adeq operating air permit€¦ · adeq operating air permit transfer of permit effective june 14,...

ADEQOPERATINGAIR PERMIT

Transfer of Permit Effective June 14, 2002

Pursuant to the Regulations of the Arkansas Operating Air Permit Program, Regulation #26:

Permit #: 1002-AOP-R0

IS ISSUED TO:

Enbridge Gathering (Texarkana) L.L.C.Texarkana Gas Processing Plant

Highway 237, South of TexarkanaTexarkana, AR 75502

Miller CountyCSN: 46-0133

THIS PERMIT AUTHORIZES THE ABOVE REFERENCED PERMITTEE TO INSTALL,OPERATE, AND MAINTAIN THE EQUIPMENT AND EMISSION UNITS DESCRIBED INTHE PERMIT APPLICATION AND ON THE FOLLOWING PAGES. THIS PERMIT ISVALID BETWEEN:

February 11, 2000 and February 10, 2005

AND IS SUBJECT TO ALL LIMITS AND CONDITIONS CONTAINED HEREIN.

Signed:

Keith A. Michaels Date Modified

2

SECTION I: FACILITY INFORMATION

PERMITTEE: Enbridge Gathering (Texarkana)L.L.C.

Texarkana Gas Processing PlantCSN: 46-0133PERMIT NUMBER: 1002-AOP-R0

FACILITY ADDRESS: Highway 237, South of TexarkanaTexarkana, AR 75502

COUNTY: Miller

CONTACT POSITION: Ray BetheaTELEPHONE NUMBER: (870) 653-2556

REVIEWING ENGINEER: Melissa J. Blumenthal

UTM North-South (X): 3687.8UTM East-West (Y): 406.5

Sulfur River Gathering LP -- Texarkana Gas Processing PlantPermit #: 1002-AOP-R0CSN #: 46-0133

3Page Amended

SECTION II: INTRODUCTION

The Texarkana Gas Plant is a sour gas processing plant which produces elemental sulfur, natural gasliquids (NGLs), residue gas, and sweet, dry sales gas. The plant is currently permitted to processa maximum of 27 million standard cubic feet per day (Mmscfd) of inlet gas and produce a maximumof 32 long tons per day (LTPD) of liquid sulfur.

The Texarkana Gas Plant is subject to regulation under Regulation #18 (Air Code), Regulation #19(SIP), Regulation #26 (Title V), Prevention of Significant Deterioration (PSD), and the followingNew Source Performance Standards (NSPS):

• Subpart Dc – Standards of Performance for Small Industrial-Commercial-Institutional SteamGenerating Units

• Subpart KKK – Standards of Performance for Equipment Leaks of VOC from OnshoreNatural Gas Processing Plant

• Subpart LLL – Standards of Performance for Onshore Natural Gas Processing: SO2Emissions

Process Description

This plant processes natural gas produced from existing wells which produce sour gas. The inletgas has varying amounts of H2S and CO2. The sweet, dry sales gas from the plant has an H2Scontent of less than one ppmv and a CO2 content of less than 44 ppmv. Therefore, essentially allof the H2S and CO2 is removed from the gas in the facility.

To remove H2S and CO2, the inlet gas is passed through two consecutive amine contact towerswhere it flows counter-current to liquid amine solutions. The amine solution in the first aminecontactor selectively absorbs nearly all of the H2S and part of the CO2 from the gas. This initialtreating step affords a lower acid gas CO2/H2S ratio for enhanced sulfur recovery. Gas exits the firstamine contactor and flows directly into a second amine contactor. The second amine solutionabsorbs the remaining CO2 and residual H2S that “slipped” from the first contactor. Sweet gas exitsthe second amine contactor and flows to the dehydration unit where molecular sieve beds are usedto absorb almost all of the water vapor. The gas leaving the molecular sieve unit is sweet, dry gassuitable for cryogenic processing. The amine unit flash vent releases are captured and returned tothe inlet vapor recovery unit (VRU).

The “rich” liquid amine leaving the first contactor contains absorbed H2S and CO2. It flows to aregenerator tower, where, at low pressure and elevated temperature, the acid gases (H2S and CO2)are liberated from the amine. The “lean” regenerated amine solution then is recirculated to the first


4

amine contactor. The acid gas flows to the sulfur recovery unit (SRU) for the conversion of H2S toelemental sulfur.

The “rich” liquid amine leaving the second contactor contains mainly absorbed CO2 and a very smallamount of H2S. It flows to a second regeneration tower, where, at low pressure and elevatedtemperature, the CO2 and minute amounts of H2S are liberated from the amine. This resulting gasstream, consisting of CO2, water vapor and only trace amounts of H2S, is fed directly into theincinerator along with tail gas from the sulfur recovery unit.

Approximately 0.5 % of the sulfur entering the gas plant will bypass the sulfur recovery unit viastreams which are not suitable for processing by the sulfur recovery unit. They include:

1. The No. 2 amine unit regenerator vent is transferred to the thermal incinerator. This streamcontains approximately 99.99 vol. % CO2 and only 0.01 vol. % H2S. This stream wouldsignificantly increase the volume of acid gas feed to the SRU, but only about 3.0 pounds perhour of H2S would be available for conversion to SO2. The presence of the additional CO2would shift equilibrium in the SRU so that overall recovery would decrease.

2. The inlet condensate flash vapor is recovered using the VRU. Small quantities of H2S areestimated to be less than 1 pound per occurrence and sent to the plant flare upondepressurization of the inlet pig receiver. This activity occurs no more than once every twodays.

Sulfur Recovery: Acid gas from the amine regeneration equipment is fed to the acid gas furnace.In the acid gas furnace, one third of the H2S is oxidized to sulfur dioxide by combustion. The SO2and H2S react to produce elemental sulfur.

The acid gas stream exiting the acid gas furnace is cooled to approximately 375EF. This allows thesulfur formed in the acid gas furnace to condense. The molten sulfur is separated from the acid gasand sent to storage. The remaining acid gas mixture is heated to approximately 500EF and fed tothe first Claus Converter. In the Claus Converter the reaction between unreacted H2S and SO2 isenhanced by the Claus catalyst. The sulfur formed in the first Claus Converter is condensed and thesulfur is separated from the acid gas. This process of heating and cooling is repeated through eachof two remaining Claus Converters.

In the Shell Claus Off-gas Treatment (SCOT) unit the un-reacted SO2 exiting the third Claus reactoris reacted with hydrogen over a catalyst to form H2S. The cool acid gas stream is then contactedwith amine to remove H 2S. The residual acid gas exiting the SCOT Contactor is fed to theincinerator where the remaining residual sulfur compounds are oxidized to SO2. The gas is then


5

emitted to the atmosphere via a stack. The liquid elemental sulfur is collected and sold. The H2S isstripped from the amine solution and recycled to the Acid Gas Furnace.

The amine regeneration unit used in the SCOT process will be used to regenerate the rich amineused to treat the feed gas. The amine solution discharged from the SCOT contactor will be used toabsorb a portion of the acid gas contained in the feed.

Gas Processing for Liquids Recovery and Nitrogen Rejection: Dehydrated, treated gas flows fromthe molecular sieve bed to the Nitrogen Rejection Unit/Natural Gas Liquids (NRU/NGL) facilityfor gas processing. In this section of the plant, cryogenic expansion significantly reduces thetemperature of the composite gas stream. Gases with different boiling points are separated as thehydrocarbon gases condense. Heavier hydrocarbons liquify first and are recovered as natural gasliquids (NGL) and sold.

The final stages of processing separate nitrogen and what remains of the hydrocarbon gas (mainlymethane and ethane). After passing through inlet gas exchangers, nitrogen gas is vented to theatmosphere along with a small amount (approximately 1.7 vol. %) of methane, and the remaininghydrocarbon gas is re-vaporized, compressed to pipeline pressure and sold as residue gas.

Combustion Units: There are currently eight combustion units at this facility. They are all fired bya fuel gas stream which is a split-stream off sweet sales gas. The total fuel load at maximum designrates will be approximately 48.7 million Btu per hour, requiring about 51,300 standard cubic feet(Scf) per hour of fuel (fuel gas contains 949 Btu/Scf). The fuel gas for all nine combustion units issweet, pipeline quality natural gas. For startup, sweet pipeline quality gas is purchased from anearby interstate pipeline.

A brief description of each combustion unit is given below:

1. The thermal incinerator oxidizes the remaining H2S, sulfur vapor, and other sulfurcompounds in the SRU tail gas to SO2 prior to emitting the gas to the atmosphere. Theincinerator vent stack has two sample ports for flow measurement and gas sampling. Also,a continuous SO2 analyzer is installed on the incinerator vent stack.

2. The boilers provide supplemental steam (in addition to that generated by the ConventionalThree Bed Claus Plant with SCOT Tail Gas Treating sulfur condensers) needed to regenerateamines.

3. The regeneration gas heater heats a split stream of residue gas for warming the molecularsieve dehydration beds to 600°F for sieve regeneration.


6Page Amended

4. The compressor-drive engines (three units) provide mechanical power to drive twoconventional reciprocating gas compressors which boost pressure of residue gas up torequired sales (pipeline) pressure as well as a third compressor to recycle low pressurevapors to inlet.

5. The flare stack is for emergency use only and remains burning continuously with 200 scf perhour fuel gas “purge” (pilot) stream. This stack provides a ready means of handling plantupsets by temporarily burning full well stream gas, “off-spec” residue gas or acid gas toensure full conversion to SO2 prior to release to atmosphere. The use of the flare isminimized, and natural gas wells are shut down when prolonged upsets occur. Maximumduration of any flaring event should not exceed 2 hours under normal circumstances.

Permit #1002-AOP-R0 is the first operating permit issued to the Texarkana Gas Plant underRegulation #26. No physical modifications occurred with the issuance of this permit. The followingtable is a summary of emissions from the facility. Specific conditions and emissions for each sourcecan be found starting on the page cross referenced in the table.

EMISSION SUMMARY

SourceNo.

Description Pollutant Emission Rates CrossReference

Pagelb/hr ton/yr

Total Allowable Emissions PMPM10SO2

VOCCONOx

AcroleinFormaldehyde

Methanol

0.60.6

47.23.8

22.520.50.141.840.09

2.62.6

205.715.698.589.10.588.000.33

n/a

01 Waukesha 7042 GLCompressor Engine

VOCCONOx


Methanol

0.18.05.4

0.070.760.04

0.235.223.50.293.300.15

12


EMISSION SUMMARY

SourceNo.

Description Pollutant Emission Rates CrossReference

Pagelb/hr ton/yr

7Page Amended

02 Waukesha 7042 GLCompressor Engine

VOCCONOx


Methanol

0.18.05.4

0.070.760.04

0.235.223.50.293.300.15

14

04 Steam Boiler PMPM10SO2

VOCCONOx

0.30.30.10.20.83.0

1.31.30.10.63.3

12.9

16

06 Process VOC Fugitive VOC 2.9 12.6 18

07 Caterpillar 3306 NA Engine VOCCONOx

FormaldehydeMethanol

0.31.00.5

0.320.01

1.44.42.2

1.400.03

19

09 Emergency Flare see Specific Condition #21 21

10 SRU and SCOT Unit TailGas Incinerator

SO2CONOx

47.03.93.2

205.517.114.1

22

11 Steam Boiler PMPM10SO2

VOCCONOx

0.30.30.10.20.83.0

1.31.30.10.63.3

12.9

24

12 Secondary Condensate Tank Source Reclassified as Insignificant Activity


8

SECTION III: PERMIT HISTORY

On May 18, 1990, the Department issued Permit #1002-A to NGC Energy, Inc. (NGCEI). As a partof this permit, NGCEI was required to undergo a Prevention of Significant Deterioration review forSO2 and NOx. This permit allowed NGCEI to construct and operate a gas sweetening plant. Thisplant was permitted to process 18 million standard cubic feet per day of sour gas containing up to12.56 long tons per day of sulfur.

In 1990, before plant construction was complete and the plant was started, an application wassubmitted to increase throughput to 27 million standard cubic feet per day. Permit #1002-AR-1 wasissued on November 27, 1990, and the plant startup commenced in December 1990. The plant wasin full operation by mid-1990.

In 1992, NGC Energy Resources, Limited Partnership (NER) applied for and received permissionto make a minor modification. NER installed a vapor recovery compressor to reduce incidentalflaring of sour gas from the plant (due to pigging operations) and to eliminate sour flaring fromCarter Resources Day’s Creek Unit adjacent to the plant. This compressor commenced operationin early 1993. A formal revision of Permit #1002-AR-1 was not required.

In late 1993, NER applied for and received permission to make another minor modification. NERinstalled a diglyocolamine (DGA) reclaimer. This unit was installed in early 1994. A formalrevision of Permit #1002-AR-1 was not required.

On April 18, 1994, the Department issued Permit #1002-AR-2 to NER. The purpose of this permitrevision was to increase the permitted sulfur throughput to 16 long tons per day. In conjunction,NER proposed to install an additional converter in the sulfur recovery unit in order to minimize theincrease in SO2 emissions resulting from the increased throughput. The purpose of the converterwas also to eliminate switching peaks which contributed to two violations of the incinerator CEMstandard since operations began in 1991. In unrelated matters, NER also requested a modificationto the compressor engine monitoring requirements and for a modified procedure for controlling SO2emissions from the emergency flare.

On September 15, 1998, the Department issued Permit #1002-AR-3 to Warren Energy Resources,Limited Partnership (WER). This permit was issued as a part of a Permit Appeal Resolution (LISNo. 96-071). WER proposed to replace the current Sulfur Recovery Unit with a new SulfurRecovery Unit. A Shell Claus Off-gas Treatment system would also be added to the new SulfurRecovery Unit. The new Sulfur Recovery Unit and Shell Claus Off-gas Treatment system wouldbe routed to the same tail gas incinerator (SN-10) as the current Sulfur Recovery Unit. Along with


9

the Sulfur Recovery Unit modification, WER proposed to increase the sulfur production of thefacility to 32.0 long tons per day. The modifications allowed by this permit have not begun yet. Thefacility has 18 months after permit issuance to commence construction.


10

SECTION IV: EMISSION UNIT INFORMATION


11

SN-01Waukesha 7042 GL Compressor Engine

Source Description

The Waukesha 7042 GL Compressor Engine (SN-01) has a rated capacity of 1215 horsepower (hp,@1000 rpm). The compressor engine is not equipped with any control equipment. The compressorengine compresses dry sales gas to the appropriate pipeline pressure.

Specific Conditions

1. Pursuant to §19.501 et seq and §19.901 et seq of the Regulations of the Arkansas Plan ofImplementation for Air Pollution Control (Regulation #19) effective February 15, 1999, and40 CFR Part 52 Subpart E, the permittee shall not exceed the emission rates set forth in thefollowing table. The emission rates are based on using natural gas and the maximumoperating capacity of the equipment.

Pollutant lb/hr ton/yr

NOX 5.4 23.5

2. Pursuant to §19.501 et seq of Regulation #19 and 40 CFR Part 52 Subpart E, the permitteeshall not exceed the emission rates set forth in the following table. The emission rates arebased on using natural gas and the maximum operating capacity of the equipment.


VOC 0.1 0.2

CO 8.0 35.2

3. Pursuant to §18.801 of the Arkansas Air Pollution Control Code (Regulation #18) effectiveFebruary 15, 1999, and A.C.A. §8-4-203 as referenced by §8-4-304 and §8-4-311, thepermittee shall not exceed the emission rates set forth in the following table. The emissionrates are based on using natural gas and the maximum operating capacity of the equipment.


Acrolein 0.07 0.29

Formaldehyde 0.76 3.30



12

Methanol 0.04 0.15

4. Pursuant to §18.501 of Regulation #18, and A.C.A. §8-4-203 as referenced by §8-4-304 and§8-4-311, the permittee shall not exceed 5% opacity from source SN-01 as measured by EPAReference Method 9. Compliance with this condition shall be demonstrated by burningnatural gas.


13

SN-02Waukesha 7042 GL Compressor Engine

Source Description

The Waukesha 7042 GL Compressor Engine (SN-02) has a rated capacity of 1215 horsepower (hp,@1000 rpm). The compressor engine is not equipped with any control equipment. The compressorengine compresses dry sales gas to the appropriate pipeline pressure.

Specific Conditions

5. Pursuant to §19.501 et seq and §19.901 et seq of Regulation #19, and 40 CFR Part 52Subpart E, the permittee shall not exceed the emission rates set forth in the following table.The emission rates are based on using natural gas and the maximum operating capacity ofthe equipment.


NOX 5.4 23.5



VOC 0.1 0.2

CO 8.0 35.2

7. Pursuant to §18.801 of Regulation #18, and A.C.A. §8-4-203 as referenced by §8-4-304 and§8-4-311, the permittee shall not exceed the emission rates set forth in the following table.The emission rates are based on using natural gas and the maximum operating capacity ofthe equipment.


Acrolein 0.07 0.29


Methanol 0.04 0.15


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15

SN-04Steam Boiler

Source Description

The heat input capacity of the Steam Boiler (SN-04) is 21 MMBtu/hr. The boiler is not equippedwith any control equipment. The boiler is subject to NSPS Subpart Dc.

Specific Conditions



PM10 0.3 1.3

SO2 0.1 0.1

VOC 0.2 0.6

CO 0.8 3.3

NOx 3.0 12.9

10. Pursuant to §18.801 of Regulation #18 and A.C.A. §8-4-203 as referenced by §8-4-304 and§8-4-311, the permittee shall not exceed the emission rates set forth in the following table.The emission rates are based on using natural gas and the maximum operating capacity ofthe equipment.


PM 0.3 1.3


12. The Steam Boiler (SN-04) is subject to and shall comply with applicable provisions of 40CFR Part 60 Subpart A – General Provisions and 40 CFR Part 60 Subpart Dc – New Source


16

Performance Standards for Industrial-Commercial-Institutional Steam Generating Units. Acopy of Subpart Dc is provided in Appendix A. Applicable provisions of Subpart Dcinclude, but are not limited to, the following:

1. Pursuant to 40 CFR §60.48c(a), the owner or operator of each affected facility shallsubmit notification of the date of construction or reconstruction, anticipated startup,and actual startup, as provided by 40 CFR §60.7.

2. Pursuant to 40 CFR §60.48c(g), the owner or operator of each affected facility shallrecord and maintain records of the amounts of each fuel combusted during each day.


17

SN-06Process VOC Fugitive

Source Description

This source accounts for potential equipment leaks. The facility is divided into nine separate processareas which may come into contact with one of three process stream types: inlet gas, LPG product,and residue gas. This source is subject to NSPS Subpart KKK.

Specific Conditions

13. Pursuant to §19.501 et seq of Regulation #19 and 40 CFR Part 52 Subpart E, the permitteeshall not exceed the emission rates set forth in the following table. The pound per hour ratesare based on a 1995 equipment leak detection test. The ton per year rates are based onoperating at maximum capacity.


VOC 2.9 12.6

14. The Process VOC Fugitives (SN-06) is subject to and shall comply with applicableprovisions of 40 CFR Part 60 Subpart A – General Provisions and 40 CFR Part 60 SubpartKKK – Standards of Performance for Equipment Leaks of VOC from Onshore Natural GasProcessing Plants. A copy of Subpart KKK is provided in Appendix D. For specificprovisions of this subpart, please see Plantwide Condition #17.


18

SN-07Caterpillar 3306 NA Engine

Source Description

The Caterpillar 3306 NA Engine (SN-07) has a rated capacity of 145 horsepower (hp). Thecompressor engine is equipped with a catalytic converter. The compressor engine compresses drysales gas to the appropriate pipeline pressure.

Specific Conditions

15. Pursuant to §19.501 et seq and §19.901 et seq of Regulation #19, and 40 CFR Part 52Subpart E, the permittee shall not exceed the emission rates set forth in the following table.The emission rates are based on using natural gas and the maximum operating capacity ofthe equipment.


NOX 0.5 2.2



VOC 0.3 1.4

CO 1.0 4.4

17. Pursuant to §18.801 of Regulation #18, and A.C.A. §8-4-203 as referenced by §8-4-304 and§8-4-311, the permittee shall not exceed the emission rates set forth in the following table.The emission rates are based on using natural gas and the maximum operating capacity ofthe equipment.



Methanol 0.01 0.03


19



20

SN-09Emergency Flare

Source Description

The Emergency Flare will be operated as needed subject to the following conditions.

Specific Conditions

19. Pursuant to §19.501 et seq of Regulation #19 and 40 CFR Part 52 Subpart E, the cumulativetotal of all SO2 emissions from the emergency flare shall not exceed 9.75 short tons duringany quarter (3 month period). This will limit emissions to levels below the significantincreases defined in 40 CFR §52.21(b)(23)(i).

20. Pursuant to §19.705 of Regulation #19, 40 CFR Part 52 Subpart E, and A.C.A. §8-4-203 asreferenced by §8-4-304 and §8-4-311, the permittee shall maintain records whichdemonstrate compliance with the limit listed in Specific Condition #21. The records shallbe updated on a monthly basis. These records shall be kept on site, provided to Departmentpersonnel upon request, and may be used by the Department for enforcement purposes.

21. The Emergency Flare (SN-09) is subject to and shall comply with applicable provisions of40 CFR §60.18. A copy of 40 CFR §60.18 is included in Appendix B. Applicableprovisions of 40 CFR §60.18 include, but are not limited to, the following:

1. Pursuant to 40 CFR §60.18(c)(1), flares shall be designed for and operated with novisible emissions as determined by EPA Reference Method 22, except for periods notto exceed a total of 5 minutes during any 2 consecutive hours.

2. Pursuant to 40 CFR §60.18(c)(2), flares shall be operated with a flame present at alltimes. The presence of a flare pilot flame shall be monitored using a thermocoupleor any other equivalent device to detect the presence of a flame.

3. Pursuant to 40 CFR §60.18(c)(3), flares shall be used only with the net heating valueof the gas being combusted being 300 Btu/scf or greater if the flare is steam-assistedor air-assisted; or with the net heating value of the gas being combusted being 200Btu/scf or greater if the flare is non-assisted. The net heating value of the gas beingcombusted shall be determined by the methods specified in 40 CFR §60.18(f).

SN-10Sulfur Recovery Unit (SRU) & SCOT Unit Tail Gas Incinerator


21

Source Description

The sulfur recovery plant recovers elemental sulfur from the acid gas stream processed in thesweetening unit. Tail gas from the sulfur recovery unit is sent to an incinerator and oxidized beforebeing discharged to the atmosphere. The source is subject to NSPS Subpart LLL.

Specific Conditions

22. Pursuant to §19.501 et seq and §19.901 et seq of Regulation #19, and 40 CFR Part 52Subpart E, once the new SRU is ready for operation, the permittee shall not exceed theemission rates set forth in the following table. The emission rates are based on operating atmaximum capacity. The SO2 emissions will be verified using a SO2 CEM.


SO2 47.0 205.5

NOX 3.2 14.1

23. Pursuant to §19.501 et seq of Regulation #19 and 40 CFR Part 52 Subpart E, once the newSRU is ready for operation, the permittee shall not exceed the emission rates set forth in thefollowing table. The emission rates are based on using natural gas and the maximumoperating capacity of the equipment.


CO 3.9 17.1

24. The Sulfur Recovery Unit (SRU) & SCOT Unit Tail Gas Incinerator are subject to and shallcomply with applicable provisions of 40 CFR Part 60 Subpart A – General Provisions and40 CFR Part 60 Subpart LLL – Standards of Performance for Onshore Natural GasProcessing: SO2 Emissions. A copy of Subpart LLL is provided in Appendix E. For specificprovisions of this subpart, please see Plantwide Condition #18.

25. Pursuant to §19.501 et seq of Regulation #19, 40 CFR Part 52 Subpart E, and A.C.A.§8-4-203 as referenced by §8-4-304 and §8-4-311, until the new Conventional Three BedClaus Plant SRU and SCOT Tail Gas Treating unit are constructed, installed and ready foroperation, the facility shall continue to operate the existing MCRC SRU at the permittedrates found in Permit #1002-AR-2. Sulfur dioxide emissions shall not exceed 74.5 poundsper hour for the first five hours after switching, 65.56 pounds per hour for the next nineteenhours and 295.3 tons per twelve consecutive months. Carbon monoxide emissions shall not


22

exceed 5.9 pounds per hour and 25.7 tons per twelve consecutive months. Nitrogen oxideemissions shall not exceed 1.9 pounds per hour and 8.2 tons per twelve consecutive months.Once the new SRU is ready for operation, the existing SRU shall be taken out of service.

26. Pursuant to §19.703 of Regulation #19, 40 CFR Part 52 Subpart E, A.C.A. §8-4-203 asreferenced by §8-4-304 and §8-4-311, and 40 CFR Part 60 Subpart LLL, the permittee shallmaintain a CEM for SO2 on SN-10 (the Tailgas Incinerator). This CEMS shall be operatedin accordance with the Department’s Continuous Emission Monitoring System Conditions.A copy of the Department’s Continuous Emission Monitoring System Conditions is providedin Appendix G.

27. Pursuant to §19.702 of Regulation #19 and 40 CFR Part 52 Subpart E, compliance testingfor NOx and CO shall be performed, using approved EPA testing methods, at the time ofcompliance testing for SO2 after the SRU and SCOT system installations are complete.Testing shall be conducted in accordance with Plantwide Condition #3.

28. Pursuant to §19.501 et seq of Regulation #19 and 40 CFR Part 52 Subpart E, the permitteeshall calculate a daily total of SO2 emissions from SN-10 (the Tailgas Incinerator). Tocalculate the daily total, the permittee shall determine an average emission rate during eachhour and then sum the hourly averages for the 24 hour period. SO2 emissions during anycontiguous 24 hour period shall not exceed 1126 pounds.


23

SN-11Steam Boiler

Source Description

The heat input capacity of the Steam Boiler (SN-04) is 21 MMBtu/hr. The boiler is not equippedwith any control equipment. The boiler is subject to NSPS Subpart Dc.

Specific Conditions



PM10 0.3 1.3

SO2 0.1 0.1

VOC 0.2 0.6

CO 0.8 3.3

NOx 3.0 12.9

30. Pursuant to §18.801 of Regulation #18 and A.C.A. §8-4-203 as referenced by §8-4-304 and§8-4-311, the permittee shall not exceed the emission rates set forth in the following table.The emission rates are based on using natural gas and the maximum operating capacity ofthe equipment.


PM 0.3 1.3


32. The Steam Boiler (SN-11) is subject to and shall comply with applicable provisions of 40CFR Part 60 Subpart A – General Provisions and 40 CFR Part 60 Subpart Dc – New Source


24

Performance Standards for Industrial-Commercial-Institutional Steam Generating Units. Acopy of Subpart Dc is provided in Appendix A. Applicable provisions of Subpart Dcinclude, but are not limited to, the following:

1. Pursuant to 40 CFR §60.48c(a), the owner or operator of each affected facility shallsubmit notification of the date of construction or reconstruction, anticipated startup,and actual startup, as provided by 40 CFR §60.7.

2. Pursuant to 40 CFR §60.48c(g), the owner or operator of each affected facility shallrecord and maintain records of the amounts of each fuel combusted during each day.

33. Pursuant to §19.702 of Regulation #19 and 40 CFR Part 52 Subpart E, the permittee shallperform stack testing of SN-11 for carbon monoxide and nitrogen oxides emissions. Testingfor carbon monoxide and nitrogen oxides emission shall be performed in accordance withPlantwide Condition #3 and EPA Reference Methods 10 and 7E respectively as found in 40CFR Part 60 Appendix A.


25

SECTION V: COMPLIANCE PLAN AND SCHEDULE

Texarkana Gas Plant is in compliance with the applicable regulations cited in the permit application.Texarkana Gas Plant will continue to operate in compliance with those identified regulatoryprovisions. The facility will examine and analyze future regulations that may apply and determinetheir applicability with any necessary action taken on a timely basis.


26

SECTION VI: PLANTWIDE CONDITIONS

1. Pursuant to §19.704 of Regulation 19, 40 CFR Part 52, Subpart E, and A.C.A. §8-4-203 asreferenced by §8-4-304 and §8-4-311, the Director shall be notified in writing within thirty(30) days after construction has commenced, construction is complete, the equipment and/orfacility is first placed in operation, and the equipment and/or facility first reaches the targetproduction rate.

2. Pursuant to §19.410(B) of Regulation 19, 40 CFR Part 52, Subpart E, the Director maycancel all or part of this permit if the construction or modification authorized herein is notbegun within 18 months from the date of the permit issuance if the work involved in theconstruction or modification is suspended for a total of 18 months or more.

3. Pursuant to §19.702 of Regulation 19 and/or §18.1002 of Regulation 18 and A.C.A.§8-4-203 as referenced by A.C.A. §8-4-304 and §8-4-311, any equipment that is to be tested,unless stated in the Specific Conditions of this permit or by any federally regulatedrequirements, shall be tested with the following time frames: (1) Equipment to beconstructed or modified shall be tested within sixty (60) days of achieving the maximumproduction rate, but in no event later than 180 days after initial start-up of the permittedsource or (2) equipment already operating shall be tested according to the time frames setforth by the Department. The permittee shall notify the Department of the scheduled dateof compliance testing at least fifteen (15) days in advance of such test. Compliance testresults shall be submitted to the Department within thirty (30) days after the completedtesting.

4. Pursuant to §19.702 of Regulation 19 and/or §18.1002 of Regulation 18 and A.C.A.§8-4-203 as referenced by A.C.A. §8-4-304 and §8-4-311, the permittee shall provide:

1. Sampling ports adequate for applicable test methods2. Safe sampling platforms 3. Safe access to sampling platforms4. Utilities for sampling and testing equipment

5. Pursuant to §19.303 of Regulation 19 and A.C.A. §8-4-203 as referenced by A.C. A. §8-4-304 and §8-4-311, the equipment, control apparatus and emission monitoring equipmentshall be operated within their design limitations and maintained in good condition at alltimes.

6. Pursuant to Regulation 26 and A.C.A. §8-4-203 as referenced by §8-4-304 and §8-4-311,this permit subsumes and incorporates all previously issued air permits for this facility.


27

7. Pursuant to 19.705 of Regulation 19, A.C.A. §8-4-203 as referenced by A.C.A. §8-4-304 and§8-4-311 and 40 CFR 70.6, pipeline quality natural gas shall be the only fuel used to fire theeight combustion units at this facility.

8. Pursuant to A.C.A. §8-4-203 as referenced by §8-4-304 and §8-4-311, the facility shallupdate the contingency plan submitted for permit #1002-AR-1 as needed.

9. Pursuant to A.C.A. §8-4-203 as referenced by §8-4-304 and §8-4-311, within 60 days aftercompletion of each operating year, the permittee shall submit to the Department an engineperformance report comparing measured performance throughput of the year with the enginemanufacturer’s performance predictions. This report shall be sent to the address given inGeneral Provision #7. The start of the operating year will be documented by compliancewith Plantwide Condition #1, notification of the facility first being placed in operation.

Permit #1002-AR-2 and Permit #1002-AR-3

10. Pursuant to §19.410(B) of Regulation #19 and 40 CFR Part 52 Subpart E, the permittee has18 months from the date of issuance (September 18, 1998) of Permit #1002-AR-3 to makethe modifications allowed by that permit. In the event that the modifications do not takeplace, the permittee shall modify this permit accordingly.

SN-01 and SN-02

11. Pursuant to §19.702 and §19.703 of Regulation #19 , 40 CFR Part 52 Subpart E, and A.C.A.§8-4-203 as referenced by §8-4-304 and §8-4-311, the permittee shall perform a full loademissions test for NOx and CO on SN-01 and SN-02. This testing shall be performed inconjunction with the Sulfur Recovery Unit (SRU) modification compliance test required bySpecific Condition #29. The testing of SN-01 and SN-02 does not have to be simultaneouswith the testing of the SRU. The purpose of this test shall be to benchmark the performanceof the DAI Systems 6000 combustion analyzer against data collected by an approved testingcompany using an approved EPA test method.

The permittee shall thereafter monitor oxygen, NOx, and CO concentrations in the exhaustfrom SN-01 and SN-02 at least weekly using the combustion analyzer. Measurements shallbe taken and recorded on each bank of power cylinders, and engine adjustments shall bemade as required to restore acceptable concentrations as determined in the initial emissionstest.


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The permittee shall maintain the operations data at the plant for annual review by aDepartment inspector. Within 60 days after the end of each calendar year, the permitteeshall submit a report transmitting the recorded data and discussing the compliance record ofeach engine for the previous year. Upon receipt and review of the report, the Departmentshall determine whether or not compliance testing will be required for the next year inaddition to continued monitoring with the combustion analyzer.

Where deviation exists between actual and expected performance of such magnitude that theDepartment feels corrective actions should be taken, the permittee shall submit a plan whichhas been reviewed by the engine manufacturer to reduce or eliminate the deviations.

This plan shall be submitted within 90 days of the request of the Department, and shall becarried out within 60 days of the Department’s written approval of the plan.

Use of a combustion analyzer other than the DAI Systems 6000 will require permission ofthe Department.

Continuous Emission Monitoring Systems (CEMS)

12. Pursuant to §19.703 of Regulation #19, 40 CFR Part 52 Subpart E, and A.C.A. §8-4-203 asreferenced by §8-4-304 and §8-4-311, all CEMS shall be operated in accordance with theDepartment’s Continuous Emission Monitoring System Conditions. A copy of theDepartment’s Continuous Emission Monitoring System Conditions is provided inAppendix G.

13. Pursuant to §19.703 of Regulation #19, 40 CFR Part 52 Subpart E, and A.C.A. §8-4-203 asreferenced by §8-4-304 and §8-4-311, the facility shall notify the Department of any CEMupgrade or replacement.

Reporting and Recordkeeping

14. Pursuant to §19.705 of Regulation #19, A.C.A. §8-4-203 as referenced by §8-4-304 and§8-4-311, and 40 CFR §70.6, the facility shall not process more than 27 million standardcubic feet per day (MMSCFD) of sour natural gas. This is a maximum figure, not a twentyfour hour average.

15. Pursuant to §19.705 of Regulation #19, A.C.A. §8-4-203 as referenced by §8-4-304 and§8-4-311, and 40 CFR §70.6, once the modifications allowed by Permit #1002-AR-3 havebeen made, the facility shall be limited to 32.00 long tons per day (LTPD) of sulfur in theacid gas. This is a maximum figure, not a twenty four hour average.


29

Before the modifications allowed by Permit #1002-AR-3 have been made, the facility shallbe limited to 16.00 LTPD of sulfur in the acid gas. This is a maximum figure, not a twentyfour hour average.

16. Pursuant to §19.705 of Regulation #19 and 40 CFR Part 52 Subpart E, the permittee shallmaintain records which demonstrate compliance with the limits set in Plantwide Conditions#14 and #15. These records may be used by the Department for enforcement purposes. Therecords shall be updated on a daily basis, shall be kept on site, and shall be provided toDepartment personnel upon request. An annual total and each individual month’s data shallbe submitted in accordance with General Provision 7.

Regulations

17. The Texarkana Gas Plant is subject to and shall comply with applicable provisions of 40CFR Part 60 Subpart A – General Provisions and 40 CFR Part 60 Subpart KKK – Standardsof Performance for Equipment Leaks of VOC from Onshore Natural Gas Processing Plants.A copy of Subpart KKK is provided in Appendix D. Applicable provision of Subpart KKKinclude, but are not limited to, the following:

A. The Texarkana Gas Plant shall comply with the leak detection and repair standardsin 40 CFR §60.482-1(a), (b), and (d) and 40 CFR §60.482-2 through 40 CFR§60.482-10 for pumps, compressors, pressure relief devices, sampling connections,open-ended lines, valves, and closed vent systems (considering exceptions in 40 CFR§60.633).

B. The Texarkana Gas Plant shall comply with the recordkeeping requirements of 40CFR §60.635.

C. The owner/operator of the Texarkana Gas Plant must submit semiannual reports asrequired in 40 CFR §60.636.

18. The Texarkana Gas Plant is subject to and shall comply with applicable provisions of 40CFR Part 60 Subpart A – General Provisions and 40 CFR Part 60 Subpart LLL – Standardsof Performance for Onshore Natural Gas Processing: SO2 Emissions. A copy of SubpartLLL is provided in Appendix E. Applicable provision of Subpart LLL include, but are notlimited to, the following:

A. Records of calculations and measurements required must be retained for at least twoyears following the date of the measurements.


30

B. Each owner/operator shall semiannually submit a written report of excess emissions,defined as when average temperatures are less than the appropriate operatingtemperature during a 24 hour period and any 24 hour period where the average sulfuremissions reduction efficiency (R) is less than the minimum required reductionefficiency (Z).

C. The facility shall conduct initial performance tests which demonstrate the emissionreduction efficiency achieved by the sulfur recovery technology is greater than theminimum required sulfur dioxide emission reduction efficiency.

D. The facility shall achieve an SO2 emission reduction efficiency as determined by 40CFR §60.642(b). The owner/operator shall maintain devices which monitor thesulfur production, the H2S concentration, and the average acid gas flow rate at leastonce in a 24 hour period. In addition, the owner shall operate a CEM for SO2emissions and shall monitor the temperature of the gas leaving the combustion zoneof the incinerator. The CEM must meet the requirements of 40 CFR §60.13.

19. When asbestos renovation or demolition is performed, the Texarkana Gas Plant will besubject to and shall comply with applicable provisions of 40 CFR Part 61, Subpart A –General Provisions and 40 CFR Part 61, Subpart M – Renovation/Demolition of Asbestos.A copy of Subpart M is provided in Appendix F.

Title VI Provisions

20. The permittee shall comply with the standards for labeling of products using ozone depletingsubstances pursuant to 40 CFR Part 82, Subpart E:

1. All containers containing a class I or class II substance stored or transported, allproducts containing a class I substance, and all products directly manufactured witha class I substance must bear the required warning statement if it is being introducedto interstate commerce pursuant to §82.106.

2. The placement of the required warning statement must comply with the requirementspursuant to §82.108.

3. The form of the label bearing the required warning must comply with therequirements pursuant to §82.110.

4. No person may modify, remove, or interfere with the required warning statementexcept as described in §82.112.

21. The permittee shall comply with the standards for recycling and emissions reductionpursuant to 40 CFR Part 82, Subpart F, except as provided for MVACs in Subpart B:


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1. Persons opening appliances for maintenance, service, repair, or disposal must complywith the required practices pursuant to §82.156.

2. Equipment used during the maintenance, service, repair, or disposal of appliancesmust comply with the standards for recycling and recovery equipment pursuant to§82.158.

3. Persons performing maintenance, service repair, or disposal of appliances must becertified by an approved technician certification program pursuant to §82.161.

4. Persons disposing of small appliances, MVACs, and MVAC-like appliances mustcomply with record keeping requirements pursuant to §82.166. (“MVAC-likeappliance” as defined at §82.152.)

5. Persons owning commercial or industrial process refrigeration equipment mustcomply with leak repair requirements pursuant to §82.156.

6. Owners/operators of appliances normally containing 50 or more pounds ofrefrigerant must keep records of refrigerant purchased and added to such appliancespursuant to §82.166.

22. If the permittee manufactures, transforms, destroys, imports, or exports a class I or class IIsubstance, the permittee is subject to all requirements as specified in 40 CFR part 82,Subpart A, Production and Consumption Controls.

23. If the permittee performs a service on motor (fleet) vehicles when this service involvesozone-depleting substance refrigerant (or regulated substitute substance) in the motor vehicleair conditioner (MVAC), the permittee is subject to all the applicable requirements asspecified in 40 CFR part 82, Subpart B, Servicing of Motor Vehicle Air Conditioners.

The term “motor vehicle” as used in Subpart B does not include a vehicle in which finalassembly of the vehicle has not been completed. The term “MVAC” as used in Subpart Bdoes not include the air-tight sealed refrigeration system used as refrigerated cargo, or thesystem used on passenger buses using HCFC-22 refrigerant.

24. The permittee shall be allowed to switch from any ozone-depleting substance to anyalternative that is listed in the Significant New Alternatives Program (SNAP) promulgatedpursuant to 40 CFR Part 82, Subpart G, Significant New Alternatives Policy Program.

Permit Shield

25. Compliance with the conditions of this permit shall be deemed compliance with allapplicable requirements, as of the date of permit issuance, included in and specificallyidentified in item A of this condition:


32Page Amended

a. The following have been specifically identified as applicable requirements basedupon the information submitted by the permittee in an application datedFebruary 1997.

Source No. Regulation Description

Facility Arkansas Regulation #19 Regulations of the Arkansas Plan of Implementation for AirPollution Control

Facility Arkansas Regulation #26 Regulations of the Arkansas Operating Air Permits Program

Facility 40 CFR Part 60, Subpart A New Source Performance Standards General Provisions

Facility 40 CFR 52.21 Prevention of Significant Deterioration

Facility 40 CFR Part 61, Subpart M Renovation/Demolition of Asbestos

Facility, SN-06 40 CFR Part 60, Subpart KKK Standards of Performance for Equipment Leaks of VOC fromOnshore Natural Gas Processing Plants

Facility, SN-10 40 CFR Part 60, Subpart LLL Standards of Performance for Onshore Natural Gas Processing:SO2 Emissions

04, 11 40 CFR Part 60, Subpart Dc New Source Performance Standards for Industrial-Commercial-Institutional Steam Generating Units

09 40 CFR §60.18 General Control Device Requirements

b. The following requirements have been specifically identified as not applicable basedupon information submitted by the permittee in an application dated February 1997.

Source No. Regulation Description Basis for Determination

Facility 40 CFR Part 60Subpart D

New Source Performance Standards forFossil Fuel Fired Steam Generators

The facility does not have anysteam generators with heat inputcapacities greater than 250MMBtu/hr.

Facility 40 CFR Part 60Subpart Da

New Source Performance Standards forElectric Utility Steam Generating Units

The facility does not have anyelectric utility steam generators.

Facility 40 CFR Part 60Subpart Db

New Source Performance Standards forIndustrial-Commercial-Institutional SteamGenerating Units

The facility does not have anysteam generators with heat inputcapacities greater than 100MMBtu/hr.


Source No. Regulation Description Basis for Determination

33Page Amended

Facility 40 CFR Part 60Subpart K

New Source Performance Standards forStorage Vessels for Petroleum Liquids

The facility does not have anystorage tanks with a capacitygreater than 40,000 gallons.

Facility 40 CFR Part 60Subpart Ka

New Source Performance Standards forStorage Vessels for Petroleum Liquids

The facility does not have anystorage tanks with a capacitygreater than 40,000 gallons.

Facility 40 CFR Part 63Subpart HH

National Emission Standards forHazardous Air Pollutants from Oil andNatural Gas Production Facilities

The facility does not have aglycol unit. The facility does nothave any subject storage tanks.The toxic emissions fromfugitives are less than 10 tons peryear of a single HAP and less than25 tons per year of the aggregateof HAPs.

Facility 40 CFR Part 60Subpart Kb

New Source Performance Standards forVolatile Organic Liquid Storage Vessels

The facility is exempt fromregulating vessels with a designcapacity less than 75 m3 andpressure vessels designed tooperate in excess of 204.9 kPa.


34

c. Nothing shall alter or affect the following:

Provisions of Section 303 of the Clean Air Act;

The liability of an owner or operator for any violation of applicable requirementsprior to or at the time of issuance;

The applicable requirements of the acid rain program, consistent with Section 408(a)of the Clean Air Act; or

The ability of the EPA to obtain information under Section 114 of the Clean Air Act.


35

SECTION VII: INSIGNIFICANT ACTIVITIES

Pursuant to §26.3(d) of Regulation 26, the following sources are insignificant activities.Insignificant and trivial activities will be allowable after approval and federal register noticepublication of a final list as part of the operating air permit program. Any activity for which a stateor federal applicable requirement applies is not insignificant even if this activity meets the criteriaof §3(d) of Regulation 26 or is listed below. Insignificant activity determinations rely upon theinformation submitted by the permittee in an application dated February 1997.

Molecular Sieve Regenerator Gas Heater (SN-03, 2.5 MMBtu/hr)Nitrogen Rejection Unit Vent (SN-05, this source only emits methane)DGA Reclaimer (SN-08, 1.57 MMBtu/hr)8820 gallon Secondary Condensate Tank (formerly SN-12, no enforceable permit conditions arenecessary to insure compliance with any applicable law or regulation because the emissions are lessthan 5 tpy of any pollutant regulated under this regulation or less than 1 tpy of a single HAP or 2.5tpy of any combination of HAPs)

Pursuant to §26.3(d) of Regulation 26, the following emission units, operations, or activities havebeen determined by the Department to be insignificant activities. Activities included in this list areallowable under this permit and need not be specifically identified.

1. Combustion emissions from propulsion of mobile sources and emissions from refuelingthese sources unless regulated by Title II and required to obtain a permit under Title V of thefederal Clean Air Act, as amended. This does not include emissions from any transportableunits, such as temporary compressors or boilers. This does not include emissions fromloading racks or fueling operations covered under any applicable federal requirements.

2. Air conditioning and heating units used for comfort that do not have applicable requirementsunder Title VI of the Act.

3. Ventilating units used for human comfort that do not exhaust air pollutants into the ambientair from any manufacturing/industrial or commercial process.

4. Non-commercial food preparation or food preparation at restaurants, cafeterias, or caterers,etc.

5. Consumer use of office equipment and products, not including commercial printers orbusiness primarily involved in photographic reproduction.

6. Janitorial services and consumer use of janitorial products.


1 Cleaning and painting activities qualify if they are not subject to VOC or HAP control requirements. Asphalt batch plantowners/operators must get a permit.

2 “Moved by hand” means that it can be moved by one person without assistance of any motorized or non-motorized vehicle,conveyance, or device.

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7. Internal combustion engines used for landscaping purposes.

8. Laundry activities, except for dry-cleaning and steam boilers.

9. Bathroom/toilet emissions.

10. Emergency (backup) electrical generators at residential locations.

11. Tobacco smoking rooms and areas.

12. Blacksmith forges.

13. Maintenance of grounds or buildings, including: lawn care, weed control, pest control, andwater washing activities.

14. Repair, up-keep, maintenance, or construction activities not related to the sources’ primarybusiness activity, and not otherwise triggering a permit modification. This may include, butis not limited to such activities as general repairs, cleaning, painting, welding, woodworking,plumbing, re-tarring roofs, installing insulation, paved/paving parking lots, miscellaneoussolvent use, application of refractory, or insulation, brazing, soldering, the use of adhesives,grinding, and cutting.1

15. Surface-coating equipment during miscellaneous maintenance and construction activities.This activity specifically does not include any facility whose primary business activity issurface-coating or includes surface-coating or products.

16. Portable electrical generators that can be “moved by hand” from one location to another.2

17. Hand-held equipment for buffing, polishing, cutting, drilling, sawing, grinding, turning, ormachining wood, metal, or plastic.


3 Brazing, soldering, and welding equipment, and cutting torches related to manufacturing and construction activities that emit HAPmetals are more appropriate for treatment as insignificant activities based on size or production thresholds. Brazing, soldering, and weldingequipment, and cutting torches related directly to plant maintenance and upkeep and repair or maintenance shop activities that emit HAPmetals are treated as trivial and listed separately in this appendix.

4 Exemptions for storage tanks containing petroleum liquids or other volatile organic liquids are based on size and limits includingstorage tank capacity and vapor pressure of liquids stored and are not appropriate for this list.

37

18. Brazing or soldering equipment related to manufacturing activities that do not result inemission of HAPs.3

19. Air compressors and pneumatically operated equipment, including hand tools.

20. Batteries and battery charging stations, except at battery manufacturing plants.

21. Storage tanks, vessels, and containers holding or storing liquid substances that do not containany VOCs or HAPs.4

22. Storage tanks, reservoirs, and pumping and handling equipment of any size containing soaps,vegetable oil, grease, animal fat, and no volatile aqueous salt solutions, provided appropriatelids and covers are used and appropriate odor control is achieved.

23. Equipment used to mix and package soaps, vegetable oil, grease, animal fat, and non-volatileaqueous salt solutions, provided appropriate lids and covers are used and appropriate odorcontrol is achieved.

24. Drop hammers or presses for forging or metalworking.

25. Equipment used exclusively to slaughter animals, but not including other equipment atslaughter-houses, such as rendering cookers, boilers, heating plants, incinerators, andelectrical power generating equipment.

26. Vents from continuous emissions monitors and other analyzers.

27. Natural gas pressure regulator vents, excluding venting at oil and gas production facilities.

28. Hand-held applicator equipment for hot melt adhesives with no VOCs in the adhesive.

29. Lasers used only on metals and other materials which do not emit HAPs in the process.

30. Consumer use of paper trimmers/binders.


38

31. Electric or steam-heated drying ovens and autoclaves, but not the emissions from the articlesor substances being processed in the ovens or autoclaves or the boilers delivering the steam.

32. Salt baths using non-volatile salts that do not result in emissions of any air pollutant coveredby this regulation.

33. Laser trimmers using dust collection to prevent fugitive emissions.

34. Bench-scale laboratory equipment used for physical or chemical analysis not including labfume hoods or vents.

35. Routine calibration and maintenance of laboratory equipment or other analytical instruments.

36. Equipment used for quality control/assurance or inspection purposes, including samplingequipment used to withdraw materials for analysis.

37. Hydraulic and hydrostatic testing equipment.

38. Environmental chambers not using hazardous air pollutant gases.

39. Shock chambers, humidity chambers, and solar simulators.

40. Fugitive emissions related to movement of passenger vehicles, provided the emissions arenot counted for applicability purposes and any required fugitive dust control plan or itsequivalent is submitted.

41. Process water filtration systems and demineralizers.

42. Demineralized water tanks and demineralizer vents.

43. Boiler water treatment operations, not including cooling towers.

44. Emissions from storage or use of water treatment chemicals, except for hazardous airpollutants or pollutants listed under regulations promulgated pursuant to Section 112(r) ofthe Act, for use in cooling towers, drinking water systems, and boiler water/feed systems.

45. Oxygen scavenging (de-aeration) of water.

46. Ozone generators.


39

47. Fire suppression systems.

48. Emergency road flares.

49. Steam vents and safety relief valves.

50. Steam leaks.

51. Steam cleaning operations.

52. Steam and microwave sterilizers.

53. Site assessment work to characterize waste disposal or remediation sites.

54. Miscellaneous additions or upgrades of instrumentation.

55. Emissions from combustion controllers or combustion shutoff devices but not combustionunits itself.

56. Use of products for the purpose of maintaining motor vehicles operated by the facility, notincluding air cleaning units of such vehicles (i.e. antifreeze, fuel additives).

57. Stacks or vents to prevent escape of sanitary sewer gases through the plumbing traps.

58. Emissions from equipment lubricating systems (i.e. oil mist), not including storage tanks,unless otherwise exempt.

59. Residential wood heaters, cookstoves, or fireplaces.

60. Barbecue equipment or outdoor fireplaces used in connection with any residence orrecreation.

61. Log wetting areas and log flumes.

62. Periodic use of pressurized air for cleanup.

63. Solid waste dumpsters.


40

64. Emissions of wet lime from lime mud tanks, lime mud washers, lime mud piles, lime mudfilter and filtrate tanks, and lime mud slurry tanks.

65. Natural gas odoring activities unless the Department determines that emissions constituteair pollution.

66. Emissions from engine crankcase vents.

67. Storage tanks used for the temporary containment of materials resulting from an emergencyreporting of an unanticipated release.

68. Equipment used exclusively to mill or grind coatings in roll grinding rebuilding, andmolding compounds where all materials charged are in paste form.

69. Mixers, blenders, roll mills, or calenders for rubber or plastic for which no materials inpowder form are added and in which no organic solvents, diluents, or thinners are used.

70. The storage , handling, and handling equipment for bark and wood residues not subject tofugitive dispersion offsite (this applies to the equipment only).

71. Maintenance dredging of pulp and paper mill surface impoundments and ditches containingcellulosic and cellulosic derived biosolids and inorganic materials such as lime, ash, or sand.

72. Tall oil soap storage, skimming, and loading.

73. Water heaters used strictly for domestic (non-process) purposes.

74. Facility roads and parking areas, unless necessary to control offsite fugitive emissions.

75. Agricultural operations, including onsite grain storage, not including IC engines or grainelevators.

76. The following natural gas and oil exploration production site equipment: separators,dehydration units, natural gas fired compressors, and pumping units. This does not includecompressors located on natural gas transmission pipelines.


41

SECTION VIII: GENERAL PROVISIONS

1. Pursuant to 40 CFR 70.6(b)(2), any terms or conditions included in this permit which specifyand reference Arkansas Pollution Control & Ecology Commission Regulation 18 or theArkansas Water and Air Pollution Control Act (A.C.A. §8-4-101 et seq.) as the sole originof and authority for the terms or conditions are not required under the Clean Air Act or anyof its applicable requirements, and are not federally enforceable under the Clean Air Act.Arkansas Pollution Control & Ecology Commission Regulation 18 was adopted pursuant tothe Arkansas Water and Air Pollution Control Act (A.C.A. §8-4-101 et seq.). Any terms orconditions included in this permit which specify and reference Arkansas Pollution Control& Ecology Commission Regulation 18 or the Arkansas Water and Air Pollution Control Act(A.C.A. §8-4-101 et seq.) as the origin of and authority for the terms or conditions areenforceable under this Arkansas statute.

2. Pursuant to 40 CFR 70.6(a)(2) and §26.7 of the Regulations of the Arkansas Operating AirPermit Program (Regulation 26), this permit shall be valid for a period of five (5) yearsbeginning on the date this permit becomes effective and ending five (5) years later.

3. Pursuant to §26.4 of Regulation #26, it is the duty of the permittee to submit a completeapplication for permit renewal at least six (6) months prior to the date of permit expiration.Permit expiration terminates the permittee's right to operate unless a complete renewalapplication was submitted at least six (6) months prior to permit expiration, in which casethe existing permit shall remain in effect until the Department takes final action on therenewal application. The Department will not necessarily notify the permittee when thepermit renewal application is due.

4. Pursuant to 40 CFR 70.6(a)(1)(ii) and §26.7 of Regulation #26, where an applicablerequirement of the Clean Air Act, as amended, 42 U.S.C. 7401, et seq (Act) is more stringentthan an applicable requirement of regulations promulgated under Title IV of the Act, bothprovisions are incorporated into the permit and shall be enforceable by the Director orAdministrator.

5. Pursuant to 40 CFR 70.6(a)(3)(ii)(A) and §26.7 of Regulation #26, records of monitoringinformation required by this permit shall include the following:

1.The date, place as defined in this permit, and time of sampling or measurements;2.The date(s) analyses were performed;3.The company or entity that performed the analyses;4.The analytical techniques or methods used;5.The results of such analyses; and


42

6.The operating conditions existing at the time of sampling or measurement.

6. Pursuant to 40 CFR 70.6(a)(3)(ii)(B) and §26.7 of Regulation #26, records of all requiredmonitoring data and support information shall be retained for a period of at least 5 yearsfrom the date of the monitoring sample, measurement, report, or application. Supportinformation includes all calibration and maintenance records and all original strip-chartrecordings for continuous monitoring instrumentation, and copies of all reports required bythis permit.

7. Pursuant to 40 CFR 70.6(a)(3)(iii)(A) and §26.7 of Regulation #26, the permittee shallsubmit reports of all required monitoring every 6 months. If no other reporting period hasbeen established, the reporting period shall end on the last day of the anniversary month ofthis permit. The report shall be due within 30 days of the end of the reporting period. Eventhough the reports are due every six months, each report shall contain a full year of data. Allinstances of deviations from permit requirements must be clearly identified in such reports.All required reports must be certified by a responsible official as defined in §26.2 ofRegulation #26 and must be sent to the address below.

Arkansas Department of Environmental QualityAir DivisionATTN: Compliance Inspector SupervisorPost Office Box 8913Little Rock, AR 72219

8. Pursuant to 40 CFR 70.6(a)(3)(iii)(B), §26.7 of Regulation #26, and §19.601 and 19.602 ofRegulation #19, all deviations from permit requirements, including those attributable to upsetconditions as defined in the permit shall be reported to the Department. An initial reportshall be made to the Department by the next business day after the occurrence. The initialreport may be made by telephone and shall include:

1.The facility name and location,2.The process unit or emission source which is deviating from the permit limit, 3.The permit limit, including the identification of pollutants, from which deviationoccurs, 4.The date and time the deviation started, 5.The duration of the deviation, 6.The average emissions during the deviation,7.The probable cause of such deviations,8.Any corrective actions or preventive measures taken or being taken to prevent suchdeviations in the future, and


43

9.The name of the person submitting the report.

A full report shall be made in writing to the Department within five (5) business days ofdiscovery of the occurrence and shall include in addition to the information required byinitial report a schedule of actions to be taken to eliminate future occurrences and/or tominimize the amount by which the permits limits are exceeded and to reduce the length oftime for which said limits are exceeded. If the permittee wishes, they may submit a fullreport in writing (by facsimile, overnight courier, or other means) by the next business dayafter discovery of the occurrence and such report will serve as both the initial report and fullreport.

9. Pursuant to 40 CFR 70.6(a)(5) and §26.7 of Regulation #26, and A.C.A.§8-4-203, asreferenced by §8-4-304 and §8-4-311, if any provision of the permit or the applicationthereof to any person or circumstance is held invalid, such invalidity shall not affect otherprovisions or applications hereof which can be given effect without the invalid provision orapplication, and to this end, provisions of this Regulation are declared to be separable andseverable.

10. Pursuant to 40 CFR 70.6(a)(6)(i) and §26.7 of Regulation #26, the permittee must complywith all conditions of this Part 70 permit. Any permit noncompliance with applicablerequirements as defined in Regulation #26 constitutes a violation of the Clean Air Act, asamended, 42 U.S.C. 7401, et seq. and is grounds for enforcement action; for permittermination, revocation and reissuance, or modification; or for denial of a permit renewalapplication. Any permit noncompliance with a state requirement constitutes a violation ofthe Arkansas Water and Air Pollution Control Act (A.C.A. §8-4-101 et seq.) and is alsogrounds for enforcement action; for permit termination, revocation and reissuance, ormodification; or for denial of a permit renewal application.

11. Pursuant to 40 CFR 70.6(a)(6)(ii) and §26.7 of Regulation #26, it shall not be a defense fora permittee in an enforcement action that it would have been necessary to halt or reduce thepermitted activity in order to maintain compliance with the conditions of this permit.


44

12. Pursuant to 40 CFR 70.6(a)(6)(iii) and §26.7 of Regulation #26, this permit may bemodified, revoked, reopened, and reissued, or terminated for cause. The filing of a requestby the permittee for a permit modification, revocation and reissuance, or termination, or ofa notification of planned changes or anticipated noncompliance does not stay any permitcondition.

13. Pursuant to 40 CFR 70.6(a)(6)(iv) and §26.7 of Regulation #26, this permit does not conveyany property rights of any sort, or any exclusive privilege.

14. Pursuant to 40 CFR 70.6(a)(6)(v) and §26.7 of Regulation #26, the permittee shall furnishto the Director, within the time specified by the Director, any information that the Directormay request in writing to determine whether cause exists for modifying, revoking andreissuing, or terminating the permit or to determine compliance with the permit. Uponrequest, the permittee shall also furnish to the Director copies of records required to be keptby the permit. For information claimed to be confidential, the permittee may be required tofurnish such records directly to the Administrator along with a claim of confidentiality.

15. Pursuant to 40 CFR 70.6(a)(7) and §26.7 of Regulation #26, the permittee shall pay allpermit fees in accordance with the procedures established in Regulation #9.

16. Pursuant to 40 CFR 70.6(a)(8) and §26.7 of Regulation #26, no permit revision shall berequired, under any approved economic incentives, marketable permits, emissions tradingand other similar programs or processes for changes that are provided for elsewhere in thispermit.

17. Pursuant to 40 CFR 70.6(a)(9)(i) and §26.7 of Regulation #26, if the permittee is allowedto operate under different operating scenarios, the permittee shall, contemporaneously withmaking a change from one operating scenario to another, record in a log at the permittedfacility a record of the scenario under which the facility or source is operating.

18. Pursuant to 40 CFR 70.6(b) and §26.7 of Regulation #26, all terms and conditions in thispermit, including any provisions designed to limit a source's potential to emit, areenforceable by the Administrator and citizens under the Act unless the Department hasspecifically designated as not being federally enforceable under the Act any terms andconditions included in the permit that are not required under the Act or under any of itsapplicable requirements.


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19. Pursuant to 40 CFR 70.6(c)(1) and §26.7 of Regulation #26, any document (includingreports) required by this permit shall contain a certification by a responsible official asdefined in §26.2 of Regulation #26.

20. Pursuant to 40 CFR 70.6(c)(2) and §26.7 of Regulation #26, the permittee shall allow anauthorized representative of the Department, upon presentation of credentials, to perform thefollowing:

1.Enter upon the permittee's premises where the permitted source is located oremissions-related activity is conducted, or where records must be kept under theconditions of this permit;2.Have access to and copy, at reasonable times, any records that must be kept underthe conditions of this permit;3.Inspect at reasonable times any facilities, equipment (including monitoring and airpollution control equipment), practices, or operations regulated or required under thispermit; and 4.As authorized by the Act, sample or monitor at reasonable times substances orparameters for the purpose of assuring compliance with this permit or applicablerequirements.

21. Pursuant to 40 CFR 70.6(c)(5) and §26.7 of Regulation #26, the permittee shall submit acompliance certification with terms and conditions contained in the permit, includingemission limitations, standards, or work practices. This compliance certification shall besubmitted annually and shall be submitted to the Administrator as well as to the Department.All compliance certifications required by this permit shall include the following:

1.The identification of each term or condition of the permit that is the basis of thecertification; 2.The compliance status;3.Whether compliance was continuous or intermittent;4.The method(s) used for determining the compliance status of the source, currentlyand over the reporting period established by the monitoring requirements of thispermit; and 5.Such other facts as the Department may require elsewhere in this permit or by§114(a)(3) and 504(b) of the Act.

22. Pursuant to §26.7 of Regulation #26, nothing in this permit shall alter or affect the following:

1.The provisions of Section 303 of the Act (emergency orders), including theauthority of the Administrator under that section;


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2.The liability of the permittee for any violation of applicable requirements prior toor at the time of permit issuance;3.The applicable requirements of the acid rain program, consistent with §408(a) ofthe Act; or4.The ability of EPA to obtain information from a source pursuant to §114 of theAct.

23. Pursuant to A.C.A. §8-4-203 as referenced by §8-4-304 and §8-4-311, this permit authorizesonly those pollutant emitting activities addressed herein.

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APPENDIX A

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APPENDIX B

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APPENDIX C

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APPENDIX G

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Route To: FELICIA INMANAdministration

AIR DIVISION

INVOICE REQUEST FORM

(9-96)

Facility Name & Address:Dynegy Energy Resources, L.P.Texarkana Gas Plant1000 Louisiana Street, Suite 5800Houston, TX 77002

CSN: 46-0133Permit No: 1002-AOP-R0

Permit Description: T5(e.g. A = AIR CODE, S=SIP, H=NESHAP, P=PSD, N=NSPS, T5= Title V)

Initial Fee Calculations:

Title V = 3($18.08)(TPY each pollutant, except CO) - amount of last annual air permit fee

2.6 (PM/PM10) + 205.7 (SO2) + 15.7 (VOC) + 89.1 (NOx) = 310.5 * 18.08 = 5614 - 3719 = 1895

Mod Fee Calculations:

Title V = 3 ($18.08)(TPY increase of each pollutant, except CO)

NOTE: Do Not double count HAPs and VOCs!!!No greater than 4,000 tpy for each contaminant but not less than $1,000

Fee Amount: $ 1895

Engineer: Melissa J. BlumenthalDate: June 26, 2002

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Public Notice

Pursuant to the Arkansas Operating Air Permit Program (Regulation #26) Section 6(b), the AirDivision of the Arkansas Department of Pollution Control and Ecology gives the following notice:

Dynegy Energy Resources, L.P. owns and operates the Texarkana Gas Plant (CSN: 46-0133) locatedon Highway 237, south of Texarkana in Texarkana, Arkansas 75502. The Texarkana Gas Plant isa sour gas processing plant which produces elemental sulfur, natural gas liquids, residue gas, andsweet, dry sales gas. Permit #1002-AOP-R0 is the first permit issued to the Texarkana Gas Plantunder Regulation #26. No physical modifications occurred with the issuance of this permit.

The application has been reviewed by the staff of the Department and has received the Department'stentative approval subject to the terms of this notice.

Citizens wishing to examine the permit application and staff findings and recommendations may doso by contacting Rhonda Sharp, Information Officer. Citizens desiring technical informationconcerning the application or permit should contact Melissa J. Blumenthal, Engineer. Both RhondaSharp and Melissa J. Blumenthal can be reached at the Department's central office, 8001 NationalDrive, Little Rock, Arkansas 72209, telephone: (501) 682-0744.

The draft permit and permit application are available for copying at the above address. A copy ofthe draft permit has also been placed at the Texarkana Public Library, 600 West Third Street,Texarkana, Texas 75501. This information may be reviewed during normal business hours. Interested or affected persons may also submit written comments or request a hearing on theproposal, or the proposed modification, to the Department at the above address - Attention: RhondaSharp. In order to be considered, the comments must be submitted within thirty (30) days ofpublication of this notice. Although the Department is not proposing to conduct a public hearing,one will be scheduled if significant comments on the permit provisions are received. If a hearingis scheduled, adequate public notice will be given in the newspaper of largest circulation in thecounty in which the facility in question is, or will be, located.

The Director shall make a final decision to issue or deny this application or to impose specialconditions in accordance with Section 2.1 of the Arkansas Pollution Control and EcologyCommission’s Administrative Procedures (Regulation #8) and Regulation #26.

Dated this

Randall Mathis Director

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40 CFR 60, Subpart KbDELETED

adeq operating air permit€¦ · adeq operating air permit transfer of permit effective june 14,...

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