ADEQ - Arkansas Department of Environmental Quality€¦ · After considering the facts and...

ADEQARK A N S A SDepartment of Environmental Quality

April 21, 2009

William O'Brien, Plant ManagerUnion Power Partners, L.P.6434 Calion HighwayEl Dorado, AR 71730

Dear Mr. O'Brien:

The enclosed Permit No. 1861-AOP-R4 is issued pursuant to the Arkansas Operating PermitProgram, Regulation # 26.

After considering the facts and requirements of A.C.A. §8-4-101 et seq., and implementingregulations, I have determined that Permit No. 1861-AOP-R4 for the construction, operation andmaintenance of an air pollution control system for Union Power Partners, L.P. to be issued andeffective on the date specified in the permit, unless a Commission review has been properlyrequested under §2.1.14 of Regulation No.8, Arkansas Department of Pollution Control &Ecology Commission's Administrative Procedures, within thirty (30) days after service of thisdecision.

All persons submitting written comments during this thirty (30) day period, and all other personsentitled to do so, may request an adjudicatory hearing and Commission review on whether thedecision of the Director should be reversed or modified. Such a request shall be in the form andmanner required by §2.1.14 of Regulation No.8.

Sincerely,

) ,lic-~ ~h<JJ.fl ,\-)dY-{;~

Mike BatesChief, Air Division

ARKANSAS DEPARTMENT OF ENVIRONMENTAL QUALITY5301 NORTHSHORE DRIVE / NORTH UTILE ROCK / ARKANSAS 72118-5317 / TELEPHONE 501-682-0744 / FAX 501-682-0880

www.adeq.state.ar.us

111111111111111111111111111111111111111111111111111

ADEQOPERATINGAIR PERMIT

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

Permit No. : 1861-AOP-R4

IS ISSUED TO:

Union Power Partners, L.P.6434 Calion HighwayEl Dorado, AR 71730

Union CountyAFIN: 70-00543

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:

September 7,2005 AND September 6,2010

THE PERMITTEE IS SUBJECT TO ALL LIMITS AND CONDITIONS CONTAINEDHEREIN.

Signed:

\ ,,~'c;"/OAhM.)I~ p~:; ,";:{'J,/Q~~-

Mike BatesChief, Air Division

April 21, 2009

Date Modified

Union Power Partners, L.P.Permit #: 1861-AOP-R4AFIN: 70-00543

Table of Contents

SECTION I: FACILITY INFORMATION 4SECTION II: INTRODUCTION 5

Summary of Permit Activity 5Process Description 5Regulations 6Emission Summary 7

SECTION III: PERMIT HISTORY 12SECTION IV: SPECIFIC CONDITIONS 14SECTION V: COMPLIANCE PLAN AND SCHEDULE 29SECTION VI: PLANTWIDE CONDITIONS 30SECTION VII: INSIGNIFICANT ACTIVITIES 33SECTION VIII: GENERAL PROVISIONS 34Appendix A

Appendix BAppendix CAppendix D

2


List of Acronyms and Abbreviations

A.C.A.

AFIN

CFR

CO

HAP

lb/hr

MVAC

No.

PM

PM lO

SNAP

S02

SSM

Tpy

UTM

VOC

Arkansas Code Annotated

ADEQ Facility Identification Number

Code of Federal Regulations

Carbon Monoxide

Hazardous Air Pollutant

Pound Per Hour

Motor Vehicle Air Conditioner

Number

Nitrogen Oxide

Particulate Matter

Particulate Matter Smaller Than Ten Microns

Significant New Alternatives Program (SNAP)

Sulfur Dioxide

Startup, Shutdown, and Malfunction Plan

Tons Per Year

Universal Transverse Mercator

Volatile Organic Compound

3

Union Power Partners, L.P.Pennit #: 1861-AOP-R4AFIN: 70-00543

SECTION I: FACILITY INFORMATION

PERMITTEE: Union Power Partners, L.~

AFIN: 70-00543

PERMIT NUMBER: 1861-AOP-R4

FACILITY ADDRESS: 6434 Calion HighwayEI Dorado, AR 71730

MAILING ADDRESS: 6434 Calion HighwayEI Dorado, AR 71730

COUNTY: Union County

CONTACT NAME: William O'Brien

CONTACT POSITION: Plant Manager

TELEPHONE NUMBER: 870-748-2001

REVIEWING ENGINEER: Kimberly O'Guinn

VIM North South (Y):

VIM East West (X):

Zone 15: 3684915.66 m

Zone 15: 538363.58 m

4

Union Power Partners, L.P.Permit #: l86l-AOP-R4AFIN: 70-00543

SECTION II: INTRODUCTION

Summary of Permit ActivityUnion Power Station (UPS) is operated by Union Power Partners L.P. (UPP). The facility is anatural gas-fired combined-cycle power generation facility in southern Arkansas approximately11 kilometers (km) northeast of El Dorado and 6 km southwest of Calion. The site isapproximately 33 km north of the Arkansas/Louisiana border in Union County. Thismodification is to incorporate Clean Air Interstate Rule (CAIR) requirements set forth inRegulation 19, Chapter 14. Permitted emissions will remain unchanged.

Process Description

The UPS combined-cycle power generating facility includes eight "GE 7FA" CTs with ductburners and eight Heat Recovery Steam Generating Units (HRSGs). Each CTIHRSG unit has anominal generating capacity of 170 MW. The eight CTIHRSG units provide steam for foursteam turbines which produce additional generating capacity. Each power block has thepotential to generate 550 MW of electricity.

CTs are heat engines that convert latent fuel energy into work using compressed hot gas as theworking medium. CTs deliver mechanical output by means of a rotating shaft which is used todrive an electrical generator, thereby converting a portion of the engine's mechanical output toelectrical energy. Ambient air is first filtered and then compressed by the CT compressor. TheCT compressor increases the pressure of the combustion air stream and also raises itstemperature. During warm days when the ambient air temperature exceeds 65 degreesFahrenheit (OF), the turbine inlet ambient air is cooled by an evaporative cooler, thus providingdenser air for combustion and improving the power output. The compressed combustion air isthen combined with natural gas fuel and burned in the CT's high-pressure combustor to producehot exhaust gases. These high pressure, hot gases next expand and tum the CT's turbine toproduce rotary shaft power, which is used to drive an electric generator as well as the CTcombustion air compressor.

The hot exhaust gases from the CTs next flow across the duct burners for additional heat input tothe HRSGs for steam production. Each CT will use a duct burner and HRSG to produce steamto power the steam turbines. The eight duct burners and HRSGs will provide steam for fourseparate steam two-on-one turbine/ generator sets.

Normal operation consists of all CTIHRSG units operating in Mode 6, which is defined as the"normal operating mode by the GE Mark V control system. Alternate UPS operating modesinclude duct burner firing. The CTs are not designed with bypass stacks and always operate incombined-cycle mode. The CTs are permitted for continuous operation (i.e. 8760 hr/yr) whileduct burners may be fired up to 4,000 hours per year each (285 MMBtuIhr HHV).

More specifically Mode 6 is the DLN (Dry Low NOx) Firing Mode. There are four differentoperating modes in which the Union CTs may operate and they are: mode 6, startup, shutdown,or malfunction. When the CTs transition from startup mode to mode 6 they are then capable

5

Union Power Partners, L.P,Pennit #: 1861-AOP-R4AFIN: 70-00543

(with the use of SCR) of meeting the permit limits listed in this air permit. Each of theseoperating modes is recorded by Union for every hour ofoperation.

The CTs and duct burners will utilize low NOx combustion chambers along with SCR to controlNOx • The SCR system reduces the NOx emissions to nitrogen and water vapor. Ammonia isinjected prior to the catalyst bed to help push the reaction. Following reuse of the CT and DBexhaust waste heat by the HRSGs, the exhaust gases are discharged to the atmosphere. Theexclusive use of low-sulfur, low-ash natural gas in the CTs will minimize PM, SOz, and HzS04

air emissions from the CTIHRSG units. High efficiency combustion practices will be employedto control CO and VOC emissions.

Combustion Turbine Tuning

Tuning involves adjusting the mass of fuel and mass of air (fuel to air ratio) entering thecombustion chamber of the CT. The combustion zone of a dry low nitrogen oxides (DLN)combustor is separated into multiple stages which need to be provided the proper fuel to airratios to support efficient turbine operation. The tuning process optimizes the air to fuel ratio toeach of these stages to maintain a low flame temperature. This low flame temperature allows forthe lowest possible nitrogen oxides (NOx) formation during normal operation, The fuel to airratio is set based on feedback from the NOx emissions generated from the CT. Proper tuningalso accomplishes complete mixing in the combustion chamber keeping the carbon monoxide(CO) and volatile organic compounds (VOC) emissions at a minimum.

Since the actual NOx emissions from the CT must be measured during tuning, the SelectiveCatalytic Reduction (SCR) must be turned off. With the SCR off the NOx CEMS units canprovide feedback to appropriately adjust the fuel to air ratios. Without the use of the SCR, NOxemissions can reach 65 pounds per Ib/hr. However, during a majority of the consecutive 24 hourtuning period NOx emission should be below 65 Ib/hr, but will be above the current permittinglimit of33.81b/hr over a 24-hour averaging period.

A 260-hp diesel-fired engine will be installed to drive an emergency fire water pump. Theemergency fire water pump will typically operate for no more than 200 hr/yr for routine testingpurposes.

Regulations

h'r bl1 .hble 0 owmg ta e contams t e regu abons appJ lca e to t IS pennlt.

Regulations

Arkansas Air Pollution Control Code, Regulation 18, effective January 25,2009

Regulations of the Arkansas Plan of Implementation for Air Pollution Control,Regulation 19, effective January 25,2009Regulations of the Arkansas Operating Air Pennit Program, Regulation 26, effectiveJanuary 25,2009

Th fi 11

6


Regulations

40 CFR 52.21, Prevention of Significant Deterioration (PSD)

NSPS Subpart Da - Standards ofPerfonnance for Industria1-Commercia1-InstitutionalSteam Generating Units

NSPS Subpart GG - Standards ofPerfonnance for Stationary Combustion Turbines

40 CFR Part 75 - Continuous Emission Monitoring

Emission Summary

The following table is a summary of emissions from the facility. This table, in itself, is not anenforceable condition ofthe pennit.

EMISSION SUMMARYSource

Description PollutantEmission Rates

Number 1blhr tpy

PM 178.4 724.4

PM10 175.6 712.4

S02 24.0 88.8

Total Allowable Emissions VOC 48.8 144.0

CO 378.4 1244.0

NOx 270.4 918.4

Pb* 0.016 0.032

Acetaldehyde* 0.64 2.48Arsenic* 0.08 0.08Benzene* 0.24 0.80

HAPs Cadmium 0.08 0.08Fonna1dehyde* 1.36 5.04

Mercury 0.08 0.08To1uene* 2.08 8.0

Air Contaminants **H2S04** 2.8 10.24NH3** 245.6 1076.0

7




Number Iblhr tpyPM 21.6 87.5

PMlO 21.6 87.5S02 3.0 ILl

VOC 6.1 18.0CO 47.3 155.5NOx 33.8 114.8Pb* 0.002 0.004

01#1 CTIHRSG Combustion H2SO4 0.35 1.28

Turbine Acetaldehyde* 0.08 0.31Arsenic* 0.01 0.01Benzene* 0.03 0.1Cadmium 0.01 0.01

Formaldehyde* 0.17 0.63Mercury 0.01 0.01Toluene* 0.26 1.0

NH3** 30.7 134.5PM 21.6 87.5

PMlO 21.6 87.5S02 3.0 ILl

VOC 6.1 18.0CO 47.3 155.5NOx 33.8 114.8Pb* 0.002 0.004



Forma1dehyde* 0.17 0.63Mercury 0.01 0.01To1uene* 0.26 1.0

NH3** 30.7 134.5

8




Number Ib/hr tpyPM 21.6 87.5

PM10 21.6 87.5S02 3.0 11.1

VOC 6.1 18.0CO 47.3 155.5NOx 33.8 114.8Pb* 0.002 0.004


Turbine Acetaldehyde* 0.08 0.31Arsenic* 0.Q1 0.01Benzene* 0.03 0.1Cadmium 0.01 0.01

Fonnaldehyde* 0.17 0.63Mercury 0.01 0.01Toluene* 0.26 1.0

NH3** 30.7 134.5PM 21.6 87.5

PM10 21.6 87.5S02 3.0 11.1

VOC 6.1 18.0CO 47.3 155.5

NOx 33.8 114.8Pb* 0.002 0.004



Fonnaldehyde* 0.17 0.63Mercury 0.01 0.01Toluene* 0.26 1.0

NH3** 30.7 134.5

9




Number 1b/hr tpy

PM 21.6 87.5PM10 21.6 87.5S02 3.0 11.1

VOC 6.1 18.0CO 47.3 155.5NOx 33.8 114.8Pb* 0.002 0.004




NH3** 30.7 134.5PM 21.6 87.5

PM10 21.6 87.5S02 3.0 11.1

VOC 6.1 18.0CO 47.3 155.5NOx 33.8 114.8Pb* 0.002 0.004


Turbine Acetaldehyde* 0.08 0.31Arsenic* O.oI 0.01Benzene* 0.03 0.1Cadmium 0.01 0.01


NH3** 30.7 134.5

10




Number lb/hr tpyPM 21.6 87.5

PM10 21.6 87.5S02 3.0 11.1

VOC 6.1 18.0CO 47.3 155.5NOx 33.8 114.8Pb* 0.002 0.004



Formaldehyde* 0.17 0.63Mercury 0.01 0.01Toluene* 0.26 1.0NH3** 30.7 134.5

PM 21.6 87.5PM10 21.6 87.5S02 3.0 11.1

VOC 6.1 18.0CO 47.3 155.5

NOx 33.8 114.8Pb* 0.002 0.004




NH3** 30.7 134.5

11 Cooling Towers #1PM 1.4 6.1

PMIO 0.7 3.1

12 Cooling Tower #2PM 1.4 6.1

PMIO 0.7 3.1


PMIO 0.7 3.1


PMIO 0.7 3.1*HAPs mcluded m the VOC totals. Other HAPs are not mcluded m any other totals unless specIfically stated.**Air Contaminants such as ammonia, acetone, and certain halogenated solvents are not VOCs or HAPs.

11


SECTION III: PERMIT HISTORYPennit #1861-AOP-RO was issued on August 24, 2000. This was the first air pennit issued to

the facility. The facility was pennitted to construct and operate either of the following two of

operating scenarios:

• Scenario 1 included ten ABB Combustion Turbines (CTs) and ten Heat Recovery Steam

Generating Units (HRSGs) without duct burners.

• Scenario 2 included ten GE CT/HRSGs and five HRSGs with duct burners.

The facility was capable of producing either 2,600 or 2,500 megawatts (MW) of electricity underscenarios I and 2 respectively, depending on the operating scenario.

A BACT analysis was perfonned for each regulated pollutant emitted in amounts that exceed thePSD significant levels. BACT applies to each emissions unit at which significant net emissions

in the pollutant would occur as a result of the method of operation of the unit. Therefore, the

BACT analysis for UPS considers emission controls for PMIPMIQ, SOz, VOC, CO, NOx, and

HzS04.

BACT Summary

~ Pollutant I BACT Detennination I01 PMIQ good combustion practices and the use ofclean 0.021bs/MM Btu(HHV)

thru fuels

08 SOz use of low sulfur fuel :0:0.5 gr S/lOO scf

VOC combustor design and good operating practices 2.2 ppmvd*

CO combustor design and good operating practices 9.5 ppmvd*

NOx SCR 3.5 ppmvd*

HzS04 use oflow sulfur fuel :0:0.5 gr S/lOO set)

*At 15% oxygen

Pennit 1861-AOP-Rl was issued on September 5, 2001. Modification in this pennit included:

• Reduction from 10 to 8 GE 7FA combustion turbines (CTs) with duct burners (DBs).

• Increased in the size ofthe 8 DBs from 200 million British thennal units per hour(MMBtu/hr) (based on a higher heating value, HHV) to 285 MMBtulhr HHV.

• Removal of the ABB CT scenario.• PM emission limit was increased to accommodate compliance testing using method 5 in

conjunction with method 202.

• The nominal generating capacity was decreased from 2,600 to 2,200 MW of electricity.

12

Union Power Partners, L.P.Pennit #: l86l-AOP-R4AFIN: 70-00543

Pennit 186l-AOP-R2 Renewal #1 was issued on September 7,2005. The renewal quantifiesparticulate emissions from the existing cooling towers, revises the ammonia emission rates, andupdates the fonnaldehyde emission rates using the latest stack testing data. Five years testingcycle requirements for the eight CT/HRSGs are also incorporated in the pennit

Pennit #1 861-AOP-R3 was issued on June 25, 2007. The minor modification allowed for semiannual combustion turbine tuning (adjustment of fuel to air ratios) of the eight natural gas-firedcombined-cycle combustion turbines (CTs). Each CT is part of a combined--eycle powergenerating unit, designated as SN-Ol through SN-08. Periodic tuning ofthe CTs is conducive tomaintaining low emissions and efficient perfonnance. During CT tuning events, which takesplace within a consecutive 24-hour period, NOx emissions are above the current 24-houraveraging (lb/hr) pennit limit. However, during nonnal operation, this pennit modification didnot affect the NOx emission rates. Specific Condition #38 was added to include combustionturbine tuning. Compliance with the 30 day BACT limit in Specific Condition #21 was metbecause the CTs were operated at lower NOx levels during the remaining hours ofoperation.

13


SECTION IV: SPECIFIC CONDITIONS

SN- 01 - SN-08Eight (8) Combustion Turbine/Heat Recovery Steam Generators

Source Description

Union Power Station's combustion turbines are designed at 1,946 MMBtu/hr (HHV) heat inputcapacity each. Each unit employs duct burners with a design maximum of 285 MM Btulhr(HHV) for a combined plant heat input of 17,848 MM Btu/hr (HHV). Duct burner firing islimited to 4,000 hours per year, allowing a total plant heat input capacity of 145,495,680 MMBtu/year (HHV).

Specific ConditionsParticulate Matter and Opacity

1. The pennittee shall not exceed the emission rates set forth in the following table for eachCT/HRSG/duct burner exhaust. Compliance with this condition will be demonstrated bySpecific Condition 5. The hourly emission rates set forth in the following table werebased on a worse-case load scenario. [Regulation 19, §19.501 et seq., and 40 CFR Part52, Subpart E)

Pollutant lb/hr Averaging Period

PM 21.6 3-hour

PMIO 21.6 3-hour

2. The pennittee shall not exceed the emission rates set forth in the following table for eachCTIHRSG/duct burner exhaust. Compliance with the annual emission rates set forth inthe following table shall be demonstrated by pennitting these sources at maximum annualrates. Maximum annual emission rates are based on an average ambient temperature.Compliance with pound per hour worst-case emissions shall be deemed compliance withannual emission rates. [Regulation 19, §19.501 et seq. and §19.901 et seq. and 40 CFRPart 52 Subpart E)

Pollutant tons per consecutive twelve months

PM 87.5

PMIO 87.5

14

Union Power Partners, L.P.Permit #: l86l-AOP-R4AFIN: 70-00543

3. The permittee shall comply with the following BACT determinations for eachCT/HRSG/duct burner exhaust. Compliance with the emission factors set forth in thefollowing table shall be demonstrated by the performance test of four of eight combustionturbine/heat recovery steam generating unit stacks for PMlPMJO • [Regulation 19,§19.90l et seq. and 40 CFR Part 52 Subpart E]

Pollutant BACT Determination

PM good combustion practices and clean 0.02 3-hrfuels IbsIMMBtu(HHV) avg.

PM10 good combustion practices and clean 0.02 3-hrfuels IbsIMMBtu(HHV) avg.

4. The permittee shall not cause to be discharged to the atmosphere from SN-Ol throughSN-08 stack gases which exhibit greater than 5% opacity. Compliance with this opacitylimit shall be demonstrated by the use of natural gas. [Regulation 19, §19.503 and 40CFR Part 52 Subpart E]

5. The permittee shall perform stack testing on four of the eight CT/HRSG/duct burnerexhausts to demonstrate compliance with the limits specified in Specific Conditions 1 and3. Testing shall be performed every five years in accordance with Plantwide Condition 3and EPA Reference Method 5 and 202 as found in 40 CFR Part 60 Appendix A. Testingshall be performed at greater than or equal to 90% of the maximum operating load. TheDepartment reserves the right to select the CT/HRSG/duct burner to be tested. Thespecific stacks tested shall be rotated every five years. [Regulation 19, §19.702 and§19.90l et seq. and 40 CFR Part 52 Subpart E]

Sulfur Dioxide

6. The permittee shall not exceed the emission rates set forth in the fOllowing table at eachCT/HRSG/duct burner exhaust. Compliance with the hourly emission rates set forth inthe following table shall be demonstrated by permitting this source at maximum hourlyrates. [Regulation 19, §19.50l et seq. and §19.90l et seq. and 40 CFR Part 52 Subpart E]

Pollutant Ibs/hr Averaging Period

SOz 3.0 24-hour

15


7. The permittee shall not exceed the emission rates set forth in the following table at eachsource. Compliance with the annual emission rates set forth in the following table shallbe demonstrated by permitting these sources at maximum annual rates. Maximum annualemission rates are based on an average ambient temperature. Compliance with pound perhour worst-case emissions shall be deemed compliance with annual emission rates.[Regulation 19, §19.501 et seq. and §19.901 et seq. and 40 CFR Part 52 Subpart E]


11.1

8. The permittee shall comply with the following BACT determinations for fuel sulfurcontent at each CT/HRSG/duct burner exhaust. Compliance with the emission factors setforth in the following table shall be demonstrated by Specific Condition 9. [Regulation19, §19.9OI et seq. of Regulation 19 and 40 CFR Part 52 Subpart E]


SOz use oflow sulfur 0.5 gr S/l 00 scffuels

9. The monitoring requirements relative to SOz emissions from the CT/HRSG/duct burnerexhausts shall be as follows: [Regulation 19, §19.703 and §19.901 et seq., NSPS SubpartGG, 40 CFR Part 75 Subpart B, and A.C.A. §8-4-203 as referenced by §8-4-304 and §84-311]

a. The permittee shall monitor the natural gas fuel sulfur content using the customfuel monitoring schedule outlined in Appendix B of this permit in order to satisfyfuel bound sulfur monitoring requirements ofNSPS Subpart GG.

b. The permittee shall conduct SOz emissions monitoring procedures in accordancewith 40 CFR Part 75. These procedures shall include, measuring pipeline naturalgas fuel flow rate using an in-line fuel flow meter, determining the gross calorificvalue of the pipeline natural gas at least once per month, and using the defaultemission rate of 0.0006 pounds ofSOzper million Btu of heat input.

c. The permittee shall maintain records which demonstrate compliance with theabove conditions.

16


Volatile Organic Compounds10. The permittee shall not exceed the emission rates set forth in the following table at each

source. Compliance with the hourly emission rates set forth in the following table shall

be demonstrated by the performance test of four of the eight CT/HRSG/duct burnerexhaust stacks for VOC. The hourly emission rates set forth in the following table werebased on worst-case scenario. [Regulation 19, §19.501 et seq. and §19.901 et seq. and 40CFR Part 52 Subpart E]


VOC 6.1 3-hr. Avg.

11. The permittee shall not exceed the emission rates set forth in the following table at eachsource. Compliance with the annual emission rates set forth in the following table shall

be demonstrated by permitting these sources at maximum annual rates. Maximum annualemission rates are based on an average ambient temperature. Compliance with pound perhour worst-case emissions shall be deemed compliance with annual emission rates.[Regulation 19, §19.501 et seq. and §19.901 et seq. and 40 CFR Part 52 Subpart E]

Pollutant

VOC

tons per consecutive twelve months

18.0

12. The permittee shall comply with the following BACT determinations for eachCT/HRSG/duct burner exhaust stack for VOC. Compliance with the emission factors setforth in the following table shall be demonstrated by the performance test of four of theeight stacks for VOC. [Regulation 19, §19.901 et seq. and 40 CFR Part 52 Subpart E]


VOC combustor design and good operating 2.2 ppmvd* 3-hr. avg.

practices

*at 15% oxygen

13. The permittee shall perform stack testing of four of the eight CT/HRSG/duct burnerexhaust stacks for VOC to demonstrate compliance with the limits specified in SpecificConditions 10 and 12. Testing shall be performed every five years in accordance withP1antwide Condition 3 and EPA Reference Method 25A as found in 40 CFR Part 60Appendix A. Method 25A may be modified to allow for off-site analysis of the

integrated samples collected during the tests for enhanced VOC detection. The off-siteanalysis procedures shall be detailed in the test protocol. Testing shall be performed at

17


greater than or equal to 90% of the maximum operating load. The Department reservesthe right to select the CT/HRSG/duct burner to be tested. The specific stacks tested shallbe rotated every five years. [Regulation 19, §19.702 and §19.901 et seq. and 40 CFRPart 52 Subpart E]

Carbon Monoxide14. The pennittee shall not exceed the emission rates set forth in the following table at each

CT/HRSG/duct burner exhaust. Each combustion turbine/heat recovery stearn generatingunit will be equipped with a CO CEMS. This CEMS shall be used to demonstratecompliance with the hourly emission rate set forth in the following table. [Regulation 19,§19.501 et seq. and §19.901 et seq. and 40 CFR Part 52 Subpart E]


CO 47.3 24-hour

15. The pennittee shall not exceed the emission rates set forth in the following table at eachsource. Compliance with the annual emission rates set forth in the following table shallbe demonstrated by Specific Condition 18. [Regulation 19, §19.501 et seq. and §19.901et seq. and 40 CFR Part 52 Subpart E]

Pollutant

CO


155.5

16. The pennittee shall comply with the following BACT detenninations for eachCT/HRSG/duct burner exhaust. Compliance with the emission factors set forth in thefollowing table shall be demonstrated by the perfonnance testing of the combustionturbine heat recovery steam generating unit for CO. [Regulation 19, §19.901 et seq. and40 CFR Part 52 Subpart E]

Pollutant BACT Detennination Limit

CO combustor design and good operating practices 9.5 ppmvd*

*corrected to 15% oxygen

17. The pennittee shall perfonn stack testing of four of the eight CT/HRSG/duct burnerexhaust stacks to demonstrate compliance with all emission limits specified in SpecificConditions 14 and 16. Testing shall be perfonned every five years in accordance withPlantwide Condition 3 and EPA Reference Method 10 as found in 40 CFR Part 60Appendix A. Testing shall be perfonned at greater than or equal to 90% of maximumoperating load. The Department reserves the right to select the CT/HRSG/duct burner tobe tested. The specific stacks tested shall be rotated every five years. [Regulation 19,§19.702 of and §19.901 et seq. and 40 CFR Part 52 Subpart E]

18


18. The pennittee shall install, maintain, and operate a CO CEMS on each CT/HRSG/ductburner exhaust stack. The CEMS shall comply with the ADEQ's Continuous EmissionsMonitoring Systems Conditions. A copy is provided in Appendix C. The CEMS datamay be used by the Department for enforcement purposes. The CEMS shall be used todemonstrate compliance with the CO mass emission limits specified in SpecificConditions #14, and #15. [Regulation 19, §19.703 and §19.901 et seq., 40 CFR Part 52Subpart E, and A.C.A. §8-4-203 as referenced by §8-4-304 and §8-4-311]

Nitrogen Oxides19. The pennittee shall not exceed the emission rates set forth in the following table at each

CT/HRSG/duct burner exhaust. The CT/HRSG/duct burner exhaust will be equippedwith a NOx CEMS. This CEMS shall be used to detennine compliance with the hourlyemission rates set forth in the following table. [Regulation 19, §19.501 et seq. and§19.901 et seq. and 40 CFR Part 52 Subpart E]

Pollutant Ib/hr Averaging Period

NOx 33.8 24-hour

20. The pennittee shall not exceed the emission rates set forth in the following table at eachCT/HRSG/duct burner exhaust. Compliance with the annual emission rates set forth inthe following table shall be demonstrated by Specific Condition 23. [Regulation 19,§19.501 et seq. and §19.901 et seq. and 40 CFR Part 52 Subpart E]

PollutantNOx

tons per consecutive twelve months114.8

21. The pennittee shall comply with the following BACT detenninations for eachCT/HRSG/duct burner stack. The CT/HRSG/duct burner exhaust will be equipped with aNOx CEMS. This CEMS shall be used to detennine compliance with the emission ratesset forth in the following table. [Regulation 19, §19.901 et seq. and 40 CFR Part 52Subpart E]

Pollutant BACT Detennination

NOx SCR I 3.5 ppmvd* I 30-dayavg.

*corrected to 15% oxygen

19


22.

23.

Lead24.

25.

The permittee shall perform stack testing on four of the eight CT/HRSG/duct burnerexhaust stacks for NOx to demonstrate compliance with the emission limit set forth inSpecific Conditions 19 and 21. Testing shall be performed every five years inaccordance with Plantwide Condition 3 and EPA Reference Method 7E as found in 40CFR Part 60 Appendix A. Testing shall be performed at greater than or equal to 90% ofthe maximum operating load. The Department reserves the right to select theCTiHRSG/duct burner to be tested. The specific stacks tested shall be rotated every fiveyears. [Regulation 19, §19.702 and §19.901 et seq. and 40 CFRPart 52 Subpart E]

The permittee shall install, calibrate, maintain, and operate a NOx CEMS on eachCT/HRSG/duct burner exhaust stack. The measured concentrations of NOx and O2 in theflue gas along with the measured fuel flow shall be used to calculate NOx massemissions. The CEMS shall comply with the ADEQ's Continuous Emission MonitoringSystems Conditions. The CEMS data may be used by the Department for enforcementpurposes. The CEMS shall be used to demonstrate compliance with Specific Conditions19,20, and 21. [Regulation 19, §19.703 and §19.901 et seq., 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 not exceed the emission rates set forth in the following table for eachCTiHRSG/duct burner exhaust. Compliance with the hourly emission rates set forth inthe following table shall be demonstrated by the use of natural gas. The hourly emissionrates set forth in the following table are based on the worst-case scenario. [Regulation19, §19.501 et seq. and 40 CFR Part 52 Subpart E]


Pb 0.002 24-hour

The permittee shall not exceed the emission rates set forth in the following table for eachsource. Compliance with the annual emission rates set forth in the following table shallbe demonstrated by permitting these sources at maximum annual rates. Maximum annualemission rates are based on an average ambient temperature. Compliance with pound perhour worst-case emissions shall be deemed compliance with annual emission rates.[Regulation 19, §19.501 et seq. and 40 CFR Part 52 Subpart E]

Pollutant

Pb


0.004

20


Sulfuric Acid Mist (H2S04)

26. The permittee shall not exceed the emission rates set forth in the following table at eachsource. Compliance with the hourly emission rates set forth in the following table shallbe demonstrated by Specific Condition #9. The hourly emission rates set forth in thefollowing table are based on worst-case scenario. [Regulation 19, §19.501 et seq. and§19.901 et seq. and 40 CFR Part 52 Subpart E]

Pollutant 1b/hr Averaging Period

H2SO4 0.35 24-hour

27. The permittee shall not exceed the annual emission rates set forth in the fOllowing table ateach source. Compliance with the annual emission rates set forth in the following tableshall be demonstrated by Specific Condition #9. [Regulation 19, §19.50l et seq. and§19.901 et seq. and 40 CFR Part 52 Subpart E]


1.28

28. The permittee shall comply with the following BACT determinations for each of theCT/HRSG/duct burner exhaust stacks for H 2S04• Compliance with the emission factorset forth in the following table shall be demonstrated by Specific Condition #9.[Regulation 19, §19.901 et seq. and 40 CFR Part 52 Subpart E]


use oflow sulfur fuels I 0.5 gr S/l00 scf

21


Non-criteria Pollutants29. The permittee shall not exceed the emission rates set forth in the following table for each

CTIHRSG/duct burner exhaust. Compliance with the hourly emission rates set forth inthe following table shall be demonstrated by Specific Conditions #31 and #32. Thehourly ammonia emission rates set forth in the following table are based on the worstcase scenario. [Regulation 18, §18.801 and AC.A §8-4-203 as referenced b §8-4-304and §8-4-311]


NH3 30.7 3-houracetaldehyde 0.08

arsemc 0.01 3-hourtoluene 0.26benzene 0.03

cadmium 0.01formaldehyde 0.17

mercury 0.01

30. The permittee shall not exceed the emission rates set forth in the following table at eachsource. Compliance with the annual emission rates set forth in the following table shallbe demonstrated by permitting these sources at maximum annual rates. Maximum annualemission rates are based on an average ambient temperature. Compliance with pound perhour worst-case emissions shall be deemed compliance with annual emission rates.[Regulation 18, §18.801 and AC.A. §8-4-203 as referenced b §8-4-304 and §8-4-311]


NH3 134.50acetaldehyde 0.31

arsemc 0.01toluene 1.00benzene 0.10cadmium 0.01

formaldehyde 0.63mercury om

22


31. The permittee shall conduct a performance test on anyone stack for ammoniaconcentration at SN-OI through SN-08 once every five years to assure compliance withthe limits set in Specific Condition #29. The permittee shall use EPA Reference Method206 or other Department approved methodology. The specific stack tested shall berotated every five years. [Regulation 18, §18.1002 and A.C.A. §8-4-203 as referenced by§8-4-304 and §8-4-311]

32. The permittee shall conduct a performance test on anyone of sources SN-O1 through SN08 once every five years using Method 18 for all detectable HAPs concentrations.Testing shall demonstrate compliance with emission rates listed in Specific Condition#29 (excluding NH3). The test shall be performed when operating in combined cycle atgreater than 90% of capacity. The permittee shall also demonstrate that the combustionturbines alone are not a major source for HAPs (i.e. 10 tpy single HAP or 25 tpy totalHAPs). The permittee has the option to test the CT again in simple cycle mode at greaterthan 90% load in order to demonstrate that the facility (the 8 CTs alone) is not a majorsource for HAPs and is therefore not subject to requirements of the Clean Air Act§112(g). Testing shall be performed in accordance with Plantwide Condition #3.[Regulation 18, §18.1 002 and A.C.A. §8-4-203 as referenced by §8-4-304 and §8-4-311]

Throughput Limitations33. Each combustion turbine/heat recovery steam generating unit may only fire pipeline

quality natural gas. [Regulation 19, §19.705 and §19.901 et seq., A.C.A. §8-4-203 asreferenced by §8-4-304 and §8-4-311 and 40 CFR 70.6]

34. The pipeline quality natural gas combusted in the combustion turbine/heat recoverysteam generating units shall be natural gas whose quality would meet the tariff of anymajor interstate gas transporter. [Regulation 19, §19.705 and §19.901 et seq., A.c.A. §84-203 as referenced by §8-4-304 and §8-4-311 and 40 CFR 70.6]

35. The permittee's feed to the duct burners shall not exceed 9,120,000 MMBtu (HHV) pertwelve consecutive months period. [Regulation 19, §19.705 and §19.901 et seq., A.C.A.§8-4-203 as referenced by §8-4-304 and §8-4-311 and 40 CFR 70.6]

36. The permittee shall maintain records to demonstrate compliance with Specific Condition#35. Records shall be kept on-site and made available to Department personnel uponrequest. Records shall be updated monthly within 15 days of the month to which therecords pertain. A twelve month rolling total shall be kept. Records shall be submitted tothe Department in accordance with General Provision #7. [Regulation 19, §19.705 and§19.901 et seq., A.C.A. §8-4-203 as referenced by §8-4-304 and §8-4-311 and 40 CFR70.6]

23


Hourly Emission Limits37. The hourly emission rates and concentration limits listed in this permit do not apply

during start-up, shut-down and malfunction periods. The permittee shall report upsetconditions pursuant to §19.601 of Regulation 19. [A.C.A. §8-4-203 as referenced by §84-304 and §8-4-311]

Combustion Turbine Tuning38. The hourly NOx emission rate listed in Specific Condition #19 (33.8 lb/hr, averaging 24

hour period) is not applicable during combustion turbine tuning. The hourly NOxemission rate shall not exceed 65 lbs/hour during combustion turbine tuning.Combustion turbine tuning shall not occur more than two (2) times per consecutivetwelve month period, per combustion turbine, and shall not exceed 24 hours percombustion turbine tuning period. Emissions during combustion turbine tuning hoursshall be included in determining compliance with Specific Condition #20 «114.8 tpy)and Specific Condition #21 (BACT Determination: 3.5 ppmvd corrected to 15% oxygen,30-dayaverage). The permittee shall maintain records of combustion turbine tuning onsite and be made available to Department personnel upon request.

24


New Source Performance Standards (NSPS)39. Each combustion turbine/heat recovery steam generating unit is subject to and shall

comply with applicable provisions of 40 CFR Part 60 Subpart A - General Provisions and40 CFR Part 60 Subpart GG - Standards of Performance for Stationary Gas Turbines(included in Appendix B). Applicable provisions of Subpart GG include but are notlimited to, the following:

a. The permittee shall not exceed a NOx emission rate of 109.0 ppmvd at 15%oxygen on a dry basis. Specific Condition 21 is demonstration of compliancewith these standards. [40 CFR §60.332(a)(l)]

b. The permittee shall not bum any fuel which contains sulfur in excess of 0.8percent by weight. Compliance with this condition shall be demonstrated bycompliance with Specific Condition 9. [40 CFR §60.333(b)]

c. The permittee shall report any monitoring period during which the sulfur contentof the fuel being fired in the gas turbines exceeds 0.8 percent by weight. [40 CFR§60.334(c)(2)]

d. Initial compliance testing for NOx and S02 is required within 180 days after startup. Compliance with the S02 requirements will be demonstrated by compliancewith Specific Condition 9 (A). [40 CFR §60.335 and §60.8]

The NOx performance testing shall be conducted in accordance with test methodsin 40 CFR Part 60 Appendix A or alternative approved methods. The testing shallbe conducted at four points in the normal operating range of the turbinesincluding the minimum point in the range and at the peak load. Compliance withthe NOx performance testing requirements may be waived pending EPA approvalof the use of CEMS required by Specific Condition #23 to demonstratecompliance with the NOx standard.

40. The duct burners are subject to and shall comply with applicable provisions of 40 CFRPart 60 Subpart A-General Provisions and 40 CFR Part 60 Subpart Da - Standards ofPerformance for Industrial-Commercial-Institutional Steam Generating Units. A copy ofSubpart Da is provided in Appendix A. Applicable provisions of Subpart Da include, butare not limited to, the following:

a. NOx emissions shall not exceed 0.2 lb/MMBtu (HHV) heat input. Compliancewith this condition shall be demonstrated by complying with Specific Condition#22. [40 CFR §60.44b(a)(4)(i)]

25


b. The nitrogen oxides emission standards under §60.44b apply at all times, thisincludes periods of startup, shutdown, and malfunction. [40 CFR §60.46b(a)]

c. To determine compliance with the emission limit for nitrogen oxides required by40 CFR §60.44b(a)(4) for duct burners, the owner or operator of the facility shallconduct a performance test required under 40 CFR §60.8 using the nitrogenoxides and oxygen measurement procedures in 40 CFR part 60 Appendix A,Method 20. During the performance test, one sampling site shall be located asclose as practicable to the exhaust of the turbine; as provided by 6.1.1 of Method20. A second sampling site shall be located at the outlet to the steam generatingunit. Measurements of nitrogen oxides and oxygen shall be taken at both samplingsites during the performance test. The nitrogen oxides emission rate from thecombined cycle system shall be calculated by subtracting the nitrogen oxidesemission rate measured at the sampling site and at the outlet from the turbine fromthe nitrogen oxides emission rate measured at the sampling site at the outlet fromthe steam generating unit. [40 CFR §60.46b(f)]

d. The owner shall record and maintain records of the amounts of fuel combustedduring each day and calculate the annual capacity factor individually for eachcalendar quarter. The annual capacity factor is determined on a 12-month rollingaverage basis with a new annual capacity factor calculated at the end of eachcalendar month. [40 CFR §60.49b(d)]

e. All records required under the section shall be maintained by the owner oroperator of the facility for a period of 2 years following the date of such record.[40 CFR §60.49b(0)]

41. The following notifications to the Department are required for the combustion turbinesand the duct burners: CEMS, opacity, and emissions performance testing postmarked notless than 30 days prior to testing. [40 CFR §60.7(a)]

Acid Rain Program42. The affected units (SN-Ol through SN-08) are subject to and shall comply with

applicable provisions of the Acid Rain Program (40 CFR Parts 72, 73, and 75).

43. The submission of the NOx, S02, and O2 or CO2 monitoring plans and notice of CEMScertification testing is required at least 45 days prior to the CEMS certification testing.[40 CFR Part 75 Continuous Emission Monitoring Subpart G]

26


44. A monitoring plan is required to be submitted for NOx, S02, and 02 or CO2 monitoring.[40 CFR Part 75 - Continuous Emission Monitoring Subpart G]

45. The initial NOx, and O2 or CO2 CEMS certification testing is to occur no later than 90days after the unit commences commercial operation except the testing must occur priorto the date this unit is declared commercial in accordance with DOE Form EIA-860. [40CFR Part 75 Subpart A]

46. The permittee shall ensure that the continuous emISSIOns monitoring systems are inoperation and monitoring all unit emissions at all times, except during periods ofcalibration, quality assurance, preventative maintenance or repair. [40 CFR Part 75.10.]

27


SN-11 through SN-14Cooling Towers

Source DescriptionThe four (4) mechanical draft cooling towers are each equipped with drift eliminators. Eachtower has nine cells.

Specific Conditions

47. The permittee shall not exceed the emission rates set forth in the following table. Theemission rates are based on maximum capacity. [Regulation 19, §19.501 et seq. and 40CFR Part 52, Subpart E]

Pollutantlb/hr tpy

(24-hr average)

PM IO 0.7 3.1

48. The permittee shall not exceed the emission rates set forth in the following table at eachsource. The permittee shall demonstrate compliance with this condition by SpecificCondition #50. [Regulation 18, §18.801, and A.C.A. §8-4-203 as referenced by AC.A§8-4-304 and §8-4-311]

Pollutantlb/hr tpy

(24-hr average)

PM 1.4 6.1

49. Visible emissions may not exceed the limits specified in the following table of this permitas measured by EPA Reference Method 9. [Regulation 19, §19.503 and 40 CFR 52Subpart E]

SN Limit Regulatory Citation

11, 12, 13, and 14 20% §19.503

50. The total dissolve solids content at each cooling tower shall not exceed 3000 part permillion by weight. [Regulation 19, §19.705, AC.A. §8-4-203 as referenced by AC.A§8-4-304 and §8-4-311, and 40 CFR 70.6]

51. The permittee shall monitor monthly the total dissolved solids to demonstrate compliancewith Specific Condition #50. These records shall be updated on a monthly basis. Therecords shall be kept on site, provided to Department personnel upon request, and may beused by Department for enforcement purposes. The permittee shall submit these recordsin accordance with General Provision 7. [Regulation 19, §19.705 and 40 CFR Part 52,Subpart E

28


SECTION V: COMPLIANCE PLAN AND SCHEDULE

Union Power Partners, L.P. will continue to operate in compliance with those identifiedregulatory provisions. The facility will examine and analyze future regulations that may applyand detennine their applicability with any necessary action taken on a timely basis.

29


SECTION VI: PLANTWIDE CONDITIONS

1. The permittee shall notify the Director in writing within thirty (30) days aftercommencing construction, completing construction, first placing the equipment and/orfacility in operation, and reaching the equipment and/or facility target production rate.[Regulation 19, §19.704,40 CFR Part 52, Subpart E, and A.C.A. §8-4-203 as referencedby A.C.A. §8-4-304 and §8-4-311]

2. If the permittee fails to start construction within eighteen months or suspendsconstruction for eighteen months or more, the Director may cancel all or part of thispermit. [Regulation 19, §19.410(B) and 40 CFR Part 52, Subpart E]

3. The permittee must test any equipment scheduled for testing, unless otherwise stated inthe Specific Conditions of this permit or by any federally regulated requirements, withinthe following time frames: (1) new equipment or newly modified equipment within sixty(60) days of achieving the maximum production rate, but no later than 180 days afterinitial start up of the permitted source or (2) operating equipment according to the timeframes set forth by the Department or within 180 days of permit issuance if no date isspecified. The permittee must notify the Department of the scheduled date of compliancetesting at least fifteen (15) days in advance of such test. The permittee shall submit thecompliance test results to the Department within thirty (30) days after completing thetesting. [Regulation 19, §19.702 and/or Regulation 18 §18.1002 and A.C.A. §8-4-203 asreferenced by A.C.A. §8-4-304 and §8-4-311]

4. The permittee must provide:

a. Sampling ports adequate for applicable test methods;b. Safe sampling platforms;c. Safe access to sampling platforms; andd. Utilities for sampling and testing equipment.

[Regulation 19, §19.702 and/or Regulation 18, §18.1002 and A.C.A. §8-4-203 asreferenced by A.c.A. §8-4-304 and §8-4-311]

5. The permittee must operate the equipment, control apparatus and emission monitoringequipment within the design limitations. The permittee shall maintain the equipment ingood condition at all times. [Regulation 19, §19.303 and A.C.A. §8-4-203 as referencedby A.C.A. §8-4-304 and §8-4-311]

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

30


Acid Rain (Title IV)

7. The Director prohibits the permittee to cause any emissions exceeding any allowances thesource lawfully holds under Title IV of the Act or the regulations promulgated under theAct. No permit revision is required for increases in emissions allowed by allowancesacquired pursuant to the acid rain program, if such increases do not require a permitrevision under any other applicable requirement. This permit establishes no limit on thenumber of allowances held by the permittee. However, the source may not useallowances as a defense for noncompliance with any other applicable requirement of thispermit or the Act. The permittee will account for any such allowance according to theprocedures established in regulations promulgated under Title IV of the Act. A copy ofthe facility's Acid Rain Permit is attached in an appendix to this Title V permit.[Regulation 26, §26.701 and 40 CFR 70.6(a)(4)]

Title VI Provisions

8. The permittee must comply with the standards for labeling of products using ozonedepleting substances. [40 CFR Part 82, Subpart E]

a. All containers containing a class I or class II substance stored or transported, allproducts containing a class I substance, and all products directly manufacturedwith a class I substance must bear the required warning statement ifit is beingintroduced to interstate commerce pursuant to §82.106.

b. The placement of the required warning statement must comply with therequirements pursuant to §82.108.

c. The form of the label bearing the required warning must comply with therequirements pursuant to §82.11 O.

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

9. The permittee must comply with the standards for recycling and emissions reduction,except as provided for MVACs in Subpart B. [40 CFR Part 82, Subpart F]

a. Persons opening appliances for maintenance, service, repair, or disposal mustcomply with the required practices pursuant to §82.156.

b. Equipment used during the maintenance, service, repair, or disposal of appliancesmust comply with the standards for recycling and recovery equipment pursuant to§82.l58.

c. Persons performing maintenance, service repair, or disposal of appliances must becertified by an approved technician certification program pursuant to §82.l61.

d. 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)

31


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

f. Owners/operators of appliances normally containing 50 or more pounds ofrefiigerant must keep records of refrigerant purchased and added to suchappliances pursuant to §82.166.

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

II. If the permittee performs a service on motor (fleet) vehicles when this service involvesozone depleting substance refrigerant (or regulated substitute substance) in the motorvehicle air conditioner (MVAC), the permittee is subject to all the applicablerequirements as specified in 40 CFR part 82, Subpart B, Servicing of Motor Vehicle AirConditioners.

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 SubpartB does not include the air tight sealed refiigeration system used as refrigerated cargo, orthe system used on passenger buses using HCFC 22 refiigerant.

12. The permittee can switch from any ozone depleting substance to any alternative listed inthe Significant New Alternatives Program (SNAP) promulgated pursuant to 40 CFR Part82, Subpart G.

Clean Air Act Interstate Rule (CAIR)

13. The permittee shall comply with the monitoring, reporting, and recordkeepingrequirements of subpart HHHH of 40 CFR part 96. The permittee shall comply with theNOx emission requirements established under CAIR. The Permittee shall report andmaintain the records required by subpart HHHH of 40 CFR part 96. A copy of the CAIRpermit is attached to this Title V permit. [Regulation No. 19 §19.1401 and 40 CFR Part52, Subpart E]

32

Union Power Partners, L.P.Pennit #: I86I-AOP-R4AFIN: 70-00543

SECTION VII: INSIGNIFICANT ACTIVITIES

The following sources are insignificant activities. Any activity that has a state or federalapplicable requirement shall be considered a significant activity even if this activity meets thecriteria of §26.304 ofRegulation 26 or listed in the table below. Insignificant activitydetenninations rely upon the infonnation submitted by the pennittee in an application datedFebruary 22,2005.

Description

240-hp diesel fire-water pump

33

Category

A-I


SECTION VIII: GENERAL PROVISIONS1. Any tenns or conditions included in this pennit which specify and reference Arkansas

Pollution Control & Ecology Commission Regulation 18 or the Arkansas Water and AirPollution Control Act (AC.A §8-4-101 et seq.) as the sole origin of and authority for thetenns or conditions are not required under the Clean Air Act or any of its applicablerequirements, and are not federally enforceable under the Clean Air Act. ArkansasPollution Control & Ecology Commission Regulation 18 was adopted pursuant to theArkansas Water and Air Pollution Control Act (AC.A §8-4-101 et seq.). Any terms orconditions included in this permit which specify and reference Arkansas PollutionControl & Ecology Commission Regulation 18 or the Arkansas Water and Air PollutionControl Act (AC.A §8-4-101 et seq.) as the origin of and authority for the terms orconditions are enforceable under this Arkansas statute. [40 CFR 70.6(b)(2)]

2. This pennit shall be valid for a period of five (5) years beginning on the date this permitbecomes effective and ending five (5) years later. [40 CFR 70.6(a)(2) and §26.701(B) ofthe Regulations of the Arkansas Operating Air Permit Program (Regulation 26)]

3. The pennittee must submit a complete application for pennit renewal at least six (6)months before pennit expiration. Permit expiration tenninates the pennittee's right tooperate unless the permittee submitted a complete renewal application at least six (6)months before pennit expiration. If the permittee submits a complete application, theexisting pennit will remain in effect until the Department takes final action on therenewal application. The Department will not necessarily notify the pennittee when thepennit renewal application is due. [Regulation 26, §26.406]

4. Where an applicable requirement of the Clean Air Act, as amended, 42 U.S.C. 7401, etseq. (Act) is more stringent than an applicable requirement of regulations promulgatedunder Title IV of the Act, the pennit incorporates both provisions into the permit, and theDirector or the Administrator can enforce both provisions. [40 CFR 70.6(a)(1)(ii) andRegulation 26, §26.701(A)(2)]

5. The permittee must maintain the following records of monitoring infonnation as requiredby this pennit.

a. The date, place as defined in this pennit, and time of sampling or measurements;b. The date(s) analyses performed;c. The company or entity performing the analyses;d. The analytical techniques or methods used;e. The results of such analyses; and£ The operating conditions existing at the time of sampling or measurement.

[40 CFR 70.6(a)(3)(ii)(A) and Regulation 26, §26.701(C)(2)]

34


6. The permittee must retain the records ofall required monitoring data and supportinformation for at least five (5) years from the date of the monitoring sample,measurement, report, or application. Support information includes all calibration andmaintenance records and all original strip chart recordings for continuous monitoringinstrumentation, and copies of all reports required by this permit. [40 CFR70.6(a)(3)(ii)(B) and Regulation 26, §26.701(C)(2)(b)]

7. The permittee must submit reports of all required monitoring every six (6) months. Ifpermit establishes no other reporting period, the reporting period shall end on the last dayof the anniversary month of the initial Title V permit. The report is due within thirty (30)days of the end of the reporting period. Although the reports are due every six months,each report shall contain a full year ofdata. The report must clearly identify all instancesof deviations from permit requirements. A responsible official as defined in RegulationNo. 26, §26.2 must certify all required reports. The permittee will send the reports to theaddress below:

Arkansas Department of Environmental QualityAir DivisionATTN: Compliance Inspector Supervisor5301 Northshore DriveNorth Little Rock, AR 72118-5317

[40 C.F.R. 70.6(a)(3)(iii)(A) and Regulation 26, §26.701(C)(3)(a)]

8. The pemlittee shall report to the Department all deviations from permit requirements,including those attributable to upset conditions as defined in the permit.

a. For all upset conditions (as defined in Regulation19, § 19.601), the permittee willmake an initial report to the Department by the next business day after thediscovery of the occurrence. The initial report may be made by telephone andshall include:

I. The facility name and location;B. The process unit or emission source deviating from the permit limit;

lll. The permit limit, including the identification of pollutants, from whichdeviation occurs;

IV. The date and time the deviation started;v. The duration of the deviation;

VI. The average emissions during the deviation;VB. The probable cause ofsuch deviations;

Vll1. Any corrective actions or preventive measures taken or being taken toprevent such deviations in the future; and

IX. The name ofthe person submitting the report.

35


The pennittee shall make a full report in writing to the Department within five (5)business days ofdiscovery of the occurrence. The report must include, in addition tothe infonnation required by the initial report, a schedule of actions taken or plannedto eliminate future occurrences and/or to minimize the amount the pennit's limitswere exceeded and to reduce the length of time the limits were exceeded. Thepennittee may submit a full report in writing (by facsimile, overnight courier, or othermeans) by the next business day after discovery of the occurrence, and the report willserve as both the initial report and full report.

b. For all deviations, the pennittee shall report such events in semi-annual reportingand annual certifications required in this pennit. This includes all upsetconditions reported in 8a above. The semi-annual report must include all theinfonnation as required by the initial and full reports required in 8a.

[Regulation 19, §19.601 and §19.602, Regulation 26, §26.701(C)(3)(b), and 40 CFR70.6(a)(3)(iii)(B)]

9. Ifany provision of the pennit or the application thereof to any person or circumstance isheld invalid, such invalidity will not affect other provisions or applications hereof whichcan be given effect without the invalid provision or application, and to this end,provisions of this Regulation are declared to be separable and severable. [40 CFR70.6(a)(5), Regulation 26, §26.701(E), and AC.A §8-4-203 as referenced by AC.A §84-304 and §8-4-311]

10. The pennittee must comply with all conditions of this Part 70 pennit. Any pennitnoncompliance with applicable requirements as defined in Regulation 26 constitutes aviolation of the Clean Air Act, as amended, 42 U.S.C. §7401, et seq. and is grounds forenforcement action; for pennit tennination, revocation and reissuance, for pennitmodification; or for denial ofa pennit renewal application. [40 CFR 70.6(a)(6)(i) andRegulation 26, §26.701(F)(l)]

11. It shall not be a defense for a permittee in an enforcement action that it would have beennecessary to halt or reduce the pennitted activity to maintain compliance with theconditions of this pennit. [40 CFR 70.6(a)(6)(ii) and Regulation 26, §26.701(F)(2)]

12. The Department may modify, revoke, reopen and reissue the pennit or tenninate thepennit for cause. The filing of a request by the pennittee for a pennit modification,revocation and reissuance, tennination, or of a notification of planned changes oranticipated noncompliance does not stay any pennit condition. [40 CFR 70.6(a)(6)(iii)and Regulation 26, §26.701(F)(3)]

13. This pennit does not convey any property rights of any sort, or any exclusive privilege.[40 CFR 70.6(a)(6)(iv) and Regulation 26, §26.701(F)(4)]

36


14. The pennittee must furnish to the Director, within the time specified by the Director, anyinfonnation that the Director may request in writing to detennine whether cause exists formodifying, revoking and reissuing, or tenninating the pennit or to detennine compliancewith the pennit. Upon request, the pennittee must also furnish to the Director copies ofrecords required by the pennit. For infonnation the pennittee claims confidentiality, theDepartment may require the pennittee to furnish such records directly to the Directoralong with a claim ofconfidentiality. [40 CFR 70.6(a)(6)(v) and Regulation 26,§26.701(F)(5)]

15. The pennittee must pay all pennit fees in accordance with the procedures established inRegulation 9. [40 CFR 70.6(a)(7) and Regulation 26, §26.701(G)]

16. No pennit revision shall be required, under any approved economic incentives,marketable pennits, emissions trading and other similar programs or processes forchanges provided for elsewhere in this pennit. [40 CFR 70.6(a)(8) and Regulation 26,§26.701(H)]

17. If the pennit allows different operating scenarios, the pennittee shall, contemporaneouslywith making a change from one operating scenario to another, record in a log at thepennitted facility a record of the operational scenario. [40 CFR 70.6(a)(9)(i) andRegulation 26, §26.701(I)(1)]

18. The Administrator and citizens may enforce under the Act all tenns and conditions in thispennit, including any provisions designed to limit a source's potential to emit, unless theDepartment specifically designates tenns and conditions of the pennit as being federallyunenforceable under the Act or under any of its applicable requirements. [40 CFR70.6(b) and Regulation 26, §26.702(A) and (B)]

19. Any document (including reports) required by this pennit must contain a certification bya responsible official as defined in Regulation 26, §26.2. [40 CFR 70.6(c)(l) andRegulation 26, §26.703(A)]

20. The pennittee must allow an authorized representative of the Department, uponpresentation of credentials, to perfonn the following: [40 CFR 70.6(c)(2) and Regulation26, §26.703(B)]

a. Enter upon the pennittee's premises where the pennitted source is located oremissions related activity is conducted, or where records must be kept under theconditions of this pennit;

b. Have access to and copy, at reasonable times, any records required under theconditions of this pennit;

c. Inspect at reasonable times any facilities, equipment (including monitoring and airpollution control equipment), practices, or operations regulated or required underthis pennit; and

37


d. As authorized by the Act, sample or monitor at reasonable times substances orparameters for assuring compliance with this permit or applicable requirements.

21. The permittee shall submit a compliance certification with the terms and conditionscontained in the permit, including emission limitations, standards, or work practices. Thepermittee must submit the compliance certification annually within 30 days following thelast day of the anniversary month of the initial Title V permit. The permittee must alsosubmit the compliance certification to the Administrator as well as to the Department.All compliance certifications required by this permit must include the following: [40CFR 70.6(c)(5) and Regulation 26, §26.703(E)(3)]

a. The identification of each term or condition of the permit that is the basis of thecertification;

b. The compliance status;c. Whether compliance was continuous or intermittent;d. The method(s) used for determining the compliance status of the source, currently

and over the reporting period established by the monitoring requirements of thispermit; and

e. Such other facts as the Department may require elsewhere in this permit or by§114(a)(3) and §504(b) ofthe Act.

22. Nothing in this permit will alter or affect the following: [Regulation 26, §26.704(C)]

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

b. The liability of the permittee for any violation of applicable requirements prior toor at the time of permit issuance;

c. The applicable requirements of the acid rain program, consistent with §408(a) ofthe Act; or

d. The ability of EPA to obtain information from a source pursuant to §114 oftheAct.

23. This permit authorizes only those pollutant emitting activities addressed in this permit.[AC.A. §8-4-203 as referenced by A.C.A. §8-4-304 and §8-4-311]

24. The permittee may request in writing and at least 15 days in advance of the deadline, anextension to any testing, compliance or other dates in this permit. No such extensions areauthorized until the permittee receives written Department approval. The Departmentmay grant such a request, at its discretion in the following circumstances:

a. Such an extension does not violate a federal requirement;b. The permittee demonstrates the need for the extension; andc. The permittee documents that all reasonable measures have been taken to meet

the current deadline and documents reasons it cannot be met.

38


[Regulation 18, §18.l02(C-D), Regulation 19, §19.103(D), A.c.A. §8-4-203 asreferenced by A.c.A. §8-4-304 and §8-4-311, and 40 CFR Part 52, Subpart E]

25. The permittee may request in writing and at least 30 days in advance, temporaryemissions and/or testing that would otherwise exceed an emission rate, throughputrequirement, or other limit in this permit. No such activities are authorized until thepermittee receives written Department approval. Any such emissions shall be included inthe facility's total emissions and reported as such. The Department may grant such arequest, at its discretion under the following conditions:

a. Such a request does not violate a federal requirement;b. Such a request is temporary in nature;c. Such a request will not result in a condition of air pollution;d. The request contains such information necessary for the Department to evaluate

the request, including but not limited to, quantification of such emissions and thedate/time such emission will occur;

e. Such a request will result in increased emissions less than five tons of anyindividual criteria pollutant, one ton of any single HAP and 2.5 tons of totalHAPs; and

f. The permittee maintains records of the dates and results of such temporaryemissions/testing.

[Regulation 18, §18.102(C-D), Regulation 19, §19.103(D), A.C.A. §8-4-203 asreferenced by A.C.A. §8-4-304 and §8-4-311, and 40 CFR Part 52, Subpart E]

26. The permittee may request in writing and at least 30 days in advance, an alternativeto the specified monitoring in this permit. No such alternatives are authorized until thepermittee receives written Department approval. The Department may grant such arequest, at its discretion under the following conditions:

a. The request does not violate a federal requirement;b. The request provides an equivalent or greater degree of actual monitoring to the

current requirements; andc. Any such request, if approved, is incorporated in the next permit modification

application by the permittee.

[Regulation 18, §18.102(C-D), Regulationl9, §19.103(D), A.C.A. §8-4-203 as referencedby A.C.A. §8-4-304 and §8-4-311, and 40 CFR Part 52, Subpart E]

39

APPENDIX A40 CFR Part 60, Subpart Da

Subpart Da-Standards of Performance for Electric UtilitySteam Generating Units forWhich Construction Is Commenced After September 18,1978

SOURCE: 44 FR 33613, June II, 1979, unless otherwisenoted.

§ 60.40a Applicability and designationof affected facility.

(a) The affected facility to which this subpartapplies is each electric utility steam generatingunit:

(l) That is capable of combusting more than 73megawatts (250 million Btulhour) heat input offossil fuel (either alone or in combination with anyother fuel); and

(2) For which construction or modification iscommenced after September 18, 1978.

(b) This subpart applies to electric utility combined cycle gas turbines that are capable of combusting more than 73 megawatts (250 million Btu!hour) heat input of fossil fuel in the steam generator. Only emissions resulting from combustion offuels in the steam generating unit are subject tothis subpart. (The gas turbine emissions are subjectto subpart GG.)

(c) Any change to an existing fossil-fuel-firedsteam generating unit to accommodate the use ofcombustible materials, other than fossil fuels. shallnot bring that unit under the applicability of thissubpart.

(d) Any change to an existing steam generatingunit originally designed to fire gaseous or liquidfossil fuels, to accommodate the use of any otherfuel (fossil or nonfossil) shall not bring that unitunder the applicability of this subpart.

§ 60.41a Definitions.

As used in this subpart, all terms not definedherein shall have the meaning given them in theAct and in subpart A of this part.

Steam generating unit means any furnace, boiler, or other device used for combusting fuel forthe purpose of producing steam (including fossilfuel-fired steam generators associated with combined cycle gas turbines; nuclear steam generatorsare not included).

Electric utility steam generating unit means anysteam electric generating unit that is constructedfor the purpose of supplying more than one-thirdof its potential electric output capacity and morethan 25 MW electrical output to any utility powerdistribution system for sale. Any steam supplied toa steam distribution system for the purpose of providing steam to a steam-electric generator thatwould produce electrical energy for sale is also

considered in detennining the electrical energyoutput capacity of the affected facility.

Fossil fUel means natural gas, petroleum, coal,and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.

Subbituminous coal means coal that is classifiedas subbituminous A, B, or C according to theAmerican Society of Testing and Materials(ASTM) Standard Specification for Classificationof Coals by Rank D388-77 (incorporated by reference-see §60.17).

Lignite means coal that is classified as lignite Aor B according to the American Society of Testingand Materials' (ASTM) Standard Specification forClassification of Coals by Rank D388-77 (incorporated by reference-see §60.17).

Coal refuse means waste products of coal mining, physical coal cleaning, and coal preparationoperations (e.g. culm, gob, etc.) containing coal,matrix material, clay, and other organic and inorganic material.

Potential combustion concentration means thetheoretical emissions (ngll, Ib/mi11ion Btu heatinput) that would result from combustion of a fuelin an uncleaned state without emission control systems) and:

(a) For particulate matter is:(I) 3,000 ngll (7.0 Ib/million Btu) heat input for

solid fuel; and(2) 75 ngll (0.17 Ib/million Btu) heat input for

liquid fuels.(b) For sulfur dioxide is determined under

§ 60.48a(b).(c) For nitrogen oxides is:(I) 290 ng/l (0.67 Ib/million Btu) heat input for

gaseous fuels;(2) 310 ng/l (0.72 Ib/million Btu) heat input for

liquid fuels; and(3) 990 ngll (2.30 Ib/million Btu) heat input for

solid fuels.Combined cycle gas turbine means a stationary

turbine combustion system where heat from theturbine exhaust gases is recovered by a steam generating unit.

Interconnected means that two or more electricgenerating units are electrically tied together by anetwork of power transmission lines, and otherpower transmission equipment.

Electric utility company means the largest interconnected organization, business, or governmentalentity that generates electric power for sale (e.g.,a holding company with operating subsidiary companies).

Principal company means the electric utilitycompany or companies which own the affected facility.

Neighboring company means anyone of thoseelectric utility companies with one or more electric

§60.41a

power interconnections to the principal companyand which have geographically adjoining serviceareas.

Net system capacity means the sum of the netelectric generating capability (not necessarily equalto rated capacity) of all electric generating equip.ment owned by an electric utility company (including steam generating units, internal combustion engines. gas turbines, nuclear units, hydroelectric units, and all other electric generatingequipment) plus finn contractual purchases thatare interconnected to the affected facility that hasthe malfunctioning flue gas desulfurization system.The electric generating capability of equipmentunder multiple ownership is prorated based onownership unless the proportional entitlement toelectric output is otherwise established by contractual arrangement.

System load means the entire electric demand ofan electric utility company's service area interconnected with the affected facility that has themalfunctioning flue gas desulfurization systemplus finn contractual sales to other electric utilitycompanies. Sales to other electric utility companies (e.g., emergency power) not on a finn contractual basis may also be included in the systemload when no available system capacity exists inthe electric utility company to which the power issupplied for sale.

System emergency reserves means an amount ofelectric generating capacity equivalent to the ratedcapacity of the single largest electric generatingunit in the electric utility company (includingsteam generating units, internal combustion engines, gas turbines, nuclear units, hydroelectricunits, and all other electric generating equipment)which is interconnected with the affected facilitythat has the malfunctioning flue gasdesulfurization system. The electric generating capability of equipment under multiple ownership isprorated based on ownership unless the proportional entitlement to electric output is otherwiseestablished by contractual arrangement.

Available system capacity means the capacitydetennined by subtracting the system load and thesystem emergency reserves from the net systemcapacity.

Spinning reserve means the sum of theunutilized net generating capability of all units ofthe electric utility company that are synchronizedto the power distribution system and that are capable of immediately accepting additional load. Theelectric generating capability of equipment undermultiple ownership is prorated based on ownershipunless the proportional entitlement to electric output is otherwise established by contractual arrangement.

Available purchase power means the lesser ofthe following:

2

(a) The sum of available system capacity in allneighboring companies.

(b) The sum of the rated capacities of the powerintercOlUlection devices between the principalcompany and all neighboring companies, minusthe sum of the electric power load on these interconnections.

(c) The rated capacity of the power transmissionlines between the power interconnection devicesand the electric generating units (the unit in theprincipal company that has the malfunctioning fluegas desulfurization system and the unit(s) in theneighboring company supplying replacement electrical power) less the electric power load on thesetransmission lines.

Spare flue gas desulfurization system modulemeanS a separate system of sulfur dioxide emission control equipment capable of treating anamount of flue gas equal to the total amount offlue gas generated by an affected facility when operated at maximum capacity divided by the totalnumber of nonspare flue gas desulfurization modules in the system.

Emergency condition means that period of timewhen:

(a) The electric generation output of an affectedfacility with a malfunctioning flue gasdesulfurization system cannot be reduced or electrical output must be increased because:

(I) All available system capacity in the principal company interconnected with the affected facility is being operated, and

(2) All available purchase power interconnectedwith the affected facility is being obtained, or

(b) The electric generation demand is beingshifted as quickly as possible from an affected facility with a malfunctioning flue gasdesulfurization system to one or more electricalgenerating units held in reserve by the principalcompany or by a neighboring company, or

(c) An affected facility with a malfunctioningflue gas desulfurization system becomes the onlyavailable unit to maintain a part or all of the principal company's system emergency reserves andthe unit is operated in spinning reserve at the lowest practical electric generation load consistentwith not causing significant physical damage tothe unit. If the unit is operated at a higher load tomeet load demand, an emergency condition wouldnot exist unless the conditions under (a) of thisdefinition apply.

Electric utility combined cycle gas turbinemeans any combined cycle gas turbine used forelectric generation that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25MW electrical output to any utility power distribution system for sale. Any steam distribution system that is constructed for the purpose of provid-

ing steam to a steam electric generator that wouldproduce electrical power for sale is also considered in detennining the electrical energy outputcapacity of the affected facility.

Potential electrical output capacity is defined as33 percent of the maximum design heat input capacity of the steam generating unit (e.g., a steamgenerating unit with a lO(}-MW (340 million Btu!hr) fossil-fuel heat input capacity would have a33~MW potential electrical output capacity}. Forelectric utility combined cycle gas turbines the potential electrical output capacity is detennined onthe basis of the fossil-fuel firing capacity of thesteam generator exclusive of the heat input andelectrical power contribution by the gas turbine.

Anthracite means coal that is classified as anthracite according to the American Society ofTesting and Materials' (ASTM) Standard Specification for Classification of Coals by Rank D388~

77 (incorporated by reference-see §60.17).Solid-derived fuel means any solid, liquid, or

gaseous fuel derived from solid fuel for the purpose of creating useful heat and includes, but isnot limited to, solvent refined coal, liquified coal,and gasified coal.

24-hour period means the period of time between 12:01 a.m. and 12:00 midnight.

Resource recovery unit means a facility thatcombusts more than 75 percent non-fossil fuel ona quarterly (calendar) heat input basis.

Noncontinental area means the State of Hawaii,the Virgin Islands, Guam, American Samoa, theCommonwealth of Puerto Rico, or the NorthernMariana Islands,

Boiler operating day means a 24-hour periodduring which fossil fuel is combusted in a steamgenerating unit for the entire 24 hours,

[44 FR 33613. June 11. 1979, as amended at 48 FR 3737.Jan. 27. 1983]

§ 60.42a Standard for particulate matter.

(a) On and after the date on which the performance test required to be conducted under § 60,8 iscompleted, no owner or operator subject to theprovisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases which contain particulate matter inexcess of:

(I) 13 ngll (0.03 Ib/million Btu) heat input derived from the combustion of solid, liquid, or gaseous fuel;

(2) I percent of the potential combustion concentration (99 percent reduction) when combustingsolid fuel; and

(3) 30 percent of potential combustion concentration (70 percent reduction) when combustingliquid fuel.

3

§60.43a

(b) On and after the date the particulate matterperfonnance test required to be conducted under§ 60.8 is completed, no owner or operator subjectto the provisions of this subpart shall cause to bedischarged into the atmosphere from any affectedfacility any gases which exhibit greater than 20percent opacity (6-minute average), except for one6-minute period per hour of not more than 27 percent opacity.

§ 60.43a Standard for sulfur dioxide.

(a) On and after the date on which the initialperfonnance test required to be conducted under§ 60.8 is completed, no owner or operator subjectto the provisions of this subpart shall cause to bedischarged into the atmosphere from any affectedfacility which combusts solid fuel or solid-derivedfuel, except as provided under paragraphs (c), (d),(I) or (h) of this section, any gases which containsulfur dioxide in excess of:

(I) 520 ngll (1.20 Ib/million Btu) heat input and10 percent of the potential combustion concentration (90 percent reduction), or

(2) 30 percent of the potential combustion concentration (70 percent reduction), when emissionsare less than 260 ngll (0.60 Ib/million Btu) heatinput.

(b) On and after the date on which the initialperfonnance test required to be conducted under§ 60.8 is completed, no owner· or operator subjectto the provisions of this subpart shall cause to bedischarged into the atmosphere from any affectedfacility which combusts liquid or gaseous fuels(except for liquid or gaseous fuels derived fromsolid fuels and as provided under paragraphs (e) or(h) of this section), any gases which contain sulfurdioxide in excess of:

(I) 340 ngll (0.80 Ib/million Btu) heat input and10 percent of the potential combustion concentration (90 percent reduction), or

(2) 100 percent of the potential combustion concentration (zero percent reduction) when emissionsare less than 86 ng/l (0.20 Ib/million Btu) heatinput.

(c) On and after the date on which the initialperfonnance test required to be conducted under§ 60.8 is complete, no owner or operator subject tothe provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility which combusts solid solvent refined coal(SRC-I) any gases which contain sulfur dioxide inexcess of 520 ngll (1.20 Ib/million Btu) heat inputand 15 percent of the potential combustion concentration (85 percent reduction) except as provided under paragraph (I) of this section; compliance with the emission limitation is detennined ona 30-day rolling average basis and compliancewith the percent reduction requirement is determined on a 24-hour basis.

§60.44a

Fuel type

Emission limit for heatinput

ides in excess of the following emission limits,based on a 30-day rolling average.

(l) NO. emission limits.

1 Exempt from NO~ standards and NO~ mOOitonng re-quirements.

2Any fuel containing !ess than 25%, by weight, lignite is nolprorated but its percenlage is added to the percentage of thepredominant fueL

(2) NOx reduction requirement.

Percent reduction of potential combus

tion concentra·tion

340 0.80

2'0 0.50280 0.60260 0.60260 0.60

ng/J (Ib/millionBtu)

210 0.5086 0.20

2'0 0.50210 0.50130 0.30

210 0.50

(') (')

Fuel type

Gaseous fuels:Coakferived fuels.All other fuels ....

Liquid fuels:Coal-derived fuels .Shale oil ....All other fuels.

Solid fuels:Coal-derived fuels .,.Any fuel containing more than

25%, by weight, coal refuseAny fuel containing more than

25%, by weight, lignite if thelignite is mined in North Da-kota, South Dakota, or Mon-tana, and is combusted in aslag tap fumace2 .

Any fuel containing more than25%, by weight, lignite notsubject to the 340 ng/J heatinput emission Iimit2..

Subbituminous coal .Bituminous coal .Anthracite coal ...All other fuels.

(2) If emissions of sulfur dioxide to the atmosphere are equal to or less than 260 ngll (0.60 Ib/million Btu) heat input:

E.~(340x+520 y)/IOO and%P.~IOx+30 y)/IOO

(d) Sulfur dioxide emissions are limited to 520ngll (1.20 Ib/million Btu) heat input from any affected facility which:

(I) Combusts 100 percent anthracite,(2) Is classified as a resource recovery facility,

or(3) Is located in a noncontinentaJ area and com

busts solid fuel or solid-derived fuel.(e) Sulfur dioxide emissions are limited to 340

ngll (0.80 Ib/million Btu) heat input from any affected facility which is located in a noncontinentalarea and combusts liquid or gaseous fuels (excluding solid-derived fuels).

(f) The emission reduction requirements underthis section do not apply to any affected facilitythat is operated under an S02 commercial demonstration pennit issued by the Administrator inaccordance with the provisions of § 60.45a.

(g) Compliance with the emission limitation andpercent reduction requirements under this sectionare both determined on a 30-day rolling averagebasis except as provided under paragraph (c) ofthis section.

(h) When different fuels are combusted simultaneously, the applicable standard is detennined byproration using the following fonnula:

(1) If emissions of sulfur dioxide to the atmosphere are greater than 260 ngll (0.60 Ib/millionBtu) heat input

E.~(340x+520 y)/IOO and%Ps=IO

where:

En is the applicable standard for nitrogen oxides whenmultiple fuels are combusted simultaneously (ngl)heat input);

w is the percentage of total heat input derived from thecombustion of fuels subject to the 86 ng/J heat inputstandard;

(b) The emission limitations under paragraph (a)of this section do not apply to any affected facilitywhich is combusting coal-derived liquid fuel andis operating under a commercial demonstrationpermit issued by the Administrator in accordancewith the provisions of § 60.45a.

(c) When two or more fuels are combusted simultaneously, the applicable standard is determined by proration using the following fonnula:

E,,~[86 w+130x+210 y+260 z+340 vVIOO

where:

E" is the prorated sulfur dioxide emission limit (ngl) heatinput),

%P" is the percentage of potential sulfur dioxide emissionallowed.

x is the percentage of total heat input derived from thecombustion of liquid or gaseous fuels (excludingsolid-derived fuels)

y is the percentage of total heat input derived from thecombustion of solid fuel (including solid-derivedfuels)

[44 FR 33613. June II. 1979. as amended at 54 FR 6663,Feb. 14. 1989; 54 FR 21344, May 17, 1989J

§ 6O.44a Standard for nitrogen oxides.(a) On and after the date on which the initial

perfonnance test required to be conducted under§ 60.8 is completed, no owner or operator subjectto the provisions of this subpart shall cause to bedischarged into the atmosphere from any affectedfacility, except as provided under paragraph (b) ofthis section, any gases which contain nitrogen ox-

Gaseous fuels ..Liquid fuelsSolid fuels ..

253065

4

§60.46a

eration capacity for all commercial demonstrationplants may not exceed 15,000 MW.

Equivalentelectrical ca-

Technology Pollutant pacity (MWelectrical out

put)

Solid solvent refined coal (SRCI) . So., 6.000-10,000

Fluidized bed combustion (at-mospheric) . 502 400-3,000

Fluidized bed combustion (pres~

surized) ... . 502 400-1,200Coalliquification . NOx 750-10,000

§ 60.46a Compliance provisions.

(a) Compliance with the particulate matter emission limitation under § 60.42a(a)(I) constitutescompliance with the percent reduction requirements for particulate matter under § 60.42a(a)(2)and (3).

(b) Compliance with the nitrogen oxides emission limitation under § 60.44a(a) constitutes compliance with the percent reduction requirementsunder § 60.44a(a)(2).

(c) The particulate matter emission standardsunder § 60.42a and the nitrogen oxides emissionstandards under § 60.44a apply at all times exceptduring periods of startup, shutdown, or malfimction. The sulfur dioxide emission standards under§ 60.43a apply at all times except during periodsof startup, shutdown. or when both emergencyconditions exist and the procedures under paragraph (d) of this section are implemented.

(d) During emergency conditions in the principal company, an affected facility with a malfunctioning flue gas desulfurization system may be operated if sulfur dioxide emissions are minimizedby:

(I) Operating all operable flue gasdesulfurization system modules. and bringing backinto operation any malfunctioned module as soonas repairs are completed.

(2) Bypassing flue gases around only those fluegas desulfurization system modules that have beentaken out of operation because they were incapable of any sulfur dioxide emission reduction orwhich would have suffered significant physicaldamage if they had remained in operation, and

(3) Designing, constructing, and operating aspare flue gas desulfurization system module foran affected facility larger than 365 MW 0,250million BtuIhr) heat input (approximately 125 MWelectrical output capacity). The Administrator mayat his discretion require the owner or operatorwithin 60 days of notification to demonstrate sparemodule capability, To demonstrate this capability,the owner or operator must demonstrate compli-

15,000Total allowable for atl

technOlogies ..

x is the percentage of total heat input derived from thecombustion of fuels subject to the 130 nglJ heatinput standard;

y is the percentage of total heat input derived from thecombustion of fuels subject to the 210 ngll heatinput standard;

z is the percentage of total heat input derived from thecombustion of fuels subject to the 260 oglJ heatinput standard; and

v is the percentage of total heat input delivered from thecombustion of fuels subject to the 340 ngll heatinput standard.

[44 FR 33613, June 11, 1979, as amended al 54 FR 6664,Feb. 14, 1989J

§ 60.45a Commercial demonstrationpermit.

(a) An owner or operator of an affected facilityproposing to demonstrate an emerging technologymay apply to the Administrator for a commercialdemonstration pennit. The Administrator will issuea commercial demonstration pennit in accordancewith paragraph (e) of this section. Commercialdemonstration permits may be issued only by theAdministrator, and this authority will not be delegated.

(b) An owner or operator of an affected facilitythat combusts solid solvent refined coal (SRC-I)and who is issued a commercial demonstrationpermit by the Administrator is not subject to theS02 emission reduction requirements under§ 60.43a(c) but must, as a minimum, reduce SO,emissions to 20 percent of the potential combustion concentration (80 percent reduction) for each24-hour period of steam generator operation and toless than 520 nglJ (1.20 Iblmillion Btu) heat inputon a 30-day rolling average basis.

(c) An owner or operator of a fluidized bedcombustion electric utility steam generator (atmospheric or pressurized) who is issued a commercialdemonstration pennit by the Administrator is notsubject to the S02 emission reduction requirements under § 60.43a(a) but must. as a minimum,reduce S02 emissions to 15 percent of the potential combustion concentration (85 percent reduction) on a 3D-day rolling average basis and to lessthan 520 nglJ 0.20 lblmillion Btu) heat input ona 30-day rolling average basis.

(d) The owner or operator of an affected facilitythat combusts coal-derived liquid fuel and who isissued a commercial demonstration permit by theAdministrator is not subject to the applicable NO,emission limitation and percent reduction under§ 60,44a(a) but must, as a minimum, reduce emissions to less than 300 nglJ (0.70 Iblmillion Btu)heat input on a 30-day rolling average basis,

(e) Commercial demonstration permits may notexceed the following equivalent MW electricalgeneration capacity for anyone technology category, and the total equivalent MW electrical gen-

5

§60.47a

ance with the appropriate requirements under paragraph (a), (b), (d), (e), and (h) under § 60.43a forany period of operation lasting from 24 hours to30 days when:

(i) Anyone flue gas desulfurization module isnot operated,

(ii) The affected facility is operating at the maximum heat input rate,

(iii) The fuel fired during the 24-hour to 30-dayperiod is representative of the type and averagesulfur content of fuel used over a typical 30-dayperiod, and

(iv) The owner or operator has given the Administrator at least 30 days notice of the date andperiod of time over which the demonstration willbe performed.

(e) After the initial perfonnance test requiredunder § 60.8, compliance with the sulfur dioxideemission limitations and percentage reduction requirements under § 60.43a and the nitrogen oxidesemission limitations under § 60.44a is based on theaverage emission rate for 30 successive boiler operating days. A separate perfonnance test is completed at the end of each boiler operating day afterthe initial performance test, and a new 30 day average emission rate for both sulfur dioxide and nitrogen oxides and a new percent reduction for sulfur dioxide are calculated to show compliancewith the standards.

(f) For the initial perfonnance test requiredunder § 60.8, compliance with the sulfur dioxideemission limitations and percent reduction requirements under § 60.43a and the nitrogen oxidesemission limitation under § 60.44a is based on theaverage emission rates for sulfur dioxide, nitrogenoxides, and percent reduction for sulfur dioxide forthe first 30 successive boiler operating days. Theinitial perfonnance test is the only test in whichat least 30 days prior notice is required unless otherwise specified by the Administrator. The initialperfonnance test is to be scheduled so that thefirst boiler operating day of the 30 successive boiler operating days is completed within 60 daysafter achieving the maximum production rate atwhich the affected facility will be operated, butnot later than 180 days after initial startup of thefacility.

(g) Compliance is determined by calculating thearithmetic average of all hourly emission rates forSO, and NOx for the 30 successive boiler operating days, except for data obtained during startup,shutdown, malfunction (NOx only), or emergencyconditions (SO, only). Compliance with the percentage reduction requirement for 802 is deter~

mined based on the average inlet and average outlet 802 emission rates for the 30 successive boileroperating days.

(h) If an owner or operator has not obtained theminimum quantity of emission data as required

6

under § 60.47a of this subpart, compliance of theaffected facility with the emission requirementsunder §§ 60.43a and 60.44a of this subpart for theday on which the 30-day period ends may be determined by the Administrator by following theapplicable procedures in section 7 of Method 19.

[44 FR 33613, June tl, 1979, as amended at 54 FR 6664,Feb. 14, t989]

§ 60.47a Emission monitoring.

(a) The owner or operator of an affected facilityshall install, calibrate, maintain, and operate a continuous monitoring system, and record the outputof the system, for measuring the opacity of emissions discharged to the atmosphere, except wheregaseous fuel is the only fuel combusted. If opacityinterference due to water droplets exists in thestack (for example, from the use of an FGD system), the opacity is monitored upstream of the interference (at the inlet to the FGD system). Ifopacity interference is experienced at all locations(both at the inlet and outlet of the sulfur dioxidecontrol system), alternate parameters indicative ofthe particulate matter control system's perfonnance are monitored (subject to the approval of theAdministrator).

(b) The owner or operator of an affected facilityshall install, calibrate, maintain, and operate a continuous monitoring system, and record the outputof the system, for measuring sulfur dioxide emissions, except where namral gas is the only fuelcombusted, as follows:

(I) Sulfur dioxide emissions are monitored atboth the inlet and outlet of the sulfur dioxide control device.

(2) For a facility which qualifies under the provisions of § 60.43a(d), sulfur dioxide emissions areonly monitored as discharged to the atmosphere.

(3) An "as fired" fuel monitoring system (upstream of coal pulverizers) meeting the requirements of Method 19 (appendix A) may be used todetennine potential sulfur dioxide emissions inplace of a continuous sulfur dioxide emissionmonitor at the inlet to the sulfur dioxide controldevice as required under paragraph (b)(I) of thissection.

(c) The owner or operator of an affected facilityshall install, calibrate, maintain, and operate a continuous monitoring system, and record the outputof the system, for measuring nitrogen oxides emissions discharged to the atmosphere.

(d) The owner or operator of an affected facilityshall install, calibrate, maintain, and operate a continuous monitoring system, and record the outputof the system, for measuring the oxygen or carbondioxide content of the flue gases at each locationwhere sulfur dioxide or nitrogen oxides emissionsare monitored.

§60.47a

where:x is the fraction of total heat input derived from gaseous

fossil fuel,y is the fraction of total heat input derived from liquid

fossil fuel, andz is the fraction of total heat input derived from solid fos

sil fuel.

able alternative methods and procedures are givenin paragraph (j) of this section.

(I) Methods 6, 7, and 3B, as applicable, shallbe used to detennine Oz, SOz. and NO" concentrations.

(2) SO, or NOx (NO), as applicable, shall beused for preparing the calibration gas mixtures (inN" as applicable) under Perfonnance Specification2 of appendix B of this part.

(3) For affected facilities burning only fossilfuel, the span value for a continuous monitoringsystem for measuring opacity is between 60 and80 percent and for a continuous monitoring systemmeasuring nitrogen oxides is detennined as follows:

(4) All span values computed under paragraph(b)(3) of this section for burning combinations offossil fuels are rounded to the nearest 500 ppm.

(5) For affected facilities burning fossil fuel,alone or in combination with non-fossil fuel. thespan value of the sulfur dioxide continuous monitoring system at the inlet to the sulfur dioxidecontrol device is 125 percent of the maximum estimated hourly potential emissions of the fuelfired, and the outlet of the sulfur dioxide controldevice is 50 percent of maximum estimated hourlypotential emissions of the fuel fired.

(j) The owner or operator may use the followingas alternatives to the reference methods and procedures specified in this section:

(I) For Method 6, Method 6A or 6B (wheneverMethods 6 and 3 or 3B data are used) or 6C maybe used. Each Method 6B sample obtained over 24hours represents 24 I-hour averages. If Method 6Aor 6B is used under paragraph (i) of this section,the conditions under § 60.46(d)(1) apply; theseconditions do not apply under paragraph (h) ofthis section.

(2) For Method 7, Method 7A, 7C, 7D, or 7Emay be used. If Method 7C, 7D, or 7E is used,the sampling time for each run shall be I hour.

(3) For Method 3, Method 3A or 3B may beused if the sampling time is 1 hour.

(e) The continuous monitoring systems underparagraphs (b), (c), and (d) of this section are operated and data recorded during all periods of operation of the affected facility including periods ofstartup, shutdown. malfunction or emergency conditions, except for continuous monitoring systembreakdowns. repairs, calibration checks, and zeroand span adjustments.

(I) The owner or operator shall obtain emissiondata for at least 18 hours in at least 22 out of 30successive boiler operating days. If this minimumdata requirement cannot be met with a continuousmonitoring system, the owner or operator shallsupplement emission data with other monitoringsystems approved by the Administrator or the reference methods and procedures as described inparagraph (h) of this section,

(g) The I-hour averages required under paragraph § 60.13(h) are expressed in ngll (lbslmillionBtu) heat input and used to calculate the averageemission rates under § 60.46a. The I-hour averages are calculated using the data points requiredunder § 60.13(b). At least two data points must beused to calculate the I-hour averages.

(h) When it becomes necessaly to supplementcontinuous monitoring system data to meet theminimum data requirements in paragraph (f) ofthis section, the owner or operator shall use thereference methods and procedures as specified inthis paragraph. Acceptable alternative methods andprocedures are given in paragraph (j) of this section.

(I) Method 6 shall be used to detennine theSOz concentration at the same location as the SOzmonitor. Samples shall be taken at 60-minute intervals. The sampling time and sample volume foreach sample shall be at least 20 minutes and 0.020dscm (0.71 dscl). Each sample represents a I-houraverage.

(2) Method 7 shall be used to detennine theNO)!: concentration at the same location as theNO" monitor. Samples shall be taken at 30-minuteintervals. The arithmetic average of two consecutive samples represents a I-hour average.

(3) The emission rate correction factor, integrated bag sampling and analysis procedure ofMethod 3B shall be used to detennine the 0, orCOz concentration at the same location as the Ozor CO2 monitor. Samples shall be taken for atleast 309 minutes in each hour. Each sample represents a I-hour average.

(4) The procedures in Method 19 shall be usedto compute each I-hour average concentration inngll (Ib/million Btu) heat input.

(i) The owner or operator shall use methods andprocedures in this paragraph to conduct monitoringsystem perfonnance evaluations under § 60.13(c)and calibration checks under § 60.13(d). Accept-

7

Fossil fuel

Gas.Liquid .....Solid.Combination .

Span value for nitrogen oxides (ppm)

500500

1,000500 (x+y)+1,OOOz

§60.48a

(4) For Method 38, Method 3A may be used.

[44 FR 33613. June II, 1979, as amended at 54 FR 6664,Feb. t 4, 1989; 55 FR 5212, Feb. 14, 1990; 55 FR 18876,May 7, 1990J

§ 60.48a Compliance determinationprocedures and methods.

(a) In conducting the performance tests requiredin § 60.8, the owner or operator shaH use as reference methods and procedures the methods in appendix A of this part or the methods and procedures as specified in this section, except as provided in § 60.8(b). Section 60.8(1) does not applyto this section for S02 and NOx. Acceptable alternative methods are given in paragraph (e) of thissection.

(b) The owner or operator shall determine compliance with the particulate matter standards in§60.42a as follows:

(I) The dry basis F factor (0,) procedures ioMethod ]9 shall be used to compute the emissionrate of particulate matter.

(2) For the particular matter concentration,Method 5 shall be used at affected facilities without wet FGD systems aod Method 58 shall beused after wet FGD systems.

(i) The sampling time and sample volume foreach run shall be at least 120 minutes and 1.70dscm (60 dscl). The probe and filter holder heating system in the sampling train may be set toprovide an average gas temperature of no greaterthan 160±14 "C (320±25 "F).

(ii) For each particulate run, the emission ratecorrection factor, integrated or grab sampling andanalysis procedures of Method 3B shall be used todetennine the 02 concentration. The O2 sampleshall be obtained simultaneously with, and at thesame traverse points as, the particulate run. If theparticulate run has more than 12 traverse points,the 02 traverse points may be reduced to J2 provided that Method I is used to locate the 12 0,traverse points. If the grab sampling procedure isused, the 02 concentration for the run shall be thearithmetic mean of all the individual O2 concentrations at each traverse point.

(3) Method 9 and the procedures in § 60.11shaIl be used to determine opacity.

(c) The owner or operator shall detennine compliance with the SO, standards in § 60.43a as follows:

(I) The percent of potential SO, emissions(%P,) to the atmosphere shaIl be computed usingthe foIlowing equation:

%P.=[(IOQ--%Rr) (IOQ--%R,)]/100

where:%Ps=percent of potential S02 emissions, percent.%RFPercent reduction from fuel pretreatment, percent.%Rg=percent reduction by S02 control system, percent.

8

(2) The procedures in Method 19 may be usedto determine percent reduction (%Rr) of sulfur bysuch processes as fuel pretreatment (physical coalcleaning, hydrodesulfurization of fuel oil, etc,),coal pulverizers, and bottom and flyash interactions. This determination is optional.

(3) The procedures in Method 19 shall be usedto determine the percent S02 reduction (%Rg ofany S02 control system. Alternatively, a combination of an "as fired" fuel monitor and emissionrates measured after the control system, followingthe procedures in Method 19, may be used if thepercent reduction is calculated using the averageemission rate from the S02 control device and theaverage S02 input rate from the "as fired" fuelanalysis for 30 successive boiler operating days.

(4) The appropriate procedures in Method 19shall be used to determine the emission rate.

(5) The continuous monitoring system in§ 60.47a (b) and (d) shall be used to determine theconcentrations of S02 and C02 or 02.

(d) The owner or operator shall determine compliance with the NOx standard in § 60.44a as follows:

(I) The appropriate procedures in Method 19shall be used to determine the emission rate ofNOx_

(2) The continous monitoring system in § 60.47a(c) and (d) shall be used to determine the concentrations of NOx and CO2 or 02.

(e) The owner or operator may use the following as alternatives to the reference methods andprocedures specified in this section:

(I) For Method 5 or 58, Method 17 may beused at facilities with or without wet FGD systemsif the stack temperature at the sampling locationdoes not exceed an average temperature of 160 °c(320 "F). The procedures of §§ 2, I and 2.3 ofMethod 58 may be used in Method 17 only if itis used after wet FGD systems, Method 17 shallnot be used after wet FGD systems if the effluentis saturated or laden with water droplets.

(2) The F, factor (C02) procedures in Method19 may be used to compute the emission rate ofparticulate matter under the stipulations of§ 60.46(d)(I). The C02 shall be determined in thesame manner as the 02 concentration.

(I) Electric utility combined cycle gas turbinesare performance tested for particulate matter, sulfur dioxide, and nitrogen oxides using the procedures of Method 19 (appendix A), The sulfur dioxide and nitrogen oxides emission rates from thegas turbine used in Method 19 (appendix A) calculations are determined when the gas turbine isperformance tested under subpart GG. The potential uncontrolled particulate matter emission rate

from a gas turbine is defined as 17 ng/J (0.04 Iblmillion Btu) heat input.

[44 FR 33613, June II, 1979, as amended al54 FR 6664,Feb. 14, 1989; 55 FR 5212, Feb. 14, 1990]

§ 60.49a Reporting requirements.

(a) For sulfur dioxide, nitrogen oxides, and particulate matter emissions, the performance test datafrom the initial perfonnance test and from the performance evaluation of the continuous monitors(including the transmissometer) are submitted tothe Administrator.

(b) For sulfur dioxide and nitrogen oxides thefollowing information is reported to the Administrator for each 24-hour period.

(I) Calendar date.(2) The average sulfur dioxide and nitrogen

oxide emission rates (nglJ or Ib/million Btu) foreach 30 successive boiler operating days, endingwith the last 30-day period in the quarter; reasonsfor non-compliance with the emission standards;and, description of corrective actions taken.

(3) Percent reduction of the potential combustion concentration of sulfur dioxide for each 30successive boiler operating days, ending with thelast 30-day period in the quarter; reasons for noncompliance with the standard; and, description ofcorrective actions taken.

(4) Identification of the boiler operating daysfor which pollutant or dilutent data have not beenobtained by an approved method for at least 18hours of operation of the facility; justification fornot obtaining sufficient data; and description ofcorrective actions taken.

(5) Identification of the times when emissionsdata have been excluded from the calculation ofaverage emission rates because of startup, shutdown, malfunction (NOx only), emergency conditions (S02 only), or other reasons, and justificationfor excluding data for reasons other than startup,shutdown, malfunction, or emergency conditions.

(6) Identification of "F" factor used for calculations, method of detennination, and type offuel combusted.

(7) Identification of times when hourly averageshave been obtained based on manual samplingmethods.

(8) Identification of the times when the pollutant concentration exceeded full span of the continuous monitoring system.

(9) Description of any modifications to the continuous monitoring system which could affect theability of the continuous monitoring system tocomply with Performance Specifications 2 or 3.

(c) If the minimum quantity of emission data asrequired by § 60.47a is not obtained for any 30successive boiler operating days, the following information obtained under the requirements of

9

§60.49a

§ 60.46a(h) is reported to the Administrator forthat 30-day period:

(1) The number of hourly averages available foroutlet emission rates (no) and inlet emission rates(n.) as applicable.

(2) The standard deviation of hourly averagesfor outlet emission rates (so) and inlet emissionrates (Si) as applicable.

(3) The lower confidence limit for the meanoutlet emission rate (Eo*) and the upper confidence limit for the mean inlet emission rate (Ei*)as applicable.

(4) The applicable potential combustion concentration.

(5) The ratio of the upper confidence limit forthe mean outlet emission rate (Eo*) and the allowable emission rate (Estd) as applicable.

(d) If any standards under § 60.43a are exceededduring emergency conditions because of controlsystem malfunction, the owner or operator of theaffected facility shall submit a signed statement:

(I) Indicating if emergency conditions existedand requirements nnder § 60.46a(d) were met during each period, and

(2) Listing the following information:(i) Time periods the emergency condition ex

isted;(ii) Electrical output and demand on the owner

or operator's electric utility system and the affected facility;

(iii) Amount of power purchased from interconnected neighboring utility companies duringthe emergency period;

(iv) Percent reduction in emissions achieved;(v) Atmospheric emission rate (ng/J) of the pol

lutant discharged; and(vi) Actions taken to correct control system

malfunction.(e) If fuel pretreatment credit toward the sulfur

dioxide emission standard under § 60.43a isclaimed, the owner or operator of the affected facility shall submit a signed statement:

(I) Indicating what percentage cleaning creditwas taken for the calendar quarter, and whetherthe credit was detennined in accordance with theprovisions of § 60.48a and Method 19 (appendixA); and

(2) Listing the quantity, heat content, and dateeach pretreated fuel shipment was received duringthe previous quarter; the name and location of thefuel pretreatment facility; and the total quantityand total heat content of all fuels received at theaffected facility during the previous quarter.

(f) For any periods for which opacity. sulfur dioxide or nitrogen oxides emissions data are notavailable, the owner or operator of the affected facility shall submit a signed statement indicating ifany changes were made in operation of the emission control system during the period of data un-

§60.49a

availability. Operations of the control system andaffected facility during periods of data unavailability are to be compared with operation of thecontrol system and affected facility before and following the period of data unavailability.

(g) The owner or operator of the affected facility shall submit a signed statement indicatingwhether:

(1) The required continuous mODitoring systemcalibration, span, and drift checks or other periodicaudits have or have not been perfonned as specified.

(2) The data used to show compliance was orwas not obtained in accordance with approvedmethods and procedures of this part and is representative of plant perfonnance.

(3) The minimum data requirements have orhave not been met~ or, the minimum data require-

ments have not been met for errors that were unavoidable.

(4) Compliance with the standards has or hasnot been achieved during the reporting period.

(h) For the purposes of the reports requiredunder § 60.7, periods of excess emissions are defined as all 6-minute periods during which the average opacity exceeds the applicable opacity standards under §60.42a(b). Opacity levels in excess ofthe applicable opacity standard and the date ofsuch excesses are to be submitted to the Administrator each calendar quarter.

(i) The owner or operator of an affected facilityshall submit the written reports required under thissection and subpart A to the Administrator forevery calendar quarter. All quarterly reports shallbe postmarked by the 30th day following the endof each calendar quarter.

10

APPENDIXB40 CFR Part 60, Subpart GG

111111111111111111111111111111111111111111111111111111111

(i) Peak load means 100 percent of the manufacturer's design capacity of the gas turbine at ISOstandard day conditions.

(j) Base load means the load level at which agas turbine is normally operated.

(k) Fire-fighting turbine means any stationarygas turbine that is used solely to pump water forextinguishing fires.

(I) Turbines employed in oil/gas production oroil/gas transportation means any stationary gasturbine used to provide power to extract crude oillnatural gas from the earth or to move crude oillnatural gas, or products refined from these substances through pipelines.

(m) A Metropolitan Statistical Area or MSA asdefined by the Department of Commerce.

(n) Offshore platform gas turbines means anystationary gas turbine located on a platfonn in anocean.

(0) Garrison facility means any pennanent military installation.

(P) Gas turbine model means a group of gasturbines having the same nomina! air flow,combuster inlet pressure, combuster inlet temperature, firing temperature, turbine inlet temperatureand turbine inlet pressure.

(q) Electric utility stationary gas turbine meansany stationary gas turbine constructed for the purpose of supplying more than one-third of its potential electric output capacity to any utility powerdistribution system for sale.

(r) Emergency fuel is a fuel fired by a gas turbine only during circumstances, such as naturalgas supply curtailment or breakdown of deliverysystem, that make it impossible to fire natural gasin the gas turbine.

(s) Regenerative cycle gas turbine means anystationary gas turbine that recovers thennal energyfrom the exhaust gases and utilizes the thermal energy to preheat air prior to entering the combustor.

[44 FR 52798, Sept. 10, 1979, as amended at 47 FR3770, Jan. 27, 1982J

§60.332 Standard for nitrogen oxides.(a) On and after the date of the performance test

required by § 60.8 is completed, every owner oroperator subject to the provisions of this subpartas specified in paragraphs (b), (c), and (d) of thissection shall comply with one of the following,except as provided in paragraphs (e), (I), (g), (h),(i), (j), (k), and (I) of this section.

(I) No owner or operator subject to the provisions of this subpart shall cause to be dischargedinto the atmosphere from any stationary gas turbine, any gases which contain nitrogen oxides inexcess of:

Subpart GG-Standards of Performance for Stationary GasTurbines

§ 60.330 Applicability and designationof affected facility.

(a) The provisions of this subpart are applicableto the following affected facilities: All stationarygas turbines with a heat input at peak load equalto or greater than 10.7 gigajoules per hour. basedon the lower heating value of the fuel fired.

(b) Any facility under paragraph (a) of this section which commences construction, modification,or reconstruction after October 3, 1977. is subjectto the requirements of this part except as providedin paragraphs (e) and OJ of § 60.332.

[44 FR 52798, Sept. 10, 1979, as amended at 52 FR42434, Nov. 5, 1987J

§ 60.331 Definitions.

As used in this subpart, all terms not definedherein shall have the meaning given them in theAct and in subpart A of this part.

(a) Stationary gas turbine means any simplecycle gas turbine. regenerative cycle gas turbine orany gas turbine portion of a combined cyclesteam/electric generating system that is not selfpropelled. It may, however, be mounted on a vehicle for portability.

(b) Simple cycle gas turbine means any stationary gas turbine which does not recover heat fromthe gas turbine exhaust gases to preheat the inletcombustion air to the gas turbine, or which doesnot recover heat from the gas turbine exhaustgases to heat water or generate steam.

(c) Regenerative cycle gas turbine means anystationary gas turbine which recovers heat fromthe gas turbine exhaust gases to preheat the inletcombustion air to the gas turbine.

(d) Combined cycle gas turbine means any stationary gas turbine which recovers heat from thegas turbine exhaust gases to heat water or generatesteam.

(e) Emergency gas turbine means any stationarygas turbine which operates as a mechanical orelectrical power source only when the primarypower source for a facility has been rendered inoperable by an emergency situation.

(f) Ice fog means an atmospheric suspension ofhighly reflective ice crystals.

(g) ISO standard day conditions means 288 degrees Kelvin, 60 percent relative humidity and101.3 kilopascals pressure.

(h) Efficiency means the gas turbine manufacturer's rated heat rate at peak load in terms of heatinput per unit of power output based on the lowerheating value of the fuel.

STD ~ 0.0075(14.4)

Y+ F

§60.332

where:

N=the nitrogen content of the fuel (percent by weight).or:

where:

STD=allowable NO" emissions (percent by volume at 15percent oxygen and on a dry basis).

Y=manufacturer's rated heat rate at manufacturer's ratedpeak load (kilojoules per watt hour), or actual measured heat rate based on lower heating value of fuelas measured at actual peak load for the facility. Thevalue of Y shall not exceed 14.4 kilojoules per watthour.

F=NOl( emission allowance for fuel-bound nitrogen as defined in paragraph (a)(3) of this section.

(3) F shall be defined according to the nitrogencnntent of the fuel as follows:

where:

STD=allowable NO>; emissions (percent by volume at 15percent oxygen and on a dry basis).

Y=manufacturer's rated heat rale at manufacturer's ratedload (kilojoules per watt hour) or, actual measuredheat rate based on lower heating value of fuel asmeasured at actual peak load for the facility. Thevalue of Y shall not exceed 14.4 kilojoules per wanhour.

F=NO,. emission allowance for fuel-bound nitrogen as defined in paragraph (a)(3) of this section.

(2) No owner or operator subject to the provisions of this subpart shall cause to be dischargedinto the atmosphere from any stationary gas turbine, any gases which contain nitrogen oxides inexcess of:

Manufacturers may develop custom fuel-bound nitrogen allowances for each gas turbine model theymanufacture. These fuel-bound nitrogen allowances shall be substantiated with data and must beapproved for use by the Administrator before theinitial perfonnance test required by § 60.8. Noticesof approval of custom fuel-bound nitrogen allowances will be published in the FEDERAL REGISTER.

(b) Electric utility stationary gas turbines with aheat input at peak load greater than 107.2gigajoules per hour (J 00 million Btu/hour) basedon the lower heating value of the fuel fired shallcomply with the provisions of paragraph (a)(I) ofthis section.

(c) Stationary gas turbines with a heat input atpeak load equal to or greater than 10.7 gigajoulesper hour (10 million Btu/hour) but less than or

equal to 107.2 gigajoules per hour (100 millionBtu/hour) based on the lower heating value of thefuel fired, shall comply with the provisions ofparagraph (a)(2) of this section.

(d) Stational)' gas turbines with a manufacturer's rated base load at ISO conditions of 30megawatts or less except as provided in§ 60.332(b) shall comply with paragraph (a)(2) ofthis section.

(e) Stationary gas turbines with a heat input atpeak load equal to or greater than 10.7 gigajoulesper hour (10 million Btu/hour) but less than orequal to 107.2 gigajoules per hour (100 millionBtu/hour) based on the lower heating value of thefuel fired and that have commenced constructionprior to October 3, ]982 are exempt from paragraph (a) of this section.

(f) Stationary gas turbines using water or steaminjection for control of NOl( emissions are exemptfrom paragraph (a) when ice fog is deemed a traffic hazard by the owner or operator of the gas turbine.

(g) Emergency gas turbines, military gas turbines for use in other than a ganison facility, military gas turbines installed for use as military training facilities, and fire fighting gas turbines are exempt from paragraph (a) of this section.

(h) Stationary gas turbines engaged by manufacturers in research and development of equipmentfor both gas turbine emission control techniquesand gas turbine efficiency improvements are exempt from paragraph (a) on a case-by-case basisas detennined by the Administrator.

(i) Exemptions from the requirements of paragraph (a) of this section will be granted on a caseby-case basis as determined by the Administratorin specific geographical areas where mandatorywater restrictions are required by governmentalagencies because of drought conditions. These exemptions will be allowed only while the mandatory water restrictions are in effect.

(j) Stationary gas turbines with a heat input atpeak load greater than 107.2 gigajoules per hourthat commenced construction, modification, or reconstruction between the dates of October 3, 1977,and January 27, 1982, and were required in theSeptember 10, 1979, FEDERAL REGISTER (44 FR52792) to comply with paragraph (a)(I) of thissection, except electric utility stationary gas turbines, are exempt from paragraph (a) of this section.

(k) Stational)' gas turbines with a heat inputgreater than or equal to 10.7 gigajoules per hour(10 million Btu/hour) when fired with natural gasare exempt from paragraph (a)(2) of this sectionwhen being fired with an emergency fuel

(I) Regenerative cycle gas turbines with a heatinput less than or equal to 107.2 gigajoules per

+ F

F (NO~ percent byvolume)

oO.04{N)

O.004+0.0067(N--D.1 )0.005

(14.4)

YSTD ~ 0.0150

Fuel-bound nitrogen (percent byweight)

NSO.015 ...O.015<NsO.1O.1<NsO.25N>025.

2

hour (l00 million Btu/hour) are exempt from paragraph (a) of this section.

[44 FR 52798, Sept. 10, 1979, as amended at 47 FR3770, Jan. 27, 1982J

§ 60.333 Standard for sulfur dioxide.

On and after the date on which the performancetest required to be conducted by § 60.8 is completed, every owner or operator subject to the provision of this subpart shall comply with one or theother of the following conditions:

(a) No owner or operator subject to the provisions of this subpart shall cause to be dischargedinto the atmosphere from any stationary gas turbine any gases which contain sulfur dioxide in excess of 0.015 percent by volume at 15 percent oxygen and on a dry basis.

(b) No owner or operator subject to the provisions of this subpart shall bum in any stationarygas turbine any fuel which contains sulfur in excess of 0.8 percent by weight.

[44 FR 52798, Sept. 10, 1979J

§ 60.334 Monitoring of operations.

(a) The owner or operator of any stationary gasturbine subject to the provisions of this subpartand using water injection to control NOx emissions shall install and operate a continuous monitoring system to monitor and record the fuel consumption and the ratio of water to fuel being firedin the turbine. This system shall be accurate towithin ±5.0 percent and shall be approved by theAdministrator.

(b) The uwner or operator of any stationary gasturbine subject to the provisions of this subpartshall monitor sulfur content and nitrogen contentof the fuel being fired in the turbine. The frequency of determination of these values shall beas follows:

(I) If the turbine is supplied its fuel from a bulkstorage tank, the values shall be determined oneach occasion that fuel is transferred to the storagetank from any other source.

(2) If the turbine is supplied its fuel without intermediate bulk storage the values shall be determined and recorded daily. Owners, operators orfuel vendors may develop custom schedules fordetermination of the values based on the designand operation of the affected facility and the characteristics of the fuel supply. These custom schedules shall be substantiated with data and must beapproved by the Administrator before they can beused to comply with paragraph (b) of this section.

(c) For the purpose of reports required under§ 60,7(c), periods of excess emissions that shall bereported are defined as follows:

(l) Nitrogen oxides. Anyone-hour period duringwhich the average water-la-fuel ratio, as measured

3

§60.335

by the continuous monitoring system, falls belowthe water-ta-fuel ratio detennined to demonstratecompliance with § 60.332 by the performance testrequired in § 60.8 or any period during which thefuel-bound nitrogen of the fuel is greater than themaximum nitrogen content allowed by the fuelbound nitrogen allowance used during the performance test required in § 60.8. Each report shallinclude the average water-la-fuel ratio, averagefuel consumption, ambient conditions, gas turbineload, and nitrogen content of the fuel during theperiod of excess emissions, and the graphs or figures developed under § 60.335(a).

(2) Sulfur dioxide. Any daily period duringwhich the sulfur content of the fuel being fired inthe gas turbine exceeds 0.8 percent.

(3) Ice fog. Each period during which an exemption provided in § 60.332(g) is in effect shallbe reported in writing to the Administrator quarterly. For each period the ambient conditions existing during the period, the date and time the airpollution control system was deactivated, and thedate and time the air pollution control system wasreactivated shall be reported. All quarterly reportsshall be postmarked by the 30th day following theend of each calendar quarter.

(4) Emergency fitel. Each period during whichan exemption provided in § 60.332(k) is in effectshall be included in the report required in§60.7(c). For each period, the type, reasons, andduration of the firing of the emergency fuel shallbe reported.

[44 FR 52798, Sept. to, 1979, as amended at 47 FR3770, Jan, 27, 1982]

§ 60.335 Test methods and procedures.

(a) To compute the nitrogen oxides emissions,the owner or operator shall use analytical methodsand procedures that are accurate to within 5 percent and are approved by the Administrator to detennine the nitrogen content of the fuel beingfired.

(b) In conducting the perfonnance tests requiredin § 60.8, the owner or operator shall use as reference methods and procedures the test methods inappendix A of this part or other methods and procedures as specified in this section, except as provided for in § 60.8(b). Acceptable alternativemethods and procedures are given in paragraph (I)of this section.

(c) The owner or operator shall detennine compliance with the nitrogen oxides and sulfur dioxidestandards in §§ 60.332 and 60.333(a) as follows:

(I) The nitrogen oxides emission rate (NO,)shall be computed for each run using the following equation:

NOx=(NOl<o) (P..IPo) 0.5 eI9(Ho-0.OO633) (288°KfTa) l..53

where:

§60.335

NO,.=emission rate of NO" at 15 percent 02 and ISOstandard ambient conditions, volume percent.

NOlto=observed NO" concentration, ppm by volume.Pr=reference combustor inlet absolute pressure at 101.3

kilopascals ambient pressure, mm Hg.Po=observed combustor inlet absolute pressure at test, mm

Hg.Ho=observed humidity of ambient air, g H20/g air.e=transcendental constant, 2.718.TlI=ambient temperature, oK.

(2) The monitoring device of §60.334(a) shallbe used to determine the fuel consumption and thewater-la-fuel ratio necessary to comply with§ 60.332 at 30, 50, 75, and 100 percent of peakload or at four points in the normal operatingrange of the gas turbine, including the minimumpoint in the range and peak load. All loads shallbe corrected to ISO conditions using the appropriate equations supplied by the manufacturer.

(3) Method 20 shall be used to determine thenitrogen oxides. sulfur dioxide, and oxygen concentrations. The span values shall be 300 ppm ofnitrogen oxide and 2] percent oxygen. The NOx

emissions shall be determined at each of the loadconditions specified in paragraph (c)(2) of thissection.

(d) The owner or operator shall determine compliance with the sulfur content standard in§ 60.333(b) as follows: ASTM D 2880-71 shall beused to determine the sulfur content of liquid fuelsand ASTM D 1072-80, D 3031-81, D 4084-82,or D 3246-81 shall be used for the sulfur contentof gaseous fuels (incorporated by reference-see§ 60.17). The applicable ranges of some ASTM

4

methods mentioned above are not adequate tomeasure the levels of sulfur in some fuel gases.Dilution of samples before analysis (with verification of the dilution ratio) may be used, subject tothe approval of the Administrator.

(e) To meet the requirements of § 60.334(b), theowner or operator shall use the methods specifiedin paragraphs (a) and (d) of this section to determine the nitrogen and sulfur contents of the fuelbeing burned. The analysis may be performed bythe owner or operator, a service contractor retainedby the owner or operator, the fuel vendor, or anyother qualified agency.

(t) The owner or operator may use the following as alternatives to the reference methods andprocedures specified in this section:

(I) Instead of using the equation in paragraph(b)(I) of this section, manufacturers may developambient condition correction factors to adjust thenitrogen oxides emission level measured by theperformance test as provided in § 60.8 to ISOstandard day conditions. These factors are developed for each gas turbine model they manufacturein tenns of combustion inlet pressure, ambient airpressure, ambient air humidity, and ambient airtemperature. They shall be substantiated with dataand must be approved for use by the Administrator before the initial perfonnance test requiredby § 60.8. Notices of approval of custom ambientcondition correction factors will be published inthe FEDERAL REGISTER.

[54 FR 6675, Feb. 14. 1989. as amended at 54 FR 27016,June 27, 1989]

APPENDIXCADEQ CEM Systems Conditions

Arkansas Department of Environmental Quality

CONTINUOUS EMISSION MONITORING SYSTEMSCONDITIONS

Revised August 2004

PREAMBLE

These conditions are intended to outline the requirements for facilities required to operate Continuous EmissionMonitoring Systems/Continuous Opacity Monitoring Systems (CEMS/COMS). Generally there are three types ofsources required to operate CEMS/COMS:

1. CEMS/COMS required by 40 CFR Part 60 or 63,2. CEMS required by 40 CFR Part 75,3. CEMS/COMS required by ADEQ permit for reasons other that Part 60,63 or 75.

These CEMS/COMS conditions are not intended to supercede Part 60,63 or 75 requirements.

• Only CEMS/COMS in the third category (those required by ADEQ permit for reasons other than Part 60,63, or 75) shall comply with SECTION II, MONITORING REQUIREMENTS and SECTION IV,QUALITY ASSURANCE/QUALITY CONTROL.

• All CEMS/COMS shall comply with Section ill, NOTIFICATION AND RECORDKEEPING.

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SECTION I

DEFINITIONS

Continuous Emission Monitoring System (CEMS) - The total equipment required for the determination of a gasconcentration and/or emission rate so as to include sampling, analysis and recording of emission data.

Continuous Opacity Monitoring System (COMS) - The total equipment required for the determination ofopacityas to include sampling, analysis and recording of emission data.

Calibration Drift (CD) - The difference in the CEMS output reading from the established reference value after astated period ofoperation during which no unscheduled maintenance, repair, or adjustments took place.

Back-up CEMS (Secondary CEMS) - A CEMS with the ability to sample, analyze and record stack pollutant todetermine gas concentration and/or emission rate. This CEMS is to serve as a back-up to the primary CEMS tominimize monitor downtime.

Excess Emissions - Any period in which the emissions exceed the permit limits.

Monitor Downtime - Any period during which the CEMS/COMS is unable to sample, analyze and record aminimum of four evenly spaced data points over an hour, except during one daily zero-span check during which twodata points per hour are sufficient.

Out-of-Control Period - Begins with the time corresponding to the completion ofthe fifth, consecutive, daily CDcheck with a CD in excess of two times the allowable limit, or the time corresponding to the completion ofthe dailyCD check preceding the daily CD check that results in a CD in excess of four times the allowable limit and the timecorresponding to the completion ofthe sampling for the RATA, RAA, or CGA which exceeds the limits outlined inSection IV. Out-of-Control Period ends with the time corresponding to the completion of the CD check followingcorrective action with the results being within the allowable CD limit or the completion of the sampling of thesubsequent successful RATA, RAA, or CGA.

Primary CEMS - The main reporting CEMS with the ability to sample, analyze, and record stack pollutant todetermine gas concentration and/or emission rate.

Relative Accuracy (RA) - The absolute mean difference between the gas concentration or emission ratedetermined by the CEMS and the value determined by the reference method plus the 2.5 percent errorconfidence coefficient of a series of tests divided by the mean of the reference method tests of the applicableemission limit.

Span Value - The upper limit of a gas concentration measurement range.

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SECTION II

MONITORING REQUIREMENTS

A. For new sources, the installation date for the CEMS/COMS shall be no later than thirty (30) days from thedate of start-up of the source.

B. For existing sources, the installation date for the CEMS/COMS shall be no later than sixty (60) days fromthe issuance of the permit unless the permit requires a specific date.

C. Within sixty (60) days of installation of a CEMS/COMS, a performance specification test (PST) must becompleted. PST's are defined in 40 CFR, Part 60, Appendix B, PS 1-9. The Department may acceptalternate PST's for pollutants not covered by Appendix B on a case-by-case basis. Alternate PST's shall beapproved, in writing, by the ADEQ CEM Coordinator prior to testing.

D. Each CEMS/COMS shall have, as a minimum, a daily zero-span check. The zero-span shall be adjustedwhenever the 24-hour zero or 24-hour span drift exceeds two times the limits in the applicable performancespecification in 40 CFR, Part 60, Appendix B. Before any adjustments are made to either the zero or spandrifts measured at the 24-hour interval the excess zero and span drifts measured must be quantified andrecorded.

E. All CEMS/COMS shall be in continuous operation and shall meet minimum frequency of operationrequirements of95% up-time for each quarter for each pollutant measured. Percent ofmonitor down-timeis calculated by dividing the total minutes the monitor is not in operation by the total time in the calendar

quarter and multiplying by one hundred. Failure to maintain operation time shall constitute a violation oftheCEMS conditions.

F. Percent ofexcess emissions are calculated by dividing the total minutes ofexcess emissions by the total timethe source operated and multiplying by one hundred. Failure to maintain compliance may constitute aviolation ofthe CEMS conditions.

G. All CEMS measuring emissions shall complete a minimum ofone cycle ofoperation (sampling, analyzing,and data recording) for each successive fifteen minute period unless more cycles are required by the permit.For each CEMS, one-hour averages shall be computed from four or more data points equally spaced overeach one hour period unless more data points are required by the permit.

H. All COMS shall complete a minimum ofone cycle ofsampling and analyzing for each successive 10-secondperiod and one cycle ofdata recording for each successive 6-minute period.

I. When the pollutant from a single affected facility is released through more than one point, a CEMS/COMSshall be installed on each point unless installation of fewer systems is approved, in writing, by the ADEQCEM Coordinator. When more than one CEMICOM is used to monitor emissions from one affected facilitythe owner or operator shall report the results as required from each CEMS/COMS.

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SECTION III

NOTIFICATION AND RECORD KEEPING

A. When requested to do so by an owner or operator, the ADEQ CEM Coordinator will review plans forinstallation or modification for the purpose ofproviding technical advice to the owner or operator.

B. Each facility which operates a CEMS/COMS shall notify the ADEQ CEM Coordinator ofthe date for whichthe demonstration of the CEMS/COMS performance will commence (i.e. PST, RATA, RAA, CGA).Notification shall be received in writing no less than 15 days prior to testing. Performance test results shalIbe submitted to the Department within thirty days after completion of testing.

C. Each facility which operates a CEMS/COMS shall maintain records of the occurrence and duration of startup/shut down, cleaning/soot blowing, process problems, fuel problems, or other malfunction in the operationof the affected facility which causes excess emissions. This includes any malfunction of the air polIutioncontrol equipment or any period during which a continuous monitoring device/system is inoperative.

D. Except for Part 75 CEMs, each facility required to install a CEMS/COMS shall submit an excess emissionand monitoring system performance report to the Department (Attention: Air Division, CEM Coordinator)at least quarterly, unless more frequent submittals are warranted to assess the compliance status of thefacility. Quarterly reports shall be postmarked no later than the 30th day of the month following the end ofeach calendar quarter. Part 75 CEMs shall submit this information semi-annualIy and as part ofTitle V six(6) month reporting requirement if the facility is a Title V facility.

E. AIl excess emissions shall be reported in terms ofthe applicable standard. Each report shall be submitted onADEQ Quarterly Excess Emission Report Forms. Alternate forms may be used with prior written approvalfrom the Department.

F. Each facility which operates a CEMS/COMS must maintain on site a file ofCEMS/COMS data including alIraw data, corrected and adjusted, repair logs, calibration checks, adjustments, and test audits. This file mustbe retained for a period ofat least five years, and is required to be maintained in such a condition that it caneasily be audited by an inspector.

G. Except for Part 75 CEMs, quarterly reports shalI be used by the Department to determine compliancewith the permit. For Part 75 CEMs, the semi-annual report shall be used.

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SECTION IV

QUALITY ASSURANCE/QUALITY CONTROL

A. For each CEMS/COMS a Quality Assurance/Quality Control (QAlQC) plan shall be submitted to theDepartment (Attn.: Air Division, CEM Coordinator). CEMS quality assurance procedures are defined in 40CFR, Part 60, Appendix F. This plan shall be submitted within 180 days ofthe CEMS/COMS installation.A QAlQC plan shall consist of procedure and practices which assures acceptable level of monitor dataaccuracy, precision, representativeness, and availability.

B. The submitted QAlQC plan for each CEMS/COMS shall not be considered as accepted until the facilityreceives a written notification of acceptance from the Department.

C. Facilities responsible for one, or more, CEMS/COMS used for compliance monitoring shall meet theseminimum requirements and are encouraged to develop and implement a more extensive QAlQC program, orto continue such programs where they already exist. Each QAlQC program must include written procedureswhich should describe in detail, complete, step-by-step procedures and operations for each ofthe followingactivities:

1. Calibration of CEMS/COMSa. Daily calibrations (including the approximate time(s) that the daily zero and span

drifts will be checked and the time required to perform these checks and return tostable operation)

2. Calibration drift determination and adjustment of CEMS/COMSa. Out-of-control period determinationb. Steps of corrective action

3. Preventive maintenance ofCEMS/COMSa. CEMS/COMS information

1) Manufacture2) Model number3) Serial number

b. Scheduled activities (check list)c. Spare part inventory

4. Data recording, calculations, and reporting5. Accuracy audit procedures including sampling and analysis methods6. Program of corrective action for malfunctioning CEMS/COMS

D. A Relative Accuracy Test Audit (RATA), shall be conducted at least once every four calendar quarters.A Relative Accuracy Audit (RAA), or a Cylinder Gas Audit (CGA), may be conducted in the other threequarters but in no more than three quarters in succession. The RATA should be conducted in accordancewith the applicable test procedure in 40 CFR Part 60 Appendix A and calculated in accordance with theapplicable performance specification in 40 CFR Part 60 Appendix B. CGA's and RAA's should beconducted and the data calculated in accordance with the procedures outlined on 40 CFR Part 60Appendix F.

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If alternative testing procedures or methods of calculation are to be used in the RATA, RAA orCGA audits prior authorization must be obtained from the ADEQ CEM Coordinator.

E. Criteria for excessive audit inaccuracy.

RATAAll Pollutants

> 20% Relative Accuracyexcept Carbon

Monoxide

Carbon Monoxide > 10% Relative AccuracyAll Pollutantsexcept Carbon > 10% of the Applicable Standard

Monoxide

Carbon Monoxide > 5% of the Applicable StandardDiluent (02 & CO2) > 1.0%02orC02

Flow > 20% Relative Accuracy

eGA

Pollutant> 15% ofaverage audit valueor 5 ppm difference

Diluent (02 & CO2)> 15% ofaverage audit valueor 5 ppm difference

RAA

> 15% of the three runPollutant average or > 7.5 % of the

applicable standard

> 15% of the three runDiluent (02 & CO2) average or > 7.5 % of the

applicable standard

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F. If either the zero or span drift results exceed two times the applicable drift specification in 40 CFR, Part60, Appendix B for five consecutive, daily periods, the CEMS is out-of-control. If either the zero orspan drift results exceed four times the applicable drift specification in Appendix B during a calibrationdrift check, the CEMS is out-of-control. Ifthe CEMS exceeds the audit inaccuracies listed above, theCEMS is out-of-control. If a CEMS is out-of-control, the data from that out-of-control period is notcounted towards meeting the minimum data availability as required and described in the applicablesubpart. The end ofthe out-of-control period is the time corresponding to the completion of thesuccessful daily zero or span drift or completion of the successful CGA, RAA or RATA.

G. A back-up monitor may be placed on an emission source to minimize monitor downtime. This back-upCEMS is subject to the same QAlQC procedure and practices as the primary CEMS. The back-up CEMSshall be certified by a PST. Daily zero-span checks must be performed and recorded in accordance withstandard practices. When the primary CEMS goes down, the back-up CEMS may then be engaged tosample, analyze and record the emission source pollutant until repairs are made and the primary unit isplaced back in service. Records must be maintained on site when the back-up CEMS is placed in service,these records shall include at a minimum the reason the primary CEMS is out of service, the date and timethe primary CEMS was out of service and the date and time the primary CEMS was placed back in service.

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APPENDIXDCLEAN AIR INTERSTATE RULE PERMIT

APPLICATION

TITLE V PERMITSUPPLEMENTAL PACKAGE

CLEAN AIR INTERSTATE RULE PERMIT APPLICATIONAFIN: 70-00543 I IDate: IJanuary 10,2008

1. UNIT INFORMATIONEnter the Source ill and Description (as identified in your Arkansas Title V Permit).

Source Number DescriptionSN-Ol GE CTffiRSG with duct burners, natural gas-fired

SN-02 GE CTIHRSG with duct burners, natural gas-fired

SN-03 GE CTffiRSG with duct burners, natural gas-fired

SN-04 GE CT/HRSG with duct burners, natural gas-fired


SN-06 GE CTffiRSG with duct burners, natural gas-fired


SN-08 GE CT/HRSG with duct burners, natural gas-fired

2. STANDARD REQUIREMENTSRead the standard requirements and the certification. Enter the name of the CArR designatedrepresentative, and sign and date. Include the supplemental application along with a completedArkansas Operating Permit (Major Source) General Information Forms (pages 1-6). TheDepartment will process a modification to the facility's Title V permit to incorporate these CArRrequirements.

NO, Ozone Season Emission Requirements§ 96.306 Standard requirements(a) Permit requirements.(1) The CArR designated representative ofeach CArR NOx Ozone Season source required tohave a title V operating permit and each CArR NOx Ozone Season unit required to have a title Voperating permit at the source shall:(i) Submit to the permitting authority a complete CArR permit application under §96.322 inaccordance with the deadlines specified in §96.321(a) and (b); and(ii) Submit in a timely manner any supplemental information that the permitting authoritydetermines is necessary in order to review a CAIR permit application and issue or deny a CArRpermit.(2) The owners and operators of each CArR NOx Ozone Season source required to have a title Voperating permit and each CArR NOx Ozone Season unit required to have a title V operatingpermit at the source shall have a CAIR permit issued by the permitting authority under subpartCCCC of40 CFR part 96 for the source and operate the source and the unit in compliance withsuch CArR permit.(3) Except as provided in subpart IIIr of 40 CFR part 96, the owners and operators of a CArRNOx Ozone Season source that is not otherwise required to have a title V operating permit and

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111111111111111111111111111111111111111111111111111111

each CAIR NOx Ozone Season unit that is not otherwise required to have a title V operatingpennit are not required to submit a CAIR pennit application, and to have a CAIR pennit, undersubpart CCCC of 40 CFR part 96 for such CAIR NOx Ozone Season source and such CAIR NOxOzone Season unit.

(b) Monitoring, reporting, and recordkeeping requirements.(1) The owners and operators, and the CAIR designated representative, of each CAIR NOxOzone Season source and each CAIR NOx Ozone Season unit at the source shall comply with themonitoring, reporting, and recordkeeping requirements of subpart HHHH of 40 CFR part 96.(2) The emissions measurements recorded and reported in accordance with subpart HHHH of 40CFR part 96 shall be used to detennine compliance by each CAIR NOx Ozone Season sourcewith the CAIR NOx Ozone Season emissions limitation under paragraph (c) of this §96.306.

(c) Nitrogen oxides ozone season emission requirements.(1) As of the allowance transfer deadline for a control period, the owners and operators of eachCAIR NOx Ozone Season source and each CAIR NOx Ozone Season unit at the source shallhold, in the source's compliance account, CAIR NOx Ozone Season allowances available forcompliance deductions for the control period under §96.354(a) in an amount not less than thetons of total nitrogen oxides emissions for the control period from all CAIR NOx Ozone Seasonunits at the source, as detennined in accordance with subpart HHHH of this part.(2) A CAIR NOx Ozone Season unit shall be subject to the requirements under paragraph (c)(l)of this §96.306 starting on the later of May 1, 2009 or the deadline for meeting the unit's monitorcertification requirements under §96.370(b)(1), (2), (3), or (7) and for each control periodthereafter.(3) A CAIR NOx Ozone Season allowance shall not be deducted, for compliance with therequirements under paragraph (c)(I) of §96.306, for a control period in a calendar year before theyear for which the CAIR NOx Ozone Season allowance was allocated.(4) CAIR NOx Ozone Season allowances shall be held in, deducted from, or transferred into oramong CAIR NOx Ozone Season Allowance Tracking System accounts in accordance withsubparts, FFFF, GGGG of 40 CFR part 96 and Chapter 14 of the Arkansas Pollution Control andEcology Commission Regulation 19, Regulations of the Arkansas Plan of Implementation for AirPollution Control.(5) A CAIR NOx Ozone Season allowance is a limited authorization to emit one ton of nitrogenoxides in accordance with the CAIR NOx Ozone Season Trading Program. No provision of theCAIR NOx Ozone Season Trading Program, the CAIR pennit application, the CAIR pennit, oran exemption under §96.305 and no provision oflaw shall be construed to limit the authority ofthe State or the United States to tenninate or limit such authorization.

. (6) A CAIR NOx Ozone Season allowance does not constitute a property right.(7) Upon recordation by the Administrator under subpart FFFF, GGGG of this part or Chapter 14of the Arkansas Pollution Control and Ecology Commission Regulation 19, Regulations oftheArkansas Plan of Implementation for Air Pollution Control, every allocation, transfer, ordeduction of a CAIR NOx Ozone Season allowance to or from a CAIR NOx Ozone Seasonsource's compliance account is incorporated automatically in any CAIR pennit of the source.

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(d) Excess emissions requirements.(I) If a CAIR NOx Ozone Season source emits nitrogen oxides during any control period inexcess of the CAIR NOx Ozone Season emissions limitation, then:(i) The owners and operators ofthe source and each CAIR NOx Ozone Season unit at the sourceshall surrender the CAIR NOx Ozone Season allowances required for deduction under§96.354(d)(I) and pay any fine, penalty, or assessment or comply with any other remedyimposed, for the same violations, under the Clean Air Act or applicable State law; and(ii) Each ton of such excess emissions and each day of such control period shall constitute aseparate violation of this subpart, the Clean Air Act, and applicable State law.

(e) Recordkeeping and reporting requirements.(1) Unless otherwise provided, the owners and operators of the CAIR NOx Ozone Season sourceand each CAIR NOx Ozone Season unit at the source shall keep on site at the source each of thefollowing documents for a period of 5 years from the date the document is created. This periodmay be extended for cause, at any time before the end of 5 years, in writing by the permittingauthority or the Administrator.(i) The certificate of representation under §96.313 for the CAIR designated representative for thesource and each CAIR NOx Ozone Season unit at the source and all documents that demonstratethe truth of the statements in the certificate of representation; provided that the certificate anddocuments shall be retained on site at the source beyond such 5-year period until such documentsare superseded because of the submission of a new certificate of representation under §96.313changing the CAIR designated representative.(ii) All emissions monitoring information, in accordance with subpart HHHH of 40 CFR part 96,provided that to the extent that subpart HHHH of 40 CFR part 96 provides for a 3-year period forrecordkeeping, the 3-year period shall apply.(iii) Copies of all reports, compliance certifications, and other submissions and all records madeor required under the CAIR NOx Ozone Season Trading Program.(iv) Copies of all documents used to complete a CAIR permit application and any othersubmission under the CAIR NOx Ozone Season Trading Program or to demonstrate compliancewith the requirements of the CAIR NOx Ozone Season Trading Program.(2) The CAIR designated representative of a CAIR NOx Ozone Season source and each CAIRNOx Ozone Season unit at the source shall submit the reports required under the CAIR NOxOzone Season Trading Program, including those under subpart HHHH of 40 CFR part 96.

(f) Liability.(1) Each CAIR NOx Ozone Season source and each CAIR NOx Ozone Season unit shall meetthe requirements of the CAIR NOx Ozone Season Trading Program.(2) Any provision of the CAIR NOx Ozone Season Trading Program that applies to a CAIR NOxOzone Season source or the CAIR designated representative of a CAIR NOx Ozone Seasonsource shall also apply to the owners and operators of such source and of the CAIR NOx OzoneSeason units at the source.(3) Any provision ofthe CAIR NOx Ozone Season Trading Program that applies to a CAIR NOxOzone Season unit or the CAIR designated representative of a CAIR NOx Ozone Season unitshall also apply to the owners and operators of such unit.

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(g) Effect on other authorities.No provision of the CAIR NOx Ozone Season Trading Program, a CAIR permit application, aCAIR permit, or an exemption under §96.305 shall be construed as exempting or excluding theowners and operators, and the CAIR designated representative, of a CAIR NOx Ozone Seasonsource or CAIR NOx Ozone Season unit from compliance with any other provision of theapplicable, approved State implementation plan, a federally enforceable permit, or the Clean AirAct.

3. CERTIFICATIONI am authorized to make this submission on behalf of the owners and operators of the source orunits for which the submission is made. I certify under penalty of law that I have personallyexamined, and am familiar with, the statements and information submitted in this document andall its attachments. Based on my inquiry of those individuals with primary responsibility forobtaining the information, I certify that the statements and infonnation are to the best of myknowledge and belief true, accurate, and complete. I an1 aware that there are significant penaltiesfor submitting false statements and information or omitting required statements and information,including the possibility of fine or imprisonment.

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Date /"It> -

, . . .~ -. ".,J ,.. ,. ,

CERTIFICATE OF SERVICE

I, Cynthia Hook, hereby certify that a copy of this pennit has been mailed by first class mail to

I'J/it"Union Power Partners, L.P., 6434 Calion Highway, El Dorado, AR, 71730, on this~day

of April, 2009.

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