107 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (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.).Indiana Gasification, LLC Page 108 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
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, identif ied 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 em issions 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.1 3 .1 Permit No Defense This permit to construct does not relieve the Permittee of the respo nsibility 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 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.1 3 .3 Modification to Construction Conditions [326 IAC 2] All requirements of these constructio n 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, PM 10 and PM 2.5 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 Front

end Loader Slag Handling (EU

- 034A) and Vehicle Dust on Slag Pile (EU

- 034C) shall be as follows:

The PM, PM 10 and PM 2.5 emissions from the Front

- end Loader Sl ag 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.Indiana Gasification, LLC Page 109 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun Compliance Determination Requirements

D.13.5 Compliance Determination Requirements To demonstrate compliance status with Condition D.13.4

- PM, PM 10 and PM 2.5 PSD BACT, w et suppression shall be applied weekly to the entire slag storage pile/pad. Dust control is aided by
t he 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 a t the time of the scheduled treatment,

- The ambient air temperature is at or below 32 o 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 Monitorin g To demonstrate the compliance status with Conditions D.13.5, the Permittee shall maintain an ambient temperature monitor when ambient temperatures may drop below 32 o F.

Record Keeping and Report ing Requirements [326 IAC 2

- 7

- 5(3)] [326 IAC 2

- 7

- 19]

D.13.7 Record Keeping Requirement To document the compliance status with Condition s D.13.4

- PM, PM 10 and PM 2.5 PSD BACT and D.13.5

– Complianc e 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 b e maintained documenting the reason (i.e.: the ambient temperature, precipitation, or there is no material stored and no vehicle traffic at t he temporary slag storage area )Indiana Gasification, LLC Page 110 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
SECTION D.14 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(L) Electrical Circuit Breakers (approximately six) containing sulfur hexafluoride (SF 6 ) identified as emissions unit FUG

- SF6, permitted in 2012 , with fugitive GHG emissions
cont rolled 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.1 4 .1 Permit No Defense This permit to construct does not relieve the Permittee of the responsibility to c omply 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 fed eral requirements.

Effective Date of the Permit

D.1 4 .2 Effective Date of the Permit [IC 13

- 15

- 5

- 3] Pursuant to IC 13

- 15

- 5

- 3, th is section of this permit becomes effective upon its issuance.

D.1 4 .3 Modification to Construction Conditions [326 IAC 2] All requirements of these construction conditions s hall 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 .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 Deterioratio n (PSD)), the Best Available Control Technologies (BACT) for the Electrical Circuit Breakers ( FUG

- SF 6 ) shall be as follows:

The GHGs BACT for the Electrical Circuit Breaker (FUG

- SF 6 ) shall be the use of fully enclosed pressurized SF 6 circuit breakers with leak detection (low pressure alarm).Indiana Gasification, LLC Page 111 of 152 Rockport , Indiana T147

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SECTION D.15 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Description:

(M) Fugitive Equipment Leaks from the gasification, shift co nversion, gas cooling, AGR, CO 2 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 uni t description box is descriptive information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.1 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.1 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.1 5 .3 Modification to Constructio n Conditions [326 IAC 2] All requirements of these construction conditions shall remain in effect unless modified in a manner consistent with procedures established for revis ions pursuant to 326 IAC 2.

Operating Conditions

Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)]

D. 1 5 .4 CO, H 2 SO 4 SO 2 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 Equipme nt Leaks from the gasification, shift conversion, gas cooling, AGR, CO 2 compression

, WSA

, and methanation, identified as emissions unit 

### FUG & FUG

- WSA shall be as follows:

(1) The BACT for fugitive leaks of CO and H 2 SO 4 is no

- controls.

(2) The BACT for the fugitive leaks of SO 2 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 i nspection of the CO 2 compressors while they are in operation in any week in which there are at least twenty

- four (24) hours of operation of the CO 2 compressor to be inspected.

The LDAR program is incorporated into the permit in Section E.6Indiana Gasification, LLC Page 112 of 152 Rockport , Indiana T147

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D.15.5 Ha zardous Air Pollutants (HAPs) Minor Limits The single HAP and total HAP s from the Fugitive Equipment Leaks from the gasification, shift conversion, gas cooling, AGR, CO 2 compression

, WSA

, and methanation identified as FUG & FUG

- WSA shall be limited by comp liance 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 Re quirement s (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

- Gener al Record Keeping Requirements contains the Permittee's obligations with regard to the record keeping required by this condition.Indiana Gasification, LLC Page 113 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun
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

, 5 00 gallons

- identified as EU

- 027A through EU

- 027F.

(The information describing the process conta ined in this emissions unit description box is descriptive information and does not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.1 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 (I C 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 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.1 6 .3 M odification to Construction Conditions [326 IAC 2] All requirements of these construction conditions shall remain in effect unless modified in a manner consistent with proced ures established for revisions pursuant to 326 IAC 2.

Operating Conditions

Emission Limitations and Standards [326 IAC 2

- 7

- 5(1)]

D. 1 6 .4 H 2 SO 4 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 H 2 SO 4 emissions from the Sulfuric Acid tanks shall be limited by the use of a fixed roof tank and submerged fill.Indiana Gasification, LLC Page 114 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
SECTION D.17 EMISSIONS UNIT OPERATION CON DITIONS

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 emis sions 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 , wi th emissions controlled by a vapor recovery system and exhausting through one (1) vent, identified as S

025. [40 CFR 60 Subpart Kb].

(The information describing the process contained in this emissions unit description box is descriptive information and doe s not constitute enforceable conditions.)

Construction Conditions

General Construction Conditions

D.1 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 Cont rol 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 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.1 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

C ompliance Determination Requirements

D.17.4 Vapor Recovery System In order to ensure compliance, t he vapor recovery system must be operated at all times when the methanol tanks, identified as E U

- 024 and EU

- 02 5 are in operation

.Indiana Gasification, LLC Page 115 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun 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

re cording 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 dem onstrated 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 temp erature 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 tempe rature records ( on a 3

- hour average basis) for each vapor recovery system to demonstrate compliance.Indiana Gasification, LLC Page 116 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun
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.1 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 En vironmental 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 P ermit

D.1 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.1 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. 18 .4 Hazardo us Air Pollutants (HAPs) Control The Permittee shall operate a carbon adsorb er on the ZLD Inert Gas Vent. The carbon adsorb er shall be used at all times the ZLD inert gas ven t 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).

Compl iance Monitoring Requirements [ 326 IAC 2

- 7

- 5(1)][ 326 IAC 2

- 7

- 6(1)]

D. 18

. 5 P arametric Monitoring In order to demonstrate the compliance status with Condition D.18.4, t he Permittee shall record the pressure drop across the Sulfide d 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 practica bl e and no t later than during the next scheduled outage of the ZLD system. Actions may include replacement of the carbon, maintenance or repair

. A pressureIndiana Gasification, LLC Page 117 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun reading that exceeds the ma nufacturer’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).Indiana Gasification, LLC Page 118 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun
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 201 2

, with NO x emissions controlled by ultra

- low NO x 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 constitu te 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 boiler s 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 t he 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);Indiana Gasification, LLC Page 119 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun (22 ) 40 CFR 60.49b(i); and (23 ) 40 CFR 60.49b(o).Indiana Gasification, LLC Page 120 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun
SECTION E.2 EMISSIONS UNIT OPERATION CONDITIONS

Emissions Unit Descript ion:

(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 201 2

, with emissions controlled by a vapor recovery system and exhausting through one (1) vent, identi fied as S

025. [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 inc orporated 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 Liqu id 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, Subp art Kb (included as Attachm ent 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).Indiana Gasification, LLC Page 121 of 152 Rockport , Indiana T147

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SECTION E

. 3 EMISSIONS UNIT OPERATION CONDITIONS

Emission s 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 i ncoming sol id feedstock materials handling system, transferring material from the barge unloading facility and railcar unloading facility to storage piles and day bins are new affected source s .]

(1) One (1) barge unloading to hopper transfer point, permitted in 201 2 , 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 no minally rated at 1,500 acfm:

(a) One (1) barge unloading from the hopper to the belt, identified as EU

012B, 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, 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 EU

012H, 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, respe ctively;

(d) Two (2) rail hoppers unloading to the conveyor belts, identified as EU

012I 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 t hrough 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;Indiana Gasification, LLC Page 122 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun (g) Two (2) clas sification 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) classi fication 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 EU

012 Z, 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 unl oading 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 emissi ons 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 rate d 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 particulat e 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 nominall y rated at 3 3 ,7 6 0 dscfm, exhausting through two (2) stacks, identified as S

- 011A and S

- 011B, respectively. [Under 40 CFR 60, Subpart Y, theIndiana Gasification, LLC Page 123 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun process area solid feedstock conveying, storage, and feed bins (main and spare) are new affected source s .]

(The inf ormation 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 Provisio ns 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 emissio n 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 Par t 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, (include d 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 6 0.258(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);Indiana Gasification, LLC Page 124 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun (27) 40 CFR 60.258(c); and (28) 40 CFR 60.258(d).Indiana Gasification, LLC Page 125 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun
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 201 2

, 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 id entified as EU

- 010A through EU

- 010C, permitted in 201 2

, 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 C FR 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 wh en 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 o f 40 CFR Part 60, Subpar t IIII, included as Attachment E of this permit. The source is subject to the following portions of Subpart IIII:

(1) 40 CF R 60.4200(a ); (2) 40 CFR 60.4205(b); (3) 40 CFR 60.4205(c); (4) 40 CFR 60.4206; (5) 40 CFR 60.420 7(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 60.421 2(b); (16) 40 CFR 60.4212(c);Indiana Gasification, LLC Page 126 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (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 Rec ordkeeping 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 Subp art III.Indiana Gasification, LLC Page 127 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun
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 diese l 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 a n 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);Indiana Gasification, LLC Page 128 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun
SECTION E.6 LEAK DETECTION AND REPAIR (LDAR) CONDITIONS FOR THE FUGITIVE EQUIPMENTS LEAKS

Emissions Unit Description:

(M) Fugitive Equipment Leaks from the gasification, shif t conversion, gas cooling, AGR, CO 2 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 d escription 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 sourc e 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 t he 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, beginni ng 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.Indiana Gasification, LLC Page 129 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun 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 notificatio n 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 procedure s 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 a ny 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.Indiana Gasification, LLC Page 130 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun 

### INDIANA DEPARTMENT OF ENVIRONMENTAL MANAGEME NT 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.: T14 7

- 3046 4

- 00060

This certif ication 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 (spe cify)

 Affidavit (specify)

 Other (specify)

I certify that, based on information and belief formed after reasonable inquiry, the statements and information i n 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 6 1

- 53 IGCN 1003 Indianapolis, Indiana 4620 4

- 2251 Phone: (317) 23 3

- 0178

Fax: (317) 23 3

- 6865

PART 70 OPERATING PERMIT EMERGENCY OCCURRENCE REPORT

Source Name: Indiana Gasification, LLC Source Address: CR 200 N and Bas e Road

, Rockport , Indiana 47635 Part 70 Permit No.: T14 7

- 3046 4

- 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 ) bus iness hours ( 1

- 80 0

- 45 1

- 6027 or 31 7

- 23 3

- 0178, ask for Compliance Section); and

• The Permittee must submit notice in writing or by facsimile within two ( 2 ) working days (Facsimile Number: 31 7

- 23 3

- 6865), and follow the other requirements of 326 IAC 2

- 7

- 16.

I f 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

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- 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, P M

- 10, SO 2 , VOC, NO X , CO, Pb, other:

Estimated amount of pollutant(s) emitted during emergency:

Describe the steps taken to mitigate the problem:

Describe the corrective actions/response steps taken:

Describe the measures taken to minimize emi ssions:

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 substa ntial 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: S O 2 emission during Shutdown event Limit: not exceed 1. 9 2 tons per twelve (12) consecutive mo nth 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 Ad dress: CR 200 N and Base Road

, Rockport , Indiana 47635 Part 70 Permit No.: T147

- 30464

- 00060 Facility: Syngas Hydrocarbon Flare Parameter: S O 2 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.: T14 7

- 3046 4

- 00060 Facility: Wet Sulfuric Acid Plant Parameter: CO 2 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 Throu ghput Limit: Shall not exceed 1

, 430 billion Btu per twelve (12) consecutive mo nth 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: CO 2 Emissions Limit: shall not exceed 6

, 438 tons per twelve (12) consecutive month period with compliance determined at t he 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 CO MPLIANCE 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: CO 2 Emiss ions Limit: shall not exceed 2

, 884 tons per twelve (12) consecutive mo nth period with compliance determined at the end of each month.

QUARTER : YEAR:

Month Column 1 Column 2 Column 1 + Column 2

This M onth 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 15 2 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 Engine s (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 ENVIRONMENT AL 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: E mergency Diesel Engines Parameter: CO 2 Emissions Limit: shall not exceed 84 tons per twelve (12) consecutive mo nth period with compliance determined at the end of each month.

QUARTER : YEAR:

Month Colum n 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 Gasificati on, LLC Source Address: CR 200 N and Base Road

, Rockport , Indiana 47635 Part 70 Permit No.: T147

- 30464

- 00060 Facility: Auxiliary Boilers Parameter: CO 2 Emissions Limit: shall not exceed 88,164 tons per twelve (12) consecutive mo nth 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: Phon e:Indiana Gasification, LLC Page 142 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 

## INDIANA DEPARTMENT OF ENVIRONMENTAL MANA GEMENT 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: CO 2 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 Ad dress: 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: CO 2 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 1 2

- Month period To

- date Total

Month 1

Month 2

Month 3

 No deviation occurred in th is 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: CO 2 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:

Submi tted 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

, R ockport , Indiana 47635 Part 70 Permit No.: T147

- 30464

- 00060 Facility: Acid Gas Removal Unit Vents (EU

- 007A/B) Parameter: CO 2 Emissions Limit: shall not exceed 1,290,000 tons per twelve (12) consecutive month peri od 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 de viation 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 OF FICE 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 re ported 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: India na 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 ton s 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 / Posi tion: Signature: Date: Phone:Indiana Gasification, LLC Page 148 of 152 Rockport , Indiana T147

- 30464

- 00060 Permit Reviewer: Josiah Balogun



## INDIANA DEPARTMENT OF ENVIRO NMENTAL 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 h as 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 P ART 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.: T14 7

- 3046 4

- 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 r equired 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 a ttached 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 Requ irement (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 St eps 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 Deviati on: 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 6 1

- 53 IGCN 1003 Indianapolis, Indiana 4620 4

- 2251

Indiana Gasification, LLC CR 200 N and B ase 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 contain ed 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 Ro ad

, 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 applicat ion 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. T14 7

- 3046 4

- 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 affi rm 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) )SSIndiana Gasification, LLC Page 152 of 152 Rockport , Indiana T147

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- 00060 Permit Reviewer: Josiah Balogun
COUNTY OF )

S ubscribed and sworn to me, a notary public in and for County and

State of Indiana on this day of

, 20

. My
Commission expi res:

. 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 o f air emissions of lead at the IG facility. Although b oth 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 con centration 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 combu sted 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 al most 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 ca talyst beds that are in series

The particulate matter, including the lead, removed by these steps ends up in spent catalyst, spend sulfide d 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 p e r 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. Accordingl y, as presented in the lead and mercury spreadsheet s , 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 c oal 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

- Applicab ility 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 source s of mercury that ha s 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 mer cury 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 c ombusted at a power plant, much of the mercury is vaporize d . 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 a s 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 b y passing the syngas through sulfided carbon beds where the mercury is captured

. The sulf ided 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 perform ance of the sulfide carbon guard beds. This translates to a SNG emission factor for mercury of 1.65 lb/10 12 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 g as is also used. The mercury content of natural gas is estimated at 0.26 lb/10 12 Btu HHV . As presented in the lead and mercury spreadsheet s , 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 als o treated with a sulfided carbon adsorption bed

. This sulfide d 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 mill ing operation s . As presented in the at tached spreadsheet

, the maximum emissions of mercury in the coal dust are another 0. 0 3 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 6 0, 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 EU

012W an d 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 Ro ads (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 o perations 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 sourc es at the facility are attached . Although th e 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 th e 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 whi ch 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 whichIndiana Gasification, LLC Page 2 of 3 Rockport, Indiana T 147

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will serve to help contain emissions. Wet suppression with water sprays a nd 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 emission s. 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 b ull 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 “as

needed” 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 o f 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 t hat 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

- 03 4C]

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 C aterpillar 824H Wheel Dozer.Indiana Gasification, LLC Page 3 of 3 Rockport, Indiana T 147

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- 000 6 0 Permit Reviewer: Josiah Balogun 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 supp ressant (with or instead of water), Indiana Gas ification 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 contr ol 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 pursu ant 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 require d in 326 IAC 2.

## A ttachment 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 a nd 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 Poll**  **utants 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 em issions, 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 mechanica l work and which is not mobile. Statio nary 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, provide d 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 a rea source under this subpart. Notwithstanding the previous sentence, you must continue to comply with the provisions of this sub partIndiana Gasification LLC Page 2 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 el igible 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 R ICE 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 construc tion or reconstruction of the stationary RICE before June 12, 2006.

(iv) A change in ownership of an existin g 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 cons truction 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 afte r June 12, 2006.

(iii) A stationary RICE located at an area source of HAP emissions is new if you commenced construction of the stationary RIC E on or after June 12, 2006.

(3) Reconstructed stationary RICE. (i) A stationary RICE with a site rating of more t han 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 af ter 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 emission s 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 e xcept for the initial notification requirements of §63.6645(f).

(i) The stationary RICE is a new or reconstructed emergency statio nary RICE with a site rating of more than 500 brake HP located at a major source of HAP emissions.Indiana Gasification LLC Page 3 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 l ocated 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 basi s 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 followi ng 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 br ake 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 a t 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 emiss ions;

(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 subp art IIII, for compress ion 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 stationar y 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 o r 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 equa l 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 sit e 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 emissi ons.Indiana Gasification LLC Page 4 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 ex isting 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 late r 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 limitation s 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 a nd 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 a fter 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 rec onstructed 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 s tartup 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 sub part 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, 20 08, 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 s ource.

(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 CF R 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]Indiana Gasification LLC Page 5 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 th**  **an 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 t han 500 brake HP located at a major source of HAP emissions, you must comply with the emissio n 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 sour ce 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 br ake HP located at a m ajor 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 2SL B 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 ann ual 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 limit ations 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 thr ee 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 br ake H P 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. 1 8, 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 sourc**  **e 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.Indiana Gasification LLC Page 6 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 s ubpart 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 emissio ns, 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 locat ed 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 ratin g 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 requir ements in 40 CFR 80.510(b) for nonroad diesel fuel. Existing non

- emergency CI stationary RICE located i n 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

**§ 63.6**  **605 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 al l 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. T he general duty to minimize emissions does not require y ou 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 m ay 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

**§ 63.66**  **10 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?** Indiana Gasification LLC Page 7 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 Ta ble 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 em ission 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 performa nce 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 t est 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 p erformed, 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 s ite 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** 

**c ompliance 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**Indiana Gasification LLC Page 8 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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## emissions or an existing stationary RICE located at an area source of HAP **emissions?**

If you o wn 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 t his section.

(a) You must conduct any initial performance test or other initial compliance demonstration according to Tables 4 and 5 to th is 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 be en previously conducted, but the test must meet all of the conditions descr ibed 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 mu st 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 ad justments, 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 limitat ions 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 subp art. If you own or operate a non

- operational stationary RICE that is subject to performance testing, y ou 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 run s 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:Indiana Gasification LLC Page 9 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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C i = concentration of CO or formaldehyde at the control device inlet,

C o = concentration of CO or formaldehyde at the control device outlet, and

R = percent reduction of CO or fo rmaldehyde 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 (CO 2 ). If pollutant concentr ations are to be corrected to 15 percent oxygen and CO 2 concentration is measured in lieu of oxygen concentration measurement, a CO 2 correction factor is needed. Calculate the CO 2 correction factor as described in paragraphs (e)(2)(i) through (iii) of this se ction.

(i) Calculate the fuel

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

Where:

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

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

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

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

(ii) Calculate the CO 2 correction factor for correcting measurement data to 15 pe rcent oxygen, as follows:

Where:

X co2 = CO 2 correction factor, percent.

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

(iii) Calculat e the NO X and SO 2 gas concentrations adjusted to 15 percent O 2 using CO 2 as follows:

Where:

%CO 2 = Measured CO 2 concentration measured, dry basis, percent.Indiana Gasification LLC Page 10 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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(f) If you c omply 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 concentrat ion 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 m onitored thereafte r; or for approval of no operating limitations. You must not conduct the initial performance test until after the petition ha s been approved by the Administrator.

(g) If you petition the Administrator for approval of operating limitations, your petition mu st 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 emission s, 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 es tablish 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 meth ods 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 mu st 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 c ould change intentionally ( e.g., operator a djustment, 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 t hem 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 limit ations.

(i) The engine percent load during a performance test must be determined by documenting the calculati ons, 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 informatio n 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 assumptio ns that were made to estimate or calculate percent load during the performance test must be clearly explained. If measurement devices such as f low meters, kilowatt meters, beta analyzers, stain gauges, etc. are used, the model number of the measurement dev ice, and an estimate of its accurate in percentage of true value must be provided.Indiana Gasification LLC Page 11 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 CO 2 at both the inlet and the outlet of the control device according to the requirements in paragrap hs (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 rela tive 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 da ta recording) for each successive 15

- minute period. You must have at least two data points, with each re presenting a different 15

- minute period, to have a valid hour of data.

(4) The CEMS data must be reduced as specified in §63.8(g)(2) and recorded in parts per million or parts per billion (as appropriate for the applicable limitation) at 15 percent oxygen or the equivalent CO 2 concentration.

(b) If you are required to install a continuous parameter monitoring system (CPMS) as specified in Table 5 of this subpart, y ou 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 requiremen ts 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 speci fied in §63.8(f)(4), yo u 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 spec ifications 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 representat ive 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 recordkee ping 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 da ta 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 la rger.

(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.Indiana Gasification LLC Page 12 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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(6) You must conduct a performance evaluation of each CPMS in accorda nce 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 per cent or more of the gross heat input on an annual basis, you must monitor and record y our 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 reasonabl y minimizes HAP emissions.

(d) If you are operating a new or reconstructed emerge ncy 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 o r operate any of the following stationary RICE, you must operate and maintain the stationary RICE and after

treatment control device (if any) according to the manufacturer's emission

- related written instructions or develop your own maintenance plan which m ust 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 a t 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 majo r source of HAP emissions;

(3) An existing emergency or black start stationary RICE located at a n 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 RIC E 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 sit e 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 existin g, 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 stationa ry 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 b rake 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 man ufacturer'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 app rove different maintenance requirements that are as pr otective 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 p revents crankcase emissions from being emitted to the atmosphere, orIndiana Gasification LLC Page 13 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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(2) Install an open crankcase filtration emission control system that reduces emissions from the crankcase by filtering the e xhaust 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 durin g startup and minimize the engine's startup time to a period needed for appropriate and safe loading of the engine, not to exce ed 3 0 minutes, after which time the emission standards applicable to all times other than startup in Tables 1a, 2a, 2c, and 2d to t his subpart apply.

(i) If you own or operate a stationary CI engine that is subject to the work, operation or management practice s 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 pro gram in order to extend the specified oil change requirement in Tables 2c and 2d to this subpart. The oil anal ysis 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 conde mning 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 cont ent (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 re ceiving 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 m ust 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 S I 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 a nalysis program in order to extend t he 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 a t 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 t he 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 exceede d, 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 cha nges 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 Tabl e 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 acc ording to the requirements in §63.6645.


## Continuous Compliance Requirements

**§ 63.6635**  **How do I monitor and collect data to demonstrate continuous**Indiana Gasification LLC Page 14 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 d ata 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 vali d 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 eac h 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 deviat ions 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 parame ters, 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) Y ou 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
ma jor 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 RIC E 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 stati onary 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 reconstru cted stationary RICE that com busts 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 stationa ry 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 5 00 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 th e emergency stationary RICE according to the requir ements 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 und er thisIndiana Gasification LLC Page 15 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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subpart and will need to meet all requirements f or 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 tha t the tests a re 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 owne r or operator may peti tion 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 s tandards require maintenanc e 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 otherw ise supply power as part of a financial arrangement with another entity; except th at 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 defici ency, 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 t he emergency condition is no longer imminent. The 15 hours per year of demand response operation are count ed 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 provide d 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 paragra phs (f)(2)(i) through (iii) of this section, the engine will not be co nsidered 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 RIC E 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 lo cated at a major source of HAP emissions.

(2) An existing stationary RICE located at an area source of HAP emissions.Indiana Gasification LLC Page 16 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 stationar y 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 befo re 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 emi ssions 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 notifi cation, 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 sub mit 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 th e 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 t o 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, y ou 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 o f Compliance Status, including the performance test results, before the close of business on the 60th day following the completion of the performance test accor ding 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 s ection.

(1) For semiannual Compliance reports, the first Compliance report must cover the period beginning on the compliance date thatIndiana Gasification LLC Page 17 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 foll owing 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 semi annual 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 su bject 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 subs equent 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 p eriod 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 e nd 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 add ress.

(2) Statement by a responsible official, with that official's name, title, and signature, certifying the accuracy of the cont ent of the report.

(3) Date of report and beginning and ending dates of the reporting period.

(4) If you had a malfunction du ring 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 a re 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 monito ring system (CMS), including CEMS and CPMS, was out

- of

control, as specified in §63.8(c)(7), a statement that there were no periods during which the CMS was out

- of

- control during the reporting period.

(d) For each deviation from an emission or operating li mitation 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 infor mation in paragraphs (d)(1) and (2) of this section.Indiana Gasification LLC Page 18 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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

- l evel) 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 durati on 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 a t 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 pe riod.

(f) Each affected source that has obtained a title V operating permit pursuant to 40 CFR part 70 or 71 must report all deviat ions 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 incl udes all required information concerning deviations from any emission or operating limitation in this subpart, submission of the Compl iance 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 whic h 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 consu mption on an annual basis.Indiana Gasification LLC Page 19 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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(2) The operating limits provided in your federally en forceable 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 emissio n 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 do cumentation 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 equipmen t) 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 equipmen t.

(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 usua l

man ner 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 emissio n 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 re cords 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 ho urs are spent for non

- emergency operation. If the engines are used for demand response operation, the owner or operator must keepIndiana Gasification LLC Page 20 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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) A n 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, mainten ance, 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 t o §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 §§6 3.1 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 HA P 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 rat ing 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 existi ng 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 o f 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 stati onary RICE that combusts landfill gas or digester gas equivalent to 10 percent or m ore 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 we ll 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 age ncy 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 a nd 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:Indiana Gasification LLC Page 21 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 defi ned 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 wa s 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; an d 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 stati onary R ICE.

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 pro cessing 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 in cluded in the operating permit for any affected source require d to obtain such a permit; or

(3) Fails to meet any emission limitation or operating limitation in this subpart during malfunction, regardless or whether o r not such failure is permitted by this subpart.

(4) Fails to satisfy the general duty to minimize em issions 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

- igniti on. This process is also known as compression ignition.Indiana Gasification LLC Page 22 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 an aerobic decomposition of organic waste materials and composed principally of methane and CO 2

.

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 cri tical networks or equipment (including power supplied to portions of a facility) when electric power from the local utility (or the normal powe r 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 anot her 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 n ot comply with the requirements specified in §63.6640(f), then it is not considered to be an emergency stationary RICE under this subpa rt.

Engine startup means the time from initial start until applied load and engine and associated equipment reaches stead y state or normal operation. For stationary engine with catalytic controls, engine startup means the time from initial start until appli ed load and engine and associated equipment, including the catalyst, reaches steady state or normal operation.

Four

- stro ke 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 com bustion 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 c ontact 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 med ical 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 degre es 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 com posed principally of methane and CO 2

.
Lean burn engine means any two

- stroke or four

- stroke spark ignited engine that does not meet the definition of a rich 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.Indiana Gasification LLC Page 23 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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Liquid fuel means any fuel in liquid form at standard temperature and pressure, including but not limited to di esel, 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 equipmen t (as defined in this section)) and emissions from any pipeline compressor station or pump station shall not be aggregated with emissions from other similar unit s, 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 o il and gas production facility, as defined in §63.1271 of subpart HHH of t his 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 aggr egated 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.

M

alfunction 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 formation s 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 (NO X ) control device for rich burn engines that, in a two

- step reaction, promotes the conversion of excess oxygen, NO X , CO, and volatile organic compounds (VOC) into CO 2 , nitrogen, and water.

Oil and 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 transmissi on and storage source category. For purposes of a major source determination, facility (including a building, structure, or installa tion) means oil and natural gas production and processing equipment that is located within the boundaries of an individual s urface site as defined in this section. Equipment that is part of a facility will typically be located within close proximity to other eq uipment 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 sur face sites, whether or not connected by a road, waterway, power line or pipeline, shall not be considered part of the same facility. Examples of facilities in the oil and natural gas production source category include, but are not limited to, well sites, satellite ta nk batteries, central tank batteries, a compressor station that transports natural gas to a natural gas processing plant, and natural gas processing plants.

Oxidation catalyst means an add

- on catalytic control device that controls CO and VOC by oxidation.

Peaking unit or engine means any standby engine intended for use during periods of high demand that are not emergencies.

Percent load means the fractional power of an engine compared to its maximum manufacturer's design capacity at engine site conditions. Percent load may range between 0 percent to above 100 percent.

Potential to emit means the maximum capa city 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 ho urs 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 an d naturalIndiana Gasification LLC Page 24 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 s torage 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 cus tody transfer.

Production well means any hole drilled in the earth from which crude oil, condensate, or field natural gas is extracted.

Propane means a colorless gas derived from petroleum and natural gas, with the molecular structure C 3 H 8

.

Residential eme rgency 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 ignit ed 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 manufac tured as rich burn engines, but modified prior to December 19, 2002 with passive emission control technology for NO X (such as pre

combustion chambers) will be considered lean burn engines. Also, existing engines where there are no manufacturer's recommendations regarding air/fuel ratio will be considered a rich bur n 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

- f ueled 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 eng ines usually use a throttle to regulate intake air f low 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 aver age ratio of less than 2 parts diesel fuel t o 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 mecha nical 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 emi ssions 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.

Surfac e 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.Indiana Gasification LLC Page 25 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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**  **Reconstruc ted 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 recon structed 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. Re duce 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 sp ent 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 forma ldehyde in the stationary RICE exhaust to 350 ppbvd or less at 15 percent O 2

1 Sources can petition the Administrator pursuant to the requirements of 40 CFR 63.6(g) for alternative work practices.

[75 FR 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 a nd 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 require ment 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 thanIndiana Gasification LLC Page 26 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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### to 350 pp bvd 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 st ationary 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 12 867, Mar. 9, 2011]



## Table 2a **to 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 emissi on 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 le ss at 15 percent O 2 

### . If you commenced construction or reconstruction between December 19, 2002 and June 15, 2004, you may limit concentration of formaldehyde to 17 ppmvd or less at 15 percent O 2 

### until June 15, 2007 Minimize the engine's time spent at idle

a nd 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 9 3 percent or more; orIndiana Gasification LLC Page 27 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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### stationary RICE
b. Limit concentration of formaldehyde in the stationary RICE exhaust to 14 ppmvd or less at 15 percent O 2


### 3. CI stationary RICE a. Reduce CO emissions by 70 percent or more; or

b. Limit concentration of formaldehyde in th e stationary RICE exhaust to 580 ppbvd or less at 15 percent O 2

1 Sources can petition the Administrator pursuant to the requirements of 40 CFR 63.6(g) for alternative work practices.

[75 FR 9680, Mar. 3, 2010]


## Table 2bto Subpart ZZZZ of Part 63

**— Operatin**  **g 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**  **Ig nition 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 recons tructed 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 exis ting 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 c omplying 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 R ICE 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.Indiana Gasification LLC Page 28 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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### emissions and not using an oxidat ion 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 RI CE 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 Stationar y 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 igniti on stationary RICE located at a major source of HAP emissions and existin g 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 an d 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 3 0 minutes, after which time the non

- startup emission limitations apply. 3



### 2. Non

- Emergency, non

black start stationary CI RICE <100 HP a. Change oil and filter every 1,000 hours of operation or annually, whichever comes first; 2


### b. Inspect air cleaner every 1,000 hours of operation orIndiana Gasification LLC Page 29 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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, non

black start CI stationary RICE 100≤HP≤300 HP Limit concentration of CO in the stationary RICE exhaust to 230 ppmvd or less at 15 percent O 2


### 4. Non

- Emergency, non

black 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 O 2 

### ; or b. Reduce CO emissions by 70 percent or more.

5. Non

- Emergency, non

black start stationary CI RICE >500 HP a. Limit concentration of CO in the stationary RICE exhaust to 23 ppm vd or less at 15 percent O 2 

### ; 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. Ins pect 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, non

black start stationa ry 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 everyIndiana Gasification LLC Page 30 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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, non

black start 2SLB stationary SI RICE <100 HP a. Change oil and filter every 4,320 hours of operation or annually, whic hever 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

- em ergency, non

black start 2SLB stationary RICE 100≤HP≤500 Limit concentration of CO in the stationary RICE exhaust to 225 ppmvd or less at 15 percent O 2


### 10. Non

- emergency, non

black start 4SLB stationary RICE 100≤HP≤500 Limit concentration of CO in the st ationary RICE exhaust to 47 ppmvd or less at 15 percent O 2


### 11. Non

- emergency, non

black start 4SRB stationary RICE 100≤HP≤500 Limit concentration of formaldehyde in the stationary RICE exhaust to 10.3 ppmvd or less at 15 percent O 2


### 12. Non

- emergency, n on

black start landfill or digester gas

- fired stationary RICE 100≤HP≤500 Limit concentration of CO in the stationary RICE exhaust to 177 ppmvd or less at 15 percent O 2

1 If an emergency engine is operating during an emergency and it is not possible to shu t 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 re quired 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 perform ed as soon as practicable after the emergency has ended or the unacceptable risk un der Federal, State, or local law has abated.Indiana Gasification LLC Page 31 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 und er 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 lo cated 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 hose s 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 O 2 

### ;

or
b. Reduce CO emissions by 70 percent or more.Indiana Gasification LLC Page 32 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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### 3. Non

- Emergency, non

- black start CI stationar y RICE >500 HP a. Limit concentration of CO in the stationary RICE exhaust to 23 ppmvd at 15 percent O 2 

### ;

or
b. Reduce CO emissions by 70 percent or more.
4. Emergency stationary CI RICE and black start stationary CI RICE. 2 

### a. Change oil and filter

e very 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 come s 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 stationar y 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. Ins pect 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 come s first; 1


### b. Inspect spark plugs every 4,320 hours ofIndiana Gasification LLC Page 33 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 a ll 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 p ercent O 2 

### ;

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 hoursIndiana Gasification LLC Page 34 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 O 2 

### ; 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 S ources have the option to utilize an oil analysis program as described in §63.6625(i) in order to extend the specified oil ch ange requirement in Table 2d of this subpart.

2 If an emergency engine is operating during an emergency and it is not possible to sh ut 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, Sta te, 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. T he 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 mus t . . .Indiana Gasification LLC Page 35 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 Cond uct 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 f

ormaldehyde 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 sta rt 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 subsequ ent 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 followingIndiana Gasification LLC Page 36 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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### . . the require ment to

. . . requirements . . .

1. 2SLB, 4SLB, and CI stationary RICE a. Reduce CO emissions i. Measure the O 2 

### at the inlet and outlet of the control device; and (1) Portable CO and O 2 

### analyzer (a) Usin g ASTM D6522

– 00 (2005) a 

### (incorporated by reference, see §63.14). Measurements to determine O 2 

### must be made at the same time as the measurements for CO concentration.

ii. Measure the CO at the inlet and the outlet of the control device (1) Portable CO and O 2 

### analyzer (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 O 2 

### , dry basis.

2. 4SRB stationary RICE a. Reduce formaldehyde emissions i. Select the
samp ling 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 O 2 

### at 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 O 2 

### concentration must be made at the same time as the measurements for formaldehyde concentration.

iii. Measure moisture content at the inlet and outlet of the control device; and (1) Method 4 of 40 CFR part 60, appendix A, or Test Method 320 of 40 CFR part 63, appendix A, or ASTM D 6348

– 03 (a) Measurements to determine moisture content must be made at the same time and location as the measurements for formaldehyde concentration.

iv. Measure formaldehyde at the inlet and the outlet of the control device (1) Method 320 or 323 of 40 CFR part 63, appendix A; or ASTM D6348

– 03, c 

### provided in ASTM D6348

– 03 Annex A5 (A nalyte Spiking Technique), the percent R must be greater than or equal to 70 and less than (a) Formaldehyde concentration must be at 15 percent O 2 

### , dry basis. Results of this test consist of the average of the three 1

- hour or longer runs.Indiana Gasification LLC Page 37 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 co ntrol device, the sampling site must be located at the outlet of the control device.

ii. Determine the O 2 

### concentration of the stationary RICE exhaust at the sampling port location; and (1) Method 3 or 3A or 3B of 40 CFR part 60, appendix A, or ASTM Method D6522

– 00 (2005) (a) Measurements to determine O 2 

### concentration 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 loc ation; 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 concen tration.

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

– 03, c 

### provided in ASTM D6348

– 03 Annex A5 (Analyte Spiking Technique), the percent R must be greater than or equal to 70 and less than or equal to 130 (a) Formaldehyde concentration must be at 15 percent O 2 

### , dry basis. Results of this test consist of the average of the three 1

- hour or longer runs.

v. Measure CO at the exhaust of the stationary RICE (1) Met hod 10 of 40 CFR part 60, appendix A, ASTM Method D6522

– 00 (2005), a 

### Method 320 of 40 CFR part 63, appendix A, or ASTM D6348

– 03 (a) CO Concentration must be at 15 percent O 2 

### , dry basis. Results of this test consist of the average of the three 1

- hour longer r uns.

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 andIndiana Gasification LLC Page 38 of 54 Rockport, Indiana P SD and TV Permit No.: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun

Materials, 100 Barr Harbor Drive, West Conshohocken, PA 19428

– 2959, or University Microfilms International, 300 North Zeeb Road, Ann Arbor, MI 48 106.

[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 a s 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 non

emergency stationary CI RICE >500 HP located at an area source of HAP, and existing non

- eme rgency 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 th e 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 non

emergenc y 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 a nd 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 toIndiana Gasification LLC Page 39 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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### major source of HAP, non

- emergency stationary CI RICE >500 HP located at a maj or source of HAP, existing non

emergency 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 parameter s 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 majo r source of HAP, existing non

- emergency stationary CI RICE >500 HP located at an area source of HAP, and existing non

emergency 4SLB stationary RICE >500 HP located at an area source of HAP that are operated more than 24 hours per calendar year a. Limit th e 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
pa rameters 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 non

emergency 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 O 2 

### or CO 2 

### at 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, a ppendix 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 perce nt 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 non

a. Limit the concentration of CO, and using a CEMS i. You have installed a CEMS to continuously monitor CO and either O 2 

### or CO 2 

### at the outlet of the oxidation catalyst according to the requirements in §63.6625(a); andIndiana Gasification LLC Page 40 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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### emergency 4SLB stationary RI CE >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 >50 0 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 require ments 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 perf ormance 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. Lim it 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 emissionIndiana Gasification LLC Page 41 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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### limitation; and

ii. You have installed a CPMS to continuo usly 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 non

emergency 4SRB stationary RICE >500 HP a. Limit the concentration of formaldehyde in the stationary RICE exhaust and using oxidation catalyst or NSCR i. The average formaldehyde concentration, corrected to 15 percent O 2 

### , dry basis, from the three test runs is less than or equal to the formaldehyde emission limitation; and ii. You have installed a CPMS to continuously monitor catalyst inlet tempe rature 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 non

emergency 4SRB stationary RICE >500 HP a. Limit the concentration of formaldehyde in the stationary RICE exhaust and not using oxidation catalyst or NSCR i. The average formaldehyde concentration, corrected to 15 percent O 2 

### , dry basis, from the three test runs is less than or equal to the formaldehyde emission limitation; and ii. You have installed a CPMS to continuousl y 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 non

emergency stationary CI RICE 300<HP≤500 located at an area source of HAP a. Reduce CO or formaldehyde emissions i. The average reduction of emissions of CO or formaldehyde, as ap plicable determined from the initial performance test is equal to or greater than the required CO or formaldehyde, as applicable, percent reduction.Indiana Gasification LLC Page 42 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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### 13. Existing non

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

e mergency 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 O 2 

### , dry basis, f rom 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 Practic es, 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 dem onstrate continuous compliance by . . .

1. New or reconstructed non

emergency 2SLB stationary RICE >500 HP located at a major source of HAP, new or reconstructed non

emergency 4SLB stationary RICE ≥250 HP located at a major source of HAP, and new or recon structed non

emergency CI stationary RICE >500 HP located at a major source of HAP a. Reduce CO emissions and using an oxidation catalyst, and using a CPMS i. Conducting semiannual performance tests for CO to demonstrate that the required CO percent reduct ion 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 inl et temperature; and
v. Measuring the pressure drop across the catalyst once per month and demonstrating that the pressure drop across the catalyst is within the operating limitation established during the performance test.

2. New or reconstructed non

emergency 2SLB stationary RICE >500 HP located at a major source of HAP, new or reconstructed non

emergency 4SLB stationary RICE ≥250 HP located at a major source of HAP, and new or reconstructed non

a. Reduce CO emissions and not using an oxidation catalyst, and using a CPMS i. Conducting semiannual performance tests for CO to demonstrate that the required CO percent reduction is achieved; a 

### and ii. Collecting the approved operating
param eter (if any) data according to §63.6625(b); andIndiana Gasification LLC Page 43 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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### 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 non

emergency 2SLB stationary RICE >500 HP located at a major source of HAP, new or reconstructed non

emergency 4SLB stationary RICE ≥250 HP located at a major source of HAP, new or reconstructed non

emergency stationary CI RICE >500 HP located at a major source of HAP, existing non

- emergency stati onary CI RICE >500 HP, existing non

emergency 4SLB stationary RICE >500 HP located at an area source of HAP that are operated more than 24 hours per calendar year a. Reduce CO emissions or limit the concentration of CO in the stationary RICE exhaust, and u sing 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 a s 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 toIndiana Gasification LLC Page 44 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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### source of HAP NSCR §63.6625(b); and ii. Reducing these data to 4

- hour rolling averages; and
iii. Maintaining the 4

- hour rolling

av erages 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 achie ved. a



### 7. New or reconstructed non

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

- emergency 4SLB stationary RICE 250 ≤HP≤500 located at a major source of HAP a. Limit the concentration of formaldehyde in the stationary RICE exhaust and using oxidation catalyst or NSCR i. Conducting semiannual performance tests for formaldehyde to demonstrate that your emissions remain at or below the formaldehyde concentration limit; a 

### and ii. Collecting the catalyst inlet temp erature 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 pressur e drop across the catalyst once per month and demonstrating that the pressure drop across the catalyst is within the operating limitation established during the performance test.

8. New or reconstructed non

emergency stationary RICE >500 HP located at a m ajor 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 sem iannual 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; andIndiana Gasification LLC Page 45 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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### iv. Maintaining the 4

- hour rolling averages within the operating limitations for the operating parameters established during the performance test.
9. Existing emergency and black start stationary RICE ≤500 HP located at a major source of HAP, existing non

emergency stationary RICE <100 HP located at a major source of HAP, existing emergency and black start stationary RICE located at an area source of HAP, existing non

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

- emergency 2SLB stationary RICE located at an area source of HAP, existing non

emergency landfill or digester gas stationary SI RICE located at an area

so urce of HAP, existing non

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

emergency 4SLB and 4SRB stationary RICE >500 HP located at an area source of HAP that operate 24 hours or less per calendar year a. Wor k 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 practic able 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
sta tionary 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 reductio n 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 rollingIndiana Gasification LLC Page 46 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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### 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 wit hin 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
t han 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 performan ce 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 for maldehyde 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 op erating 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, w hichever 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; andIndiana Gasification LLC Page 47 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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### 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 with in 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

ca lendar 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 fi rst, 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 th e 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 establis hed 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 submitIndiana Gasification LLC Page 48 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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- 00060 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 non

emergency 4SRB stationary RICE >500 HP located at a major source of HAP; existing non

- emergency, non

- black start stationary CI RICE >300 HP located at an area source of HAP; existing non

emergency, non

- black start 4SLB and 4SRB stationary RICE >500 HP located at an area source of HAP and opera ted 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 statem ent 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 g as 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 land fill gas or digester gas, is equivalent to 10 percent or more of theIndiana Gasification LLC Page 49 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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### 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 devia tions 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 i n §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 term s 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.Indiana Gasification LLC Page 50 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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 crit eria 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 t ests and reduction of data Yes Subpart ZZZZ specifies test methods at §63.6620.Indiana Gasification LLC Page 51 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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) Perf ormance 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 mai ntenance 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 installat ion 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) C MS requirements Yes Except that subpart ZZZZ does not require COMS.
§63.8(d) CMS quality control Yes.Indiana Gasification LLC Page 52 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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) Initi al 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) Notificatio n 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 visibl e 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 Subp art ZZZZ does not containIndiana Gasification LLC Page 53 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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) Notificatio n 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 o f 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) R ecords 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 a pplicability 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.Indiana Gasification LLC Page 54 of 54 Rockport, Indiana P SD and TV Permit No.: 147

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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.

§6 3.10(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 Y es.

[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

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## Subpart Y

**— Standards of Performance for Coal Preparation and Processing**  **Plants**

Source: 74 FR 5197 7, 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) (20 0 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 af ter 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) Th e 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 s ystems.

(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 comm enced construction, reconstruction or modification after May 27, 2009: Thermal dryers, pneumatic coal

cleaning equipment (air tables), coal processing and conveying equipment (including breakers and crushers), coal storage systems, transfer and loading sys tems, 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 acc ording 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 re lative particulate matter loadings.Indiana Gasification LLC Page 2 of 15 Rockport, Indiana PSD and TV Permit No.: 147

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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, 2 009, 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 m ore 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 pl ant.

(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 f acility 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 (meg agrams 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 p owered 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 pe riod.

(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).Indiana Gasification LLC Page 3 of 15 Rockport, Indiana PSD and TV Permit No.: 147

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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, reconstructe d, 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 an d 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 fir st, 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, whic hever 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 d ryer constructed, reconstructed, or modified after May 29, 2009, subject to the provisions of this subpart must also meet the applicable standards for sulfur dioxide (SO 2 ), and combined nitrogen oxides (NO X ) and carbon monoxide (CO) as specified in paragra phs (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 reconstruc ted 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.Indiana Gasification LLC Page 4 of 15 Rockport, Indiana PSD and TV Permit No.: 147

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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 con tain 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 SO 2 emissions in either paragraph (b)(2)(i) or (b)(2)(ii) of this section.

(i) The owner or opera tor must not cause to be discharged into the atmosphere from the affected facility any gases that contain SO 2 in 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 affecte d facility any gases that either contain SO 2 in excess of 520 ng/J (1.20 lb/MMBtu) heat input or contain SO 2 in 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 sou rce subject to an SO 2 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 SO 2 limits 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 NO X and 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 NO X and CO in excess of 280 ng/J (0.65 lb/MMBtu) heat input.

(ii) For each thermal dryer reconst ructed 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 NO X and CO in excess of 430 ng/J (1.0 lb/MMBtu) heat input.

(iii) T hermal 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 NO X limit and/or CO limit under another subpart of this part, or that use waste heat or r esidual from the combustion of coal or residual oil as their only thermal input, are not subject to the combined NO X and CO limits of this section.

(c) Thermal dryers receiving all of their thermal input from an affected facility covered under another 40 CF R 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 conducte d 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.Indiana Gasification LLC Page 5 of 15 Rockport, Indiana PSD and TV Permit No.: 147

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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

- cleanin g 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 performa nce 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 requ irements 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 facil ity 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 (0.01 0 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 e quipment 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 i s 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 condition s. 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 affecte d 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 t his section as specified in paragraphs (c)(3)(i) through (iv) of this section.Indiana Gasification LLC Page 6 of 15 Rockport, Indiana PSD and TV Permit No.: 147

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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 parag raph (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 w ith 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 w hile 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 subpar t, 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 Administrat or 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 Healt h 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 emiss ions control plan the site

- specific impacts associated with the use of such chemical dust suppressants.Indiana Gasification LLC Page 7 of 15 Rockport, Indiana PSD and TV Permit No.: 147

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## § **60.255 Performance tests and other compliance requirements.** 

(a) An owner or operator of each affected facility that commenced construction, recon struction, 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, SO 2 , or combined NO X and CO emissions standard, an initial performance test must be performed. Thereafter, a new performanc e 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 perce nt 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 tha t 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 own er 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 a ffected 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 perf ormance 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 o f) 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 modific ation 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 ow ner 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 emi ssions 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,Indiana Gasification LLC Page 8 of 15 Rockport, Indiana PSD and TV Permit No.: 147

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(2) The control device manufacturer's recommended maintenance procedures are followed, an d

(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 delegate d 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 man ufacturer'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 pr eparation 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 specifi ed 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. I f 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) Pre pare 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, s ee 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 Standar ds; 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 ap proved 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 constructio n, 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 m ust be installed, calibrated, maintained, and continuously operated according to the requirements in paragraphs (g)(1) and (2) of this section.Indiana Gasification LLC Page 9 of 15 Rockport, Indiana PSD and TV Permit No.: 147

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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 d rift 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 perc ent 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 check s, 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, cali bration 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, reconstr uction, 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 paragr aphs (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 defi ciencies 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 Contin**  **uous monitoring requirements.**Indiana Gasification LLC Page 10 of 15 Rockport, Indiana PSD and TV Permit No.: 147

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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 applicab le 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 me asurement 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 di scharge 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 §6 0.13(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 ton s) 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 sect ion.

(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 monit oring 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 fo r 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 eac h 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 scrub bers, 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 a verage basis.Indiana Gasification LLC Page 11 of 15 Rockport, Indiana PSD and TV Permit No.: 147

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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 o f 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 rela tive 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 dete ction 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 o r 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 ma y 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) T he 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 site

specific 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. T he 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 para graph (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 identi fies in the monitoring plan this specific condition as one that could lead to an alarm, adequately explains why it is not feasible to alleviate thisIndiana Gasification LLC Page 12 of 15 Rockport, Indiana PSD and TV Permit No.: 147

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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 fab ric 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 con trol 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 method**  **s 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 t o 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 obser vation 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 deter mine 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 su n 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 perpendicula r 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 mo re than three emissions points may be read concurrently.Indiana Gasification LLC Page 13 of 15 Rockport, Indiana PSD and TV Permit No.: 147

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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 opaci ty 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 p oint.

(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 procedu res 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 t he 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 th e 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 termin ate 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 desulfurizati on (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 roo f 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 SO 2 concentration. A minimum of three valid test runs are needed to comprise an SO 2 performance test.

(7) Method 7 or 7E of appendix A

– 4 of this part shall be used to determin e the NO X concentration. A minimum of three valid test runs are needed to comprise an NO X performance 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 NO X performance tests.


## § **60.258 Reporting and recordkeeping.** Indiana Gasification LLC Page 14 of 15 Rockport, Indiana PSD and TV Permit No.: 147

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(a) The owner or operator of a coal preparation and processing plant that commenced con struction, 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 procedur es 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 s tabilizer 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 contro l 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 o f 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 relativ e 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 o f 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 perfo rmance 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 Administrat or 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.Indiana Gasification LLC Page 15 of 15 Rockport, Indiana PSD and TV Permit No.: 147

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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 perf ormance 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 identic al.

(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 enter ing 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 Roa d, Rockport, IN 47635 County: Spencer SIC Code: 4925, 2819 Operation Permit No.: T 147

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## Subpart Db

**— Standards of Performance for Industrial** 

**- Commercial** 

**** **Institutiona l 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 faci lities 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 (NO X ) standards under this subpart.

(2) Coal

- fired affected facilities having a heat input capacity g reater 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 NO X standards under this subpart and to the sulfur dioxide (SO 2 ) 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 NO X standards under this subpart.

(4) Oil

- fired affected facilities having a heat i nput 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 NO X standards under this subpart and the PM and SO 2 s tandards 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 NO X standards under this subpart and t he SO 2 standards 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 NO X and PM standards under this subpart.

(e) Steam genera ting 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.Indiana Gasification LLC Page 2 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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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 Sta te 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 requir ements 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 recove ry 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 a ffected 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 G enerators, §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 3 2742, 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 t he 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 aff ected 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 (CO 2 ) levels greater than 50 percent or carbon monoxide levels greater than 10 percent are not byproduct/waste for the purpose of this subpart.

Chemical manufacturin g 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. Coal

derived synthetic fuels, including but not limited to solvent refined coal, gasified coal not meeting the definition ofIndiana Gasification LLC Page 3 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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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 s ource.

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 engi ne, 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.

Dist illate 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) o r 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 SO 2 control 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 powd er 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 burne r 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 ga ses enter a steam generating unit.

Emerging technology means any SO 2 control system that is not defined as a conventional technology under this section, and for which the owner or operator of the facility has applied to the Administrator and received approv al 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 Stat e 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 sulf ur 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,Indiana Gasification LLC Page 4 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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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 u sed 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 t he 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

- m 3 (70,000 Btu/hr

- ft 3 ).

ISO Conditions m eans 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 refer ence, see §60.17).

Low heat release rate means a heat release rate of 730,000 J/sec

- m 3 (70,000 Btu/hr

- ft 3 ) 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 direct ly 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 genera ting 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 gl ass 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 b y 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 perc ent 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, t he 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 D epartment of Commerce under Standard Industrial Classification (SIC) Code 29.Indiana Gasification LLC Page 5 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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Potential sulfur dioxide emission rate means the theoretical SO 2 emissions (nanograms per joule (ng/J) or lb/MMBtu heat input) that would result from combusting fuel in an unclean ed 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 SO 2 emissions (ng/J or lb/MMBtu heat input) that would result from combusti ng 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 ca talyst.

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 gen erating 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 co al

- 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 sol id 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 ent ire 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 SO 2 emission control, has a SO 2 emission 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 SO 2 emission control, has a SO 2 emission 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, ve ry low sulfur oil means oil that contains no more than 0.5 weight percent sulfur or that, when combusted without SO 2 emission control, has a SO 2 emission rate equal to or less than 215 ng/J (0.50 lb/MMBtu) heat input.

Wet flue gas desulfurization technology means a SO 2 control 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 mat erial. 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 SO 2

.

Wood means wood, wood residue, bark, or any derivative fuel or residue thereof, in any form, including, but not limited to, sawdust, sanderdust, wood chips, scraps, slabs, millings, shavings, and processed pellets made from wood or other forest residues.

[72 FR 32742, June 13, 2007, as amended at 74 FR 5084, Jan. 28, 2009]Indiana Gasification LLC Page 6 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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## § **60.42b Standard for sulfur dioxide (SO**  **2**



## ).

(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 SO 2 in excess of 87 ng/J (0.20 lb/MMBtu) or 10 percent (0.10) of the potential SO 2 emission rate (90 percent reduction) and the emission limit determined according to the following formula:

Where:

E s = SO 2 emission limit, in ng/J or lb/MMBtu heat input;

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

K b = 340 ng/J (or 0.80 lb/MMBtu);

H a = Heat input from the combustion of coal, in J (MMBtu); and

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

Fo r 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 c ombustion 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 comp leted 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 fluidi zed bed combustion steam generating unit shall cause to be discharged into the atmosphere any gases that contain SO 2 in excess of 87 ng/J (0.20 lb/MMBtu) or 20 percent (0.20) of the potential SO 2 emission rate (80 percent reduction) and 520 ng/J (1.2 lb/MMBt u) 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 fac ility 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 gase s 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 SO 2 emissions, shall cause to be discharged into the atmosphere any gases that contain SO 2 in excess of 50 percen t of the potential SO 2 emission rate (50 percent reduction) and that contain SO 2 in excess of the emission limit determined according to the following formula:

Wher e:

E s = SO2 emission limit, in ng/J or lb/MM Btu heat input;Indiana Gasification LLC Page 7 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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

K d = 170 ng/J (or 0.40 lb/MMBtu);

H c = Heat input from the combustion of coal, in J (MMBtu); and

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

For facilit ies 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 SO 2 in 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 combus ts 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 fede rally 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 paragr aph (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, com pliance 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 SO 2 emission limits and percent reduction requirements under this section apply at all times, including p eriods of startup, shutdown, and malfunction.

(h) Reductions in the potential SO 2 emission 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 SO 2 emissions and

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

- combustion SO 2 control) are equal to or less than the emission limits specified in paragraph (c) of this section.Indiana Gasification LLC Page 8 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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(i) An affec ted facility subject to paragraph (a), (b), or (c) of this section may combust very low sulfur oil or natural gas when the SO 2 control system is not being operated because of malfunction or maintenance of the SO 2 control system.

(j) Percent reduction require ments 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 t he 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 SO 2 emission rate or fuel oil sulfur content; or (2) maintaining fuel records as descri bed 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 b e discharged into the atmosphere any gases that contain SO 2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 8 percent (0.08) of the potential SO 2 emission rate (92 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input. For facilities complying with th e 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 affect ed 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 SO 2 emission rate of 140 ng/J (0.32 lb/MMBtu) heat input or less are exempt from the SO 2 emissions limit in paragraph (k)(1) of this section.

(3) Unit s that are located in a noncontinental area and that combust coal, oil, or natural gas shall not discharge any gases that contain SO 2 in 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 in put 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 SO 2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO 2 emission rate (90 percent reduction) 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 aff ected 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 subj ect 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 c oal and other fuels and

(i) Has an annual capacity factor for coal or coal and other fuels of 30 percent (0.30) or less,Indiana Gasification LLC Page 9 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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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 operatio n 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 facilit y 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 SO 2 emissions 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 Feb ruary 28, 2005, and that combusts oil (or mixtures of oil with other fuels) and uses a conventional or emerging technology to reduce SO 2 emissions shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in exce ss 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 constructi on, 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 faci lity 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 i f 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 capa city 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 othe r fuels; andIndiana Gasification LLC Page 10 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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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 generat ing 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 t he 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, wo od, 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. Own ers 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 enforc eable 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 paragra phs (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 th at 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 aff ected 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 mo dification 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 o f 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 comb usts 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 Fe bruary 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 co ntain 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 fue l (or a mixture of these fuels) in combination with other fuels not subject to a PM standard in §60.43b and not using a post

combustion technology (except a wet scrubber) to reduce SO 2 or PM emissions is not subject to the PM limits in (h)(1) of this sectio n.Indiana Gasification LLC Page 11 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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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 constructio n, 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 fue ls not subject to a PM standard in §60.43b and not using a post

combustion technology (except a wet scrubber) to reduce SO 2 or 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 d ate 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 con tain NO X (expressed as NO 2 ) in excess of the following emission limits:



### Fuel/steam generating unit type Nitrogen oxide emission limits (expressed as NO 2 

### ) heat input
ng/J lb/MMBTu
(1) Natural gas and distillate oil, except (4):
(i) Low heat release rat e 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) Pul verized 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 0.40Indiana Gasification LLC Page 12 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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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 NO X in exce ss of a limit determined by the use of the following formula:

Where:

E n = NO X emission limit (expressed as NO 2 ), ng/J (lb/MMBtu);

EL go = Appropriate emission limit f rom paragraph (a)(1) for combustion of natural gas or distillate oil, ng/J (lb/MMBtu);

H go = Heat input from combustion of natural gas or distillate oil, J (MMBtu);

EL ro = Appropriate emission limit from paragraph (a)(2) for combustion of residual oil, ng/J (lb/MMBtu);

H ro = Heat input from combustion of residual oil, J (MMBtu);

EL c = Appropriate emission limit from paragraph (a)(3) for combustion of coal, ng/J (lb/MMBtu); and

H c = Heat input from combustion of coal, J (MMBtu).

(c) Except as provided under parag raph (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 NO X in excess of the emission limit for the coal or oil, or mixtures of these fue ls 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 dat e 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 oth er solid fuel, except coal, shall cause to be discharged into the atmosphere from that affected facility any gases that contain NO X in excess of 130 ng/J (0.30 lb/MMBtu) heat input unless the affected facility has an annual capacity factor for natural gas o f 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 s ection, 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 wit h byproduct/waste shall cause to be discharged into the atmosphere any gases that contain NO X in 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:Indiana Gasification LLC Page 13 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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Where:

E n = NO X emission limit (expressed as NO 2 ), ng/J (lb/MMBtu);

EL go = Appropriate emission limit from paragraph (a)(1) for combustion of natural gas or distillate oil, ng/J (lb/MMBtu);

H go = Heat input from combustion of natural gas, distillate oil and gaseous byproduct/waste, J (MMBtu);

EL ro = Appropriate emission limit from paragraph (a)(2) for combustion of residual oil and/or byproduct/waste, ng/J (lb/MMBtu);

H ro = Heat input from combustion of residual oil, J (MMBtu);

EL c = Appropri ate emission limit from paragraph (a)(3) for combustion of coal, ng/J (lb/MMBtu); and

H c = 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 peti tion the Administrator within 180 days of the initial startup of the affected facility to establish a NO X emission 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 NO X emissions 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 NO X emission limit under this s ection 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 t est 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 natur al 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 usin g the same technological system of emission reduction applied when demonstrating compliance under paragraph (f)(1)(i) of this section.

(2) The NO X emission limits for natural gas or distillate oil in paragraph (a)(1) of this section or for residual oil in p aragraph (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 NO X emission limit will be established at the NO X emission 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 NO X emissions. In lieu of amending this su bpart, a letter will be sent to the facility describing the facility

- specific NO X limit. 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 theIndiana Gasification LLC Page 14 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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affected facility for a waiver from compliance with the NO X emission limit that applies specifically to that affected facility. The petition must include sufficient and appropriate data, as det ermined by the Administrator, on NO X emissions 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 t o determine if the affected facility is able to comply with the NO X emission 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 destructi on efficiency requirements for hazardous waste specified in an applicable federally enforceable requirement preclude compliance with the NO X emission limits of this section. The NO X emission limits for natural gas or distillate oil in paragraph (a)(1) of thi s 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 incine ration 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 NO X limit. The facility shall use the compliance procedures detailed in the letter an d 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 NO X standards 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 combi nation, 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 oi l 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 NO X emission limits under this section.

(l) On and after the date on which the initial performance tes t 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 NO X (expressed as NO 2 ) 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 capaci ty 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 com bustion of all fuels, a limit determined by use of the following formula:Indiana Gasification LLC Page 15 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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Where:

E n = NO X emission limit, (lb/MMBtu);

H go = 30

- day heat input from combustion of natu ral gas or distillate oil; and

H r = 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/M Wh) 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 SO 2 emission 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 SO 2 control system maintenance.

(b) In conducting the performance tests re quired 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 dete rmine compliance with the percent of potential SO 2 emission rate (% P s ) and the SO 2 emission rate (E s ) 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 SO 2 standards 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 proced ures are used:

(i) The procedures in Method 19 of appendix A

– 7 of this part are used to determine the hourly SO 2 emission rate (E ho ) and the 30

- day average emission rate (E ao ). The hourly averages used to compute the 30

- day averages are obtained from the CE MS of §60.47b(a) or (b).

(ii) The percent of potential SO 2 emission rate (%P s ) emitted to the atmosphere is computed using the following formula:

Where:

%P s = Poten tial SO 2 emission rate, percent;Indiana Gasification LLC Page 16 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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%R g = SO 2 removal efficiency of the control device as determined by Method 19 of appendix A of this part, in percent; and

%R f = SO 2 removal efficiency of fuel pretreatment as determined by Method 19 of appendix A of this part, i n 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 SO 2 emission rate (E ho o ) is used in Equation 19

– 19 of Method 19 of appendix A of this part to compute an adjusted 30

- day average emission rate (E ao o ). The Eho° is computed using the following formula:

Where:

E ho o = Adjust ed hourly SO 2 emission rate, ng/J (lb/MMBtu);

E ho = Hourly SO 2 emission rate, ng/J (lb/MMBtu);

E w = SO 2 concentration in fuels other than coal and oil combusted in the affected facility, as determined by the fuel sampling and analysis procedures in Method 19 of appendix A of this part, ng/J (lb/MMBtu). The value E w for each fuel lot is used for each hourly average during the time that the lot is being combusted; and

X k = 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 SO 2 emission rate (%P s ), an adjusted %R g (%R g o ) is computed from the adjusted E ao o from paragraph (b)(3)(i) of this section and an adjusted average SO 2 inlet rate (E ai o ) using the following formula:

To compute E ai o , an adjusted hourly SO 2 inlet rate (E hi o ) is used. The E hi o is computed using the fol lowing formula:

Where:

E hi o = Adjusted hourly SO 2 inlet rate, ng/J (lb/MMBtu); and

E hi = Hourly SO 2 inlet rate, ng/J (lb/MMBtu).

(4) The owner or operator of an affe cted facility subject to paragraph (c)(3) of this section does not have to measure parameters E w or X k if the owner or operator elects to assume that X k = 1.0. Owners or operators of affected facilities who assume X k = 1.0 shall:Indiana Gasification LLC Page 17 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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(i) Determine %P s following the procedures in paragraph (c)(2) of this section; and

(ii) Sulfur dioxide emissions (E s ) are considered to be in compliance with SO 2 emission limits under §60.42b.

(5) The owner or operator of an affected facility that qualifies under the provisions of §60.4 2b(d) does not have to measure parameters E w or X k in paragraph (c)(3) of this section if the owner or operator of the affected facility elects to measure SO 2 emission rates of the coal or oil following the fuel sampling and analysis procedures in Method 19 o f 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 1 0 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 consecutiv e 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 u sed, 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 demonstr ate 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 af fected 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 SO 2 emission limits and percent reduction requirements under §60.42b is based on the average emission rates and the average percent reduction for SO 2 for 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 d ays 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 withi n 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 SO 2 emission limits and percent reduction requirements under §60 .42b is based on the average emission rates and the average percent reduction for SO 2 for 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 generatin g unit operating day after the initial performance test, and a new 30

- day average emission rate and percent reduction for SO 2 are calculated to show compliance with the standard.

(h) Except as provided under paragraph (i) of this section, the owner or opera tor of an affected facility shall use all valid SO 2 emissions data in calculating %P s and E ho under paragraph (c), of this section whether or not the minimum emissions data requirements under §60.46b are achieved. All valid emissions data, including valid SO 2 emission data collected during periods of startup, shutdown and malfunction, shall be used in calculating %P s and E ho pursuant to paragraph (c) of this section.

(i) During periods of malfunction or maintenance of the SO 2 control systems when oil is combusted as provided under §60.42b(i), emission data are not used to calculate %P s or E s under §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 faci lity that only combusts very low sulfur oil, natural gas, or a mixture of these fuels with any other fuels not subject to an SO 2 standard 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).Indiana Gasification LLC Page 18 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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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 appl y at all times except during periods of startup, shutdown, or malfunction. The NO X emission 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 NO X emission standards under §60.44b shall be determined through performance testing under paragraph (e) or (f), or under paragraphs (g) and (h) o f 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 subs equent 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 (FG D) 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 Metho d 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 drop lets.

(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 12 0 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 tem perature 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 (O 2 ) or CO 2 sample is obtained simultaneously with each run of Method 5, 5B, or 17 of append ix 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 O 2 or CO 2 measurements and PM measureme nts obtained under this section;

(ii) The dry basis F factor; andIndiana Gasification LLC Page 19 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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(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 stac k emissions.

(e) To determine compliance with the emission limits for NO X required 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 NO X under §6 0.48(b).

(1) For the initial compliance test, NO X from 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 NO X emission 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 d etermine compliance with the NO X emission 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 aver age of all of the hourly NO X emission 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 th e NO X standards 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 NO X emission 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 tha t 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 NO X standards in §60.44b through the use of a 30

- day performance test. During periods when performance tests are not requested, NO X emissions 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 dail y basis and used to prepare excess emission reports, but will not be used to determine compliance with the NO X emission 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 NO X emission 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 NO X required 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 NO X shall be computed using Equation 1 in this section:

Where:Indiana Gasification LLC Page 20 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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E = Emissions rate of NO X from the duct burner, ng/J (lb/MMBtu) heat input;

E sg = 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;

H g = Heat input rate to the combustion turbine, in J/hr (MMBtu/hr);

H b = Heat input rate to the duct burner, in J/hr (MMBtu/hr); and

E g = Emissions rate from th e 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 NO X concentrations. Method 3A or 3B of

a ppendix A of this part shall be used to determine O 2 concentration.

(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 NO X and O 2 and meet the requirements of §60.48b. The sampling site shall be located a t the outlet from the steam generating unit. The NO X emissions rate at the outlet from the steam generating unit shall constitute the NO X emissions rate from the duct burner of the combined cycle system.

(g) The owner or operator of an affected facility desc ribed 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 inpu t 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 perf ormance 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 ea ch 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 capac ity 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 NO X emission 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 NO X emission standards under §60.44b over a minimum of 3 consecutive steam generating unit operat ing 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).Indiana Gasification LLC Page 21 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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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 syst em.

(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 late r 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 co mpliance 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 s hall 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 arithme tic 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, P M and O 2 (or CO 2 ) data shall be collected concurrently (or within a 30

- to 60

- minute period) by both the continuous emission monitors and performance tests conducted using the following test methods.

(i) For PM, Method 5 or 5B of appendix A

– 3 of this part or Method 17 of appendix A

– 6 of this part shall be used; and

(ii) For O 2 (or CO 2 ), Method 3A or 3B of appendix A

– 2 of this part, as applicable shall be used.

(12) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accord ance 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.Indiana Gasification LLC Page 22 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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(13) When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibr ation 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 mini mum 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 SO 2 s tandards in §60.42b shall install, calibrate, maintain, and operate CEMS for measuring SO 2 concentrations and either O 2 or CO 2 concentrations and shall record the output of the systems. For units complying with the percent reduction standard, the SO 2 and eithe r O 2 or CO 2 concentrations shall both be monitored at the inlet and outlet of the SO 2 control device. If the owner or operator has installed and certified SO 2 and O 2 or CO 2 CEMS 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, SO 2 concentration data and CO 2 (or O 2 ) data are collected simultaneously; and

(2) In addition to meeting the applicable SO 2 and CO 2 (or O 2 ) relative accuracy specifications in Figure 2 of appendix B to part 75 of this chapter, t he 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. SO 2 and CO 2 (or O 2 ) data used to meet th e 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 SO 2 data have been bias adjusted according to the procedures of part 75 of this chapter.

(b) A s an alternative to operating CEMS as required under paragraph (a) of this section, an owner or operator may elect to determine the average SO 2 emissions and percent reduction by:

(1) Collecting coal or oil samples in an as

- fired condition at the inlet to t he 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 SO 2 input rate, or

(2) Measuring SO 2 according to Method 6B of appendix A of this part at the inlet or outlet to the SO 2 control system. An initial stratification test is required to verify the adequacy of the Method 6B of appendix A of this part sampling location. The stratification test shall consist of three paired runs of a suitable SO 2 and CO 2 measurement train operated at the candidate location and a second similar train operated according to the procedures in section 3.2 and the applicable pro cedures 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 suitab le 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 SO 2 emission rate, E D , 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.Indiana Gasification LLC Page 23 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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(4) The mean 30

- day emission rate is calculated using the daily measured values in ng/J (lb/MMBtu) fo r 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 ou t 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 ap proved by the Administrator or the reference methods and procedures as described in paragraph (b) of this section.

(d) The 1

- hour average SO 2 emission rates measured by the CEMS required by paragraph (a) of this section and required under §60.13(h) is expre ssed 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 SO 2 emission rate must be based on 30 or more minutes of steam generating unit operation. The hourly averages shall be calculated ac cording to §60.13(h)(2). Hourly SO 2 emission 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 af fected facilities combusting coal or oil, alone or in combination with other fuels, the span value of the SO 2 CEMS at the inlet to the SO 2 control device is 125 percent of the maximum estimated hourly potential SO 2 emissions of the fuel combusted, and the spa n value of the CEMS at the outlet to the SO 2 control device is 50 percent of the maximum estimated hourly potential SO 2 emissions of the fuel combusted. Alternatively, SO 2 span values determined according to section 2.1.1 in appendix A to part 75 of this chap ter 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 requ ired CO 2 and O 2 monitors and for SO 2 and NO X monitors 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 b e followed instead of the CD assessment procedures in Procedure 1, section 4.1 of appendix F to this part.

(ii) For all required CO 2 and O 2 monitors and for SO 2 and NO X monitors 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 c hecks 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 SO 2 and NO X span values less than or equal to 30 p pm; and

(iii) For SO 2 , CO 2 , and O 2 monitoring systems and for NO X emission 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, s ection 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

- of

control 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, sect ion 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 Perfor mance Specification 2 in appendix B toIndiana Gasification LLC Page 24 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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this part shall be met on a lb/MMBtu basis for SO 2 (regardless of the SO 2 emission level during the RATA), and for NO X when the average NO X emission 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 operat or 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 an d 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 condu ct 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 s tartup 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 a ll 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 o perator 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 th e 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 t est 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 paragrap hs (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 3 0 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 op erator 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 minuteIndiana Gasification LLC Page 25 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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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 whi ch 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 NO X standard under §60.44b shall comply with either paragraphs (b)(1) or (b)(2) of this sectio n.

(1) Install, calibrate, maintain, and operate CEMS for measuring NO X and O 2 (or CO 2 ) emissions discharged to the atmosphere, and shall record the output of the system; or

(2) If the owner or operator has installed a NO X emission rate CEMS to meet the requi rements 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 chapt er.

(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 NO X emission rates measured by the continuous NO X monitor 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 NO X is determined using one of the following procedures:

(i) Except as provided under paragraph (e)(2)(ii) of this section, NO X span values shall be determined as follows:



### Fuel Span values for NO X 

### (ppm)
Natural gas 500.Indiana Gasification LLC Page 26 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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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 NO X span 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 NO X emission data are not obtained becaus e 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 meth ods 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 ha s 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 th an 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 NO X emission rates as specified in a plan submitted pursua nt to §60.49b(c).

(h) The owner or operator of a duct burner, as described in §60.41b, that is subject to the NO X standards 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 NO X emissions.

(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 NO X emissions.

(j) The owner or operator of an affected facility that meets the conditions in e ither 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 SO 2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and does not use a post

- combustion technology to reduce SO 2 or PM emissions. The owner or operator must maintain fuel records of the sulfur content of the fuels burned, as described under §60.49b(r); orIndiana Gasification LLC Page 27 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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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 SO 2 or PM emissions; or

(4) The affected facility does not use post

- combustion technology (except a wet scrubber) for reducing PM, SO 2 , or carbon monoxide (CO) emissions, burns only gaseous fuels or fuel oils that contain less than or equal to 0.30 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) throug h (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 calcu late 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 correspo nding 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 evaluat e 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 inv estigation 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 f abric 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 s tandard.

(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.Indiana Gasification LLC Page 28 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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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. T his 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 ope rator 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 SO 2 . 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 c ontrol 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 SO 2 , PM, and/or NO X emission 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 ope rator 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 ea ch affected facility subject to the NO X standard 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 fo r 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 affecte d 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 Novembe r 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. T he plan shall:

(1) Identify the specific operating conditions to be monitored and the relationship between these operating conditions and NO X emission 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 O 2 level);

(2) Include the data and information that the owner or operator used to identify the relationship between NO X emission 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 record s 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.Indiana Gasification LLC Page 29 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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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 indiv idually 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 facil ity 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 nitrog en 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 pe rformance 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 observ ation 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 visibl e 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 NO X standards under §60.44b shall maintain records of the following information for each steam generating unit operating day:

(1) Calendar date;

(2) The average hourly NO X emission rates (expressed as NO 2 ) (ng/J or lb/MMBtu heat input) measured or predicted ;Indiana Gasification LLC Page 30 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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(3) The 30

- day average NO X emission 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 operat ing days;

(4) Identification of the steam generating unit operating days when the calculated 30

- day average NO X emission rates are in excess of the NO X emissions 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) Identific ation 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 d rift 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 emissio n 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 NO X standard 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 requir ed to monitor NO X emissions 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 ex ceeds 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 NO X emission 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 NO X under §60.48(b) shall submit reports containing the information recorded under paragraph (g) of this section.

(j) The owner or operator of any affe cted facility subject to the SO 2 standards 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 follo wing information shall be reported to the Administrator:

(1) Calendar dates covered in the reporting period;Indiana Gasification LLC Page 31 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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(2) Each 30

- day average SO 2 emission rate (ng/J or lb/MMBtu heat input) measured during the reporting period, ending with the last 30

- day period; re asons for noncompliance with the emission standards; and a description of corrective actions taken; For an exceedance due to maintenance of the SO 2 control system covered in paragraph 60.45b(a), the report shall identify the days on which the maintenance wa s performed and a description of the maintenance;

(3) Each 30

- day average percent reduction in SO 2 emissions 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 SO 2 or diluent (O 2 or CO 2 ) data have not been obtained by an approved method for at least 75 percent of the operating ho urs 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 rat es; 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 cal culations, 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, Proce dure 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 requiremen ts 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 SO 2 emission rate measured for each steam gener ating 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 S0 2 or diluent (O 2 or CO 2 ) 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 be en 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;Indiana Gasification LLC Page 32 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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(8) Description of any modifications to the CEMS that could affect the ability of the CEM S 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 as sessment 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 SO 2 standards 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 Administra tor 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 par t, 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. , %R f ) is used to determine the overall percent reduction ( i.e. , %R o ) 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. , % R f ) 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 tota l 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 op erator 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 o f 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 aff ected 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 owne r 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;Indiana Gasification LLC Page 33 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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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 NO X emission tests required during the reporting period, the hours of operation during the reporting period, and the hours of operat ion since the last NO X emission 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 §6 0.42b(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 t he 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 elec ts 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. E ach 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 in put;

(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 NO X standard 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 sect ion 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 NO X emission limit for fossil fuel in §60.44b(a) applies.

(ii) When natural gas and chemical by

- product waste are simulta neously combusted, the NO X emission 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.Indiana Gasification LLC Page 34 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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(3) Emission monitoring . (i) The percent of to tal 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 NO X emission limit shall be determined by the compliance and performance test methods and procedures for NO X in §60.46b(i).

(iii) The monitoring of the NO X emission 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 y ears 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 NO X standard for Rohm and Haas Kentucky Incorporate d's Boiler No. 100 located in Louisville, Kentucky:

(1) Definitions

.
Air ratio control damper is defined as the part of the low NO X burner 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 NO X emis sion limit for fossil fuel in §60.44b(a) applies.

(ii) When fossil fuel and chemical by

- product waste are simultaneously combusted, the NO X emission limit is 473 ng/J (1.1 lb/MMBtu), and the air ratio control damper tee handle shall be at a minimum of 5 inc hes (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 da mper 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 NO X emission limit shall be determined by the compliance and performance test methods and pro cedures for NO X in §60.46b.

(iii) The monitoring of the NO X emission 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 fo r 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.Indiana Gasification LLC Page 35 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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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 installe d 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 NO X technology.

(ii) The site shall install, calibrate, maintain, and operate a continuous monitoring and recording system for measuring NO X emissions discharged to the atmosphere a nd 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 quantif y criteria pollutant emissions.

(2) [Reserved]

(v) The owner or operator of an affected facility may submit electronic quarterly reports for SO 2 and/or NO X and/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 fo rmat, 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 shal l be submitted to the Administrator and shall be postmarked by the 30th day following the end of the reporting period.

(x) Facility

- specific NO X standard for Weyerhaeuser Company's No. 2 Power Boiler located in New Bern, North Carolina:

(1) Standard for nit rogen oxides . (i) When fossil fuel alone is combusted, the NO X emission limit for fossil fuel in §60.44b(a) applies.

(ii) When fossil fuel and chemical by

- product waste are simultaneously combusted, the NO X emission limit is 215 ng/J (0.5 lb/MMBtu).

(2) Emi ssion monitoring for nitrogen oxides . (i) The NO X emissions shall be determined by the compliance and performance test methods and procedures for NO X in §60.46b.

(ii) The monitoring of the NO X emissions shall be performed in accordance with §60.48b.

(3) Repo rting 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 §60.4 9b(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 s hall perform all the applicable reporting and recordkeeping requirements of §60.49b.

(y) Facility

- specific NO X standard for INEOS USA's AOGI located in Lima, Ohio:Indiana Gasification LLC Page 36 of 36 Rockport, Indiana PSD and TV Permit No.: 147

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(1) Standard for NO X . (i) When fossil fuel alone is combusted, the NO X emission limit for fos sil fuel in §60.44b(a) applies.

(ii) When fossil fuel and chemical byproduct/waste are simultaneously combusted, the NO X emission limit is 645 ng/J (1.5 lb/MMBtu).

(2) Emission monitoring for NO X . (i) The NO X emissions shall be determined by the compliance and performance test methods and procedures for NO X in §60.46b.

(ii) The monitoring of the NO X emissions 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 b y 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, 19 84 [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

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## 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,**  **198 4** 

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 ves sel with a capacity greater than or equal to 75 cubic meters (m 3 ) 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 ves sels with a capacity greater than or equal to 151 m 3 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 m 3 but less than 151 m 3 storing a liquid with a maximum true vapor press ure 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 perman ently 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 m 3 used for petroleum or condensate stored, processed, or treated prior to custody transfer.

(5) Vessels locate d at bulk gasoline plants.

(6) Storage vessels located at gasoline service stations.

(7) Vessels used to store beverage alcohol.Indiana Gasification LLC Page 2 of 12 Rockport, Indiana PSD and TV Permit No.: 147

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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 sec tion. 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 m 3 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 m 3 but less than 151 m 3 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, 6 0.6, 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 p art 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, sub part 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 gasol ine 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 requirem ent 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 stan dard 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 transporta tion.

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.Indiana Gasification LLC Page 3 of 12 Rockport, Indiana PSD and TV Permit No.: 147

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Maximum true vapor press ure 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 bel ow 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 ot her 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 transfe rred 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 deter mined 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 m 3 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 equa l to 75 m 3 but less than 151 m 3 containing a VOL that, asIndiana Gasification LLC Page 4 of 12 Rockport, Indiana PSD and TV Permit No.: 147

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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 ro of 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 in ternal 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 fl oating 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 r oof. The lower seal may be vapor

mounted, 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 th e 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 spac e 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 spa ce 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 s leeve 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

- dec k 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.Indiana Gasification LLC Page 5 of 12 Rockport, Indiana PSD and TV Permit No.: 147

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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 floa ting 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 g ap) 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 roo f 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 leas t 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 unti l the roof is lifted off leg supports and when the tank is completely emptied and subseque ntly 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 specification s:

(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 inspecti ons, 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 th e 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 m 3 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 c ontrol 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 appl ies 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 proce dures 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 otherwi se 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]Indiana Gasification LLC Page 6 of 12 Rockport, Indiana PSD and TV Permit No.: 147

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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 affi xed 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, o r 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 o r 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 inter nal 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 requeste d 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 con trol 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 i n 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 inspectio n 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 filli ng 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 secti on 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 rece ived 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.Indiana Gasification LLC Page 7 of 12 Rockport, Indiana PSD and TV Permit No.: 147

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(i) Measurements of gaps between the tank wall and the primary seal (seal gaps) shall be performed d uring 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 f ill 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 circumferent ial 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 an d 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 co mpare 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 Cm 2 per meter of tank diameter, and the width of any portion of any gap shall not exceed 3.81

cm.

(A) One e nd 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 env elope.

(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 cm 2 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 r equested 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 equ ipment 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.Indiana Gasification LLC Page 8 of 12 Rockport, Indiana PSD and TV Permit No.: 147

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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 th e 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 o r 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 storag e vessel. Notification shall be made by telephone immediately followed by written documentation demonstrating why the inspectio n 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 sour ce 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 Administ rator 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 de monstrating 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 varyi ng 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 designate d 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 s econds 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 monitore d 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 requirem ents, §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 reduct ion 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 r equirement.

(b) Any notice under paragraph (a) of this section will be published only after notice and an opportunity for a hearing.Indiana Gasification LLC Page 9 of 12 Rockport, Indiana PSD and TV Permit No.: 147

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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 temperat ure 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 req uired 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 furnish ed 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 i n 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 spec ifications 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 Administ rator 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).Indiana Gasification LLC Page 10 of 12 Rockport, Indiana PSD and TV Permit No.: 147

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(3) Keep a record of each gap measurement performed as required by §60.113b(b). E ach 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 eac h 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 op erator 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 o wner 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 shal l 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 wa s 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 yea rs. 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 m 3 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 m 3 but less than 151 m 3 storing a liquid with a maximum true vapor pressure greater than or equal to 15.0 kPa shall maintain a record of th e 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 g reater than or equal to 151 m 3 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 m 3 but less than 151 m 3 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.Indiana Gasification LLC Page 11 of 12 Rockport, Indiana PSD and TV Permit No.: 147

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(e) Available data on the storage temperatur e 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 storag e 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 d etermine 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 Re id 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 o r 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 method s 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 ref erence

— 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 reduc tions 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 59 333, Oct. 15, 2003]


## § **60.117b Delegation of authority.** Indiana Gasification LLC Page 12 of 12 Rockport, Indiana PSD and TV Permit No.: 147

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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 Administrato r 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 2 00 N and Base Road, Rockport, IN 47635 County: Spencer SIC Code: 4925, 2819 Operation Permit No.: T 147

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## Subpart IIII

**— Standards of Performance for Stationary Comp**  **ression 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 o perators 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 engin e 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 Tabl e 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 engin es, 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 o r 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.Indiana Gasification LLC Page 2 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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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 par t 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 o f 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, s ubpart 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 IC E 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 pr ovisions, 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 m eet for non** 

**- emergency**  **engines if I am a stationary CI internal combustion engine manufacturer?**

(a) Stationary CI internal combustion engine manufacturers must certify their 2007 model year and later non

emergency stationary CI ICE with a maximum engine pow er 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 m odel year non

emergency stationary CI ICE with a maximum engine power greater than 2,237 KW (3,000 HP) and a displacement of less than 10 liters per cylinder to the emission standards in table 1 to this subpart, for all pollutants, for the same maximum eng ine power.

(c) Stationary CI internal combustion engine manufacturers must certify their 2011 model year and later non

emergency stationary CI ICE with a maximum engine power greater than 2,237 KW (3,000 HP) and a displacement of less than 10 liters per cy linder 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 displacemen t 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 stationa ry 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 wit h a displacement of greater than or equal to 15 liters per cylinder and less than 30 liters per cylinder.Indiana Gasification LLC Page 3 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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(e) Stationary CI internal combustion engine manufacturers must certify the following non

- emergency stationary CI ICE to the certification emission st andards 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 l ater 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 C I 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 f ollowing 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

en gine 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 statio nary 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 certificatio n 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 a nd 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.Indiana Gasification LLC Page 4 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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(2) For 2011 model year and later, the certification emission standards for new nonroad CI engine s 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 c ertify 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 emerg ency 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 le ss 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 4 0 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 identifi ed 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 u sed 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 combu stion 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 ap plicable 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]Indiana Gasification LLC Page 5 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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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 operator s 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 pre

2007 model year non

- emergency stationary CI ICE with a displacement of greater than or equal to 10 liters per cylinder and less than 30 liters per cylinder 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 en gines 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 NO X in 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 −0.2 g/KW

- hr (34 · n −0.2 g/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 NO X in the sta tionary 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 −0.23 g/KW

- hr (33 · n −0.23 g/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 NO X in 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;Indiana Gasification LLC Page 6 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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(ii) 9.0 · n −0.20 g/KW

- hr (6.7 · n −0.20 g/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 perf ormance 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]


## § **6 0.4205**  **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 l iters 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 cyli nder 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 lit ers 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 NO X in 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 −0.2 g/KW

- hr (34 · n −0.2 g/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 Jan uary 1, 2012, limit the emissions of NO X in 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 −0.23 g/KW

- hr (33 · n −0.23 g/HP

- hr) when maximum engi ne speed is greater than or equal to 130 but less than 2,000 rpm and where n is maximum engine speed; andIndiana Gasification LLC Page 7 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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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 in ternal 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 i n §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 interna l 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 Requir **ements 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 subj ect 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 c ylinder 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 ha ve 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 deadli ne 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.Indiana Gasification LLC Page 8 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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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 mode l 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 applica ble 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 6 00 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 addit ion 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) thr ough (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 engi nes 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 inte rnal 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 stati onary 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 combustio n 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 en gine is approached.

[71 FR 39172, July 11, 2006, as amended at 76 FR 37969, June 28, 2011]


## Compliance RequirementsIndiana Gasification LLC Page 9 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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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 c ombustion 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 requi red 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 th e 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 §60.420 2(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 e ngine 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 m ust 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 manufact ured 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) Stat ionary 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 re quirements 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 4 0 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 tha t 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 manu facturers 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 l abeled 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 yea r and HP must be labeled according to the provisions in 40 CFR parts 89, 94, 1039 or 1042, as appropriate.Indiana Gasification LLC Page 10 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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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 nonro ad (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 addi tion, 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 C FR 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) Manufactu rers of engine families discussed in paragraph (d) of this section may meet the labeling requirements referred to in paragraph (c) of this section for stationary CI ICE by either adding a separate label containing the information required in paragraph (c) of this section or by adding the words “and stationary” after the word “nonroad” or “marine,” as appropriate, to the label.

(f) Starting with the model years shown in table 5 to this subpart, stationary CI internal combustion engine manufacturers must add a permanent label stating that the engine is for stationary emergency use only to each new emergency stationary CI internal combustion engine greater than or equal to 19 KW (25 HP) that meets all the emission standards for emergency engines in §60.4202 but does not meet all the emission standards for non

emergency engines in §60.4201. The label must be added according to the labeling requirements specified in 40 CFR 1039.135(b). Engine manufacturers must specify in the owner's manual that operation of emerg ency 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, pr ovided 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 st andards 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 no t 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 pr ovisions 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, Ju ne 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 t hose emission

- related settings that are permitted by the manufacturer; andIndiana Gasification LLC Page 11 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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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 en gine 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 de vice 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 opera tor 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 afte r 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 p ermitted 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 int ernal combustion engine continues to meet the emission standards. The owner or operator must petition the Administrator for approval of operating parameters to be monitored continuously. The petition must include the information described in paragraphs (d) (2)(i) through (v) of this section.

(i) Identification of the specific parameters you propose to monitor continuously;

(ii) A discussion of the relationship between these parameters and NO X and PM emissions, identifying how the emissions of these pollutants change with changes in these parameters, and how limitations on these parameters will serve to limit NO X and PM emissions;

(iii) A discussion of how you will establish the upper and/or lower values for these parameters which will establish the limits on th ese 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; andIndiana Gasification LLC Page 12 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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(v) A discussion ident ifying 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 de monstrate 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 §60.4 204(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, t he 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 lo cal 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 m aintenance 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 w ith 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 y ou 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 d emonstrate 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 m anufacturer'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 standar ds 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 m ust, 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 applicabl e 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 af ter 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 ma intenance 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 wit h 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 w ithin 1 year after youIndiana Gasification LLC Page 1 3 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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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 c ompliance 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 operato**  **r 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 subpar t 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 103 9.104(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 n ew 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 engin es 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.Indiana Gasification LLC Page 14 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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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 stat ionary 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 acc ording 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:

C i = concentration of NO X or PM at the control device inl et,

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

R = percent reduction of NO X or PM emissions.

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

Where:

C adj = Ca lculated NO X or PM concentration adjusted to 15 percent O 2 .

C d = Measured concentration of NO X or PM, uncorrected.Indiana Gasification LLC Page 15 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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- 00060 Permit Reviewer: Josiah Balogun 5.9 = 20.9 percent O 2 −15 percent O 2 , the defined O 2 correction value, percent.

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

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

(i) Calculate the fuel

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

Where:

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

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

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

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

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

Where:

X CO2 = CO 2 correction factor, percent.

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

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

Where:

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

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

%CO 2 = Measured CO 2 concentration, dry basis, percent.Indiana Gasification LLC Page 16 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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(e) To determine compliance with the NO X mass per unit output emission limitation, convert the concentration of NO X in the engine exhaust using Equation 7 of this section:

Where:

ER = Emission rate in grams per KW

- hour.

C d = Measured NO X concentration in ppm.

1.912x10 −3 = Conversion constant for ppm NO X to grams per standard cubic meter at 25 degrees Celsius.

Q = Stack gas volumetric flow rate, in standard cubic meter per hour.

T = Time of test run, in hours.

KW

- hour = Brake work of the engine, in KW

- hour.

(f) To determine compliance with the PM mass per unit output emission limitation, convert the concentration of PM in the engine exhaust using Equation 8 of this section:

Where:

ER = Emission rate in grams per KW

- hour.

C adj = Calculated PM concen tration 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

- em ergency 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 requir ements of paragraphs (a)(1) and (2) of this section.Indiana Gasification LLC Page 17 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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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 oper ator;

(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 intern al 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 t he 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

- r esettable 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 oper ator 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) S tationary 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 instal led prior to January 1, 2012, limit the emissions of NO X in the stationary CI internal combustion engine exhaust to the following:Indiana Gasification LLC Page 18 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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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 −0.2 g/KW

- hr (34 · n −0.2 g/HP

- hr) whe n 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 o f NO X in 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 −0.23 g/KW

- hr (33 · n −0.23 g/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 ma y 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 §§6 0.4201(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 non

emergency CI ICE, the owner or operator of any such engine that was not certified as meeting Tier 4 PM standards, must meet the appli cable 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 eng ine

- 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 m ust 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]Indiana Gasification LLC Page 19 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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## § **60.4217 What emission standards must I meet if I am an owner or**  **operator o f 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 t his 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

ca lendar 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 sub

components comprising any simple cycle combustion turbine, any regenerative/recuperative cycle combustion turbine, the combustion turbine portion of any cog eneration 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 wa s 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 excep t for the engine block. In these cases, the date of manufacture is the date of reconstruction or the date the new engine is produced.Indiana Gasification LLC Page 20 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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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 particl es 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 an d 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 anot her 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 NF PA 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.

Instal led 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 manufac ture”), 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 non

stationary engine, model year means the calendar year or new model production period in which the engine wa s 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 inter nal 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 i nto 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 andIndiana Gasification LLC Page 21 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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gaseous fuel (typica lly 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 e ngine, 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 parag raph (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 Pre** 

**** **2007 Model Year Engines With a Displacement of <10 Liters per Cylinder and 2007** 

**–**

**2010 Model Year En gines >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 + NO X 

### HC NO X 

### CO PM
KW<8 (HP<11) 10.5 (7.8) 8. 0 (6.0) 1.0 (0.75)

8≤KW<19 (11≤HP<25) 9.5 (7.1) 6.6 (4.9) 0.80 (0.60)

19≤KW<37 (25≤HP<50) 9.5 (7.1) 5.5 (4.1) 0.80 (0.60)

37≤KW<56 (50≤HP<75) 9.2 (6.9)

56≤KW<75 (75≤HP<100) 9.2 (6.9)

75≤KW<130 (100≤HP<175) 9.2 (6.9)

130≤KW<225 (175≤HP<300) 1.3 (1.0) 9.2 (6.9) 11.4 (8.5) 0.54 (0.40)

225≤KW<450 (300≤HP<600) 1.3 (1.0) 9.2 (6.9) 11.4 (8.5) 0.54 (0.40)

450≤KW≤560 (600≤HP≤750) 1.3 (1.0) 9.2 (6.9) 11.4 (8.5) 0.54 (0.40)Indiana Gasification LLC Page 22 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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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 s tandards 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) NO X 

### + NMHC CO PM
KW<8 (HP<11) 2008+ 7.5 (5.6) 8.0 (6.0) 0.40 (0.30)

8≤KW<19 (11≤HP<25) 2008+ 7.5 (5.6) 6.6 (4.9) 0.40 (0.30)

19≤KW<37 (25≤HP<50) 2008+ 7.5 (5.6) 5.5 (4.1) 0.30 (0.22)



## Table 3 to Subpart IIII of Part 60

**— Certification Requirements for Stationary**  **Fire Pump Engines**

Table 3 to Subpart IIII of Part 60

— Certifica tion 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) 2008Indiana Gasification LLC Page 23 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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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 tha n 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 3 7972, 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 po wer Model year(s) NMHC + NO X 

### CO PM
KW<8 (HP<11) 2010 and earlier 10.5 (7.8) 8.0 (6.0) 1.0 (0.75)

2011+ 7.5 (5.6) 0.40 (0.30) 8≤KW<19 (11≤HP<25) 2010 and earlier 9.5 (7.1) 6.6 (4.9) 0.80 (0.60)

2011+ 7.5 (5.6) 0.40 (0.30) 19≤KW<37 (25≤HP<50) 20 10 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)Indiana Gasification LLC Page 24 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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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 ye ar 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 s tationary 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 E ngines** 

[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 speed 1 

### Torque (percent) 2 

### Weighting factors

1 Rated 100 0.30

2 Rated 75 0.50

3 Rated 50 0.20

1 Engine sp eed: ±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 Displacem ent 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:]Indiana Gasification LLC Page 25 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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### For each Complying with the requirement to You must Using Ac cording to the following requirements
1. Stationary CI internal combustion engine with a displacement of ≥30 liters per cylinder a. Reduce NO X 

### emissions by 90 percent or

more i. Select the sampling port location and the number of traverse points; (1) Metho d 1 or 1A of 40 CFR part 60, appendix A (a) Sampling sites must be located at the inlet and outlet of the control device.

ii. Measure O 2 

### at the inlet and outlet of the control device; (2) Method 3, 3A, or 3B of 40 CFR part 60, appendix A (b) Measuremen ts to determine O 2 

### concentration must be made at the same time as the measurements for NO X 

### concentration.
iii. If necessary, measure moisture content at the inlet and outlet of the control device; and, (3) Method 4 of 40 CFR 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 NO X 

### concentr ation.

iv. Measure NO X 

### at the inlet and outlet of the control device (4) Method 7E of 40 CFR part 60, appendix A, Method 320 of 40 CFR part 63, appendix A, or ASTM D 6348

– 03 (incorporated by reference, see §60.17) (d) NO X 

### concentration must be at 15 per cent O 2 

### , dry basis. Results of this test consist of the average of the three 1

- hour or longer runs.

b. Limit the concentration of NO X 

### in the stationary CI internal combustion i. Select the sampling port location and the number of travers e 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.Indiana Gasification LLC Page 26 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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### engine exhaust.

ii. Determine the O 2 

### concentration of the stationary internal combustion engine exhaust at the sampling port location; and, (2) Method 3, 3A, or 3B of 40 CFR part 60, appendix A (b) Measurements to determine O 2 

### concentration must be made at the same time as the measurement for NO X 

### concentration.
iii. If necessary, measure moisture content of the stationary internal combustion engine exhaust at the sampling port location; and, (3) Method 4 of 40 CFR part 60, appendix A, Method 320 of 40 CFR part 63, appendix A, or ASTM D 6348

– 03 (incorporated by reference, see §60.17) (c) Measurements to determ ine moisture content must be made at the same time as the measurement for NO X 

### concentration.

iv. Measure NO X 

### at the exhaust of the stationary internal combustion engine (4) Method 7E of 40 CFR part 60, appendix A, Method 320 of 40 CFR part 63, appendix A, or ASTM D 6348

– 03 (incorporated by reference, see §60.17) (d) NO X 

### concentration must be at 15 percent O 2 

### , dry basis. Results of this test consist of the average of the three 1

- hour or longer runs.

c. Reduce PM emissions by 60 percent or more i. Selec t the sampling port location and the number of traverse points; (1) Method 1 or 1A of 40 CFR part 60, appendix A (a) Sampling sites must be located at the inlet and outlet of the control device.

ii. Measure O 2 

### at the inlet and outlet of the control dev ice; (2) Method 3, 3A, or 3B of 40 CFR part 60, appendix A (b) Measurements to determine O 2 

### concentration must be made at the same time as the measurements for PM concentration.
iii. If necessary, measure moisture content at the inlet (3) Method 4 of 40 CFR part 60, appendix A (c) Measurements to determine and moisture content mustIndiana Gasification LLC Page 27 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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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 O 2 

### , dry basis. Results of this test consist of the average of the three 1

- hour or longer runs.

d. Limit the concentration of PM in the stationary CI internal combustion 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 O 2 

### concentration of the stationary internal combustion engine exhaust at the sampling port location; and (2) Method 3, 3A, or 3B of 40 CFR part 60, appendix A (b) Measurements to determine O 2 

### concentration must be made at the same time as the

measuremen ts 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 O 2 

### , 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:]Indiana Gasification LLC Page 28 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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### Gene ral 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 stationar y 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 i n 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 YesIndiana Gasification LLC Page 29 of 29 Rockport, Indiana PSD and TV Permit No.: 147

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**Browse Previous |**  **Browse Ne xt** 

## 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

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## 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 t o 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 c ompliance 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 onl y 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 th is 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), o r (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.Indiana Gasification LLC Page 2 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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(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 ch oosing 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 als o 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 subj ect 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 compl y 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 intermitte ntly 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 tr ain 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 faci lity) 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 equipmen t. 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.Indiana Gasification LLC Page 3 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 cov ered 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 pie ce 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.

Co mpliance 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 subpart s 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 proce ss 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, open

ended valve or line, va lve, 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 stop ping 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 offsi te 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 equipme nt 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.Indiana Gasification LLC Page 4 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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In food/medical service means that a pie ce 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 dilut ion 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 i s 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 organi c 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 t his 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 bel ow 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 samp lers.

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 pr ocess units following malfunctions or process unit shutdowns.Indiana Gasification LLC Page 5 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 operat ing 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 i nstrumentation 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 o r 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 manu facturing 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 includ es 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 struc ture (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 bei ng 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 oper ating 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 bypass ing of equipment without stopping production are not process unit shutdowns.Indiana Gasification LLC Page 6 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 inc lude, 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, re use, 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 c onsidered 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 mon itored 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 sys tem 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 no t 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 requireme nts of §§63.163 through 63.170, and §§63.172 through 63.174 of this subpart, the owner or operator shall comply with the alternative.Indiana Gasification LLC Page 7 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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(c) Each piece of equipment in a process unit to which this subpart applies shall be identified such that it can be distin guished 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 f rom 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 subpa rt, 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 §6 3.174(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 unl ess 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 op erator 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 accord ing 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 day s 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 p rovisions 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 leakIndiana Gasification LLC Page 8 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 appl icable 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, beginn ing 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) Beg inning 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 gr eater.

(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 fo r pumps in food/medical service; and

(C) 1,000 parts per million or greater for all other pumps.Indiana Gasification LLC Page 9 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 liqu ids 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 grea ter 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 percen t 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 qu ality 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:

%P L =((P L −P S )/(P T −P S ))×100

where:

%P L =Perce nt leaking pumps

P L =Number of pumps found leaking as determined through monthly monitoring as required in paragraphs (b)(1) and (b)(2) of this section.

P T =Total pumps in organic HAP service, including those meeting the criteria in paragraphs (e) and (f) of this section.

P S =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) thro ugh (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 barri er 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; orIndiana Gasification LLC Page 10 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 obse rved 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 freq uency 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 o n 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 l ater 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 actuate d 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 sit e 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 mo nthly.

(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 descr ibed 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 du ring safe

- to

- monitor times, but not more frequently than the periodic monitoring schedule otherwise applicable.Indiana Gasification LLC Page 11 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 p aragraphs (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 tha t 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 detect ed, 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 i s 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 ini tially 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]Indiana Gasification LLC Page 12 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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## § **63.165 Standards: Pressure relief devic**  **es 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 sect ion, 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 relie f 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 t he 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

- p urge, 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 re quired 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 f luid 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), o r (iii) of this section.

(i) A waste ma nagement 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 n ot 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 faci lity 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; orIndiana Gasification LLC Page 13 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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(iii) A facility permitted, licensed, or registered by a Stat e 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 thi s 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 sy stem 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 ligh t 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 requi rements; and

(B) Beginning no later than 1 year after initial start

- up, comply with the Phase III requirements.Indiana Gasification LLC Page 14 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 subp art.

(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 de tect 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 instrume nt 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 fo r 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 fi rst 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 own er 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:

%V L =(V L /(V T +V C ))×100

where:

%V L =Percent leaking valves as determined through periodic monitoring required in paragraphs (b) through (d) of this section.Indiana Gasification LLC Page 15 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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V L =Number of valves found leaking excluding nonrepairables as provided in paragraph (e)(3)(i) of this section.

V T =Total valves monitored, in a monitoring period excluding valves monitored as required by (f)(3) of this section.

V C =Optional credit for removed valves=0.67 × net number (i.e., total removed−total added) of valves in organic HAP service removed from proces s 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 V C =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 perio ds 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 se ction. 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 ca lculation 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 perce nt 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 detect ed, 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 month s 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 t o 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), r egardless 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 monitorin g, 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 moni toring 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,Indiana Gasification LLC Page 16 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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(2) Replacement of bonnet bolts,

(3) Tightening of packing gland nuts, and

(4) Injection of l ubricant 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 numb er 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 val ves 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 devi ces 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, olfactor y, 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 re ading 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 mill ion 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 detect ed, except as provided in §63.171 of this subpart.Indiana Gasification LLC Page 17 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 sp ecified 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 F R 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 proc ess 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 r**  **epair.**

(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) T he 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 collec ted 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

(i ii) 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 sh utdown 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 assemblyIndiana Gasification LLC Page 18 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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supplies had been sufficiently stocked before the supplies were depleted. Delay o f 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 782 85, 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 a n 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 combusti on 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 vol ume, 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 §6 3.11(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 sp ecified 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) Cond uct 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 pro cedures 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 le aks 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 fromIndiana Gasification LLC Page 19 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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immediate repair would be greater than the fugitive emissions likely to result fr om 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 leas t 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 des ignated, 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 in specting 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 a s 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 requir ements 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 p art 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.Indiana Gasification LLC Page 20 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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(2) If an instrument reading of 10,000 parts per million or grea ter 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 day s 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) thr ough (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 inspec tion 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 d aily 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 freque ncy 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.Indiana Gasification LLC Page 21 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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(e) Any agitator that is designed with no externally a ctuated 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 exe mpt 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 agit ators 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 fro m 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 comply ing 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 periodi c 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 speci fied 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.Indiana Gasification LLC Page 22 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 mo nths 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 initi al 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 para graph (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 s econd 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 perc ent 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 e ach 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 pe rcent 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 comp lying 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 operat or 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 th e 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 ca se 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 monitorin g periods described in paragraph (b) of this section, by setting the nonrepairable component, C AN , 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 parag raphs (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 altern ative shall be completed no later than 12 months after reporting the switch.Indiana Gasification LLC Page 23 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 befor e 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 pollutant s 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 provi sions 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 connecto rs 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 dange r 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 shutdo wn.

(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 requirement s 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 connect or 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 p ersonnel more than 2 meters above a permanent support surface or would require the erection of scaffold; orIndiana Gasification LLC Page 24 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 inacc essible 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 secti on, 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:

% C L = C L /(C t + C C ) × 100

where:

% C L = Percent leaking connectors as determi ned through periodic monitoring required in paragraphs (a) and (b) of this section.

C L = Number of connectors measured at 500 parts per million or greater, by the method specified in §63.180(b) of this subpart.

C t = Total number of monitored connectors in th e process unit.

C C = 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 s ubpart for existing process units, and after the date of initial start

- up for new process units. If credits are not taken, then C C = 0.

(2) For subsequent monitoring periods, use the following equation:

% C L = [(C L − C AN )/(C t + C C )] × 100

where:

% C L = Percent leaking connectors as determined through periodic monitoring required in paragraphs (a) and (b) of this section.

C L = Number of connectors, including nonrepairables, measured at 500 parts per million or greater, b y the method specified in §63.180(b) of this subpart.

C AN = 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, C t .

C t = T otal number of monitored connectors, including nonrepairables, in the process unit.

C C = 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 theIndiana Gasification LLC Page 25 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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- up for new process units. If credits are not taken, then C C = 0.

(j) Optional credit for removed connectors. If an own er 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 paragrap hs (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 b y 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 t his 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, a s 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 paragr aph (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 perfor mance 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 th e 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:Indiana Gasification LLC Page 26 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 quar terly.

(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 observe d 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 m ethods 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 redu cing 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 ea ch 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 quarter s of monitoring data. The percent reduction shall be calculated using the rolling average percent leaking valves, according to the following:

%LV R = (%LV AVG1 − %LV AVG2 / %LV AVG1 × 100

where:

%LV R =Percent leaking valve reduction.

%LV AVG1 =(%V Li + %VLi=1)/2.

%LV AV G2 =(%VLi=1+ %VLi=2)/2.

where:

%V Li , %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 monito ring 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 tri als 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:Indiana Gasification LLC Page 27 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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%RR = percent reduction required each quarter, as calculated according to §63.168(e)

%V L = 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 achiev e 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 operat or 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 g roup 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 obser vation 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 o f 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 operat or 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 part s 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 paragra ph (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 d etermine 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 les s than 2 percent for specific applications in such a process unit. A candidate superior performing valve technology is oneIndiana Gasification LLC Page 28 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 lit erature 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 per forming 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 wi th 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 estima ted 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 an d 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 aft er 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 proce ss 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 demonstrate d superior emission performance valve designs or technologies shall be amended in the future, as appropriate, as additional information and experience is obtained.Indiana Gasification LLC Page 29 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 tec hnically 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 techni cally 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 detail s 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 associat ed 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 th is 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 a s 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, manufactur er, 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) Requir e 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 wi th 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) Be ginning 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 corpo ration 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 appropriateIndiana Gasification LLC Page 30 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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process, operating, and maintenance practices, will result in less than 2 percent leaking valves f or 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 ident ified, 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 im**  **provement 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 mon itoring 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 t rials.

(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 ver tical 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 characteristic s 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, instrum ent 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 typ es of process units, a description of any maintenance or quality assurance programs used in the process unit that are intended to improve emission performance.Indiana Gasification LLC Page 31 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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(3) The owner or operator shall continue to collect data on the pumps as long as the process uni t (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 pro bable 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 wi th 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 inspecti ons 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) T he 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 imp rovement 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 pr actices 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 c andidate 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 te chnologies 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 mini mum 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:Indiana Gasification LLC Page 32 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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(A) The candidate superior performing pump seal designs or technologies to be evaluated, the stage s 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 whic h 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 leas t, 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 appropr iate, 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 pe rformance 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 superio r 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 t hat 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 assur ance 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 emissio n 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 wit h 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 provi sions 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.Indiana Gasification LLC Page 33 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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(ii) The quality assurance program shall be established no later than the start o f 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 t hat 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 perfor mance 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 mate rial 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 numbe r 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 o f 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 alt ernative 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 limitatio n.

(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 op eration 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 ver ifying 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.Indiana Gasification LLC Page 34 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 o f 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 e nsure 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) Manuf acturers 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, desig n, 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 altern ative 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 paragra phs (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 product

process 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 product

process equipment train shall be pressure

- tested for leaks before organic HAP is first fed to the equipment and the equipment is placed in organi c 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 cale ndar 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 inter mediate.

(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 press ure 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.Indiana Gasification LLC Page 35 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 start

up of the process.

(ii) If a batch product

- pro cess 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 m et.

(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 compl y 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 produ ction 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 a djusted 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 c ampaign. 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 cond itions 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 Alternativ**  **e 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 a re 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.Indiana Gasification LLC Page 36 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 s ubpart, 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 crite ria 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 contai n 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 con ducted.

(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 flui d, 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 a ir 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 t o 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, an d 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 Pha se 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 f or 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 methan e 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 fo r 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.Indiana Gasification LLC Page 37 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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(6) Monitoring data that do not meet the criteria specified in pa ragraphs (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 parag raphs (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) a re 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 requir ed 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 accord ing 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 s hall 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 HA P 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 pe rcent 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 thi s 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

con tained in or contacts the equipment.Indiana Gasification LLC Page 38 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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.

P f =Final pressure, psig.

P i =Initial pressure, psig.

t f −t i =Elapsed time, hours.

(4) The pressure shall be measured using a pressure measurement device (gauge, manometer, or e quivalent) 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 ra te 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.Indiana Gasification LLC Page 39 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 t ime 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 314 40, 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 equ ipment (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 designa ted 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 req uired 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 num bers 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 tha t 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.Indiana Gasification LLC Page 40 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 ex planation 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 p rocess 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 pro cess 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 provisi ons 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 f or 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 thro ugh 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 d ate of first attempt to repair the leak.Indiana Gasification LLC Page 41 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 dela yed” 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 th e 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 p rocess 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 require d 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 thi s 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 computerize d 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 req uirements 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 necess ary 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. Equi pment 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 pressur e, 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 r ecorded in a log and kept for 2 years:Indiana Gasification LLC Page 42 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 deliver y 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 contr ol 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 retai ned 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 diagram s.

(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.

(i v) 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 s elected 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.Indiana Gasification LLC Page 43 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 t he 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 info rmation 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) o f 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 ea ch 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 th e 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 dat es 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 maintena nce practices.Indiana Gasification LLC Page 44 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 pe rformance 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 qu ality 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 th e 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 p iece 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) Identifi cation, 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 wit h 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 th e 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 F R 2792, Jan. 17, 1997; 64 FR 20198, Apr. 26, 1999; 68 FR 37344, June 23, 2003]


## § **63.182 Reporting requirements.** Indiana Gasification LLC Page 45 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 sec tion. 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 des cribed 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 t o 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 applicat ion. 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 s ubmittal 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 sub mit 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 af fected 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 refe rences 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 recons truction 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 s ooner than 90 days after the date of promulgation of the subpart that references this subpart).Indiana Gasification LLC Page 46 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 p rocess 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 standar d (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 par agraphs (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 require ments 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 comp liance 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 s ource 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 pe riod.

(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;Indiana Gasification LLC Page 47 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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(ii) The number of valves for which leaks were not repaired as required in §63.168(f) of this subpart, identi fying 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 whic h 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 nu mber 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 comp liance 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 pro cess 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.Indiana Gasification LLC Page 48 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 F R 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 sub part 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 a re 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 d efined 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 f requency 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.Indiana Gasification LLC Page 49 of 49 Rockport, Indiana PSD and TV Permit No.: 147

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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 pressure 1 

### (kilopascals) 75 ≤ capacity < 151 ≥13.1 151 ≤ capacity ≥ 5.2 a

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 Bottom**  **s Receivers at New Sources** 

Vessel capacity (cubic meters) Vapor pressure 1 

### (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 F R 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 Gasifica tion, LLC Source Location: CR 200 N and Base Road, Rockport, IN 47635 County: Spencer SIC Code: 4925, 2819 Operation Permit No.: T 147

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Public Notice Information

On December 1 5 , 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 dioxid e (CO 2 ) 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 intere sted 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 Spe ncer 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 reflect s 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 documente d and part of the record regarding this permit decision.

Comments Received from USEPA

On February 2, 201 2

, 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 “signific ant” 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 em it 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 ana lysis is not necessarily required, but IDEM shouldIndiana Gasification, LLC Page 2 of 122 Rockport, Indiana T 147

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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 it s 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 d esignate air quality models for ozone and PM 2.5 for use by all major sources applying for a PSD permit that, because “[t]he complex chemistry of ozone and secondary formation of PM 2.5 are well

- documented and have historically presented significant challeng es 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 mode ls 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 case

by

- 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. P art 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 of fice to determine the most suitable approac h 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 m odels 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 str ategies 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 impac t in these regional models.

Given the limited significance of Indiana Gasification’s emissions, 16 tons per year for V OCs and 127 tons per year for NOx , the analysis set forth below demonstrates that the IG project would not have an effect on the attainme nt status. Examining the point source emissions for Spen cer 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 repres ent 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 thi s 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

.

.Indiana Gasification, LLC Page 3 of 122 Rockport, Indiana T 147

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- 00060 Permit Reviewer: Josiah Balogun Since ozone is a regional pollutant a s 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 Be cause 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 in cluded 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 a ll 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. T he CSAPR website is located at http://www.epa.gov/crossstaterule/techinfo.html.

Information regarding the NO x 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 spreadshe et shows the base case annual NOx emissions for Indiana by 2014 at 431,342 tons and

r emedy 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 va lue 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 reduct ion 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 impac ted 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 co ncentrations, the r atio 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 NO x and VOC/7,092 tons NO x = 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 o zone monitors and the impact that IG would have on ozone concentrations in the area. Base case and remedyIndiana Gasification, LLC Page 4 of 122 Rockport, Indiana T 147

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concentrations come from t ables located in CSAPR_AQModeling.pdf, Appendix B, pages B

- 10 and B

- 12 for 8

- hour ozone design values that show the project ed 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 emiss ion 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 Base

Remedy (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 0.008 7%

Based on this analysis, IG’s impact to regional ozone is expected to be only about 1/100 th 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 ozon e monitoring network is 0.5 ppb. Values contained in Table 1 (0.01 ppb or less) would not be measurable.

Summary

Indiana Gasification’s NO x 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 CO 2 equivalent (CO 2 e) basis. The GHG PTE should account for CO 2 emissions and any other GHG emitted from the facility (e.g., methane, nitrous oxide).

Response 2: The PT E for total GHG

— expressed as CO 2 e

— 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 CO 2 , but does not contain limits for other GHG pollutants. Please clarify, in the permit record, how compliance will be demonstrated for any non

- CO 2 GHG emitted from the facility.Indiana Gasification, LLC Page 5 of 12 2 Rockport, Indiana T 147

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Response 3: CO 2 was selecte d as a surrogate for point source CO 2 e 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 CO 2 emissions. Thus, limitat ions on CO 2 will directly and proportionately limit non

- CO 2 , point source GHG emissions. Second, point source GHG emissions at the proposed facility total 2.18 tons per year CH 4 and 0.34 tons per year N 2 O, for a total of 151.18 tons per year CO 2 e. Point

so urce CO 2 emissions from this proposed facility total 1,875,000 tons per year. The relative contribution of CH 4 and N 2 O to total point source CO 2 e (0.0081%) is insignificant and does not warrant separate limits. Third, the principal source of CH 4 and N 2 O 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, CO 2 was selected as the surrogate for all point source GHG emissions at the proposed facility. Compliance for GHGs other than CO 2 from such sources can and will be demonstrated through the emission limits for CO 2 . The explanation of this approach is in the current record at several points. (For example, see TSD BA CT Analysis text at page 149 of 181).

The only instances where CO 2 is not an adequate surrogate are in the case of fugitive SF 6 emissions from circuit breakers (FUG

- SF6), and fugitive CH 4 emissions from equipment (FUG). For this reason, emissions of the se 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 t here are any G HG emissions from the gasifier.

Response 4 : No. The gasifier is not an emission source except for small amounts of fugitive emission s, 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 the m in the permit

.

Comment 5 : The flare minimization plan require ment (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/PM 10 /PM 2.5 , CO, SO 2 , and NOx apply to startup and shutdown, but does not mention limits for other flaring events. Since BACT applies at all times, t he 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 ) ). Thi s 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 infre quent. 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 malfunct ion flaring

, instead of numeric limits. These work practices are required at all times and include use of flare best practices (e.g.

, C ondition D.2.4 ( 1 )( B ) ) and a requirement to follow the flare minimization plan (e.g.; C ondition D.2.4 ( 1 )( A ) ) which includ es, among other requirements, a requirement toIndiana Gasification, LLC Page 6 of 122 Rockport, Indiana T 147

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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 nume ric 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 SO 2 emissions during a shutdown event to 85.21 pounds pe r hour (lb/hr) or 255.6 lb per 24

- hour period. The technical support document lists SO 2 emissions from this flare as 1.97 tpy. However, the 255.6 lb per 24

- hour limit could result in maximum SO 2 emissions of 46.65 tpy. Given the disparity between the pr ojected 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 SO 2 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 esti mated 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 o f 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 SO 2 e missions have been added to the permit.

D.2.4 PM, PM 10 and PM 2.5 , CO, SO 2 , NOx and GHGs PSD BACT [326 IAC 2

- 2

- 3] Pursuant to PSD/Operating Permit T 147

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- 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 SO 2 emissions from the Syngas Hydrocarbon Flare, identified as (EU

- 001) shall be limited as follows :

.............................................................................. ............................................... The SO 2 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 pe r twelve (12) consecutive month period with compliance determined at the end of each month . The SO 2 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 twelv e (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 CO 2 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 CO 2 reduction is to be achieved by the production of liquified CO 2 that will be sold to third parties for use in enhanced oil recovery. Permit condition D.4.16 includes a compliance determination method for CO 2 emissions; however, this condition does not appear to account for monitoring CO 2 emissions from the liquefaction process. The permit should include a monitoring requirement that accounts for the removal of CO 2 from the AGR emission stream in order to demonstrate compliance with the 1,290,000 tpy limit for emissions of CO 2 from the facility.

Response 7 : With respect to monitoring the CO 2 from the AGR vent, the AGR will isolate CO 2 to produce a 98% pure CO 2 stream. (See IG Permit A pplication Secti on 2.0). That CO 2 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 Condition s D.4.11 and D.4.24 (d) . CO 2 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 intoIndiana Gasification, LLC Page 7 of 122 Rockport, Indiana T 147

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account the flow and the CO 2 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 CO 2 emissions from the liquefaction process, liquefaction i s performed through electric

- power compressors that do not themselves emit combustion

related CO 2 . The fugitive CO 2 emissions from the compressors are addressed in the leak detection and repair requirements of permit condition D.15.4. The CO 2 emissions fro m 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

– SO 2 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 ve nt 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 operatio n.

............................................................................................................................. ..........................

D.4.2 3 4 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 oxid izer 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

– SO 2 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 s D.4.22

- Vent Flow Monit oring, D.4.6

– SO 2 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

.

............................. .........................................................................................................................Indiana Gasification, LLC Page 8 of 122 Rockport, Indiana T 147

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Comment 8 : A continuous emission monitoring system (CEMS) for NOx, SO 2 , and CO 2 is being proposed for the wet sulfuric acid (WSA) pl ant but not the AGR system vent. Since the AGR vent is the largest source of GHG emissions from the facility, please clarify whether a CO 2 CEMS was considered for the AGR vent and, if so, why a CO 2 CEMS was not included in the draft permit.

Response 8 : T here are three substantial differences between the WSA and the AGR relevant to whether a CO 2 CEMS is appropriate:

First, in contrast to the AGR stream described below, the concentration of the CO 2 in the WSA can vary based on composition of the feedstock and the relative port ions 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 CO 2 , with the rest being mostly CO which combusts in the RTO to CO 2 . The compliance demonstration calculation for the AGR/RTO emissions of CO 2 accounts for the CO 2 in the exhaust, as well as the CO and organics that are converted to CO 2 . Due to conservative default factors, the equation in the permit at S ection D.4.16 results in all the flow being treated as CO 2 . Any variability that would occur would be within the 1% relative accuracy of CO 2 concentration in a CEMS. Accordingly, a CEMS will offer no improvement in the CO 2 tracking of this source.

Seco nd, the WSA will already have NOx and SO 2 CEMs and, therefore, the incremental cost to add and maintain a CO 2 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 CO 2 from this source.

Comment 9 : Pe rmit 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. Th e 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 attac hed 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 HAP s associated with the AGR units are being revised in response to th is 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 o f organic HAP s , 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, an d the method for demonstrating compliance with the COS and total HAP limit s 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.Indiana Gasification, LLC Page 9 of 122 Rockport, Indiana T 147

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D.4.11 Hazardous A ir 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 determi ned at the end of each month.

(b) The Acid Gas R ecovery 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 a t 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 ther mal 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 MM SC F 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 12.7 0.127 lbs methanol emitted /million SCF of vent flow shall be used.

Control Eff ic. = 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 emi ssions 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 continu ously by the Permittee.

Ca rbonyl 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 o xidizer. 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:Indiana Gasification, LLC Page 10 of 122 Rockport, Indiana T 147

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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 o f 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 ga s 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 0.00 023 lbs. formaldehyde emitted/million SCF ven t 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 deter mined 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 w ith 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 so urce an area source of HAPs.Indiana Gasification, LLC Page 11 of 122 Rockport, Indiana T 147

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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 othe r 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 u tilize 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 (Sour ce 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 appl y 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 perfo rmance 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 t hese 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 temperatur e of 750 F at all times acid gases are being fed to the unit . The only period when temper a tures 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 o f 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

.

Th is will require the following changes to the perm it:Indiana Gasification, LLC Page 12 of 122 Rockport, Indiana T 147

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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 Availab le 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) whe n 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, t he 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 al l 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.5.2 0 1 Record Keeping Requirements

............................................................................................................................. .............................. (e) To demonstrate compliance with Co ndition D.5.19, the Permittee shall record the output of the continuous temperature monitoring system on the flow to the SCR.

( f e ) 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, PM 10 , PM 2.5 , CO, SO 2 , 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 oper ating 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 cal culations 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 fiv e 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 acc ordingly.

D. 7 .4 PM, PM 10 and PM 2.5 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 (P SD)), the Best Available Control Technologies (BACT) for the Gasifier Preheat Burners , identified as EU

- 008A

- E shall be as follows:

The PM, PM 10 and PM 2.5 emissions from the Gasifier Preheat Burners (EU

- 008A

- E) operation shall not exceed 0.0007 lb /MMBt u , each and only natural gas or SNG shall be used

.Indiana Gasification, LLC Page 13 of 122 Rockport, Indiana T 147

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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 Sig nificant 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 SO 2 PSD BACT [326 IAC 2

- 2

- 3] Pursuant to PSD/Operating Permit T 147

- 30464

- 00060 and 326 IAC 2

- 2

- 3 (Preventi on 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 SO 2 emissions from the Gasifier Preheat Burners (EU

- 008A

- E) operation shall be not exceed 0.0006 lb SO 2 /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 sha ll 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 (EU

033). Permit condition D.18.4 says that operation of the carbon ad sorber (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 spe cific HAP limit for this unit. If use of this con trol 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 state s 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, 32 6 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.Indiana Gasification, LLC Page 14 of 122 Rockport, Indiana T 147

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D.5

. 2 2 1 Reporting Requirements (a ) Pursuant to 326 IAC 3

- 5

- 7(5) 32 6 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 corr ected the typo in Condition D. 6

. 17 in the permit accordingly.

D.6

. 1 7 8 Reporting Requirements (a ) Pursuant to 326 IAC 3

- 5

- 7(5) 326 IAC 3

- 5

- 7(c)(4 ) , reporting of continuous monitoring system instrument d owntime, 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 r eceived 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 i s 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 incine ration 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 th e 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 refu se 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 operat ions begin; why isn’t this required?

Response 2 : Sources that are constructing new emission units are allowed 90 days after th ose units begin operation to get monitoring equipment and processes running correctly . New monitoring equipment for new units r equire 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 theIndiana Gasification, LLC Page 15 of 122 Rockport, Indiana T 147

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monitoring requir ements. The source must still comply with all of its emission limits and standards once it begins operation. IDEM does not have to have emission monit oring 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 pro ve 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 exis ting? 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 Emergen c y 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 t he 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 establ ished 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 epi sode 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 am bient 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 techn ology

- 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 conditio n 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.Indiana Gasification, LLC Page 16 of 122 Rockport, Indiana T 147

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Comment 4 : Section C.16 allow s 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 D emonstrated 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 demonst rate 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 subpa rt (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 respon se 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 actio n 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. Em issions 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 actua l measured emissions?

Response 5 : This p ermit 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.Indiana Gasification, LLC Page 17 of 122 Rockport, Indiana T 147

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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 w ould 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 CO 2 emissions in the first two years of o peration. This indicates that unnecessary emissions will occur, that or the CO 2 capture process is not perfected. What is the cause of these variations in CO 2 emissions over time? How will the capture of CO 2 be accomplished? Where will the CO 2 be stored or how will it be removed from the site?

Response 6 : With respect to the commenter’s use of the phrases “CO 2 capture process,” “capture of CO 2 ” or “CO 2 be stored or removed from the site” to describe the manufacture of CO 2 as a product for sale , it shoul d be clarified that the CO 2 is produced in the gasification and purification process and is not “captured” from an emission unit. (See Response to Public Comment 9). Further more it is not stored at the Indiana Gasification site. The cause of the variations in CO 2 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 ca lls for a pipeline to Louisiana for transporting liquid CO 2 captured by the plant, so that CO 2 can be used to enhance oil recovery from old wells. There is no assurance that thi s pipeline will ever be built. The plant proposes to operate the first two yea rs 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 CO 2 into the atmosphere. Otherwise, we would have to shut

- down the plant and layoff 200 plant worke rs." Enhanced oil recovery is an established means of sequestering CO 2 . 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 CC S, the plant will unnecessarily inc rease CO 2 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 Pe rmit Condition D.4.9 expressly prohibits what this commenter speculates will occur by providing enforceable limits on CO 2 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 CO 2 emissions but despite the progress shown by the CO 2 emission limit in the Draft Permit, it simply does not include
sufficient limits on future CO 2 emissions from the Project, given the record available

below. The Indiana Air Pollution Control Board has adopted thi s rule into its PSD program. SeeIndiana Gasification, LLC Page 18 of 122 Rockport, Indiana T 147

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326 I A C 2

- 2

- 1(zz)(1) (including facilities that emit 75,000 CO 2 e , or 100,000 CO 2 e if the project is built after July 1, 2011, in the definition of “subject to regulation”). The Project will exceed this applicability thr eshold, and thus IG was required to perform a greenhouse gas BACT analysis. The inclusion of a CO 2 emission limit is therefore required for this facility. See Draft Permit Condition D.4.9 (establishing CO 2 emission limit of 1.29 million tpy during and af ter the third 12 months of operation). The Project’s CO 2 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 CO 2 produced at the facility. See Application, Appx. F at 2

- 7. However, IG b elieves that operational constraints, including potential downtime of the CO 2 pipeline and downstream offtakers, as well as maintenance and other issues within the facility itself, may result in the amount of CO 2 actually placed into the pipeline to be onl y about 80% of the potential CO 2 emissions from the AGR. Thus, the CO 2 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 CO 2 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 emiss ion 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 CO 2 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 CO 2 emissions.

A s 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 forIndiana Gasification, LLC Page 19 of 122 Rockport, Indiana T 147

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some CO 2 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 CO 2 from it. For example, the coordination of maintenance outages across the facility and with
downstream CO 2 customers is likely to improve with experience. So, too, should knowledge of the operation of such other key equipment as CO 2 compressors. We recognize that IG views CO 2 as a sales product of the Project, and thus has
incentives to minimize the vented volume of CO 2 in order to maximize the CO 2 sales volume. The record therefore supports an additional CO 2 emission limit to be effective begi nning in the eighth operational year at a level equal to the actual CO 2 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 tha t 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 CO 2 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 input

based 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 CO 2 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 i s 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 uni t until that unit later makes a change that triggers another PSD review. O ccasionally

, a permitting authority may devise a flexible approach to BACT emission limitation s , 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 vent s is appropriate. To the extent that additional te chnical 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 informati on available at those times would be used to inform any future BACT determination

.

It should be noted that the CO 2 manufactured in the AGR is a valuable product, and the permittee has significant incentives to minimize the emission of CO 2 at the AGR ven t. 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 CO 2 as product as feasible, and is therefore also inappropriate

.Indiana Gasification, LLC Page 20 of 122 Rockport, Indiana T 147

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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 a nd 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 plai n 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 polluta nt 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. S uch 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 CO 2 . CO 2 is widely distributed pollutant that produces impacts as

a re sult of increasing global average concentrations of the gas in the atmosphere. Thus, imposing a constraint on the amount of CO 2 that may be released at one point without requiring a demonstration that the captured CO 2 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 CO 2 must contain conditions sufficient to demon strate that captured CO 2 will be handled in a manner providing a high degree of assurance that the CO 2 will not be released to the air, either during transport of the CO 2 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 historicall y interpreted the BACT requirement to be inapplicable to secondary emission s, 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 Guida nce 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 rev iewed, 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 collectio n 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 n ot 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 * * * theIndiana Gasification, LLC Page 21 of 122 Rockport, Indiana T 147

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- 00060 Permit Reviewer: Josiah Balogun 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. , PS D 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 limitat ion 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. 1 990 Manual at C.1. However, because there is no NAAQS or PSD increment for GHGs, EPA has directed that secondary emissions of CO 2 need not be included in the ambient air quality impacts analysis. See GHG Guidance at 47

– 48. S econdary emissions of CO 2 have no place in a review of the proposed facility.

Consequently, comments that relate to the control of CO 2 downstream of the proposed facility ( e.g. , control of CO 2 during transportation, storage, use, and re

- use in EOR operations) are not relevant to this p ermitting 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 ap plicant’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 requir ed 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 CO 2 for EOR

– relied upon later in selecting the proposed CO 2 BACT limit on the AGR vents themselves. Nor does IDEM determine whether sequestration of the AGR Vent CO 2 is an “available” technol ogy 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 CO 2 for EOR as a control technology in Step 1, but it then discusses in Step 4 potent ial constraints on the project’s ability to control CO 2 via EOR based on uncertainty around construction of the pipeline for EOR shipments ofIndiana Gasification, LLC Page 22 of 122 Rockport, Indiana T 147

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CO 2 . Assuming for argument’s sake that these considerations are properly Step 4 factors, and that they go to issue s 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 CO 2 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 st ate 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 a r m’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 EO R 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 di stinguish between high

- purity CO 2 produced by the AGR and delivered to the pipeline, and the high

- purity CO 2 produced by the AGR but routed to the AGR vent. As explained on page one of the TSD, CO 2 produced by the AGR, compressed, and delivered to the pipe line is a product of the Indiana Gasification facility. That the delivered CO 2 has value as a product is evident by the fact that revenues from CO 2 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 CO 2 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 CO 2 ”) . As a product, that CO 2 is not an “air pollutant” as that t erm is defined by the Clean Air Act, and therefore no BACT analysis is required for the product CO 2 . Conversely, CO 2 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 i s required. The CO 2 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 CO 2 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 CO 2 are not the responsibility of the permit applicant any more than a carbonated beverage manufacturer is responsible for the ultimate release of CO 2 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 ass erting that sequestration for AGR vent CO 2 was excluded from the list of available technologies in Step 1 of the top

- down approach. For CO 2 emitted from the AGR vent, the BACT analysis explicitly included carbon sequestration in Step 1 of the top

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down anal ysis. 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 ‘avail able’ 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 CO 2 as an “available ” technology, and then in detail explained why the technology is nevertheless technically infeasible. See TSD BACT Analysis at 150

– 153.

Comment 1 1 : IDEM erroneously eliminated sequestration as technically infeasible.

The analysis of sequestration that IDE M 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 se questration 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”) wi ll 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 sandsto ne, 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 (CO 2 ) 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 CO 2 from the plant; 2. Containment o f 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 gr ains 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 ofIndiana Gasification, LLC Page 24 of 122 Rockport, Indiana T 147

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- 00060 Permit Reviewer: Josiah Balogun accommodating all of the CO 2 produced by the plant over a pla nned 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 CO 2 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 (seis mic) 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 w ith 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 requir e 3 to 4 wells with a well spacing of only 2 miles. The thickness also reduces the area required for the CO 2 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 speci fic 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 Gasifica tion if they decided to transport CO 2 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 abou t 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 challen ges related to the acquisition of rights of way for a CO 2 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 othe r 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 a rgument against the technical feasibility, especially when the construction of a pipeline by a third party is used as an option to transport CO 2 away from the plant site.

Finally, the ongoing nature of sequestration research sponsored by the U.S. Departme nt 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 notIndiana Gasification, LLC Page 25 of 122 Rockport, Indiana T 147

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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

- sp ecific analysis can be used to examine the technical feasibility of sequestration.

Response 1 1 : The commenter questions the determination that sequestration is technically infeasible as BACT for CO 2 emissions from the AGR vent. Accordingly, this response will address that comment. The technical infeasibility of capturing CO 2 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 v ent GHG BACT analysis for the Indiana Gasification project. The BACT determination indicates that MGSC was beginning a large

- scale CO 2 injection project (1 million tons) over a three year period, but concludes that this Department of Energy funded demonstr ation 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 CO 2 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 Ce nter. The Schlumberger studies were conducted on behalf of a proposed IGCC plant in Illinois, which IDEM understands does not have a CO 2 BACT limit as part of its State of Illinois issued air permit. The study describes its objectives as follows:

A geolo gical 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 (CO 2 ) 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 CO 2 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 CO 2 produced by the Taylorville Energy Center over a p lanned 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 sequestr ation 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 seque stration 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 CO 2. Moreover, th e 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 varyIndiana Gasification, LLC Page 26 of 122 Rockport, Indiana T 147

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from those assumptions and could therefore result in t he 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 CO 2 , and plans to continue to inject CO 2 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, monitorin g and verification activities will be ongoing to evaluate how the injection proceeds, where the underground CO 2 plume forms, and whether permanent storage has been accomplished. The results of these evaluations are not known today. Importantly, Chuck McCon nell, 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 pot ential 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 technicall y 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 build

up of CO 2 . 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 demons trating 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, th e 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 ofIndiana Gasification, LLC Page 27 of 122 Rockport, Indiana T 147

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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 ha s 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

- is sued 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 20 10. 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 CO 2 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 emissio n 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 as serted 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 facili ty. 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 CO 2 in the future, however, and does not conflict with IEPA’s finding that geologic sequestration is currently tec hnically 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 feas ible 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 CO 2 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 technical ly feasible at the Taylorville site, t he assessment of sequestration as presented in the BACT determination remains valid.

Comment 1 2 : 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 CO 2 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 wi th the BACT limit. See supra ,2

- 6. Due to its composition as a compressed gas, the potential for release of captured CO 2 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 CO 2 vents and ignores the fate of the captured CO 2 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 CO 2 that was emitted to the air or resulted from the facility. Such a permit structure would allow the captured CO 2 to be released at any ti me and any point. For example, captured CO 2Indiana Gasification, LLC Page 28 of 122 Rockport, Indiana T 147

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- 00060 Permit Reviewer: Josiah Balogun could be piped to facility that used the CO 2 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 CO 2 to an enhanced oil recovery operation cannot be recognized as establishing an emission limitation for CO 2 unless the enhanced oil recovery facility is required to operate pursuant to an approved regime that demonstrates permanent retention of the injected CO 2 . Thus, the permit for any source that captures CO 2 must require a demonstration that the captured CO 2 is delivered to a facility that is subject to design and operational requirements adequate to assure the permanent isolation of the delivered CO 2 from t he atmosphere.

Current federal and state regulations for pipelines and enhanced oil recovery sites do not provide any assurance that CO 2 from the source will not be vented to the atmosphere or that any leaks will be remedied or quantified. Underground i njection of carbon dioxide (CO 2 ) 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 RCR A 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 CO 2 injection: Cla ss VI and Class II. Class II dates back several decades and is used for injecting brines, CO 2 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 CO 2 offtakers would operate. Class VI is a new injection well class, which applies to wells that inject CO 2 for geologic sequestration. Class VI rules were proposed by EPA in July, 2008 and were promulgated in December, 2010, specifically the purpose of CO 2 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 requ irements include an injection zone with sufficient properties to receive the total anticipated volume of CO 2 injectate, a confining zone big enough to contain injected and displaced fluids, and with sufficient integrity to allow injection without initiatin g 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 CO 2 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 requ iring 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 CO 2 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 CO 2 plume and displaced fluids, and more extensiveIndiana Gasification, LLC Page 29 of 122 Rockport, Indiana T 147

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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 furth er 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

- inje ction 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 imple mentation 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 o f protecting USDWs and not necessarily ensuring the safe and effective sequestration of CO 2 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 nee d 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 CO 2 inje ction 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 th ere 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 transi tion 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 CO 2 stream for long

- term containment in subsurface geologic formations. S ubpart UU applies to wells that inject a CO 2 stream into the subsurface (without the objective of long

term containment.

Under subpart RR (which, alongside subpart UU was promulgated in December, 2011), there is no reporting threshold, and basic mass flo ws 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 

### CO 2 leakage pathways in MMA, incl. l ikelihood, magnitude and timing, and b. Delineation of the monitoring area

c. A strategy for detecting and quantifying any surface leakage of 

### CO 2 d. A strategy for establishing expected baselines for monitoring 

### CO 2 surface leakage

There are no specific requireme nts 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 CO 2 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 discretionIndiana Gasification, LLC Page 30 of 122 Rockport, Indiana T 147

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of an EOR operator whether to conduct any MRV needed to demonstrate sequestration and whether to quantify and report a ny leakage. This is wholly inadequate for the purposes of demonstrating that CO 2 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 wil l 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 CO 2 must require a demonstration that t he captured CO 2 is delivered to a facility subject to design, maintenance and operational requirements adequate to assure the permanent isolation of the delivered CO 2 from the atmosphere. EPA’s current regulatory infrastructure as it applies to Enhanced Oi l Recovery operations is not adequate in ensuring the non

- emission of transported and injected CO 2 , 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

su bmit as part of its permit application a CO 2 plan under which the applicant certifies that the entities to which it transfers captured CO 2 are subject to a regulatory program that requires them to follow design, operational and maintenance requirements suf ficient to assure permanent isolation of the CO 2 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 recor d and subject to public comment; thus, IDEM must renotice the proposed permit for public comment once the applicant submits the CO 2 plan.

In advance of comprehensive regulations from EPA that ensure the permanent sequestration of CO 2 during enhanced oil recovery, a CO 2 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 potentia l 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 

### CO 2 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 

### CO 2 emissions from project operations;

• Monitoring and mode ling to predict and confirm the position and behavior of the 

### CO 2 and other fluids in the subsurface during and after injection;

• Accounting and reporting of 

### CO 2 quantities sequestered, injected, recycled, leaked, vented, and any other categories as appropri ate; and,

• Post

- injection site closure and financial responsibility requirements that ensure the long

- term containment of injected 

### CO 2 . Response 1 2 : The commenter suggests that the entire regulatory program for managing the transportation, storage, and inje ction of CO 2 in geologic formations and any consequent “leakage” of CO 2 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 discusse d in Response to Public Comment 10

, which includes a description of the CO 2 sources that must be analyzed for BACT purposes , secondary emissions (if any) associated with CO 2 delivered as product are not air emissions associated with this facility , and the refore not subject to BACT.Indiana Gasification, LLC Page 31 of 122 Rockport, Indiana T 147

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- 00060 Permit Reviewer: Josiah Balogun Consequently, the commenter ’ s detailed discussion of preventing CO 2 from entering the air from EOR use of CO 2 is not relevant to th i s permit proceeding.

Comment 1 3 : Higher carbon dioxide emissions for two years should not be al lowed, use the lower limit from the start of the permit.

Response 1 3 : See Response to Public Comment 8.

Comm ent 1 4 : In diana is one of the worst state s for CO 2 emissions.

Response 1 4 : Indiana’s current economy is based on energy intensive industry and e lectrical power generation. This leads to relatively high CO 2 emissions at the state level. Indiana regulates CO 2 emissions from all new plants that emit large amounts of CO 2 through the Prevent of Significant Deterioration (PSD) program.

This permit ting 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 CO 2 . The GHG BACT Analysis for this source is set out in Append ix 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 : CO 2 sequestration is too costly and dangerous. Will this CO 2 be sequestered?

R e sponse 16 : The permitting authority has concluded that geologic sequestration of emitted CO 2 is technically infeasible for this project, and has accordingly not required CO 2 sequestration. 

## Hazardous Air Pollutants (HAPs) Comments:

Comment 17 : The Permit M ust 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 (Uncontroll ed 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 sufficie nt 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 so urce (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 add ressing the comments below.Indiana Gasification, LLC Page 32 of 122 Rockport, Indiana T 147

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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 i ncluded):

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 throug hput 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 wit h 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 comb ination of HAPs and make the source an area source of HAPs. 

### ”

Response 17 : As stated above t he 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 t he 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 Pollutan ts (HAPs) Minor Limits The single HAP and total HAP from the natural gas

- fired auxiliary boilers identified as EU

005A and EU

- 005B shall be limited by c ompliance with Condition D.6. 10

- Operational Limit and , combined with the potential to emit HAP emissio ns 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

.Indiana Gasification, LLC Page 33 of 122 Rockport, Indiana T 147

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Comment 1 8 : 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 presum ed 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 a ppear 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 1 8 : ID EM has revised the emission unit description for the t wo (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

o xidi zer controlling the AGR which is the AGR/RTO. This is the identification for the AGR regenerative thermal oxidizer not th e identification for the AGR it self. As stated above the identification for the AGR Unit vents are EU

- 007A and EU

- 007B

.

Comment 1 9 : Th e 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 CO 2 emission s 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 indi vidual HAP and twenty

- five (25) tons per year of any combination of HAPs and make the source an area source of HAPs. 

### ”

Response 1 9 : While the commenter is correct that the CO 2 emissions limit operates as a practical limitation on overall HAPs, because unc ontrolled 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, t he HAPs emissions from the preheat burners are very small but the source will be restricting their fuel usage to comply with the CO 2 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 mont hly 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 B ACT [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 f ugitive 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 Addend um 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:Indiana Gasification, LLC Page 34 of 122 Rockport, Indiana T 147

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### “ Compliance with the LDAR program incorporated in Section E.6 for equi pment 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 HAP s from the Fugitive Equipment Leaks from the gasification, shift conversion, gas cooling, AGR, CO 2 compr ession , WSA , and methanation identified as FUG & FUG

- WSA shall be limited by c ompliance 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

. 

## BACT Analysis Comm e n ts :

Comment 2 1 : 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 2 2 : 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 th e 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 presente d in IG’s application on page 3

- 4.


## LDAR Comm e n ts :

Comment 2 2 : 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 a nd 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 4 0 CFR 63.160(a) that are in service at the facility for the following processIndiana Gasification, LLC Page 35 of 122 Rockport, Indiana T 147

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streams : methanol streams, propylene streams, and product SNG streams. The same Subpart H requirements apply to any leaks of SO 2 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 SO 2 .

The conditio n’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 requiremen ts. 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 implementati on 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 pr oduct 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 unclea r 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, SO 2 , 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, c omplete, and practically enforceable.

Response 2 2 : 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 con text 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 sy stems, 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 Sub part H requirements apply to any leaks of SO 2 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 thatIndiana Gasification, LLC Page 36 of 122 Rockport, Indiana T 147

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references in the regulations to methane or VOCs will instead be applied to the pollutant SO 2 . 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 : T he LDAR provisions of this permit are applicable to appropriate piping and components wit h the po tential 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

ex perience 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 2 4 : Section A.3 (c)

- Specific ally 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 2 4 : 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 mill s , 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. T his 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 emi ssion of PM10 is less than five pounds per hour or twenty

- five pounds per d ay. The classification s of these emission units in this draft permit are strictly related to air pollution emissions.

Comment 2 5 : 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 e mitted. 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 PM 2.5 ?

Response 2 5 : A baghouse (also known as a fabric filter) does provide the greatest level of control for PM, PM 10 and PM 2.5 . IDEM conducted a top

- down BACT analysis of PM, PM 10 , and PM 2.5 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 w et scrubber, w et suppression, a c yclone and a f abric filter. IDEM made a final determination that a fabric filter was the top ranked control technology for all three forms of PM (PM, PM 10 and PM 2.5 ) and t hat 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 standar d cubic foot ( dscf ) for PM and PM 10 and 0.00 15 grains per dry standard cubic foot ( dscf ) for PM 2.5 . This level of control is more stringent than any BACT limit reviewed for permits for other sources with similar emission units. Therefore, the baghouse con trol devices provide the highest effective control for PM, PM 10 , and PM 2.5 .Indiana Gasification, LLC Page 37 of 122 Rockport, Indiana T 147

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Comment 2 6 : 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 degre es 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 2 6 : The temper ature is in Fahrenheit. IDEM has made the appropriate clarification in Condition D.1.6

- PM, PM 10 and PM 2.5 Control in the permit accordingly

. See response to Sierra Club Comment 69.

Comment 2 7 : 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 o perations 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 o f 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 th e 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 cond itions not representative of normal loading on the control system. Section D.5.16 applies to the demonstration of particulate emissions fr om 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 summa ry, 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 c annot 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 ha s 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 2 8 : The syn gas flare is extremely dirty for its fuel consumption. Can th e 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 wi ll 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 smallIndiana Gasification, LLC Page 38 of 122 Rockport, Indiana T 147

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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 ava ilable control technologies.

C omment 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 em issions can change with those. This testing is inadequate to protect the public. Will these test result s 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 t wo (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 testi ng 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 th e 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 5 0

. 

## Potential to Emit Comments :

Comment 3 1 : 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 : Th e 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, a ccording 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 chlorinat ion 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 downstrea m 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/publ ications/others/techrpts/igcc_wp.pdf)

.

Comment 3 2 : 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 contai ned in it are not reliably accurate for a specific source.Indiana Gasification, LLC Page 39 of 122 Rockport, Indiana T 147

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- 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 condensab le 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?

Th is 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 em issions and appears not to be. What justifies not listing PTEs of condensable particulate matter in this permit?

Response 3 2 : Because there is no separate applicability threshold for the condensable fraction of particulate, IDEM is not required to separately list out the PTE for thi s subset of total particulate. How ever, 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 Sulfur ic 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 ba sed 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 a nd 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 b ased 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 parti culate 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 3 3 : 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 de termined. Where are these factors from, and what is their degre e of inaccuracy?Indiana Gasification, LLC Page 40 of 122 Rockport, Indiana T 147

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Response 3 3 : Permit condition D.6.15 is the permit condition limiting total CO 2 emission from the Auxiliary Boilers. The CO 2 emissions factor specified (116.89 lb CO2/MMBtu) is taken from the methodology in US EPA’s 2009 Greenhouse G as 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 CO 2 Emissions factors and High Heat Values for Various Types of Fuels) for “Natural Gas, Pipeline (weighted U.S average)” which is 53.02 kg CO 2 /MMBtu (converted to lbs

. /MMBtu). This value is similar to, but about 1⁄2% lower than the older AP42 factor for CO 2 from natural gas external combustion in AP42 Chapter 1.4 (most recent update was July 19 98). 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 3 4 : AP

- 42 clearly states the degree of inaccuracy cannot be de termined: “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

- 9 1

- 028, EPA, 1991, Crosswalk [XATEF] Air Toxic Emission Factor Data Base Management System User’s Manual, Version 1.2, p. 7)

Response 3 4 : The permit contains enforceable limits on the operation of sources and the emissions of sources that serve as the cont rolled potential to emit (“PTE”) for those units. For information related to the use of emission factors, s ee Response s to Public Comment 42 and Sierra Club Comment s 29, 33, and 36

.

Comment 3 5 : Section D. 2.7 requires calculation of emissions using an em issions 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 3 5 : 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 determi ne 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 consi dered to be accurate and appropriate for the source.

The NOx and CO emissions factors specified for the flare are design specificati ons from the equipment vendor. The particulate emissions factors are based on AP

- 42 Chapter 1.4 for natural gas combustio n, 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 n on

- smoking flares as zero (0). A detailed explanation of the basis of the SO 2 emissio n factor for the hydrocarbon flare is provided in the response to Sierra Club Comment 44.Indiana Gasification, LLC Page 41 of 122 Rockport, Indiana T 147

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## Environmental Justice Comment:

Comment 3 6 : Environmental Justice Comment:

(a) Rockport, a community of slightly greater than 2,000 p e opl e has Toxic Release s 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, Phi ladelphia, 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 aver age. 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 th at 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 3 6 : 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 lo cation 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 Age ncy 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 th roughout 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 meetin g 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” f or 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 are as 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 t his 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, PresidentIndiana Gasification, LLC Page 42 of 122 Rockport, Indiana T 147

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Clinton issued Executive Order (EO) 12898, “Federal Actions to Address Enviro nmental 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 cov ered 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 wer e 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 s tructures 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 devel op 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 proc ess 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, ove rlaps 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 CO 2 production plant. At 6:30 p.m., IDEM conducted a formal public hearing on the draft permits. Citizens had the opportunity to subm it 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 at tend the meeting were permitted to submit written comments on the draft permits.Indiana Gasification, LLC Page 43 of 122 Rockport, Indiana T 147

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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 p pb. 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 Qual ity 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 4 th High”) in each table, all sites are currently in attainme nt 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.Indiana Gasification, LLC Page 44 of 122 Rockport, Indiana T 147

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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 HighIndiana Gasification, LLC Page 45 of 122 Rockport, Indiana T 147

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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 HighIndiana Gasification, LLC Page 46 of 122 Rockport, Indiana T 147

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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 HighIndiana Gasification, LLC Page 47 of 122 Rockport, Indiana T 147

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Regarding particulate, IDEM performed a modeling analysis for PM 2.5 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 violat ion 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 contr ibute to a violation of the NAAQS. The analysis and results of the evaluation of PM 2.5 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 sh ed 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 non

attainment of the National Ambient Air Quality Standards for both ozone and fine particles if 2011 w as 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 t he 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 HighIndiana Gasification, LLC Page 48 of 122 Rockport, Indiana T 147

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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 whic h 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.

Fur ther, 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 J uly 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 Ma intenance 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 determinatio n 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 emiss ions 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 prov ides 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 PM 2.5 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 f uture 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 th e PM 2.5 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 QUAL ITY 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 r edesignation 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 PM 2.5 .Indiana Gasification, LLC Page 49 of 122 Rockport, Indiana T 147

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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 analy sis, which is included in the draft permit documentation

, included an evaluation of PM 10 and PM 2.5 .

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.

R esponse 41 : For a description of the ozone analysis, see the R esponse 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 t o 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 e ach 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, t his project does not combust any coal, and so IDEM has not u sed coal combustion emission factors. The c oal and petroleum coke feedstock s are instead chemically converted through a fully enclosed gasification process. Gas ification 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 l imits 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 infor mation, 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 b ased 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 emission s 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.Indiana Gasification, LLC Page 50 of 122 Rockport, Indiana T 147

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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 c ases 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 pollute d 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 med ical problems such as asthma, premature de ath, cardiovascular disease and decrease lung function.

As a resident of Rockport, I am very concerned about the added pol l uti on a coal gasification plant wil l bring to our community. Approval of permit number 147

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- 00060 would expose the residents t o greater heath risks. Spencer C ounty already is high on the pol l ution levels. It's not fair to our younger generation to have them grow up in an unhea l thy environment. I am not willing to trade my grand chi ldren's well

- being for

econom ic 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 th e health of our County people. The effect on the public health must be considered.

Indiana Gasif ication’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 member s 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 ar ea 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 Bio accumulative 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 Pow er 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,

s elenium, and acid emissions.

W e already have so many entities that are polluting the immediate area that it is hard to believe that they are considering another on e?

I don’t want to live here if it gets so bad that you can’t breathe without getting a resp iratory problem.Indiana Gasification, LLC Page 51 of 122 Rockport, Indiana T 147

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- 00060 Permit Reviewer: Josiah Balogun 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 scre ening 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. T he 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 i n 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 so urces, 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 ri sk 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 emer gency 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 Associat ion’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 asth ma

- 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 Asthm a Emergency Department Visits in Indiana 2009Indiana Gasification, LLC Page 52 of 122 Rockport, Indiana T 147

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Source: Indiana Hospital Association’s Hospital Discharge Database

Table 2 below shows the cancer rate compared to the rest of Ind iana 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).Indiana Gasification, LLC Page 53 of 122 Rockport, Indiana T 147

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Table 2. Cancer Incidence Rates, Indiana and Spencer County, 2004

– 2008 *

All Cancers Prostate

Female Breast Lung Colon and Rectum (Male

- only disease) 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 979 th in the state of Indiana. The hi ghest 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 woul d 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, N ATA 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 n on

- 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

- Rock port, AK Steel Corporation an d 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 an d Toxic Release Inventory data where possible. These emissions were combined for each source to come up with a com bined 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.Indiana Gasification, LLC Page 54 of 122 Rockport, Indiana T 147

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- 00060 Permit Reviewer: Josiah Balogun For the 2005 NATA there were a total of 5,221 tons of air toxics in Spencer County, with hydrochloric aci d 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 Coun ty (the three large existing facilities mentioned above and the new proposed Indiana Gasification facility)

. Indiana Gasification parameters were based on available technological informatio n and permit application data. The other three major sources’ stack locations and release parameters were r etrieved 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 m inute 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 buildi ngs 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 pla ced 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 co ncentration for each receptor. For each facility, the estimated concentration for each air to xic was calculated based on the source’s modeled impact a nd the estimated emissions. The concentration was then used to calculate cancer risk and non

- c ancer 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 dose

response 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 r eceptor over one in a million. The average for all the receptors was 0.15 excess cancer

cases. Indiana Gasification highest excess c ancer case receptor was 0.006. The average cance r 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 exc ess 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 u sed 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, ma nganese, cadmium and arsenic. A non

- cancer hazard quotient under 1.0 is commonly recog nized to be health

- p rotective. 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 quoti ent

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 4 4 : Several commenters expressed concerns over the effect of the source ' s emissions on wildl ife, 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 QualityIndiana Gasification, LLC Page 55 of 122 Rockport, Indiana T 147

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Standards (NAAQS) for six criteria pollutants. T hese 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 ab out 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/41 16.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 wat er 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 4 5 : One commenter w as 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 se t and enforce traffic controls. 

## Fugitive Emission Comments

Comment 46 : IDEM barely addressed the very real issue of fugitive emissions from the plan t 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 fugit ive 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 f ormed 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 i s a useful product that will be sold for commercial use. As noted in response to public comment 2 3 , 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 a ny 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 select ion of materials for components and piping that are resistant to acid corrosion.Indiana Gasification, LLC Page 56 of 122 Rockport, Indiana T 147

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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 CO 2 thus, providing a second dose of potential effect on global weather patterns.

Response 47 : In r esponse to concerns over climate change, U.S. EPA promulgat ed new regulations under the PSD program requiring facilities that emit greenhouse gas es (GH G) 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 a ppl ied 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? I s 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 ope rating 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 f ive plants are operating in the Unit ed 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.Indiana Gasification, LLC Page 57 of 12 2 Rockport, Indiana T 147

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Comment 49 : IDEM did not add ress 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 Ind iana 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 ke ep 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 5 0 : 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 5 0 : IDEM monitors the leve ls 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 Smog Watch site at http://www.in.gov/apps/idem/smog/ on IDEM’s website.

Under this permit, IG will have an obligation to submit q uarterly 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 I DEM 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 c an 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 iss ued. 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 mak e 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’sIndiana Gasification, LLC Page 58 of 122 Rockport, Indiana T 147

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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 Re gional Office, P.O. Box, 1120 N. Vincennes Avenue, Petersburg, Indiana 47567.

Comment 5 1 : 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 environ ment, 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 sourc e 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 in crease 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://w ww.cdc.gov/ncbddd/autism/index.html on the internet.

Comment 53 : T he 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 floo d 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 p roperties.

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@d nr.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, t he applicant would be required to ob tain proper permits for proposed wetland impacts. Specifically, the IDEM

- Section 401 Wetlands program require s applicant s to obtain a State certification for jurisdictional impacts. In addition, an applicant would be required to obtain a Section 404 perm it 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.Indiana Gasification, LLC Page 59 of 122 Rockport, Indiana T 147

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Comment 5 4 : The President rejected to bui ld a pipeline to carry oil from Canada to Texas. Why would he approve this pipeline for CO 2 ?

Response 54 : There are a number of interstate permits in the US that support the transport of fuels and products such as CO 2 . In fact, there are a number of CO 2 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 A chievable Control Technology requirements for Green House Gases (GHG BACT).

Comment 5 5 : W hat is the current status concerning the cl ean air permits for the coal ga sification plant bein g proposed for Spencer County?

Response 5 5 : IDEM has now issued the fi nal permit decision, as set out in the Notice of Decision document.

Comment 5 6 : Big Plains Gasification Project in North Dakota: Why is there no TRI data a vailable for this plant?

Response 56 : IDEM has not been able to locate a source named “Big Plains G asification” 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 5 7 : 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 w as 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 5 8 : 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 th e IDEM review

. IDEM has no authority to direct the focus of energy generation or use.Indiana Gasification, LLC Page 60 of 122 Rockport, Indiana T 147

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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 p ermit. 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 handli ng 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 6 3 : 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 j ob 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 facil ity 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 genera lly, and in the central US in particular, especially through development of a CO 2 pipeline to injection sites in the Gulf Coast states and we support the selection of a phased

- in limit for CO 2 over the initial three years of the facility’s operation.Indiana Gasification, LLC Page 61 of 122 Rockport, Indiana T 147

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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 CO 2 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 Coun ty.

(k) I s upport this permit and the project

(l) This is good public policy, Ind. Reg. Comm. Approved.

(m) Oil Recovery use of captured CO 2 will reduc e dependence on foreign oil. I am i n support of th e project.

(n) We need jobs so that pe ople can pay their bills and to support our local tax base. I am i n 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 SO 2 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 compu ter disks available. These contained PM 2.5 and PM 10 modeling but not the SO 2 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 th e spreadsheet were the inputs actually used in the modeling. This is particularly problematic because as explained below, the SO 2 and NOx modeling claims to have predicted impacts very close to the significant impact level and contained numerous flaws. T herefore, IDEM should hold make these computer files available at the public library and then hold a new public comment period.Indiana Gasification, LLC Page 62 of 122 Rockport, Indiana T 147

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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 applic ation 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 dra ft 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 th e 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 SO 2 SIL is not in Indiana’s SIP. There fore, 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 SO 2 . 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 Signi ficant 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 implementa tion 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 tha n 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 addit ion 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 SO 2 and the 1

- hour NO 2 standards, U.S. EPA provided an interim SIL. The interim SIL for SO 2 is 3 ppb (7.86 μg/m 3 ). See Memorandum from Anna Marie W ood, Acting Director, U.S. EPA Air Quality Policy Division, to Regional Air Division Directors, “Guidance Concerning the Implementation of the 1

- hour SO 2 NAAQS for the Prevention of Significant Deterioration Program,” at 6 (Aug. 23, 2010) (“SO 2 SIL Guidanc e”). U.S. EPA derived this value by using an impact equal to 4% of the 1

- hour SO 2 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

corr esponding 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 p lans containing a PSD program to use at their discretion.” Id. at 5.Indiana Gasification, LLC Page 63 of 122 Rockport, Indiana T 147

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- 00060 Permit Reviewer: Josiah Balogun 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 SO 2 SIL Guidance. Thus, although the SIL for SO 2 is not incor porated 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 1 st highest 1

- hour concentration averaged over 5 years for comparison to the 1

- hour SO 2 SIL of 3 ppb (7.86 μg/m 3 ).

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 d o 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 SO 2 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 t he Implementation of the 1

- hour SO 2 NAAQS for the Prevention of Significant Deterioration Program,” at 6 (August 23, 2010) (“SO 2 SIL Guidance”). Specifically, the SO 2 SIL Guidance provides:

[W]e are providing an interim 1

- hour SO 2 SIL value of 3 ppb to i mplement 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 followi ng:

• The highest of the 5

- year averages of the maximum modeled 1

- hour SO 2 concentrations predicted each year at each receptor, based on 5 years of National Weather Service data; or

• The highest modeled 1

- hour SO 2 concentration predicted across all receptors based on 1 year of site

- specific meteorological data, or the highest of the multi

year averages of the maximum modeled 1

- hour SO 2 concentrations predicted each year at each receptor, based on 2 or more, up to 5 complete years of available site

- specific me teorological 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 site

specific meterological data. Consistent with this guidance, IDEM used the maximum 1 st highest 1

- hour concentration at each receptor averaged over 5 years for comparison to the 1

- hour SO 2 SIL of 3 ppb (7.86 μg/m 3 ).

Comment 4: THE MODELING USES IMPROPER EMISSION RATES

IDEM claims that the maximum emissions from the sy ngas 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 obtaine d 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 Permi t”), 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 startupIndiana Gasification, LLC Page 64 of 122 Rockport, Indiana T 147

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- 00060 Permit Reviewer: Josiah Balogun 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 sta rtups 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 litt le SO 2 emissions as compared to coal. IG has committed to using methanol as a start up fuel which gives lower lb/hr values for SO 2 . IG has also committed to slightly lower shutdown SO 2 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 SO 2 mod eling fails to consider SO 2 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 s p readsheet submitted to IDEM under a September 29, 2011 cover letter, SO 2 tab. The modeling must model SO 2 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 federa l 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 emission s 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 SO 2 , startups represent the operating scenario resul ting 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, SO 2 emission from start up flaring is relatively small because the facility will be permitted to startup on methanol, which is essentially sulfur free. Instead, the maximum flare SO 2 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 sulf ur content. As a result, as this gas is vented to the flare following a shutdown, SO 2 will be generated. Again, the modeling analysis for SO 2 included shutdown flaring.

No other facility equipment would require flaring due to startup or shutdown, or hav e 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 Pow er 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 inIndiana Gasification, LLC Page 65 of 122 Rockport, Indiana T 147

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- 00060 Permit Reviewer: Josiah Balogun 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. Malfu nction 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 pollut ion 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 malfu nction 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 wa y 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 limit s 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 sti ll 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 A ppendix 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 det ermining 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 NO 2 NAAQS, EPA recommends that the revie wing 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 i n 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 SO 2 inadequate, the ambient impact analysis for NOx, PM 10 , PM 2.5 and the synthetic minor HAPs determination are also invalid.Indiana Gasification, LLC Page 66 of 122 Rockport, Indiana T 147

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Response 6: The Acid Gas Flare is used only for relief protection during upsets or malfunctions of the Wet Sulfu ric 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 malfun ctions. Therefore, the potential to emit (PTE) must be used in the modeling. The SO 2 PTE is 400 tons per hour of coal * 3.66% S coal * 64/32 = 29.28 tons per hour SO 2 . Assuming that all the sulfur is converted into SO 2 is appropriate because IDEM admi ts 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. Therefor e, 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. T herefore, the modeling must use 1

- hour averaging time PTE. In the SO 2 modeling, according to the shreadsheet submitted to IDEM under a September 29, 2011 cover letter, the modeling used a SO 2 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 scena rio. 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 sce nario 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 modeli ng must use 0.015 lb/hr in all scenarios.

The same is true for the firewater diesel pumps. In the SO 2 modeling, according to the shreadsheet submitted to IDEM under a September 29, 2011 cover letter, the modeling used a SO 2 emission rate of 0.00004 lb/hr for one scenario, 0.002 for another, 0.00025 for a third and no emissions for the “wor st 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 t he “wor st 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 dependingIndiana Gasification, LLC Page 67 of 122 Rockport, Indiana T 147

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on the averaging time of the standard bein g modeled:

• Modeling for a 3 hr standard assumed each engine was tested for 1 hr resulting in an average emissions rate for the period 1/3 rd the single hourly emission rate (1 hr of emissions divided by 3 hours of the standard).

• Modeling for a 24 hr sta ndard used 1/24 th 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. The refore, 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. F or 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 modeli ng (SO 2 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 th e 1

- hour NO 2 National Ambient Air Quality Standard”). The memorandum provides additional clarification regarding application of Appendix W modeling which applies to both NO 2 and SO 2 1

- hour standards . The memo addresses emission scenarios concerning int ermittent 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 Append ix 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 expecte d 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 im pacts 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

- cas e 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 provi de 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 NO 2 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.Indiana Gasification, LLC Page 68 of 122 Rockport, Indiana T 147

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Page 9

-
Given the implications of the probabilistic form of the 1

- hour NO 2 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 NO 2 NAAQS be based on emission scenarios that can logically be assumed to be relatively continuous or which occur frequently enough to contri bute 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 NO 2 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 em issions 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 a t 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 t he past to demonstrate compliance with the annual NO 2 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 NO 2 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 SO 2 and NOx modeling used an average annual emissi ons 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 cond ition 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 underst anding 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 mem orandum add resses 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 StandardsIndiana Gasification, LLC Page 69 of 122 Rockport, Indiana T 147

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- 3.

Among other things, the Seitz Memo explains that “EPA has determined that a reasonable an d 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. Co nsequently, EPA does not recommend the use of 8760 hours per year (i.e., full

year 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

- cas e 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 incor rect 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 ea ch of these e mergency 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 powe r 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 on ly 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 u nlikely 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 t he 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 an d 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 hydrocarbo n 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 t he 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 differenc es 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, t he 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.Indiana Gasification, LLC Page 70 of 122 Rockport, Indiana T 147

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EPA OAQPS, September 1995) to calcula te 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 fu rther in IG’s application be ginning 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 stac k 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 s ources 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 ast hma 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 o zone 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. Howe ver, 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

e specially 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 C ounty 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 formin g 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 no t 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 rat e. TSD pdf page 812. However, NO 2 is also an ozone precursor. IG is over the 100 TPY significant level for NO 2 . Therefore an ambient impact analysis is required for ozone.Indiana Gasification, LLC Page 71 of 122 Rockport, Indiana T 147

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IDEM claims:

An air quality analysis is not performed for VOCs because they a re photochemically reactive. Photochemical models like UAM

- V are used in regula tory or policy assessments to s imulate the impacts from all sources by estimating pollutant concentrations and deposition of both inert and chemically reactive pollutants over l arge 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 PM 2.5 , the December 8, 2011 letter providing additional documents which support the petition, and US EPA’s January 4, 2012 re sponse 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 s ays, 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 model s that may be used under specific circumstances for assessing the impacts of an individual source on ozone concentrations and on the secondary formation of PM 2.5 . These advances have resulted in some methods that may allow for tracking the formation and tr ansport of ozone and secondary PM 2.5 impacts from specific emissions sources and calculating the contribution of sources and precursors to ozone and PM 2.5 at individual receptor locations. In fact, the EPA engaged the modeling community on these developmen ts 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 a genda with the topic of chemistry models and related techniques for addressing impacts of ozone and secondary PM 2.5 being a major session and focus of the EPA's efforts to engage the regulatory modeling community.

This modeling conference will serve as th e 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 necessa ry 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 incorp oration into Appendix W.Indiana Gasification, LLC Page 72 of 122 Rockport, Indiana T 147

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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, t he 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 PM 2.5 formation.”

(Emphasis added). In summary, IDEM did us e 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 evalua ted 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 a vailable 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 s ignificant 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 Commen t 2 with respect to SO 2 , the NOx ambient impacts analysis was appropriate and correct

.

For the 1

- hour SO 2 and 1

- hour NO 2 standards, U.S. EPA provided an interim SIL. The interim SIL for NO 2 is 4 ppb (7.55 μg/m 3 ). See Memorandum from Anna Marie Wood, Ac ting Director, U.S. EPA Air Quality Policy Division, to Regional Air Division Directors, “General Guidance for Implementing the 1

- hour NO 2 National Ambient Air Quality Standard in Prevention of Significant Deterioration Permits, Including an Interim 1

- hour NO 2 Significant Impact Level” (June 28, 2010) (“NO 2 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 NO 2 National Ambient Air Quality Standard” (March 1, 2011).

U.S. EPA explained the basis for this SIL value:Indiana Gasification, LLC Page 73 of 122 Rockport, Indiana T 147

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We derived this interim 1

- hour NO 2 SIL by using an impact equal to 4% of the 1

- hour NO 2 NAAQS (which is 100 ppb). We ha ve chosen this approach because we believe it is reasonable to base the interim 1

- hour NO 2 SIL directly on consideration of impacts relative to the 1

- hour NO 2 NAAQS. In 1980, we defined SER for each pollutant subject to PSD. For PM and SO 2 , 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

unreas onably 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 consumptio n 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 documen tation, EPA decided to use 4% of the 24

- hour primary NAAQS for PM and SO 2 to define the significant emissions rates (SERs) for those pollutants. It was noted that, at the time, only an annual NO 2 NAAQS existed. Thus, for reasons explained in the 1980 pream ble, to define the SER for NOx emissions we used a design value of 2% of the annual NO 2 NAAQS. Looking now at a short

- term NAAQS for NO 2 , we believe that it is reasonable as an interim approach to use a SIL value that represents 4% of the 1

- hour NO 2 NAAQS.
NO 2 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. NO 2 SIL Guidance at 10 (“EPA intends to implement the interim 1

- hour NO 2 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 i n accordance with the NO 2 SIL Guidance. Thus, although the SIL for NO 2 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 1 st highe st 1

- hour concentration averaged over 5 years for comparison to the 1

- hour NO 2 SIL of 4 ppb (7.55 μg/m 3 ).

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 off ered nothing in the record to support the use of a SIL in generally or a 7.55 ug/m3 1

- hour SO 2 . 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 NO 2 SIL

, this issue is addressed in the resp onse to Sierra Club Comment 16. See the response to Sierra Club comment 2 for a justification of the 1

- hour SO 2 SIL.

Comment 18: Also, even if the SIL was permissible, IDEM averaged five years of impacts and compared the average to t he SIL. The p roper 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 o ne year was above the SIL. Therefore, a cumulative impact analysis is required followed by an additional public comment period.Indiana Gasification, LLC Page 74 of 122 Rockport, Indiana T 147

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Response 18: For the same reasons discussed in response to Sierra Club Comment 2 with respect to SO 2 , the NOx ambient impact s analysis was appropriate and correct

. IDEM modeled NO 2 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 Implement ing the 1

- hour NO 2 National Ambient Air Quality Standard in Prevention of Significant Deterioration Permits, Including an Interim 1

- hour NO 2 Significant Impact Level” (June 28, 2010) (“NO 2 SIL Guidance”); Memorandum from Tyler Fox, Leader, U.S. EPA Air Qua lity Modeling Group, to Regional Air Division Directors, “Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1

- hour NO 2 National Ambient Air Quality Standard” (March 1, 2011). Specifically, the NO 2 SIL Guidance provides :
In this guidance, EPA recommends an interim 1

- hour NO 2 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 NO 2 concentrations predicted each year at each receptor, based on 5 years of National Weather Service data; or

• The highest modeled 1

- hour NO 2 concentration predicted across all receptors based on 1 year of site

- specific meteorological data, or the highest of the multi

year averages of the maximum modeled 1

- hour NO 2 concentrations predicted each year at each receptor, based on 2 or more, up t o 5 complete years of available site

- specific meteorological data.

NO 2 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 1 st highest 1

- hour concentration at each receptor averaged over 5 years for comparison to the 1

- hour NO 2 SIL of 4 ppb (7.55 μg/m 3 ).

Comment 19: In addition, the draft permit do es not contain any enforceable 1

- hour averaging time emission limits. Therefore, the modeling must use 1

- hour averaging time PTE. In the N Ox modeling, according to the sp readsheet submitted to IDEM under a September 29, 2011 cover letter, the modeling us ed 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 us e 14.58 lb/hr rather than 0.09 lb/hr.

The same is true for the firewater diesel pumps. In the N Ox modeling, according to the sp readsheet submitted to IDEM under a September 29, 2011 cover letter, the modeling used a NOx emission rate of 0.02 lb/hr for th e 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.

Respo nse 19: See response to Sierra Club Comment 9, which discusses the same issue regarding SO 2 emissions from these emergency engines. In summary, this emergency equipment will only operate intermittently and briefly. Therefore, their emissions rate for mo deling 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 hou rs based on theIndiana Gasification, LLC Page 75 of 122 Rockport, Indiana T 147

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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 generator s 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 Sept ember 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 th at 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 f t. 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 basi s for flare modeling parameters.

Comment 22: Finally, the TSD indicates that a Tier II 80% conversion of NO to NO 2 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 NO 2. 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 NO 2 am bient 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 NO 2 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 NO 2 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

- hou r standard, but several references cite ambient ratios of about 0.80 for hourly NO 2 /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 NO 2 standard.” (Empha sis added).

Comment 23: THE AMBIENT IMPACT ANALYSIS FOR PM 2.5 IS INADEQUATE

IDEM acknowledges that it modeled a violation of the 24

- hour PM 2.5 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 hasIndiana Gasification, LLC Page 76 of 122 Rockport, Indiana T 147

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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 PM 2.5 standards, U.S. EPA published a final rule in the Federal Register on Oc tober 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 PM 2.5 are incorporated into the Federal PS D 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/m 3 and for the annual averaging period is 0.3 ug/m 3

. Id. As explained by U.S. EPA in the Final Rule, these values were derived by scaling the PM 10 SIL values by the ratio of the PM 2.5 NAAQS to the PM 10 NAAQS. Id. at 64890. Of the three methodologies originally p roposed 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 PM 2.5 SILs into the Indiana Administrative Code (IAC) became effective on August 3, 2011. See “Emergenc y 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 PM 2.5 was implemented in accordance with LSA D ocument #12

- 68(E), section 13(b) and U.S. EPA’s PM 2.5 rulemaking.

Commenter is incorrect in its claim that “IDEM acknowledges that it modeled a violation of the 24

- hour PM 2.5 NAAQS to which IG is contributing.” During the time of the two modeled NAAQS v iolations, 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 NAAQ S 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 c onsidered 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 o r contribute to a violation of the PM 2.5 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 att aching 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 44 3, 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).Indiana Gasification, LLC Page 77 of 122 Rockport, Indiana T 147

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U.S. EPA’s use of SILs is rooted in the de minimis ex ception 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 bur den 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 PM 2.5 in Indiana’s rules, see IDEM’s response to Sierra Club Comment 23.

Comment 25: In addition, the PM 2.5 modeling failed to include all PM 2.5 . First, it failed to include secondary PM 2.5 , that is chemical s that are emitted from stacks and vents as PM 2.5 precursors and converted to PM 2.5 in the ambient air. Above, we explained how ozone impacts can be modeled for a single source. Those same documents establish that secondary PM 2.5 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 PM 2.5 . Also, 40 CFR Part 51, Appendix W, Sec. 5.2.2.1.c provides the following for PM 2. 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 suit able 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 PM 2.5 often contributes significantly to total ambient levels of PM 2.5 , certain aspects of standard modeling practices used for PM

- 10 and other criteria pollutants may not be appropriate for PM 2.5 . See Memorandum from Stephen D. Page, Director, U.S. EPA Office of Ai r 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 an alysis for PM 2.5 secondary formation can be found at pages 9

- 12 of 49 in the Air Quality Analysis for the permit

.

Comment 26: Finally, the PM 2.5 modeling failed to include emissions from the barges and trains in the PM 2.5 NAAQS modeling. These sources sh ould have been included the NAAQS modeling as nearby background sources.Indiana Gasification, LLC Page 78 of 122 Rockport, Indiana T 147

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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 qualit y 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, exist ing mobile source emissions are included in background for the modeling.

As part of the cumulative PSD analysis for the PM 2.5 24

- hour and annual NAAQS,

re presentative background monitoring data in vicinity of the IG facility are included in the analysis to represent the ambient background PM 2.5 concentrations from sources not included in the regional modeling analysis, such as mobile emissions and smaller

u npermitted 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 a rea 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 PM 2.5 design value of 26 micrograms per cubic meter (ug/m 3 ) for the Owensboro station is the highest of the three closes t stations to the IG facility.

IG used the Owensboro background design values of 26 ug/m 3 and 12.2 ug/m 3 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 unques tionably 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 re main 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 no t 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 err oneous and based on severely flawed and not adequately supported emission estimates for HAPs. The Draft Permit thenIndiana Gasification, LLC Page 79 of 122 Rockport, Indiana T 147

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compounds these errors by failing to reflect the emission calculations in enforceable permit limits. When properly estimated, potential emi ssions 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 l imits, the facility c ould 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 c ondition 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 H AP 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 C O 2 strea m is directed to the vent during the full year, with none to the pipeline (i.e., resulting in 6,430,000 tpy of CO 2 emissions from the AGR vent). In fact, the figures used are allowed only during year 2 of operation. Beginning in year three, the A GR vent will be allowed only 1,290,000 tpy of CO 2 , 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 contro lling 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 stre am is well controlled and will be assured to emit less than 9 tons/yr of the single la rgest 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 CO S 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% effect ive 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 C omment 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.4.11Indiana Gasification, LLC Page 80 of 122 Rockport, Indiana T 147

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Plantwide, all other HAP pollutants are emitted in very small amounts, to taling 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. for maldehyde 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.

C omment 2 8: THE TSD I NCORRECTLY 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 doc umented 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 e mergency 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, ope ration 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 2 8: 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 emis sions 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 op erate 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)

. T he use of the natural ga s 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, H 2 , CO 2 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 depressurizat ion during planned shutdowns. The total quantity of the se gases vented to the flare is very small. Also, these flared gases, are products of the gasification process and are predominantly CO, CO 2 and H 2 . These compounds would combust in a flare extremely cleanly, with negligible HAP formation.Indiana Gasification, LLC Page 81 of 122 Rockport, Indiana T 147

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Neverthel ess, 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 f actors, 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 flar e operating 8760 hours a year. The acid gas fla re 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 d iesel 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.

Th e emission calculations for all three sources described above are set out in the attached tables in 30464 ATSD

- Appendix A

.
Comment 2 9: 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 me rcury emission factor came from . Thus, IDEM significantly underestimated the HAPs PTE.

Response 2 9: 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 i n very small quantities . While natural gas contains some light hydrocarbons that remain from the separation of liquids and gases during its extraction and produ ction, the methane in SNG is chemically built from CO, H 2 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 comparis on. 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 i n 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 synga s before methanation (the process that converts it to SNG). Average reported mercury levels in Indiana coal is about 1/4 th the assumed level. Therefore, the mercury emissions estimate is conservative.Indiana Gasification, LLC Page 82 of 122 Rockport, Indiana T 147

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Comment 3 0: IDEM FAILED TO CONSIDER SSM WHEN CALCULA TING 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 3 0: As explained in the response to S ierra 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 so urce 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 imple mentation 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. . . .”).

Comm ent 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 com bustion 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 d evices, 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 comm enter cites three references. The first two references (footnotes 11 and 12) address emis sions from gas

- fired turbines. The proposed IG facility does not have any combustion turbines and, from an emissions perspective, they are very differ en t 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 comb ustion 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 h ave 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 int erest 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 calculateIndiana Gasification, LLC Page 83 of 122 Rockport, Indiana T 147

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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 : Considerin g 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 sour ce 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 bee n 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”), Chapt ers 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 explai ned in r esponse 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 contain s 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 character istics 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 compone nts that affect the combustion process and the formation of pollutants.

Response 34 : As discussed in r esponse 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 S NG 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 sy ngas and the syngas into SNG. These gas treatment and processing steps include water washing, acid gas removal, carbon adsorption and catalytic conversion.

All t hese 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 metallicIndiana Gasification, LLC Page 84 of 122 Rockport, Indiana T 147

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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 synga s 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 n atural 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 high er 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,

cu mulatively, 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 whic h affect the combustion process and the formation of combustion products including HAPs.

Response 35 : The SNG is being produced and sol d into the natural gas market. Therefore, it has to meet the same quality requirements that any natural gas producer mu st meet befo re 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 mos t 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 95 th 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 95 th upper percentile emission factor may be more appropriate to

us e [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.Indiana Gasification, LLC Page 85 of 122 Rockport, Indiana T 147

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The Envir onmental 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 t hat 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 efficienc ies, 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, howev er, 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 t hat 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 per formance 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 i n 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 tha t 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 cre ation 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 relian ce 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 Per mit 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 i s 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 contemplate s 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 Fa ctors, 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

sour cewide 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 evaluat ing 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 areIndiana Gasification, LLC Page 86 of 122 Rockport, Indiana T 147

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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 amount s 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 q uality 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.” I d. 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 p oints raised by Commenters overall about AP

- 42 are unpersuasive. It is noted that t his 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

- 4 2 factors. Therefore, use of these factors is conservative in that regard. Also, the C ommenter ’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 t his project has no gas combustion turbines

– t he 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, estimat ed 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 estimat e 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 chl oride (“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 emiss ion factors were not deemed equally applicable to combustion of SNG at the IG facility andIndiana Gasification, LLC Page 87 of 122 Rockport, Indiana T 147

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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 gasifi ed 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 fl aring 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 gasif ier. 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 synga s 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 p roject 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 pres ented in the references used by this commenter.

Comment 3 8: 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

a pplicable to combustion of SNG at the IG and instead zero emissions were assumed for combustion of these gases.

Response 3 8: The SNG is chemically derived from reactions of H 2 , CO and water and those reactions do not produce the organic HAPs listed by t he 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 repre sentative 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 th e total using the factors for natural gas is actually greater than those attributed to SNG in the Kentucky New Gas documentation.Indiana Gasification, LLC Page 88 of 122 Rockport, Indiana T 147

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Comment 3 9: 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 o f 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 t o 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. T he draft Permit does not meet that standard, so IG cannot deem this facility a synthetic minor source.

Response 3 9: See Response to Sierra Club Comment 27.

Comment 4 0: 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 malf unctions as the stack test is p e r formed only at steady sta te 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 4 0: As indicated in the Respon se 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’ emissio ns. 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 4 1: HYDROCARBON FLARE

The TSD claims that ma ssive SO 2 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 sec ond 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 valv e to the syngas hydrocarbon flare is completely closed.”

Response 4 1: The proposed permit includes requirements sufficient to ensure compliance with the startup SO 2 limit in Condition D.2.4(3)A. The permittee must use only methanol duringIndiana Gasification, LLC Page 89 of 122 Rockport, Indiana T 147

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startup conditions requiring flaring

-- D.2.4(3)A. The permit tee 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 fla ring

– 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 4 2: Also, the TSD assumes maximum emission of 0.70 lb/hr SO 2 from the flare except during certain startup and shutdown events. Thus, the per mit needs a condition limiting SO 2 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 4 2: The emissions estimate for the hydrocarbon flare of 0.70 lb/hr SO 2 s et 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 r equiring flaring

-- D.2.4(3)A. Outside of startups and shutdowns, in normal operation the only emissi ons 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 a mounts, 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 un its. 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).

Th e following changes have been made to the permit :

D.2. 6 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 H ydrocarbon Flare is in operation and at least one gasifier is in operation or in startup or shut down. 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, t he flare must be operated with a flame present at all times when the Acid Ga s Flare , identified as EU

- 00 2 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 4 3: The draft permit uses emission factors to de termine compliance with the SO 2 emission limits during startup and shutdown. See Draft permit at page 59. The draft permit has absolutely no compliance mechanism at all for SO 2 emissions from the hydrocarbon flare for times other than startup and shutdown . Id.Indiana Gasification, LLC Page 90 of 122 Rockport, Indiana T 147

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Response 4 3: 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 opera tion 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 gasif ier startup requiring flaring, t he routing of gas whenever a gasifier is depressurized during a planned gasifier shutdown

, and t he operating rate of each gasifier prior to and during a planned shutdown of a gas treatment train

. See Condition D.2.9(e). Co ndition 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, t he Permittee sh all 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 4 4 : The draft permit must have monitoring for SO 2 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

- 716 57, 08

- 72642 (9 TH 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 ad equate 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 (9 th Cir. 2012), arises out of SO 2 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 facilit y. 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 SO 2 emissions will be negligible due to the startup feedstock required. The emission factor us ed to calculate SO 2 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, SO 2 emissions will be very low due to t he strict requirements for shutdown operations. The emission factor used to calculate SO 2 emissions during shutdown is 0.001264 lb SO 2 /scf. This sulfur content is calculated based on the conservativeIndiana Gasification, LLC Page 91 of 122 Rockport, Indiana T 147

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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 com pounds covert into SO 2 emissions when combusted in the flare. Actual sulfur content and SO 2 emissions per cubic foot of syngas flared should be no more than this conservative assumptio n, 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, SO 2 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 SO 2 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 t o Sierra Club Comment 42.

Comment 4 5: 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 significantl y 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 lo wer operating temperature will increase emissions of VOCs and aldehydes. This problem could be solved by adopting our recommendation to establish an operating range.

Response 4 5 : The primary purpose of the AGR thermal oxidizer is to pr ovide thermal destr uction 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, I G’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 ab ove 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 corr esponding emission limits. The stack test will determine the three

hour 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 av eraging would necessarily require operation of the unit consistently above thatIndiana Gasification, LLC Page 92 of 122 Rockport, Indiana T 147

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level, resulting in th e wasted fuel addressed above. Therefore, IDEM determined that maintaining the units’ three

- hour average temperature at or above the three

- hour average te mperature 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 tem perature falls below that observed during the most recent compliant stack test.

Comment 4 7 : The gasifier preheat burners do not have monitoring requirements: There are five proposed natural gas

- fired and SNG fuel

- fired gasifier preheat burners, emi ssion 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 expl ain

so.

Response 4 7 : IDEM has already conducted a top

- down BACT analysis for all the emi ssions in the gasifier preheat burners as included in Appendix B of the Technical Support Document. The control technologies evaluated for the gasifier preheat burne rs are as follows:

PM, PM 10 and PM 2.5 (1) Mechanical Collectors (such as Cyclones or Multiclones); ( 2 ) Wet Scrubbers; ( 3 ) Electrostatic P recipitators (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 (SO 2 ) ( 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/ Prehea t Startup Burners for all the polluta nts

. 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.Indiana Gasification, LLC Page 93 of 122 Rockport, Indiana T 147

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The burners fire into the gasifiers whic h 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 4 8: Emission Unit EU

- 012A does not have compliance demonstration testing requirements Feedst ock 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 suppressi on 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

— whi ch 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 bagho use. 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 w ith 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.

Re sponse 4 8 : IDEM has inadventently includ e d 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 Condition s D.1.4( b 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

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 St ackers to the Pile (EU

- 012N

- O) to determine compliance with the PM, PM 10 , and PM 2.5 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 vali d 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, PM 10 and PM 2.5 Control and Condition D.1.12

- Record Keeping Requirement s of the permit.Indiana Gasification, LLC Page 94 of 122 Rockport, Indiana T 147

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Comment 5 0: Emission Unit EU

- 012Z do es 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 parti culate 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 o utlet concentrations for PM, PM 10 , and PM 2.5 . 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 5 0 : IDEM inadvertently omitted one of the truck stations unloading to a truck hopper

, identified as EU

- 012Z and its conditions from the permit. Th ere are three (3 ) truck stations unloading to a truck hop pers 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 permi t

.

D.1.4 PM, PM 10 and PM 2.5 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)), t he Best Available Control Technologies (BACT) for the Incoming Solid feedstock material handling and the Process area solid feedstock conveying storage, identified as EU

- 011 A /B and EU

- 012A

- AC shall be as follows:

.......................................... .................................................................................................................. (k) The PM, PM 10 and PM 2.5 emissions from the Truck/rail conveyor transfer tower (EU

012Y); truck stations unloading to a truck hopper (EU

- 01 2 Z , AB

, - and AC); and truck hopper unloading to the conveyor Belts (EU

- 012AA) operation shall be limited as follows:

............................................................................................................................. ............ ...................

Comment 5 1: COMPRESSOR FOR CO 2 : Presumably the CO 2 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 pip eline would need a compressor. The co mpressor 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 el ectric.

Response 5 1 : With respect to the assertion that a permit condition is necessary to require the shipment of CO 2 by pipeline, see Responses to Public Comments 7 and 10 . The facility is designed to deliver at least 80% of the high

- purity CO 2 manu factured 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 compresso r, 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 electri c 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 C

012S. Draft Permit at page 2 of 6. IDEM cannot permit hypothetical or alternativeIndiana Gasification, LLC Page 95 of 122 Rockport, Indiana T 147

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- 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 t op

- d own 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 th e 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).

Th e 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 hum an 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 ambien t 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 variabl es 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 val ues 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.Indiana Gasification, LLC Page 96 of 122 Rockport, Indiana T 147

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Comment 5 4: 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/m 2

. There are several reasons why this value is ina ccurate and understates the true silt loading value.

Response 5 4: 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/m 2 . The commenter suggests that this number is too low (and instead suggests in Sierra Club Comment 58 that it should be 9.7 g/m 2 (Steel/Iron Production mean silt from AP

- 42 table 13.2.1

- 3)). However, the value of 1.0 g/m 2 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 n ot 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 sho ws their use of similar, but even lower silt loading factors for paved roadways.

• Duke Edwardsport IGCC project assumed 0.4 g/m 2 for their silt factor for paved roads;

• Cash Creek Generation SNG/NGCC permit in Kentucky used 0.4 g/m 2 ; and

• KY Newgas used 0.6 g/m 2 for their paved roadway calculations.

The use of 1.0 g/m 2 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/m 2 to 0.6 g/m 2 . The proposed IG silt factor of 1.0 g/m 2 is higher (more conservative) than any of these numbers. While the roads within the faci lity 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 co ntents 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 in dustries listed, a wide range of silt loadings are presented

– without guidance on how to use that information.Indiana Gasification, LLC Page 97 of 122 Rockport, Indiana T 147

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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 t o 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 Ta ble 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 val ues 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 PM 10 / PM 2.5 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 c onsistent with tests from the better/lower end of the range of the industrial data available.

Comment 5 5: 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 th at the silt load upon which any final permit is based is complied with in reality.

Response 5 5: The silt factor assumed in the estimation of fugitive dust from paved roadways is considered reasonable and conservative as discussed in response to Sierr a 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 re quired of the three gasification plants listed in response to Sierra Club Comment 54 which assumed an

eve n 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 5 6: 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 indust rial 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/m 2 . AP

- 42 Sec. 13.2.1

- 4, Table 13.2.1

- 4.Indiana Gasification, LLC Page 98 of 122 Rockport, Indiana T 147

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Response 5 6: AP42 does not “rec ommend” 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 5 7: The chose n 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 5 7: See response to Sierra Club Comment 54.

Comment 5 8: IDEM used a silt loading value of 1 g/m 2 , 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/m 2 , 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 o f 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 PM 10 and 1.759 tpy of PM 2.5 , an increase of more than an order of magni tude. If the upper end of the industrial road range of 292 g/m 2 is used, which is appropriate for a potential to emit calculation, the emissions increase hugely to 159 tpy of PM 10 and 39 tpy of PM 2.5 . Response 5 8: 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 c haracterizing 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 5 9: In no event is there any justi fication for the use of IDEM’s 1 g/m 2 , which is well below the bottom of the range given in AP

- 42. IDEM offers no data to support its 1 g/m 2 value. The TSD does say this is reasonably considering the control achieved through road watering. However, setti ng 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 r oad watering and then also set a high control factor based on road watering. There is actually no justification for either.

Response 5 9: A detailed explanation of the basis for the selection of 1 g/m2 silt loading factor is provided in response to Sie rra 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 t o 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 6 0: 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 ar eas 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,Indiana Gasification, LLC Page 99 of 122 Rockport, Indiana T 147

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meaning that t he 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/m 2 .” Id.

Response 6 0: AP42 does mention that h igher 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 Minne sota 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 muc h milder winters than Colorado or Minnesota, salt is the com mon 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. N ote 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 6 1: 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 disreg arded AP

- 42’s recommendation that it do so.

Response 6 1: See response to Sierra Club Comment 60.

Comment 6 2: 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. Applicati on 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 6 2: The commenter has suggested that since there are unpaved areas at the IG facil ity, 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.Indiana Gasification, LLC Page 100 of 122 Rockport, Indiana T 147

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AP42 does suggest an adjustment to the PM emiss ions 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 estima ted 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 cons truction 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 e ffects 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 r easons, 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 6 3: I t 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 int ended vehicle traffic, we conclude that IDEM simply ignored the silt loading contribution from mud and dirt trackout.

Response 6 3: There is no routine reason for the bull dozers used to manage the stockpiles to travel or cause “track

- out” on paved roadwa ys. 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 6 4: The vehicle miles traveled calculation is unsupported and likely too small IDEM ha s 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 se lling sulfuric acid and arg on. 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 genera l 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 part iculate emissions calculation is inadequate.

Response 6 4: 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 fi lter cake, cooling tower chemicals, glycol, and trash.Indiana Gasification, LLC Page 101 of 122 Rockport, Indiana T 147

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The last of these categories was included to address other miscellaneous trucking activitie s mentioned by the commenter. T his 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.

T he 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 in stead 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 offsit e 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 6 5: The draft permit does not have enforceable conditions which lead to 90%

c on trol efficiency

The TSD emission calculations of fugitive PM, PM 10 and PM 2.5 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 on ly 0.53 tons/yr. Because of the very small amount of emission, no formal controls are proposed beyon d just good housekeeping, i.e.: cleaning off the roadways of any material spilled or other road cleaning if visible emissions are observed.

BACT for PM 10 i s 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 bee n properly calculated.

Response 6 5: 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 c ontrols 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 6 6: IDEM assumes these “good housekeeping” practices will achieve a 9 0% control factor

— “the highest specified in the [RACT/BACT/LAER Clearinghouse] for such sources.” TSD at pdf p. 774.

Response 6 6: See response to Sierra Club comment 6 7

.

Comment 6 7: IDEM has not adequately explained how it arrived at a control factor o f 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 a t the time of the scheduled treatment,Indiana Gasification, LLC Page 102 of 122 Rockport, Indiana T 147

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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 southwe st 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 o r 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 6 7: Even uncontrolled p aved roadway dust emissions are very sm all. Uncontrolled

, the emissions from paved haul roads are conservatively estimated to be no more than 1.3 tons/yr PM 10 , and 0.3 tons/yr PM 2.5 before control. With controls, emissions are 0.13 tons/yr PM 10 and 0.03 tons/yr PM 2.5 . 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 Fuel s 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 i s belo w 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, i n the originally proposed permit conditions, wet suppres sion 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 le ss 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 usin g 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.Indiana Gasification, LLC Page 103 of 122 Rockport, Indiana T 147

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• A review of past temperature data for the area (Evansville Met data for 2006

- 2009) shows tha t 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 (whic h 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 temper atures.

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 discusse d 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 roadw ay 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 sub

freezing 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, PM 10 and PM 2.5 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 32 o F at the time of a scheduled wet suppressionIndiana Gasification, LLC Page 104 of 122 Rockport, Indiana T 147

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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 act ive 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 i s 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))

W here: Control Efficiency = percent control efficiency T = Daily truck trips on roadway (truck trips/calendar day) C = Number of Wet Suppression roadway dust control treatments per calendar day (watering events / calendar day)

For the purposes of this formu la, 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 s hall 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 sh all maintain an ambient temperature monitor when ambient temperatures may drop below 32 o F.

Record Keeping and Reporting Requirements [326 IAC 2

- 7

- 5(3)] [326 IAC 2

- 7

- 19]

D.12. 6 7 Record Keeping Requirements To document the compliance status with Condition s D.12.4

- PM, PM 10 and PM 2.5 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 6 8: Even IDEM’s own formula for calculating control efficiency demonstrates th at this figure is

unrea listic. The formula is:

Control Efficiency = 96

– (0.263*(T/C) Where: T = daily truck trips; C = Number of wet suppression treatments per day.Indiana Gasification, LLC Page 105 of 122 Rockport, Indiana T 147

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- 00060 Permit Reviewer: Josiah Balogun 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 we t 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 6 8: 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 6 9: Bulldozer controls are over estimated 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 bull dozers are just as inadequate as those for the haul roads. Draft permit at pdf p. 58.

Response 6 9 : 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.1 3.4, 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 . A ggregate 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. B elow is revised language for those and related conditions . This language narrows the provision that allow s 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 doz er 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

.Indiana Gasification, LLC Page 106 of 122 Rockport, Indiana T 147

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D.1.6 PM, PM 10 and PM 2.5 Control [326 IAC 2

- 7

- 6(6)]

..................................... ...................................................................................................................... (d) In order t o ensure compliance with Condition s D.1.4(i) and (j)

, wet suppression using water sprays shall be used daily on active area s 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 whe n ever :

- 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 32 o F degrees

, or forecast to be so within the next 24 hours,

- The s ubject Dozer activity area s 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 compl iance status with Conditions D.1.6(c) an d (d) , the Permittee shall maintain an ambient temperature monitor when ambient temperatures may drop below 32 o F.

D.1.1 2 3 Record Keeping Requirement s

............................................. ............................................................................................................... (d ) To document the compliance status with Condition s D.1.4(b)

- PM, PM 10 and PM 2.5 PSD BACT and D.1.6(c)

- PM, PM 10 and PM 2.5 Control , the per mittee 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 unload ing 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 Condition s D.1.4(i), and (j)

- PM, PM 10 and PM 2.5 PSD BACT and D.1.6( d )

- PM, PM 10 and PM 2.5 Control

, the Permittee shall maintain the following daily record s :

- 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 wa ter. recent rainfall, snow, etc.

............................................................................................................................. ...............................Indiana Gasification, LLC Page 1 07 of 122 Rockport, Indiana T 147

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D.13.5 Compliance Determination Requirements To demonstrate compliance status with Condition D.13.4

- PM, PM 10 and PM 2.5 PSD BACT, w et suppression shall be applied weekly to the entire slag storage pile/pad. Dust control is aided by the f act that the in coming 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 when ever :

- Rainfall of 0.1 or m ore 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 t T here 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.1 3.5 , the Permittee shall maintain an ambient temperature monitor when ambient temperatures may drop below 32 o F.

Record Keeping and Reporting Requirements [326 I AC 2

- 7

- 5(3)] [326 IAC 2

- 7

- 19]

D.13. 6 7 Record Keeping Requirement To document the compliance status with Condition s D.13.4

- PM, PM 10 and PM 2.5 PSD BACT and D.13.5

– Compliance Determination Require ments, 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 do cumenting of the reason (i.e.: the ambient temperatu re, 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 7 0: Compliance Monitoring is no t 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 co ntinuous 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 So urce 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 monitori ng 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 mo nitoring and should be avoided when any other monitoring technique is feasible. IDEM proposesIndiana Gasification, LLC Page 108 of 122 Rockport, Indiana T 147

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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 mor e accurate monitoring techniques, or explain why other techniques are not feasible for each of these six units.

Response 7 0 : IDEM has appropriately evaluated the monitoring options for each emission unit. Generally, many emission units do have requirem ents 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 ar e 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 7 1: Parametric monitoring is inadequate Parame tric 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, EU

012V, EU

- 012Z, EU

- 012AB, EU

- 012AC, EU

- 012AA, EU

- 012Y, EU

- 012N, EU

- 012O, EU

012R, EU

- 012S, EU

- 011A, EU

- 011B, EU

- 001, EU

- 002, EU

- 015A, EU

- 015B, EU

- 032, EU

024, EU

- 025, EU

- 033)

. IDEM should follow EPA’s complia nce monitoring hierarchy and require continuous direct monitoring or initial and periodic direct monitoring where feasible for these 34 emissions units.

Response 7 1 : IDEM requires either direct emissions measurement or parametric monitoring for all emissi on 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 opti ons. 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 becau se 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 limit s at this source. Furt her more , 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 7 2: 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 Sulfuri c 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.Indiana Gasification, LLC Page 109 of 122 Rockport, Indiana T 147

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Response 7 2: 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 monitorin g 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 the n 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 comm ent. See also the response to Public Comment 29 regarding stack testing requirements for the auxiliary boilers.

Comment 7 3: 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 magnit ude. At a minimum, the permit should be revised to require a Method 9 test once a day during maximum operations.

Response 7 3: All of the BACT limits are numerical limits subject to stack testing to determine compliance, as already required by the permi t. 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 requir ements 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 observat ions 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 v isible emissions m onitoring 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, th e 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 requi rements are sufficient enough for the source to comply with the limit given in the permit.Indiana Gasification, LLC Page 110 of 122 Rockport, Indiana T 147

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Comment 7 4: Second, the permit does not require that a relationship be established between visible emissions and the underlying PM/PM10 emission rates. Many of th e emissions units monitored via visible emissions notations have v ery 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 te chnique.

Response 7 4 : 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 no tations 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 vis ible 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 whe n their emissions were established or tested.

Comment 7 5 : 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 e quivalent to certification in Method 9.

Response 7 5: 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 7 6: 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 7 6: 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 t aken 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 7 7: 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 7 7: The proper and accurate visible emission notation can only be taken during daylight. Any reading during non

- daylight hours wi ll 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 7 8 : 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 cau se of the flaring event. Flare best practices require operation with no visible emissions, operationIndiana Gasification, LLC Page 111 of 122 Rockport, Indiana T 147

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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

s ource “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 7 8 : 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 cont rol 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 wi th 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 expe cted 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 shu tdowns.” 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 malfunc tion 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 ap propriate 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.Indiana Gasification, LLC Page 112 of 122 Rockport, Indiana T 147

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## Footnote Comments

Com ment 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 un it, 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 e mission 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 larg er 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 determi ned 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

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- 00060 . (deleted language appea rs 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 r esulted in changes to the rule c it ations listed in the permit. These changes are not chan ges to the underlining provisions. The change is only to c it ations 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 IA C 2

- 7

- 5( 14) (15) ]

***Indiana Gasification, LLC Page 113 of 122 Rockport, Indiana T 147

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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 pri or 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) . T he 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( 11 12 )] [40 CFR 68]

***

Change 2 : IDEM has moved to separate CAM language for Section C

- compliance monitoring, REE, and reporting. Th is language is mainly verbatim from the CAM rule and is to clarify the Permitt ee'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 requi rements 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 m onitoring 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 Enforcem ent Branch, Office of Air Quality 100 North Senate Avenue MC 6 1

- 53 IGCN 1003 Indianapolis, Indiana 4620 4

- 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.Indiana Gasification, LLC Page 114 of 122 Rockport, Indiana T 147

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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 fo r 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

m onitoring, 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 assuranc e 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 pollut ant

- 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 fulfi lling 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 su dden, 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 limitat ion in this permit:

............................................................................................................................. ............. (II) (a) CAM Response to excursions or exceedances. (1) Upon detecting an excursion or exc eedance, 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 wi th 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 recurr ence 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 t hrough 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

.Indiana Gasification, LLC Page 115 of 122 Rockport, Indiana T 147

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- 00060 Permit Reviewer: Josiah Balogun
(2) Determi nation 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 pro mptly 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 designate d 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 existi ng 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 monitori ng data, monitor performance data, corrective actions taken, any written qualityIndiana Gasification, LLC Page 116 of 122 Rockport, Indiana T 147

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- 00060 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 inform ation 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 Permitt ee'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 th e 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. The se revisions included the incorporation of the U.S. EPA's definition of reasonable possi bility. The permit previously c ited to the EPA definition. Also, the revisions res ulted in changes to other rule c ites listed in the permit. And IDEM, OAQ has clarif ied 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, measur ement, repor t, or application. Support information includes the following: (AA) All calibration and maintenance records. (BB) All original strip chart recor dings 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) T he 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 loc ation 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 reco rds to the Commissioner within a reasonable time.

............................................................................................................................. .......................Indiana Gasification, LLC Page 117 of 122 Rockport, Indiana T 147

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- 00060 Permit Reviewer: Josiah Balogun
(c) If there is a reasonable possibility (as defined in 4 0 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 beginnin g 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 un it 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) Bas eline 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 a ny 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 de viation 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 sha ll 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 de fined 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.Indiana Gasification, LLC Page 118 of 122 Rockport, Indiana T 147

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- 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 app licable:

(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 (includin g 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 si milar 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 .1 5 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 immed iately 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 Z LD

- 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.Indiana Gasification, LLC Page 119 of 122 Rockport, Indiana T 147

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- 00060 Permit Reviewer: Josiah Balogun

............................................................................................................................. .............. .......... 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 e mission 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

- elect rical 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 suppl ying 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 determination s set forth in Section D of this permit, the IDEM, OAQ has made the following determination s regarding this source.

.............................. ................................................................................................................. (4) 40 CFR 60, Subpart Da

- Standards of Performance for Electric Utility Steam Generating Units for which Construction is Commenced after Sep tember 18, 1978:

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

electrical output to any utility power distri bution system for sale.Indiana Gasification, LLC Page 120 of 122 Rockport, Indiana T 147

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( 11 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. P ursuant 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 o r 219,000 MW

- hours (25 MW), whichever is greater, to any utility power distribution system for sale.

( 12 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 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. 9 10 Record Keeping Requirements

............................................................................................................................. ................. (c) To doc ument 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.

( d c ) To document the compliance status with Condition D .2.4, the Permi ttee 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.4.2 3 4 Record Keeping Requirements (a) In order to document the compliance status wi th Condition s D. 4.4

- PM, PM 10 and PM 2.5 PSD BACT, D.4.6

– SO 2 PSD BACT, D.4.9

- GHGs PSD BACT, D.4.13

– Compliance Determination Requirements PM, PM 10 , and PM 2.5 Calculations , D.4.15

– Sulfur Dioxide Control and Calculations , and D.4.16

– Compliance Deter mination 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 Co ndition 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

- SO 2 PSD BACT , D.8.7

– NOx PSD BACT , and D.8.8(a)

- GHGs PSD BAC T, the Permittee shall only use natural gas or SNG in the ZLD

- Spray Dryer (EU

- 032).Indiana Gasification, LLC Page 121 of 122 Rockport, Indiana T 147

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- 00060 Permit Reviewer: Josiah Balogun
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 t otal HAP from the syngas hydrocarbon flare identified as EU

- 001 shall be limited by c ompliance with the SO 2 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 lim it 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(1 4 )] 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 fa cility and railcar unloading facility to storage piles and day bins, consisting of: [Under 40 CFR 60, Subpart Y, the i ncoming solid feedstock materials handling system, transferring material from the barge unloading facility and railcar unloading facili ty to storage piles and day bins are new affected source s .]

(1) One (1) barge unloading to hopper transfer point, to be permitted in 201 2

, nominally rated at 750 tons per hour, identified as EU

- 012A, with particulate emissions controlled by wet suppressio n.

............................................................................................................................. ....................... (E) Two (2) Acid Gas Removal (AGR) Unit vents, identified as EU

- 007A and EU

- 007B, to be permitted in 20 1 2 , with methanol, H 2 S, 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 fu el input, exhausting through two (2 ) stack, identif ied as S

- 007 A and S

- 007B

. (F) Two (2) Wet Sulfuric Acid (WSA) plant trains, each nominally rated at 800 stpd H 2 SO 4 and identified as EU

- 015A and EU

- 015B, to be permitted in 2012, with NO x , SO 2 , H 2 SO 4 emissions controlled by two (2) selective catalytic red uction (SCR) systems identified as C

- 015

- 1A and C

- 015

- 1B, respectively, and particulate, H 2 SO 4 , and SO 2 emissions controlled by two (2) hydrogen peroxide scrubbers identified as C

- 015

- 2A and C

- 015

- 2B, respectively, and particulate and H 2 SO 4 emissions contr olled 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, vent ing through the same stacks.

............................................................................................................................. ........................... (I) One (1) ZLD

- Spray Dryer, to be permitted in 201 2 , 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.Indiana Gasification, LLC Page 122 of 122 Rockport, Indiana T 147

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Change 1 1 : A reporting f orm 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 Re port

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) conse cutive month period with compliance determined at the end of each month.

QUARTER : YEAR:

Month Column 1 Column 2 Column 1 + Column 2

This Month Previ ous 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 uni t 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 (007A

B) 17.00 Gasifier Preheat Burners (008A

E) 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) 0Wet 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) 0Plant Haul Roads (FUGROAD) 0Electric 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 ePage 1 of 2 ATSD Appx AEstimated HAP Emissions From Emergency Diesel Engines (Emergency Generators EU# 009A/B, Fire Water Pump Engine EU 010A/B/C)EU# Emissions UnitHAPs (TPY)009A Emergency Diesel Power Generator A 1,341 HP 52 hr/yr 1.10E-05 lb/hp-hr 0.00038009B Emergency Diesel Power Generator B 1,341 HP 52 hr/yr 1.10E-05 lb/hp-hr 0.00038010A Fire Water Diesel Pump A 575 HP 52 hr/yr 2.71E-05 lb/hp-hr 0.00041010B 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/yr2.71E-05 lb/hp-hr0.00041Total HAPs 0.00198These 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 3.3-2HAP HAPBenzene 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/mmBtuPh th4 08E 05lb/ BtFl2 92E 05lb/ BtRating Frequency - Limited by Permit Emission FactorFactor FactorPhenanthrene4.08E-05lb/mmBtuFluorene2.92E-05lb/mmBtuAnthracene 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/mmBtuTotal 1.57E-03 lb/mmBtu Benzo(g,h,l)perylene 4.89E-07 lb/mmBtuTotal in different units 1.10E-05 lb/hr-hr Total 3.87E-03 lb/mmBtu2.71E-05 lb/hr-hrConversion Factor 7,000 Btu/hp-hrAP-42 Section 3.3 Table 3.3-1 reference a & Section 3.4 Table 3.4-1 reference eFLARE 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/h r CO DRE 0 %

Average Maximum Annual Emissions Emissions Emissions Pollutan t lb-mol/h r lb-mol/h r lb-mol/h r Mol % lb/h r lb/h r TPY PM

10 -- -- -- -- 6.42 6.42 28.12
PM

2.5 0.09 0.09 0.41 SO

2 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/h r A P-42 Heating Value = 1,020 Btu/sc f

Average Maximum Annual Emissions Emissions Emissions Pollutan t lb/h r lb/h r TPY PM

10 0.0020 0.0020 0.0087
PM

2.5 0.0019 0.0019 0.0081
SO

2 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 PM

10 6.422 6.42 28.13
PM

2.5 0.095 0.09 0.41
SO

2 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 2/10 0 Emissions (NOx, PM 10

, 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) A verage 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/f t 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) A verage Emissions (lb/hr) = Maximum Emissions.

NOx PM 10 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 PM

10 SO 2 7.600 0.60

NO

x 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/y r 513.9 A verage Maximum A nnual Emission s Emission s Emission s Pollutan t lb/even t lb/h r TPY PM

10 0.260 0.09 0.002
PM

2.5 0.260 0.09 0.002
SO

2 255.62 85.21 1.917 NO

x 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/h r TPY MT/yr CO2 for Gasifier Flare = 185

, 818.1 813

, 883.3 738354.9

Equation Y-5

N 2

O = Annual nitrous oxide emissions from flared gas (metric ton N 2 O/year)
CO 2 = Emission rate of CO 2 from flared gas calculated (metric ton/year)
EmF N2O = Default N 2 O emission factor for “Petroleum Products” from Table C-2 of subpart C (General Stationary Fuel Combustion Sources) (kg N 2 O/MMBtu) = 0.0006 EmF = Default CO 2 emission factor for flare gas of 60 kg CO 2 /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 ba lance 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 PM 10 for Syngas are based on values from vendor supplied data. VOC for Syngas = 2% of AP-42 Section 1.4 "Natural Gas Combustion" Ta ble 1.4-2

Scenario 2 Factor (lb/MMscf)CO2 = 123.2 MT Page 3 of 3 ATSD App A

Equation C-9a

CH 4

or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons) Fuel = Mass or volume of the fuel combusted during the reporting yea r 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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.

Pilo

t

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 CO2Hydrocarbon / Gasifier Startup FlareFLARE 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/h r CO DRE 99.5 %

Average Maximum Annual Emissions Emissions Emissions Pollutan t lb-mol/h r lb-mol/h r lb-mol/h r Mol % lb/h r lb/h r TPY PM

10 -- -- -- -- 6.42 6.42 0.43
PM

2.5 6.02 6.02 0.41 SO

2 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/h r A P-42 Heating Value = 1,020 Btu/sc f

Average Maximum Annual Emissions Emissions Emissions Pollutan t lb/h r lb/h r TPY PM

10 0.0020 0.0020 0.0087
PM

2.5 0.0019 0.0019 0.0081
SO

2 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 PM

10 0.101 6.42 0.44
PM

2.5 0.095 6.02 0.41
SO

2 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 2/10 0 Emissions (NOx, PM 10

, 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) A verage 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/f t 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) A verage Emissions (lb/hr) = Maximum Emissions.

NOx PM 10 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 PM

10 SO 2 7.600 0.60

NO

x 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 A verage Maximum A nnual Emission s Emission s Emission s Pollutan t lb/even t lb/h r TPY PM

10 0.260 0.09 0.002
PM

2.5 0.260 0.09 0.002
SO

2 255.62 85.21 1.917 NO

x 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/h r TPY MT/yr CO2 for Gasifier Flare = 185

, 818.1 12

, 542.7 11378.8

Equation Y-5

N 2

O = Annual nitrous oxide emissions from flared gas (metric ton N 2 O/year)
CO 2 = Emission rate of CO 2 from flared gas calculated (metric ton/year)
EmF N2O = Default N 2 O emission factor for “Petroleum Products” from Table C-2 of subpart C (General Stationary Fuel Combustion Sources) (kg N 2 O/MMBtu) = 0.0006 EmF = Default CO 2 emission factor for flare gas of 60 kg CO 2 /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 ba lance 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 PM 10 for Syngas are based on values from vendor supplied data. VOC for Syngas = 2% of AP-42 Section 1.4 "Natural Gas Combustion" Ta ble 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

CH 4

or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons) Fuel = Mass or volume of the fuel combusted during the reporting yea r 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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.

Pilo

t

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 CO2Hydrocarbon / Gasifier Startup FlareHydrocarbon Flare Shutdown Emissions HAP CalculationsPage 1 of 2 ATSD Appx AEmission 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 ShutdownsHAP2-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 FactorFactor Basis of FactorHAPs factors for Syngas Flaring during Shutdowns (Continued) Page 2 of 2 ATSD Appx AHAPHydrochloric Acid18.85E-03 lb/mmBtu Note 1Arsenic21.60E-06 lb/mmBtu Note 2Beryllium21.80E-07 lb/mmBtu Note 2Cadmium22.20E-07 lb/mmBtu Note 2Chromium21.00E-06 lb/mmBtu Note 2Cobalt28.24E-08 lb/mmBtu Note 2Manganese21.10E-06 lb/mmBtu Note 2Mercury31.71E-04 lb/mmBtu Note 3Nickel21.10E-06 lb/mmBtu Note 2Selenium21.50E-06 lb/mmBtu Note 2Lead24.00E-06 lb/mmBtu Note 2Total HAPs for Syngas combustion 1.09E-02 lb/mmBtuShutdown 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 perNote 2 - Metal HAP factors (except mercury) are from Proposed Duke Edwardsport IGCC ,Factor Basis of FactorPage 1 of 2 ATSD Appx AFugitive Emissions: Additional HAP Calculations for Emiss. Unit FUG and FUG-WSAHCl1HAP Conc%v lb/hr/component lb/hr % lb/hr TPYValves 270 0.0010% 0.0089 0.00002 0 0.00002 0.0001Flanges 650 0.0010% 0.0029 0.00002 0 0.00002 0.0001Compressor Seals 0 0.0010% 0.5027 0 0 0 0Pump Seals 0 0.0010% 0.0386 0 0 0 0Relief Valves 36 0.0010% 0.2293 0.00008 0 0.0001 0.0004Sample Connections 8 0.0010%0.0330.000003 0 0.000003 0.00001Total HAPs0.0001 0.001Fugitve 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 TPYValves 270 0.000004% 0.0089 0.0000001 0 0.0000001 0.0000004Flanges 650 0.000004% 0.0029 0.0000001 0 0.0000001 0.0000003Compressor Seals 0 0.000004% 0.5027 0 0 0 0Pump Seals 0 0.000004% 0.0386 0 0 0 0Relief Valves 36 0.000004% 0.2293 0.0000003 0 0.0000003 0.000001Sample Connections 8 0.000004%0.0330.00000001 0 0.00000001 0.00000005Total HAPs0.000001 0.000002See next page for metalic hapSpecifically, the below caluclations quantify HAPs from syngas piping leaks of HCl and trace metals. Other HAPs present in Fugitive Leaksfrom Emission Unit FUG and FUG-WSA (e.g. Methanol, COS) are documented on a separate spreadsheet which was part of the originalIGApplication and IDEM's proposed TSD document.Fugitive SourceFugitive SourceControlled EmissionsControlled EmissionsComponentCountEmission FactorsUncontrolledEmissionsControlEfficiencyComponentCountEmission FactorsUncontrolledEmissionsControlEfficiencyPage 1 of 2 ATSD Appx AMetal HAPs factors for Fugitives leaks of SyngasHAPArsenic20.0000001% volume % Note 2Beryllium20.0000001% volume % Note 2Cadmium20.00000001% volume % Note 2Chromium20.0000001% volume % Note 2Cobalt20.00000001% volume % Note 2Manganese20.0000001% volume % Note 2Mercury30.000004% volume % Note 3Nickel20.0000001% volume % Note 2Selenium20.0000001% volume % Note 2Lead20.0000001% volume % Note 2Total 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 EdwardsportFactor Basis of FactorControl Efficiencies shown above of zero reflect the fact that the syngas piping is not subject to any control requirements (i.e.; LDAR isnot required.)

## Indiana Department of Environmental Management Office of Air Quality

Addendum to the Technical Support Document ( A TSD) Appendix B

– Public Comments List

Source Description and Location

Source Name: Indiana Gasification, LLC Source Location: CR 200 N a nd 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, I nc 800 Adams Avenue, Evansville IN 47713

Ben A. Taylor 419 Yelvi ngton

- 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 RosenbergIndiana 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 Ma rvin 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 Sisle y Steve McNamara Larry Herm Rick MckeeIndiana 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 CO 2 . 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 CO 2 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 wit h the Department of E nergy, which is intended to encourage advanced coal gasification facilities. As a re sult, 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 CO 2 . 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

SO 2 Better than national standards. CO Unclassifiable or attainment effective November 15, 1990. O 3 Unclassifiable or attainment effective June 15, 2004, for the 8-hour ozone standard. 1
PM 10 Unclassifiable effective November 15, 1990. NO 2 Cannot be classified or better than national standards. PM 2.5 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 applicabilit y relating to ozone. Spencer County has been designated as attainment or unclassifiable for ozone. Therefore, VOC and NOx emissions were reviewed pursuant to the r equirements for Prevention of Significant Deterioration (PSD), 326 IAC 2-2.

(b) PM 2.5 Spencer County has been classified as attainment for PM 2.5 . On May 8, 2008, U.S. EPA promulgated the requirements for Prevention of Significant Deterioration (PSD) for PM 2.5 emissions. These rules became effective on July 15, 2008. On May 4, 2011 the air pollution control board issued an emergency rule establishing the direct PM 2.5 significant level at ten (10) tons per year. This rule became effective, November 2, 2011. Therefore, direct PM 2.5 and SO 2 emissions were reviewed pursuant to the requirements for Prevention of Significant Deterioration (PSD), 326 IAC 2-2. See the State Rule Applicability – Entire Source section.

(c) Other Criteria Pollutants Spencer County has been classified as attainm ent 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-ei ght (28) listed source categories, as specified in 326 IAC 2-2, 326 IAC 2-3, or 326 IAC 2-7. Ther efore, fugitive emissions are counted toward the determination of PSD, Emission Offset, and Part 70 Permit applicability.

Description of New Source and Emission Un its with Control Equipment Summary

The Office of Air Quality (OAQ) has reviewed a Ne w Source Construction application, submitted by Indiana Gasification, LLC on April 20, 2011, relati ng to the construction and operation of a state - of- the - art substitute natural gas ("SNG") and liquefied carbon dioxide ("CO 2 ") 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 CO 2 . 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 CO 2 that will be sold to third parties for use in Enhanced Oil Recovery (“EOR”) where it is esti mated 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 andC-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 transferringfeed 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 c apacity 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 pe rmitted 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 nomina lly 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 v ents, identified as EU-007A and EU-007B, to be permitted in 2012, with methanol, H 2 S, COS, and CO emissions controlled by two (2) regenerative thermal oxidizers (RTO) ident ified as C-007A and C-007B, respectively, each nominally rated at 38.8 MMBtu/hr HHV f uel 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 H 2 SO 4 and identified as EU-015A and EU-015B, to be permitted in 2012, with NO x , SO 2 , H 2 SO 4 emissions controlled by two (2) selective ca talytic reduction (SCR) systems identified as C-015-1A and C-015-1B, respectively, and tw o (2) hydrogen peroxide scrubbers identified as C-015-2A and C-015-2B, respectively, exhaus ting through two (2) stacks, identified asIndiana 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 emi ssions 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 NO x emissions controlled by ultra-low NO x 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 identif ied 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 controlledby a vapor recovery system and exhausting through one (1) vent, identified as S025. [40 CFR 60 Subpart Kb].

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

(L) Electrical Circuit Breakers (approximatel y six) containing sulfur hexafluoride (SF 6 ) 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 gasificati on, shift conversion, gas cooling, AGR, CO 2 compression, WSA and methanation are ident ified 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 ca rbon 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 insigni ficant 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, re spectively. [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 permitt ed 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 twent y-four (24) vents, identified as S-016BA through S-016B-X.

(f) Two (2) Air Separation Unit (ASU) molecu lar 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, eac h, 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 - identif ied 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 stor age 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 Docu ment 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 t he capacity of a source to emit an air pollutant, including air pollution control equipment and restri ctions 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. Contro l 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 PM 10 207.09 PM 2.5 73.63 SO 2 119.9 VOC 90.26 CO 302,916 NO X 588.4 H 2 SO 4 43.89

H 2 S 12.3 Pb 0.04 Hg 0.07 GHGs as CO 2 e 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 < 10Indiana Gasification LLC Page 8 of 43 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 oper ating 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 PM 10 , PM 2.5 , SO 2 , 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 CO 2 equivalent emissions (CO 2 e) 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, in cluding 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 c ontinuous compliance with the applicable requirements.Indiana Gasification LLC Page 9 of 43Rockport,Indiana PSD and TV Permit No.: 147-30464-00060Permit Reviewer: Josiah BalogunPermit Level Determination – PSDThe table below summarizes the potential to emit, reflecting alllimits, of the emission units at Indiana Gasification, LLC. Any new controlequipment is considered federally enforceableonly after issuance of this Part 70 permit, and only to the extent that the effect of the controlequipment is made practically enforceable in the permit.Potential to Emit (ton/yr)Process /EmissionUnitPM PM10PM2.5SO2VOC CO NOx H2SO4H2S Pb Hg MethanolTotalHAPsTotalGHGCO2eSyngasHydrocarbon Flare0010.44 0.44 0.41 1.97 0.03 23.5 6.07 0 0.04 3E-06 1.9E-06 0 0 13,343Acid Gas Flare -0020.01 0.01 0.01 0.001 0.023 0.06 0.23 0 0 3E-06 1.9E-06 0 0 136Auxiliary Boiler (AB) -0055.62 5.62 5.62 0.44 4.07 27.159.4300 2E-03 1.3E-03 0 1.4 88,254Acid Gas RecoveryUnit (A-B) -0072.46 2.46 2.46 26.98 8.96 410.2716.8500.1 9.6E-0.45.5E-04 9.0 22.5 1,290,000Gasifier PreheatBurners (A-E) -0080.04 0.04 0.04 0.03 0.3 3.085.51001.6E-049.0E-050 0.1 6444Emergency DieselGenerators (A-B) -0090.003 0.003 3E-04 0.008 0.015 0.0190.7600 0 0 0 084EmergencyFirewater pumps(A-C) - 0100.008 0.008 8E-03 5E-04 0.017 0.060.2400 0 0 0 0Process Area SolidFeedstockHandling(Coal/Petcoke) -0113.8 3.8 1.86 0 0 00001.1E035.5E-06000Incoming SolidFeed stockhandling(Coal/petcoke) (A5.45 3.25 0.88 0 0 000008.9E-06000Indiana Gasification LLC Page 10 of 43Rockport,Indiana PSD and TV Permit No.: 147-30464-00060Permit Reviewer: Josiah BalogunPotential to Emit (ton/yr)Process /EmissionUnitPM PM10PM2.5SO2VOC CO NOx H2SO4H2S Pb Hg MethanolTotalHAPsTotalGHGCO2eAC) - 012Rod Mill (A-D) -0130.44 0.44 0.13 0 0 0000 0 3.8E-07 0 0 0Wet Sulfuric AcidPlant (A-B) - 01542.6 42.6 42.6 70.74 0.01 159.786.9342.60 6E-06 3.5E-06 0 0 474,000Cooling Tower -ASU - 016A0.9 0.9 0.70 0 0 0000 0 0 0 0 0Cooling Tower -Main - 016B6.65 6.65 5.19 0 0 0000 0 0 0 0 0ASU MolecularSieveRegeneration (A-B)- 0170.22 0.22 0.08 0 0 000000000Slag Sump (A-E) -0230 0 0 0 0 0000.1 0 0 0 0 0MethanolDeinventory Tank -0240 0 0 0 0.16 0000000.160.160Fresh MethanolStorage Tank - 0250 0 0 0 0.13 0000000.130.130Sour Water StriperSurge Tank - 0260 0 0 0 0.004 0000.5400000Sulfuric AcidStorage Tank (A-F)- 0270.0015 0.0015 0.0015 0 0 000.0015000000Diesel FuelStorage Tank - 0290 0 0 0 0.35 00000000.070Gasoline FuelStorage Tank - 0300 0 0 0 0.1 000000000Indiana Gasification LLC Page 11 of 43Rockport,Indiana PSD and TV Permit No.: 147-30464-00060Permit Reviewer: Josiah BalogunPotential to Emit (ton/yr)Process /EmissionUnitPM PM10PM2.5SO2VOC CO NOx H2SO4H2S Pb Hg MethanolTotalHAPsTotalGHGCO2eTriethylene GlycolStorage Tank - 0310 0 0 0 0 000000000ZLD Spray Dryer -0320.51 0.51 0.48 0.015 0.13 0.890.8600 7E-05 4.1E-05 0 0.046 2886ZLD Inert Gas Vent(033)0 0 0 0 0 0000 0 3.6E-04 0 0 203.7EU-034A and EU034C0.04 0.017 0.0024 0 0 0000 0 0 0 0 0FugitiveEmissionsGasification, ShiftConv., AGR,Methanation - FUG0 0 0 0 1.61 9.45000.37000.370.3821WSA - FUG-WSA0 0 0 0.003 0 000093.74 0 0 0 0 4Plant Haul Road -FUG ROAD0.45 0.09 0.022 0 0 0000 0 0 0 0 0Electric CircuitBreakers - FUGSF60 0 0 0 0 0000 0 0 0 0 72Total Emissionfor New SourceConstruction69.63 67.05 60.48 100.2 15.90 634.18 126.9 42.68 4.89 0.004 0.0023 9.66 24.79 1,875,448(Note 2)NonattainmentNSR MajorSourceThresholds-- -- 100 100 -- ------------------SignificantLevel25 15 10 40 40 10040710 0.6 0.1 10 25 75,000Note 2: The above GHG emissions reflectthe PTE in operating year three and beyond. The PTE Year 1 estimated as 5,275,448 tons/yr CO2e. The PTE Year 2 estimated as7,015,448 tons/yr CO2e.Indiana Gasification LLC Page 12 of 43Rockport,Indiana PSD and TV Permit No.: 147-30464-00060Permit Reviewer: Josiah BalogunThis new stationary source is a major stationary source, underPSD (326 IAC 2-2), because a regulated pollutant is emitted at arate of 100tons per year or more, emissions of GHGs are equalto or greater than one hundred thousand (>100,000) tons of CO2equivalent emissions(CO2e) per year, which is greater than the PSD threshold and it isone of the twenty-eight (28) listed source categories, as specified in 326IAC 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 Assu rance 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 (SO 2 ) Y Y >100 < 100 100 Y N

Wet Sulfuric Acid Plant (A-B) - 015 (H 2 SO 4 ) 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, SO 2 and H 2 SO 4 , the Acid Gas Recovery Unit (A-B) -007 for CO, upon start-up. A CAM plan has been s ubmitted (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 em issions 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 Institut ional 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 EPAIndiana Gasification LLC Page 14 of 43 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 notapplicable to any sources in this project. The requirements of this rule apply to steamgenerating units that commence construction, modi fication, or reconstruction after August 17, 1971 and that have a heat input capacity from f uels 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 MMB tu/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 subjec t 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 t han 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 sour ces. The requirements of this rule apply to electric utility steam-generating units that commence construction, modification, or reconstruction after September 18, 1978, and t hat have a heat input capacity from fuels combusted in the steam-generating unit of greater than 73 MW (250 million Btu/hour). Theauxiliary boilers, which can supply steam to an electric generating steam turbine are steamgenerating units, but they are not considered el ectric utility units bec ause they will not supply more than 1/3 of its potential elec trical 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 bur ners (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 boile rs (EU 005A/B) have a heat input capacity greater 100 MMBtu/hr; theref ore Subpart Dc does not apply. The thermal oxidizers (EUs 007A, B) and the burners (E Us 008A-E) are not steam generating units; therefore, 40 CFR 60, Subpart Dc does not apply.

(f) 40 CFR Part 63 Subpart VVVVVV—National Em ission 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 notIndiana Gasification LLC Page 15 of 43 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 at mosphere 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 su lfur 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 H 2 S and COS in the acid gas stream from the Rectisol Process is combusted for conversion to SO 2 . The SO 2 rich gas produced is sent to catalyst beds for conversion to SO 3 and then conversion to sulfuric acid (H 2 SO 4 ) 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 H 2 SO 4 from H 2 S 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 (m 3 ) 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) AtmosphereIndiana Gasification LLC Page 16 of 43 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 N SPS 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 NO x emissions controlled by ultra-low NO x 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);Indiana Gasification LLC Page 17 of 43 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 PM 10 or SO 2 emission standards. The Subpart Db NO x 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. NO x emission will be controlled with the use of ultra low NO x 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) fo r 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 (m 3 ) (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 161Indiana 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 N SPS 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 andC-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 transferringfeed 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 c apacity 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 Igni tion 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 generat or 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 dies el 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 Combus tion 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 generat or 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 dies el 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 ar e 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 connec tor 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 inspecti on 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 el ectric 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 progr am 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 di oxide 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 bas is to any utility power distribution system for sale. Therefore, the auxiliary boilers, ident ified 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% (H 2 S 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 Avail able Control Technologies (BACT) for the source shall be as follows:

Syngas Hydrocarbon Flare, identified as (EU-001):

(1) The PM, PM 10 and PM 2.5 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/PM 10 emissions shall not exceed 3.21 lb/hour during startup or shutdown, based on a 3-hour average.

D. The Syngas Hydrocarbon Flare PM 2.5 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 Hydroc arbon 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 SO 2 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 r equiring 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 Hydr ocarbon 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 Hy drocarbon 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, s hutdowns, 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 minimi ze re-occurrence of these events. Such identified measures shall be implemented and documented.

Acid Gas Flare, identified as (EU-002):

(1) The PM, PM 10 and PM 2.5 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 SO 2 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, PM 10 and PM 2.5 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 SO 2 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 Auxilia ry 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 CO 2 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, PM 10 and PM 2.5 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 SO 2 emissions shall be reduced by the use of a Rectisol process and the SO 2 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 CO 2 emissions from the Acid Gas Recovery (AGR) Vents operation shall be limited as follows:

(A) The CO 2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed 4,690,000 tons of CO 2 during the first 12 months of operation.

(B) The CO 2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed 6,430,000 tons of CO 2 during the second 12 months of operation.

(C) The CO 2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed 1, 290,000 tons of CO 2 during the third 12 months of operation.

(D) Thereafter, the CO 2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed 1,290,000 tons CO 2 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, PM 10 and PM 2.5 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 SO 2 emissions from the Gasifier Preheat Burners (EU-008A-E) operation shall be not exceed 0.0006 lb SO 2 /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 CO 2 emissions from the Gasifier Preheater Burners shall not exceed 6,438 tons CO 2 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) SO 2 : 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 CO 2 emissions from the emergency engines (EU-009A/B and EU-010A/B/C) shall not exceed 84 tons CO 2 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, PM 10 and PM 2.5 : emissions shall be limited through the use of low-S diesel (less than15ppm sulfur) and limited hours of non-emergency operation;

(4) SO 2 : 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, PM 10 and PM 2.5 emissions from the Process Area Solid Feedstock Conveying, storage and feedbin (EU-011A/B) shall be limited through a baghouse.

(2) The PM and PM 10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM 2.5 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, PM 10 and PM 2.5 emissions from the barge unloading to hopper transfer point (EU-012A) operation shall be controlled by a wet suppr ession with a control efficiency of 90%.

Railcar Unloading to Rail Hoppers (EU-012G/H):

(1) The PM, PM 10 and PM 2.5 emissions from the railcar unloading to rail hoppers shall be controlled by a wet dust extraction system or baghouse.

(2) The PM and PM 10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM 2.5 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, PM 10 and PM 2.5 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 PM 10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM 2.5 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, PM 10 and PM 2.5 emissions shall be controlled by a wet dust extraction system or a baghouse.

(2) The PM and PM 10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM 2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Stacker Belt to the Radial Stacker (EU-012 L- M):

(1) The PM, PM 10 and PM 2.5 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 PM 10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM 2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Transfer systems consisting of hoppers and c onveyor 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, PM 10 and PM 2.5 emissions shall be controlled by a wet dust extraction system or a baghouse.

(2) The PM and PM 10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM 2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Radial Stacker to the Pile (EU-012 N-O):

(1) The PM, PM 10 and PM 2.5 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 PM 10 emissions shall not exceed 0.003 gr/dscf.

(3) The PM 2.5 emissions shall not exceed 0.0015 gr/dscf.

Storage Pile (EU-012W/X):

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

(2) The PM and PM 10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM 2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Rod Mill Vent (EU-013A-D):

(1) The PM and PM 10 emissions from each Rod Mill Vents shall not exceed 0.025 pounds per hour based on a 3-hour average.

(2) The PM 2.5 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 PM 10 emissions from each Air Separation Unit (ASU) shall not exceed 0.026 pounds per hour based on a daily average.

(2) The PM 2.5 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, PM 10 and PM 2.5 emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall be controlled by a high Effici ency Mist Eliminator and H 2 O 2 scrubber and the PM, PM 10 and PM 2.5 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 H 2 SO 4 emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall be controlled by a high Efficiency Mist Eliminator and H 2 O 2 scrubber and the H 2 SO 4 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 SO 2 emissions from the Wet Sulfuric Acid Plants (EU-015A/B) shall be controlled by a peroxide scrubber, the SO 2 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 CO 2 emissions from the Wet Sulfuric Acid Plant operation shall not exceed 474,000 tons per twelve (12) consecutive month per iod, with compliance determined at the end of each month.

ASU and Main Cooling Tower (EU-016A and 016B):

The PM, PM 10 and PM 2.5 emissions from the ASU Cooling Tower (EU-016A) and the Main Cooling Tower (EU-016B) shall be controlled by High effici ency 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 H 2 SO 4 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, PM 10 and PM 2.5 emissions from the Zero Liquid Discharge (ZLD) spray dryer shall be controlled by a fabric filter baghouse and the PM, PM 10 and PM 2.5 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 SO 2 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 CO 2 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 CO 2 emissions from the ZLD Spray Dryer shall not exceed 2,884 tons CO 2 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 H 2 SO 4 is no-controls.

(2) The BACT for the fugitive leaks of SO 2 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 CO 2 compressors while they are in operation in any week in which there are at least twenty-four (24) hours of operation of the CO 2 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, PM 10 and PM 2.5 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, PM 10 and PM 2.5 emissions from the Front-end Loader Slag Handling (EU-034A) and Vehicle Dust on Slag Pile (EU-034C) shall be c ontrolled 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 SF 6 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 Met hanol 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 tw enty-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 re striction 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 diversi on 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 diversi on from the flare to the downstream AGR/WSA trains.

Operational Limits for the auxiliary BoilersThe 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 (G EP) 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 SO 2 emissions greater than 25 tons per year, so these stacks will be subject to this rule for SO 2 . 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 st atement 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 sour ce 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 fir ed 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 O 2 or CO 2 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. SO 2 monitoring is not required because the boiler will not be subject to SO 2 monitoring under 40 CFR 60 and will not have SO 2 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 SO 2 or other sulfuric compounds. Since the Indiana Gasification sulfuric acid plant s 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 Limita tions for Sources of Indirect Heating) (a) Pursuant to 326 IAC 6-2-4 (Particulate Em ission 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, identif ied 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:

26

. 0 Q 09

. 1 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 limit ation established by this rule is inconsistent with a limitation required by the permit regulati ons, 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 Li mitations 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 mu ch more stringent. Therefore, pursuant to 326 IAC 6-3-1(b), these emission units ar e 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 noncontac t cooling tower systems, trivial activities as defined at 326 IAC 2-7-1(40), processes wi th 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 emi ssion units have potential to emit greater than 25 tons of SO 2 per year, each. However, pursuant to this rule, there are no specific SO 2 emission limitations for the combustion of natural gas. Therefore, the requirements of 326 IAC 7-1.1-2 (Sulfur Dioxi de 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 SO 2 per year. Therefore, the requirements of 326 IAC 7-1.1-2 (Sulfur Diox ide Emission Limitati ons) 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, lo cated 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 Re covery 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 ot her emission units are less than 25 tons per year, therefore, all other emission units at th is 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 di spensing 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 ru le, 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 sour ce would affect for pollutants that are emitted at major levels or significant amounts. Indi ana 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 PM 2.5 was conducted and compared to the respective NAAQS limit. For the 24-hour m odeling, two scenarios were examined and had to do with feedstock deliveries both by truck or trai n. 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 com pared 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 concent rations used in the demonstration processes required by this section shall be based upon t he applicable air quality models, data bases, and other requirements specified in 40 CFR Part 51, Appendix W (Requirements for Preparation, Adoption, and Submittal of Impl ementation 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 anot her 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 m odel 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 ei ther quantitatively or qualitatively.

It is estimated that approximately 200 additional j obs will be created as a result of the proposed project. Most of the employees will be draw n 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 ar ea was determined. Soil types include the following: Moderately thick loess over weathered loamy gl acial till, discontinuous loess over weathered sandstone and shale, discont inuous 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 Agricult ural Census for Spencer County). The maximum modeled concentrations fo r 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 horse tail, and milkweed (Flora of Indiana – Charles Deam). Livestock in Spencer County consist ma inly 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 t he U.S. Fish and Wildlife Service; Division of Endangered Species for Indiana, and includes 5 am phibians, 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 habita t within Spencer County. The mollusks, fish, amphibians, and certain species of birds and mamma ls 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 re sidential 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 allo wable increases (MAI) over the baseline concentration of sulfur dioxide, particulate ma tter, and nitrogen dioxide i ndicated 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 impairm ent 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 associ ated 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 re ceipt of the approval, if construction isIndiana 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 eight een (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 t he 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 nec essary 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 gener ator 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 IA C 24-1(b)(1)(B) the CAIR does not apply to a boiler serving a generator that supplies, in any ca lendar 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. Ther efore, 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 t hat 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 r equirements. 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 gr eater than 1/3 their potential electrical output and greater than 219,000 MWe-hrs (25MW) actual elec trical 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 rule s 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 se rves as grounds for enforcement action.

If the Compliance Determination Requirements are not sufficient to demonstrate continuous compliance, they will be supplemented with Compli ance Monitoring Requirements, also in Section D of the permit. Unlike Compliance Determinati on Requirements, failure to meet Compliance Monitoring conditions would serve as a tri gger 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 appropr iate 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 applicabl e 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, PM 10 and PM 2.5 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, PM 10 and PM 2.5 Every five (5) years 326 IAC -2-2-3Indiana 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, PM 10 PM 2.5 and

H 2 S0 4 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, PM 10 and PM 2.5 Every five (5) years 326 IAC -2-2-3

Stack testing of the ZLD Spray Dryer for NOx emissi on is not justified because of its small size and low emissions rate. NOx emissions from this source re sults 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 emissi ons is not justified because it is technically very difficult and also because the burners are each such sm all 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, av erage 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 proce ss configuration. The burners are used inside of the gasifier vessel to warm it prior to startup. Unlike a conventional heat er 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 v ent 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 326 IAC 2-2-3 Total gas flow 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 FIndiana 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 SO 2 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 enclosedhandling (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 and 40 CFR 64 Water Pressure Drop 1.0 to 5.0 inches
Visible Emissions NormalAbnormal

Incoming Solid Feed stock enclosedhandling (R-S) EU012 Wet Dust Extractor or Baghouse Water flow rate

Daily > 5.0 gpm Response steps 326 IAC 2-2-3 and 40 CFR 64 Water Pressure 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 < 0 o F Response steps 40 CFR 64

ZLD Vent EU-033 Sulfided Carbon Adsorbent Pressure Drop Weekly N/A Response steps HAPs Minor LimitIndiana 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 SO 2 CEMS Continuous N/A Continuous emission monitoring system measurement data. 326 IAC 2-2-3

Wet Sulfuric Acid Plant (A-B) - 015 CO 2 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 c an 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, Indi ana 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.govAppendix A: Emissions CalculationsPage 1 of 2 TSD App AEmission SummarySource Name:Indiana Gasification, LLCSource Location:CR 200 N and Based Road, Rockport, IN 47635Permit Number:147-30464-00060Permit Reviewer:Josiah BalogunDate:30-Jun-2011Uncontrolled Potential to EmitPM(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)TotalHAPs(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 DieselGenerator (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 FirewaterEngine (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 SolidFeedstock (011)5.49 5.49 1.94 0 0 0 0 0 0 0.00105 5.40E-06 0 0 0 0Incoming Solid FeedstockHandling (012A-AC)202.1 88.38 12.24 0 0 0 0 0 0 0.00E+00 8.94E-06 0 0 0 0Rod 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 SieveRegeneration (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-InventoryStorage 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 StorageTank (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 SurgeTank (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 StorageTank (030)0 0 0 0 0.1 0 0 0 0 0.00E+00 0.00E+00 0 0 0 0Triethylene Glycol StorageTank (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 034C0.041 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 3094535.97Appendix A: Emissions CalculationsPage 2 of 2 TSD App AEmission SummarySource Name:Indiana Gasification, LLCSource Location:CR 200 N and Based Road, Rockport, IN 47635Permit Number:147-30464-00060Permit Reviewer:Josiah BalogunDate:30-Jun-2011Limited Potential to EmitPM(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)TotalHAPs(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-0600 13302 13,343Acid Gas Flare (002)0.01 0.01 0.01 0.001 0.023 0.06 0.23 0 0 3.4E-06 1.90E-0600 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-0301.4 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-04922.5 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-0500.1 6438 6444Emergency DieselGenerator (009A-B)0.003 0.003 0.0003 0.0008 0.0015 0.019 0.76 0 0 0.00E+00 0.00E+0000Emergency FirewaterEngine (010A-C)0.008 0.008 0.0078 0.0005 0.017 0.06 0.24 0 0 0.00E+00 0.00E+0000Process Area SolidFeedstock (011)3.8 3.8 1.86 0 0 0 0 0 0 0.00103 5.40E-06000 0Incoming Solid FeedstockHandling (012A-AC)5.45 3.25 0.88 0 0 0 0 0 0 0.00E+00 8.94E-06 0 0 0 0Rod Mill (013A-D)0.44 0.44 0.13 0 0 0 0 0 0 0.00E+00 3.80E-07000 0Wet 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-0600 474000 474000Cooling Tower -ASU(016A)0.9 0.9 0.7 0 0 0 0 0 0 0.00E+00 0.00E+00000 0Cooling Tower -Main(016B)6.65 6.65 5.19 0 0 0 0 0 0 0.00E+00 0.00E+00000 0ASU Molecular SieveRegeneration (017A-B)0.22 0.22 0.08 0 0 0 0 0 0 0.00E+00 0.00E+00000 0Slag Sump (023A-E)0 0 0 0 0 0 0 0 0.1 0.00E+00 0.00E+00000 0Methanol De-InventoryStorage Tank (024)0 0 0 0 0.16 0 0 0 0 0.00E+00 0.00E+000.160.16 0 0Fresh Methanol StorageTank (025)0 0 0 0 0.13 0 0 0 0 0.00E+00 0.00E+000.130.13 0 0Sour Water Stripper SurgeTank (026)0 0 0 0 0.004 0 0 0 0.54 0.00E+00 0.00E+00000 0Sulfuric Acid Storage Tank(027A-F)0.0015 0.0015 0.0015 0 0 0 0 0.0015 0 0.00E+00 0.00E+00000 0Diesel Fuel Storage Tank(029)0 0 0 0 0.35 0 0 0 0 0.00E+00 0.00E+0000.07 0 0Gasoline Fuel StorageTank (030)0 0 0 0 0.1 0 0 0 0 0.00E+00 0.00E+00000 0Triethylene Glycol StorageTank (031)0 0 0 0 0 0 0 0 0 0.00E+00 0.00E+00000 0ZLD Spray Dryer (032)0.51 0.51 0.48 0.015 0.13 0.89 0.86 0 0 0.000071 4.10E-0500.046 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 034C0.04 0.017 0.0024 0 0 0 0 0 0 0.00E+00 0.00E+00000 0Fugitive EmissionsGasification, Shift Conv.AGR, methanation (FUG)0 0 0 0 1.61 9.45 0 0 0.37 0.00E+00 0.00E+000.370.38 19 21Fugitive Emission - WSA(FUG-WSA)0 0 0 0.003 0 0 0 0.09 3.74 0.00E+00 0.00E+00004 4Plant Haul Roads (FUGROAD)0.45 0.09 0.022 0 0 0 0 0 0 0.00E+00 0.00E+00000 0Electric Circuit Breakers(FUG-SF6)0 0 0 0 0 0 0 0 0 0.00E+00 0.00E+0000 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 1875447.678484FLARE SOURCES Page 1 of 3 TSD App A

NAME Hydrocarbon / Gasifier Start-up Flare Unit ID: 001

STACK DATA HEIGHT 300 f t DIAMETER 6 f t

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 Pollutan t lb-mol/hr lb-mol/hr lb-mol/hr Mol % lb/hr lb/hr TPY PM

10 -- -- -- -- 6.42 6.42 28.12
PM

2.5 0.09 0.09 0.41
SO 2 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 A P-42 Heating Value = 1,020 Btu/sc f

Average Maximum Annual Emissions Emissions Emissions Pollutan t lb/hr lb/hr TPY PM

10 0.0020 0.0020 0.0087
PM

2.5 0.0019 0.0019 0.0081
SO 2 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 PM

10 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

PM

2.5 0

. 095 0

. 09 0

. 41
SO 2 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-06Calculations: 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, PM 10 , 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) A verage 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/f t 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) A verage Emissions (lb/hr) = Maximum Emissions.

NOx PM 10 VOC 0.100 0.007 0.0001

PM

10 SO 2 7.600 0.60

NO

x 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 A verage Maximum A nnual Emissions Emissions Emissions Pollutan t lb/even t lb/hr TPY Scenario 1 Factor (lb/MMBtu)

Sources: NOx and PM 10 for Syngas are based on values from vendor supplied data. VOC for Syngas = 2% of AP-42 Section 1.4 "Natural Gas Combustion" Ta ble 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

PM

10 0.260 0.09 0.002
PM

2.5 0.260 0.09 0.002
SO 2 255.62 85.21 1.917 NO

x 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 0.000Page 3 of 3 TSD App A GHG Emissions from Gasifier Start-up

lb/hr TPY MT/y r CO2 for Gasifier Flare = 185,818.1 813,883.3 738354.9

Equation Y-5

N 2

O = Annual nitrous oxide emissions from flared gas (metric ton N 2 O/year)
CO 2

= Emission rate of CO 2 from flared gas calculated (metric ton/year)
EmF N2O = Default N 2 O emission factor for “Petroleum Products” from Table C-2 of subpart C (General Stationary Fuel Combustion Sources) (kg N 2 O/MMBtu) = 0.0006
EmF = Default CO 2 emission factor for flare gas of 60 kg CO 2 /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

CH 4

or N 2 O = Annual CH 4 or N 2 O 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 ba lance was used to determine the CO2 and N2O emissions. There w ill be no CH4 emissions. The GHG S ubpart Y (Refinery) flare equations are not applicable; however, the Subpart Y equation for N2O w ill be used to conservatively estimate N2O emissions.

       

  EmF EmF CO O N O N 2 2 2

EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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.

Pilo

t

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 CO2Hydrocarbon / Gasifier Startup FlareFLARE 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 DAT A HEIGHT 300 ft DIAMETER 1.6 ft

EMISSIONS: A cid Gas Flare Pilot Only hr/yr = 8,760 Pilot Firing Rate = 0.27 MMBtu/hr A P-42 Heating Value = 1,020 Btu/sc f

Average Maximum Annual Emissions Emissions Emissions Pollutant lb/hr lb/hr TPY
PM

10 0.0020 0.0020 0.0087
PM

2.5 0.0019 0.0019 0.0081
SO 2 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/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 (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton) A verage Emissions (lb/hr) = Maximum Emissions.

PM

10 SO 2 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 5/3/2012Stationary 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

CH 4

or N 2 O = Annual CH 4 or N 2 O 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 y ear 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 EF HHV Fuel CO       3 2 10

1

EF HHV Fuel O orN CH       3 2 4 10 1

16_30464 Calcs F 7 5/3/2012COMBUSTION SOURCES Page 1 of 3 TSD App A

NAME Auxiliary Boiler Unit ID: 

### 005A & B

Emissions shown are for sum of tw o (2) boilers each at 408 MMBtu/h r

STACK DAT A 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 DAT A HEAT INPUT - Full rate - Natural Gas 816.33 MM Btu/h r HEAT INPUT - Full rate (Black Start) - Natural Gas 816.33 MM Btu/h r HEAT INPUT - Pilot Gas - Natural Gas 10.00 MM Btu/h r AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft 3 OPERATING HOURS- Full rate - Natural Gas 8760 hr/y r OPERATING HOURS - Full rate (Black Start) - Natural Gas 96 hr/y r

EMISSIONS: Full rate case - Natural Gas lb/hr avg. lb/hr max. TPY PM

10 6.08 6.08 26.64
PM

2.5 1.22 1.22 5.33
SO 2 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 PM

10 6.08 6.08 0.29
PM

2.5 6.08 6.08 0.29
SO 0 48 0 48 0 023

2 . . . 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-05EMISSIONS: Normal Operations Total Page 2 of 3 TSD App A lb/hr avg. lb/hr max. TPY PM

10 6.15 6.08 26.93
PM

2.5 1.28 6.08 5.62
SO 2 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 Fact or (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft 3 ) X Heat Input (MMBtu/hr) Emissions (NOx, CO) (Avg. lb/hr) = Vendor Fa ctor (lb/MM Btu) X Heat Input (MMBtu/hr) Emissions (TPY) = Emissions (lb/h r) x (Operating hr/yr / 2000 lb/ton) Total Emissions (Avg. lb/hr) = Total TPY x 2,000 lb/ton / 8,760 hr/y r Total Emissions (Max. lb/hr) = Highest Ma ximum lb/hr value from either case

PM

10 VOC SO 2 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 Sect ion 1.4, Tables 1.4-3 and 1.4-4. To be conservative SO2 emissions will be ca lculated assuming all scenarios fire natural gas If SNG is fired there will be no S O2 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 conser v ati v

e , SO2 emissions w ill be calc u lated ass u ming all scenarios fire nat u ral gas

. If SNG is fired

, there w ill be no SO2 emissions as SNG is ass u med 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 calculat or for SCCs per Roy Hu ntley (EPA EI and Analysis Group).Page 3 of 3 TSD App A

Stationary Combus tion Sources - Natural Gas (semi-a nnual or more fr equent 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a pa rticular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid measur ements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific defaul t emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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 BoilerCOMBUSTION SOURCES Pa ge 1 of 9 TSD App A

NAME AGR CO2 Regenerative Thermal Oxidizer Unit ID: 

### 007

STACK DAT A 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/h r HEAT INPUT: One Unit at full rate 38.81 MM Btu/h r HEAT INPUT: Black-starts (1 unit at half rate) 19.41 MM Btu/h r AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft 3 OPERATING HOURS: Two Units at full rate 8760 hr/y r OPERATING HOURS: One Unit at full rate 8760 hr/y r OPERATING HOURS: Black-start 24 hr/y r

H2S in Waste gas to each RTO = 0.57 lb/h r COS in Waste gas to each RTO = 2.00 lb/h r CO in Waste gas to each RTO: 4673.99 lb/h r 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 PM

10 0.58 0.58 2.53
PM

2.5 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 G as Removal Unit.

Emissions are calculated for both cases (c oal / coke and coal only) and the higher (c onservative) value for each pollutant will be permitted.

SO 2 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 PM

10 0.29 0.29 1.27
PM

2.5 0.01 0.01 0.06
SO 2 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-04EMISSIONS: One Unit at half rate - Conservatively assu me Natural Gas for entire 24 hrs Page 2 of 9 TSD App A

lb/hr avg. lb/hr max. TPY PM

10 0.14 0.14 0.0017
PM

2.5 0.14 0.14 0.0017
SO 2 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
PM

10 0.87 0.58 3.80
PM

2.5 0.56 0.56 2.46
SO 2 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 (PM 10

) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft 3 ) 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/ft 3 ) X Heat Input (MMBtu/hr) Emissions (NOx) (Avg. lb/hr) = Vendor Fact or (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 = Su m of individual cases Emissions (Avg. lb/hr) Total = TPY Total X 2,000 (lb/T) / (Total Hrs Operation)

Natural Gas Combustion PM 10 VOC SO 2 HAP
7.60 5.50 0.6 1.89

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM 10

Natural Gas Combustion NOx CO 0.05 0.036

Comments: Factor (lb/MM scf)

Factor (lb/MMBtuf)

SO 2 emissions based on 98% conversion of sulfur in waste gas to SO 2 . Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). During "normal operations" the thermal oxid izer burns SNG (which contai ns no sulfur); during a bla ck-start, it fires natural ga s 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 calculat or for SCCs per Roy H untley (EPA EI and Analysis Group). Total HAPs are based on AP-42 Secti on 1.4, Tables 1.4-3 and 1.4-4. Source: Emission factors for NOx and CO are based on information from vendor supp lied 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/h r HEAT INPUT: One Unit at full rate 31.35 MM Btu/h r HEAT INPUT: Black-starts (1 unit at half rate) 15.67 MM Btu/h r AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft 3 OPERATING HOURS: Two Units at full rate 8760 hr/y r OPERATING HOURS: One Unit at full rate 8760 hr/y r OPERATING HOURS: Black-start 24 hr/y r

H2S in Waste gas to each RTO = 0.56 lb/h r COS in Waste gas to each RTO = 1.97 lb/h r CO in Waste gas to each RTO: 4595.57 lb/h r Total Sulfur in Waste gas to each RTO: 1.58 lb/hr Methanol in Waste Gas to each RTO: 78.86 lb/h r

H2S and COS DRE: 98 % CO and Methanol DRE: 99 %

EMISSIONS: Two Units at Full Rate lb/hr avg. lb/hr max. TPY PM

10 0.47 0.47 2.05
SO 2 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 PM

10 0.23 0.23 1.02
SO 2 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-04EMISSIONS: One Unit at half rate - Conservatively assume Natura l Gas (for SO2) and SNG (for Hg) for entire 24 hrs Page 5 of 9 T SD App A

lb/hr avg. lb/hr max. TPY PM

10 0.12 0.12 0.0014
SO 2 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 PM

10 0.70 0.47 3.07
SO 2 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 PM 10 VOC SO 2 HAP
7.60 5.50 0.6 1.89

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM 10

Natural Gas Combustion NOx CO 0.05 0.036 Factor (lb/MM scf)

Factor (lb/MMBtu)

Natural Gas SNG 1.95E-07 1.68E-06 Mercury Factor (lb/MMBtu)Page 6 of 9 TSD App A Stationary Combus tion Sources - Natural Gas (semi-a nnual or more fr equent 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid meas urements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific default emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

all valid samples for the year A verage 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 CO2ePage 7 of 9 TSD App A Coal Only Case

COMBUSTION DATA HEAT INPUT: Two Units at full rate 77.62 MM Btu/h r HEAT INPUT: One Unit at full rate 38.81 MM Btu/h r HEAT INPUT: Black-starts (1 unit at half rate) 19.41 MM Btu/h r AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft 3 OPERATING HOURS: Two Units at full rate 8760 hr/y r OPERATING HOURS: One Unit at full rate 8760 hr/y r OPERATING HOURS: Black-start 24 hr/y r

H2S in Waste gas to each RTO = 0.57 lb/h r COS in Waste gas to each RTO = 2.00 lb/h r CO in Waste gas to each RTO: 4673.99 lb/h r Total Sulfur in Waste gas to each RTO: 1.60 lb/hr Methanol in Waste Gas to each RTO: 80.20 lb/h r

H2S and COS DRE: 98 % CO and Methanol DRE: 99 %

EMISSIONS: Two Units at Full Rate (100%) lb/hr avg. lb/hr max. TPY PM

10 0.58 0.58 2.53
SO 2 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 PM

10 0.29 0.29 1.27
SO 2 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-04EMISSIONS: One Unit at half rate (25%) - C onservatively assume Natural Gas (for SO2) and SNG (for Hg) for entire 24 hrs Page 8 o f 9 TSD App A

lb/hr avg. lb/hr max. TPY PM

10 0.14 0.14 0.0017
SO 2 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 PM

10 0.87 0.58 3.80
SO 2 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 PM 10 VOC SO 2 HAP
7.60 5.50 0.6 1.89

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM 10

Natural Gas Combustion NOx CO 0.05 0.036 Factor (lb/MM scf)

Factor (lb/MMBtu)

Natural Gas SNG 1.95E-07 1.61E-06 Mercury Factor (lb/MMBtu)Page 9 of 9 TSD App A Stationary Combus tion Sources - Natural Gas (semi-a nnual or more fr equent 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a pa rticular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid meas urements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific defaul t emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

valid samples for the year A verage 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/y rCOMBUSTION 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/h r HEAT INPUT: Black Start 35.00 MM Btu/h r AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft 3
OPERATING HOURS -Normal Case 8760 hr/y r OPERATING HOURS -Black Starts 28.8 hr/y r

EMISSIONS: Normal Case lb/hr avg. lb/hr max. TPY PM

10 0.013 0.013 0.0587
PM

2.5 0.002 0.002 0.0073
SO

2 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 PM

10 0.026 0.026 0.00038
PM

2.5 0.024 0.024 0.00035
SO

2 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/ft 3 ) 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/h r) x (Operating hr/yr / 2000 lb/ton) A verage Emissions (lb/hr) = Maximum Emissions.

Natural Gas Combustion SO 2 0.6

Natural Gas Combustion PM 10 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. A ssumes sulfur content in natural gas of 2,000 grains/10^6 scf (< 5 ppmv of H2S). Natural gas or SNG may be combusted. Conservatively assum ed 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 PM 10 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 aver age 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

CH 4

or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons) Fuel = Mass or volume of the fuel combusted during the reporting yea r 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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 CO2COMBUSTION SO URCES P age 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/ft 3
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
PM

10 0.013 0.013 0.0587
PM

2.5 0.002 0.002 0.0073
SO 2 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
PM

10 0.026 0.026 0.00038
PM

2.5 0.024 0.024 0.00035
SO 2 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/ft 3 ) 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 SO 2 0.6

Natural Gas Combustion PM 10 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

CH 4

or N 2 O = Annual CH 4 or N 2 O 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

GHG Pollutant GHG Metric Tons GWP Factors M e t r i c

T ons CO2e CO2 8,414 1 8,414 CH4 0.2 21 3 N2O 0.0 310 5 TOTAL = 8,422 9,281 TPY CO2COMBUSTION SO URCES P age 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/ft 3
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
PM

10 0.013 0.013 0.0587
PM

2.5 0.002 0.002 0.0073
SO 2 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
PM

10 0.026 0.026 0.00038
PM

2.5 0.024 0.024 0.00035
SO 2 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/ft 3 ) 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 SO 2 0.6

Natural Gas Combustion PM 10 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

CH 4

or N 2 O = Annual CH 4 or N 2 O 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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 CO2COMBUSTION SO URCES P age 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/ft 3
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
PM

10 0.013 0.013 0.0587
PM

2.5 0.002 0.002 0.0073
SO 2 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
PM

10 0.026 0.026 0.00038
PM

2.5 0.024 0.024 0.00035
SO 2 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/ft 3 ) 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 SO 2 0.6

Natural Gas Combustion PM 10 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

CH 4

or N 2 O = Annual CH 4 or N 2 O 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

GHG Pollutant G H G 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 CO2COMBUSTION SO URCES P age 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/ft 3
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
PM

10 0.013 0.013 0.0587
PM

2.5 0.002 0.002 0.0073
SO 2 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
PM

10 0.026 0.026 0.00038
PM

2.5 0.024 0.024 0.00035
SO 2 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/ft 3 ) 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 SO 2 0.6

Natural Gas Combustion PM 10 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

CH 4

or N 2 O = Annual CH 4 or N 2 O 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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 CO2COMBUSTION SOURCES Pa ge 1 of 4 TSD App A

NAME Emergency Diesel Power Generator A Unit ID: 

### 009 A

COMBUSTION DAT A FUEL TYPE Diesel ENGINE SIZE 1,341 HP HOURS OF OPERATION 500 hr/y r

EMISSIONS avg lb/h r lb/hr max. TP Y PM

10 0.06 0.06 0.0148
PM

2.5 0.01 0.01 0.0014
SO 2 0.015 0.015 0.00377
NO

X 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)

PM

10 SO 2 NO X 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 us e 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 calculat or for SCCs per Roy H untley (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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid measur ements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific defaul t emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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. A ssumed Fuel at 100% Load = 41.6 gal/hr.COMBUSTION SOURCES Pag e 3 of 4 TSD App A

NAME Emergency Diesel Power Generator B Unit ID: 

### 009 B

COMBUSTION DAT A FUEL TYPE Diesel ENGINE SIZE 1,341 HP HOURS OF OPERATION 500 hr/y r

EMISSIONS avg lb/h r lb/hr max. TP Y PM

10 0.06 0.06 0.0148
PM

2.5 0.01 0.01 0.0014
SO 2 0.015 0.015 0.00377
NO

X 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 (L B/HR) X (Hours of operation/2000)

PM

10 SO 2 NO X 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 us e source assumed to be negligable PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculat or for SCCs per Roy Hunt ley (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 di esel 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a pa rticular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid meas urements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific defaul t emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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. A ssumed 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 DAT A FUEL TYPE Diesel ENGINE SIZE 575 HP HOURS OF OPERATION 500 hr/y r

EMISSIONS avg lb/h r lb/hr max. TP Y PM

10 0.108 0.108 0.0269
PM

2.5 0.011 0.011 0.0026
SO 2 0.0061 0.0061 0.00152
NO

X 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 (L B/HR) X (Hours of operation/2000)

PM

10 SO 2 NO X 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 us e source assumed to be negligable PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculat or for SCCs per Roy H untley (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 di esel 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a pa rticular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid measur ements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific defaul t emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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. A ssumed 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 DAT A FUEL TYPE Diesel ENGINE SIZE 575 HP HOURS OF OPERATION 500 hr/y r

EMISSIONS avg lb/h r lb/hr max. TP Y PM

10 0.108 0.108 0.0269
PM

2.5 0.011 0.011 0.0026
SO 2 0.0061 0.0061 0.00152
NO

X 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 (L B/HR) X (Hours of operation/2000)

PM

10 SO 2 NO X 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 us e source assumed to be negligable PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculat or for SCCs per Roy H untley (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 di esel 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a pa rticular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid measur ements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific defaul t emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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. A ssumed 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 DAT A FUEL TYPE Diesel ENGINE SIZE 575 HP HOURS OF OPERATION 500 hr/y r

EMISSIONS avg lb/h r lb/hr max. TP Y PM

10 0.108 0.108 0.0269
PM

2.5 0.011 0.011 0.0026
SO 2 0.0061 0.0061 0.00152
NO

X 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 (L B/HR) X (Hours of operation/2000)

PM

10 SO 2 NO X 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 us e source assumed to be negligable PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculat or for SCCs per Roy H untley (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 di esel 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a pa rticular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid measur ements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific defaul t emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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. A ssumed 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 A nnual PM10 Factor A nnual

Emissions PM Total/ Emissions Unit ID Name TPY PM10 TPY 012 A Bar g e Unload to Ho pp

e r 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87 012 B Bar g e Unload Ho pp

er to Bel t 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87 012 C Bar g e Conve y or Transfer Dro p 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87 012 D Bar g e Conve y or Transfer Dro p 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87 012 E Bar g e Conve y or Transfer Dro p 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87 012 F Bar g e Conve y or Transfer Dro p 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87 012 G Rail Unload 1 to Ho pp

e r 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87 012 H Rail Unload 2 to Ho pp

e r 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87 012 I Rail Unload Ho pp

er 1 to Bel t 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87 012 J Rail Unload Ho pp

er 2 to Bel t 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 Activit y on Pile 1 1,500 TPH 0.798 lb/hr 8,760 3.50 4.58 16.01 012 Q Dozer Activit y 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 Da y 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 conve y or to 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87 012 Z Truck Ba y 1 dum p to Ho pp

e r 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87 012 A A Truck ho pp

er to conve y o

r 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87 012 AB Truck Ba y 2 dum p to Ho pp

e r 750 TPH 0.00056 lb/ton 8,760 1.83 2.114 3.87 012 AC Truck Ba y 3 dum p to Ho pp

e r 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/PM 10

EMISSIONS Uncontrolled Annual Ave Process Rate Uncontrolled Emission Factor Operating HoursComments:

Dozer activity (012 P and 012 Q) factors calculated based on equations from AP-42 Section 13.2. 2 A ll 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 documen t

Page 3 of 3 TSD App A

A nnual Emissions Unit ID Name TPY 012 A Bar g e Unload to Ho pp

e r 750 TPH 0.00008 lb/ton 8,760 0.28 012 B Bar g e Unload Ho pp

er to Bel t 750 TPH 0.00008 lb/ton 8,760 0.28 012 C Bar g e Conve y or Transfer Dro p 750 TPH 0.00008 lb/ton 8,760 0.28 012 D Bar g e Conve y or Transfer Dro p 750 TPH 0.00008 lb/ton 8,760 0.28 012 E Bar g e Conve y or Transfer Dro p 750 TPH 0.00008 lb/ton 8,760 0.28 012 F Bar g e Conve y or Transfer Dro p 750 TPH 0.00008 lb/ton 8,760 0.28 012 G Rail Unload 1 to Ho pp

e r 750 TPH 0.00008 lb/ton 8,760 0.28 012 H Rail Unload 2 to Ho pp

e r 750 TPH 0.00008 lb/ton 8,760 0.28 012 I Rail Unload Ho pp

er 1 to Bel t 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 Activit y on Pile 1 1,500 TPH 0.080 lb/hr 8,760 0.35 012 Q Dozer Activit y 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 Da y 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 conve y or to 750 TPH 0.00008 lb/ton 8,760 0.28 012 Z Truck Ba y 1 dum p to Ho pp

e r 750 TPH 0.00008 lb/ton 8,760 0.28 012 A A Truck ho pp

er to conve y o

r 750 TPH 0.00008 lb/ton 8,760 0.28 012 AB Truck Ba y 2 dum p to Ho pp

e r 750 TPH 0.00008 lb/ton 8,760 0.28 012 AC Truck Ba y 3 dum p to Ho pp

e r 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 A ll 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 documen t PM 2.5

EMISSIONS Uncontrolled Annual Ave Process Rate Uncontrolled Emission Factor Operating HoursPage 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 Methodolog y

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

PM

10

EMISSIONS A verage Maximum A nnual PM 10 A nnual PM 2.5 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 5/3/2012VENT SOURCES P age 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/h r AP-42 NATURAL GAS HEAT VALUE 1,020 Btu/ft 3 OPERATING HOURS: Two Unit Operation 8,760 hr/y r OPERATING HOURS: One Unit Operation 0 hr/y r OPERATING HOURS: Black-start 24 hr/y r OPERATING HOURS: Preheat 60 hr/y r

EMISSIONS: Full Rate lb/hr avg. lb/hr max. TPY SO 2 8.30 8.30 36.35

NOx 10.17 10.17 44.55
CO 18.72 18.72 82.01 H 2

SO 4 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/y r lb/hr avg. lb/hr max. TPY SO 2 4.15 4.15 0.00

NOx 5.09 5.09 0.00
CO 9.36 9.36 0.00 H 2

SO 4 2.50 2.50 0.00 Mercury (HAP) 3 3E 10 3 3E 10 0 0E+00 3

. 3E

- 10 3

. 3E

- 10 0

. 0E+00

EMISSIONS: Half Rate (including Black Start) lb/hr avg. lb/hr max. TPY SO 2 2.08 2.08 0.02

NOx 2.54 2.54 0.03
CO 4.68 4.68 0.06 H 2

SO 4 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
PM

10 0.03 0.03 0.0008
PM

2.5 0.02 0.02 0.0006
SO 2 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-06EMISSIONS: Normal Operations Total Page 2 of 9 TSD App A lb/hr avg. lb/hr max. TPY PM

10 0.00018 0.03 0.0008
PM

2.5 0.00015 0.02 0.0006
SO 2 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 H 2

SO 4 5.00 5.00 21.90
PM

2.5 including H 2 SO 4 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.

PM

10 VOC SO 2 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/ft 3 ) 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 g rains/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/h r 1,020 Btu/ft 3 Full Rate 8,760 hr/y r Half Rate 0 hr/y r Black Start 24 hr/y r Preheat 60 hr/y r

EMISSIONS: Full Rate lb/hr avg. lb/hr max. TPY SO 2 8.30 8.30 36.35 NOx 10.17 10.17 44.55 CO 18.72 18.72 82.01
H 2

SO 4 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/y r lb/hr avg. lb/hr max. TPY SO 2 4.15 4.15 0.00 NOx 5.09 5.09 0.00 CO 9.36 9.36 0.00 H 2

SO 4 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 SO 2 2.08 2.08 0.02 NOx 2.54 2.54 0.03 CO 4.68 4.68 0.06 H 2

SO 4 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

. . PM

10 0.03 0.03 0.0008
SO 2 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

PM

10 VOC SO 2 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 C ase: Natural

Gas CombustionPage 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons) Fuel = Mass or volume of the fuel combusted during the reporting yea r 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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

sam p les for the y ea r Annual Average 0.00102 MMBtu per scf

GHG WSA Preheat

Burners EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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/h r CO2% = 6.60% CO2 MW = 44.01 lb/lb-mole CO2 Emissions = 42,209 lb/h r 185,003 TPY CO2 15% Contingency due to lack of performance guarantee 212,999 TPY CO2Page 7 of 9 TSD App A Coal Only Case

35.00 MM Btu/h r 1,020 Btu/ft 3 Full Rate 8,760 hr/y r Half Rate 0 hr/y r Black Start 24 hr/y r Preheat 60 hr/y r

EMISSIONS: Full Rate lb/hr avg. lb/hr max. TPY SO 2 7.57 7.57 33.15 NOx 7.40 7.40 32.43 CO 13.63 13.63 59.69
H 2

SO 4 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/y r lb/hr avg. lb/hr max. TPY SO 2 3.78 3.78 0.00 NOx 3.70 3.70 0.00 CO 6.81 6.81 0.00 H 2

SO 4 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 SO 2 1.89 1.89 0.02 NOx 1.85 1.85 0.02 CO 3.41 3.41 0.04 H 2

SO 4 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

. . PM

10 0.03 0.03 0.0008
SO 2 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

PM

10 VOC SO 2 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 C ase: 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons) Fuel = Mass or volume of the fuel combusted during the reporting yea r 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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

sam p les for the y ea r Annual Average 0.00102 MMBtu per scf

GHG GHG GWP Metric Tons WSA Preheat

Burners EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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/h r CO2% = 10.262% CO2 MW = 44.01 lb/lb-mole CO2 Emissions = 46,941 lb/h r 205,743 TPY CO2 15% Contingency due to lack of performance guarantee 236,877 TPY CO2VENT SOURCES P age 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/h r AP-42 NATURAL GAS HEAT VALUE 1,020 Btu/ft 3 OPERATING HOURS: Two Unit Operation 8,760 hr/y r OPERATING HOURS: One Unit Operation 0 hr/y r OPERATING HOURS: Black-start 24 hr/y r OPERATING HOURS: Preheat 60 hr/y r

EMISSIONS: Full Rate lb/hr avg. lb/hr max. TPY SO 2 8.30 8.30 36.35

NOx 10.17 10.17 44.55
CO 18.72 18.72 82.01 H 2

SO 4 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/y r lb/hr avg. lb/hr max. TPY SO 2 4.15 4.15 0.00

NOx 5.09 5.09 0.00
CO 9.36 9.36 0.00 H 2

SO 4 2.50 2.50 0.00 Mercury (HAP) 3 3E 10 3 3E 10 0 0E+00 3

. 3E

- 10 3

. 3E

- 10 0

. 0E+00

EMISSIONS: Half Rate (including Black Start) lb/hr avg. lb/hr max. TPY SO 2 2.08 2.08 0.02

NOx 2.54 2.54 0.03
CO 4.68 4.68 0.06 H 2

SO 4 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
PM

10 0.03 0.03 0.0008
PM

2.5 0.02 0.02 0.0006
SO 2 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-06EMISSIONS: Normal Operations Total Page 2 of 9 TSD App A lb/hr avg. lb/hr max. TPY PM

10 0.00018 0.03 0.0008
PM

2.5 0.00015 0.02 0.0006
SO 2 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 H 2

SO 4 5.00 5.00 21.90
PM

2.5 including H 2 SO 4 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.

PM

10 VOC SO 2 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/ft 3 ) 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/h r 1,020 Btu/ft 3 Full Rate 8,760 hr/y r Half Rate 0 hr/y r Black Start 24 hr/y r Preheat 60 hr/y r

EMISSIONS: Full Rate lb/hr avg. lb/hr max. TPY SO 2 8.30 8.30 36.35 NOx 10.17 10.17 44.55 CO 18.72 18.72 82.01
H 2

SO 4 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/y r lb/hr avg. lb/hr max. TPY SO 2 4.15 4.15 0.00 NOx 5.09 5.09 0.00 CO 9.36 9.36 0.00 H 2

SO 4 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 SO 2 2.08 2.08 0.02 NOx 2.54 2.54 0.03 CO 4.68 4.68 0.06 H 2

SO 4 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

. . PM

10 0.03 0.03 0.00078
SO 2 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

PM

10 VOC SO 2 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons) Fuel = Mass or volume of the fuel combusted during the reporting yea r 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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/h r CO2% = 6.60% CO2 MW = 44.01 lb/lb-mole CO2 Emissions = 42,209 lb/h r 185,003 TPY CO2 15% Contingency due to lack of performance guarantee 212,999 TPY CO2Page 7 of 9 TSD App A Coal Only Case

35.00 MM Btu/h r 1,020 Btu/ft 3 Full Rate 8,760 hr/y r Half Rate 0 hr/y r Black Start 24 hr/y r Preheat 60 hr/y r

EMISSIONS: Full Rate lb/hr avg. lb/hr max. TPY SO 2 7.57 7.57 33.15 NOx 7.40 7.40 32.43 CO 13.63 13.63 59.69
H 2

SO 4 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/y r lb/hr avg. lb/hr max. TPY SO 2 3.78 3.78 0.00 NOx 3.70 3.70 0.00 CO 6.81 6.81 0.00 H 2

SO 4 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 SO 2 1.89 1.89 0.02 NOx 1.85 1.85 0.02 CO 3.41 3.41 0.04 H 2

SO 4 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

. . PM

10 0.03 0.03 0.00078
SO 2 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

PM

10 VOC SO 2 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons) Fuel = Mass or volume of the fuel combusted during the reporting yea r 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O per m 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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/h r CO2% = 10.262% CO2 MW = 44.01 lb/lb-mole CO2 Emissions = 46,941 lb/h r 205,743 TPY CO2 15% Contingency due to lack of performance guarantee 236,877 TPY CO2Page 1 of 2 TSD App A

NAME 

### ASU Coolin g Water Tower CAP Unit ID: 

### 016a

Evaporative Cooler Operating Parameter s Emission s Emission s Flow Rate, (gpm ) Drift Rate, % Drift lb/h r TDS (ppm) PM lb/h r PM TPY PM2.5 lb/h r PM2.5 TPY 54,95 6 0.000 5 138 1,50 0 0.21 0.9 0 0.1 6 0.7 0

Comments:

Drift rate guaranteed by vendor.
Assume all dissolved solids to be PM 10. 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 rat e cannot exceed the CAP value, regardless of the number of cells in operation. Therefore, the emissions listed above are the capped tot al 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 Coolin g Water Tower CAP Unit ID: 

### 016b

Evaporative Cooler Operating Parameter s Emission s Emission s Flow Rate, (gpm ) Drift Rate, % Drift lb/h r TDS (ppm) PM10 lb/h r PM10 TPY PM2.5 lb/h r PM2.5 TPY 404,67 6 0.000 5 1,01 3 1,50 0 1.52 6.6 5 1.1 8 5.1 9

Comments:

Drift rate guaranteed by vendor.
Assume all dissolved solids to be PM 10. 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 r ate cannot exceed the CAP value, regardless of the number of cells in operation. Therefore, the emissions listed above are the capped tot al 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

PM

10

EMISSIONS A verage Maximum A nnual PM 10 A nnual PM 2.5 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 5/3/2012Page 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)



#     3 12 * * 

### W

s b a k E  

##      



 

## 365 365 P E E extPage 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 Tr ucks = 50 t ons, Limestone Tr ucks = 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)



#     3 12 * * 

### W

s b a k E  

##      



 

## 365 365 P E E extEmissions 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.wr apair.org/forums/dejf/fdh/content/C h9-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]Page 1 of 2 TSD App A6.23 acres271,379 ft^2top height = 203top diameter = 150top slant = 135.62√[(topheight‐pileheight)^2+(topdiameter/2)^2]pile height = 90pile diameter = 539pile slant = 337.40√[(topheight)^2+(pilediameter/2)^2]Surface area truncated cone = SA of whole cone - SA of top/removed cone + area of top.5.18 acres225,647 ft^2top height = 186top diameter = 150top slant = 135.62√[(topheight‐pileheight)^2+(topdiameter/2)^2]pile height = 73pile diameter = 494pile slant = 309.20√[(topheight)^2+(pilediameter/2)^2]coal pile surface area =coke pile surface area =2tttpprsrsrSA 



16_30464 CalcsD 725/3/2012Page 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 231.87 269.43 269.43 269.43 FT OUTSIDE PILE DIAMETER 463.74 538.85 538.85 538.85 FT PI*R*R 168,901.00 228,051.00 228,051.00 228,051.00 SQ FT HEIGHT OF TOTAL CONE 174.74 203.04 203.04 203.04 FT TOTAL CONE CAPACITY 9,837,695.00 15,434,491.70 15,434,491.70 15,434,491.70 CU FT TOP CONE RADIUS 135.00 150.00 150.00 150.00 FT PI*R*R 57,255.50 70,685.80 70,685.80 70,685.80 HEIGHT OF TOP CONE 101.74 113.04 113.04 113.04 FT TOP CONE CAPACITY 1,941,649.00 2,663,441.00 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 91,761.00 113,130.00 113,130.00 113,130.00 CU FT NET CAPACITY 7,804,285.00 12,657,920.70 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 366,801,395.00 632,896,035.00 632,896,035.00 632,896,035.00 LBS 2,000.00 2,000.00 2,000.00 2,000.00 LBS/TON NET CAPACITY 183,400.70 316,448.00 316,448.00 316,448.00 TONS AREA OF PILE 168,901.25 228,050.64 228,050.64 228,050.64 SQ FT AREA OF PILE 3.88 5.24 5.24 5.24 ACRES
DAYS STORAGE 44.87 33.08 38.92 64.86 DAYS each Coal Consumption (100% fuel) 9,565.00 8,131.10 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 5/3/2012COMBUSTION SOURCES Page 1 of 3 TSD App A

NAME ZLD Spray Dryer Stack Unit ID: 

### 032

STACK DAT A HEIGHT 100 ft DIAMETER 1 ft GAS EXIT TEMP 310 °F GAS EXIT VELOCITY 35.49 fps

COMBUSTION DAT A HEAT INPUT 5.6 MM Btu/h r AP-42 NATURAL GAS HEAT VALUE 1,020 Btu/ft 3
PROCESS FLOW RATE 2,735 dscfm OPERATING HOURS 8,760 hr/y r

EMISSIONS: lb/hr avg. lb/hr max. TPY PM

10 0.12 0.12 0.51
PM

2.5 0.11 0.11 0.48
SO 2 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/ft 3 ) X Heat Input (MMBtu/hr) Emissions (NOx, CO, VOC) (Avg. lb/hr) = Vendor Fa ctor (lb/MM Btu/hr) x Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/h r) x (Operating hr/yr / 2000 lb/ton) A verage Emissions (lb/h r) = Maximum Emissions.

Natural Gas Combustion SO 2 Fabric Filter PM 10 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. C onservatively assumed natural gas for SO2 calculation (as SNG contains no sulfur). Total HAPs are based on AP-42 Sect ion 1.4, Tables 1.4-3 and 1.4-4. PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculat or for SCCs per Roy Hu ntley (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 Combus tion Sources - Natural Gas (semi-a nnual or more fr equent 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a pa rticular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid measur ements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific defaul t emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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

A

verage Maximum A verage Annual A verage 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, al l 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 5/3/2012Basis 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 = 1.8879 6 0.0018 5 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, Append ix 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. FactorPage 2 of 2 TSD App A

EMISSION FACTOR BASED INVENTOR Y 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, Append ix 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

TotalPage 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/componen t lb/h r % lb/h r 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 Com p ressors 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 Sam p lin

g Connections A ll 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/componen t lb/h r % lb/h r 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 Com p ressors 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 Sam p lin

g Connections A ll 1 0.033 0.033 0 0.033 0.145 Total VOCs 399 4.63 20.30

Carbonyl Sulfide

COS Conc %v lb/hr/componen t lb/h r % lb/h r 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 Efficiency Component

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 Emissions Process Stream Component Count

ValvesCarbon Monoxide Page 2 of 6 TSD App A

CO Conc

%v lb/hr/componen t lb/h r % lb/h r 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/componen t lb/h r % lb/h r 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 StreamAmmonia Page 3 of 6 TSD App A

NH3 Conc

%v lb/hr/componen t lb/h r % lb/h r 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 Emissions Component

Count Process Stream Fugitive Source Controlled Emissions Emission Factors Control EfficiencyPage 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/componen t lb/h r % lb/h r TPY Valves A cid Gas 10 20 44.00 0.00890 0.0783 0 0.0783 0.3430 Flanges A cid Gas 100 200 44.00 0.00290 0.2552 0 0.2552 1.1178 Compressor Seals A cid Gas 0 0 44.00 0.50270 0 0 0.0000 0.0000 Pump Seals A cid Gas 0 0 44.00 0.03860 0 0 0.0000 0.0000 Relief Valves A cid Gas 2 4 44.00 0.22930 0.4036 0 0.4036 1.7676 Sample Connections A cid 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/componen t lb/h r % lb/h r TPY Valves A cid Gas 0 0 6.20 0.00890 0 0 0.0000 0.0000 Flanges A cid Gas 20 40 6.20 0.00290 0.0072 0 0.0072 0.0315 Compressor Seals A cid Gas 0 0 6.20 0.50270 0 0 0.0000 0.0000 Pump Seals A cid Gas 0 0 6.20 0.03860 0 0 0.0000 0.0000 Relief Valves A cid Gas 0 0 6.20 0.22930 0 0 0.0000 0.0000 Sample Connections A cid 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/componen t lb/h r % lb/h r TPY Valves A cid Gas 0 0 3.30 0.00890 0.0000 0 0.0000 0.0000 Flanges A cid Gas 30 60 3.30 0.00290 0.0057 0 0.0057 0.0251 Compressor Seals A cid Gas 0 0 3.30 0.50270 0 0 0.0000 0.0000 Pump Seals A cid Gas 0 0 3.30 0.03860 0 0 0.0000 0.0000 Relief Valves A cid Gas 0 0 3.30 0.22930 0.0000 0 0.0000 0.0000 Sample Connections A cid 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/componen t lb/h r % lb/h r TPY Valves A cid Gas 0 0 3.60 0.00890 0.0000 0 0.0000 0.0000 Flanges A cid Gas 10 20 3.60 0.00290 0.0021 0 0.0021 0.0091 Compressor Seals A cid Gas 0 0 3.60 0.50270 0 0 0.0000 0.0000 Pump Seals A cid Gas 0 0 3.60 0.03860 0 0 0.0000 0.0000 Relief Valves A cid Gas 0 0 3.60 0.22930 0.0000 0 0.0000 0.0000 Sample Connections A cid 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 Emission Factors Process Stream

Emission Factors Emission Factors Process 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 EfficiencyPage 5 of 6 TSD App A NAME Fugitive Emissions - Greenhouse Gas Emissions Only (from Gasification/SNG and from WSA) Unit ID: FUG & FUG-WS A

CO2 in WSA (FUG-WSA) Total A vera g e Uncontrolled Control Controlled Controlled Emission Sourc e Source Componen t Conc Emission s Total Emission s Efficienc y Total Emission s Total Emission s Process Stream Coun t %w Factor lb/h r lb/h r % lb/h r tpy V alve s A cid Gas 20 42.90 0.0089 0 0.07 6 0.076 4 0.3345 Flan g e s A cid Gas 200 42.90 0.0029 0 0.24 9 0.248 8 1.089 8 Compressor Seal s A cid Gas 0 42.90 0.5027 0 0.00 0 0.000 0 0.000 0 Pump Seal s A cid Gas 0 42.90 0.0386 0 0.00 0 0.000 0 0.000 0 Relief Valve s A cid Gas 4 42.90 0.2293 0 0.393 0.3935 1.723 4 Sample Connection s A cid Gas 8 42.90 0.0330 0 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 T otal Emission s 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 48.577Methane from FUG Page 6 of 6 TSD App A CH4 Uncontrolled Control Controlled Controlled Emission Source Source Component Conc Emissions Factor Total Emissions Efficiency T otal Emission s 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 CO 2 e 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 flarePage 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/m 2 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/m 2 (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 

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##   

16_30464 Calcs H 85 5/3/2012Page 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 tem porary storage, then it must travel 900 feet offsite to c oal yard area, then it trav els 1100 feet in coal yard to drop off and 1100 feet in c oal yard to pick up. (wor se-case total = 600+600+1100+1100 excluding the porti on of travel "o ffsite"/outside t he fenceline.)

Emissions calculated = Emissions factor (lb/vmt) * trip distance (miles) * number of trips * (1-control efficiency) 

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##   

Total Round-Trip Distance: 0.644 mile/trip "Wet" Days, P: 117 days Road Surface Silt Loading, sL: 1.0 g/m 2 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/h r PM2.5 0.00088 lb/hr Potential PM2.5 Emisions: Total PM 0.01801 lb/h r 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/h r 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) 

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##   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

A lso 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      

      Page 1 of 1 TSD App AAlthough Storage Pad is paved, assume it is partially covered in slag, calculate emissions assuming unpaved road equation.Description of Vehicles Load SizeVehicle WeightEmptyAverageVehicleWeightDaily Slag(annualaverage)Max Slagper dayMiles pertripMaximumDaily Ave AnnualMaximumVMTAve. AnnualVMTtons tons tons tons/daytons/dayMile/trip Trips/day Trips/day Miles/day Miles/dayFront End Loader20 32.66 26.33 1,440 2,068 0.0142 103.4 72 1.469 1.023Assume each trip of front end loader trip is 75 feet round trip (1/4 width of pad times 2)AverageVehicle weigh(tons)UncontrolledEmissionsfactor (lbs totalPM/VMT)UncontrolledEmissionsfactor (lbsPM10/VMT)UncontrolledEmissionsfactor (lbsPM2.5/VMT)ControlEfficiencyMax dailylb/hr TotalPMMax dailylb/hr PM10Max dailylb/hr PM2.5Front End Loader/dozer26.33 2.287 0.426 0.043 90% 0.014 0.003 0.000Front End LoaderTotal 0.014 0.003 0.000Max AnnualTons/yrTotal PMMax AnnualTons/yrPM10Max AnnualTons/yrPM2.50.007 0.001 0.000Front End LoaderNote: 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 and beingpicked 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/pileTotal 0.007 0.001 0.000UNPAVED 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 particulateW = Vehicle average weight (tons)P = number of days per year with 0.01 in or more of precipitationINPUTS TO EQUATION/CALCULATIONS Total PM PM10 PM2.5k 4.9 1.5 0.15 lb/vmts1 1 1 %a 0.7 0.9 0.9b 0.45 0.45 0.45P 117 117 117 days/yr312**WsbakE365365PEEextPage 1 of 1 TSD App A 

### Indiana Gasification, LLC Spencer County Facility
Emission Unit:


### FUG

‐ SF6 Emission Estimate for Fugitive Emissions of SF 6 from Circuit Breakers

The IG facility will include a switchyard with circuit breakers that include sulfur hexafluoride (SF 6 ), 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 brea k 6 Amount of SF 6 in each 100 lbs
Assumed leak rate: 1%

Emissions (lb/yr): 6 lbs/yr

GWP of SF 6 : 23,900 CO2e (tons/yr): 71.7 tons/yrBasis: 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 HH V 8760 1.65E-06 4.376E-07 0.000001 9 2.90E-06 7.69E-07 0.000003 4

002 Acid Gas Flare - Nat Gas Pilots 1 1 300 0.27 MMBtu/h HH V 8760 1.65E-06 4.376E-07 0.000001 9 2.90E-06 7.69E-07 0.000003 4

005 Auxiliary Boiler, Full Load Operation - black plant su (nat gas fuel) 1 1 200 816 MMBtu/h HH V 8760 2.55E-07 2.081E-04 0.000907 2 4.90E-07 4.00E-04 0.001744 7

005 Auxiliary Boiler, Full Load Operation (SNG or Nat Gas) 1 1 200 816 MMBtu/h HH V 8760 1.65E-06 1.347E-03 0.005872 5 2.90E-06 2.37E-03 0.010321 7

005 Auxiliary Boiler, Half Load Operation (SNG or Nat Gas) 1 1 200 408 MMBtu/h HH V 0 1.65E-06 6.735E-04 0.002936 3 2.90E-06 1.18E-03 0.005160 8

008 Gasifier Preheat Burners - black p lant su ( nat g as fuel ) 5 5 200 35 MMBtu/h HH V 8760 2.55E-07 8.922E-06 0.000038 9 4.90E-07 1.72E-05 0.000074 8

008 Gasifier Preheat Burners ( one o p eratin g 8 months p er y ear, SNG or NG fuel 5 1 200 18 MMBtu/h HH V 8760 1.65E-06 2.970E-0 5 0.000129 5 2.90E-06 5.22E-05 0.000227 6

009 Emergency Diesel Generators (2 units each tested 1 hour weekly) 2 1 20 1,341 h p 500

010 Diesel Fire Water Pump Engine (3 units each tested 1 hour weekly) 3 1 20 575 h p 500

011 Coal Conveying and Feed Bins Dust Control System Vents 2 1 200 8760 1.244E-06 0.000005 4 2.42E-04 0.001054 6

012 Coal Unloading and Storage (Barge, Rail, Truck) 0.0000000 0.0000000

013 Rod Mill Vent Stacks 4 4 125 8760 0.000000 0 0.000000 0

032 ZLD Spray Drier Stack 1 1 100 5.6 MMBtu/h HH V 8760 1.65E-06 9.294E-06 0.000040 5 2.90E-06 1.63E-05 0.000071 2

033 ZLD Inert Gas Vent 1 1 100 8760 1.404E-07 0.000000 6

015 WSA Preheat 2 1 200 35.0 MMBtu/h HH V 8760 1.65E-06 5.775E-0 5 0.000251 8 2.90E-06 1.02E-04 0.000442 5

015 WSA Stack - black plant su 2 1 213 291 stpd 100% H2SO4 8760 8.348E-11 0.000000 0

015 WSA Stack - One Unit Operation 2 1 213 582 stpd 100% H2SO4 8760 1.670E-10 0.000000 0

015 WSA Stack - Two Unit Operation 2 2 213 1,164 stpd 100% H2SO4 8760 3.339E-10 0.000000 0

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-0 5 0.000139 6 2.90E-06 5.63E-05 0.000245 4

007 Re g en Thermal Oxidizers ( Note 1, Two Units Hot Standb y 80% of the y ear, SNG 1 1 200 10.3 MMBtu/h HHV SNG 0 1.65E-06 1.705E-0 5 0.000074 3 2.90E-06 3.00E-05 0.000130 7

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-0 5 0.000279 2 2.90E-06 1.13E-04 0.000490 7

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 RateIndiana 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 ma x Mercury ma x 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 millsIndiana Gasification, LL C Page 3 of 3 TSD App A

Plant Lead Balance for 125% of design plant operating rat e Natural Gas Combustio n 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 Combustio n 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 ma x Lead ma x stph dry ppm, dry lb/h r 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 Assessme nt 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 l iquid 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 drscfFLARE SOURCES Page 1 of 3 TSD App A

NAME Hydrocarbon / Gasifier Start-up Flare Unit ID: 001

STACK DATA HEIGHT 300 f t DIAMETER 6 f t

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 Pollutan t lb-mol/hr lb-mol/hr lb-mol/hr Mol % lb/hr lb/hr TPY PM

10 -- -- -- -- 6.42 6.42 0.43
PM

2.5 6.02 6.02 0.41
SO 2 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 A P-42 Heating Value = 1,020 Btu/sc f

Average Maximum Annual Emissions Emissions Emissions Pollutan t lb/hr lb/hr TPY PM

10 0.0020 0.0020 0.0087
PM

2.5 0.0019 0.0019 0.0081
SO 2 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 PM

10 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

PM

2.5 0

. 095 6

. 02 0

. 41
SO 2 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-06Calculations: 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, PM 10 , 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) A verage 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/f t 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) A verage Emissions (lb/hr) = Maximum Emissions.

NOx PM 10 VOC 0.100 0.007 0.0001

PM

10 SO 2 7.600 0.60

NO

x 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 A verage Maximum A nnual Emissions Emissions Emissions Pollutan t lb/even t 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 PM 10 for Syngas are based on values from vendor supplied data. VOC for Syngas = 2% of AP-42 Section 1.4 "Natural Gas Combustion" Ta ble 1.4-2

Scenario 2 Factor (lb/MMscf)
Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for PM10.

PM

10 0.260 0.09 0.002
PM

2.5 0.260 0.09 0.002
SO 2 255.62 85.21 1.917 NO

x 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 0.000Page 3 of 3 TSD App A GHG Emissions from Gasifier Start-up

lb/hr TPY MT/y r CO2 for Gasifier Flare = 185,818.1 12,542.7 11378.8

Equation Y-5

N 2

O = Annual nitrous oxide emissions from flared gas (metric ton N 2 O/year)
CO 2

= Emission rate of CO 2 from flared gas calculated (metric ton/year)
EmF N2O = Default N 2 O emission factor for “Petroleum Products” from Table C-2 of subpart C (General Stationary Fuel Combustion Sources) (kg N 2 O/MMBtu) = 0.0006
EmF = Default CO 2 emission factor for flare gas of 60 kg CO 2 /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

CH 4

or N 2 O = Annual CH 4 or N 2 O 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 ba lance was used to determine the CO2 and N2O emissions. There w ill be no CH4 emissions. The GHG S ubpart Y (Refinery) flare equations are not applicable; however, the Subpart Y equation for N2O w ill be used to conservatively estimate N2O emissions.

       

  EmF EmF CO O N O N 2 2 2

EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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.

Pilo

t

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 CO2Hydrocarbon / Gasifier Startup FlareFLARE 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 DAT A HEIGHT 300 ft DIAMETER 1.6 ft

EMISSIONS: A cid Gas Flare Pilot Only hr/yr = 8,760 Pilot Firing Rate = 0.27 MMBtu/hr A P-42 Heating Value = 1,020 Btu/sc f

Average Maximum Annual Emissions Emissions Emissions Pollutant lb/hr lb/hr TPY
PM

10 0.0020 0.0020 0.0087
PM

2.5 0.0019 0.0019 0.0081
SO 2 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/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 (TPY) = Emissions (lb/hr) x (Operating hr/yr / 2000 lb/ton) A verage Emissions (lb/hr) = Maximum Emissions.

PM

10 SO 2 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 5/3/2012Stationary 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

CH 4

or N 2 O = Annual CH 4 or N 2 O 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 y ear 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 EF HHV Fuel CO       3 2 10

1

EF HHV Fuel O orN CH       3 2 4 10 1

17_30464 limited Calcs F 5 5/3/2012COMBUSTION SOURCES Page 1 of 3 TSD App A

NAME Auxiliary Boiler Unit ID: 

### 005A & B

Emissions shown are for sum of tw o (2) boilers each at 408 MMBtu/h r

STACK DAT A 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 DAT A HEAT INPUT - Full rate - Natural Gas 816.33 MM Btu/h r HEAT INPUT - Full rate (Black Start) - Natural Gas 816.33 MM Btu/h r HEAT INPUT - Pilot Gas - Natural Gas 10.00 MM Btu/h r AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft 3 OPERATING HOURS- Full rate - Natural Gas 1752 hr/y r OPERATING HOURS - Full rate (Black Start) - Natural Gas 96 hr/y r

EMISSIONS: Full rate case - Natural Gas lb/hr avg. lb/hr max. TPY PM

10 6.08 6.08 5.33
PM

2.5 6.08 6.08 5.33
SO 2 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 PM

10 6.08 6.08 0.29
PM

2.5 6.08 6.08 0.29
SO 0 48 0 48 0 023

2 . . . 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-05EMISSIONS: Normal Operations Total Page 2 of 3 TSD App A lb/hr avg. lb/hr max. TPY PM

10 1.28 6.08 5.62
PM

2.5 1.28 6.08 5.62
SO 2 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 Fact or (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft 3 ) X Heat Input (MMBtu/hr) Emissions (NOx, CO) (Avg. lb/hr) = Vendor Fa ctor (lb/MM Btu) X Heat Input (MMBtu/hr) Emissions (TPY) = Emissions (lb/h r) x (Operating hr/yr / 2000 lb/ton) Total Emissions (Avg. lb/hr) = Total TPY x 2,000 lb/ton / 8,760 hr/y r Total Emissions (Max. lb/hr) = Highest Ma ximum lb/hr value from either case

PM

10 VOC SO 2 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 Sect ion 1.4, Tables 1.4-3 and 1.4-4. To be conservative SO2 emissions will be ca lculated assuming all scenarios fire natural gas If SNG is fired there will be no S O2 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 conser v ati v

e , SO2 emissions w ill be calc u lated ass u ming all scenarios fire nat u ral gas

. If SNG is fired

, there w ill be no SO2 emissions as SNG is ass u med 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 calculat or for SCCs per Roy Hu ntley (EPA EI and Analysis Group).Page 3 of 3 TSD App A

Stationary Combus tion Sources - Natural Gas (semi-a nnual or more fr equent 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a pa rticular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid measur ements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific defaul t emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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 BoilerCOMBUSTION SOURCES Pa ge 1 of 9 TSD App A

NAME AGR CO2 Regenerative Thermal Oxidizer Unit ID: 

### 007

STACK DAT A 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/h r HEAT INPUT: One Unit at full rate 38.81 MM Btu/h r HEAT INPUT: Black-starts (1 unit at half rate) 19.41 MM Btu/h r AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft 3 OPERATING HOURS: Two Units at full rate 8298 hr/y r OPERATING HOURS: One Unit at full rate 438 hr/y r OPERATING HOURS: Black-start 24 hr/y r

H2S in Waste gas to each RTO = 0.57 lb/h r COS in Waste gas to each RTO = 2.00 lb/h r CO in Waste gas to each RTO: 4673.99 lb/h r 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 PM

10 0.58 0.58 2.40
PM

2.5 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 G as Removal Unit.

Emissions are calculated for both cases (c oal / coke and coal only) and the higher (c onservative) value for each pollutant will be permitted.

SO 2 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 PM

10 0.29 0.29 0.06
PM

2.5 0.29 0.29 0.06
SO 2 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-05EMISSIONS: One Unit at half rate - Conservatively assu me Natural Gas for entire 24 hrs Page 2 of 9 TSD App A

lb/hr avg. lb/hr max. TPY PM

10 0.14 0.14 0.0017
PM

2.5 0.14 0.14 0.0017
SO 2 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
PM

10 0.56 0.58 2.46
PM

2.5 0.56 0.56 2.46
SO 2 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 (PM 10

) (Avg. lb/hr) = AP-42 Factor (lb/MMscf)/ AP-42 Natural Gas Heat Value (Btu/ft 3 ) 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/ft 3 ) X Heat Input (MMBtu/hr) Emissions (NOx) (Avg. lb/hr) = Vendor Fact or (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 = Su m of individual cases Emissions (Avg. lb/hr) Total = TPY Total X 2,000 (lb/T) / (Total Hrs Operation)

Natural Gas Combustion PM 10 VOC SO 2 HAP
7.60 5.50 0.6 1.89

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM 10

Natural Gas Combustion NOx CO 0.05 0.036

Comments: Factor (lb/MM scf)

Factor (lb/MMBtuf)

SO 2 emissions based on 98% conversion of sulfur in waste gas to SO 2 . Assumes sulfur content in natural gas of 2,000 grains/10^6 scf (<5 ppmv of H2S). During "normal operations" the thermal oxid izer burns SNG (which contai ns no sulfur); during a bla ck-start, it fires natural ga s 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 calculat or for SCCs per Roy H untley (EPA EI and Analysis Group). Total HAPs are based on AP-42 Secti on 1.4, Tables 1.4-3 and 1.4-4. Source: Emission factors for NOx and CO are based on information from vendor supp lied 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/h r HEAT INPUT: One Unit at full rate 31.35 MM Btu/h r HEAT INPUT: Black-starts (1 unit at half rate) 15.67 MM Btu/h r AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft 3 OPERATING HOURS: Two Units at full rate 8298 hr/y r OPERATING HOURS: One Unit at full rate 438 hr/y r OPERATING HOURS: Black-start 24 hr/y r

H2S in Waste gas to each RTO = 0.56 lb/h r COS in Waste gas to each RTO = 1.97 lb/h r CO in Waste gas to each RTO: 4595.57 lb/h r Total Sulfur in Waste gas to each RTO: 1.58 lb/hr Methanol in Waste Gas to each RTO: 78.86 lb/h r

H2S and COS DRE: 98 % CO and Methanol DRE: 99 %

EMISSIONS: Two Units at Full Rate lb/hr avg. lb/hr max. TPY PM

10 0.47 0.47 1.94
SO 2 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 PM

10 0.23 0.23 0.05
SO 2 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-05EMISSIONS: One Unit at half rate - Conservatively assume Natura l Gas (for SO2) and SNG (for Hg) for entire 24 hrs Page 5 of 9 T SD App A

lb/hr avg. lb/hr max. TPY PM

10 0.12 0.12 0.0014
SO 2 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 PM

10 0.45 0.47 1.99
SO 2 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 PM 10 VOC SO 2 HAP
7.60 5.50 0.6 1.89

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM 10

Natural Gas Combustion NOx CO 0.05 0.036 Factor (lb/MM scf)

Factor (lb/MMBtu)

Natural Gas SNG 1.95E-07 1.68E-06 Mercury Factor (lb/MMBtu)Page 6 of 9 TSD App A Stationary Combus tion Sources - Natural Gas (semi-a nnual or more fr equent 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid meas urements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific default emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

all valid samples for the year A verage 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 CO2ePage 7 of 9 TSD App A Coal Only Case

COMBUSTION DATA HEAT INPUT: Two Units at full rate 77.62 MM Btu/h r HEAT INPUT: One Unit at full rate 38.81 MM Btu/h r HEAT INPUT: Black-starts (1 unit at half rate) 19.41 MM Btu/h r AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft 3 OPERATING HOURS: Two Units at full rate 8298 hr/y r OPERATING HOURS: One Unit at full rate 438 hr/y r OPERATING HOURS: Black-start 24 hr/y r

H2S in Waste gas to each RTO = 0.57 lb/h r COS in Waste gas to each RTO = 2.00 lb/h r CO in Waste gas to each RTO: 4673.99 lb/h r Total Sulfur in Waste gas to each RTO: 1.60 lb/hr Methanol in Waste Gas to each RTO: 80.20 lb/h r

H2S and COS DRE: 98 % CO and Methanol DRE: 99 %

EMISSIONS: Two Units at Full Rate (100%) lb/hr avg. lb/hr max. TPY PM

10 0.58 0.58 2.40
SO 2 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 PM

10 0.29 0.29 0.06
SO 2 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-05EMISSIONS: One Unit at half rate (25%) - C onservatively assume Natural Gas (for SO2) and SNG (for Hg) for entire 24 hrs Page 8 o f 9 TSD App A

lb/hr avg. lb/hr max. TPY PM

10 0.14 0.14 0.0017
SO 2 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 PM

10 0.56 0.58 2.46
SO 2 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 PM 10 VOC SO 2 HAP
7.60 5.50 0.6 1.89

Source: AP-42 (7/98), Section 1.4, Table 1.4-2 for VOC and PM 10

Natural Gas Combustion NOx CO 0.05 0.036 Factor (lb/MM scf)

Factor (lb/MMBtu)

Natural Gas SNG 1.95E-07 1.61E-06 Mercury Factor (lb/MMBtu)Page 9 of 9 TSD App A Stationary Combus tion Sources - Natural Gas (semi-a nnual or more fr equent 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a pa rticular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid meas urements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific defaul t emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

valid samples for the year A verage 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/y rCOMBUSTION 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/h r HEAT INPUT: Black Start 35.00 MM Btu/h r AP-42 NATURAL GAS HEAT VALUE 1020 Btu/ft 3
OPERATING HOURS -Normal Case 1168 hr/y r OPERATING HOURS -Black Starts 28.8 hr/y r

EMISSIONS: Normal Case lb/hr avg. lb/hr max. TPY PM

10 0.013 0.013 0.0078
PM

2.5 0.013 0.013 0.0073
SO

2 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 PM

10 0.026 0.026 0.00038
PM

2.5 0.024 0.024 0.00035
SO

2 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/ft 3 ) 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/h r) x (Operating hr/yr / 2000 lb/ton) A verage Emissions (lb/hr) = Maximum Emissions.

Natural Gas Combustion SO 2 0.6

Natural Gas Combustion PM 10 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. A ssumes sulfur content in natural gas of 2,000 grains/10^6 scf (< 5 ppmv of H2S). Natural gas or SNG may be combusted. Conservatively assum ed 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 PM 10 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 aver age 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

CH 4

or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons) Fuel = Mass or volume of the fuel combusted during the reporting yea r 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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 CO2COMBUSTION SO URCES P age 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/ft 3
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
PM

10 0.013 0.013 0.0078
PM

2.5 0.013 0.013 0.0073
SO 2 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
PM

10 0.026 0.026 0.00038
PM

2.5 0.024 0.024 0.00035
SO 2 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/ft 3 ) 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 SO 2 0.6

Natural Gas Combustion PM 10 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

CH 4

or N 2 O = Annual CH 4 or N 2 O 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

GHG Pollutant GHG Metric Tons GWP Factors M e t r i c

T ons CO2e CO2 1,168 1 1,168 CH4 0.0 21 0 N2O 0.0 310 1 TOTAL = 1,169 1,289 TPY CO2COMBUSTION SO URCES P age 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/ft 3
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
PM

10 0.013 0.013 0.0078
PM

2.5 0.013 0.013 0.0073
SO 2 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
PM

10 0.026 0.026 0.00038
PM

2.5 0.024 0.024 0.00035
SO 2 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/ft 3 ) 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 SO 2 0.6

Natural Gas Combustion PM 10 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

CH 4

or N 2 O = Annual CH 4 or N 2 O 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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 CO2COMBUSTION SO URCES P age 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/ft 3
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
PM

10 0.013 0.013 0.0078
PM

2.5 0.013 0.013 0.0073
SO 2 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
PM

10 0.026 0.026 0.00038
PM

2.5 0.024 0.024 0.00035
SO 2 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/ft 3 ) 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 SO 2 0.6

Natural Gas Combustion PM 10 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

CH 4

or N 2 O = Annual CH 4 or N 2 O 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

GHG Pollutant G H G 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 CO2COMBUSTION SO URCES P age 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/ft 3
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
PM

10 0.013 0.013 0.0078
PM

2.5 0.013 0.013 0.0073
SO 2 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
PM

10 0.026 0.026 0.00038
PM

2.5 0.024 0.024 0.00035
SO 2 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/ft 3 ) 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 SO 2 0.6

Natural Gas Combustion PM 10 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

CH 4

or N 2 O = Annual CH 4 or N 2 O 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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 CO2COMBUSTION SOURCES Pa ge 1 of 4 TSD App A

NAME Emergency Diesel Power Generator A Unit ID: 

### 009 A

COMBUSTION DAT A FUEL TYPE Diesel ENGINE SIZE 1,341 HP HOURS OF OPERATION 52 hr/y r

EMISSIONS avg lb/h r lb/hr max. TP Y PM

10 0.06 0.06 0.0015
PM

2.5 0.06 0.06 0.0014
SO 2 0.015 0.015 0.00039
NO

X 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)

PM

10 SO 2 NO X 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 us e 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 calculat or for SCCs per Roy H untley (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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid measur ements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific defaul t emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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. A ssumed Fuel at 100% Load = 41.6 gal/hr.COMBUSTION SOURCES Pag e 3 of 4 TSD App A

NAME Emergency Diesel Power Generator B Unit ID: 

### 009 B

COMBUSTION DAT A FUEL TYPE Diesel ENGINE SIZE 1,341 HP HOURS OF OPERATION 52 hr/y r

EMISSIONS avg lb/h r lb/hr max. TP Y PM

10 0.06 0.06 0.0015
PM

2.5 0.06 0.06 0.0014
SO 2 0.015 0.015 0.00039
NO

X 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 (L B/HR) X (Hours of operation/2000)

PM

10 SO 2 NO X 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 us e source assumed to be negligable PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculat or for SCCs per Roy Hunt ley (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 di esel 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a pa rticular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid meas urements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific defaul t emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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. A ssumed 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 DAT A FUEL TYPE Diesel ENGINE SIZE 575 HP HOURS OF OPERATION 52 hr/y r

EMISSIONS avg lb/h r lb/hr max. TP Y PM

10 0.108 0.108 0.0028
PM

2.5 0.101 0.101 0.0026
SO 2 0.0061 0.0061 0.00016
NO

X 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 (L B/HR) X (Hours of operation/2000)

PM

10 SO 2 NO X 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 us e source assumed to be negligable PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculat or for SCCs per Roy H untley (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 di esel 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a pa rticular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid measur ements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific defaul t emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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. A ssumed 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 DAT A FUEL TYPE Diesel ENGINE SIZE 575 HP HOURS OF OPERATION 52 hr/y r

EMISSIONS avg lb/h r lb/hr max. TP Y PM

10 0.108 0.108 0.0028
PM

2.5 0.101 0.101 0.0026
SO 2 0.0061 0.0061 0.00016
NO

X 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 (L B/HR) X (Hours of operation/2000)

PM

10 SO 2 NO X 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 us e source assumed to be negligable PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculat or for SCCs per Roy H untley (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 di esel 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a pa rticular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid measur ements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific defaul t emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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. A ssumed 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 DAT A FUEL TYPE Diesel ENGINE SIZE 575 HP HOURS OF OPERATION 52 hr/y r

EMISSIONS avg lb/h r lb/hr max. TP Y PM

10 0.108 0.108 0.0028
PM

2.5 0.101 0.101 0.0026
SO 2 0.0061 0.0061 0.00016
NO

X 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 (L B/HR) X (Hours of operation/2000)

PM

10 SO 2 NO X 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 us e source assumed to be negligable PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculat or for SCCs per Roy H untley (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 di esel 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a pa rticular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid measur ements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific defaul t emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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. A ssumed 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.

A

verage Maximum A nnual PM 10 A nnual PM 2.5 Emissions Hourly Emissions Emissions Unit ID Name dscfm gr/dsc f lb/hr lb/hr TPY TPY

011 A System 1A -- Coal-Coke Handling S y

stem 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 ba ghouses.

PM

10

EMISSIONS Exhaust Air Flow per filter Filter PM 10 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 5/3/2012URS INDIANA GASIFICATION FACILITY Vent Calculations

Height of Pile s 90 ft Diameter of Pile s 539 ft

A verage Maximum A nnual Factor A verage Maximum A nnual Emissions Hourly Emissions PM Total/ Emissions Hourly Emissions Unit ID Name lb/h r lb/h r TP Y lb/h r lb/h r TP Y 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/P M10, 0.0015 gr/dscf PM2.5

. Total PM Emissions (Calc. here) VENT SOURCE S

The following are the sources related to solids unloading (barge and rail car) and handling, including coke and coal piles.

PM

10 EMISSIONS Process Rate Emission Factor Control Type Control Efficiency Operating Hours

17_30464 limited Calcs D 39 5/3/2012URS INDIANA GASIFICATION FACILITY Vent Calculations

VENT SOURCE S

A verage Maximum A nnual Emissions Hourly Emissions Unit ID Name lb/h r lb/h r TP Y 012 A Bar g e Unload to Ho pp

e r 750 TPH 0.000084 lb/ton WET SUPPRESSIO N 85.0% 2,678 0.0095 0.0095 0.013 012 B Bar g e Unload Ho pp

er to Bel t 1,500 A CFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTE R 99.14% 2,678 0.019 0.019 0.026 012 C Bar g e Conve y or Transfer Dro p 1,500 A CFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTE R 99.14% 2,678 0.019 0.019 0.026 012 D Bar g e Conve y or Transfer Dro p 1,500 A CFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTE R 99.14% 2,678 0.019 0.019 0.026 012 E Bar g e Conve y or Transfer Dro p 1,500 A CFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTE R 99.14% 2,678 0.019 0.019 0.026 012 F Bar g e Conve y or Transfer Dro p 1,500 A CFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTE R 99.14% 2,678 0.019 0.019 0.026 012 G Rail Unload 1 to Ho pp

e r 1,500 A CFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTE R 99.14% 663 0.019 0.019 0.006 012 H Rail Unload 2 to Ho pp

e r 1,500 A CFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTE R 99.14% 663 0.019 0.019 0.006 012 I Rail Unload Ho pp

er 1 to Bel t 1,500 A CFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTE R 99.14% 663 0.019 0.019 0.006 012 J Rail Unload Ho pp

er 2 to Bel t 1,500 A CFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTE R 99.14% 663 0.019 0.019 0.006 012 K Rail Unload Belts 1 & 2 to Stacker Belt 1 1,500 A CFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTE R 99.14% 663 0.019 0.019 0.006 012 L Stacker Belt 1 to Radial Stacker ( Pile1 ) 1,500 A CFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTE R 99.14% 2,002 0.019 0.019 0.019 012 M Stacker Belt 2 from Radial Stacker ( Pile 1 ) 1,500 A CFM 0.175000 GR/ACFM DUST EXTRACTION SYSTEM or FILTE R 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 CHUT E 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 CHUT E 99.9% 2,002 0.00025 0.00025 0.00025 012 P Dozer Activit y on Pile 1 1,500 TPH 0.024 lb/h r WET SUPPRESSIO N 90.0% 4,380 0.002 0.005 0.005 012 Q Dozer Activit y on Pile 2 1,500 TPH 0.024 lb/h r WET SUPPRESSIO N 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 A CFM 0.18 GR/ACFM DUST EXTRACTION SYSTEM or FILTE R 99.14% 2,708 0.019 0.019 0.026 012 U CLASSIFICATION TOWER #2 1,500 A CFM 0.18 GR/ACFM DUST EXTRACTION SYSTEM or FILTE R 99.14% 2,708 0.019 0.019 0.026 012 V Classification Towers to Da y Bin 1,500 A CFM 0.18 GR/ACFM DUST EXTRACTION SYSTEM or FILTE R 99.14% 2,708 0.019 0.019 0.026 012 W Wind Erosion Pile 1 300,000 Tons 0.229 lb/h r WET SUPPRESSION/COMPACTIO N 90.0% 8,760 0.023 0.023 0.10 012 X Wind Erosion Pile 2 300,000 Tons 0.190 lb/h r WET SUPPRESSION/COMPACTIO N 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/P M10, 0.0015 gr/dscf PM2.5

. PM

2.5 EMISSIONS Process Rate Emission Factor Control Type Control Efficiency Operating Hours

17_30464 limited Calcs D 40 5/3/2012URS INDIANA GASIFICATION FACILITY Vent Calculations

VENT SOURCE S

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 A P 0.35 Factor to c 2.114

Wind Erosion From Piles - Total Particulate Factor for Alternative Method from W R 1.0 - PM10 factor for Alternative Method from WRAP docu m 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. A ll outlet PM is conservatively assumed to be PM10, therefore total PM = PM10

.

17_30464 limited Calcs D 41 5/3/2012Page 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

PM

10

EMISSIONS A verage Maximum A nnual PM 10 A nnual PM 2.5 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 5/3/2012VENT SOURCES P age 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/h r AP-42 NATURAL GAS HEAT VALUE 1,020 Btu/ft 3 OPERATING HOURS: Two Unit Operation 8,298 hr/y r OPERATING HOURS: One Unit Operation 438 hr/y r OPERATING HOURS: Black-start 24 hr/y r OPERATING HOURS: Preheat 60 hr/y r

EMISSIONS: Full Rate lb/hr avg. lb/hr max. TPY SO 2 8.30 8.30 34.44

NOx 10.17 10.17 42.20
CO 18.72 18.72 77.69 H 2

SO 4 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/y r lb/hr avg. lb/hr max. TPY SO 2 4.15 4.15 0.91

NOx 5.09 5.09 1.11
CO 9.36 9.36 2.05 H 2

SO 4 2.50 2.50 0.55 Mercury (HAP) 3 3E 10 3 3E 10 7 3E 11 3

. 3E

- 10 3

. 3E

- 10 7

. 3E

- 11

EMISSIONS: Half Rate (including Black Start) lb/hr avg. lb/hr max. TPY SO 2 2.08 2.08 0.02

NOx 2.54 2.54 0.03
CO 4.68 4.68 0.06 H 2

SO 4 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
PM

10 0.03 0.03 0.0008
PM

2.5 0.02 0.02 0.0006
SO 2 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-06EMISSIONS: Normal Operations Total Page 2 of 9 TSD App A lb/hr avg. lb/hr max. TPY PM

10 0.00018 0.03 0.0008
PM

2.5 0.00015 0.02 0.0006
SO 2 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 H 2

SO 4 4.86 5.00 21.29
PM

2.5 including H 2 SO 4 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.

PM

10 VOC SO 2 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 g rains/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/ft 3 ) 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/h r 1,020 Btu/ft 3 Full Rate 8,298 hr/y r Half Rate 438 hr/y r Black Start 24 hr/y r Preheat 60 hr/y r

EMISSIONS: Full Rate lb/hr avg. lb/hr max. TPY SO 2 8.30 8.30 34.44 NOx 10.17 10.17 42.20 CO 18.72 18.72 77.69
H 2

SO 4 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/y r lb/hr avg. lb/hr max. TPY SO 2 4.15 4.15 0.91 NOx 5.09 5.09 1.11 CO 9.36 9.36 2.05 H 2

SO 4 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 SO 2 2.08 2.08 0.02 NOx 2.54 2.54 0.03 CO 4.68 4.68 0.06 H 2

SO 4 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

. . PM

10 0.03 0.03 0.0008
SO 2 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

PM

10 VOC SO 2 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 C ase: 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons) Fuel = Mass or volume of the fuel combusted during the reporting yea r 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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

sam p les for the y ea r Annual Average 0.00102 MMBtu per scf

GHG WSA Preheat

Burners EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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/h r CO2% = 6.60% CO2 MW = 44.01 lb/lb-mole CO2 Emissions = 42,209 lb/h r 179,875 TPY CO2 18% Contingency due to lack of performance guarantee 212,999 TPY CO2Page 7 of 9 TSD App A Coal Only Case

35.00 MM Btu/h r 1,020 Btu/ft 3 Full Rate 8,298 hr/y r Half Rate 438 hr/y r Black Start 24 hr/y r Preheat 60 hr/y r

EMISSIONS: Full Rate lb/hr avg. lb/hr max. TPY SO 2 7.57 7.57 31.40 NOx 7.40 7.40 30.72 CO 13.63 13.63 56.54
H 2

SO 4 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/y r lb/hr avg. lb/hr max. TPY SO 2 3.78 3.78 0.83 NOx 3.70 3.70 0.81 CO 6.81 6.81 1.49 H 2

SO 4 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 SO 2 1.89 1.89 0.02 NOx 1.85 1.85 0.02 CO 3.41 3.41 0.04 H 2

SO 4 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

. . PM

10 0.03 0.03 0.0008
SO 2 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

PM

10 VOC SO 2 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 C ase: 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons) Fuel = Mass or volume of the fuel combusted during the reporting yea r 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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

sam p les for the y ea r Annual Average 0.00102 MMBtu per scf

GHG GHG GWP Metric Tons WSA Preheat

Burners EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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/h r CO2% = 10.262% CO2 MW = 44.01 lb/lb-mole CO2 Emissions = 46,941 lb/h r 200,039 TPY CO2 18% Contingency due to lack of performance guarantee 236,877 TPY CO2VENT SOURCES P age 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/h r AP-42 NATURAL GAS HEAT VALUE 1,020 Btu/ft 3 OPERATING HOURS: Two Unit Operation 8,298 hr/y r OPERATING HOURS: One Unit Operation 438 hr/y r OPERATING HOURS: Black-start 24 hr/y r OPERATING HOURS: Preheat 60 hr/y r

EMISSIONS: Full Rate lb/hr avg. lb/hr max. TPY SO 2 8.30 8.30 34.44

NOx 10.17 10.17 42.20
CO 18.72 18.72 77.69 H 2

SO 4 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/y r lb/hr avg. lb/hr max. TPY SO 2 4.15 4.15 0.91

NOx 5.09 5.09 1.11
CO 9.36 9.36 2.05 H 2

SO 4 2.50 2.50 0.55 Mercury (HAP) 3 3E 10 3 3E 10 7 3E 11 3

. 3E

- 10 3

. 3E

- 10 7

. 3E

- 11

EMISSIONS: Half Rate (including Black Start) lb/hr avg. lb/hr max. TPY SO 2 2.08 2.08 0.02

NOx 2.54 2.54 0.03
CO 4.68 4.68 0.06 H 2

SO 4 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
PM

10 0.03 0.03 0.0008
PM

2.5 0.02 0.02 0.0006
SO 2 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-06EMISSIONS: Normal Operations Total Page 2 of 9 TSD App A lb/hr avg. lb/hr max. TPY PM

10 0.00018 0.03 0.0008
PM

2.5 0.00015 0.02 0.0006
SO 2 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 H 2

SO 4 4.86 5.00 21.29
PM

2.5 including H 2 SO 4 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.

PM

10 VOC SO 2 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/ft 3 ) 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/h r 1,020 Btu/ft 3 Full Rate 8,298 hr/y r Half Rate 438 hr/y r Black Start 24 hr/y r Preheat 60 hr/y r

EMISSIONS: Full Rate lb/hr avg. lb/hr max. TPY SO 2 8.30 8.30 34.44 NOx 10.17 10.17 42.20 CO 18.72 18.72 77.69
H 2

SO 4 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/y r lb/hr avg. lb/hr max. TPY SO 2 4.15 4.15 0.91 NOx 5.09 5.09 1.11 CO 9.36 9.36 2.05 H 2

SO 4 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 SO 2 2.08 2.08 0.02 NOx 2.54 2.54 0.03 CO 4.68 4.68 0.06 H 2

SO 4 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

. . PM

10 0.03 0.03 0.00078
SO 2 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

PM

10 VOC SO 2 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons) Fuel = Mass or volume of the fuel combusted during the reporting yea r 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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/h r CO2% = 6.60% CO2 MW = 44.01 lb/lb-mole CO2 Emissions = 42,209 lb/h r 179,875 TPY CO2 18% Contingency due to lack of performance guarantee 212,999 TPY CO2Page 7 of 9 TSD App A Coal Only Case

35.00 MM Btu/h r 1,020 Btu/ft 3 Full Rate 8,298 hr/y r Half Rate 438 hr/y r Black Start 24 hr/y r Preheat 60 hr/y r

EMISSIONS: Full Rate lb/hr avg. lb/hr max. TPY SO 2 7.57 7.57 31.40 NOx 7.40 7.40 30.72 CO 13.63 13.63 56.54
H 2

SO 4 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/y r lb/hr avg. lb/hr max. TPY SO 2 3.78 3.78 0.83 NOx 3.70 3.70 0.81 CO 6.81 6.81 1.49 H 2

SO 4 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 SO 2 1.89 1.89 0.02 NOx 1.85 1.85 0.02 CO 3.41 3.41 0.04 H 2

SO 4 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

. . PM

10 0.03 0.03 0.00078
SO 2 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

PM

10 VOC SO 2 7.600 5.50 0.60

NOx CO
0.110 0.056

Natural Gas SNG (Coal Only)

1.95E-07 1.61E-06 Mercury Factor (lb/MMBtu) 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 CombustionPage 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a particular type of fuel (metric tons) Fuel = Mass or volume of the fuel combusted during the reporting yea r 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 CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O per m 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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/h r CO2% = 10.262% CO2 MW = 44.01 lb/lb-mole CO2 Emissions = 46,941 lb/h r 200,039 TPY CO2 18% Contingency due to lack of performance guarantee 236,877 TPY CO2Page 1 of 2 TSD A

NAME 

### ASU Cooling Water Tower CAP Unit ID:

Evaporative Cooler Operating Parameters Emissions Emi s 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 PM 10. 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 rat e cannot exceed the CAP value, regardless of the number of cells in operation. Therefore, the emissions listed above are the capped tot al 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).A pp A



### 016a

s sions PM2.5 TPY 0.70Page 2 of 2 TSD A

NAME 

### Main Cooling Water Tower CAP Unit ID:

Evaporative Cooler Operating Parameters Emissions Emi s 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 PM 10. 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 r ate cannot exceed the CAP value, regardless of the number of cells in operation. Therefore, the emissions listed above are the capped tot al 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).A pp A



### 016b

s sions PM2.5 TPY 5.19Page 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

PM

10

EMISSIONS A verage Maximum A nnual PM 10 A nnual PM 2.5 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 5/3/2012Page 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)



#     3 12 * * 

### W

s b a k E  

##      



 

## 365 365 P E E extPage 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 Tr ucks = 50 t ons, Limestone Tr ucks = 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)



#     3 12 * * 

### W

s b a k E  

##      



 

## 365 365 P E E extUNCONTROLLEDAVERAGE* EMISSION UNPAVED UNCONTROLLED Trucks TrucksTYPES OF TRUCKS TRUCK FACTOR PRECIPITATION EMISSION FACTOR Trips TripsWEIGHT UNPAVED CORRECTION UNPAVED per day per hourTONS lb/VMT lb/VMTCOAL PILE DOZER OPERATIONS41.38 4.868 0.68 3.33 155 12.9ASSUMPTIONSCAT 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 12.9Emission Calculation for Dozer Activity on the pile [EU-012P & EU-012Q / Total Particulate]70Unpaved 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).70Ave DailyMILES MILES ON-SITE VMT/DAY UNCONTROLLED PERCENT CONTROLLED CONTROLLEDROUND TRIP ROUND TRIP UNPAVED EMISSIONS CONTROL EMISSIONS EMISSIONSPAVED UNPAVED LBS/DAY LBS/DAYLBS/HR*each trip0 0.05105 7.91 26.4 90% 2.6357 0.1098UNPAVED ROADS EQUATIONSE = 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 precipitations = surface material silt content (%)a = constant based on size of particulatebconstant based on size of particulateEmission Calculation for Dozer Activity on the pile [EU-012P & EU-012Q / Total Particulate]312**WsbakE365365PEEext71b = constant based on size ofparticulateW = Vehicle average weightINPUTSk 4.9 lb/VMTP 115 wet days/yrs 2.2 % AP-42 13.2.4-1a 0.7b 0.45P 115 days71CONTROLLEDEMISSIONSTons/yr0.481072Emissions 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.wr apair.org/forums/dejf/fdh/content/C h9-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]Page 1 of 2 TSD App A6.23 acres271,379 ft^2top height = 203top diameter = 150top slant = 135.62√[(topheight‐pileheight)^2+(topdiameter/2)^2]pile height = 90pile diameter = 539pile slant = 337.40√[(topheight)^2+(pilediameter/2)^2]Surface area truncated cone = SA of whole cone - SA of top/removed cone + area of top.5.18 acres225,647 ft^2top height = 186top diameter = 150top slant = 135.62√[(topheight‐pileheight)^2+(topdiameter/2)^2]pile height = 73pile diameter = 494pile slant = 309.20√[(topheight)^2+(pilediameter/2)^2]coal pile surface area =coke pile surface area =2tttpprsrsrSA 



17_30464 limited CalcsD 745/3/2012Page 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 231.87 269.43 269.43 269.43 FT OUTSIDE PILE DIAMETER 463.74 538.85 538.85 538.85 FT PI*R*R 168,901.00 228,051.00 228,051.00 228,051.00 SQ FT HEIGHT OF TOTAL CONE 174.74 203.04 203.04 203.04 FT TOTAL CONE CAPACITY 9,837,695.00 15,434,491.70 15,434,491.70 15,434,491.70 CU FT TOP CONE RADIUS 135.00 150.00 150.00 150.00 FT PI*R*R 57,255.50 70,685.80 70,685.80 70,685.80 HEIGHT OF TOP CONE 101.74 113.04 113.04 113.04 FT TOP CONE CAPACITY 1,941,649.00 2,663,441.00 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 91,761.00 113,130.00 113,130.00 113,130.00 CU FT NET CAPACITY 7,804,285.00 12,657,920.70 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 366,801,395.00 632,896,035.00 632,896,035.00 632,896,035.00 LBS 2,000.00 2,000.00 2,000.00 2,000.00 LBS/TON NET CAPACITY 183,400.70 316,448.00 316,448.00 316,448.00 TONS AREA OF PILE 168,901.25 228,050.64 228,050.64 228,050.64 SQ FT AREA OF PILE 3.88 5.24 5.24 5.24 ACRES
DAYS STORAGE 44.87 33.08 38.92 64.86 DAYS each Coal Consumption (100% fuel) 9,565.00 8,131.10 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 5/3/2012COMBUSTION SOURCES Page 1 of 2 TSD App A

NAME ZLD Spray Dryer Stack Unit ID: 

### 032

STACK DAT A HEIGHT 100 ft DIAMETER 1 ft GAS EXIT TEMP 310 °F GAS EXIT VELOCITY 35.49 fps

COMBUSTION DAT A HEAT INPUT 5.6 MM Btu/h r AP-42 NATURAL GAS HEAT VALUE 1,020 Btu/ft 3
PROCESS FLOW RATE 2,735 dscfm OPERATING HOURS 8,760 hr/y r

EMISSIONS: lb/hr avg. lb/hr max. TPY PM

10 0.12 0.12 0.51
PM

2.5 0.11 0.11 0.48
SO 2 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/ft 3 ) X Heat Input (MMBtu/hr) Emissions (NOx, CO, VOC) (Avg. lb/hr) = Vendor Fa ctor (lb/MM Btu/hr) x Heat Input (MMBtu/hr)

Emissions (TPY) = Emissions (lb/h r) x (Operating hr/yr / 2000 lb/ton) A verage Emissions (lb/h r) = Maximum Emissions.

Natural Gas Combustion SO 2 Fabric Filter PM 10 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. C onservatively assumed natural gas for SO2 calculation (as SNG contains no sulfur). Total HAPs are based on AP-42 Sect ion 1.4, Tables 1.4-3 and 1.4-4. PM2.5 emissions ratioed from PM10 emissions. Ratios are from EPAs PM calculat or for SCCs per Roy Hu ntley (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 Combus tion Sources - Natural Gas (semi-a nnual or more fr equent 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

CH 4 or N 2 O = Annual CH 4 or N 2 O emissions from the combustion of a pa rticular type of fuel (metric tons)
Fuel = Mass or volume of the fuel combusted during the reporting yea r HHV = High heat value of the fuel, averaged for all valid measur ements for the reporting year (MMBtu per mass or volume) EF = Fuel-specific defaul t emission factor for CH 4 or N 2 O, from Table C-2 = (kg CH 4 or N 2 O 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 EF HHV Fuel CO       3 2 10 1

EF HHV Fuel O orN CH       3 2 4 10 1

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

A

verage Maximum A verage Annual A verage 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, al l 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 5/3/2012Basis 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 = 1.8879 6 0.0018 5 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, Append ix 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. FactorPage 2 of 2 TSD App A

EMISSION FACTOR BASED INVENTOR Y 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, Append ix 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

TotalPage 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/componen t lb/h r % lb/h r 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 Com p ressors 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 Sam p lin

g Connections A ll 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/componen t lb/h r % lb/h r 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 Com p ressors 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 Sam p lin

g Connections A ll 1 0.033 0.033 97 0.001 0.004 Total VOCs 399 0.28 1.23

Carbonyl Sulfide

COS Conc %v lb/hr/componen t lb/h r % lb/h r 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 Emissions Process 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 EfficiencyCarbon Monoxide Page 2 of 6 TSD App A

CO Conc

%v lb/hr/componen t lb/h r % lb/h r 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/componen t lb/h r % lb/h r 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 EfficiencyAmmonia Page 3 of 6 TSD App A

NH3 Conc

%v lb/hr/componen t lb/h r % lb/h r 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. Controlled Emissions Emission Factors Control Efficiency Uncontrolled Emissions Component

Count Process Stream Fugitive SourcePage 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/componen t lb/h r % lb/h r TPY Valves A cid Gas 10 20 44.00 0.00890 0.0783 0 0.0783 0.3430 Flanges A cid Gas 100 200 44.00 0.00290 0.2552 0 0.2552 1.1178 Compressor Seals A cid Gas 0 0 44.00 0.50270 0 0 0.0000 0.0000 Pump Seals A cid Gas 0 0 44.00 0.03860 0 0 0.0000 0.0000 Relief Valves A cid Gas 2 4 44.00 0.22930 0.4036 0 0.4036 1.7676 Sample Connections A cid 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/componen t lb/h r % lb/h r TPY Valves A cid Gas 0 0 6.20 0.00890 0 97 0.0000 0.0000 Flanges A cid Gas 20 40 6.20 0.00290 0.0072 97 0.0002 0.0009 Compressor Seals A cid Gas 0 0 6.20 0.50270 0 0 0.0000 0.0000 Pump Seals A cid Gas 0 0 6.20 0.03860 0 85 0.0000 0.0000 Relief Valves A cid Gas 0 0 6.20 0.22930 0 100 0.0000 0.0000 Sample Connections A cid 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/componen t lb/h r % lb/h r TPY Valves A cid Gas 0 0 3.30 0.00890 0.0000 0 0.0000 0.0000 Flanges A cid Gas 30 60 3.30 0.00290 0.0057 0 0.0057 0.0251 Compressor Seals A cid Gas 0 0 3.30 0.50270 0 0 0.0000 0.0000 Pump Seals A cid Gas 0 0 3.30 0.03860 0 0 0.0000 0.0000 Relief Valves A cid Gas 0 0 3.30 0.22930 0.0000 0 0.0000 0.0000 Sample Connections A cid 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/componen t lb/h r % lb/h r TPY Valves A cid Gas 0 0 3.60 0.00890 0.0000 0 0.0000 0.0000 Flanges A cid Gas 10 20 3.60 0.00290 0.0021 0 0.0021 0.0091 Compressor Seals A cid Gas 0 0 3.60 0.50270 0 0 0.0000 0.0000 Pump Seals A cid Gas 0 0 3.60 0.03860 0 0 0.0000 0.0000 Relief Valves A cid Gas 0 0 3.60 0.22930 0.0000 0 0.0000 0.0000 Sample Connections A cid 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 Emission Factors Process Stream

Emission Factors Emission Factors Process StreamPage 5 of 6 TSD App A NAME Fugitive Emissions - Greenhouse Gas Emissions Only (from Gasification/SNG and from WSA) Unit ID: FUG & FUG-WS A

CO2 in WSA (FUG-WSA) Total A vera g e Uncontrolled Control Controlled Controlled Emission Sourc e Source Componen t Conc Emission s Total Emission s Efficienc y Total Emission s Total Emission s Process Stream Coun t %w Factor lb/h r lb/h r % lb/h r tpy V alve s A cid Gas 20 42.90 0.0089 0 0.07 6 0.076 4 0.3345 Flan g e s A cid Gas 200 42.90 0.0029 0 0.24 9 0.248 8 1.089 8 Compressor Seal s A cid Gas 0 42.90 0.5027 0 0.00 0 0.000 0 0.000 0 Pump Seal s A cid Gas 0 42.90 0.0386 0 0.00 0 0.000 0 0.000 0 Relief Valve s A cid Gas 4 42.90 0.2293 0 0.393 0.3935 1.723 4 Sample Connection s A cid Gas 8 42.90 0.0330 0 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 T otal Emission s 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 48.577Methane from FUG Page 6 of 6 TSD App A CH4 Uncontrolled Control Controlled Controlled Emission Source Source Component Conc Emissions Factor Total Emissions Efficiency T otal Emission s 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 CO 2 e 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 flarePage 1 of 1 TSD APP ANote: Truck and Rail unloading is not simultantious, During Trucking reciepts, the below sources replace 12g, h, I, j and k.Max. HourAverageAnnualEmissions DailyEmissionsUnit ID Namelb/hrlb/hrTPY012 YTransfer tower from Truck/Rail conveyor topile conveyor1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 8,760 24 0.039 0.0390.17012 Z Truck Bay 1 dump to Hopper 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 2,365 12 0.039 0.0190.046012 AA Truck hopper to conveyor 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 2,365 12 0.039 0.0190.046012 AB Truck Bay 2 dump to Hopper 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 2,365 12 0.039 0.0190.046012 AC Truck Bay 3 dump to Hopper 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 2,365 12 0.039 0.0190.046Max. HourAverageAnnualEmissions DailyEmissionsUnit ID Namelb/hrlb/hrTPY012 YTransfer tower from Truck/Rail conveyor topile conveyor1,500 ACFM 0.175 GR/ACF DUST EXTRACTION SYSTEM 99.14% 8,760 24 0.019 0.0190.085012 Z Truck Bay 1 dump to Hopper 1,500 ACFM 0.175 GR/ACF DUST EXTRACTION SYSTEM 99.14% 2,365 12 0.019 0.00970.023012 AA Truck hopper to conveyor 1,500 ACFM 0.175 GR/ACF DUST EXTRACTION SYSTEM 99.14% 2,365 12 0.019 0.00970.023012 BB Truck Bay 2 dump to Hopper 1,500 ACFM 0.175 GR/ACF DUST EXTRACTION SYSTEM 99.14% 2,365 12 0.019 0.00970.023012 CC Truck Bay 3 dump to Hopper 1,500 ACFM 0.175 GR/ACF DUST EXTRACTION SYSTEM 99.14% 2,365 12 0.019 0.00970.0230.18Max. HourAverageAnnualEmissions DailyEmissionsUnit ID Namelb/hrlb/hrTPY012 YTransfer tower from Truck/Rail conveyor topile conveyor1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 8,760 24 0.0386 0.03860.17012 Z Truck Bay 1 dump to Hopper 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 2,365 12 0.0386 0.0190.046012 AA Truck hopper to conveyor 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 2,365 12 0.0386 0.0190.046012 BB Truck Bay 2 dump to Hopper 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 2,365 12 0.0386 0.0190.046012 CC Truck Bay 3 dump to Hopper 1,500 ACFM 2.50 GR/ACF DUST EXTRACTION SYSTEM 99.88% 2,365 12 0.0386 0.0190.0460.35Comments: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 PMOperatingHours/dayOperatingHours/yrOperatingHours/yrControlEfficiencyOperatingHours/yrProcess Rate Emission FactorOperatingHours/dayOperatingHours/dayCoal/Coke Truck Unloading OperationEmission FactorControlTypeControlTypePM2.5EMISSIONSControlEfficiencyControlEfficiencyTOTAL PARTICULATE EMISSIONSProcess Rate Emission FactorControlTypeProcess RatePM10EMISSIONSPage 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/m 2 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/m 2 (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 

#     02

. 1 91

. 0 

## W sL k E   

#    

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ext 

## 4 / 1 02

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. 0



##   

17_30464 limited Calcs H 88 5/3/2012Page 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 tem porary storage, then it must travel 900 feet offsite to c oal yard area, then it trav els 1100 feet in coal yard to drop off and 1100 feet in c oal yard to pick up. (wor se-case total = 600+600+1100+1100 excluding the porti on of travel "o ffsite"/outside t he fenceline.)

Emissions calculated = Emissions factor (lb/vmt) * trip distance (miles) * number of trips * (1-control efficiency) 

#    02

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##   

Total Round-Trip Distance: 0.644 mile/trip "Wet" Days, P: 117 days Road Surface Silt Loading, sL: 1.0 g/m 2 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/h r PM2.5 0.00088 lb/hr Potential PM2.5 Emisions: Total PM 0.01801 lb/h r 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/h r 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) 

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##   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

A lso 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      

      Page 1 of 1 TSD App AAlthough Storage Pad is paved, assume it is partially covered in slag, calculate emissions assuming unpaved road equation.Description of Vehicles Load SizeVehicle WeightEmptyAverageVehicleWeightDaily Slag(annualaverage)Max Slagper dayMiles pertripMaximumDaily Ave AnnualMaximumVMTAve. AnnualVMTtons tons tons tons/daytons/dayMile/trip Trips/day Trips/day Miles/day Miles/dayFront End Loader20 32.66 26.33 1,440 2,068 0.0142 103.4 72 1.469 1.023Assume each trip of front end loader trip is 75 feet round trip (1/4 width of pad times 2)AverageVehicle weigh(tons)UncontrolledEmissionsfactor (lbs totalPM/VMT)UncontrolledEmissionsfactor (lbsPM10/VMT)UncontrolledEmissionsfactor (lbsPM2.5/VMT)ControlEfficiencyMax dailylb/hr TotalPMMax dailylb/hr PM10Max dailylb/hr PM2.5Front End Loader/dozer26.33 2.287 0.426 0.043 90% 0.014 0.003 0.000Front End LoaderTotal 0.014 0.003 0.000Max AnnualTons/yrTotal PMMax AnnualTons/yrPM10Max AnnualTons/yrPM2.50.007 0.001 0.000Front End LoaderNote: 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 and beingpicked 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/pileTotal 0.007 0.001 0.000UNPAVED 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 particulateW = Vehicle average weight (tons)P = number of days per year with 0.01 in or more of precipitationINPUTS TO EQUATION/CALCULATIONS Total PM PM10 PM2.5k 4.9 1.5 0.15 lb/vmts1 1 1 %a 0.7 0.9 0.9b 0.45 0.45 0.45P 117 117 117 days/yr312**WsbakE365365PEEextPage 1 of 1 TSD App A 

### Indiana Gasification, LLC Spencer County Facility
Emission Unit:


### FUG

‐ SF6 Emission Estimate for Fugitive Emissions of SF 6 from Circuit Breakers

The IG facility will include a switchyard with circuit breakers that include sulfur hexafluoride (SF 6 ), 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 brea k 6 Amount of SF 6 in each 100 lbs
Assumed leak rate: 1%

Emissions (lb/yr): 6 lbs/yr

GWP of SF 6 : 23,900 CO2e (tons/yr): 71.7 tons/yrPage 1 of 3 TSD App AThisworkbookdocumentscalculationsfortotalparticulateemissionsfromtheIndianaGasificationSyngasPlant.Mostofthesecalculationsarebasedonand/orarerelatedtotheestimatesofPM10emissions.Formostofthesources,theestimatedtotalparticulateemissionsestimatesareequaltothePM10estimatedemissionsbecauseallparticulateisfinerthanPM10.NotableexceptionsareuncontrolledmaterialhandlingandroadwayemissionssourceswhichhaveahigherquantityoftotalPMcomparedtothePM10.Forsuchsources,emissionsofvariousparticlesizesarebasedonstandardequationsutilizingparticlesizemultipliersuniquetothesourceunderconsideration.ThisworkbookhasasummaryofthetotalPMemissionsfortheIndianaGasificationplant,withnotesonthebasisoftheemissionsestimates.ForsourceswheretotalPMisnotequaltoPM10,otherworksheetpagesdocumentthoseemissionscalculations(formaterialhandlingsourcesandroadwayemissions).93Page 2 of 3 TSD App AEmissionsUnitNumberSourceNameTotalParticulateSameasEstimatedPM10BasisofTotalPMEstimate1 SyngasHydrocarbonFlare 0.44 Yes Note12 AcidGasFlare 0.01 Yes Note15 AuxiliaryBoilers(A‐B) 5.62 Yes Note17 AcidGasRecoveryUnit(A‐B) 2.46 Yes Note18 GasifierPreheatBurners(A‐E) 0.04 Yes Note19 EmergencyDieselGenerators(A‐B) 0.00 Yes Note210 EmergencyFirewaterPumpsDieselEngines(A‐C) 0.01 Yes Note211 ProcessAreaSolidFeedstockHandling(coal/petcoke) 6.35 Yes Note312(A‐X) IncomingSolidFeedstockHandling(coal/petcoke)(A‐X) #REF! No Note413 RodMill(A‐D) 0.44 Yes Note315 WetSulfuricAcidPlant(WSA)(A‐B) 42.59 Yes Note516A CoolingTower‐ASU 0.90 Yes Note616B CoolingTower‐Main 6.65 Yes Note617 ASUMolecularSieveRegeneration(A‐B) 0.22 Yes Note223 SlagSump(A‐E)‐ ‐n/a24 MethanolDe‐InventoryTank‐ ‐n/a25 FreshMethanolStorageTank‐ ‐n/a26 SourWaterStripperSurgeTank‐ ‐n/a27 SulfuricAcidStorageTank(A‐F) 0.00 Yes Note529 DieselFuelStorageTank‐ ‐n/a30 GasolineFuelStorageTank‐ ‐n/a31 TriethyleneGlycolStorageTank‐ ‐n/a32 ZLDSprayDryer 0.51 Yes Note3FUG FugitiveEmissions‐Gasification,ShiftConversion,AGR,Methanation‐ ‐n/aFUG‐WSA FugitiveEmissions‐WSA‐ ‐n/aFUG‐Road FugitiveEmissions‐PlantHaulRoads 2.63 No Note7Total#REF!SummaryofIndianaGasificationPlantTotalParticlateEmissions9495BasisofTotalPMEmissionsEstiimates(BasedonordifferencesversusPM10estimate)Page 3 of 3 TSD App ANote1Note2Note3Note4Note5Note6Note7 ThisrepresentsthePM10figurefromtheoriginalapplication(seeAppendixB,pageH1)multipliedbyaPM‐sizemultiplierof5.(SeeAP‐42,Chapter13.2,Table13.2.1‐1).CombustionSources:PM10EmissionsforcombustionsourceshavebeencalculatedusingparticulatefactorsforfilterableandcondensibleparticulatefromAP42.Thesefactorsarefortotalparticulate,thereforetheiruseforPM10isconservative,andresultintotalPM=PM10.EngineeredEquipment:ThesesourceshavePM10basedonvendorordesignengineeringestimateoftotalparticulateconservativelyassumingallPMisPM10.Therefore,estimateoftotalparticulateequalsPM10estimate.Baghousecontrolledsources:PM10isestimatedusingdesigntotalparticulategrainloadingonoutletofbaghouse.AlloutletPMisconservativelyassumedtobePM10,thereforetotalPM=PM10.ParticulatesourcesusingvariousAP42orotherequations(aggregatehandling,roadway,winderosion):Thesesourcescalculateemissionsusingcomplexequationsbasedonsiltlevel,vehicleweight,windspeedandotherparameters.However,theyallcontaina"particlesizemultiplier"factoruniquetoeachPMparticlesizerange.Otherthanthisfactor,theremainderoftheequationandparamatersarethesameforaggregatehandlingandwinderosion.Therefore,totalPMhasbeencalculatedbymultiplyingestimatedPM10bytheratioofthetotalPMfactor:PM10factor.Fordozer‐relateddust,theequationalsoincludesadditionalexponentswhichdifferfordifferentparticlesizes.ThereforetotalPMhasbeencalculatedusingthefullequationandtheapplicablefactorsandexponents.DocumentationofthesetotalPMestimatesareprovidedonseparatespreadsheets.SulfuricAcidMistSources:TheWSAparticulateconsistspredominantlyofcondensiblesulfuricacidmist.ThiscondensibleparticulateisallassumedtobePM2.5.Therefore,totalPM=PM10=PM2.5.Additionally,thereisasmallamountofPMfromcombustion,however,asexplainedaboveinNote1,forcombustionPM,totalPMisalsoequaltoPM10.Coolingtowerparticulate:PMfromcoolingtowersisbasedontotaldissolvedsolidsinthecoolingwater.Thiscalculationgivestotalparticulateemissions.IGhasconservativelyassumedthatalltheparticulateisPM10.ThereforetotalPM=PM10.96Basis: 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 HH V 8760 1.65E-06 4.376E-07 0.000001 9 2.90E-06 7.69E-07 0.000003 4

002 Acid Gas Flare - Nat Gas Pilots 1 1 300 0.27 MMBtu/h HH V 8760 1.65E-06 4.376E-07 0.000001 9 2.90E-06 7.69E-07 0.000003 4

005 Auxiliary Boiler, Full Load Operation - black plant su (nat gas fuel) 1 1 200 816 MMBtu/h HH V 8760 2.55E-07 2.081E-04 0.000907 2 4.90E-07 4.00E-04 0.001744 7

005 Auxiliary Boiler, Full Load Operation (SNG or Nat Gas) 1 1 200 816 MMBtu/h HH V 8760 1.65E-06 1.347E-03 0.005872 5 2.90E-06 2.37E-03 0.010321 7

005 Auxiliary Boiler, Half Load Operation (SNG or Nat Gas) 1 1 200 408 MMBtu/h HH V 0 1.65E-06 6.735E-04 0.002936 3 2.90E-06 1.18E-03 0.005160 8

008 Gasifier Preheat Burners - black p lant su ( nat g as fuel ) 5 5 200 35 MMBtu/h HH V 8760 2.55E-07 8.922E-06 0.000038 9 4.90E-07 1.72E-05 0.000074 8

008 Gasifier Preheat Burners ( one o p eratin g 8 months p er y ear, SNG or NG fuel 5 1 200 18 MMBtu/h HH V 8760 1.65E-06 2.970E-0 5 0.000129 5 2.90E-06 5.22E-05 0.000227 6

009 Emergency Diesel Generators (2 units each tested 1 hour weekly) 2 1 20 1,341 h p 500

010 Diesel Fire Water Pump Engine (3 units each tested 1 hour weekly) 3 1 20 575 h p 500

011 Coal Conveying and Feed Bins Dust Control System Vents 2 1 200 8760 1.244E-06 0.000005 4 2.42E-04 0.001054 6

012 Coal Unloading and Storage (Barge, Rail, Truck) 0.0000000 0.0000000

013 Rod Mill Vent Stacks 4 4 125 8760 0.000000 0 0.000000 0

032 ZLD Spray Drier Stack 1 1 100 5.6 MMBtu/h HH V 8760 1.65E-06 9.294E-06 0.000040 5 2.90E-06 1.63E-05 0.000071 2

033 ZLD Inert Gas Vent 1 1 100 8760 1.404E-07 0.000000 6

015 WSA Preheat 2 1 200 35.0 MMBtu/h HH V 8760 1.65E-06 5.775E-0 5 0.000251 8 2.90E-06 1.02E-04 0.000442 5

015 WSA Stack - black plant su 2 1 213 291 stpd 100% H2SO4 8760 8.348E-11 0.000000 0

015 WSA Stack - One Unit Operation 2 1 213 582 stpd 100% H2SO4 8760 1.670E-10 0.000000 0

015 WSA Stack - Two Unit Operation 2 2 213 1,164 stpd 100% H2SO4 8760 3.339E-10 0.000000 0

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-0 5 0.000139 6 2.90E-06 5.63E-05 0.000245 4

007 Re g en Thermal Oxidizers ( Note 1, Two Units Hot Standb y 80% of the y ear, SNG 1 1 200 10.3 MMBtu/h HHV SNG 0 1.65E-06 1.705E-0 5 0.000074 3 2.90E-06 3.00E-05 0.000130 7

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-0 5 0.000279 2 2.90E-06 1.13E-04 0.000490 7

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 CapacityIndiana 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 ma x Mercury ma x 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 millsIndiana 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 R e 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 I G 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 En v 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 drscfA

e source Table 46 A R esource Table 46 A

G CC Environmental Assessment by SAIC & NETL)

v ironmental Assessment by SAIC & NETL)

c atalyst, and liquid filtersPage 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 =TTANK 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 c f

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/y r

8760 8760 hr/yr 8288.58 237,741.01 lb/yr UNCONTROLLED TOTAL EMISSIONS (H 2 S 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 LOSSTANK 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 c f

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/y r

8760 8760 hr/yr 8288.58 237,741.01 lb/yr UNCONTROLLED TOTAL EMISSIONS (H 2 S 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 LOSSTANK 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 c f

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/y r

8760 8760 hr/yr 8288.58 237,741.01 lb/yr UNCONTROLLED TOTAL EMISSIONS (H 2 S 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 LOSSTANK 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 c f

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/y r

8760 8760 hr/yr 8288.58 237,741.01 lb/yr UNCONTROLLED TOTAL EMISSIONS (H 2 S 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 LOSSTANK 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 c f

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/y r

8760 8760 hr/yr 8288.58 237,741.01 lb/yr UNCONTROLLED TOTAL EMISSIONS (H 2 S 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 DIAMETER023

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 DeterminationAt 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 DeterminationTANK 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 EMISSIONSTANK 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 HOURL Y 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 DIAMETERTANK 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 da y

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/y r

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 LOSS026

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)

026At 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 DeterminationTANK 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 HOURL Y 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 LOSSTANK 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 HOURL Y 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 DIAMETERTANK 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 HOURL Y 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 DIAMETERTANK 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 HOURL Y 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 LOSSTANK 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 HOURL Y 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 LOSSTANK 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 HOURL Y 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 LOSSTANK 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 A mmonia A mmonia 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 c f

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 HOURL Y SPECIES lb/yr lb/hr A mmonia (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 LOSSTANK 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 DIAMETER028 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 DeterminationAt 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 av g) ( 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 da y

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: 91.879 9 236835.2 6 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 XyleneTANK 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 c f

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 da y

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/y r

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 DIAMETERSPECIATED EMISSIONS : Page 26 of 40 TSD App A NORMAL SERVIC E MAXIMUM HOURL Y 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 FuelsAt 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 Fuels30

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 DeterminationAt 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 DeterminationCAS 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 Wate r 7732-18- 5 18.01 73.64 9 7258.2 -7.303 7 4.165E-0 6 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 CONSTANTSPage 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 (t able 51.3). ANTOINES CONSTANTS FOR VARIOUS COMPONENTSPage 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 CHARACTER I STORAGE TANK PARAMETERS
TANK IDENTIFICATIONUnit 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 V ertical 18.0536 18.0300 33,540 V ertical 18.0536 18.0300 33,540 V ertical 18.0536 18.0300 33,540 V ertical 18.0536 18.0300 33,540 V ertical 18.0536 18.0300 60,000 V ertical 32.0399 32.0399 10,800 V ertical 32.0399 32.0399 93,000 V ertical 98.0700 98.0700 93,000 V ertical 98.0700 98.0700 93,000 V ertical 98.0700 98.0700 93,000 V ertical 98.0700 98.0700 93,000 V ertical 98.0700 98.0700 93,000 V ertical 98.0700 98.0700 12,000 V ertical 17.0299 17.0299 12,000 V ertical 17.0299 17.0299 6,000 V ertical 63.8339 63.5117 600 V ertical 66.1205 66.2741 42,420 V ertical 32.0399 32.0399 I STICS BULK LIQUID CHARACTERISTICSUnit 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 TEMPERATURESUnit 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 A queous Ammonia 028 B A queous 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 V

APOR PREUnit 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 S SURE PARAMETERSUnit 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 CharacteristicsUnit 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 A mmonia 7.70 0.0322 32,243 248,271 A mmonia 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 VolumePage 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 11.0843355 2 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)BaghouseCostAnalysis:ZLDSprayDryer‐CostEffectivenesstoachieve0.001gr/dscfPM/PM10EmissionsEmissionsReductionControl CapitalCostControl OperatingCost/yrTotal AnnualizedCostsCost EffectivenessTons/yr tons/yr $ $/yr $/yr $/Ton PM/PM10Teflon Fabric Baghouseachieving 0.001 gr/dscf0.102 0.408 $0 4,381$ 4,381$ $10,700Marginal increased energyfor increased delta PAssumptions:Baseline - Baghousecontrollingto 0.005gr/dscf0.5 (proposed)ZLDSprayDryerZLDSprayDryer‐CostEffectivenesstoachieve0.001gr/dscf(onlyconsideringincreasedbagcosts)EU‐032Basis(pageref.fromEPACostManual(Note1)ExhaustFlow dscf/m 2735 OneUnitGastoClothRatio cfm/netft2 6 pageI‐22NetClothRequir. netft2 455.8GrossvsNetcloth ratio 2 pageI‐23Grossclothrequir. totalft2 911.7TeflonFabriccost1998$/ft10.958$pageI‐42(average)Ave.Conv.Fabric 1998$/ft 0.639$pageI‐42,polyesterorpolypropyleneIncreasedCost 1998$/ft10.319$IncreasedCost 2011$/ft13.348$assume2%inflationfor13years.Increasedcostforbags Total$ 12,169$materialprice(minustax/freight)Increasedcostforbags Total$ 13,143$Priceplus8%taxandfreightChangeoutFrequencyyears 3 pageI‐46(average)Averageannualincrementalcost4,381$Emissions@0.005gr/dscftons/yr 0.51Emissionsdecreaseat0.001ton/yr0.40810,738$$/toncontrolledIncrementalCostAnalysisForabaghousetoachieve0.001gr/dscfversusconventional0.005gr/dscf.(increasedbagcostsonly)Control AlternativeOther ImpactsCostEffectivenessofTeflonBagsand0.001gr/dscfNote1:EPAAIRPOLLUTIONCONTROLCOSTMANUAL,SixthEdition,EPA/452/B‐02‐001January2002,Section6Chapter1BaghouseandFiltersNote:thesecostsdonotincludeincreasedcostsforhigherpressuredrop,largerbaghouses,orotherenhancementstoachievelowerperformance.Incremental Cost Analysis for a Baghouse to achieve 0.001 gr/dscf versus baghouse at 0.003 gr/dsc f

Process Material Handling EU

‐ 011A&B Cost Effectiveness to achieve 0.001 gr/dsc f

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
g r/dscf 3.8 (proposed)

Incoming Material Handling EU

‐ 012 R&S (each 6000 acfm units) Cost Effectiveness to achieve 0.001 gr/dsc f
PM/PM10 Emissions (if 8760 hr/ y r ) 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
g r/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
g r/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 ImpactsCostsforFabricFiltersUpgradefrom0.003to0.001gr/dscfPM10PerformanceEmissionsUnitAirFlowRate(ACF/M)0.003gr/dscf0.001gr/dscfDelta0.003gr/dscf0.001gr/dscfDelta0.003gr/dscf0.001gr/dscfDeltaTotalCapitalInvestment(Note1,Note2) $337,600 $371,360$33,760$15,000 $16,500$1,500$60,000 $66,000$6,000AnnualCostsTotalDirectCostsDelta Delta DeltaLabor,Maintenance,ReplacementBags,etc.(Note3,Note4)$303,840$349,416$45,576$13,500$15,525$2,025$54,000$62,100$8,100Energytokeepairabovedewpoint(preventcondensation)(Note5)$22,451$22,451$998$998$3,990$3,990SubtotalAnnualDirectCostsIndirectCostsCapitalRecovery(Capital*0.14assuming7%interestand10yrlife)$47,264$51,990$4,726$2,100$2,310$210$8,400$9,240$840TotalAnnualCosts $351,104$423,857$72,753$15,600$18,833$3,233$62,400$75,330$12,930Emissions(tons/yr)ifrun8760hr/yratdesignoutletgrainloading3.80 1.272.530.17 0.060.110.68 0.230.45IncrementalCostEffectiveness($/Tontoimprovecontrolfrom0.003to0.001gr/dscf)$28,701 $28,701 $28,701Note1 Capitaltoachieve0.003gr/dscfbasedon$10/acfmconservativelybasedonlowerendofrangeofcostsfromEPAPollutionControlFactSheetforJetPulseFabricFilters(SixthEdition,EPA/452/B‐02‐001,January2002Note2 Capitalcostsestimatedtoincreaseatleast10%toachieve0.001gr/dscfpervendorNote3 Annualcosts(excludingcapitalrecovery)for0.003gr/dscfbasedon9$/acfmconservativelybasedonlowerendofrangeofcostsfromEPAFactSheetforJetPulseFiltersNote4 Annualcostsestimatedtoincreaseatleast15%toachieve0.001gr/dscfpervendorNote5 Energycoststokeepfilteredairabovedewpointassume10degFtemperaturerise,energycosts$7/MMBtu,airheatcapacityof0.241btu/lb‐F,andairdensity0.075lb/ft3GeneralExplaintionofAboveCalculations:Toachieve0.001gr/dscfrequiresseveralchangestothebaghousedesignversusaconventionalbaghouse,allofwhicharemoreexpensive.Basedondiscussionswithvendor,Capitalcostsincrease10%,operatingcostsincrease15‐25%,andtheairneedstobeheatedtoavoidcondensationonthefiltermedia.Thesecostsarereflectedinbelowincrementalcapitalandoperatingcostestimates.BaselineCapitalandoperatingcostsestimatedfromEPA'spollutioncontrolfactsheetforjetpulsefabricfilters.Incrementalcostsbasedonabovevendorestimatedfactors.EU‐011a/b33760EU‐012B‐0,T‐AC1500EU‐012R/S6000

## 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 S ource 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 Gasifi cation, 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 CO 2 . The project will produce up to 48 billion standard cubic f eet (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 proj ect will also produce annually up to approximately 6.43 million tons of liquefied CO 2 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 domes tic oil in the Gulf Coast region.
The facility will have several products in addition to SNG and liquefied CO 2 . Sulfur compounds in the feedstocks will be processed into sulfuric acid, which IG plans to sell into the industrial market. Argon will be re covered 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 ne eds. 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 abov e 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 operati ng 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 constr uction has the potential to emit of CO emissions greater than 1 00 tons per year , which exceed the PSD threshold and significant levels for this pollutant. The BACT review also addressed the following poll utants PM, PM 10 , PM 2.5 , SO 2 , NOx, H 2 SO 4 and GHGs tha t 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 perform ed 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 i ncoming 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 source s .]

(1) One (1) barge unloadi ng to hopper transfer point, to be permitted in 201 2

, 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

con trolled 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 EU

012B, to be permitted in 201 2

, with one (1) control device, identified as C

- 012B, exhausting throug h 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 201 2

, 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 EU

012H, to be permitted in 2012

, with two (2) control devices, identified as C

- 012G through C

- 012H, respectively, exhaus ting through two (2) vents, identified as S

- 012G through S

- 012H, respectively;

(d) Two (2) rail hoppers unloading to the conveyor belts, identified as EU

012I 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, exh austing through one (1) vent, identified as S

- 012K;

(f) Two (2) stacker belts to the radial stacker, identified as EU

- 012L and EU

012M, to be permitted in 2012

, with two (2) control devices, identified as C

- 012L and C

- 012M, respectively, exhausting thro ugh 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 S

012T through S

- 012U, respectively; andIndiana 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) ven t, identified as S

- 012V ;
(i) Three (3 ) truck stations unloading to a truck hopper

, identified as EU

012Z, 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 t hrough 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, to be permitted in 2012, with one (1) control device, identified as C

- 012AA exhausting throu gh 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) Tw o (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) st acks, 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, to be permitted in 2012

, with particulate emis sions 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 activ ities 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 E U

- 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 3 3 ,7 6 0 dscfm, exhausting through two (2) stacks, identified as S

- 011A and S

- 011B, respectivel y. [Under 40 CFR 60, Subpart Y, the process area solid feedstock conveying, storage, and feed bins (main and spare) are new affected source s .]

(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 o ne ( 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, H 2 S, 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, resp ectively, each nominally rated at 38.8 MMBtu/hr HHV fu el input, exhausting through two (2 ) stack s , identified as S

- 007 A and S

- 007 B

. (F ) Two (2) Wet Sulfuric Acid (WSA) plant trains, each nominally rated at 800 stpd H 2 SO 4 and identified as EU

- 015A and EU

- 0 15B, to be permitted in 2012

, with NO x , SO 2 , H 2 SO 4 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, r espectively, 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 NO x emissions controlled by ultra

- low NO x burners/Flue Gas Recirculation (ULNB/FGR), with both boiler s exhausting through one (1) stack, identified as S

- 005. [Under 40 CFR 60, Subpart Db, the natural gas

- fired auxiliary boilers are new affected sour ce s .]

(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, 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

, nominall y 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 NO x burners (LNB), exhausting through one (1) stack, identified as S

- 014.

(J) Methanol Tanks:

(1) O ne (1) Methanol De

- Inventory Tank, with a nominal capacity of 700,000 gallons, identified as EU

- 024, to be permitted in 201 2 , 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 201 2 , with emissions controlled by a vapor recovery system and exhausting through one (1) vent, identified as S

025. [40 C FR 60 Subpart Kb]

(k ) Paved Plant Haul Roads are identified as emissions unit FUG

- ROAD.

( L ) Electrical Circuit Breakers (approximately six) containing sulfur hexafluoride (SF 6 ) identified as emissions unit FUG

- SF6, to be permitted in 2012

, with fugitiv e GHG emissions controlled by full enclosure.

( M ) Fugitive Equipment Leaks from the gasification, shift conversion, gas cooling, AGR, CO 2 compression, WSA, and methanation are identified as emissions unit s FUG and FUG

WSA and will be controlled by a Leak Detec tion 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, respecti vely. [Under 40 CFR 60, Subpart IIII, each, emergency diesel fired generator is considered a new affected source.][Under 40Indiana Gasification LLC Page 5 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun CFR 63, Subpart ZZZZ, each, emergency diesel fired generator is considered a new affected source.]

(O ) Three (3) firewater pump di esel 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 p ump 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 5 4

, 960 gpm and identified as EU

- 01 6A, 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 S

016B

- A through S

- 016B

- X.

( S ) Two (2) Air Separation Unit (ASU) molecular sieve regener ation train vent, which each vent a nominal 1 87,000 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 S

- 017A andS

- 017B, respectively.

(T ) One (1 ) slag ha ndling 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 activit y 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

, 5 00 ga llons

- 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, ident ified as S

- 033.

Summary of the Best Available Control Technology (BACT) Process

BACT is a n 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 identif ies the best controlled similar source on the basis of controlsIndiana Gasification LLC Page 6 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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" approac h.

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 ac hievable 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 BAC T 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 techno logies 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 Effec**  **tiveness** 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). I f 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 eff ective 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 pe rform 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.Indiana Gasification LLC Page 7 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun

Pa rticulate (PM, PM 10 and PM 2.5 ) BACT

– Syngas Hydrocarbon Flare (EU

- 001)

Step 1: Identify Potential Control Technologies

In evaluating BACT for flare PM

, PM 10 and PM 2.5 emissions, there are limited process and/or add

- on control alternatives available. Bas ed 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 Pla n); a nd (3) Flare gas recovery

.

Add

- on PM

, PM 10 and PM 2.5 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 follo ws:
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. T he fact that all gas es 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 determi nation, 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 m inimize the volume of gas going to the flare, emissions of PM

, PM 10 and PM 2.5 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. Howe ver, 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, flarin g 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 contra st, 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.Indiana Gasification LLC Page 8 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (3) Another difference is that during some of the IG flaring events, the flared material may

no t 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 BAC T 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 rem aining technically feasible control technologies for flares are:

(1) Proper f lare d esign and o peration ;
(2) Process flaring minimization practices (Flare Minimization Plan)

.

These two co ntrols listed above are proposed to be implemented by the source

, therefore, no
ra nking of control technologies are needed.

Flare Design and Operation T he flare design will be inherently efficient at ensuring complete combustion and minimizing PM / PM 10 /PM 2.5 emissions. The f lares will be designed for and operated wit h 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 red uce 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 th e 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 t o 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 minim ize re

- occurrence of these events.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM

, PM 10 and PM 2.5 BACT determination along with the existing PM

, PM 10 and PM 2.5 BACT determinations for simi lar p lants. 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 oth er 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 PlanIndiana Gasification LLC Page 9 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 lbs/hr (3 hr ave),

PSD

- LA

- 742(M1) Louisiana Lake Charles Cogeneration, LLC 1 2 / 30 /20 10 001 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 08 1801 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 l ow emissions rate f or 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 (s ee Ap

- 42 Chapter 13.5

, T able 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, T able 1.4

- 2)

. Proposal : Indiana Gasification, LLC

– Rockport, IN

The following has been proposed as BACT for PM, PM 10 and PM 2.5 from the proposed Syngas Hydrocarbon Flare (EU

- 001) :
(1) Comply with the following Flare Minimization Plan to reduce PM, PM 10 and PM 2.5 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.Indiana Gasification LLC Page 10 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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 abo ve 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 t hat 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 wit h 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 t hermocouple, infrared monitor, or other approved device. (3) The Syngas Hydrocarbon Flare PM/PM 10 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 P M calculator, t he Syngas Hydrocarbon Flare PM 2.5 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 establish ed the following as BACT for PM, PM 10 and PM 2.5 for Syngas Hydrocarbon Flare (EU

- 001)

. (1) Comply with the following Flare Minimization Plan to reduce PM, PM 10 and PM 2.5 emissions during startups, shutdowns, and other flaring events.

During a planned s hutdown 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 p rocedures 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 pr eventative 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:Indiana Gasification LLC Page 11 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (A) Flares shall be design ed 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/PM 10 emissions shall not exceed 3.21 lb/hour during startup or shutdown, based on a 3

- hour average.

(4) The Syngas Hydrocarbon Fla re PM 2.5 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 emissio ns, 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 p roper o p eration; (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 el evated process flare is not enclosed or contained. Therefore, the emissions 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 operation are key elements in the em issions performance of flares. The source is proposing the use of elevated flares which have ve ry high combustion efficiency. These are the most commonly us ed 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 i n 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 rate s 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 f lare design and proper operation is a technically feasible option for the Syngas Hydrocarbon Flare (EU

- 001 ) at this source.Indiana Gasification LLC Page 12 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun Process flaring minimization practices (Flare Minimizatio n 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 p rocess 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 ver sus 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 u pset, 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, fla re 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 d esign and p roper o peration

(2) Process flaring minimization pr actices

These two co ntrols listed above are proposed to be implemented by the source

, therefore, no
ra nking of control technologies are needed.

Flare Design and Operation The design of the flares is specific for the process stream that will be contro lled and includes the following considerations:

(1) The f lares 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, NH 3 and HCN that require oxidation for control. US EPA research indicates that 99.5% oxidation efficiency (CO) is achievable in well

- designed flaresIndiana Gasification LLC Page 13 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (Flare Efficiency Study, USEP A, EPA

- 600

- 83

- 052, July 1983.) The stream also contains H 2 S and COS that require conversion to SO 2 , as well as NH 3 and HCN that require conversion to N 2 , H 2 O and CO 2 for control. Ninety eight percent (98%) oxidation efficiency of H 2 S and COS and NH 3 are r easonable given the oxidation efficiency of the main fuel components H 2 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 w ill 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 tak en 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 initi al 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 simil ar p lants. 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 oth er 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 1 2/30/2010 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 NoneIndiana Gasification LLC Page 14 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 standby (3 hr ave)

V

- 09

- 006

- Kentucky K y 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 N o. 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 pe ak 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.

S yngas from gasifier startup and shutdown will contain a high CO and H 2 concentration and very low concentrations of hydro carbons. Syngas combustion at the flare tip will be oxidizing CO to CO 2 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 s o 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 Minimizatio n 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 dep ressurization 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 shut down, 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 Min imization 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 in itial 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 a mount 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 c ause” 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 docume nted.

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 presen t 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 star tup or shutdown, based on a 3 hour average.

Sulfur Dioxide (SO 2 ) BACT

- Syngas Hydrocarbon Flare (EU

- 001)

Step 1: Identify Potential Control Technologies

In evaluating BACT for flare SO 2 emissions, there are limited process and/or add

- on control alternativ es 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 Min imization Plan); and (3 ) Flare gas recovery

. Add

- on SO 2 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, t he emissions 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 the emissions performance of flares. However, SO 2 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 SO 2 purposes, flare desi gn is not considered further.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that the use of a f lare design and proper operation is not a technically feasible option for the Syngas Hydrocarbon Flare (EU

- 001 ) at th is 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 SO 2 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 ha s 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 facili ties 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 ga ses, 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 facilit y’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 differenc e 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 fe asible 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 i mplemented by the source and only one option has been identified

, therefore, no ra nking 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 r educe 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 planne d 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 suc h 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 c ause” 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 Docum ent the Results

The following table lists the proposed SO 2 BACT determination along with the existing SO 2 BACT determinations for similar p lants. All data in the table is based on the information obtained from the permit application submitted by Indiana G asification, 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 Meth od 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 Fl are Minimization Plan

PSD

- LA

- 742(M1) Louisiana Lake Charles Cogeneration, LLC 1 2/30/2010 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 No ne Written Flare minimization plan, compliance with 40 CFR 60.18 081801 AAF (Application No. 07100063) Power Holdings of 10/26/2009 Flare * 1 3 ,70 0 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 Meth od Illinois Gasification T083

- 23529

- 00003 Duke Energy Indiana

- Edwardsport 01/25/2008 Flare * 6 18 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 pro posed the use of sulfur

- free fuel for startup, resulting in minimal SO2 emissions from S tartup flaring. The other above facilities , which show significantly higher emissions, likely propose to use coal or other sulfur

- containing fuel for startup.

Prop osal : Indiana Gasification, LLC

– Rockport, IN

1. Comply with the following Flare Minimization Plan to reduce SO 2 emissions during startups, shutdowns, and other flaring events.

The use of methanol, rather than coal or pet coke, as the feedstock in each ga sifier 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, s crubber 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 c an be implemented to minimize re

- occurrence of these events. Such identified measures would be implemented and documented.

The SO 2 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 SO 2 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 Deterioratio n (PSD), IDEM has established the following as BACT for SO 2 for Syngas Hydrocarbon Flare (EU

- 001)

.

1. Comply with the following Flare Minimization Plan to reduce SO 2 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 me thanol, 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 p rocessed 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 a nd 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 t hat can be implemented to minimize re

- occurrence of these events. Such identified measures shall be implemented and documented.

2. The SO 2 emissions from the Syngas Hydrocarbon Flare during a shutdown event shall not exceed 85.21 lb/hr based on a 3

- hou r average and shall not exceed 255.6 lb per 24 hours. The SO 2 emissions from the Syngas Hydrocarbon Flare shall not exceed 0.35 lb/hour during startup, based on a 3 hour average.

Nitrogen Oxide (NO X ) BACT

- Syngas Hydrocarbon Flare (EU

- 001)

Step 1: Ident ify Potential Control Technologies

In evaluating BACT for flare NO x 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 p rocess alternatives includes the following:

(1 ) Flare design and proper operation ; (2 ) Process flaring minimization practices (Flare Minimization Plan); and (3 ) Flare gas recovery.

Certain NO x controls that may be used on other types of sources, such as s elective 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 f lue 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 moni toring 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 f lare 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

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- 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 flar e 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 landfi ll 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, n o 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 t his 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 syst em 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 rec overy 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 o ption for the Syngas Hydrocarbon Flare (EU

- 001 ) at this source.
Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The remaining technical ly 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 (Fl are Minimization P lan)

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 eve nts 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 ; the refore, no ra nking 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 p lant s. 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 permi tting 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/da y , 48 BSCF/yr

SNG 43.09 lb/hr (3 hr ave) Flaring Minimization P lan

PSD

- LA

742(M1) Louisiana Lake Charles Cogeneration, LLC 1 2/30/2010 001 Gasifier Flare * 9, 413 T coke/day 86.28 lb/hr N o 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 * 400,00 0 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 * 1 3 ,70 0 T coal per

day 513 lb per SSM event Flare Minimization Plan,

T083

- 23529

- 0 0003 Duke Energy Indiana

- Edwardsport 01/25/2008 Flare * 6 18 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 : India na Gasification, LLC

– Rockport, INIndiana 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 treatme nt 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

m easures 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: Identi fy Potential Control Technologies

In evaluating BACT for flare PM, PM 10 and PM 2.5 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 Pla n); and (3) Flare gas recovery

.

Add

- on PM, PM 10 and PM 2.5 controls that may be used on othe r 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 con trol 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 a cid 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 determi nation, 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/PM 10 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, O AQ has determined that the use of a p rocess 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 pro duce and use internally generated fuel gas streams such as petroleum refineries. Howe ver, flare gas recovery for this f acility 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 pro cess 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 th e Acid Gas Flare (EU

002 ) 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 d esign and p roper o peration

(2) Process flaring minimiza tion practices (Flare Minimization Plan)

These two co ntrols listed above are proposed to be implemented by the source

, therefore, no
ra nking of control technologies are needed.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM 10 and PM 2.5 BACT determination along with the existing PM, PM 10 and PM 2.5 BACT determinations for similar p lants. 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 Co ntrol 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 Cogenera tion, LLC 1 2/30/2010 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, PM 10 and PM 2.5 from the proposed Ac id 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 thatIndiana Gasification LLC Page 25 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 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 an d 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 continuo usly monitored to ass ure 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 BA CT for PM, PM 10 and PM 2.5 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 g ases 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 continuous ly monitored to assu re 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 emi ssions, 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 Prope r 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 a n elevated process flare is not enclosed or contained. Therefore, the emissions 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 pr oper 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 comm only used type of flares for emergency release control. Elevated flares are capable of extremely effective control of ventedIndiana 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 sit uations. 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 val ues). 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 f lare design and proper o peration 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 o f 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 p rocess 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 fu el 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 n on

- 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 b e 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 (EU

002 ) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The remaining technically feasible control technologies for flares are:

(1) Flare d esign and p roper o peration

(2) Process flaring minimization practices (Flare Minimization Plan)

These t wo co ntrols listed above are proposed to be implemented by the source

, therefore, no
ra nking of control technologies are needed.Indiana Gasification LLC Page 27 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 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 an d 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 ass ure the presence of a pilot flame with a thermocouple, infrared monitor, or other approved device.

Process fl aring 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 ca use” 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 documen ted

. 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 p lants. All data in the table is based on the informatio n 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 1 2/30/2010 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 * 1 3 ,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 timeIndiana 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 CO 2 . Flares are inherently efficient at combustion and the amount of CO emitted will pri marily 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 sha ll 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 preven tative 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 v isible 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 ass ure the presence of a pilot flame with a thermoc ouple, 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 comp ly 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 fla me with a thermocouple, infrared monitor, or other approved device.

Sulfur Dioxide (SO 2 ) BACT

- Acid Gas Flare (EU

- 002)

Step 1: Identify Potential Control TechnologiesIndiana Gasification LLC Page 29 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun In evaluating BACT for flare SO 2 emissions, there are limited process and/or add

- on control alternatives avai lable. 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 Minimizati on Plan); and (3 ) Flare gas recovery

. Add

- on SO 2 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 emis sions cannot be routed to an add

- on control device, and such add

on controls h ave not been utilized on flares

Step 2: Eliminate Technically Infeasible Options

Flare design and proper operation Flare design and proper operation

– Flare design and moni toring are key elements in the emissions performance of flares. However, SO 2 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 SO 2 purposes, flare design i s 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.

Pro cess 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 SO 2 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 p rocess 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 feasi ble 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 sce narios 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 dete rmination, IDEM, OAQ has determined that the use of a Flare Gas Recovery 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

The remaining technicall y 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 fl aring 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. Therefo re, 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 th ese 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 SO 2 BACT determination along with the existing SO 2 BACT determinations for similar p lants. 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 websit es 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 Flar e Minimization P lan

PSD

- LA

- 742(M1) Louisiana Lake Charles Cogeneration, LLC 1 2/30/2010 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 min imization 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 01/25/200 8 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 practicesIndiana Gasification LLC Page 31 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun

The Source is propos ing the follo wing as BACT from the Acid Gas Flare vents for SO 2 :
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 t o 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 SO 2 for Acid Gas Flare (EU

- 002)

. The permittee shall comply with the following Flare Minimization Plan to reduce emissions during flaring events. The pe rmittee 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 mea sures shall be implemented and documented.

Nitrogen Oxide (NO X ) 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 availab le. 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 NO x 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 I nfeasible 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 bu rners 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 effe ctive 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 (lowIndiana 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 con trols 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 fe asible for this, high gas flow, lower heating value application.
Based on the information reviewed for this BACT determination, IDEM, OAQ has determin ed that the use of f lare design and proper operation is not a technically feasible option for the Acid Ga s 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. F laring 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 feasib le 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 flar ing 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 receiv e 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 th e 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 Re maining 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. Therefo re, 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 th ese 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 p lants. 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 websit es 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

- LA

742(M1) Louisiana Lake Charles Cogeneration, LLC 1 2/30/2010 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 propos ing 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 caus e 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 identi fied 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/PM 10 /PM 2.5 ) BACT

– Auxiliary Boilers (EU

- 005 A and B)

Step 1: Identify Potential Control Technologies

Emissions of particulate matter (PM), particulate matter with an aerodynamic di ameter less than or equal to ten (10) micrometers (PM 10 ) and particulate matter with an aerodynamic diameter less than or equal to 2.5 micrometers ( PM 2.5 ) are generally controlled with add

- on control equipment designed to capture the emissions prior to the time they are exhausted to the atmosphere. The available technologies include:

(1) Cyclones ;

(2) Wet Scrubber s ;
(3) Electrostatic P recipitators (ESP); and

(4) Fabric Filter Dust Collectors (Baghouses).

The choice of which technology is most appropriat e 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 c ontrols 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: Eliminat e 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 typica lly cone

- shaped cyclone. Cyclones are used in applications with waste gas pollutant loadings of 1

– 100 gr/scf. Since the concentration of PM/PM 10 in the Auxiliary Boilers exhaust is very low (~0.005 gr/cf), a cyclone would not be effective at this sourc e.

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 beIndiana Gasification LLC Page 35 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun used but typical l oadings 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 ach ieve any appreciable particulate control.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that the wet s crubber is not a technically feasible option for the Auxiliary Boilers (EU

- 005A/B) at this source.

(c) Elect rostatic P recipitators 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/ft 3 . 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 determina tion, IDEM, OAQ has determined that the e lectrostatic p recipitator 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 particl es 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 concentrati on 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 inform ation reviewed for this BACT determination, IDEM, OAQ has determined that the fabric filter d ust c ollector is not a technically feasible option for the Auxiliary Boilers (EU

- 005A/B) at this source.

(e) Fuel Specifications

– Clean Burning Fuel: Clean burni ng natural gas and SNG have a very low potential for generating PM, PM 10 and PM 2.5 emissions.

(f) Good Combustion Practices / Combustion Controls: Good combustion practices as well as operation and maintenance of the Auxiliary Boilers to keep them in go od working order per the manufacturer's specifications will minimize PM, PM 10 and PM 2.5 emissions.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The following measures have been identified for control of PM, PM 10 and PM 2.5 r es ulting from the operation of the Auxiliary Boilers (EU

- 005A/B)

. (1) Fuel Specifications

– Clean Burning Fuel

(2) Good Combustion Practices / Combustion ControlsIndiana Gasification LLC Page 36 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 tabl e lists the proposed PM, PM 10 and PM 2.5 BACT determination for IG along with the existing PM, PM 10 and PM 2.5 BACT determinations for similar p lants. All data in the table is based on the information obtained from the permit application submitted by Indian a 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 M ethod Draft Permit No. 147

- 30464

- 000 60 Proposed Limit Indiana Gasification

- **proposed** P roposed Auxiliary Boiler (EU

005 A/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 Poi nt 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 G as * 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, PM 10 and PM 2.5 emis sions from the Auxiliary Boilers result only from fuel combustion (natural gas or SNG). Total PM/PM 10 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/ ds cf. This low concentration renders add

- on controls infeasible as described below.

Generally add

- on controls for PM, PM 10 and PM 2.5 are not applied to a combustion source firing only clean gaseous fuel. This is because the PM, PM 10 and PM 2.5 emissions are already ext remely low (~0.005 gr/ ds cf ), 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 R ACT/BACT/LAER Clearinghouse database did not indicate control technologies for PM/ PM 10 /PM 2.5 emissions from gas

- fired boilers. The combustion of clean gaseous fuel is inherently low in particulate ( PM, PM 10 and PM 2.5 ) emissions and add

- on controls

are no t feasible. Gas fired sources have expected emissions of 0.0075 lb/MMBtu PM, PM 10 and PM 2.5 (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 app ear 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, PM 10 and PM 2.5 for Auxiliary Boilers (EU

- 005A/B)

.Indiana Gasification LLC Page 37 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun

The PM, PM 10 and PM 2.5 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 o xidation;

(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 t hermal 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 2,000 o F. Once the unit is designed and built, the residence time is not easily changed, so that the required reaction temperature becomes a function of the particular gaseous species and the 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.

T he 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 h eating it to the combustion chamber outlet temperature. The process flows are then switched, feeding the inlet stream to the hot be d. This cyclic process affords high energy recovery (up to 95%). The higher capital costs associated with these high

- performa nce heat exchangers and combustion chambers may be offset by the auxiliary fuel savings to make such a system economical.Indiana Gasification LLC Page 38 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 oxid izer 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 cat alyst 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 speed s 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 ft 3 of catalyst per 1000 standard ft 3 per gas flow rat e.

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 b e 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 i n 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 i s 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 sup plementary fuel. Therefore, a secondary impact of the use of flare for this stream would be the creation of additional emissions from burning supplemental fuel, including NO x . Flares have not been utilized or demonstrated as a control device for CO from this type of high

volume process stream. In addition, the flare would have no additional control versus the thermal oxidizers.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that the use of a flare is a technic ally 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 o f 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 in complete 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 opti on for the Auxiliary Boilers.Indiana Gasification LLC Page 39 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 ) Re generative Thermal Oxidizer

- 99 % destruction efficiency

( 2 ) Oxidation Catalyst

- 75 % destruction efficiency

(3) Combustion Control

CO emis sions 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 fo llowing table lists the proposed CO BACT determination along with the existing CO BACT determinations for similar p lants. 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. 14 7

- 30464

- 000 60 Proposed Limit Indiana Gasification

- **proposed** P roposed Auxiliary Boiler (EU

005 A/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 Auxi liary 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 G as * 1119 MMB tu/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 sear ch 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 oxidat ion co ntrols 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 contr ol technology would not be cost effective since the CO concentration 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 TechnologyIndiana Gasification LLC Page 40 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun Fact Sheet for Regener ative 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 (al though 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 Exha ust

Control Alternative CO Emissions Emissions Reduction Control Capital

Cost Con trol Operating Cost Total Annualized Costs Cost Effectiveness Other Impacts Tons/yr tons/yr $ $/yr $/yr $/Ton CO

RTO 0.27 26.73 $9

, 800 ,000 $1

, 1 20,0 00 $ 2 ,240

, 0 00 $8 3

, 8 00 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 NO x ) which will at least partially offset any benefits of additional CO contro l.

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 C O 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 p ractices

.
Sulfur Dioxide (SO 2 ) BACT

- Auxiliary Boilers (EU

- 0 05 A and B)

Step 1: Identify Potential Control Technologies

Emissions of Sulfur dioxide (SO2) from Auxiliary Boilers are generally controlled by;

1. Flue Gas DesulfurizationIndiana Gasification LLC Page 41 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 feasibil ity of any control option is whether it is both available and applicable to reducing SO 2 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 spra y 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 SO 2 in the exhaust gas is the driving force for the reaction between SO 2 and the reagent. Therefore, removal efficiencies are significantly reduced with lower inlet concentrations of SO 2 . FGD systems are listed in the RBLC as BACT for

sources higher concentrations of SO 2 emissions. Even though the SO 2 concentrations in the exhaust g ases 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 concentrati on is a proven system which operates at or below 2500 ° F.

Add

- on SO 2 controls such as flue gas desulfurization described above, a common control in coal combustion, is not feasible for further control of SO 2 emissions because of inherently low SO 2 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 the re is no viable technology for controlling the SO 2 emissions resulting from the Auxi liary Boilers

. Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed SO 2 BACT determination along with the existing SO 2 BACT determinations for similar p lants. All data in the table is based on the i nformation 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 # Facilit y Issued Date Process Description Rating (TPH) Limitation Control Method Draft Permit No. 147

- 30464

- 00060 Proposed Limit Indiana Gasification

- **proposed** Proposed Auxiliary Boiler (EU

005A/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 Boile r * None None None

07

- 00534 Biomass Energy South Point Biomass 04/04/2006 Auxiliary Boiler * 247 MMBtu/Hr 0.60 lb/MMscf NoneIndiana Gasification LLC Page 42 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun

BACT ID or Permit # Facilit y 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 Fu el sulfur content limits

97019 Grays Ferry Cogen Partnership 03/21/2001 Auxiliary Boiler , Natural G as * 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 De terioration (PSD), IDEM has established the following as BACT for SO 2 for Auxiliary Boilers (EU

- 005A/B)

.
The SO 2 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 Ox ide (NO X ) 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 Reducti on (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: Eliminat e Technically Infeasible Options

Selective Catalytic Reduction (SCR) Selective Catalytic Reduction (SCR) process involves the mixing of anhydrous or aqueous ammonia vapor with flue gas and passing the mixture through a catalytic reactor to reduce NO X to N 2 and water . Under optima l 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 optim um decrease catalyst activity and allow NH 3 to slip through; above the optimum range, ammonia will oxidize to formIndiana Gasification LLC Page 43 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun

additional NO x . SCR efficiency is also largely dependent on the stoichiometric molar ratio of NH 3 :NO x ; 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 (S CR ) is a technically feasible option for the Auxiliary Boilers at this

sou rce.

Selective Non

- Catalytic Reduction (SNCR) With selective non

- catalytic reduction (SNCR), NO X is selectiv ely removed by the injection of ammonia or urea into the flue gas at an appropriate temperature window of 1600 ° F to 2000 ° F and without employing a catalyst. Similar to SCR without a catalyst bed, the injected chemicals selectively reduce the NO X to molecular nitrogen and water. This approach avoids the problem related to catalyst fouling but the temperature window and reagent mixing residence time is critical for conducting the necessary chemical reaction.

At the proper temperature, urea decomposes to produce ammonia which is responsible for NO X reduction. At a higher temperature, the rate of a competing reaction for the direct oxidation of ammoni a that actually forms NO x becomes significant

. At a lower temperature, the rates of NO X reduction reactions become too slo w resulting in urea slip (i.e. emissions of unreacted urea).

Optimal implementation of SNCR requires the employment of an injection system that can accomplish thorough reagent/gas mixing within the temperature window while accommodating spatial and production rate temperature variability in the gas stream. The attainment of maximum NO x control performance therefore requires that the fu rnace 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 o perating 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 te mperature.

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 ins tallation 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 techni cally feasible option for the Auxiliary Boilers at this source.

Flue Gas Recirculation (FGR) R ecirculating 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 reci rculation (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 throu gh the burner could lower NOx emissions to as little as 25% of their normal levels. FGR lower s NOx emissions i n two ways; t he coole r , relatively inert, recirculated flue gases act as heat sink, absorbing heat from the flame and lowering peak flame temperat ures and when mixed with the combustion air, recirculated flue gases lower the average oxygen content of the air, starving the NOx

- forming reaction s for one of the needed ingredients

.Indiana Gasification LLC Page 44 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, OA Q 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 Effectiven ess

(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% NO x 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 p lants. All data in the table is based on the inf ormation 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 # Facili ty Issued Date Process Description Rating (TPH) Limitation Control Method Draft Permit No. 147

- 30464

- 000 60 Proposed Limit Indiana Gasification

- **proposed** P roposed Auxiliary Boiler (EU

005 A/B) 408 MMBtu/hr 0.0125 lb/MMBtu based on 24

- hr block daily average

basis U ltra 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 Aux iliary 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 U sing Natural Gas

PSD TX

- 943 Corpus Christi Energy Center 02/04/2000 (3) Auxiliar y Boilers 1

- 3, AB1

- 3 * 315 MMBtu/Hr 0.06 lb/MMBtu None

97019 Grays Ferry Cogen Partnership 03/21/2001 Auxiliary Boiler , Natural G as * 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 f or installing SCR on these boiler s . The estimated cost

- effectiveness shown below of more than $80,000/ton NO x reduced is too high t o 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 Impacts Tons/yr tons/yr $ $/yr $/yr $/Ton NOx

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 Ap pendix C.

NSPS Subpart Db requires these boilers to achieve NO x performance of at least 0.1 lb NO x /MMBtu. A review of the RBLC for limited

- use auxiliary boilers indicates the use of Low

- NO x (LNB) or Ultra Low NO x burners (ULNB) with NO x performance rangi ng from 0.035 to 0.10 lb NO x /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 wi th 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 NO x emissions rate for any recently permitted boilers of this size regardless of operating rates.

Even further reduct ion 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 justif y 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 performan ce will be compromised during those significant swings in load.

(a) Proposal : Indiana Gasification , LLC

– Rockport, IN

The follow ing has been proposed as BACT for NOx from the proposed Auxiliary Boiler s (EU

- 005 ) :
Based on this analysis, BACT for the auxiliary boilers is proposed to be NO x 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 NO x 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 (PS D), 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 basi s and shall use Ultra Low NOx burner s with FGR

.
Particulate Matter (PM/ PM 10 / PM 2.5 ) BACT

– Regenerative Thermal Oxidizer (RTO) on the Acid Gas Removal Unit Vents (AGR) (EU

- 007A and B)

The acid gas removal (AGR) units remove CO 2 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 heat ing value of the CO 2 stream to be vented is very low ( it contains mostly non

- combustible CO 2 ), 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.

Althoug h 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 SO 2 , NOx and PM from this vent, none of which are present in the AGR vent upstream of the R TO. 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 SO 2 , 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 fue l 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 e qual to ten (10) micrometers (PM 10 ) and PM 2.5 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 P recipitators (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 physic al 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 o r 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 metho ds 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 ine rtial 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/PM 10 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 physica lly, 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 Pollu tion 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 fo r 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 P recipitators (ESP) An electrostatic precipitator is a particulate control device that uses e lectrical 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/ft 3 . 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 e lectrostatic p recipitator 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 outle t design concentration is 0.005 gr/s cf. 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 t hat 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 ha ve 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, PM 10 and PM 2.5 emissions f rom 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, PM 10 and PM 2.5 emission s. 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 ha ve been identified for control of PM, PM 10 and PM 2.5 r esulting 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 Contr ols and Document the Results

The following table lists the proposed PM, PM 10 and PM 2.5 BACT determination along with the existing PM, PM 10 and PM 2.5 BACT determinations for similar p lants . All data in the table is based on the information obtained from th e 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 Descr iption Rating (TPH) Limitation Control Method Draft Permit No. 147

- 30464

- 000 60 Proposed Limit Indiana Gasification

- **proposed** P roposed 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 , G ood 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 Non e

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 NoneIndiana 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 Descr iption 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, PM 10 and PM 2.5 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, H 2 S, COS and methanol in the AGR unit vent stream. The vented material (upstream of the RTO) contains no PM/PM 10 . The RTO itself has inherently low PM/PM 10 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/PM 10 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, PM 10 and PM 2.5 have ever been applied to a similar RTO or other gas

- only fired combustion source. The lack o f 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 normal ly 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 pe rmitted and similar SNG facilities

. The table shows their recently permitted PM, PM 10 and PM 2.5 limits. The emission rates for PM, PM 10 and PM 2.5 are comparable to other permitted emission of these similar facilities.

Step 5: Select BACT

Pursuant to 326 IAC 2

- 2

- 3 (Prevention of Signifi cant Deterioration (PSD), IDEM has established the following as BACT for PM, PM 10 and PM 2.5 for AGR Regenerative Thermal Oxidizer (EU

007A/B)

.
The PM, PM 10 and PM 2.5 emissions from the AGR Regenerative Thermal Oxidizer (EU

- 007A/B) operation shall not exce ed 0.29 pounds per hour , each, through the use of clean burning gaseous fuel and g ood 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 Ven t BACT analysis.Indiana Gasification LLC Page 50 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
Sulfur Dioxide (SO 2 ) BACT

- AGR Regenerative Thermal Oxidizer (EU

- 007A and B)

The acid gas removal (AGR) units remove CO 2 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 SO 2 , but the RTOs will oxidize small amounts of COS and H 2 S in the vent gas. The sulfur dioxide emissions from the AG R vent result almost entirely from the oxidation of the sulfur that was in the AGR vent stream. Because the heating value of the CO 2 stream to be vented is very low , supplemental natural gas or NSG fuel will be used and will also contribute a very small am ount of SO 2 to the emissions. However, less than 1% of the total SO 2 in this vent comes from the supplemental fuel.

Step 1: Identify Potential Control Technologies

Emissions of sulfur dioxide (SO 2 ) from this vent are primarily controlled by the inherent efficient design of the Rectisol acid gas removal system which results in a CO 2 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 th e Rectisol process for removal of acid gases (principally H 2 S and COS) from the syngas stream and subsequent conversion to sulfuric acid product. SO 2 emissions from the AGR vent are a function of the effectiveness of the AGR system in separating these sul fur

bearing streams out of the syngas and out of the captured CO 2 stream.

Physical solvent systems such as Selexol and Rectisol provide the highest level of control for this type of s ource. 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 R ectisol system is a technically feasible option for the Acid Gas Removal Unit Vents (EU

- 007A/B) at this source

Scrubber The SO 2 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 whi ch 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 H 2 S and COS, is converted in the ther mal oxidizer to SO 2 emissions. The SO 2 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 SO 2 fro m 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 pol lutant loading of approximately 250

- 2000 ppm SO 2 . In the very best cases, wet scrubbing systems reduce SO 2 to single digit ppm levels. H owever, the AGR vent is already 2 ppm SO 2 (because it is the product of an extremely effective sul fur scrubbing syst em

– 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 determin ation, 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 met hod for control of SO 2 emissions resulting from operation of the Acid Gas Removal Unit Vents at this source is the use of a Rectisol to conver t acid gases to sulfuric acid.

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed SO 2 BACT determination along with the existing SO 2 BACT determinations for similar p lants. All data in the table is based on the information obtained from the permit application submitted by Indiana Gasification, LLC, the U.S. EP A 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

- 3046 4

- 000 60 Proposed Limit Indiana Gasification

- **proposed** P roposed 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 Rec tisol , Proper design of AGR and Limit on Sulfur to RTO PSD

- LA

- 742(M 1) 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 Hype rion 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 1 1.0 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 CO 2 stream to the RTO to very low levels. The small residual sulfur in the AGR vent stream, in the form of H 2 S and COS, is converted in the thermal oxidizer to SO 2 emissions. IG expects potential S O 2 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 SO 2 in the exhaust. This is too low for further scrubbing to be effectiv e and there is no feasible add

- on control for SO 2 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 SO 2 compared to the above similar permitted facilities. Given the relative size of each facility and the proposed SO 2 emission rate, IG is achieving the lowest SO 2 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 Sig nificant Deterioration (PSD), IDEM has established the following as BACT for SO 2 for Acid Gas Removal Unit Vents (EU

- 007A/B)

.

T he SO 2 emissions shall be reduced by the use of a Rectisol process and the SO 2 emis sions shall not exceed 3.17 pounds per hour f or each Acid Gas Removal Unit Vent (EU

- 007A/B), based

on a 3

- hour average.

Nitrogen Oxide (NO X ) BACT

- AGR Regenerative Thermal Oxidizer (EU

- 007A and B)

The acid gas removal (AGR) units remove CO 2 from the syngas and it will normally be compressed to a li quid 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 val ue of the CO 2 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 combu stion 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 met hod s:

(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 N Ox 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 NO x . (NO x emissions from supplemental fuel combustion are estimated to result in NO x emissions equal to 0.05 lb NO x /MMBtu w hich 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 red uces the supplemental fuel used for combust ion 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 auto

ignition te mperature 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 NO x generated. (Note: Con ventional 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 tem perature of combustion and NO x formation, this design reduces NOx emissions versus conventional regenerative thermal oxidizers

All three of the above techniques are technically feasible and reduce NO x emissions.

Add

- on Controls Add

- on controls for NO x , such as SCR, SNCR and FGR are not feasible because the exhaust/vent stream is already extremely low in NO x concentration and flow to the RTO will be intermittent. The combustion stream that exits the RTO is diluted with the high

- volume process stream mak ing the NO x concentrations extremely dilute. NO x emissions at the stack outlet will be less than 2 ppm. This low concentration and low total mass of NO x emissions do not allow additional reductions through the use of any further add

- on controls to be tech nically 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 t he 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 simila r p lants. 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 othe r permitting agencies.

BACT ID or Permit # Facility Issued Date Process Description Rating (TPH) Limitation Control Method Draft Permit No. 147

- 30464

- 000 60 Proposed Limit Indiana Gasification

- **proposed** P roposed Acid Gas Removal Unit Vents (EU

- 007A/B) 1 0,400 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 ho ur 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 BurnersIndiana Gasification LLC Page 54 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 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 pe rmi tted and similar SNG facilities . The table shows their recently permitted NO x limits.

The emission rates for N Ox 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 V ents (EU

- 007A/B) shall be controlled by Low NOx Performance with natural gas injection and the NOx emissions shall not exceed 1.9 8 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 generall y controlled by efficient oxidation. Possible

c ombustion control technologies include:

(a) Regenerative Thermal oxidizer;

(b) Conventional Thermal oxidizer;

(c) Flare; and

(d) Catalytic Oxidation.

Step 2: Eliminate Technically Infeasible Options

Regener ative 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 waterIndiana Gasification LLC Page 55 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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 u se 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 in to 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 CO 2 is the most effective treatment for th is AGR Vent stream prior to venting to the atmosphere. Thermal oxidation will also control other contaminants in this stream by converting methanol to CO 2 and water, H 2 S to SO 2 and water and COS to SO 2 and CO 2 . To achieve thermal oxidation, air must be add ed and the combined stream heated to approximately 1600 degrees F.

The heating value of the CO 2 stream to the RTO is very low because it contains mostly non

combustible CO 2 (98%). Consequently, each RTO will have a natural gas/SNG burner to raise the tem perature in the combustion chamber of the RTO to 1600 degrees F. This ensures a high oxidation efficiency of the CO (99%), CH 3 OH (99%), H 2 S (98%), and COS (98%). Most of this heat is recovered by heating one of the heat transfer beds which will be used s ubsequently 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 w ould 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 H 2 S 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 CO 2 . Consequently, a conventional Thermal Oxidizer without heat

recover y 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 (NO x , VOC, PM 10 ).

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, H 2 S, and COS) concentrations are low to very low, the stream flow rate is very high. The low heating value of the CO 2 stream is too low for flaring. As there are insufficient organics in this vent stream to support combustion, use of a flare would require a significant addition of supplementary fuel. Therefore, a secondary impact of the use of flare for this stream would be the creation of additional emissions from burning supplemental fuel, including NO x . Flares h ave 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.Indiana Gasification LLC Page 56 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun

Based on the information reviewed for this BACT determi nation, IDEM, OAQ has determined that the use of a flare is a technically infeasible option for the Acid Gas Removal Unit Vents (EU

007A/B) at this source

Catalytic Oxidation A catalytic oxidizer is an add

- on control device to control VOC emissions by u sing 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 incin erator 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 CO 2 at temperatures ranging from 500 degrees F to 700 degrees F in the presence of a catalyst. Cat alytic 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: Eva luate 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 Descrip tion 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 48 pounds per hour based on 3 hour average,

each Regenerati ve 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 OxidizerIndiana 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 Descrip tion 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 1 0/26/2009 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 emissio n 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 (NO x and PM 10 ) 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 t hermal 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.

Th e 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 m ore 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 pou nds per hour for the Acid Gas Removal Unit Vents (EU

- 007A/B), each, based on a 3

- hour average

.

Particulate Matter (PM/PM 10 /PM 2.5 ) BACT

– Gasifier Preheat Burners (EU

- 008A

- E)

Step 1: Identify Potential Control Technologies

PM, PM 10 and PM 2.5 are generally controlled with add

- on control equipment designed to capture the emissions prior to the time they ar e exhausted to the atmosphere. Generally, PM, PM 10 and PM 2.5 emissions are controlled through one of the following mechanisms:

(1) Mechanical Collectors (su ch as Cyclones or Multiclones);

( 2 ) Wet Scrubbers;Indiana Gasification LLC Page 58 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun ( 3 ) Electrostatic P recipitators (ESP) ; and

( 4 ) Fabric Filter Dust Collectors (Baghouses)

. The choice of which technology is most appropriate for a specific application depends upon several factors, includi ng 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 O ptions

Add

- on - Control s The PM

, PM 10 and PM 2.5 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 wat er quench section of the gasifier where the quench water may serve to remove some of the PM. The resultant PM/ PM 10 / PM 2.5 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 c ontrols such as cyclones, baghouses, ESPs or wet scrubbers to effectively further reduce emissions. Also, regardless of the emissions rate, because a steam eductor draw s the exhaust out of the gasifier, the resultant very high moisture content of the exh aust 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 th is 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 Gasifi er 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 the re is no viable technology for controlling the PM, PM 10 and PM 2.5 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, PM 10 and PM 2.5 BACT determination along with the existing PM

, PM 10 and PM 2.5 BACT determinations for similar p lants. 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 versio ns 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

- 000 60 Proposed Limit Indiana Gasification

- **proposed** P ropo sed 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 operationIndiana 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

08180 1 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 bu ilt yet.

(a) Proposal : Indiana Gasification , LLC

– Rockport , IN The following has been proposed as BACT for the PM, PM 10 and PM 2.5 emissions from the Gasifier Preheat Burners (EU

- 008A

- E ) :

The PM, PM 10 and PM 2.5 emissions from the Gasifier Preheat Burne rs (EU

- 008A

- E ) operation shall be the use of clean burning gaseous fuel and the PM, PM 10 and PM 2.5 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 establis hed the following as BACT for PM, PM 10 and PM 2.5 for Gasifier Preheat Burners (EU

- 008A

- E)

.
The PM, PM 10 and PM 2.5 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 c ases. 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 auxi liary 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 th e high temperature zone , the waste gas

,Indiana Gasification LLC Page 60 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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 2,000 o F. Once the unit is designed and built, the residence time is not easily changed, so that the required reaction temperature becomes a function of the particular gaseous species and the desired le vel 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 throug h 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 d etermination, IDEM, OAQ has determined that the use of a regenerative thermal oxidizer is a technically in feasible option for the Gasifier Preheat Burners at this source.
Catalytic Oxidizers Catalytic oxidation is also a widely used control technology. Th e waste gas is passed through a flame area and then through a catalyst bed for complete combustion of the waste in the gas. This technology is typically applied for destruction of organic vapors, nevertheless it is considered as a technology for controlli ng CO emissions. A catalyst is an element or compound that speeds up a reaction at lower temperatures compared to thermal oxidation without undergoing change itself. Catalytic oxidizers operate at 650°F to 1000°F and approximately require 1.5 to 2.0 ft 3 of catalyst per 1000 standard ft 3 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 det ermined that the use of a catalytic oxidizer is a technically in feasible option for Gasifier Preheat Burners at this

source.

Flare Although the pollutants (CO, methanol, H 2 S, and COS) concentrations are low to very low, the stream flow rate is very high. The low heating value of the CO 2 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 combust ion 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.Indiana Gasification LLC Page 61 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun

Combustion Control Because CO is essential ly 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 combust ion 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 characteristi cs.
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 p lants. All data in the table is based on the information obtained from the permit application submitted by Indiana Gasificati on, 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

- 000 60 Proposed Limit Indiana Gasification

- **proposed** P roposed Gasifier Preheat Burners (EU

008A

- 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 d etermination 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

- 0 08A

- 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

.Indiana Gasification LLC Page 62 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 Dete rioration (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 practice s.

Sulfur Dioxide (SO 2 ) BACT

- Gasifier Preheat Burners (EU

- 008A

- E)

Step 1: Identify Potential Control Technologies

Emissions of Sulfur dioxide (SO 2 ) 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 SO 2 emissions from the Gasifier Preheat Burners (EU

- 008A

- E)

.

Low sulfur fuel These burners are pr oposed to use only natural gas or SNG. As a low

- sulfur fuel source, this will minimize SO 2 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 rea gent followed by particulate control or wet scrubber that uses limestone as a reagent. FGD is an established technology. The concentration of SO 2 in the exhaust gas is the driving force for the reaction between SO 2 and the reagent. Therefore, removal eff iciencies are significantly reduced with lower inlet concentrations of SO 2 . FGD systems are listed in the RBLC as BACT for sources high in SO 2 emissions. Wet scrubbing FGD system is considerably cheaper than dry scrubbing.

Add

- on SO 2 controls such as flu e gas desulfurization described above, a common control in coal combustion, is not feasible for further control of SO 2 emissions because of inherently low SO 2 emissions from a clean gas fired operation

.

The SO 2 emissions are inherently very low through t he use of natural gas or SNG . Clean natural gas combustion exhaust contains less than 2 ppm SO 2

. 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 SO 2 . In the very best cases, wet scrubbing systems can achieve up to as high as 98% control and reduce SO 2 to single digit ppm levels. However, this vent is alr eady less than 2 ppm SO 2 (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 SO 2 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

.Indiana Gasification LLC Page 63 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. Low sulfur fuel

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed SO 2 BACT determination along with the existing SO 2 BACT determinations for similar p lants. 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 websit es of other permitting agencies.

BACT ID or Permit # Facility Issued Date Process Description Rating (TPH) Limitation Control Method Draft Permit No. 147

- 30464

- 000 60 Proposed Limit Indiana Gasification

- **proposed** P roposed 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 Star tup 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 Illinoi s 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

– Ro ckport , IN

The following has been proposed as BACT for the SO2 emissions from the Gasifier Preheat Burners (EU

- 008A

- E ) :

The SO 2 emissions from the Gasifier Preheat Burners (EU

- 00 8 A

- E ) operation shall be Use of Clean burning gaseous fuel and the SO2 em issions 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 SO 2 for Gasifier Flare (EU

- 008A

- E)

.
The SO 2 emissions from the Gasi fier Preheat Burners (EU

- 008A

- E) operation shall not exceed 0.0006 lb SO 2 /MMBtu and shall u se 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 (NO X ) BACT

- Gasifier Preheat Burners (EU

- 008A

- E)

Step 1: Identify Potential Control Technologies

The nitrogen oxide (NOx) em issions 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 Cataly tic Reduction (SCR) process involves the mixing of anhydrous or aqueous ammonia vapor with flue gas and passing the mixture through a catalytic reactor to reduce NO X to water and nitrogen ( N 2 ) . Under optima l conditions, SCR has removal efficiency up to 90 % when used on steady state processes. The efficiency of removal will be reduced for processes that are not stable or require frequent changes in the mode of operation.

NOx add

- on controls such as SCR would not be effective in this service because SCR requires a specific narrow operating temperature range (about 480 o F to 800 o F) 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 2500 o 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 232 o 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 (S CR ) is not a technically feasible option for the Gasif ier 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 e ffectively 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 NO x burner technology. The extreme desired operating temperature is above the temperature that nitrogen breaks apart making NO x r eduction 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) R ecirculating 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 burner s 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 avera ge 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 du ring 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 revie wed for this BACT determination, IDEM, OAQ has determined that the re 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

T he following table lists the proposed NOx BACT determination along with the existing NOx BACT determinat ions for similar p lants. 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

- 000 60 Proposed Limit Indiana Gasification

- **proposed** P roposed 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 0.0 7 lb/MMBtu low NOx BurnersIndiana 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 03/21/2 000 #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 determ ination 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 communi cations 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 N O x emissions shall not ex ceed 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 Prehe at Burners (EU

- 008A

- E) operation shall not exceed 0.10 lb NOx /MMBtu and shall use good combustion practices.

NOx, CO, SO 2 and PM/PM 10 /PM 2.5 BACT

– Emergency Generators (EU

- 009A/B)

Step 1: Identify Potential Control Technologies

These generators are used i n 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 availabl e. Beyond the use of low sulfur diesel, which has beneficial impacts on both the SO 2 and particulate emissions of the unit, the emissions of Nitrogen oxide (NOx), CO, SO 2 , PM, PM 10 and PM 2.5 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: Ra nk the Remaining Control Technologies by Control Effectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that the re is no viable technology for controlling the NOx, CO, SO 2 PM, PM 10 and PM 2.5 emissions resultin g from the Emergency Generator s

. 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 emergen cy 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).

T hese emergency diesel e ngines 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 NO x , 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 desig n 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 t his 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 en gines 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, PM 10 and PM 2.5 emissi ons from the emergency generator s :
(1) NOx : emissions shall be limited through the implementation of good combu stion 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, PM 10 and PM 2.5 : emissions shall be l imited through the use of low

- S diesel (less than15ppm sulfur) and limited hours of non

- emergency operation;

(4 ) SO 2 : 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.

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, PM 10 and PM 2.5 BACT for the Emergency Generator s

.

The BACT for Emergency G enerator s 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: e missions shall be limited through the implementation of good combustion practices and limited hours of non

- emergency operation;

(3) PM, PM 10 and PM 2.5 : emissions shall be limited through the use of low

- S diesel (less than15ppm sulfur l) and limited ho urs of non

- emergency operation;

(4 ) SO 2 : 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

. Nitrogen Oxide (NO X ) , CO, SO 2 , PM/PM 10 /PM 2.5 BACT

- Firewater Pump Engine s (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 w hen needed. They will be designed to meet the applicable NSPS and NESHAP limited discussed below. Combustion design will be used by the manu facturer to meet those limits. These units will be operated on low sulfur diesel. Diesel has been chosen over nat ural 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 SO 2 and particulate emissions of the unit, the emissions of Nitrogen oxide (NOx), CO, SO 2 , PM, PM 10 and PM 2.5 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, SO 2 , PM, PM 10 and PM 2.5 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 E ffectiveness

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that the re is no viable technology for controlling the NOx, CO, SO 2 PM, PM 10 and PM 2.5 emissions resulting from the Firewater Pump Engines

. Step 4: Evalua te 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 wh ere 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).

T hese fir ewater 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 igniti on internal combustion engines. They establish emissions standards that must be me t by the manufacturer and owner/operator regarding N Ox , 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 Sub part IIII, NESHAPS Subpart ZZZZ and the burning of fuels with no more than 15 ppm sulfur for all BACT pollutants. T he non

- emergency operation of these engines will be limited to no more than 52 hours per year each.

(a) Proposal: Indiana Gasification, L LC

- Rockport, IN

The following has been proposed as BACT for the NOx, CO, SO 2 PM, PM 10 and PM 2.5 emissions from the firewater pump engines :
(1) NOx : emissions shall be limited through the implementation of good combustion practices and limited ho urs 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, PM 10 and PM 2.5 : emissions shall be limited through the use of low

- S die sel (less than15ppm sulfur l) and limited hours of non

- emergency operation;

(4 ) SO 2 : 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 n ot exceed 52 hours per year of non

emergency 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, SO 2 PM, PM 10 and PM 2.5 BACT for the Firewater Pu mp 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 l imited through the implementation of good combustion practices and limited hours of non

- emergency operation;

(3) PM, PM 10 and PM 2.5 : emissions shall be limited through the use of low

- S diesel (less than15ppm sulfur ) and limited hours of non

- emergency o peration;

(4 ) SO 2 : 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

.

Parti culate Matter (PM/PM 10 /PM 2.5 ) BACT

– Process Area Solid Feedstock Conveying, storage and feedbin (EU

- 011 A and B)

Step 1: Identify Potential Control Technologies

The emissions of PM, PM 10 and PM 2.5 are generally controlled by the following add

- on control

e quipment 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 approp riate 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 des ired 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, o r 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 ope rated 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 fi lters collect particles with sizes ranging from submicron to several hundred microns in diameter at efficie ncies generally in excess of 99%

. The layer of dust, or dust cake, collected on the fabric is primarily responsible for such high efficiency. The c ake 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 a ppears 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 i mposed 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 characteristi cs, gas characteristics, and fabric properties.

The most important design parameter is the air

- or gas

- to

- cloth ratio (the amount of gas in ft 3 /min that penetrates one ft 2 of fabric) and the usual operating parameter of interest is pressure drop across t he 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 conce ntrations.

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 smalle r 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 minimize s 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 fro m 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 Proces s 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, interceptio n 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 re moval 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 f easible 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 applica tions, 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 rem ove 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 f easible 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 mechan isms 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 t he 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 foa ms 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 fe asible 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, PM 10 and PM 2.5 r esulting 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 grea ter 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 alternati ve for control of particulate matter emissions from the Process Area Soli d 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, PM 10 and PM 2.5 BACT determination along with the existing PM, PM 10 and PM 2.5 BACT deter minations for similar p lants. 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 Feed stock Conveying, storage and feedbin 10,400 T dry coal/day PM/PM 10 /: 0.003 gr/dscf PM 2.5 : 0.00 15 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 controlIndiana 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

- LA

742(M1) Louisiana Lake Charles Cogen eration, 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 specif ication 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, PM 10 and PM 2.5 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 s ignificant additional cost.

According to IG’s engineering design firm, achieving 0 .001 gr/dscf is very difficult and expensive for a bulk material handling baghous e . It is generally achievable with PTFE (Teflon) bags, very low air

- to

- cloth ratio ( i.e. : req uiring 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 va por 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 emiss ions 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, PM 10 and PM 2.5 from the proposed Proce ss Area Solid Feedstock Conveying, storage and feedbin (EU

- 011A/B) :
(1) The construction of a baghouse for control of PM, PM 10 and PM 2.5 emissions.

(2) The PM and PM 10 maximum outlet concentration of 0.00 3 gr/dscf.

(3) The PM 2.5 maximum outlet concentra tion 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, PM 10 and PM 2.5 for Process Area Solid Feedstock Conveying, storage and feedbin (EU

- 01 1A/B)

. (1) The PM, PM 10 and PM 2.5 emissions from the Process Area Solid Feedstock Conveying, storage and feedbin (EU

- 011A/B) shall be limited through a baghouse

. (2) The PM and PM 10 maximum outlet concentration of 0.003 gr/dscf.

(3) The PM 2.5 maximum out let concentration of 0.0015 gr/dscf.

Particulate Matter (PM/PM 10 /PM 2.5 ) 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

, PM 1 0 and PM 2.5 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., t emperature, 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 elimi nates 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 Sup pression: 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 suppr ession 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 informat ion 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

- 012 A) at this source.
Step 3: Rank the Remaining Control Technologies by Control Effectivenes s

(1) Wet Suppression (90 % PM/PM 10 /PM 2.5 Reduction).

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM 10 and PM 2.5 BACT determination along with the existing PM, PM 10 and PM 2.5 BACT dete rminations for coal handling facilitie s . 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 av ailable at the websites of ot her 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 Ba rge 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

areaIndiana 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 emission s by 95% Chemical suppressant with 95% control

CO

- 0057

- Colorado Public Service Company of C olorado 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 inc lude 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 Low ering 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 waterin g 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 f acilities 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 liste d 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, PM 10 and PM 2.5 from the proposed Barge Unloading to hopper transfer point (EU

- 012 A) :
(1) The PM, PM 10 and PM 2.5 emissions from the barge unloading to hop per transfer point shall be control led 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, PM 10 and PM 2.5 for barge unloading (EU

- 01 2 A)

.
The PM, PM 10 and PM 2.5 emissions from the barge unloading to hopper transfer point (EU

- 012 A) operation shall be controlled by a wet suppressi on with a control efficiency of 90%.

Particulate Matter (PM/PM 10 /PM 2.5 ) BACT

– Rail Unloading to Rail Hoppers (EU

- 012 G/H )

Step 1: Identify Potential Control Technologies

The emissions of PM, PM 10 and PM 2.5 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 depe nds 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: E liminate Technically Infeasible Options

T hese material handling steps are fully enclosed and proposed to be vented through a dust control system.

Fabric Fil t er (Baghouse) A baghouse fabric filter unit consists of one or more isolated compar tments 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 efficie ncies generally in excess of 99 %.

The layer of dust, or dust c ake, 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 accommoda ted 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 filt ers 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 ft 3 /min that penetrates one f t 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 b y 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 t he 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 Ra ilcar 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, wh ich is described next. Since they are no more effective than the se control strateg ies , 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 a n 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 simila r 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 du st/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 t hat 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 (Baghous es) (>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 E ffective Controls and Document the Results

The following table lists the proposed PM, PM 10 and PM 2.5 BACT determination along with the existing PM, PM 10 and PM 2.5 BACT determinations for coal handling operations . All data in the table is based on the info rmation 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 I ssued 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/ PM 10 : 0.00 3 gr/dscf PM 2.5 : 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

- LA

742(M1) Lou isiana 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, PM 10 and PM 2.5 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 contr ol 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 baghous e . 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 emissio ns 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 achiev e 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, PM 10 and PM 2.5 from the proposed Rail Unloading to Rail Hoppers (EU

- 012G/H):

(1) The PM, PM 10 and PM 2.5 emissions from the railcar unloading to rail hoppers shall be controlled by either wet dust extraction or a baghouse

. (2) The PM and PM 10 m aximum outlet concentr ation shall not exceed 0.0 0 3 gr/dscf

. ( 3 ) The PM 2.5 maximum outlet concentration shall not exceed 0.001 5 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 f or PM, PM 10 and PM 2.5 for the Railcar Unloading (EU

- 012G/H )

. (1) The PM, PM 10 and PM 2.5 emissions from the railcar unloading to rail hoppers shall be controlled by wet dust extraction or a baghouse

. (2) The PM and PM 10 maximum outlet concentration shall not exceed 0.0 0 3 gr/dscf

. (3 ) The PM 2.5 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/PM 10 /PM 2.5 ) BACT

– Barge Unloading from the Hopper to the Belt (EU

- 012B) and Barge Conveyor Transfer Points (EU

- 012 C

- F )

Step 1: Identify Potential Control Technologies The emissions of PM, PM 10 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 colle cted, 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

T hese material handli ng 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, f lat, 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 atmosp here. 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 subsequ ent disposal. Fabric filters collect particles with sizes ranging from submicron to several hundred microns in diameter at efficienci es generally in excess of 99 %.

The layer of dust, or dust cake, collected on the fabric is primarily responsible for suc h 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 req uired. 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 includ e particle characteristics, gas characteristics, and fabric properties.

The most important design parameter is the air

- or gas

- to

- cloth ratio (the amount of gas in ft 3 /min that penetrates one ft 2 of fabric) and the usual operating parameter of interest i s 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 particul ate air (HEPA) filters, high efficiency air filters (HEAFs), and automotive induction air filters are examples of filters that must be discarded after a significantIndiana 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 thi s 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 effec tive 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 in to 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 simila r level of control as baghouses. However wastewater treatment and water freezing in cold weather result in higher mainte nance 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/wat er 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 n eeded 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 un it 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 Stac ker ( EU

- 012B

- F ) at this source.
Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1) Baghouse fabric filter (>99% PM/PM 10 /PM 2.5 Reduction)

(2) Wet Dust Extraction ( ≥ 99 % PM/PM 10 /PM 2.5 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, PM 10 and PM 2.5 BACT determination along with the existing PM, PM 10 and PM 2.5 BACT determinations for coal handling operations . All data in the table is based on the inf ormation 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/ PM 10 : 0.00 3 gr/dscf PM 2.5 : 0.0015 gr/dscf Baghous e 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 E nergy Indiana

- Edwardsport 01/25/2008 Coal

- Coke Handling System (2 identical facilities) * 630 MW 0.003 gr/dscf Baghouse

PSD

- LA

742(M1) Louisiana Lake Charles Cogeneration, LLC 12/30/2010 Coal

- Coke Handling System (2 identical facilities) * 9,413 T/D 0.00 5 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) * 77 0 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 d atabase for baghouses and is standard design for an efficient baghouse. In special circumstances, baghouses can be designed to achieve even lower outlet PM, PM 10 and PM 2.5 emissions. Evidently, as shown in the above table, the Power Holdings and Duke Edw ardsport 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 baghous e . 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 structur es, 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. Th is 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, PM 10 and PM 2.5 from the proposed Barge Unloading from the Hopper to the Belt (EU

- 012B) and Barge Conveyor Transfer Points ( EU

012C

- F ) :
(1) The PM, PM 10 and PM 2.5 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 PM 10 m aximum outlet concentration shall not exceed 0.0 0 3 gr/dscf

. (3 ) The PM 2.5 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 a s BACT for PM, PM 10 and PM 2.5 for the Conveyance from barge Hopper to Pile Stacker (EU

- 012B

- F )

. (1) The PM, PM 10 and PM 2.5 emissions from the Barge Unloading from the Hopper to the Belt (EU

- 012B) and Barge Conveyor Transfer Points (EU

- 012C

- F ) shall be con trolled by a wet dust extraction or a baghouse

. (2) The PM and PM 10 maximum outlet concentration shall not exceed 0.0 0 3 gr/dscf

. (3 ) The PM 2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Particulate Matter (PM/PM 10 /PM 2.5 ) BACT

– Rail Hopper s Unloading to the Conveyor Belts (EU

- 012I

- J) and Rail Conveyor Belt to the Stacker (EU

- 012 K )

Step 1: Identify Potential Control Technologies The emissions of PM, PM 10 and PM2.5 are generally controlled by the following add

- on control equipment des igned 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 materia ls), and desired collection efficiency.

Step 2: Eliminate Technically Infeasible Options

T hese material handling steps are fully enclosed and proposed to be vented through a dust control system.

Fabric Filter (Baghouse) A baghouse fabric fi lter 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 g enerally 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 50 0°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 affec t 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 (t he amount of gas in ft 3 /min that penetrates one ft 2 of fabric) and the usual operating parameter of interest is pressure drop across the filter system. The major operating feature of fabric filters that distinguishes them from other gas filters is the abil ity 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 a fter 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 bag house 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 extractio n 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 a re 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 simila r 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 lad en 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 wat er 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 wate r 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/PM 10 /PM 2.5 Reduction)

(2) Wet Dust Extraction ( ≥ 99% PM/PM 10 /PM 2.5 Reduction).

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM 10 and PM 2.5 BACT determination along with the existing PM, PM 10 and PM 2.5 BACT determinations for coal han dling 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

- LA

742(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 05/0 5/2010 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. Th is 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, PM 10 and PM 2.5 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.

A ccording to IG’s engineering design firm, achieving 0 .001 gr/dscf is very difficult and expensive for a bulk material handling baghous e . It is generally achievable with PTFE (Teflon) bags, very low air

- to

- cloth ratio ( i.e. : requiring a large unit), a low p ressure/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 dropl ets 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/ds cf 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, PM 10 and PM 2.5 from the proposed Rail Hopper Unloading to the Con veyor Belts (EU

- 012I

- J) and Rail Conveyor Belt to the Stacker (EU

012K):

(1) The PM, PM 10 and PM 2.5 emissions shall be controlled by a wet dust extraction or a baghouse

. (2) The PM and PM 10 m aximum outlet concentration shall not exceed 0.0 0 3 gr/dscf

. ( 3 ) The PM 2.5 maximum outlet concentration shall not exceed 0.001 5 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, PM 10 and PM 2.5 for the Rail Hopper Unloading to the Conveyor Belts (EU

- 012I

- J) and Rail Conveyor Belt to the Stacker (EU

- 012K):

(1) The PM, PM 10 and PM 2.5 emissions shall be controlled by a wet dust extraction or baghouse

. (2) The PM and PM 10 maximum outlet concentration shall not exceed 0.0 0 3 gr/dscf

. (3 ) The PM 2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Particulate Matter (PM/PM 10 /PM 2.5 ) BACT

– Stacker Belt s to the Radial Stacker (EU

- 012 L

- M )

Step 1: Identify Potential Control Technologies The emissions of PM, PM 10 and PM 2.5 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 (E SP);

(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 physi cal characteristics (e.g., temperature, moisture content, presence of reactive materials), and desired collection efficiency.

Step 2: Eliminate Technically Infeasible Options

T hese material handling steps are fully enclosed and proposed to be vented throug h 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 ra nging from submicron to several hundred microns in diameter at efficienci es 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 b ags 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 (tempe rature 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 ft 3 /min that penetrates one ft 2 of fabric) and the usual operating parameter of interest is pressure drop across the filter system. The major operatin g 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 concentr ations 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 cyclo nes 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 a n extractor panel and demister. Dust is expected to be controlled to the high effi ciency of 99.7% for the IG facility. This alternative technology achieves a simila r 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 act ion 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 extra ctor 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 Remaini ng Control Technologies by Control Effectiveness

(1) Baghouse fabric filter (>99% PM/PM 10 /PM 2.5 Reduction)

(2) Wet Dust Extraction ( ≥ 99% PM/PM 10 /PM 2.5 Reduction).

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM 10 and PM 2.5 BACT determination along with the existing PM, PM 10 and PM 2.5 BACT determinations for coal han dling 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

c oal/day PM/ PM 10 : 0.00 3 gr/dscf PM 2.5 : 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 controlIndiana 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

- LA

742(M1) Louisiana Lake Charles Cogeneration , LLC 12/30/2010 Coal

- C oke 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. Th is 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, PM 10 and PM 2.5 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.

A ccording to IG’s engineering design firm, achieving 0 .001 gr/dscf is very difficult and expensive for a bulk material handling baghous e . It is generally achievable with PTFE (Teflon) bags, very low air

- to

- cloth ratio ( i.e. : requiring a large unit), a low p ressure/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 dropl ets 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/ds cf 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 9 3 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, PM 10 and PM 2.5 from the proposed Stacker Belt s to the Radial S tacker (EU

- 012 L

- M ) :
(1) The PM, PM 10 and PM 2.5 emissions from the Stacker Belts to the Radial Stacker shall be controlled by a wet dust extraction or a baghouse

. (2) The PM and PM 10 m aximum outlet concentration shall not exceed 0.00 3 gr/dscf

. (3 ) The PM 2.5 maximum outlet concentration shall not exceed 0.001 5 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, PM 10 and PM 2.5 for the Stacker Belt to St acker (EU

- 012L

- M )

. ( 1) The PM, PM 10 and PM 2.5 emissions from the Stacker Belts to the Radial Stacker shall be controlled by a wet dust extraction or a baghouse

. (2) The PM and PM 10 maximum outlet concentration shall not exceed 0.00 3 gr/dscf

. (3 ) The PM 2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Particulate Matter (PM/PM 10 /PM 2.5 ) BACT

– T ransfer systems consisting of hoppers and conveyor belts transferring feed stock from the piles to classification towers (EU

– 012R

- S); Classifica tion towers (EU

- 012T

- U); and Classification tower to a day bin (EU

- 012 V )

Step 1: Identify Potential Control Technologies The emissions of PM, PM 10 and PM2.5 are generally controlled by the following add

- on control equipment designed to capture the emissio ns 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 spec ific 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

T hese 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 on e 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 retaine d 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 accumulate d 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 efficie ncies 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 abou t 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 inche s 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 oper ation 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 ft 3 / min that penetrates one ft 2 of fabric) and the usual operating parameter of interest is pressure drop across the filter system. The major operating feature of fabric filters that distinguishes them from other gas filters is the ability to renew the filteri ng 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 se wn 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 f easible option for the T ransfer 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 sourc e.

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 th e 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 a n extractor panel and demister. Du st is expected to be controlled to the high efficiency of 99.7% for the IG facility. This alternative technology achieves a simila r level of control as baghouses . However wastewaterIndiana 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 maintenanc e 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. T he 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 need ed 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 T ransfer systems consisting of hoppers and c onveyor 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 Effec tiveness

(1) Baghouse fabric filter (>99% PM/PM 10 /PM 2.5 Reduction)

(2) Wet Dust Extraction ( ≥ 99% PM/PM 10 /PM 2.5 Reduction).

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM 10 and PM 2.5 BACT determination along with the existing PM, PM 10 and PM 2.5 BACT determinations for coal han dling 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

c oal/day PM/ PM 10 : 0.00 3 gr/dscf PM 2.5 : 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 BaghouseIndiana 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

- LA

742(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 05/0 5/2010 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. T his 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, PM 10 and PM 2.5 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 baghous e . 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 drop lets 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/d scf 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 cos t

- 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, PM 10 and PM 2.5 from the proposed T ransfer 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, PM 10 and PM 2.5 emissions shall be controlled by a we t dust extraction or a baghouse

. (2) The PM and PM 10 m aximum outlet concentration shall not exceed 0.0 0 3 gr/dscf

. (3 ) The PM 2.5 maximum outlet concentration shall not exceed 0.001 5 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, PM 10 and PM 2.5 for the T ransfer systems consisting of hoppers and conveyor belts transferring feed stock from the piles to classification towers (EU

– 012R

- S); Classificat ion towers (EU

- 012T

- U); and Classification tower to a day bin (EU

- 012V )

. (1) The PM, PM 10 and PM 2.5 emissions shall be controlled by a wet dust extraction or a baghouse

. (2) The PM and PM 10 maximum outlet concentration shall not exceed 0.0 0 3 gr/dscf

. ( 3 ) The PM 2.5 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/PM 10 /PM 2.5 ) BACT

– Radial Stacker s to the Pile (EU

- 012 N

- O )

Step 1: Identify Potential Control Technologies

The emissions of PM, PM 10 and PM2.5 are generall y 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 C hutes.

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, moistu re 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 enclos ed 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 d evice. 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 fabri c 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 dep osited in a hopper for subsequent disposal. Fabric filters collect particles with sizes ranging from submicron to several hundred microns in diameter at efficie ncies 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 configurati ons. 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 efficienc y 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. Import ant process variables include particle characteristics, gas characteristics, and fabric properties.

The most important design parameter is the air

- or gas

- to

- cloth ratio (the amount of gas in ft 3 /min that penetrates one ft 2 of fabric) and the usual opera ting 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 filte rs, 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 typ ically 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 d ust, 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 sophisticat ed 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 ) a t this source if used as part of a system that includes enclosure of the emissionsIndiana 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 e missions 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 b y 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 Ra dial 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 tele scoping 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 telesco ping tube with a fan vented to a dust collector filter system. This system guarantees 99.9% dust collector control efficiency with an outlet loadi ng compar a ble to other baghouses 0.005 gr/dscf particulates

.

Based on the information reviewed for this B ACT 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 Effective ness

The above control technologies have been identified for control of PM, PM 10 and PM 2.5 r esulting 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 eff iciency 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 alternati ves for control of particulate matter emissions from the Radial Stackers to the Pile (EU

012N

- 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, PM 10 and PM 2.5 BACT determination a long with the existing PM, PM 10 and PM 2.5 BACT determinations for similar p lants. 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 (RBL C), 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 Gasi fication

- **proposed** Proposed Coal/Coke Barge Unloading and Storage 10,400 T dry coal/day PM/PM 10 : 0.003 gr/dscf PM 2.5 : 0.0015 gr/dscf Telescoping Chute with dust collect ion or Baghouse

081801 AAF (Application No. 07100063) Power Holdings of Illinois Gasif ication 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 M W 0.003 gr/dscf Baghouse

PSD

- LA

742(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 identica l 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 majorit y 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 circumstance s, baghouses can be designed to achieve even lower outlet PM, PM 10 and PM 2.5 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 han dling 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 baghous e . It is generally ach ievable 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 c ollector 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 ad ditional 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 a nd 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 followi ng has been proposed as BACT for PM, PM 10 and PM 2.5 from the proposed Radial Stackers to the Pile (EU

- 012 N

- O ) :
(1) The PM, PM 10 and PM 2.5 emissions shall be controlled by a Telescoping chute with dust collection

. (2) The PM and PM 10 maximum outlet conce ntration shall not exceed 0.0 0 3 gr/dscf , each.

(3 ) The PM 2.5 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, PM 10 and PM 2.5 for Radial Stackers to the Pile (EU

- 012N

- O )

. (1) The PM, PM 10 and PM 2.5 emissions shall be controlled by a Telescoping chute with dust collection.

(2) The PM and PM 10 maximum outlet concentration shall not exceed 0.0 0 3 gr/d scf , each.

(3 ) The PM 2.5 maximum outlet concentration shall not exceed 0.0015 gr/dscf.

Particulate Matter (PM/PM 10 /PM 2.5 ) BACT

– Storage Pile s (EU

- 012 W/X)

Step 1: Identify Potential Control Technologies

The emissions of PM, PM 10 and PM2.5 are often cont rolled 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, prese nce 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 s uppression 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 air borne 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 a gent 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% particulat e matter (PM 10 ). (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 Pi le s (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 devic e 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 ch emical 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 (PM 10 ).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, PM 10 and PM 2.5 BACT determination along with the existing PM, PM 10 and PM 2.5 BACT determinatio ns for coal handlin g 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 o ther 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 emission s by 95% Chemical suppressant with 95% control

CO

- 0057

- Colorado Public Service Company of Colorado Comanche Station 07/05/2 005 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, du st 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

- 03 17 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 emission s. 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

ma terial 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 : Ind iana Gasification , LLC

– Rockport, IN T he following has been proposed as BACT for PM, PM 10 and PM 2.5 from the proposed Storage Piles (EU

- 012W/X ) :
(1) The PM, PM 10 and PM 2.5 emissions shall be controlled by wet suppression with pile compaction with a contr ol 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, PM 10 and PM 2.5 for Storage Piles (EU

- 01 2W/X).

The PM, PM 10 and PM 2.5 emissions from t he Storage Piles (EU

- 01 2W/X ) ope ration shall be controlled by wet s uppression with pile compaction with a control efficiency of 90 %

.
Particulate Matter (PM/PM 10 /PM 2.5 ) BACT

– Dozer Activities (EU

- 012 P/Q)

Step 1: Identify Potential Control Technologies

The emissions of PM, PM 10 and PM 2.5 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 characte ristics (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 technica lly 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 liq uid 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 t hat 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 (PM 10 ). (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 ad ditives 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/PM 10 /PM 2.5 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 tha t 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 appl y wet or chemical suppression to achieve reduction of 90% particulate matter (PM 10 ).

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM 10 and PM 2.5 BACT determination along with the existin g PM, PM 10 and PM 2.5 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 ele ctronic 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

areaIndiana 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 emission s by 95% Chemical suppressant with 95% control

CO

- 0057

- Colorado Pub lic 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

un loading

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 Suppressi on, 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 sup pressants 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 n ot normally considered practicable.

(a) Proposal : Indiana Gasification , LLC

– Rockport, IN

The following has been proposed as BACT for PM, PM 10 and PM 2.5 from the proposed Dozer Activit ies (EU

- 012P/Q ) :
(1) The PM, PM 10 and PM 2.5 emissions from the Doz er Activit ies (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 B ACT for PM, PM 10 and PM 2.5 for Dozer Activit ies (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, PM 10 and PM 2.5 emissions from the Dozer Activit ies (EU

- 012P/Q ) operation shall be

con trolled by wet s uppression with pile compaction with a control efficiency of 90 %

.

Particulate Matter (PM/PM 10 /PM 2.5 ) 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

- 012 AA)

Step 1: Identify Potential Control Technologies

The emissions of PM, PM 10 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/extractio n/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 ga s 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, al ternating 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 partic les with sizes ranging from submicron to several hundred microns in diameter at efficie ncies 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 wi th 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 chara cteristics (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 characteris tics, 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 ft 3 /min that penetrates one ft 2 of fabric) and the usual operating parameter of interest is pressure drop across the filter system. Th e 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 whe re dust concentrations are relatively low. Fabric filters are usually made of woven or (more commonly) needle

- punched felts sewn to the desired shape, mounted in a plenum with special hardware, and used across a wide range of dust concentrations.
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

- 012 Y

- AC ) at this source.

Wet Extraction System Wet extraction systems are designed sp ecifically 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 at omized water droplets which are removed from the fan exhaust in a n extract or 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 wit h 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 ext ractor 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 aw ay. 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 Tr uck unloading (EU

012 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/PM 10 /PM 2.5 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, PM 10 and PM 2.5 BACT determination along with the exi sting PM, PM 10 and PM 2.5 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 Gasificatio n - **proposed** Proposed Coal/Coke T ruck Unloading and Conveyance 10,400 T dry coal/day PM/ PM 10 : 0.00 3gr/dscf PM 2.5 : 0.0015 gr/dscf Baghouse

or Wet Dust Extraction System

081801 AAF (Application No. 07100063) Power Holdings of Illinois Gasification 10/26/20 09 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

- LA

742(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) * 4 00,000 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 b aghouse 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, PM 10 and PM 2.5 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 baghous e . It is generally achievable with PTF E (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 cos ts 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 unitIndiana 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 propo sed as BACT for PM, PM 10 and PM 2.5 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 ex traction system or a baghouse for control of PM, PM 10 and PM 2.5 emissions.

( 2) The PM and PM 10 maximum outlet concentration s hall not exceed 0.0 0 3 gr/dscf.

(3 ) The PM 2.5 maximum outlet concentration shall not exceed 0.001 5gr/dscf.

Step 5: Select BACT

P ursuant to 326 IAC 2

- 2

- 3 (Prevention of Significant Deterioration (PSD), IDEM has established the following as BACT for PM, PM 10 and PM 2.5 for the Truck/rail conveyor transfer tower (EU

012Y); truck stations unloading to a truck hopper (EU

- 012AB

- AC); and t ruck hopper unloading to the conveyor belts (EU

- 012AA).

(1) The PM, PM 10 and PM 2.5 emissions from the 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) shall be controlled by an enclosed vent to a wet dust extraction system or baghouse

. (2) The PM and PM 10 maximum outlet concentration shall not exceed 0.003 gr/dscf.

(3) The PM 2.5 maximum outlet concentration shall not exceed 0.0015gr/dscf.

Particulate Matter (PM/PM 10 /PM 2.5 ) BACT

– Rod Mill Vent (EU

- 013A

- D)

Step 1: Identify Potential Control Technologies

Emissions PM, PM 10 and PM2.5 are generally controlled with add

- on control equipment designed to capture the emissions prior to the time the y are exhausted to the atmosphere. In cases where the material being emitted is organic, particulate matter may be controlled through a combustion process. Generally, PM and PM 10 emissions are controlled through one of the following mechanisms:

(1) Mech anical Collectors (such as Cyclones or Multiclones); ( 2 ) Wet Scrubbers; ( 3 ) Electrostatic P recipitators (ESP) ; andIndiana 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

se veral 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 T echnically Infeasible Options

(a) Add

- on Control Technology: The rod

- mill eductor has a small amount of particulate (PM 10 emission s are estimated to be 0.44 tons per y ea r total for four rod mills ). This low emissions rate is due to the fact that the rod

- mi ll 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/ d scf PM/PM 10 , which is equivalent to 0.025 pounds per hour at permitted capa city , and 0.0047 grains/dscf PM 2.5 , 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 f urther 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 list ed 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 the re is no viable technology for controlling the PM/PM 10 /PM 2.5 emissions resulting from the Rod Mill Vent (EU

- 013A

- D)

. Step 4: Evaluate the Most Effective Controls and D ocument the Results

Proposal : Indiana Gasification, LLC The following has been proposed as BACT for PM/PM 10 /PM 2.5 from each proposed Rod Mill Vent at the Indiana Gasification Plant.

For each Rod Mill Vent, BACT for PM/PM 10 is proposed to be 0.025 pounds per hour based on a 3

- h ou r average and for PM 2.5 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 fo r PM/PM 10 /PM 2.5 for the Rod Mill Vent s

. (a) The PM and PM 10 emissions from each Rod Mill Vent s shall not exceed 0.025 pounds per hour based on a 3

- h ou r average

. (b) The PM 2.5 emissions from each Rod Mill Vent shall not exceed 0.0 074 pounds per hour based on a 3

- h ou r average.Indiana Gasification LLC Page 113 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
Particulate Matter (PM/PM 10 /PM 2.5 ) BACT

– ASU Regeneration Vent (EU

- 017A and B)

Step 1: Identify Potential Control Technologies

Emissions of PM , PM 10 and PM 2.5 are generally controlled with add

- on control equipment designed to capture the emissions prior to the time they are exhausted to the atmosphere. In cases where the material being emitted is organic, particulate matter may be controlled through a combustion process. Generally, PM/ PM 10 / PM 2.5 emissions are controlled through one of the following mechanisms:

(1) Mechanical Collectors (such as Cyclones or Multiclones);

( 2 ) Wet Scrubbers;

( 3 ) Electrostatic P recipitators (ESP) ; and

( 4 ) Fabric Filter Dust Collectors (Baghouses)

. The choice of which technology is most appropriate for a specific application depends upon several factors, 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 collec tion 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 (PM 10 emissions are estimated to be 0.22 tons/yr.) that operates i ntermittently 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/ds cf PM/PM 10 / / PM 2.5 concentration in the exhaust. This emissions level is so low t hat 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 abo ve 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 the re is no viable technology for controlling the PM/PM 10 /PM 2.5 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/PM 10 /PM 2.5 from the proposed Air Separation Unit (ASU) at the Indiana Gasification Plant.

For each ASU, BACT for PM/PM 10 is proposed to be 0.026 pounds per hour based on a daily average and for PM 2.5 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/PM 10 /PM 2.5 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 PM 10 emissions from each Air Separation Unit (ASU) shall not exceed 0.026 pounds per hour based on a daily average.

(b) The PM 2.5 emissions from the Air Separation Unit (ASU) shall not exceed 0.0 009 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 exhau sted to the atmosphere.

(1) Cyclones ;

(2) Wet Scrubber;

(3) Electrostatic P recipitators (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 n ot 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 technolog y 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 (H 2 O 2 ) scrubber

Step 2: Eliminate Technically Infeasible Options

(a) Add

- on Contr ol 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, th e conventional add

- on control technology was eliminated from consideration due to technical infeasibility.

(b) Mist eliminators and Hydrogen peroxide (H 2 O 2 ) scrubber The final step in the WSA process involves absorbing and recovering the produced sulfur ic acid. A small amount of s ulfuric a cid mist can carry out with the tail gas. This sulfuric acid mist (H 2 SO 4 ) is also considered PM/PM 10 / PM 2.5 for BACT review purposes. To control these emissions, a high efficiency mist elimination filter is installed do wnstream 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 upstr eam of the mist eliminator is installed primarily to control SO 2 , it is also estimated to remove 10% of the acid mist prior to the high efficiency mist eliminator filter. The peroxide scrubber use sIndiana Gasification LLC Page 115 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun a 50% hydrogen peroxide (H 2 O 2 ) solution which flows count er 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 ( H 2 O 2 ) scrubbers to control H 2 SO 4 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 un its “ 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 H 2 SO 4 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, PM 10 and PM 2.5 r esulting from operation of the WSA (EU

- 0 15 A/B)

. (1) H igh efficiency mist eliminators and hydrogen peroxide ( H 2 O 2 ) scrubbers

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed H 2 SO 4 BACT determination along with the existing H 2 SO 4 BACT determinations for similar plants. For this source, the emissions of PM, PM 10 and PM 2.5 equal those of H 2 SO 4 . All data in the tabl e 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

- 000 60 Proposed Limit Indiana Gasification

- **proposed** P roposed Wet Sulfuric Acid Plants (EU

- 0 15 A/B) 10,400 T dry coal/day 0.15 lb/ton and 5 lbs/hour based on 3

- hr average High Effi. Mist Eliminator, H 2 O 2 scrubber PSD

- LA

- 742(M1) Lake Charles Cogeneration, LLC 12 / 30 /20 10 Wet Sulfuric Acid Plants (2) * 9,413 T/D 0.15 lb/ton acid produced High Effi. Mist Eliminator, H 2 O 2 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, H 2 O 2 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. How ever, 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 tho se 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 H 2 SO 4 . Based on discussions with the ir WSA vendor, IG reports that there is not a ny confidence that the low er level of 0.06 lb/ton can be achieved. Also, th e 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 rat e for this source is proposed to be 0.15 lb/ ton using H 2 O 2 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 wh ich 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 o f 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

– becaus e 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, PM 10 and PM 2.5 for Wet Sulfuric Acid Plants (EU

- 015A/B).

The PM, PM 10 and PM 2.5 emissions from the Wet Sulfuric Acid Plants (EU

- 015A/B) shall be controlled by a high Efficiency Mist Eliminator and H 2 O 2 scrubber and the PM, PM 10 and PM 2.5 emissions shall n ot exceed 0.15 pounds per ton and 5 lb/hour , each, based on a 3

- hr average

.
Sulfuric Acid (H 2 S O 4 ) BACT

– Wet Sulfuric Acid Plants (EU

- 015 A and B)

Step 1: Identify Potential Control Technologies

Emissions of Sulfuric Acid (H 2 S0 4 ) are particulates. Partic ulates 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 P recipitators (ESP);

(4) Fabric Filter Dust Colle ctors (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., tem perature, 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 c ontrol 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 H 2 SO 4 sources from the proposed WSAs, the following alternate control methods were evaluated:

( 1) Mist eliminators and Hydrogen peroxide (H 2 O 2 ) scrubber s;
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 conden sable, 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 (H 2 O 2 ) scrubber The fina l step in the WSA process involves absorbing and recovering the produced sulfuric acid. A small amount of s ulfuric a cid 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 m ist eliminator is installed primarily to control SO 2 , it is also estimated to remove 10% of the acid mist prior to the high efficiency mist eliminator filter. The peroxide scrubber use s a 50% hydrogen peroxide (H 2 O 2 ) solution which flows counter current t o the flow of the gas stream from the WSA process.

The source is proposing to install high efficiency mist eliminators and hydrogen peroxide ( H 2 O 2 ) scrubbers to control H 2 SO 4 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 c onversion 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 S ubpart H sulfuric acid mist limit of 0.15 lbs H 2 SO 4 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 r esulting from operation of th e WSA (EU

- 0 15 A/B)

. (1) H igh efficiency mist eliminators and hydrogen peroxide ( H 2 O 2 ) scrubbers

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed H 2 SO 4 BACT determination along with the existing H 2 SO 4 BACT determinations for similar p lants. 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 perm its available at the websites of other permitting agencies.

BACT ID or Permit # Facility Issued Date Process Description Rating (TPH) Limitation Control MethodIndiana 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

- 000 60 Proposed Limit Indiana Gasification

- **proposed** P roposed Wet Su lfuric Acid Plants (EU

- 0 15 A/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, H 2 O 2 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, H 2 O 2 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 tw o conflicting limits on different pages) High Effi. Mist Eliminator, H 2 O 2 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 techn ologies. 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 th e 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 H 2 SO 4 . IG has indicated that b ased on discussions with the ir WSA vendor, t here is not a ny 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 precede nt. Therefore, based on vendor input specific to IG, the lowest achievable rate for this source is proposed to be 0.15 lb/T H 2 SO 4 emissions rate using H 2 O 2 scrubbers and high efficiency mist eliminators. This equates to emissions of 5.0 lbs/hr of H 2 SO 4 fo r 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 l b/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

- sulf ur 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 Signif icant Deterioration (PSD), IDEM has established the following as BACT for H 2 SO 4 for Wet Sulfuric Acid Plants (EU

- 015A/B).

The H 2 SO 4 emissions from the Wet Sulfuric Acid Plants (EU

- 015A/B) shall be controlled by a high Efficiency Mist Eliminator and H 2 O 2 s crubber and the H 2 SO 4 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

Emission s of carbon monoxide (CO) are gene rally 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 tec hnology 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 g as p lants sour ce s do not use any control devic e 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, was te 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 t he reactor temperature. The shorter the residence time, the higher the reactor temperature must be. Most thermal units are designed to provide no more than 1 second of residence time to the waste gas with typical temperatures of 1,200 to 2,000 o F. Once the unit is designed and built, the residence time is not easily changed, so that the required reaction temperature becomes a function of the particular gaseous species and the desired level of control.

A Regenerative Thermal Oxidizer incorporates heat recov ery 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 cerami c 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 f uel 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 th is source.
Catalytic OxidizersIndiana 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 tech nology 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 wi thout undergoing change itself. Catalytic oxidizers operate at 650°F to 1000°F and approximately require 1.5 to 2.0 ft 3 of catalyst per 1000 standard ft 3 per gas flow rate.

Emissions from emission units may contain significant amount of particulates. T hese 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 th is 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 f lare for this stream would be the creation of additional emissions from burning supplemental fuel, including NO x . Flares have not been utilized or demonstrated as a control device for CO from this type of high

- volume process stream. In addition, the flar e 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 s ource
Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1 ) Re generative Thermal Oxidizer

- 99 % destruction efficiency

( 2 ) Oxidation Catalyst

- 75 % destruction efficiency

Step 4: Evaluate the Most Effective Controls and Docum ent the Results

The following table lists the proposed CO BACT determination along with the existing CO BACT determinations for similar p lants. All data in the table is based on the information obtained from the permit application submitted by Indiana Gas ification, 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 Metho d
Draft Permit No. 147

- 30464

- 000 60 Proposed Limit Indiana Gasification

- **proposed** P roposed Wet Sulfuric Acid Plants (EU

- 0 15 A/B) 10,400 T dry coal/day 18.7 2 pounds per hour based on 3

- hour average , each None

PSD

- LA

742(M1) Lake Charles Cogeneration, LL C 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 po llutionIndiana 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 Metho d
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 Con trol Operating Cost T otal Annualized Costs Cost Effectiveness Other Impacts Tons/yr tons/yr $ $/yr $/yr $/Ton CO

RTO 0.8 79.2 $4

, 270 ,000 $ 488,0 00 $976

, 0 00 $12

, 3 00 Additional energy use & CO Emissions

Baseline 80.0 (proposed)

Note: Source exhaust (cfm) = 122 000 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)

I t 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 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 ther mal 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 h ave 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 conservativel y est imated to be at least $12,3 00/ton. This is prohibitively ex pensive 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 NO x ) which will at least partially offset any benefit of additional CO control.

Step 5: Sel ect 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

.Indiana Gasification LLC Page 122 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
Sulfur Dioxide (SO 2 ) BACT

- Wet Sulfuric Acid Plants (EU

- 015 A and B)

Step 1: Identify Potential Control Technologies

Sulfur dioxide (SO 2 ) can be controlled by the use of a scr ubber. In many applications, the scrubber is either a FGD or a dry scrubber. In those applications, the SO 2 is reacted with lime, or limestone or caustic and converted to a sulfate or sulfit e mixture which is managed as a sludge. In this application a pe roxide based scrubber is proposed. With a hydrogen peroxide scrubber, the SO 2 is converted to H 2 SO 4 and the waste stream is eliminated. A more conventional scrubber does not provide any improved efficiency and is therefore not reviewed in the subsequent s teps.

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 SO 2 , 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 CO 2 in the unit are vented out the WSA stack and will contain a very s mall amount of SO 2 . The proposed control for SO 2 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 (H 2 O 2 ). SO 2 is absorbed and converted to acid throu gh a chemical reaction that takes place as follows:

SO 2 + H 2 O 2 = H 2 SO 4 The technology provider guarantees that 95% of the SO 2 in the gas stream will be removed in the peroxide scrubber. The SO 2 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 R emaining 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 SO 2 BACT determination along with the existin g SO 2 BACT determinations for similar p lants. 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 permi ts 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

- 000 60 Proposed Limit Indiana Gasification

- **proposed** P roposed Wet Sul furic Acid Plants (EU

- 0 15 A/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

- LA

742(M1) Lake Charles Cogeneration , LLC 12/30/2010 Wet Sulfuric Acid Plants (2) * 9,413 T/D 0.5 lb/ton acid pr oduced Hydrogen peroxide scrubbingIndiana Gasification LLC Page 123 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 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 Oxid at ion Catalyst and Hydrogen peroxide scrubbing NOTE: * These emission units have not been built yet.

T he Lake Charles Gasification Plant , was identified as having a non

- elemental sulfur burning wet sulfuric acid plant. The RBLC shows the Lake Charles WSA SO 2 limit of 0.5 lb SO 2 /Ton acid produced. This limit, for comparison, is well below the NSPS Subpart H limit of 4 lbs SO 2 /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 SO 2 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 SO 2 emissions ranging from a low of 0.5 lb/ton SO 2 (Lake Charles) to a high of 3.0 lb/ton. SO 2 emissions from all facilities are controlled by scrubbing the tailgas with hydrogen peroxide.

Based on the RBLC review, a limit of 0.5 lbs SO 2 / ton acid produced is judged to be B ACT. However, IG proposes to go beyond BACT to achieve SO 2 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 l ower 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

- 015 A/B).

The SO 2 emissions from the Wet Sulfuric Acid Plants (EU

- 015A/B) shall be controlled by a peroxide scrubber, the SO 2 emissions shall not exceed 0.25 lb/ton acid produced and 8.3 lbs SO 2 /hr based on a 24

- hour block daily average for each Wet Sulfuric Acid unit

.
Nitrogen Oxide (NO X ) 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 OptionsIndiana Gasification LLC Page 124 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun Selective Catalytic Reduc tion (SCR) Selective Catalytic Reduction (SCR) process involves the mixing of anhydrous or aqueous ammonia vapor with flue gas and passing the mixture through a catalytic reactor to reduce NO X to water and N 2 . Under optima l conditions, SCR has a removal e fficiency 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 catal yst and the flue gas composition. In this particular service, the minimum target temperature is approximately 750 F

. Tem peratures 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 (S CR ) is a technically feasible option for the Wet Sul furic Acid Plants at this source.

Selective Non

- Catalytic Reduction (SNCR) With selective non

- catalytic reduction (SNCR), NO X is selectiv ely removed by the injection of ammonia or urea into the flue gas at an appropriate temperature window of 1600 ° F to 20 00 ° F and without employing a catalyst. Similar to SCR without a catalyst bed, the injected chemicals selectively reduce the NO X to molecular nitrogen and water. This approach avoids the problem related to catalyst fouling but the temperature window and rea gent mixing residence time is critical for conducting the necessary chemical reaction. At the proper temperature, urea decomposes to produce ammonia which is responsible for NO X reduction. At a higher temperature, the rate of a competing reaction for th e direct oxidation of ammonia that actually forms NO x becomes significant

. At a lower temperature, the rates of NO X reduction reactions become too slo w resulting in urea slip (i.e. emissions of unreacted urea).

Optimal implementation of SNCR requires the employment of an injection system that can accomplish thorough reagent/gas mixing within the temperature window while accommodating spatial and production rate temperature variability in the gas stream. The attainment of maximum NO x control performance therefore requires that the source 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. Depen ding on which of this NOx reduction technique is used, LNBs with staged combustion are subdivided into staged air burners and staged fuel burners.Indiana Gasification LLC Page 125 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun Experience suggests that significant reduction in NOx emissions can be realized using LNBs. The U.S. EPA rep orts 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 S ulfuric Acid Plants at this

source

Flue Gas Recirculation (FGR) R ecirculating 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 lo wer NOx emissions on two ways; t he cooled, relatively inert, recirculated flue gases act as heat sink, absorbing heat from the flame and lowering peak flame temperatures and when mixed with t he 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 th e 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 r esulting from operation of the Wet Sulfuric Acid Plants . T he source has cho sen SCR as their control for NOx emissions and no further analysis will be performed on the remaining less effective control device s.
(1) Selective Catalytic Red uction

— (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 a nd Document the Results

The following table lists the proposed NOx BACT determination along with the existing NOx BACT determinations for similar p lants. All data in the table is based on the information obtained from the permit application submitted by I ndiana 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 Con trol Method Draft Permit No. 147

- 30464

- 000 60 Proposed Limit Indiana Gasification

- **proposed** P roposed Wet Sulfuric Acid Plants (EU

- 0 15 A/B) 10,400 T dry coal/day 10.2 lb/hr NO x based

on 24

- hr block daily

average , Selective Catalytic ReductionIndiana Gasification LLC Page 126 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 Con trol 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 Pl ants * 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.

NO x 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 NO x emissions with a per mitted NO x 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 NO x emissions from the WSA at an emissions rate of 10.2 lb/hr from each WSA. Both IG and Lake Charle s 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 thi s source to be 10.2 lb/hr NOx (24

- hr block daily average) from each WSA using SCR control techn ology 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

s tringent 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 Charle s 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 emi ssions 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 NO x based on a 24

- h ou r block daily average for each Wet Sulfuric Acid unit

.
Particulate Matter (PM/PM 10 /PM 2.5 ) BACT

– ASU and Main Cooling Tower (EU

- 016A and 016B)

Step 1: Identify Potential Control Technologies

Emissions of Particulate matter ( PM, PM 10 and PM 2.5 ) 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

.Indiana Gasification LLC Page 127 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun Drift Elimination System Cooling towers are a source of particulate matter ( PM/ PM 10 /P M 2.5 ) emissions from the small amount of water mist that is entrained with the cooling air as “drift”. The cooling water con tains small amounts of dissolved solids which become particulate ( PM/ PM 10 /P M 2.5 ) emissions once the water mist evaporates. To reduce the drift from cooling towers, drift eliminators are typically incorporated into the tower design to remove as many droplet s 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 eliminat ors 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 condens ed 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 T ower a nd 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 ef ficiency 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 Docume nt the Results

The following table lists the proposed PM, PM 10 and PM 2.5 BACT determination along with o the r PM, PM 10 and PM 2.5 BACT determinations for cooling tower s . All data in the table is based on the information obtained from the U.S. EPA database o f 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/PM 10 /PM 2.5 BACT Limits

– Cooling Tower Company Name / Operation RBL C ID Date of Permit Control Technology & Compliance Methods and BACT Limit Indiana Gasification

- **proposed**

– Draft Permit No. 147

- 30464

- 000 60 Proposed Limit N/A N/A High efficiency drift eliminators designed to 0.0005% maximum drift

Gainesville Renewa ble 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 /20 10 0.0005 % Drift

USEPA’s RACT/BACT/LAER Clearinghouse shows BACT determinations specifying the use of drift/mi st eliminators for controlling PM, PM 10 and PM 2.5 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 theIndiana Gasification LLC Page 128 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun 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 tha t 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 b een proposed as BACT by for PM, PM 10 and PM 2.5 emissions from the ASU Cooling Tower EU

- 01 6A and Main Cooling T ower EU

- 01 6B operations :
Therefore, a 0.0005% drift/mist eliminator system along with a maximum TDS of 1500 ppm based on a daily average is propo sed as BACT for PM, PM 10 and PM 2.5 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, PM 10 and PM 2.5 BACT for the AS U Cooling Tower EU

- 01 6A and Main Cooling T ower EU

- 01 6B

.

The PM, PM 10 and PM 2.5 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 dissolve d solids shall not exceed 1500 ppm based on a daily average.

Sulfuric Acid (H 2 S0 4 ) BACT

– Sulfuric Acid Tanks (EU

- 027A

- F)

Step 1: Identify Potential Control Technologies

Emissions of Sulfuric Acid (H 2 S0 4 ) are generall y 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 P recipitators (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 metho ds 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 eva luated:Indiana Gasification LLC Page 129 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (1) F ixed 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 f abric 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 mi st emissions (<0.001 ton/yr , for each tank ). The tanks vent will be fitted with a pressure/vacu um 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 chan ge the emissions of H 2 SO 4 from the tanks.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The above control technologies have been identified for control of H 2 SO 4 r esulting from operation of the Sulfuric Acid tanks (EU

- 027A

- F)

. (1) F ixed 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 sto rage 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 max imum ambient condition s, so any vapor releases will be very small (estimated emissions from all sulfuric acid tanks are 0.0 0 11 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 H 2 SO 4 from the proposed Sulfuric Acid tanks at the Indiana Gasification Plant.

BACT for H 2 SO 4 is proposed to be a fi xed 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 H 2 SO 4 for the Sulfuric Acid tanks

.

The H 2 SO 4 emissions from the Sulfuric Acid t anks shall be limited by the use of a fixed roof tank and submerged fill.Indiana Gasification LLC Page 130 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
Particulate Matter (PM/PM 10 /PM 2.5 ) BACT

– ZLD Spray Dryer (EU

- 032 )

Step 1: Identify Potential Control Technologies

Emissions of PM

, PM 10 and PM 2.5 are generally controlled with add

- o n 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. Gene rally, PM, PM 10 and PM 2.5 emissions are controlled through one of the following mechanisms:

(1) Cyclones ;

(2) Wet Scrubber;

(3) Electrostatic P recipitators (ESP); and

(4) Fabric Filter Dust Collectors (Baghouses).

The choice of which technology is most appropriate for a specific application depends upon several factors, 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),

a nd 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 use d 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 part icles 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

amou nt 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 p articulates with the following characteristics: (1) Sticky and/or hygroscopic materials (materials that readily absorb water);Indiana Gasification LLC Page 131 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun (2) Combustible, corrosive and explosive materials;

(3) Particles that are difficult to remove in their dry form;

(4) Particulate s 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 opti on for the collectio n of material from the spray dry er 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 th e 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 w alls 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 knock ing 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 rang e from 99% to 99.9%.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that the use of a n Electrostatic Precipitator is a technically feasible option for the col lection of PM from the spray dry er 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 re latively 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 rangi ng from submicron to several hundred microns in diameter at efficie ncies 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 an d 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 proper ties. The most important design parameter is the air

- or gas

- to

- cloth ratio (the amount of gas in ft 3 /min that penetrates one ft 2 of fabric) and the usual operating parameter of interest is pressure drop across the filter system.

The major operating feat ure 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

a utomotive 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 revie wed for this BACT determination, IDEM, OAQ has determined that the use of a fabric filter is a technically feasible option for the c ontrol of PM from the spray dry er associated with the Zero Liquid Discharge (ZLD) at this source

. Step 3: Rank the Remai ning Control Technologies by Control Effectiveness

The above control technologies have been identified for control of PM, PM 10 and PM 2.5 r esulting from operation of the Spray dry er associated with the Zero Liquid Discharge (ZLD) Spray Dryer

. ( 1 ) Fabric Filtration (99%

- 99.9% PM/PM 10 /PM 2.5 Reduction)

(2) Electrostatic Precip itator (99%

- 99.9% PM/PM 10 /PM 2 .5 Reduction)

(3) Wet Scrubber (99% PM/PM 10 /PM 2.5 Reduction)

(4 ) Cyclones (80% PM/PM 10 /PM 2.5 Reduction)

Both the Electrostatic Precipitator an d 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 fol lowing table lists the proposed PM, PM 10 and PM 2.5 BACT determination along with other PM, PM 10 and PM 2.5 BACT determinations for similar but larger spray dry ers . All data in the table is based on the information obtained from the U.S. EPA database of pro posed 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 Contro l 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 specifiedIndiana 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 Contro l Method Estimated Control Efficiency 00060 Proposed Limit OK

- 0118 Western Farmers Electric Coop Hugo Generating Station 2/9/2007 Wastewater (brine) spray dryer 20 MMB tu /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 MMB tu /hr PM10: 0.018 gr/dscf Baghouse Not specified

AZ

- 0046 Arizona Clean Fuels Yuma 4/14/2005 Spray Dryer Heater 44 MMB tu /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 MMB tu /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 uni t is 20 times larger (in fi ring rate) than the IG spray dry er. 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 b y for PM, PM 10 and PM 2.5 emissions from the Zero Liquid Discharge (ZLD) operations :

(1) A fabric filter baghouse. (2) The PM, PM 10 and PM 2.5 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, PM 10 and PM 2.5 BACT for the Zero Liquid Discharge (ZLD) Spray Dryer :

The PM, PM 10 and PM 2.5 emissions from the Zero Liquid Discharge (ZLD) spray dry er shall be controlled by a fabric filter baghouse and the PM, PM 10 and PM 2.5 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) Flare s

(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 em issions. 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 spe nds 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 typ ical temperatures of 1,200 to 2,000 o F. Once the unit is designed and built, the residence time is not easily changed, so that the required reaction temperature becomes a function of the particular gaseous species and the desired level of control. Regenera tive 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 f eeding 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 ft 3 of catalyst per 1000 standard ft 3 per gas flow rate.

Emissions from emission units may contain significant amount of par ticulates. 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 dry er 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 NO x . 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 combu stion 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 ) Re generative Thermal Oxidizer

- 9 9 % 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 dry ers . 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 LL C 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 Pig ment 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 Con trol Operating Cost Total Annualized Costs Cost Effectiveness Other Impacts Tons/yr tons/yr $ $/yr $/yr $/To n CO

RTO 0.0089 0.8811 $2 33

, 8 00 $16

, 7 00 $5 5

, 11 0 $6 2

, 5 00 Additional energy use & CO Emissions

Baseline 0.9 (proposed)

Note: Source exhaust (cfm) = 167 0Indiana 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 a dd

- 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 obt ained 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 ox idizer 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 rat e 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 ther mal 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 combust ion 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 Dry er ;

(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 f or Zero Liquid Discharge (ZLD) Spray Dry er

. The CO emissions from the Zero Liquid Discharge (ZLD) Spray Dryer shall not excee d 0.036 lb/MMBtu and shall use good combustion practices.

Sulfur Dioxide (SO 2 ) BACT

- ZLD Spray Dryer (EU

- 032)

Step 1: Identify Po tential Control Technologies

Emissions of Sulfur dioxide (SO 2 ) from gas fired spray dryers such as the Zero Liquid Discharge (ZLD) Spray Dryer proposed here are generally not controlled. Much larger sources of SO 2 are generally controlled by;

1. Flue Ga s 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 SO 2 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 technica l feasibility of any control option is whether it is both available and applicable to reducing SO 2 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 SO 2 in the exhaust gas is the driving force fo r the reaction between SO 2 and the reagent.

Therefore, removal efficiencies are significantly reduced with lower inlet concentrations of SO 2 . FGD systems are listed in the RBLC as BACT for sources high in SO 2 emissions. Even though the SO 2 concentrati ons 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.

SO 2 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 SO 2

. 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 SO 2 . In the very best cases, wet scrubbing systems can achieve up to as high as 98% control and reduce SO 2 to single digit ppm levels. Howeve r, this vent is already less than 2 ppm SO 2 (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 opt ion 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 the re is no viable tec hnology 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 SO 2 from Spray Dryers were located in the RBLC data base

. Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that the re is no viable technology for controlling the SO 2 emissions resulting from the Zero Liquid Discharge (ZLD) spray dryer.

Proposal: Indiana Gasification, LLC,

- Rockport, IN

The following has been proposed as BACT for SO 2 from the proposed Zero Liquid Discharge (ZLD) Spray Dryer ;
(1) The use of a c lean burning gaseous fuel.

Step 5: Select BACT

Pursuant to 326 IAC 2

- 2

- 3 (Prevention of Significant Deterioratio n (PSD), IDEM has established the following as BACT for SO2 for Zero Liquid Discharge (ZLD) Spray Dryer

.
The SO 2 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 (N O X ) 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 NO X to water and N 2 . Under optima l conditions, SCR has removal efficiency up to 90% when used on steady state processes. The efficiency of removal will be reduced for processes that are not stable or require frequent changes in the mode of operation.

The most important 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 NH 3 to slip through; above the optimum range, ammonia will oxidize to form additional NO x . SCR efficiency is also largely dependent on the stoichiometric molar ratio of NH 3 :NO x ; 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 tha n 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 N Ox from this size bur ner 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 (S CR ) is not a t echnically feasible option for the Zero Liquid Discharge (ZLD) Spray Dryer at this source.

Selective Non

- Catalytic Reduction (SNCR) With selective non

- catalytic reduction (SNCR), NO X is selectiv ely removed by the injection of ammonia or urea into the flue gas at an appropriate temperature window of 1600 ° F to 2000 ° F and without employing a catalyst. Similar to SCR without a catalyst bed, the injected chemicals selectively reduce the NO X to molecular nitrogen and water. This approach avoids the problem relat ed 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 NO X reduction. At a hig her temperature, the rate of a competing reaction for the direct oxidation of ammonia that actually forms NO x becomes significant

. At a lower temperature, the rates of NO X reduction reactions become too slo w resulting in urea slip (i.e. emissions of unreac ted 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 st ream. The attainment of maximum NO x 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 revie wed 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 formatio n 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 reduc tion 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 a ctual 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) R ecirculating 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 emiss ions 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 Zer o 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 r esulting from operation of the Zero Liquid Discharge (ZL D)

. Based on the technical feasibility analysis in Step 2, the source has cho sen Low NOx Burner (LNB) as their control for NOx emissions and no further analysis will be performed on the remaining control device s.
(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 simil ar but spray dry ers . 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 Drye r 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 MM BTU/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

.

Th e 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).Indiana Gasification LLC Page 142 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
Sulfur Dioxide (SO 2 ) BACT

- Fugitive Leaks from piping (FUG & FUG

- WSA)

Step 1: Identify Potential Control Technologies

T he SO2 emissions from fugitive leaks can be controlled by;

(a) L eak detection and Repair (LDAR)

Step 2: Eliminate Technically Infeasible Options

There are small amount s of SO 2 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 SO 2 service. Th e select ed LDAR program is primarily for the purpose of controlling organic HAPs and VOC. Additionally, SO 2 is being controlled in the section of WSA piping between the combustor and oxidation.

Step 3: Rank the Remaining Control Technologies by Control E ffectiveness

(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 SO 2 from the Fugitive Leaks from Equ ipment (FUG and FUG

- WSA).

The BACT for fugitive leaks of SO 2 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 establish ed the following as BACT for SO2 for the Fugitives Leaks from piping (FUG and FUG

- W S A )

.

The BACT for the fugitive leaks of SO 2 in the WSA is the use of a Leak Detection and Repair (LDAR) program.

CO and H 2 SO 4 BACT

- Fugitive Leaks from piping (FUG & F UG

- WSA)

Step 1: Identify Potential Control Technologies

The emissions such as CO and H 2 SO 4 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 sm all amount of emissions of CO and H 2 SO 4 from fugitive leaks from equipment and pipe components such as pumps, valves, flanges and compressors. The source plans toIndiana Gasification LLC Page 143 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 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). Th e select ed LDAR program is primarily for the purpose of con trolling organic HAPs and VOC. The use of an LDAR program to control CO or H 2 SO 4 would be extremely unusual and wou ld require use of different instrumentation than a conventional organic LDAR program. Consequently, IG has not propose d 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 H 2 SO 4 and the very small amount of their emissions from the facility.



### Table 1

Concentrations of Pollutants in each Process Stream BACT Pollutants Other Pollutants Proc ess Streams CO H2SO4 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 methano l and propylene streams. The acid gas streams are included in Fugitive Equipment Leaks from t he 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 H 2 SO 4 )

Step 4: Evaluate the Most Effective Controls and Document the Results

Given the low concentration of CO and H 2 SO 4 in the process streams, the relatively low fugitive emissions rate of these pollutants

, and the fact that use of an LDAR pr ogram 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 b een proposed as BACT for CO and H 2 S0 4 from the Fugitive Leaks from Equi pment (FUG and FUG

- WSA).

(1) The BACT for fugitive leaks of CO and H 2 SO 4 is proposed as no

- controls.Indiana Gasification LLC Page 144 of 181 Rockport, Indiana PSD /TV Permit No: 147

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Pursuant to 326 IAC 2

- 2

- 3 (Prevention of Significant Deterioration (PSD), IDEM has established the following as BACT for CO and H 2 S0 4 for the Fugitives Lea ks from piping (FUG and FUG

- W S A )

. (1) The BACT for fugitive leaks of CO and H 2 SO 4 is no

- controls.

Particulate Matter (PM/PM 10 /PM 2.5 ) BACT

– Fugitive Dust From Paved Roads ( FUG

- ROAD )

Step 1: Identify Potential Control Technologi es

Emissions of particulate matter (PM), particulate matter with an aerodynamic diameter less than or equal to ten (10) micrometers (PM 10 ) and PM 2.5 from fugitive sources are generally controlled with measures to prevent the emissions from occuring. Genera lly, fugitive PM, PM 10 and PM 2.5 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 f actors 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 whi ch 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 deter mination, 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 i s feasible.Indiana Gasification LLC Page 145 of 181 Rockport, Indiana PSD /TV Permit No: 147

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2. Wet or chemical suppression (f requent use of water or chemical surfactants ) can signific antly 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, PM 10 and PM 2.5 BACT determination along with t he existing PM, PM 10 and PM 2.5 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

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- 00060 Proposed Limit Indiana Gasificatio n - **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 pract icable. 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 mate rial, 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 hi ghest 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 naturall y travel at low speeds in the IG plant.Indiana Gasification LLC Page 146 of 181 Rockport, Indiana PSD /TV Permit No: 147

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Proposal : Indiana Gasification, LLC The following has been proposed as BACT for PM, PM 10 and PM 2.5 from the proposed Plant Haul Road at the Indiana Gasification Plant.

BACT for PM, PM 10 and PM 2.5 for the Fugitiv e 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 o f Significant Deterioration (PSD), IDEM has established the following as BACT for PM, PM 10 and PM 2.5 for the Fugitive Dust from Plant Haul Roads (FUG

- ROAD).

The PM, PM 10 and PM 2.5 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/PM 10 /PM 2.5 ) BACT

– Front

- End Loader Slag Handling (EU

- 034A) and Vehicle Dust on Slag Pile (EU

- 034C)

St

ep 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 (PM 10 ) and PM2.5 are generally controlled with control s 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 PM 10 emissions are controlled throug h one of the following mechanisms:

(1) Wet Suppression or Chemical suppression ;
(2) Filtration;

(a) Baghouse; (b) Wet E xtraction System ;
(3) Other Add

- on Controls (cyclone, ESP).

Step 2: Eliminate Technically Infeasible Options

The slag pile operatio ns 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 control s for this material handling that is technically feasible for these sources is wet or chemical suppression. Frequent use of water or chemical surfactants can significantlyIndiana Gasification LLC Page 147 of 181 Rockport, Indiana PSD /TV Permit No: 147

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reduce airborne dust from these types of open material handling operations. This i s 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 e missions 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 t he liquid and the ability of the liquid to wet small particles. There are two types of w et 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 suppre ssion 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 Ve hi c le Dust on Slag Pile (EU

- 0 34C ) at this

source.
Step 3: Rank the Remaining Control Technologies by Control Effectiveness

(1 ) Wet Suppression or Chemical suppression ( up to 90 % PM, PM 10 and PM 2.5 Reduction)

Step 4: Evaluate the Most Effective Controls and Document the Results

The following table lists the proposed PM, PM 10 and PM 2.5 BACT determination along with the existing PM, PM 10 and PM 2.5 BACT determinations for relevant operations . All da ta 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 agen cies.

BACT ID or Permit # Facility Issued Date Process Description Rating (TPH) Limitation Control Method Draft Permit No. 147

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- 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 Solut ions 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, enclo sures whereIndiana Gasification LLC Page 148 of 181 Rockport, Indiana PSD /TV Permit No: 147

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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 e mission 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 acti vities 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%. Depen dent 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 , L LC

– Rockport, IN

The following has been proposed as BACT for PM, PM 10 and PM 2.5 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 effic iency

. 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, PM 10 and PM 2.5 for the Front

- end Loader Slag Handling (EU

034A) and Vehicle Dust on Slag Pile (EU

- 034C )

.
The PM, PM 10 and PM 2.5 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 CO 2 from the syngas and produce a stream which is 98% pure CO 2. This stream will be compressed to a liquid and sold. Whenever it is insteadIndiana Gasification LLC Page 149 of 181 Rockport, Indiana PSD /TV Permit No: 147

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vented, it wil l 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 CO 2 stream to be vented is very low because it co ntains mostly non

combustible CO 2 . 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 bo th 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 compo nents 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 a re technically feasible, they will reduce supplemental fuel use and, thereby, reduce the associated emissions of CO 2 . The use of the RTOs will increase the CO 2 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 CO 2 during the combustion process. Although the RTO slightly increases CO 2 emissions, its use is appropriate to reduce the emissions of other compounds as is further discus sed 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 N2 O , 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 pr oposing 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 CO 2 emissions has been identified.

(1) No Contr ol

Step 2: Eliminate Technically Infeasible Options

No technically feasible measures have been identified to control CO 2 emissions associated with the operation of the RTOs.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

T he re ar e no viable control technologies for the control of CO 2 emissions from the RTO

.

Step 4: Evaluate the Most Effective Controls and Document the Results

No technically feasible measures have been identified to control CO 2 emissions associated with the operat ion of the RTOs.Indiana Gasification LLC Page 150 of 181 Rockport, Indiana PSD /TV Permit No: 147

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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: Identi fy 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 me asures 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 V ent CO 2 .
Step 2: Eliminate Technically Infeasible Options

Sequestration of the AGR Vent CO 2
In any situation when the sale of liquefied CO 2 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 CO 2 as an add

- on pollution control technology is ‘available’ for “large CO 2 - emitting facilities including fossil fuel

- fired power plants and industrial facilities with high

- purity CO 2 s treams . . . .” 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 CO 2 from new and existing fossil energy power plants . . .”

IDEM do es 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 rem ainder 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 technol ogies 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 techniqu e 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 successfulIndiana Gasification LLC Page 151 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun 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 CO 2 that may be emitted from the AGR vent, though a small percentage of the CO 2 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 opera tion 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 pr oposed 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,” a nd “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 CO 2 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 t o 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 o f CO 2 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 CO 2 that may be vented from the AGR vents. As indicated abov e, there is an ongoing potential to emit 1,290,000 tons/yr of CO 2 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 regi on 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 CO 2 injection research projects targeting injection of over 1 million tons of CO 2 (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 in ject 1 million tons of CO 2Indiana Gasification LLC Page 152 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun 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 CO 2 from the FutureGen project, and potentially other projects, could be stored. Future Gen 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 CO 2 per year over 30 years (the amount expected to be captured by the FutureGen plant), but c ould be expanded at some point in the future to accept additional CO 2 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 m erely 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 clea r whether or by how much it will be sized to accept CO 2 beyond that produced by the FutureGen power plant, what criteria will be used to determine who can potentially use the site for CO 2 storage, or when the site might actually be completed and begin CO 2 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 I ndiana G asificati on ’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 CO 2 in 2009. Limited information is available regarding the result s of this research, but the small scale of the injection

— a total CO 2 injection that was less CO 2 than the I ndiana G asification 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 infrastruc ture that will accommodate the volume of CO 2 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 Laborator y (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 ne eded 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 de monstration of sequestration methods.Indiana Gasification LLC Page 153 of 181 Rockport, Indiana PSD /TV Permit No: 147

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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 CO 2 transportation infrastructure

— aside from the EOR p ipeline contemplated for use by this project

— that would have the capacity to transport the volume of CO 2 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 t ransportation 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 CO 2 is not sold f or 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 oppo rtunities, and then construct whatever pipelines would be needed to transport CO 2 for sequestration, all in light of the fact that there will not exist in the near future any suitable sites for the sequestration of CO 2 from the facility. Moreover, IDEM can not 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 sequ estration of the AGR vent is not a technically feasible option for the Acid Gas Recovery Unit Vent at this source.Indiana Gasification LLC Page 154 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the technical feasibility analysis in Step 2, the re are no viable control technologies for the control o f 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 faci lities were identified where controls were required for an Acid Gas Recovery (AGR) Vents

. The acid gas removal (AGR) units remove CO 2 from the syngas and produce a stream which is 98% pure CO 2. This stream will be compressed to a liquid and sold. It wi ll 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 CO 2 to the Gulf Coast EOR market from a coal

- based facility in the Midwest. There are, however, ce rtain challenges to producing and selling CO 2 product. In particular, a pipeline is needed to transport the CO 2 from the plant site to the Gulf Region. No such pipeline currently exists. The present implementation plan for the project would finance the p ipeline 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 CO 2 at the point when pipeline quality CO 2 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 CO 2 . Nevertheless, IG cannot be 100% certain that the pipel ine will be operating and ready to receive CO 2 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 throug h 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 onl y the IG facility. However, other parties are considering the production and sale of CO 2 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 CO 2 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 CO 2 may also cause a delay in shipping CO 2 , even if the pipeline is ready to receive CO 2 .

1. A customer committed to purchasing IG’s CO 2 may need to build and commission new CO 2 infras tructure which may create delays in the sale of CO 2 for the customer.
2. There may be delays as shipping schedules for the various customers are sorted out.

On those occasions when CO 2 is not sold as product, the CO 2 is vented from the AGRs. The CO 2 stre am will first be directed to a regenerative thermal oxidizer (RTO) to oxidize small amounts of methane, VOCs (methanol), H 2 S, 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 RTOsIndiana Gasification LLC Page 155 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun 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 CO 2 through the pipeline from this facility to the CO 2 customers, IG is anticipating that CO 2 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 CO 2 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 CO 2 emissions from the A G R /RTO vents for each of the first two years of operation, and a differ ent, 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 ( A G R /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 CO 2 .

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 i s 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: Selec t BACT

Pursuant to 326 IAC 2

- 2

- 3 (Prevention of Significant Deterioration (PSD), IDEM has established the following as BACT for the GHG for the Acid Gas Recovery ( AG R /RTO ) Vents

. (1) The CO 2 emissions from the Acid Gas Recovery (AGR) Vents shall not excee d 4 ,690 ,000 tons of CO 2 during the first 12 months of operation.

(2) The CO 2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed 6 ,430 ,000 tons of CO 2 during the second 12 months of operation.

(3) The CO 2 emissions from the Acid Gas Recover y (AGR) Vents shall not exceed 1, 290,000 tons of CO 2 during the third 12 months of operation.

(4) Thereafter, the CO 2 emissions from the Acid Gas Recovery (AGR) Vents shall not exceed 1,290,000 tons CO 2 per twelve (12) consecutive month per iod with compliance determined at the end of each month.Indiana Gasification LLC Page 156 of 181 Rockport, Indiana PSD /TV Permit No: 147

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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 me thane and N2 O

, 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 ga s back to the AGR (which would require pure oxygen use in the WSA combustor instead of air); and

(3) Carbon (CO 2 ) Capture in WSA Tailgas.

Step 2: Eliminate Technically Infeasible Options

No Control Most of the CO 2 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 CO 2 in the syngas for liquefaction and sale.

This perc ent capture results from the relative solubilities of CO 2 , COS and H 2 S 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) assu ring liquid CO 2 product quality; and 3) assuring acceptable acid gas quality to the WSA.

The high CO 2 capture in the AGR incidentally results in relatively modest levels of CO 2 in the acid gas stream to the WSA. WSA emissions of CO 2 are estimated to not exceed 474,000 tons
per year at maximum design rates. This is approximately 7% of the syngas CO 2 at maximum design. Below is a further brief discussion of how the AGR captures CO 2 , H 2 S and COS.

Cold methanol is used to physically absorb CO 2 , H 2 S and CO S 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 CO 2 , H 2 S and COS are significantly more solub le than other syngas components (CO, H 2 , CH 4 , and N 2 ). This solubility difference allows CO 2 , H 2 S and COS to be removed from the syngas in the AGR systems. However, their similar solubility makes it difficult to separate the H 2 S, COS, and CO 2 from each o ther.

H 2 S, COS, and CO 2 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, H 2 S and COS are more soluble than CO 2 . To achieve effective sepa ration, the loaded methanol solvent is depressurized in multiple stages

– at progressively lower pressures.Indiana Gasification LLC Page 157 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun After an initial pressure reduction to flash off any absorbed syngas product, CO 2 is next flashed out of the solvent (in three stages) generating w hat becomes the facility’s liquefied product CO 2 stream (98% pure). In a final step, the methanol solvent, having been stripped of more than 90% of its CO 2 , is then heated in a hot regenerator, to strip out the H 2 S and COS. The sulfur

- rich acid gas strea m from the regenerator, which is then sent to the WSA, will also contain some remaining CO 2 . It is very difficult to further reduce the CO 2 content of the acid gas stream because of the relatively close solubility of the acid gases and CO 2 .

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 CO 2 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 CO 2 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 H 2 S and COS necessary for the pr oduction 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 sa le 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 c hallenges. 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 d etermined that the use of pure oxygen and recycle is not a technically feasible option for the Wet Sulfuric Acid Plants at this source.

Carbon (CO 2 ) Capture in WSA Tailgas Another theoretical option is capturing the CO 2 in the WSA exhaust in a separate s olvent 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 CO 2 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 s imilarities between the WSA tailgas and a typical boiler exhaust.

(1) Low CO 2 concentration

– The WSA tail gas exhaust will contain about 6.6% CO 2 concentration. This is on the lower end of the range of the typical exhaust concentrations for natural gas boilers which range from 6

- 9% CO 2 . (2) Low Pressure

– The WSA tail gas is at atmospheric pressure as are boiler exhaust stacks.Indiana Gasification LLC Page 158 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun (3) Low quantity of CO 2 – The annual CO 2 emissions from each WSA unit are orders of magnitude smaller than are emitted from large fossil

- fuel fired power plants and concentrated industrial CO 2 sources for which carbon capture is being considered. For example, each WSA has the CO 2 equivalent emissions of a boiler of only about 360 MMBTU/hr.

The post

- combustion carbo n 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 CO 2 concentration, low exhaust pressure and limited CO 2 available for capture (i.e.: small size of the Aux boilers). For these same reasons, carbon capture of the CO 2 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 th at the use of carbon capture of CO 2 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 determinati on, 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 t he 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 Gasifi cation, LLC The following limit has been proposed for CO 2 from the proposed Wet Sulfuric Acid :

The WSA CO2 emissions shall be limited to 474,000 tons per year, as a rolling 12

- month t otal.

Step 5: Select BACT

Pursuant to 326 IAC 2

- 2

- 3 (Prevention of Sign ificant Deterioration (PSD), IDEM has established the following as BACT for the GHG for the Wet Sulfuric Acid Plant

.

The CO 2 emissions from the Wet Sulfuric Acid Plant operation shall not exceed 474,000 tons per year as a rolling 12

- month total.

Greenhou se 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 recover y, and blowdown heat recovery); and (3) Post

- combustion CO 2 capture.Indiana Gasification LLC Page 159 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun This analysis focuses on the emissions of CO 2 only. While other GHGs, such as methane and N 2 O , 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 CO 2 , the other GHGs will be reduced accordingly. Therefore, CO 2 serves as a useful surrogate for other GHGs in this regard.

Step 2: Elim inate Technically Infeasible Options

Low Carbon Fuel Carbon dioxide (CO 2 ) 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 CO 2 emissions versus use of solid or other fuels available at the IG site. The table below illustrates the CO 2 emission factors for combustion of a variety of fuels.

Typical CO 2 Emission Factors
Fuel Pounds CO 2 per Million Btu Petroleum Coke* 225 Coal** 2 10 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 CO 2 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 resu lt. (Note: A uxiliary boiler firing is also reduced through the high degree of heat

integration of the overall process which reduces supplementary steam requirements.)

S pecific energy efficiency measures that may be applied to boilers include the following:

**Inlet air controls** (such as O 2 monitor and inlet air flow control) limit excess air. Limiting the excess air enhances efficiency and reduces emissions through reducti on 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 wit h a NO x emissions limits and continuous emissions monitor required by NSPS Db, will help keep the boilers tuned for efficient operation (making periodic boiler tuning unnecessary).Indiana Gasification LLC Page 160 of 181 Rockport, Indiana PSD /TV Permit No: 147

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**Heat Recovery** of heat in the stack gas can be accomplished with either an e conomizer 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 decreasi ng 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 afte r 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
pre ssure 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, w hen at full design rate, of at least 81% (HHV basis).

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined t hat the use of energy efficiency is a technically feasible option for the Auxiliary Boilers at this source.

Post

- combustion CO 2 Capture

Post

- combustion CO 2 capture is a relatively new concept. In EPA’s recent GHG BACT guidance, EPA takes the position that, “ for the purpose of a BACT analysis for GHGs, EPA classifies CCS as an add

- on pollution control technology that is “available” for large CO 2 - emitting facilities including fossil fuel

- fired power plants and industrial facilities with high

- purity CO 2 streams”. However, the IG auxiliary boilers do not fit into either of these categories. The EPA guidance document pr ovides 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

an alysis 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 CO 2 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 o f the CO 2 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 CO 2 concentration, low pressure, low quantity of CO 2 available for capture, and the h igh variability of load for these two boilers

.Indiana Gasification LLC Page 161 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun

CO 2 Capture Difficulty Natural gas combustion boiler exhaust streams have relatively low CO 2 concentration s (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 CO 2 . Additionally, the low concentration and low pressur e complicate the absorption and desorption of the CO 2 , which increases the energy required. Also, a low pressure absorption system creates a low pressure CO 2 stream which requires a very high energy demand for compression prior to transport. All these fa ctors make the application of CO 2 capture on any natural gas combustion exhaust extremely difficult and expensive. Additionally, the cost of capturing CO 2 for smaller sources is more expensive due to the lack of economy

- of

- scale. The average annual firin g rate of the auxiliary boilers of 172 MMBTU/hr is less than 1/20 th the size of a typical fossil fuel fired power plant boilers that EPA contemplates having to consider the potential for CCS. Add itionally, 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 CO 2 capture is not a technically feasible option for the Auxiliary Boilers at this so urce.
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 R esults

In its review of the RACT/BACT/LAER Clearinghouse (RBLC) and similar permits, no facilities were identified where CO 2 controls were required on Auxiliary Boilers

. Proposal : Indiana Gasification, LLC The following has been proposed as BACT for GHG from the proposed A uxiliary 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 CO 2 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 follow ing as BACT for the GHG s for the A uxiliary Boilers

.

(1) Use of natural gas or SNG;Indiana Gasification LLC Page 162 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun (2) Energy efficient boiler design (utilizing an economizer, condensate recovery, inlet air controls and blowdown heat recovery.) ( 3) Boiler designed for 81% thermal eff iciency (HHV);

(4) The total CO 2 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 Fl are (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 an d 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 CO 2 only. While other GHGs, such as methane and N 2 O , 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 CO 2 , the other GHGs will be reduced accordingly. Therefore, CO 2 serves as a useful surrogate for other GHGs in this regard. Step 2: Eliminate Technically Infeasible Options

Flare design and proper operation Flare design a nd 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 open

flame 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 f lares 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 rat e 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 ha s 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 Minimiza tion 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, ID EM, 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.Indiana Gasification LLC Page 163 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun Flare gas recovery Flare gas recovery

– Flare gas recovery ha s 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 near ly 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 ps ig. 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 refi neries.

(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 otherwis e 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 c ompression 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 f rom the Syngas Hydrocarbon flare at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

The remaining technical ly 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 ca use” 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 Docu ment 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 per mittee shall comply with the following Flare Minimization Plan to reduce GHG emissions during startups, shutdowns, and other flaring events.Indiana Gasification LLC Page 164 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun During a planned shutdown of a gasifier, the permittee shall route the contents of each gasifier unit (gasifier ve ssel, 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 schedule d 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 t hese 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 event s. 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 Fl are (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 permitte e 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 abov e 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 tha t 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 flar e 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.Indiana Gasification LLC Page 165 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun This analysis focuses on the emissions of CO 2 only. While other GHGs, such as methane and N 2 O , 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 CO 2 , the other GHGs will be reduced accordingly. There fore, CO 2 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 Ga ses (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 open

flame nature of a flare results in inherently good Greenhouse Gases (GHG) performance (t he 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 desig n 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 feasi ble 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, emi ssions 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 fea sible 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 pet roleum 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 op erates at less than 100 psig. In contrast, the IG facility’s analogous gas cleanup system, the AGR, operates at the much higher pressu re 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 b e 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.Indiana Gasification LLC Page 166 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun (4) Given the extremely infrequent nature of flared gases being av ailable 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 Effectivene ss

The remaining technical ly 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 us ed 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 anal ysis 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 addi tional 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 Gasifica tion, 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 shal l 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 prevent ative measures that can be implemented to minimize re

- occurrence of these events. Such identified measures shall be implemented and documented.Indiana Gasification LLC Page 167 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun
Greenhouse Gases (GHG) BACT

– Gasifier Preheater Burners ( EU

- 008 A

- E )

Step 1: Identify Potential Control Techn ologies

The CO 2 is by far the dominant GHG from this source. CH 4 and N 2 O are present only in very small amounts, are incidental to combustion, and trend with the CO 2 emissions. There are no known supplemental controls for N 2 O or methane emissions from gas

- fired units. To the extent measures are identified that reduce CO 2 , the other GHGs may be also reduced accordingly. Therefore, this BACT analysis focused on CO 2 as a surrogate for all GHG emissions. 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

Na tural 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 impact s 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 wi ll 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 CO 2 capture is a relatively new concept. In EPA’s recent GHG BACT guidance, EPA takes the position that, “ for the purpose of a BACT analysis for GHGs, EPA classifies CCS as an add

- on pollution control technology tha t is “available” for large CO 2 - emitting facilities including fossil fuel

- fired power plants and industrial facilities with high

- purity CO 2 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.Indiana Gasification LLC Page 168 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun

The absence of a discussion of carbon capture in this 250 MMBtu/hr boiler example is consistent with the fact that carbon capture is extremely expensive, has numerous technical challenges, and is currently only being contemplated on very large or very concentrated CO 2 so urces. 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 th e categories that US EPA’s guidance document suggests should consider CCS.

A CO 2 capture system for the IG gasifier preheat burners is not a reasonable BACT option because the capture of the CO 2 from combustion exhaust of small sources is significantly more difficult than from the types of industrial gas streams that EPA references as having potential for CCS. The increased difficulty is due to four factors: low CO 2 concentration, low pressure, low quantity of CO 2 available for capture, and the variabil ity of load for these units.

The low concentration and low pressure of the exhausts from these processes complicate the absorption and desorption of the CO 2 , which increases the energy required. Also, a low pressure absorption system creates a low press ure CO 2 stream which requires a very high energy demand for compression prior to transport. All these factors make the application of CO 2 capture on any small combustion exhaust extremely difficult and expensive. Additionally, the cost of capturing CO 2 f or 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 f or this BACT determination, IDEM, OAQ has determined that the use of post

- combustion capture of CO 2 is not a technically feasible option for the Gasifier preheater burner s at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiv eness

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 Doc ument the Results

Proposal : Indiana Gasification, LLC The following has been proposed as BACT for GHG from the proposed Gasifier preheater burners :

( 1) T he 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 su bstitute 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 ar e removed from the gasifier. In addition,Indiana Gasification LLC Page 169 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun 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 ho urs to the time needed to achieve normal operation.

Emission Unit GHG Emissions (tons/yr) CO 2 CH 4 N 2 O CO 2 e 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 Signific ant 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. T he use of natural gas or SNG.

3. The total CO 2 emissions from all five Gasifier Preheater Burners shall not exceed 6,438 tons CO 2 per twelve (12) consecutive month period with compliance determined at the end of the month

.
Greenhouse Gases (GHG) BACT

– Emergency Generators and Fire water Pumps

Step 1: Identify Potential Control Technologies

The CO 2 is by far the dominant GHG from this source. CH 4 and N 2 O are present only in very small amounts, are incidental to combustion, and trend with the CO 2 emissions. There are no known supplemental controls for N 2 O or methane emissions from diesel engines

. To the extent measures are identified that reduce CO 2 , the other GHGs may be also reduced accordingly. Therefore, this BACT analysis focused on CO 2 as a surrogate for all GHG emissions.

Diesel fuel is used instead of SNG or NG because it is an independ ent 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 fu el 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 captureIndiana Gasification LLC Page 170 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun

Step 2: Eliminate Technicall y 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 engi nes
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 CO 2 capture is a relatively new concept. In EPA’s recent GHG BACT guidance, EPA ta kes the position that, “ for the purpose of a BACT analysis for GHGs, EPA classifies CCS as an add

- on pollution control technology that is “available” for large CO 2 - emitting facilities including fossil fuel

- fired power plants and industrial facilities with high

- purity CO 2 streams”. The 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 littl e 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 examp le is consistent with the fact that carbon capture is extremely expensive, has numerous technical challenges, and is currently only being contemplated on very large or very concentrated CO 2 sources. In stark contrast, these IG Project miscellaneous combus tion 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 CO 2 capture system for the IG gasifier emergency diesel engines is not a reasonable BACT option because the capture of the CO 2 from combustion exhaust of small sources is significantly more difficult than from the types of industrial gas streams that EPA references as having potential for CCS. The increased difficult y is due to four factors: low CO 2 concentration, low pressure, low quantity of CO 2 available for capture, and the variability of load for these units.

The low concentration and low pressure of the exhausts from these processes complicate the absorption a nd desorption of the CO 2 , which increases the energy required. Also, a low pressure absorption system creates a low pressure CO 2 stream which requires a very high energy demand for compression prior to transport. All these factors make the application of CO 2 capture on any small combustion exhaust extremely difficult and expensive. Additionally, the cost of capturing CO 2 for smaller sources is more expensive due to the lack of economy

- of

- scale. Further, the emergency engines are intermittent sources, wh ich would further increase the cost and difficulty of implementing any control.

Based on the information reviewed for this BACT determination, IDEM, OAQ has determined that the use of post

- combustion capture of CO 2 is not a technically feasible option for the Emergency generators and fire water pumps at this source.Indiana Gasification LLC Page 171 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun 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 : t he selection and use of efficient engines with good engineerin g 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 (CO 2 , CH 4 , and N 2 O) because they will combust a hydrocarbon fuel. However, because their normal use is limited to routine maintenance, inspection and testing, their total e missions are very small (less than 100 tons CO 2 e/yr). Their annual emissions in non

- emergency use are as follows

Emission Units GHG Emissions (tons/yr) CO 2 CH 4 N 2 O 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 mee ting applicable NSPS and MACT standards.

The total CO 2 emissions from all the se e mergency diesel e ngines , under non

- emergency conditions, shall not exceed 84 tons CO 2 per twelve (1 2 ) 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 CO 2 is by far the dominant GHG from this source. CH 4 and N 2 O are present only in very small amounts, are incidental to combustion, and trend with the CO 2 emissions. There are no known supplemental controls for N 2 O or methane emissions from gas

- fired units. To the extent measures are identified that reduce CO 2 , the other GHGs may be also reduced accordingly. Therefore, this BACT analysis focus ed on CO 2 as a surrogate for all GHG emissions.Indiana Gasification LLC Page 172 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun 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 desi gn 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 o f clean natural gas (or SNG) as previously mentioned, no additional applicable good combustion practices have been identified.

Carbon Capture Post

- combustion CO 2 capture is a relatively new concept. In EPA’s recent GHG BACT guidance, EPA takes the posit ion that, “ for the purpose of a BACT analysis for GHGs, EPA classifies CCS as an add

- on pollution control technology that is “available” for large CO 2 - emitting facilities including fossil fuel

- fired power plants and industrial facilities with high

- purity C O 2 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 wit h the fact that carbon capture is extremely expensive, has numerous technical challenges, and is currently only being contemplated on very large or very concentrated CO 2 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 CO 2 capture system for the IG ZLD spray dryer is not a reasonable BACT option because the capture of the CO 2 from combustion exhaust of small sources is significantly more difficult than from the types of industrial gas streams that EPA references as having potential for CCS. The increased difficulty i s due to four factors: low CO 2 concentration, low pressure, low quantity of CO 2 available for capture, and the variability of load for these units.Indiana Gasification LLC Page 173 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun The low concentration and low pressure of the exhausts from these processes complicate the absorption and desorption of the CO 2 , which increases the energy required. Also, a low pressure absorption system creates a low pressure CO 2 stream which requires a very high energy demand for compression prior to transport. All these factors make the application of CO 2 capture on any small combustion exhaust extremely difficult and expensive. Additionally, the cost of capturing CO 2 for smaller sources is more expensive due to the lack of economy

- of

- scale.

Based on the information reviewed for this BACT determination , IDEM, OAQ has determined that the use of post

- combustion capture of CO 2 is not a technically feasible option for the 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) T he 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) T he 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 t his 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 colle cted 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
MM Btu/hour , ge nerating only a small amount of GHGs.

Emission Units GHG Emissions (tons/yr) CO 2 CH 4 N 2 O CO 2 e ZLD Spray Dryer (EU

- 032) 2,884 0.05 0.01 2,887Indiana Gasification LLC Page 174 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun Step 5: Select BACT

Pursuant to 326 IAC 2

- 2

- 3 (Prevention of Significant Deterioration (PSD), IDEM has establis hed the following as BACT for the GHG s 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 CO 2 emissions from the ZLD Spray Dr yer shall not exceed 2,884 tons CO 2 per twelve (1 2 ) 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 G HG emissions f rom 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 le aks, such as pumps, valves, flanges and compressors. This includes both CO 2 and CH 4 . These fugitive emissions are so small relative to the overall facility emissions and in an absolute sense that further control of fugitive emissions would have minimal ad ditional 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. ID EM 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 compone nts is feasible and reasonably cost

- effective, costing approximately $5/ton CO 2 e. However, extending the LDAR program to include CO 2 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 CO 2 is 21 times less than methane. Consequently, on a CO 2 e basis, controlling CO 2 through an LDAR program is much less effective and less cost

- effective than implementing an LDAR p rogram for methane (natural gas and SNG).

The IG facility has three categories of CO 2 containing streams:

1. The product CO 2 stream

– 98% CO 2 ; 2. The acid gas stream from the AGR to the WSA

– approx. 50% CO 2 ; and 3. The various syngas streams

– 6

- 32% CO 2 .Indiana Gasification LLC Page 175 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun 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 CO 2 e LDAR Controlled

tons/yr CO 2 e IG Estimated LDAR Costs

per year (Note 1) LDAR Cost

Effectiveness

$/ton CO 2 e Primary Pollutant Controlled NG/SNG piping (methane) 93 276 2.09 $1,488 $5 CO 2 e
Acid Gas piping.(~50% CO 2 ) 232 3.6 0.058 $3,712 $1,035 CO 2

Prod uct CO 2 Piping ( exclude

. compressor) 95 5.2 0.08 $1,520 $298 CO 2
Syngas (6

- 32% CO 2 ) 964 8.5 0.14 $15,424 $1,840 CO 2

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 pip ing is a reasonably cost

- effective measure on a CO 2 e basis. However, the cost shown above for control of the CO 2 streams is not cost

- effective. It should be noted that the above estimates for the product CO 2 piping excludes emissions from the seals of th e CO 2 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 CO 2 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&F UG

- 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 CO 2 compressors while they are in operation.

Step 5: Select BA CT

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 (LDA R) program for the natural gas and SNG piping and weekly audio/visual inspection of the CO 2 compressors while they are in operation in any week in which there are at least twenty

- four (24) hours of operation of the CO 2 compressor to be inspected.Indiana Gasification LLC Page 176 of 181 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun

Green house 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 pressu re alarm) is state

- of

- the

art for circuit breakers and is proposed by IG. A low pressure alarm is installed on each breaker to alert operators of a loss of SF 6 gas. Operators will investigate the cause of any alarm and take corrective measures to stop the leak if one exists.

Alternative breakers without SF 6 There is no practical alternative to the use of SF 6 as the insulator and arc quenching substance in IG’s circuit breakers. The unique performance qualities of SF 6 breakers is further supported by the most recent report released by the EPA SF 6 Partnership, which states: “no clear alternative exists for this gas that is used extensively in circuit breakers, gas

- insulated substations, and switch gear, due to its inertness and dielectric properties.” Rese arch and development efforts have focused on finding substitutes for SF 6 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 s tudies have concluded, “that there is no replacement gas immediately available to use as an SF 6 substitute” for high

- voltage applications. Therefore, the use of a breaker that doesn’t contain SF 6 is judged as not feasible for this application.

Step 3: Ra nk 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, LL C

– Rockport, IN

The following has been proposed as BACT for GHGs from the proposed Electric Circuit Breaker (FUG

- SF6) : t he use of fully enclosed pressurized SF 6 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 Electric al Circuit Breaker (FUG

- SF 6 )

.
The GHGs BACT for the Electric al Circuit Breaker (FUG

- SF 6 ) shall be the use of fully enclosed
pr essurized SF 6 circuit breakers with leak detection (low pressure alarm).Indiana Gasification LLC Page 177 of 181 Rockport, Indiana PSD /TV Permit No: 147

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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 prima rily CO 2 and water vapor. The CO 2 in this vent is CO 2 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. T he total flow r ate of this vent stream is only 10.4 acf/m and it contains only 204 tons/yr of CO 2 emissions. There are no known GHG controls applicable to this extremely small process vent stream.

Step 2: Eliminate Technically Infeasible Options

No techni cally feasible measures have been identified to control CO 2 emissions in this small vent.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

No technically feasible measures have been identified to control CO 2 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 CO 2 emissions in this small vent.

Step 5: Select BACT

No technically feasible measures have been identified to cont rol GHG emissions in this small
vent.Indiana Gasification LLC Page 178 of 181 Rockport, Indiana PSD /TV Permit No: 147

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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 organ ic compounds (VOC) emissions great er than 25 tons per year , and which are not otherwise regulated by other provisions of 326 IAC 8 rule

, and requires the reduc tion of VOC emissions using Best Available Control Technology (BACT). The proposed Acid Gas Removal Unit s , identified as EU

- 007A an d 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 unit s :

(1 ) Two (2) Acid Gas Removal (AGR) Unit vents, identified as EU

- 007A and EU

- 007B, to be permitted in 2012, with methanol, H 2 S, 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 fu el input, exhausting through two (2 ) stack s , identified as S

- 007 A and S

- 007B

.

Volatile Organic Compounds (VOCs) BACT

- Acid Gas Removal Unit Vents (EU

- 007A and B)

Step 1: Identify Potential Control Technologi es

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 CO 2 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 f easibility of any control option is whether it is b oth available and applicable in reducing VOC em issions. The control technologies listed in the previous section are discussed and evaluated below for their technical feasibility.Indiana Gasification LLC Page 179 of 1 81 Rockport, Indiana PSD /TV Permit No: 147

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- 00060 Permit Reviewer: Josiah Balogun Regenerative Thermal Ox idizer 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 carb on 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 tr ansfer beds to recover thermal ener gy from the oxidation process. The heat transfer beds act as heat exchangers. The heat recover y can be as much as 90 to 95%. Process gas enters the RTO through an inlet manifold. The gas is directed into an energy recov ery 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 CO 2 and water and COS to SO 2 and CO 2 . To achieve thermal oxidation, air must be added and the combined stream heated to approxima tely 1600 degrees F.

The heating value of the stream to the RTO is very low because it contains mostly non

combustible CO 2 (98%). Consequently, each RTO will have a natural gas/SNG burner to raise the temperature in the combustion chamber of the RTO to a pproximately 1600 degrees F. This ensures a high oxidation efficiency of the CO (99%), CH 3 OH (99%), H 2 S (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 determi ned that the use of a rege nerative 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 str eam. 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 pr ovide for heat recovery.

There is very little heating value inherent in the AGR Vent stream which has an approximate concentration of 98%v CO 2 . Consequently, a conventional Thermal Oxidizer without heat recovery would have a very high supplemental fuel re quirement (more than 10 times higher than

a R TO) to reach a 1600 F gas temperature. Therefore, a conventional T hermal O xidizer would have higher operating costs and higher combustion generated pollutant emissions (NO x , VOC, PM 10 ).

Based on the informat ion 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 conver ts the VOC in the combustion gases to CO 2 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 ft 3 of catalyst per 1000 standard ft 3 per gas flow rate. Catalytic oxidation is proposed for the Cash Creek Generation gasification AGR Vent Stream at aIndiana Gasification LLC Page 180 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 Permit Reviewer: Josiah Balogun

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 T he 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, us e of a flare would require a significant addition of supplementary fuel. Therefore, a secondary impact of the use of flare for this stream would be the creation of additional emissions from burning supplemental fuel, including NO x . Flares have not been u tilized 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 determ ination, IDEM, OAQ has determined that the use of a flare is not a technically feasible option for Acid Gas Recovery Unit Vent (EU

007A/B) at this source.

Step 3: Rank the Remaining Control Technologies by Control Effectiveness

Based on the technical feas ibility 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) Conventio nal thermal oxidation (98

- 99 % VOC Reduction)

(3) Catalytic Oxidation (> 90% VOC Reduction)

The oxidation efficiency of VOC from both the Regenerative and Conventional Th ermal Oxidizers is the same (98%). Overall VOC emissions generated from the AGR Ven t 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 s uperior 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 p lants. 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 electr onic versions of permits available at the websites of other per mitting agencies.Indiana Gasification LLC Page 181 of 181 Rockport, Indiana PSD /TV Permit No: 147

- 30464

- 00060 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

- LA

742(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 Gasifi cation

– 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 deter mination 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 oxida tion 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

– Ro ckport, 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 contr ol 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 fo llowing 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 ve nt shall not exceed 1.0 5 pounds per hour based on a 3

- h our 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 t heir PSD modeling in April 2011. Revised modeling for NO 2 , SO 2 , and CO was sent in June 2011 to address model ing changes and new meteorological data. This was followed by PM 10 and PM 2.5 modeling sent in October 2011. The October PM 10 and PM 2.5 modeling was updated in November 2011 to address emis sion changes in the material handling sources.

IG proposes to construct and operate a substitute natural gas (SNG) and liquefied carbon dioxide (CO 2 ) production plant near the Ohio River in Spence r County, in Rockport, I ndiana. 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 an alysis review of the submitted modeling by URS for IG.


### Analysis Summary

Based on the potential emissions after contro ls, a PSD air quality analysis was triggered for SO 2 , PM 10 , PM 2.5, CO, NO 2 , and sulfuric acid mist. The signi ficant impact analysis for CO, NO 2 , SO 2, and PM 10 determined that modeling concentrations did not exceed the significant impact levels. A refined analysis was required for the 24 hour and annual PM 2.5 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 PM 2.5 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 im pact. A Hazardous Air Pollutant (HAP) analysis was performed. Based on the HAPs modeling result s, the source will not pose a health concern.



### Air Quality Imp act 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, andIndiana Gasification, LLC Page 2 of 49 Rockport, Indiana PSD/TV Permit No. T147-30464-00060 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 a ttainment and unclassifiable areas and require an air quality impact analysis of each regulated pollutant em itted in significant amount s 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

PM 10 , PM 2.5, NO 2 , SO 2 , CO, and sulfuric acid mist are the ma in pollutants that will be emitted from IG and are summarized below in Table 1. PM 10 , PM 2.5, NO 2 , SO 2 , CO, and sulfuric acid mist potential emissions after controls exceed the PSD signific ant 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

VOC 1 15.9 40 No 1

PM 10 67.1 15 Yes

PM 2.5 60.5 10 Yes

NO 2 127 40 Yes

SO 2 <100 2 40 Yes

CO 634 100 Yes

Sulfuric Acid Mist 3 42.7 7 No 3

1 An air quality analysis is not performed fo r VOCs because they are photochemically reac tive. Photochemical models like UAM-V are used in regulatory or policy assessments to stimulate the im pacts from all sources by esti mating pollutant concentrations a nd 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 sca les 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 SO 2 emission rates cannot happen at one time.Indiana Gasification, LLC Page 3 of 49 Rockport, Indiana PSD/TV Permit No. T147-30464-00060 Permit Writer: Michael Mosier

3 Sulfuric Acid Mist has no monitoring thres hold or National Ambient Air Quality Standard. No AQ analysis is required for Sulfur ic 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 Engineeri ng 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 est ablished 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 f eet) is limited to GEP for the purpose of establishing emission limitations. The GEP stack height takes in to account the distance and dimensions of nearby structures, which affects the downwi nd wake of the stack. The downwind wake is considered to extend five times the lesser of the structur e'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 Au tomated 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 Linc oln, 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 determi ne maximum off-property concentrations or impacts for each pollutant. All regulatory default options we re 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 gener ated 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.Indiana Gasification, LLC Page 4 of 49 Rockport, Indiana PSD/TV Permit No. T147-30464-00060 Permit Writer: Michael Mosier

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 interpol ated from DEM (Digital Elevation Model) data obtained from the USGS. DEM terrai n 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 sour ce's concentrations exceed these levels, further air quality analysis is required. Refined modeling for PM 10 , SO 2 , NO 2 , and CO was not required because the results did not exceed significant impact levels. The 24-hour and annual PM 2.5 values exceeded their significant impact levels and require refined modeling. URS modeled a variety of operating scenarios to predict maximum concentrations. A complete disc ussion 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 operatin g scenarios. A Tier II 80% conversion of NO to NO 2 was assumed based on the March 01, 2011, Tyler Fox memorandum.

TABLE 2 Significant Impact Analysis 3

POLLUTANT TIME AVERAGING PERIOD MAXIMUM MODELED IMPACTS (μg/m 3 ) SIGNIFICANT IMPACT LEVEL (μg/m 3 ) REFINED AQ ANALYSIS REQUIRED

NO 2 Annual 1 .64 1 No

NO 2 1 hour 2 7.4 7.55 No

PM 10 Annual 1 .986 1 No

PM 10 24 hour 1 4.25 5 No

PM 2.5 Annual 2 .30 .3 Yes

PM 2.5 24 hour 2 1.66 1.2 Yes

SO 2 3 hour 1 22.8 25 No

SO 2 24 hour 1 2.5 5 No

SO 2 Annual 1 .21 1 No

SO 2 1 hour 2 7.04 7.80 No

CO 1 hour 1 454 2000 No

CO 8 hour 1 207 500 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 model ed concentration may be averaged over the five years modeled for comparison with the 1 hour NO 2 , 1 hour SO 2 , 24 hour PM 2.5 and the annual PM 2.5 SIL. See the March 01, 2011, and the March 23, 2010, memorandums
3 Impacts are from IG only.Indiana Gasification, LLC Page 5 of 49 Rockport, Indiana PSD/TV Permit No. T147-30464-00060 Permit Writer: Michael Mosier 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 m onitoring 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/m 3 ) DEMINIMIS LEVEL (μg/m3) ABOVE DE MINIMIS LEVEL

NO 2 Annual 1 .64 14 No

PM 10 24 hour 1 4.25 10 No

PM 2.5 24 hour 2 1.66 4 No

SO 2 24 hour 1 2.5 13 No

1 The first highest values per the EPA NSR manual dated October 1990. Maximu m modeled impacts are from IG only.
2 In accordance with recent U.S. EPA guidanc e, the highest modeled concentration may be av eraged over the five years. See the March 01, 2011, and the March 23, 2010, memorandums from EPA.

PM 10, PM 2.5 , NO 2 and SO 2 did not trigger the preconstruction monitoring threshold level. IG can satisfy the preconstruction monitori ng requirement since there is air quality monitoring data representative of the area in other counties.

Background Concentrations

Applicability

EPA’s “Ambient Monitoring Guidelines for Prevent ion of Significant Deterioration” (EPA-450/4-87- 007) Section 2.4.1 is cited for approval of t he monitoring sites chosen for this area.

Background Monitors

Background data was taken from repr esentative monitoring stations for IG. The background design value was used for PM 2.5 . 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 *Indiana Gasification, LLC Page 6 of 49 Rockport, Indiana PSD/TV Permit No. T147-30464-00060 Permit Writer: Michael Mosier

Pollutant Location Monitoring Site Annual Concentration (μg/m3) 24 hr Concentration (μg/m3)

PM 2.5 Owensboro, Kentucky 210590005 12.2 26

*PM 2.5 used the design value.



### Section D - NAAQS and PSD Increment

OAQ supplied emission inventories of all point sour ces 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. Kentuc ky supplied emission inventories for their state. All sources with the potential to cause a significant co ncentration gradient in the vicinity of the proposed facility were explicitly included in the modeling.

NAAQS Compliance Analysis and Results for PM 2.5 24 hour

NAAQS modeling for the 24-hour time-averaging period for PM 2.5 was conducted and compared to the respective NAAQS limit. For the 24-hour mo deling, 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 modelin g 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 backgr ound were not below the NAAQS limit and a culpability analysis was required and is shown in Table 5b and Table 5c.

TABLE 5a 1 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

PM 2.5 (Truck Scenario) 2006- 2010 24 hour 17.83 2 26 43.83 35 Yes

PM 2.5 (Train Scenario) 2006- 2010 24 hour 17.82 2 26 43.82 35 Yes

1 Any differences between the maximum concentration numbers in T ables 5 and 6 are due to different sources used for the NAAQS and the increment inventories and different averaging techniques to obtain maximum concentrati ons. Tables 3 and 6 maximum concentrations are from IG only.
2 In accordance with recent U.S. EPA gui dance, the highest modeled concent ration may be averaged over the five years. See the March 23, 2010, memorandum from EPA.

Table 5b 1 24-Hour Culpability Analysis For Truck DeliveryIndiana Gasification, LLC Page 7 of 49 Rockport, Indiana PSD/TV Permit No. T147-30464-00060 Permit Writer: Michael Mosier

Highest Predicted 24-hour PM 2.5 Concentration from Cumulative Analysis for the Truck Delivery Scenario (μg/m 3 )

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 5c 1 24-Hour Culpability Analysis For Train Delivery

Highest Predicted 24-hour PM 2.5 Concentration from Cumulative Analysis for the Train Delivery Scenario (μg/m 3 )

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 evaluat ed below the maximum modeled concentration for each scenario until there was no longer a NAAQS vi olation and showed IG was below significance and did not cause or contribute to a violation of the N AAQS. A table of these values can be found in the Appendix.

NAAQS Compliance Analysis and Results for PM 2.5 Annual

NAAQS modeling for the annual time period for PM 2.5 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 5d 1 Annual NAAQS Analysis

Pollutant Year Time-Averaging Maximum Background Total NAAQS Limit NAAQSIndiana Gasification, LLC Page 8 of 49 Rockport, Indiana PSD/TV Permit No. T147-30464-00060 Permit Writer: Michael Mosier

Period Concentration μg/m3 Concentration μg/m3 μg/m3 μg/m3 Violation

PM 2.5 2006- 2010 Annual 2.66 2 12.2 14.86 15 No

1 Any differences between the maximum concent ration 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 concentrati ons. Tables 3 and 6 maximum concentrations are from IG only.
2 In accordance with recent U.S. EPA guidanc e, 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 PM 2.5 Concentration from Cumulative Analysis (μg/m 3 )

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 co ncentration 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 eval uate 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 partic ulate modeling supplemental report. The analysis showed that the nearby sources’ modeled emission s are estimated to have an annual impact at the location of the background monitor of over 4 μg/m 3 . 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 PM 2.5 . 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 PM 2.5 modeled greater than or equal to significant impact levels, a PSD increment analysis for IG was required for both averaging times. Because PM 2.5 increment values were established in 2010 and the PM 10 surrogacy policy was removed, the baseline date for the increment would be within the last few ye ars. 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.Indiana Gasification, LLC Page 9 of 49 Rockport, Indiana PSD/TV Permit No. T147-30464-00060 Permit Writer: Michael Mosier

TABLE 6 1 Increment Analysis

Pollutant Year Time-Averaging Period Maximum Concentration μg/m3 PSD Increment μg/m3 Percent Impact on the PSD Increment Increment Violation

PM 2.5 (Train Scenario) 2006-2010 24-hour 2 1.64 9 18% No

PM 2.5 (Truck Scenario) 2006-2010 24-hour 2 1.67 9 19% No

PM 2.5 (Truck

Scenario) 2006-2010 Annual 3 0.33 4 8% No

1 Any differences between the maximum concentration numbers in T ables 5 and 6 are due to different sources used for the NAAQS and the increment inventories, and different averaging techniques to obtain maximum concentrati ons. Tables 3 and 6 maximum concentrations are from IG only.
2 I n accordance with the Federal Register dated October 20, 2010; the high 2 nd high is used.
3 I n accordance with the Federal Register dated October 20, 2 010; 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 PM 2.5 secondary formation

In addition to direct emissions of PM 2.5 , other pollutants, chiefly NO x and SO 2 , can lead to formation of PM 2.5 further downwind. The photochemical reacti ons that transform these pollutants into nitrates and sulfates, which become the major species of PM 2.5 , take place over hours or days. Potentials to emit after controls for IG are 127 tpy NO x and < 100 tpy SO 2
. The modeling for these two primary pollutants sh ows that receptor c oncentrations 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.

NO x SO 2Indiana Gasification, LLC Page 10 of 49 Rockport, Indiana PSD/TV Permit No. T147-30464-00060 Permit Writer: Michael Mosier

Since the NO 2 and SO 2 standards are extremely restrictive, being below the SILs would likely prevent the pollutants from impacting secondary format ion significantly enough to result in a violation of the PM 2.5 standards.

However, it is possible that some transformation in to 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 SO 2 or NO x . All photochemical models ar e regional scale and a source of this size would not show any measurable impac t. Therefore, other available information from emissions inventories, meteorological analyses, and ot her modeling projects can be used to estimate the impact from this source.

The wind rose shows the general directions t hat emissions from this source would impact.

Evansville 2008 Evansville 2009 Evansville 2010Indiana Gasification, LLC Page 11 of 49 Rockport, Indiana PSD/TV Permit No. T147-30464-00060 Permit Writer: Michael Mosier Design values from 2008 – 2010 at all Kentucky PM 2.5 monitors in the area and Indiana PM 2.5 monitors meet the annual and 24-hour NAAQS.

Because of the well established relationship between NO x and SO 2 , regional transport, and the formation of PM 2.5 , to assist states to meet the PM 2.5 NAAQS, U.S. EPA recently finalized the Cross State Air Pollution Rule (CSAPR). This rule included exte nsive modeling to support the emissions reductions necessary in each stat e to achieve the PM 2.5 NAAQS in the eastern U.S. The source category responsible for these reductions is El ectric 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 necess ary to achieve the NAAQS at every site. The documentation includes extensive t ables showing impacts at all PM 2.5 monitoring sites in the eastern U.S. and emission reduction levels necessary to achieve those results.

To examine the possible impact of IG, modeling U.S. EPA used to establish the final 2014 budgets in CSAPR is used for this analys is. The CSAPR website is located at http://www.epa.gov/airtransport/

. Tables showing projected base case 2014 PM 2.5 concentrations at existing monitoring sites versus control strategy PM 2.5 concentrations are located in C SAPR_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 SO 2 emission reductions necessary to achieve the future year modeled design values can be found in the “Significant Cont ribution Assessment TSD”, Table 1, page 9. This table shows the base case annual SO 2 emissions for Indiana by 2014 were projected to be 727,786 tons, and remedy control scenario annual SO 2 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 Ru le 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 co ncentrations for Spencer County are 12.66 μg/m 3 for the 2014 base case and 9.95 μg/m 3 for the 2014 control scenario. This is a reduction of 2.71 μg/m 3 . In order for this modeled annual concentration reduction to occur, Indiana EGUs modeled annual SO 2 emissions by 2014 were reduced by 532,740 tons and annual NO x emissions by 2014 were reduced by 7,092 for a total of 539,833 tons of SO 2 and NO x . This particular monitoring site is not necessarily impacted by every EGU in Indiana, but in the surroun ding states, hundreds of t housands of tons of annual SO 2 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 SO 2 and NO x emissions / 539,833 tons of SO 2 and NO x can be compared to the ratio of IG PM 2.5 impact / 2.71 μg/m 3 of PM 2.5
. The calculation to estimate secondary formation is as follows:

227 tons SO 2 & NO x /539,833 tons SO 2 & NO x = (IG PM 2.5 impact) .00042* 2.71 μg/m 3 of PM 2.5 = 0.00114 μg/m 3 of PM 2.5

EPA’s Cross-State Air Pollution Rule M odeling Results & Estimated IG Impact Anticipated AnticipatedIndiana Gasification, LLC Page 12 of 49 Rockport, Indiana PSD/TV Permit No. T147-30464-00060 Permit Writer: Michael Mosier

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 PM 2.5 concentrations at this site.

EPA’s Cross-State Air Po llution Rule Annual PM 2.5 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 assess es the impacts on growth, soils and vegetation, endangered species, and visibility caused by any incr ease 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 eith er quantitatively or qualitatively.

It is estimated that approximately 200 additional jo bs 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 grow th 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 glacia l till, discontinuous loes s over weathered sandstone and shale, and discontinuous loess ov er weathered limestone and shale.

Due to the agricultural nature of the land, cr ops in the Spencer County area consist mainly of corn, sorghum, wheat, soybeans, and oats (2002 Agri cultural 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 autum n bent, nimblewill, barnyard grass, bishop’s cap, horsetail, and milkweed (Flora of Indiana – Charles De am). 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 ar e mainly hardwoods. These are hardy trees and no significant adverse impacts are expected due to modeled concentrations. Federal and State Endangered Species AnalysisIndiana Gasification, LLC Page 13 of 49 Rockport, Indiana PSD/TV Permit No. T147-30464-00060 Permit Writer: Michael Mosier Federal and state endangered species are listed by th e U.S. Fish and Wildlife Service, Division of Endangered Species for Indiana, and include 5 amphib ians, 27 birds, 10 fishes, 6 mammals, 15 mollusks, and 15 reptiles. Of the federal an d 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 rive rs 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 st ate 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 sinc e the combined emissions of visibility impairing pollutants are less the screening threshold. The thre shold is calculated by di viding 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 PM 10 , SO 2 , and NO x . Proposed potential emissions of these pollutants from IG were examined for source contribution to visibility impairment.

The CALPUFF model was used to estimate visi bility 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 = B ext ) and also in deciviews. A 5% change in light extinction (B ext ) equates to approximately 0.5 deciviews. The criteria used to de termine if a source is contributing to visibility impairment is the 98 th 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. Therefor e, IG will not contribute to visibility impairment at Mammoth Cave National Park.

Additional Analysis Conclusions

Finally, the results of the additional impact analys is 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.Indiana Gasification, LLC Page 14 of 49 Rockport, Indiana PSD/TV Permit No. T147-30464-00060 Permit Writer: Michael Mosier


### 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, Offi ce of Air Quality's construction permit application Form GSD-08.

The single HAP with the highest emissions is me thanol, with estimated annual emissions of 7.5 tons per year. Potential emissions of aggregate H APs 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 effect s that each pollutant presents to the public.

The URF is the upper-bound excess lifetime canc er 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 estima te. The cancer risk estimate is the conservative probability of developing cancer from exposure to a pollutant or a mi xture 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 t he 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 determ ine the pollutant’s Hazard Quotient (HQ). All of the HAPs’ Hazard Quotients were added toget her 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) a ssume a 70 year exposure time, 2) assume that all carcinogens cause the same type of cancer, 3) as sume that all non-carcinogens have additive health effects, 4) assume maximum permit allowable emissi ons 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 0.000Indiana Gasification, LLC Page 15 of 49 Rockport, Indiana PSD/TV Permit No. T147-30464-00060 Permit Writer: Michael Mosier

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 ar eas where adverse health effects w ill 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 y ears, the risk of getting cancer from th is 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 pr obability 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. PM 10 , NO 2 , SO 2 , CO, PM 2.5 , and sulfuric acid mist emission rates associated with the proposed facility exceeded the respective significant emission rates. Modeling results taken from AERMOD model showed PM 2.5 impacts were predicted to be greater than the significant impact levels for the 24-hour and annual averaging pe riods. IG did not trigger the preconstruction monitoring threshold level but can satisfy the prec onstruction monitoring requirement since there is existing air quality monitoring data representative of the area. The NAAQS modeling for 24-hour PM 2.5 showed violations of the standard, but IG was not significant during those violations. Though IG was significant for annual PM 2.5 , the NAAQS modeling did not show violations of the standard. IG was below the PM 2.5 increment modeling. Secondary PM 2.5 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 (H AP) analysis was performed and showed no likely adverse impact.Indiana Gasification, LLC Page 16 of 49 Rockport, Indiana PSD/TV Permit No. T147-30464-00060 Permit Writer: Michael Mosier

Appendix

24-Hour PM 2.5 Culpability Analysis For Truck DeliveryIndiana Gasification, LLC Page 17 of 49 Rockport, Indiana PSD/TV Permit No. T147-30464-00060 Permit Writer: Michael Mosier

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 16.71355Indiana 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 14.13924Indiana 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 12.95306Indiana 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 11.96871Indiana 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 11.54423Indiana 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 10.70951Indiana 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 10.46156Indiana 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 10.3388Indiana 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 9.75128Indiana 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 9.48093Indiana 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 0Indiana 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 0Indiana 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 0Indiana 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 PM 2.5 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 17.27766Indiana 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 16.35982Indiana 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 14.47843Indiana 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 13.83784Indiana 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 11.84674Indiana 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 11.79805Indiana 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 11.67839Indiana 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 10.98653Indiana 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 10.40365Indiana 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 10.74003Indiana 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 9.64718Indiana 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 9.73585Indiana 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 9.27678Indiana 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 0Indiana 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 TrainIndiana 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 0Indiana 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 9.20066Indiana 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 0Indiana 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 0Indiana 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

Technic al Support Document (TSD) for a PSD/ Part 70 Operating Permit : Appendix D: Compliance Assurance Monitoring ( CAM ) Plan

Source Background and Description

Source Name: Indiana Gas ification 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 Co mpliance 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) P lant (NO x , H 2 SO 4 & SO 2 )

These sources are subject to the Compliance Assurance Moni toring (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 establ ishes 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 Rege ne rative The rmal 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 H 2 S and COS. The AGR system, whi ch 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 CO 2 , 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 Emis sions Unit ID 07).Indiana Gasification LLC Page 2 of 7 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

sou rce. 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 regenerat ive thermal oxidizer is an abatement device that converts CO from process gas streams into CO 2 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 e nergy 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 wil l 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 c alendar 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 un it 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 esta blished performance range for the RTO shall be a recommended minimum temperature from the manufacturer, 1600 o F, or from the design or operating engineers. This minimum temperature may be determined and/or confirmed during the shakedown period of the initi al 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:Indiana Gasification LLC Page 3 of 7 Rockport, Indiana Appendix D PSD and TV Permit No.:147

- 30464

- 00060 Permit Reviewer: Josiah Balogun
Corrective action will be initiated as soon as p ractically 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

recommen ded 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 numb er 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 pla n 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 discrepa ncy, 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 minu tes) 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 t emperature are recorded in a 6

- month period (from all units addressed under this Plan).Indiana Gasification LLC Page 4 of 7 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 Sulfu ric 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, SO 2 , and H 2 SO 4 greater t han 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 p ollutants from a new major

source. As an emission limit, BACT for this emission unit is proposed equivalent to 0.15 pounds of H 2 SO 4 emissions and 0.25 pounds SO 2 per ton of acid produced and 10.7 pounds of NO x per hour from each of the two processing trai ns. SO 2 and H 2 SO 4 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 controll ed 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 s olution as a scrubbing medium. Sulfur containing compo unds (SO 2 /H 2 SO 4 ) 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 diatomi c nitrogen, N 2 and water.Indiana Gasification LLC Page 5 of 7 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 t he 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 hydrog en 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. NO x 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 pr actically 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.Indiana Gasification LLC Page 6 of 7 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 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.

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 suc cessive 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 f ollow 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 re port 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 a ction 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 sha ll 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 SO 2 and H 2 SO 4 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 Op eration Permit No.: T 147

- 30464

- 00060 Operation Permit Issuance Date: Yet to be Issued Permit Reviewer: Josiah BalogunIndiana Gasification, LLC Appendix E Page 2 of 6 Rockport , Indiana T 147

- 30464

- 000 6 0 Permit Reviewer: Josiah BalogunIndiana Gasification, LLC Appendix E Page 3 of 6 Rockport , Indiana T 147

- 30464

- 000 6 0 Permit Reviewer: Josiah BalogunIndiana Gasification, LLC Appendix E Page 4 of 6 Rockport , Indiana T 147

- 30464

- 000 6 0 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 T 147

- 30464

- 000 6 0 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 T 147

- 30464

- 000 6 0 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)

## I NDIANA 

## D EPARTMENT OF 

## E NVIRONMENTAL 

## M ANAGEMENT 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 Branc h Office of Air Quality

SUBJECT: Final Decision Title V 147-3 046 4-00060

Enclosed is the final decision and supporting material s for the air permit application referenced above. Please note that this packet contains the original, signed, permit documents.

The final decision is being sent to you because our reco rds 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 mate rials 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 doc um ents, 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 thin k you have received this do cument 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

## I NDIANA 

## D EPARTMENT OF 

## E NVIRONMENTAL 

## M ANAGEMENT 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 av ailable to the public during the public comment period of a draft permit. Enclosed is a copy of the final decision and supporting materials for the same project. Please place the enclosed information along with the information you previously received. To ensure that your patrons have am ple opportunity to review the enclosed permit, we ask that you retain this document for at least 60 days.

The applicant is responsible for placing a copy of the application in your library. If the permit application is not on file, or if you have any questions concerning this public review process, please contact Joanne Smiddie-Brush, OAQ Permits Administration Section at 1-800-451-6027, extension 3-0185.

Enclosures Final Library.dot 11/30/07

## I NDIANA 

## D EPARTMENT OF 

## E NVIRONMENTAL 

## M ANAGEMENT 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 info rmation in error, or would like to be removed from the Air Permits mailing list, pl ease 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 11/14/08FACSIMILIE OF PS Form 3877Mail Code 61-53IDEM Staff CDENNY 6/26/2012Indiana Gasification LLC 147-30464 -00060(final)AFFIX STAMPHERE IFUSED ASCERTIFICATEOF MAILINGName andaddress ofSender►Indiana Department of EnvironmentalManagementOffice of Air Quality – Permits Branch100 N. SenateIndianapolis, IN 46204Type of Mail:CERTIFICATE OFMAILING ONLYLine ArticleNumberName, Address, Street and Post Office Address Postage HandingChargesAct. Value(If Registered)InsuredValueDue Send ifCODR.R.FeeS.D. Fee S.H.FeeRest.Del. FeeRemarks1Mark Lubbers Indiana Gasification LLC PO Box 55934 Indianapolis IN 46205 (Source CAATS)2Thomas Mara President Indiana Gasification LLC 315 Park Ave South, 20th Floor New York NY 10010-3607(RO CAATS)3Mr. Wendell Hibdon Plumbers & Steam Fitters Union, Local136 2300 St. Joe Industrial Park Dr Evansville IN 47720(Affected Party)4Ms. Francis Lueken 223 W. 10th Street, P.O. Box 206 Ferdinand IN 47532(Affected Party)5Mr. Wayne Werne 10185 E SR 62 Ferdinand IN 47532(Affected Party)6Ms. Donna R. Martin 1524 S Old State Road 45 Rockport IN 47635(Affected Party)7Rockport City Council and Mayors Office P.O. Box 151 Rockport IN 47635(Local Official)8Spencer Co Public Library 210 N Walnut St Rockport IN 47635-1398(Library)9Mr. Thomas Utter Lincolnland Economical DevelopmentCorporation PO Box 400 Santa Claus IN 47579(Affected Party)10Ms. Kathy Tretter Dubois-Spencer Counties Publishing Co, Inc P.O. Box 38 Ferdinand IN 47532-0038(Affected Party)11Mr. Rex Winchell 715 W. Old SR 45 Rockport IN 47635(Affected Party)12Mr. Larry E. Sigler 668 East C.R.700 North Chrisney IN 47611-9315(Affected Party)13Spencer County Commissioners 200 Main St.,Courthouse Rockport IN 47635 (Local Official)14Spencer County Health Department Main Street Courthouse, 1st Floor, Room 1 Roackport IN 47635-1492(Health Department)15Mr. Mark Wilson Evansville Courier & Press P.O. Box 268 Evansville IN 47702-0268(Affected Party)Total number of piecesListed by SenderTotal number of PiecesReceived at Post OfficePostmaster, Per (Name ofReceiving employee)The full declaration of value is required on all domestic and international registered mail. Themaximum indemnity payable for the reconstruction of nonnegotiable documents under ExpressMail document reconstructing insurance is $50,000 perpiece subject to a limit of $50, 000 peroccurrence. The maximum indemnity payable onExpress mil merchandise insurance is $500.The maximum indemnity payable is $25,000 for registered mail, sent with optional postalinsurance. SeeDomestic Mail ManualR900, S913, andS921for limitations of coverage oninured and COD mail. SeeInternational Mail Manualfor limitations o coverage on internationalmail. Special handling charges apply only to Standard Mail (A) and Standard Mail (B) parcels.FACSIMILIE OF PS Form 3877Mail Code 61-53IDEM Staff CDENNY 6/26/2012Indiana Gasification LLC 147-30464 -00060(final)AFFIX STAMPHERE IFUSED ASCERTIFICATEOF MAILINGName andaddress ofSender►Indiana Department of EnvironmentalManagementOffice of Air Quality – Permits Branch100 N. SenateIndianapolis, IN 46204Type of Mail:CERTIFICATE OFMAILING ONLYLine ArticleNumberName, Address, Street and Post Office Address Postage HandingChargesAct. Value(If Registered)InsuredValueDue Send ifCODR.R.FeeS.D. Fee S.H.FeeRest.Del. FeeRemarks1James M. Hauck Hatchett & Hauck 111 Monument Circle Suite 301 Indianapolis IN 46204 (Attorney) (PICKED UP IN PERSON)2Mr. John Blair 800 Adams Ave Evansville IN 47713(Affected Party)3Eager Development PO Box 1612 Owensboro KY 42302(Affected Party)4Lincolnland Ecanomic Development PO Box 276 Rockport IN 47635(Affected Party)5Indiana Michigan Power Company P.O. Box 16428 Columbus OH 43216(Affected Party)6Mason & Don Foertsch P.O. Box 16 Lamar IN 47500(Affected Party)7Jasper Properties, LLC PO Box 162 Jasper IN 47547(Affected Party)8Kingdom Hall of Jehovahs Witnesses 1038 N. SR 66 Rockport IN 47635(Affected Party)9Gregory & Mary James 1062 N. SR 66 Rockport IN 47635(Affected Party)10Trustees of The Apostolic BibleChurch 713 Jefferson Rockport IN 47635(Affected Party)11Sylvester W & Agnes R Dilger Revocatble Trust 676 N Meadowland Dr Rockport IN 47635(Affected Party)12Hurm Farms Inc 371 E CR 200 N Rockport IN 47635(Affected Party)13Miramonte Property Mgmt LLC PO Box10 Hebron OH 43025-0010 (Affected Party)14Michael D & Wanda L Toler 93 E CR 200 N Rockport IN 47635(Affected Party)15Commonwealth Aluminum Concast 25825 Science Park Dr, Ste 400 Beachwood OH 44122-7392(Affected Party)Total number of piecesListed by SenderTotal number of PiecesReceived at Post OfficePostmaster, Per (Name ofReceiving employee)The full declaration of value is required on all domestic and international registered mail. Themaximum indemnity payable for the reconstruction of nonnegotiable documents under ExpressMail document reconstructing insurance is $50,000 perpiece subject to a limit of $50, 000 peroccurrence. The maximum indemnity payable onExpress mil merchandise insurance is $500.The maximum indemnity payable is $25,000 for registered mail, sent with optional postalinsurance. SeeDomestic Mail ManualR900, S913, andS921for limitations of coverage oninured and COD mail. SeeInternational Mail Manualfor limitations o coverage on internationalmail. Special handling charges apply only to Standard Mail (A) and Standard Mail (B) parcels.FACSIMILIE OF PS Form 3877Mail Code 61-53IDEM Staff CDENNY 6/26/2012Indiana Gasification LLC 147-30464 -00060(final)AFFIX STAMPHERE IFUSED ASCERTIFICATEOF MAILINGName andaddress ofSender►Indiana Department of EnvironmentalManagementOffice of Air Quality – Permits Branch100 N. SenateIndianapolis, IN 46204Type of Mail:CERTIFICATE OFMAILING ONLYLine ArticleNumberName, Address, Street and Post Office Address Postage HandingChargesAct. Value(If Registered)InsuredValueDue Send ifCODR.R.FeeS.D. Fee S.H.FeeRest.Del. FeeRemarks1Nancy Shelton & Leona Matthews 418 S Lincoln Ave Rockport IN 47635 (Affected Party)2Raymond & Patricia L Dawson 319 E CR 250 N Rockport IN 47635(Affected Party)3Owen C & Katherine Robinson 419 E CR 250 N Rockport IN 47635(Affected Party)4State of Indiana 3650 S US Hwy 41 Vincennes IN 47759(Affected Party)5Crown Communications Inc 4017 Washington Rd McMurray PA 15317(Affected Party)6Coal Inland Inc 1111 Western Row Rd Mason OH 45040(Affected Party)7Reo Properties LLC PO Box 27 Handerson KY 42419(Affected Party)8Rainbow Development Corp 4100 N Silverdale Rd Rockport IN 47635(Affected Party)9Landmark Bible Church 1124 N SR 66 Rockport IN 47635(Affected Party)10Mulzer Crushed Stone PO Box 249 Tell City IN 47586(Affected Party)11Bernard J Jr. & Mary Martha Hurm 2862 N Old State Rd Rockport IN 47635(Affected Party)12Sidney R Lindsey Life Estate 217 Main St Rockport IN 47635(Affected Party)13Spencer County Sand LLC PO Box 2428 Clarksville IN 47131 (Affected Party)14Norfolk Southern Railroad 1200 Peachtree St, Box 7-142 Atlanta GA 30309-3579(Affected Party)15Kathryn Williams & Laurel Montgomery 1837 Towington Dr Raliegh NC 27615(Affected Party)Total number of piecesListed by SenderTotal number of PiecesReceived at Post OfficePostmaster, Per (Name ofReceiving employee)The full declaration of value is required on all domestic and international registered mail. Themaximum indemnity payable for the reconstruction of nonnegotiable documents under ExpressMail document reconstructing insurance is $50,000 perpiece subject to a limit of $50, 000 peroccurrence. The maximum indemnity payable onExpress mil merchandise insurance is $500.The maximum indemnity payable is $25,000 for registered mail, sent with optional postalinsurance. SeeDomestic Mail ManualR900, S913, andS921for limitations of coverage oninured and COD mail. SeeInternational Mail Manualfor limitations o coverage on internationalmail. Special handling charges apply only to Standard Mail (A) and Standard Mail (B) parcels.FACSIMILIE OF PS Form 3877Mail Code 61-53IDEM Staff CDENNY 6/26/2012Indiana Gasification LLC 147-30464 -00060(final)AFFIX STAMPHERE IFUSED ASCERTIFICATEOF MAILINGName andaddress ofSender►Indiana Department of EnvironmentalManagementOffice of Air Quality – Permits Branch100 N. SenateIndianapolis, IN 46204Type of Mail:CERTIFICATE OFMAILING ONLYLine ArticleNumberName, Address, Street and Post Office Address Postage HandingChargesAct. Value(If Registered)InsuredValueDue Send ifCODR.R.FeeS.D. Fee S.H.FeeRest.Del. FeeRemarks1C Wayne Mastin, Sharon Greene & Darlene Richey 2611 S CR 350 W Rockport IN 47635 (Affected Party)2Ms. April Tuley/Gray 602 S CR 200 N Rockport IN 47635(Affected Party)3Larry J & Melina S Hurm 1848 N CR 200 W Rockport IN 47635(Affected Party)4Richard Family LLC 788 W SR 66 Rockport IN 46735(Affected Party)5Dan & Jessee Rininger 1001 N Silverdale Rd Rockport IN 47635(Affected Party)6Gilbert H Hartig Life Estate 7824 Middle Mt Vernon Rd Evansville IN 47712(Affected Party)7Harlan Lehr 1441 N Base Rd Rockport IN 47635(Affected Party)8Cleon Hurm 4127 W Eureka Rd Rockport IN 47635(Affected Party)9Mr. Roger Hurm 3610 N Silverdale Rd Rockport IN 47635(Affected Party)10Mr. Donald Schroeder 2281 W CR 350 S Rockport IN 46735(Affected Party)11Michael & Janice Cochenour 349 E CR 350 N Rockport IN 47635(Affected Party)12Paul Schulte 4100 Silverdale Rd. Rockport IN 47635(Affected Party)13Town Council and Town of Grandview 316 Main St. Grandview IN 47615 (Affected Party)14Quinn Bowden 1100 W 42nd St # 218 Indianapolis IN 46208(Affected Party)15Rock Blanchard 6539 W CR 400 N Richland City IN 47634(Affected Party)Total number of piecesListed by SenderTotal number of PiecesReceived at Post OfficePostmaster, Per (Name ofReceiving employee)The full declaration of value is required on all domestic and international registered mail. Themaximum indemnity payable for the reconstruction of nonnegotiable documents under ExpressMail document reconstructing insurance is $50,000 perpiece subject to a limit of $50, 000 peroccurrence. The maximum indemnity payable onExpress mil merchandise insurance is $500.The maximum indemnity payable is $25,000 for registered mail, sent with optional postalinsurance. SeeDomestic Mail ManualR900, S913, andS921for limitations of coverage oninured and COD mail. SeeInternational Mail Manualfor limitations o coverage on internationalmail. Special handling charges apply only to Standard Mail (A) and Standard Mail (B) parcels.FACSIMILIE OF PS Form 3877Mail Code 61-53IDEM Staff CDENNY 6/26/2012Indiana Gasification LLC 147-30464 -00060(final)AFFIX STAMPHERE IFUSED ASCERTIFICATEOF MAILINGName andaddress ofSender►Indiana Department of EnvironmentalManagementOffice of Air Quality – Permits Branch100 N. SenateIndianapolis, IN 46204Type of Mail:CERTIFICATE OFMAILING ONLYLine ArticleNumberName, Address, Street and Post Office Address Postage HandingChargesAct. Value(If Registered)InsuredValueDue Send ifCODR.R.FeeS.D. Fee S.H.FeeRest.Del. FeeRemarks1Angela PO Box 213 Santa Claus IN 47579 (Affected Party)2Marvin Byrer 2166 E Tennessee Evansville IN 47711(Affected Party)3James Lacy Kamuf 117 E 18th St PMB #125 Owensboro KY 42301(Affected Party)4Mickey Toler 1617 N CR 312 W Rockport IN 47635(Affected Party)5Harold Goffinet 426 Main St Rockport IN 47635(Affected Party)6Alton Goodwin 2368 N Silverdale Rd Rockport IN 47635(Affected Party)7Ferman Yearby 313 Elm St Rockport IN 47635(Affected Party)8Chuck Botsko 12540 N BaseRd Gentryville IN 47537(Affected Party)9Jean Dolezal 8401 E SR 70 Evanston IN 47531(Affected Party)10N Ryan Zaricki 1001 Oliver Rd N Wadesville IN 47638(Affected Party)11Wallace McMullen 12907 Sunnybrook Dr Prospect KY 40059(Affected Party)12Ben Taylor 419 Yel-G-View Rd Maceo KY 42355(Affected Party)13Thomas Pearce 223 E Ornsby Ave Louisville KY 40203 (Affected Party)14William Rosenberg 508 Queensferry Rd Gary NC 27511(Affected Party)15Joseph Begle 2340 E CR 1600 N Lincoln City IN 47552(Affected Party)Total number of piecesListed by SenderTotal number of PiecesReceived at Post OfficePostmaster, Per (Name ofReceiving employee)The full declaration of value is required on all domestic and international registered mail. Themaximum indemnity payable for the reconstruction of nonnegotiable documents under ExpressMail document reconstructing insurance is $50,000 perpiece subject to a limit of $50, 000 peroccurrence. The maximum indemnity payable onExpress mil merchandise insurance is $500.The maximum indemnity payable is $25,000 for registered mail, sent with optional postalinsurance. SeeDomestic Mail ManualR900, S913, andS921for limitations of coverage oninured and COD mail. SeeInternational Mail Manualfor limitations o coverage on internationalmail. Special handling charges apply only to Standard Mail (A) and Standard Mail (B) parcels.FACSIMILIE OF PS Form 3877Mail Code 61-53IDEM Staff CDENNY 6/26/2012Indiana Gasification LLC 147-30464 -00060(final)AFFIX STAMPHERE IFUSED ASCERTIFICATEOF MAILINGName andaddress ofSender►Indiana Department of EnvironmentalManagementOffice of Air Quality – Permits Branch100 N. SenateIndianapolis, IN 46204Type of Mail:CERTIFICATE OFMAILING ONLYLine ArticleNumberName, Address, Street and Post Office Address Postage HandingChargesAct. Value(If Registered)InsuredValueDue Send ifCODR.R.FeeS.D. Fee S.H.FeeRest.Del. FeeRemarks1Mark 11329 E SR 32 Zionsville IN 46077 (Affected Party)2Vicki Johnson 101 N 9th St Rockport IN 47635(Affected Party)3David Weber 6752 N 250 W Chrisney IN 47611(Affected Party)4Steve McNamara 332 S Second Rockport IN 47635(Affected Party)5Leslie Wiggins 5313 Old Boonville Hwy Evansville IN 47715(Affected Party)6Mark Osborne 5055 Jamestown Dr Newburgh IN 47630(Affected Party)7Becky Haaff 5341 W CR 200 S Rockport IN 47635(Affected Party)8Brandon Ferguson 1124 Ravenswood Dr Evansville IN 47714(Affected Party)9Tom Garrett 5313 Old Booneville Hwy Evansville IN 47715(Affected Party)10Beth Macke 4713 Housebridge Rd Corydon KY 42406(Affected Party)11Jim Werner 2646 N Burkhardt Rd Evansville IN 47715(Affected Party)12James Hunsicker 11686 US 231 S Dale IN 47523(Affected Party)13Paul Morsey 2437 Pleasant Valley Rd Owensboro KY 42303 (Affected Party)14William Bailey 841 South Rockport IN 47635(Affected Party)15Agnes Dilger 676 N Meadowland Dr Rockport IN 47635(Affected Party)Total number of piecesListed by SenderTotal number of PiecesReceived at Post OfficePostmaster, Per (Name ofReceiving employee)The full declaration of value is required on all domestic and international registered mail. Themaximum indemnity payable for the reconstruction of nonnegotiable documents under ExpressMail document reconstructing insurance is $50,000 perpiece subject to a limit of $50, 000 peroccurrence. The maximum indemnity payable onExpress mil merchandise insurance is $500.The maximum indemnity payable is $25,000 for registered mail, sent with optional postalinsurance. SeeDomestic Mail ManualR900, S913, andS921for limitations of coverage oninured and COD mail. SeeInternational Mail Manualfor limitations o coverage on internationalmail. Special handling charges apply only to Standard Mail (A) and Standard Mail (B) parcels.FACSIMILIE OF PS Form 3877Mail Code 61-53IDEM Staff CDENNY 6/26/2012Indiana Gasification LLC 147-30464 -00060(final)AFFIX STAMPHERE IFUSED ASCERTIFICATEOF MAILINGName andaddress ofSender►Indiana Department of EnvironmentalManagementOffice of Air Quality – Permits Branch100 N. SenateIndianapolis, IN 46204Type of Mail:CERTIFICATE OFMAILING ONLYLine ArticleNumberName, Address, Street and Post Office Address Postage HandingChargesAct. Value(If Registered)InsuredValueDue Send ifCODR.R.FeeS.D. Fee S.H.FeeRest.Del. FeeRemarks1John 6830 Roosevelt Ave Franklin OH 45005 (Affected Party)2David Boggs 216 Western Hills Dr Mt Vernon IN 47620(Affected Party)3456789101112131415Total number of piecesListed by SenderTotal number of PiecesReceived at Post OfficePostmaster, Per (Name ofReceiving employee)The full declaration of value is required on all domestic and international registered mail. Themaximum indemnity payable for the reconstruction of nonnegotiable documents under ExpressMail document reconstructing insurance is $50,000 perpiece subject to a limit of $50, 000 peroccurrence. The maximum indemnity payable onExpress mil merchandise insurance is $500.The maximum indemnity payable is $25,000 for registered mail, sent with optional postalinsurance. SeeDomestic Mail ManualR900, S913, andS921for limitations of coverage oninured and COD mail. SeeInternational Mail Manualfor limitations o coverage on internationalmail. Special handling charges apply only to Standard Mail (A) and Standard Mail (B) parcels.