ADEQ€¦ · Arkansas Air Pollution Control Code, Regulation 18, effective January 25, 2009 r Regulations ofthe Arkansas Plan ofImplementation for Air Pollution Control, Regulation

ADEQARKANSASDepartment of Environmental Quality

February 9, 2009

Katie RollinsAlberto-Culver Company2407 Quality Way - Craighead Technology ParkJonesboro,AR 72401

Dear Mr. Rollins:

The enclosed Permit No. 2138-AR-2 is your authority to construct, operate, and maintain theequipment and/or control apparatus as set forth in your application initially received on9/29/2008.

After considering the facts and requirements of A.c.A. §8-4-10l et seq., and implementingregulations, I have determined that Permit No. 21 38-AR-2 for the construction, operation andmaintenance of an air pollution control system for Alberto-Culver Company 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,

u~Mike BatesChief, Air Division

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

www.odeq.stote.or.us

ION 4, 5, 5, 5................................................................................................ 7, 8, 9ORMATION 10IVITIES 15)NS 16

c - Standards ofPerformance for Small Industrialrlerating Units

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Alberto-Culver CompanyPermit #: 2138-AR-2AFIN: 16-00968

List of Acronyms and Abbreviations

A.C.A.

AFIN

CFR

CO

HAP

lb/hr

No.

NOx

PM

PMlO

SOz

Tpy

UTM

VOC

Arkansas Code Annotated

ADEQ Facility Identification Number

Code of Federal Regulations

Carbon Monoxide

Hazardous Air Pollutant

Pound Per Hour

Number

Nitrogen Oxide

Particulate Matter

Particulate Matter Smaller Than Ten Microns

Sulfur Dioxide

Tons Per Year

Universal Transverse Mercator

Volatile Organic Compound

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Section I: FACILITY INFORMATION

PERMITTEE:

AFIN:

PERMIT NUMBER:

FACILITY ADDRESS:

MAILING ADDRESS:

COUNTY:

CONTACT NAME:

CONTACT POSITION:

Alberto-Culver Company

16-00968

2138-AR-2

2407 Quality Way - Craighead Technology ParkJonesboro, AR 72401

2407 Quality Way - Craighead Technology ParkJonesboro, AR 72401

Craighead County

Katie Rollins

TELEPHONE NUMBER: 870-972-1600

REVIEWING ENGINEER: Jennifer Boyette

UTM North South (Y):

UTM East West (X):

Zone 15: 396.68 m

Zone 15: 720.16 m

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Section II: INTRODUCTION

Summary of Permit Activity

Alberto-Culver Compay operates a hair products manufactuing facility at 2407 Quality WayCraighead Technology Park, Jonesboro, AR 72401. With this deminimis modifications thefacility proposes to: correct the emissions for SN-05 (Boilers 1 and 2) to reflect three smallercapacity boilers (7.876 MMBtu, 4.184 MMBtu gas fired boiler, and 11.8 MMBtu/hr gas firedboilers) that were substituted for larger boilers (two 21.46 MMBtu gas fired boilers) originallyplanned for the installation, remove the brand specific restrictions in SN-06 & SN-07 replacingthem with content limits in order to allow greater flexibility, and increase the volume of ink from13 to 26 gallons per year and the volume of face plate cleaner from 9 to 18 gallons per year atSN-07. The permitted emissions changes are: -0.5 tpy PMIPM IO , +0.1 tpy SOz, -0.5 tpy VOC,-6.8 tpy CO, and -8.3 tpy NOx.

Process Description

Alberto-Culver uses a variety of raw materials in the compounding process including propyleneglycol, surfactants (ammonium lauryl sulfate (ALS) & sodium lauryl sulfate (SLS)), perfumes,preservatives, solids, purified water, ethanol, etc. Most raw materials arrive at the facility bytruck in portable storage containers and are to be unloaded at the receiving docks, and thenplaced into racks for storage prior to being used for compounding products. The compoundingtanks are either heated or cooled according to the compounding formulae and process for thewater-based products.

After the compounding or mixing process, products are piped directly to the filling lines wherevarious bottles, tubes, jars, etc. are filled. In some cases, after the compounding or mixingprocess, product is transferred to portable tanks, and then transported to the filling lines.Following the filling process, the containers of products are packaged and then shipped to adistribution center off-site.

Compounding tanks and portable tanks are cleaned between batches. The initial rinse materialsare placed into a waste storage tank. The subsequent rinsates from the tank cleaning processesare to be discharged to the City of Jonesboro Wastewater Utility under a wastewater dischargepermit with the utility. The waste product will be periodically removed from the site for energyrecovery.

The largest ingredient in the majority of products is purified water. The site is planning a waterpurification system (i.e., reverse-osmosis (R.O.) water system) for this purpose.

The ethanol will be unloaded through a fixed location with a pipe connection and pump totransfer the material to the two (2) 10,000-gallon storage tanks (SN-03A and SN-03B), whichwill be vented to a passive carbon filtration system for controlled emissions. For the ethanolbased products, the compounding tanks are unheated. A 3,OOO-gallon waste ethanol tank (SN-

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04) will also be vented through this adsorber system. Compounding and filling for products thatwill be ethanol-based will be completed in a separate processing area. These products willinclude a non-aerosol hair spray and body splash. The compounding and filling area emissionsfrom ethanol and other VOCs will be vented through an overhead exhaust system to a secondcarbon filtration system to control emissions.

The facility installed two (2) gas-fired boilers SN-05A and SN-05B (one 7.876 MMBtu gas-firedboiler and one 4.184 MMBtu gas fired boiler) and is planning on installing a third SN-05C (11.8MMBtu gas-fired boiler). Steam generated from the boilers will be used in heating ofprocesstanks, as needed, during mixing of the products. The facility also has planned a closed loopchiller system to cool down product temperatures, when necessary, during the process.

Inkjet coders for labeling of bottle and products (SN-06) and labeling machines for outerpackaging and shipping boxes (SN-07) will be used in the packaging area of the facility and willbe another source of fugitive emissions.

Water Based Product Manufacturing (SN-OIA-C)

Shampoo Product Manufacturing. For shampoo products, surfactants are charged to a heatedvessel containing purified water. Following the mixing for the surfactants, the vessel is cooledprior to adding preservatives and perfumes. Following the addition ofperfume andpreservatives, the product is transferred to the filling lines to fill containers. The shampoocontainers are then packaged and shipped.

Body Wash Product Manufacturing. For body wash products, surfactants are charged to a heatedvessel containing purified water. Following the mixing for the surfactants, the vessel is cooledprior to adding preservatives and perfumes. Following the addition of perfume andpreservatives, the product is transferred to the filling lines to fill containers. The body washcontainers are then packaged and shipped.

Conditioner Product Manufacturing. For conditioner product manufacture, preservatives andperfumes are added to compounding vessels containing solids and deionized water. Once thishas been completed, the product is transferred to the filling lines, where product containers arefilled. The conditioner product containers are then packaged and shipped.

Gel Product Manufacturing. For the gel product, propylene glycol is added to a compoundingtank then heated for mixing. Prior to addition of perfumes and preservatives, vessel is cooled.After the addition of perfume and preservatives, the gel product is transferred to the filling lines,where product containers are filled. The gel product containers are then packaged and shipped.

Lotion Product Manufacturing. Propylene glycol is added to a compounding vessel, which isthen heated to mix the ingredients. Following the mixing, the vessel is cooled and thenpreservatives and perfumes are added to the formula. After the product is completely mixed, it istransferred to the filling lines, where product containers are filled and labeled. The productcontainers are then packaged and shipped.

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Relaxer Product Manufacturing. Propylene glycol is charged into the compounding vessel,which is then heated according to the formulation. Prior to the addition of preservatives andperfumes, the compounding tank vessel is cooled. After the product is mixed, the product istransferred to the filling line where product containers are filled. Containers of the relaxerproduct are then packaged and shipped.

Scrub Product Manufacturing. Propylene glycol is charged into a heated compounding vesselcontaining deionized water and solids. After mixing the propylene glycol, the surfactants areadded to the compounding vessel. Perfumes and preservatives are added to the vessel after thevessel has been cooled. After the product has been mixed for the specified time, the product istransferred to the filling line to fill product containers. After the scrub product containers arefilled, then the product containers are packaged and shipped.

Ethanol Based Product Manufacturing (SN-02)

Non-Aerosol Hair Spray and Body Splash. Alberto-Culver will use I ,SaO-gallon mixing tanks tomanufacture and store hair sprays and body splash. The primary components for these productsare ethanol, perfumes, and powders. Ethanol from storage tanks will be pumped into the mixingtanks. All tanks are closed during the mixing process, and are located inside an enclosed processarea for ethanol-based products. The tanks have mixers and are vented to a series of carbonadsorbers containing activated carbon. These tanks are not heated. Solid materials are added toeach tank during the mixing operation. The solid materials include waxes, flakes, granularpellets and powder materials. The waxes and flaked material are large particles. This productionoperation is a batch operation with one batch requiring approximately two hours for mixing.Following mixing, the batch will remain in the tank and then proceed to one of two bottle fillinglines.

The VOC emissions from the mixing tanks come from the displaced ethanol vapor when thetanks are filled. During mixing operation, the tanks are covered with negligible air emissions areexpected. The displaced vapor during the filling operation of these tanks is vented to activatedcarbon canisters to provide VOC emissions control. The total volume displaced from the tankmixing and filling lines is assumed to be twice the volume of the prod

Regulations

The following table contains the regulations applicable to this permit.

IIRegulations

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

r Regulations of the Arkansas Plan ofImplementation for Air Pollution Control,Regulation 19, effective January 25,2009

i 40 CFR 60, Subpart Dc - Standards ofPerformance for Small Industrial-CommercialInstitutional Steam Generating Units

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Alberto-Culver CompanyPermit #: 2l38-AR-2AFIN: 16-00968

Total Allowable Emissions

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

TOTAL ALLOWABLE EMISSIONS

Emission RatesPollutant

lb/hr tpy

PM 0.6 2.0

PMIO 0.6 2.0

S0 2 0.3 0.3

VOC 4.2 9.5

CO 2.1 8.8

NOx 2.5 10.3

Benzene 0.60 2.20

Formaldehyde 0.01 0.03

Methanol 0.7 2.4

Acetone 1.4 1.3

Total HAP 1.31 4.63

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Section III: PERMIT HISTORY

Permit 2138-A was issued on July 03, 2008. Alberto requested permission to install thenecessary equipment for both a Water Based Production Area (SN-OIA-C) and an EthanolBased Production Area (SN-02) for compounding and filling. For the Ethanol Based products,Alberto requested permission to install two (2) Ethanol Storage Tanks (SN-03A and SN-03B)and an Ethanol Waste Tank (SN-04). Alberto also requested to install two (2) 21.46 MMBtuBoilers (SN-05A and SN-05B) to generate steam for products requiring heat duringcompounding or filling. After filling is complete, Alberto codes the products either at the fillline area with ink jet coders (SN-06) or at the kit area with marsh coders (SN-07). The totalpermitted emissions for the facility were: 2.5 tpy ofPM/PMlO, 0.2 tpy of S02, 10.0 tpy ofVOC,15.6 tpy of CO, and 18.6 tpy ofNOx.

Permit 2138-AR-l was issued on March 31,2008. This permit De Minimis modification allowedfor the addition of two emission stacks to the Water Based Production Area for a total of threeemission stacks (SN-OIA-C). The total permitted emissions for the facility remained unchanged.

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Section IV: EMISSION UNIT INFORMATION

Specific Conditions

1. The permittee shall not exceed the emission rates set forth in the following table.[Regulation 19, §19.501 et seq., and A.C.A. §8-4-203 as referenced by A.C.A. §8-4-304and §8-4-311]

SN Description Pollutant Ib/hr tpy

SN-OIA-CWater Based Production PM lO 0.1 0.3

(Compounding and Filling) VOC 1.9 7.0

SN-02Ethanol Based Production PMlO 0.2 0.8

(Compounding and Filling) VOC 0.1 0.1SN-03A Ethanol Storage Tank #1 VOC 0.1 0.1SN-03B Ethanol Storage Tank #2 VOC 0.1 0.1---SN-04 Ethanol Waste Tank VOC 0.1 0.1

Natural Gas Fired Boiler #1 PM lO 0.1 0.2(4.184 MMBtu/hr) S02 0.1 0.1

SN-05A Clayton Industries VOC 0.1 0.1Model SEG- I00 CO 0.4 1.6Serial No. 24592 NOx 0.5 1.8


SN-05B Clayton Industries VOC O. I 0.2Model SEG-204-1 CO 0.7 2.9Serial No. 24209 NOx 0.8 3.4


SN-05C Clayton Industries VOC 0.1 0.3Model SEG-304 CO 1.0 4.3Serial No. 24762 NOx 1.2 5. I

SN-06 Labeling of bottle and products VOC 1.4 1.3

SN-07Labeling of Outer Packaging

VOC 0.2 0.2and Shipping boxes

2. The permittee shall not exceed the emission rates set forth in the following table.[Regulation 18, §18.801 and A.C.A. §8-4-203 as referenced by A.C.A. §8-4-304 and §84-311 ]

SN Description Pollutant Ib/hr tpvWater Based PM 0.1 0.3

SN-OIA-CProduction Benzene 0.60 2.20

(Compounding & Formaldehyde 0.01 0.03Filling) Methanol 0.30 1.10

SN-02 Ethanol Based PM 0.2 0.8

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SN Descrintion Pollutant Ib/br tpvProduction

(Compounding andFilling)

SN-05ANatural Gas Fired

PM 0.1 0.2Boiler #1

SN-05BNatural Gas Fired

PM 0.1 0.3Boiler #2

SN-05CNatural Gas Fired

PM 0.1 0.4Boiler #3

SN-06Labeling ofbottle Methanol 0.4 1.3

and products Acetone 1.4 1.3

3. Visible emissions may not exceed the limits specified in the following table of this permitas measured by EPA Reference Method 9. [AC.A §8-4-203 as referenced by A.C.A.§8-4-304 and §8-4-311]

SN Limit Regulatory Citation

SN-OIA-C 20% §19.503

SN-02 20% §19.503

SN-05A 5% §19.503

SN-05B 5% §19.503

4. The permittee shall not cause or permit the emission of air contaminants, including odorsor water vapor and including an air contaminant whose emission is not otherwiseprohibited by Regulation 18, if the emission of the air contaminant constitutes airpollution within the meaning ofAC.A §8-4-303. [Regulation 18, §18.801 andAC.A §8-4-203 as referenced by A.C.A §8-4-304 and §8-4-311]

5. The permittee shall not conduct operations in such a manner as to unnecessarily cause aircontaminants and other pollutants to become airborne. [Regulation 18, §18.901 andAC.A. §8-4-203 as referenced by A.C.A §8-4-304 and §8-4-311]

6. The permittee will not process more than 19,000 tons of water based product at thefacility per consecutive 12-month period. [Regulation 19, §19.705 and AC.A. §8-4-203as referenced by §8-4-304 and §8-4-311]

7. The permittee will not process more than 7,500 tons of ethanol based product at thefacility per consecutive 12-monthperiod. [Regulation 19, §19.705 and AC.A §8-4-203as referenced by §8-4-304 and §8-4-311]

11


8. The permittee shall perform a monthly evaluation of emissions from SN-OIA-C using theemission factors in the following table. The permittee will track emissions of particulatematter (PM IO) and volatile organic compounds (YOC) from SN-OIA-C, and suchemissions shall not exceed 0.3 tpy and 7.0 tpy, respectively, based upon a 12-monthrolling total. [Regulation 19, §19.705 and A.CA §8-4-203 as referenced by §8-4-304and §8-4-311]

Water Based Product Emissions

SN Product Emission Emission EmissionFactor Factor Factor

(lb PM/lb (lb YOC/lb SourceProduct) Product)

Gel 1.00 E-05 1.70 E-04Lotion 5.77 E-06 2.19 E-03

Relaxer 8.86 E-06 2.49 E-04SN-OIA-C Shampoo 8.82 E-06 6.19 E-04 Testing

Scrub 1.12 E-04 3.44 E-05Body Wash N/A 3.46 E-06Conditioner N/A 4.98 E-05

9. The permittee shall perform a monthly evaluation of emissions from SN-02 the followingtable. The permittee will track emissions ofparticulate matter (PM IO) and volatileorganic compounds (YOC) from SN-02, and such emissions shall not exceed 0.8 tpy and0.1 tpy, respectively, based upon a 12-month rolling total. [Regulation 19, §19.705 andA.c.A. §8-4-203 as referenced by §8-4-304 and §8-4-311]

Ethanol Based Product Emissions

Emission Emission

SN ProductFactor Factor Emission

(lb PMllb (lb YOC/lb Factor SourcePowder) Product)

SN-02Hair Spray &

1.00 E-03 2.33 E-04 TestingBody Wash

10. The permittee will maintain monthly records which demonstrate compliance withSpecific Condition 6, 7, 8, and 9. The permittee will maintain a twelve month rollingtotal and each individual month's data on-site and made available to Departmentpersonnel upon request. The permittee will update the records by the fifteenth day of themonth following the month to which the records pertain. [Regulation 19, §19.705 andA.CA §8-4-203 as referenced by §8-4-304 and §8-4-311 ]

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II. The permittee will not exceed 85 turnovers per ethanol storage tank (SN-03A and SN03B) per consecutive l2-month period. [Regulation 19, §19.705 and AC.A. §8-4-203 asreferenced by §8-4-304 and §8-4-3ll].

12. The permittee will not exceed 83 turnovers in the ethanol waste tank (SN-04) perconsecutive l2-month period. [Regulation 19, §19.705 and A.C.A §8-4-203 asreferenced by §8-4-304 and §8-4-311].

13. The permittee will maintain monthly records which demonstrate compliance withSpecific Conditions 11 and 12. The permittee will maintain a twelve month rolling totaland each individual month's data on-site and made available to Department personnelupon request. The permittee will update the records by the fifteenth day of the monthfollowing the month to which the records pertain. [Regulation 19, §19.705 andAC.A §8-4-203 as referenced by §8-4-304 and §8-4-311]

14. The permittee will bum only pipeline quality natural gas in the Natural Gas Fired Boilers(SN-05A and SN-05B). [Regulation 19, §19.705 and AC.A §8-4-203 as referenced by§8-4-304 and §8-4-31I ]

15. The permittee shall not use more that 376 gallons of ink for labeling use in the labeling ofbottle and products area (SN-06) per consecutive 12- month period. This ink shall havethe following maximum content limits: 7.44 Ib/gal ofVOC and 2.23 lb/gal methanol.[Regulation 19, §19.705 and A.C.A §8-4-203 as referenced by §8-4-304 and §8-4-3ll]

16. The permittee will maintain monthly records which demonstrate compliance withSpecific Condition 15. MSDS, a manufacturer's specification, or equivalentdocumentation shall be maintained on site for all coating and solvent materials used at thefacility which proves the VOC and methanol contents are at or below the above permittedlimit. The permittee will maintain a twelve month rolling total and each individualmonth's data on-site and made available to Department personnel upon request. Thepermittee will update the records by the fifteenth day of the month following the monthto which the records pertain. [Regulation 19, §19.705 and AC.A §8-4-203 as referencedby §8-4-304 and §8-4-3l1]

17. The permittee will not use more than 26 gallons of ink and 18 gallons offace platecleaner for use of labeling and cleaning in the printing equipment used for labeling outerpackages and shipping boxes (SN-07) per consecutive l2-month period. The ink shallhave a maximum content limit of 10.02lb/gal ofVOC and the cleaner shall havemaximum content limit of6.68Ib/gal ofVOC. [Regulation 19, §19.705 and A.C.A §84-203 as referenced by §8-4-304 and §8-4-311 ]

13


18. The permittee will maintain monthly records which demonstrate compliance withSpecific Condition 17. MSDS, a manufacturer's specification, or equivalentdocumentation shall be maintained on site for all coating and solvent materials used at thefacility which proves the VOC content is at or below the above permitted limits. Thepermittee will maintain a twelve month rolling total and each individual month's data onsite and made available to Department personnel upon request. The permittee will updatethe records by the fifteenth day of the month following the month to which the recordspertain. [Regulation 19, §19.705 and A.C.A. §8-4-203 as referenced by §8-4-304 and§8-4-311 ]

NSPS Requirements

19. The boiler, SN-05C, shall meet all applicable requirements ofNSPS Subpart Dc. ForSN-05C, applicable requirements include, but are not limited to, the record keepingprovisions of§60A8c(g). The facility shall record and maintain records of the amount offuel combusted in SN-05C on a monthly basis. [§ 19.304 of Regulation 19, andA.C.A. §8-4-203 as referenced by §8-4-304 and §8-4-311, and 40 CFR §60AOc(a) and§60A8c(g)]

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Section V: INSIGNIFICANT ACTIVITIES

The Department deems the following types of activities or emissions as insignificant on the basisof size, emission rate, production rate, or activity in accordance with Group A of theInsignificant Activities list found in Regulation 18 and 19 Appendix A. Insignificant activityemission determinations rely upon the information submitted by the permittee in an applicationdated March 23, 2007.

Description Category

Production Lab A-5

Pre-Weigh Hood for water-based production area A-13

Ammonium Thioglycolate Hood A-13

Safety Storage Cabinet Exhaust Roof Stack A-13

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Section VI: GENERAL CONDITIONS

1. Any terms or conditions included in this permit that specify and reference ArkansasPollution Control & Ecology Commission Regulation 18 or the Arkansas Water and AirPollution Control Act (A.c.A. §8-4-101 et seq.) as the sole origin of and authority for theterms 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 (A.C.A. §8-4-1OJ et seq.). Any terms orconditions included in this permit that specify and reference Arkansas Pollution Control& Ecology Commission Regulation 18 or the Arkansas Water and Air Pollution ControlAct (A.c.A. §8-4-1OJ et seq.) as the origin of and authority for the terms or conditionsare enforceable under this Arkansas statute.

2. This permit does not relieve the owner or operator of the equipment and/or the facilityfrom compliance with all applicable provisions of the Arkansas Water and Air PollutionControl Act and the regulations promulgated under the Act. [A.C.A. §8-4-203 asreferenced by A.C.A. §8-4-304 and §8-4-3l1]

3. The permittee shall notify the Department in writing within thirty (30) days aftercommencement of construction, completion ofconstruction, first operation of equipmentand/or facility, and first attainment of the equipment and/or facility target production rate.[Regulation 19, §19.704 and/or A.C.A. §8-4-203 as referenced by A.C.A. §8-4-304 and§8-4-311]

4. Construction or modification must commence within eighteen (18) months from the dateofpermit issuance. [Regulation 19, §19.41 O(B) and/or Regulation 18, §18.309(B) andA.C.A. §8-4-203 as referenced by A.C.A. §8-4-304 and §8-4-311]

5. The permittee must keep records for five years to enable the Department to determinecompliance with the terms of this permit such as hours of operation, throughput, upsetconditions, and continuous monitoring data. The Department may use the records, at thediscretion of the Department, to determine compliance with the conditions of the permit.[Regulation 19, §19.705 and/or Regulation 18, §18.1004 and A.C.A. §8-4-203 asreferenced by A.C.A. §8-4-304 and §8-4-311]

6. A responsible official must certify any reports required by any condition contained in thispermit and submit any reports to the Department at the address below. [Regulation 19,§19.705 and/or Regulation 18, §18.1004 and A.C.A. §8-4-203 as referenced by A.C.A.§8-4-304 and §8-4-311]

Arkansas Department of Environmental QualityAir DivisionATTN: Compliance Inspector Supervisor

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5301 Northshore DriveNorth Little Rock, AR 72118-5317

7. The permittee shall test any equipment scheduled for testing, unless stated in the SpecificConditions of this permit or by any federally regulated requirements, within the followingtime frames: (I) newly constructed or modified equipment within sixty (60) days ofachieving the maximum production rate, but no later than 180 days after initial start up ofthe permitted source or (2) existing equipment already operating according to the timeframes set forth by the Department. The permittee must notify the Department of thescheduled date ofcompliance testing at least fifteen (15) days in advance of such test.The permittee must submit compliance test results to the Department within thirty (30)days after the completion of testing. [Regulation 19, §19.702 and/or Regulation 18,§18.1 002 and AC.A §8-4-203 as referenced by A.C.A §8-4-304 and §8-4-311 ]

8. The permittee shall provide: [Regulation 19, §19.702 and/or Regulation 18, §18.1002and AC.A. §8-4-203 as referenced by A.C.A §8-4-304 and §8-4-311]

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

9. The permittee shall operate equipment, control apparatus and emission monitoringequipment within their design limitations. The permittee shall maintain in goodcondition at all times equipment, control apparatus and emission monitoring equipment.[Regulation 19, §19.303 and/or Regulation 18, §18.1104 and A.C.A. §8-4-203 asreferenced by AC.A §8-4-304 and §8-4-311]

10. If the permittee exceeds an emission limit established by this permit, the permittee will bedeemed in violation of said permit and will be subject to enforcement action. TheDepartment may forego enforcement action for emissions exceeding any limitsestablished by this permit provided the following requirements are met: [Regulation 19,§19.601 and/or Regulation 18, §18.1101 and AC.A. §8-4-203 as referenced by A.C.A§8-4-304 and §8-4-311]

a. The permittee demonstrates to the satisfaction of the Department that theemissions resulted from an equipment malfunction or upset and are not the resultof negligence or improper maintenance, and the permittee took all reasonablemeasures to immediately minimize or eliminate the excess emissions.

b. The permittee reports the occurrence or upset or breakdown ofequipment (bytelephone, facsimile, or overnight delivery) to the Department by the end of thenext business day after the occurrence or the discovery of the occurrence.

c. The permittee must submit to the Department, within five business days after theoccurrence or the discovery of the occurrence, a full, written report of suchoccurrence, including a statement of all known causes and of the scheduling and

17


nature of the actions to be taken to minimize or eliminate future occurrences,including, but not limited to, action to reduce the frequency of occurrence of suchconditions, to minimize the amount by which said limits are exceeded, and toreduce the length of time for which said limits are exceeded. If the information isincluded in the initial report, the information need not be submitted again.

11. The permittee shall allow representatives of the Department upon the presentation ofcredentials: [AC.A. §8-4-203 as referenced by A.C.A. §8-4-304 and §8-4-311 ]

a. To enter upon the permittee's premises, or other premises under the control of thepermittee, where an air pollutant source is located or in which any records arerequired to be kept under the terms and conditions of this permit;

b. To have access to and copy any records required to be kept under the terms andconditions of this permit, or the Act;

c. To inspect any monitoring equipment or monitoring method required in thispermit;

d. To sample any emission of pollutants; ande. To perform an operation and maintenance inspection of the permitted source.

12. The Department issued this permit in reliance upon the statements and presentationsmade in the permit application. The Department has no responsibility for the adequacy orproper functioning of the equipment or control apparatus. [AC.A §8-4-203 asreferenced by AC.A §8-4-304 and §8-4-311]

13. The Department may revoke or modify this permit when, in the judgment of theDepartment, such revocation or modification is necessary to comply with the applicableprovisions of the Arkansas Water and Air Pollution Control Act and the regulationspromulgated the Arkansas Water and Air Pollution Control Act. [Regulation 19,§19.410(A) and/or Regulation 18, §18.309(A) and AC.A. §8-4-203 as referenced byAC.A. §8-4-304 and §8-4-311]

14. This permit may be transferred. An applicant for a transfer must submit a written requestfor transfer of the permit on a form provided by the Department and submit the disclosurestatement required by Arkansas Code Annotated §8-1-106 at least thirty (30) days inadvance of the proposed transfer date. The permit will be automatically transferred to thenew permittee unless the Department denies the request to transfer within thirty (30) daysof the receipt of the disclosure statement. The Department may deny a transfer on thebasis of the information revealed in the disclosure statement or other investigation or,deliberate falsification or omission of relevant information. [Regulation 19, §19.407(B)and/or Regulation 18, §18.307(B) and AC.A. §8-4-203 as referenced by A.C.A §8-4304 and §8-4-311]

15. This permit shall be available for inspection on the premises where the control apparatusis located. [AC.A. §8-4-203 as referenced by AC.A. §8-4-304 and §8-4-311]

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

17. This permit supersedes and voids all previously issued air permits for this facility.[Regulation 18 and 19 and AC.A §8-4-203 as referenced by AC.A. §8-4-304 and §8-4311]

18. The permittee must pay all permit fees in accordance with the procedures established inRegulation No.9. [A.C.A §8-1-105(c)]

19. The permittee may request in writing and at least 15 days in advance ofthe 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.

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

20. 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 facilities 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 temporaryemissionsitesting.

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

19

Alberto-Culver CompanyPennit #: 2138-AR-2AFIN: 16-00968

21. The pennittee may request in writing and at least 30 days in advance, an alternativeto the specified monitoring in this pennit. No such alternatives are authorized until thepennittee 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 pennit modification

application by the pennittee.

[Regulation 18, §18.102(C-D), Regulation I 9, §19.103(D), AC.A §8-4-203 as referencedby AC.A §8-4-304 and §8-4-311, and CFR Part 52, Subpart E]

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Appendix A: 40 CFR 60, Subpart Dc - Standards ofPerformance for Small IndustrialCommercial-Institutional Steam Generating Units

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Electronic Code of Federal Regulations:

e-CFR Data is current as of January 22, 2009

Title 40: Protection of Environment£'ART 60,-SIANQARDS QF PERFOBMANCE FOR NEW STATIONARY SOURCES

SUbpart Dc-Standards of Performance for Smallindustrial-Commercial-institutionalSteam Generating Units

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

§ 60.40c Applicability and delegation of authority.

(a) Except as provided in paragraph (d) ofthis section, the ctfected facility to which this subpart appliesis each steam generating unit br which construction, rmdification, or reconstruction is conmenced afterJune 9, 1989 and that has a TTBximum design heat input capacity of 29 megawatts (MW) (100 millionBritish thermal units per hour (fI!fII1Btu/hr)) or less, but greater than or equa to 2.9 MVV (10 MMBtu/hr).

(b) In delegating implementation and enbrcement authority to a State under section 111 (c) ofthe CleanAir Act, §60.48c(a)(4) shall be retained bythe Administrator and not transferred to a State.

(c) Steam generating units that rreet the applicability requirements in paragraph (a) ofthis section arenot subject to the sulfur dioxide (S02) or particulate matter (PM) emission limits, performance testing

requirements, or monitoring requirerrents under this sUbpart (§§6J.42c, 60.43c, 60.44c, 60.45c, 60.46c,or 60.47c) during periods ofcombustion research, as defned in §60.41c.

(d) Any temporary change to an elGsting steam generating unit for the purpose ofconducting corrbustionresearch is not considered a rrodification under §60.14.

(e) Heat recovery steam generators that are associated wth combined cycle gas turbines and rreet theapplicability requirements of subpart GG or KKKK ofthis part are not SUbject to this subpart. Thissubpart will continue to apply to all other heat reco\ery steam generators that are capable ofcombustingmore than or equal to 2.9 MN (10 MMBtu/hr) heat input offossil fuel but less than or equal to 29 MN(100 MMBtu/hr) heat input offossil fuel. If the heat reco\ery steam generator is subjact to this SUbpart,only emissions resulting tom combustion of fuels in the steam generating unit are subjact to thissubpart. (The gas turbine erTissions are sUb,ect to subpart GG cr KKKK, as applicable, ofthis part).

(f) Any facility covered by subpart AAAA of this part is not cO\ered by this subpart.

(g) Any facility covered by an EPA appro\ed State or Federal se:::tion 111 (d)/129 plan irrplementingsubpart BBBB ofthis part is not cO\ered by this SUbpart.

§ 60.41c Definitions.

As used in this subpart, all temB not defined herein shal have the meaning given them in the Clean AirAct and in subpart A ofthis part.

Annual capacity factormeans the ratio betv-.een the actual heat input toa steam generating unit Tom anindividual fuel or combination of fuels during a period of 12 consecutive calendar rmnths and thepotential heat input to the steamgenerating unit from all fuels had the steam generating unit beE'lloperated for 8,760 hours during that 12-month period at the maximum design heat input capacity In thecase of steam generating units that are rented or lea;ed, the actual heat input shall be deterninedbased on the corrbined heat input tom all operations of the affected facility during a period of 12consecutive calendar rmnths.

Coal means all solid fuels classifled as anthracite, biturTinous, subbituminous, or lignite by the AmericanSociety otTesting and Materials in ASTM D388 (incorporated by reference, see §60.17), coal reuse,and petroleum coke. Coa~derived synthetic fuels derived from coal for the purposes ofcreating usefulheat, including but not lirTited to solvent refined coal, gasified coal, coa~oil mixtures, and coa~water

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mixtures, are also included in this defnition for the purposes of this subpart.

Coal refuse means any by-product of coal mining or coal cleaning operations vith an ash contentgreater than 50 percent (byweight) and a heating value less than 13,900 kilopules per kilogram (kJ/kg)(6,000 Btu per pound (Btu/lb) on a drybasis.

Cogeneration steam generating unitmeans a steam generating unit that silTlJltaneously produces bothelectrical (or mechanical) and themal energy from the same primary energy source.

Combined cycle system means a system in which a separate source (such as a stationay gas turbine,internal combustion engine, or kiln) prOlides exhaust gas to a steam generating unit.

Combustion research means the experimental firing of any fuel or combination of fuels in a steamgenerating unit br the purpose ofconducting research and delelopment of more efficient combustion ormore effective prevention or control ofair pollutant errissions from combustion, provided that, duringthese periods ofresearch and delelopment, the heat generated is not used Dr any purpose other thanpreheating cOrrDustion air for use by that steam generating unit ( i.e. , the heat generated is released tothe atmosphere Vvithout being used br space hecting, process heating, driling pumps, preheatingcombustion air for other units, generating electricil)( or any other purpose).

Conventional technologymeans wet flue gas desuliJrization technology, dry flue gas desulfurizationtechnology, atmospheric fluidized bed cOrrDustion technology, and oil hydrodesulfurization technolog,.'.

Distillate oil means fuel oil that complies with the specifications for fuel oil numbers 1 or 2, as deined bythe American Society for Testing and Materials in AS1M 0396 (incorporated by reference, see §60.17)

Dry flue gas desulfurization technologymeans a S02controi system that is located bel\lleen the steam

generating unit and the e>t1aust vent or stack, and that removes sulfur oxides from the combustiongases of the steam generating unit by contacting the combustion gases wth an alkaline reagent andwater, whether introduced separatelyor as a premixed slurry or solution and forming a dry powdermaterial. This definition includes de\ices where the dry powder material is subsequentiyconverted toanother form. Alkaline reagents used in dryflue gas desulfurization systems include, but are not Iirritedto, lime and sodium compounds.

Duct burner means a device that combusts fuel and that is placed inthe exhaust duct from anothersource (such as a stationarygas turbine, internal corrDustion engine, kiln, etc.) to allowthe firing ofadditional fuel to heat the exhaust gases before the exhaust gases enter a steamgenerating unit.

Emerging technologymeans any S02controi system that is not defined as a conlentional technology

under this section, and Dr which the owner or operator ci the affected facility has received approval fromthe Administrator to operate as an emerging technolog,.' under §60.48c(a)(4).

Federally enforceable means all limitations and conditions that are enbrceable by the Administrator,including the requirements of 40 CFR parts 60 and 61, rEl:luirements within any applicable Stateimplementation plan, and anypermit requirements established under 40 CFR 52.21 or under 40 CFR51.18 and 51.24.

Fluidized bed combustion technologymeans a device wherein fuel is distributed onto a bed (or series ofbeds) of limestone aggregate (or other sorbent nBterials) for combustion; and these materials are forcedupward in the device by the flow of combustion air and 1he gaseous products ofcombustion. Fluidizedbed combustion technology includes, but is not lirrited to, bubbling bed units and circulating bed urits.

Fuel pretreatment means a process that renuves a portion ofthe sulfur in a fuel before combustion ofthe fuel in a steam generating unit.

Heat input means heat deriled from combustion offuel in a steam generating unit and does not includethe heat deriled from preheated cOrrDustion air, recirculated flue gases, or exhaust gases Tom othersources (such as stationarygas turbines, internal corrbustion engines, and kilns).

Heat transfer medium means any material that is used to transer heat from one point to another point.

Maximum design heat input capacitymeans the ability of a steam generating unit to corrbust a stated

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maximum amount of fuel (or combination of fuels) on a steady state basis as deterrrined by the physicaldeSign and characteristics ofthe steam generating urit.

Natural gas means: (1) A naturally occurring mixture of hydrocarbon and nomydrocarbon gases bundin geologic lbrmations beneath the earth's surnce, of which the principal constituent is rrethane; or (2)liquefied petroleum (LP) gas, as detned by the American Society for Testing and Materials in AS1MD1835 (incorporated by reference, see §60.17).

Noncontinental area means the State of Hawaii, the Virgin Islands, Guam American Samoa, theCommonwealth of Puerto Rico, or the Northern Iv1Iriana Islands.

Oil means crude oil or petroleum or a liquid fuel derived from crude oil or petroleum including distillateoil and residual oil.

Potential sulfur dioxide emission ratemeans the theoretical S~emissions (nanogralT6 per joule (ng/J)

or Ib/MMBtu heat input) that \hOuld result from combusting fuel in an uncleaned state and vJthout usingemission control systems.

Process heatermeans a device that is primarily used to heat a rraterial to initiate or promote a chemicalreaction in \M1ich the material participates as a reactant or catayst.

Residual oil means crude oil, fuel oil that does not corrply with the specifications under the defnition ofdistillate oil, and all iJel oil numbers 4,5, and 6, as defined by the American Society for Testing andMaterials in AS1M D396 (incorporated by reference, see §60.17).

Steam generating unitmeans a device that combusts any fuel and produces steam or heats water orany other heat transer medium. This term includes any duct burner that combusts fuel and is part of acombined cycle system. This term does not include process heaters asdefined in this subpart.

Steam generating unit operating daymeans a 24-hour period betv>.een 12:00 midnight and the followingmidnight during \M1ich any fuel is combusted at anytime in the steam generating unit. It is not necessaryfor fuel to be combusted continuously for the entire 24-hour period.

Wet flue gas desulfurization technologymeans an S02controi system that is located betv>.een the steam

generating unit and the eJtlaust vent or stack, and that removes sulfur oxides from the combustiongases of the steam generating unit by contacting the combustion gases wth an alkaline slurry or solutionand forming a liquid material. This definition includes de\ices where the liquid material is subsequentlyconverted to another brm. Alkaline reagents used in vet flue gas desuliJrization systems include, butare not limited to, lime, limestone, and sodium compounds.

Wet scrubber system means any emission control de\ice that mixes an aqueous stream or slurry withthe exhaust gases tom a steam generating unit to cortrol emissions of PM or S02'

Wood means wood, wood residue, bark, or any derivative fuel or residue thereof, in any form, includingbut not limited to sawdust, sanderdust, \hOod chips, scraps, slcils, millings, shavings, and processedpellets made from wood or other brest residues.

§ 60.42c Standard for sulfur dioxide (S02)'

(a) Except as provided in paragraphs (b), (c), and (e) ofthis section, on and after the date on VIk1ich theperformance test is corrpleted or required to be corrpleted under §60.8, \M1ichever date comes first, theowner or operator ofan affected facility that combusts only coal shall neither: cause to be dischargedinto the atmosphere from the affected facility any gases that contain S02in excess of 87 ng/J (0.20

Ib/MMBtu) heat input or 10 percent (0.10) ofthe potential S02emission rate (90 percent reduction), nor

cause to be discharged into the atrrosphere from the affected facility any gases that contain S~in

excess of 520 ng/J (1.2 Ib/MMBtu) heat input. If coal is combusted with other fuels, the affected facilityshall neither: cause to be discharged into the atrlDsphere from the affected facility any gases thatcontain S02in excess of87 ng/J (0.20 Ib/MMBtu) heat input or 10 percS'lt (010) of the potential

S02emission rate (90 percent reduction), nor cause to be disch~ed into the atrrosphere from the

affected facility any gases that contain S~in excess of the emission limit is determined pursuant to

paragraph (e)(2) ofthis section

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(b) Except as pro";ded in paragraphs (c) and (e) ofthis section, on and after the date on W"iich theperformance test is completed or required to be completed under §60.8, W"iichever date comes first, theowner or operator of an affected facility that:

(1) Combusts only coal refuse alone in a fuidized bed canbustion steam generating unit shall neither:

(i) Cause to be discharged into the atrrosphere from that affected facility any gases that contain SG.2in

excess of 87 ng/J (0.20 Ib/M'v1Btu) heat input or 20 percert (0.20) of the potential S02emission rate (80

percent reduction); nor

(ii) Cause to be discharged into the atrrosphere from that affected facility any gases that contain SG.2in

excess of S02in excess of 520 ng/J (1.2 Ib/M'v1Btu) heat input. Ifcoal is fired with coal refuse, the

affected facility sUbject to paragraph (a) ofthis section. If oil or any other fuel (except coal) is fired withcoal refuse, the affected facility is subject to the 87 ng/J (020 Ib/MMBtu) heat input S~emissionslimit

or the 90 percent SG.2reduction requirement specified in paragraph (a) ofthis section and the errission

limit is determined pursuant to paragraph (e)(2) ofthis section.

(2) Combusts only coal and that uses an emerging techndogy for the control of S02emissions shall

neither:

(i) Cause to be discharged into the atrmsphere from that affected facility any gases that contain SG.2in

excess of 50 percent (0.50) ofthe potential S02emission rate (50 percent reduction); nor

(ii) Cause to be discharged into the atrmsphere from that affected facility any gases that contain SG.2in

excess of 260 ng/J (0.60 Ib/M'v1Btu) heat input. If coal is combusted with other fuels, the affected facilityis subject to the 50 percent SG.2reduction requirement specified in this paragraph and the emission limit

determined pursuant to paragraph (e)(2) ofthis section.

(c) On and after the date on W"iich the initial perbrmance test is completed or required to be completedunder §60.8, W"iichever date comes first, no owner or operator of an affected facility that combusts coal,alone or in combination Vvith any other fuel, and is listed in paragraphs (c)(1), (2), (3), or (4) ofthissection shall cause to be discharged into the atrlDsphere from that affected facility any gases thatcontain S02in excess of the emission limit determined pursuant to paragrap, (e)(2) of this section.

Percent reduction requirements are not applicable to effected facilities under paragraphs (c)(1), (2), (3),or (4).

(1) Affected facilities that ha-..e a heat input capacityof 22 MW (75 MMBtu/hr) or less.

(2) Affected facilities that ha-..e an annual capacity for coal of 55 percent (0.55) or less and are subjlct toa federally enforceable requirement limiting operation d the affected facility to an annual capacity factorfor coal of 55 percent (0.55) or less.

(3) Affected facilities located in a noncontinental area

(4) Affected facilities that combust coal in a duct burner as part cf a combined cycle system where 30percent (0.30) or less ofthe heat entering the steam generating unit is tom combustion of coal in theduct burner and 70 percent (0.70) or rmre of the heat entering the steam generating unit is tom exhaustgases entering the duct burner.

(d) On and after the date on W"iich the initial perbrmance test is completed or required to be completedunder §60.8, W"iichever date comes first, no owner or operator of an affected facility thatcombusts oilshall cause to be discharged into the atrmsphere from that affected facility any gases that contain SG.2in

excess of 215 ng/J (0.50 Ib/M'v1Btu) heat input; or, as an aternative, no owner or operator ofan affectedfacility that combusts oil shall combust oil in the affected facility that contains greater than 0.5 'Aeightpercent sulfur. The percent reduction requirements are not applicable to affected facilities under thisparagraph.

(e) On and after the date on W"iich the initial perbrmance test is completed or required to be completedunder §60.8, W"iichever date comes first, no owner or operator of an affected facility that combusts coal,oil, or coal and oil wth any other fuel shall cause to bedischarged into the atrrosphere from that

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affected facility any gases that contain SOzin excess of the following:

(1) The percent of potential S02emission rate or nUirerical S02emission rate required under paragraph(a) or (b)(2) of this section, as applicable, br any affected facility that

(i) Combusts coal in colTbination with any other fuel;

(ii) Has a heat input capacity greater than 22 WW (75 MMBtu/hr); and

(iii) Has an annual capacity factor for coal greater than 55 ~rcent (0.55); and

(2) The emission limit determined according to the bllowing formula for any affected facility thatcombusts coal, oil, or coal and oil 'llith any other fuel:

E =(K.H. + K\H\ + K,H.), (H. +H\+H,)

Where:

Es=S02emission limit, expressed in ng/J or Ib/MMBtu heat input;

Ka=520 ng/J (1.2 Ib/MMBtu);

Kb=260 ng/J (0.60 Ib/MMBtu);

Kc= 215 ng/J (0.50 Ib/MMBtu);

Ha= Heat input from the combustion of coal, except coal combusted in an affected facility

subject to paragraph (b)(2) of this section, in Joules (J) [MMBtu];

Hb=Heat input from the combustion of coal in an affected facility subject to paragraph (b)(2)

of this section, in J (MMBtu); and

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

(f) Reduction in the potential SOzemission rate through iJel pretreatment is not credited tov.ard the

percent reduction requirerrent under paragraph (b)(2) ofthis section unless:

(1) Fuel pretreatment results in a 50 percent (0.50) or greater redl£tion in the potential SOzemissionrate; and

(2) Emissions from the pretreated fuel (without either colTbustion or post-combustion S02control) are

equal to or less than the errission limits specified under pa-agraph (b)(2) of this section.

(g) Except as provided in paragraph (h) ofthis section, compliance with the percent reductionrequirements, fuel oil sulfur limits, and emission limits of this section shall be determined on a 3D-dayrolling average basis.

(h) For affected facilities listed under paragraphs (h)(1), (2), or (3) ofthis section, compliance with theemission limits or fuel oil sulfur limits under this section rray be determined based on a certification fromthe fuel supplier, as described under §60.48c(1, as applicable.

(1) Distillate oil-fired affected facilities with heat input capacities betv.een 2.9 and 29 WW (10 and 100MMBtu/hr).

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(2) Residual oi~fired affected facilities with heat input capacities betv.een 2.9 and 8.7 MJV (10 and 30MMBtu/hr).

(3) Coal-fired facilities with heat input capacities betv.een 2.9 and 8.7 rvr.N (10 and 30 MMBtu/hr).

(i) The S02emission limits, fuel oil sulfur limits, and percent reduction requirerrents under this section

apply at all times, including periods ofstartup, shutdoWl, and malfunction.

OJ Only the heat input supplied to the afected facility from the combustion of coal and oil is countedunder this section. No credit is prolided for the heat inpl1 to the affected facility from wood or other fuelsor for heat derived from exhaust gases tom other sources, such a; stationary gas turbines, internalcombustion engines, and kilns.

§ 60.43c Standard for particulate matter (PM).

(a) On and after the date on Wlich the initial perbrmance test is completed or required to be corrpletedunder §60.8, Wlichever date comes first, no owner or operator of an affected facility that commencedconstruction, reconstruction, or rmdification on or bebre Februay 28, 2005, that combusts coal orcombusts mixtures of coal with other fuels and has a heat inp.Jt capacity of 8.7 rvr.N (30 MMBtu/hr) orgreater, shall cause to be discharged into the atflDsphere from that affected facility any gases thatcontain PM in excess of the following emission limits:

(1) 22 ng/J (0.051Ib/MMBtu) heat input ifthe affected facility combusts only coal, or combusts coalwthother fuels and has an annual capacityfactor for the other fuels of 10 percent (0.10) or less.

(2) 43 ng/J (0.10 Ib/MMBtu) heat input ifthe affected facility combusts coal with other fuels, has anannual capacity factor for the other fuels greater than 10 percent (0.10), and is subj3ct to a federallyenforceable requirement limiting operation ofthe affected facility to an annual capacity factor greaterthan 10 percent (0.10) br fuels other than coal.

(b) On and after the date on Wlich the initial perbrmance test is completed or required to be corrpletedunder §60.8, Wlichever date comes first. no owner or operator of an affected facility that commencedconstruction, reconstruction, or rmdification on or bebre Februay 28, 2005, that combusts wood orcombusts mixtures of wood with other fuels (except coal) and has aheat input capacity of 8.7 rvr.N (30MMBtu/hr) or greater, shall cause to be discharged into the anosphere from that affected facility anygases that contain PM in excess of the following emissions limits:

(1) 43 ng/J (0.10 Ib/MMBtu) heat input ifthe affected facility has an annual capacity factor for woodgreater than 30 percent (0.30); or

(2) 130 ng/J (0.30 Ib/MMBtu) heat input ifthe affected facility has an annual capacity factor for wood of30 percent (0.30) or less and is sub1lct to a federally enforceable requirement limiting operation oftheaffected facility to an annual capacity factor for wood of 30 percent (0.30) or less.

(c) On and after the date on Wlich the initial perbrmance test is completed or required to be corrpletedunder §60.8, Wlichever date comes first, no owner or operator of an affected facility that combusts coal,wood, or oil and has a heat input capacityof 8.7 MW (30 MMBtulhr) or greater shall cause to bedischarged into the atrmsphere from that affected facility any gases that exhibit greater than 20 percentopacity (6-minute average), except for one 6-minute period per hour ofnot more than 27 percentopacity.

(d) The PM and opacity standards under this section appy at all times, except during periods ofstartup,shutdown, or malfunction.

(e)(1) On and after the date on Wlich the initial perbrmance test is completed or is required to becompleted under §60.8, Vohichever date comes first, no owner or operator ofan affected facility thatcommences construction, reconstruction, or rrodification after February 28,2005, and that combustscoal, oil, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels and has a heatinput capacity of 8.7 rvr.N (30 MMBtu/hr) or greater shall cause to be discllIrged into the atrrospherefrom that affected facility any gases that contain PM in excess of 13 ng/J (0.030 Ib/MMBtu) heat input,except as provided in paragraphs (e)(2), (e)(3), and (e)(4) ofthis section.

(2) As an alternative to meeting the requirements of paragraph (e)(1) of this section, the OWler or

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operator of an affected facility for which modification commenced after February 28, 2005, may elect tomeet the requirements of this paragraph. On and ater the date on v.k1ich the initial perbrmance test iscompleted or required to be corrpleted under §6Q8, whichever date comes first, no owner or operator ofan affected facility that commences modification after February 28, 2005 shall cause to be dischargedinto the atmosphere from that affected facility any gases that contain PM in excess of both:

(i) 22 ng/J (0.051Ib/Mll1Btu) heat input deri\ed from the combustion of coal, oil, wood, a mixture of thesefuels, or a mixture of these fuels with any other fuels; and

(ii) 0.2 percent of the combustion concentration (99.8 pErcent reduction) Wlen combusting coal, oil,wood, a mixture of these fuels, or a mixture of these fuels with any other fuels.

(3) On and after the date on Wlich the initial perbrmance test is completed or is required to becompleted under §60.8, v.k1ichever date comes first, no owner or operator ofan affected facility thatcommences modification after February 28, 2005, and tha combusts over 30 percent mod (by heatinput) on an annual basis and has a heat irput capacity of 8.7 MN (30 MMBtu/hr) or greater shall causeto be discharged into the atrrosphere from that affected facility any gases that contain PM in excess of43 ng/J (0.10 Ib/Mll1Btu) heat input.

(4) On and after the date on Wlich the initial perbrmance test is completed or is required to becompleted under §60.8, v.k1ichever date comes first, an owner or operator of an affected facility thatcommences construction, reconstruction, or rrodification after February 28, 2005, and that corrbustsonly oil that contains no rrore than 0.50 v.eight percent sulfur or a mixture of 0.50 weight percent sullJroil with other fuels not subject to a PM standard under §30.43c and not using a postcombustiontechnology (except a wet scrubber) to reduce PMor S02emissions is not subject to the PM limit in this

section.

§ 60.44c Compliance and performance test methods and procedures for sulfurdioxide.

(a) Except as prov;ded in paragraphs (g) and (h) ofthis section and §60.8(b), perbrmance tests requiredunder §60.8 shall be conducted ollowing the procedures specifed in paragraphs (b), (c), (d), (e), and (Jof this section, as applicable. Section 60 8(1 does not apply to this section. The 3Q.-day notice requiredin §60.8(d) applies only to the initial per1i:lrmance test Uliess otherMse specified by the Administrator.

(b) The initial performance test required under §60.8 shall til conducted o\er 30 consecuti\e operatingdays of the steam generating unit. Corrpliance with the percent reduction requirerrents andS02emission limits under §60.42c shall be deternined using a 3Q.-day average. The first operating day

included in the initial perbrmance test shall be schedued within 30 days after achieving the maximumproduction rate at Wlich the affect facility will be operated, but not later than 180 day> after the initialstartup of the facility. The steam generating unit load dlling the 3Q.-day period does not ha\e to be themaximum design heat input capacity. but must be representaive of future operating conditions.

(c) After the initial performance test required under paragraph(b) of this section and §60.8, corrpliancewith the percent reduction requirerrents and S02emission limits under §60.42c is based on the a-erage

percent reduction and the alerage S02emission rates fOr 30 consecuti\e steam generating unit

operating days. A separate perbrmance test is corrpleted at the end of each steam generating unitoperating day, and a new 30-day average percent reduction and SG.!emission rate are calCUlated to

show compliance with the standard.

(d) If only coal, only oil, or a mixture of coal and oil is corrbusted in an affected facility, the procedures inMethod 19 of appendix A of this part are used to determine the hourly S02emission rate (~o) and the

3Q.-day average S02emission rate (E"o) The hourly averages used to corrpute the 3Q.-day averages are

obtained from the CEMS. Method 19 of appendix A of this part shall be used to calculate ~owhen using

daily fuel sampling or Method 6B ofappendix A ofthis part.

(e) If coal, oil, or coal and oil are corrbusted 'hith other fuels:

(1) An adjusted ~o(EhoO) is used in Equation 1~19 of Method 19 of appendiX A of this part to corrpute

the adjusted Eao(Eaoo). The EhOo is computed using the bllowing formula:

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Where:

EhOo =Adjusted Eho' ng/J (Ib/MMBtu);

EhO= Hourly S02emission rate, ng/J (lb/MMBtu);

Ew= S02concentration in fuels other than coal and oil combusted in the affected facility, as

determined by fuel sampling and analysis procedures in Method 9 of appendix A of this part,ng/J (lb/MMBtu). The value Ewfor each fuel lot is used for each hourly average during the time

that the lot is being combusted. The owner or operator does not have to measure Ewif the

owner or operator elects to assume Ew= O.

Xk=Fraction of the total heat input from fuel combustion derived from coal and oil, as

determined by applicable procedures in Method 19 of appendix A of this part.

(2) The owner or operator ofan affected facility that qualifies under the prol.1sions of §60.42c(c) or (d)(where percent reduction is not required) does not ha'e to measure the parameters ~or Xkif the owneror operator ofthe affected facility elects to measure emission rates of the coal or oil using the iJelsampling and analysis procedures under llfethod 19 of appendix A of this part.

(f) Affected facilities subject to the percent reduction requirerrents under §60.42c(a) or (b) shalldetermine compliance with the S02emission limits under §60.42c pursuant to paragraphs (d) <D (e) ofthis section, and shall deterrrine compliance with the percent reduction requirements using the bllowingprocedures:

(1) If only coal is combusted, the percent ofpotential S02emission rate is computed using the bllowing

formula:

%P =100(1 - %Rr)(1 _ %R f ), 100 100

Where:

%Ps= Potential S02emission rate, in percent;

%Rg= S02removai efficiency of the control device as determined by Method 19 of appendix A

of this part, in percent; and

%Rr: S02removai efficiency of fuel pretreatment as determined by Method 19 of appendix A

of this part, in percent.

(2) If coal, oil, or coal and oil are corTbusted with other fuels, the same procedures required in paragraph(f)(1) of this section are used, elCept as prol.ided for in the following:

(i) To compute the %Ps ' an adjusted %l\(%Rgo) is computed from Eaoo from paragraph (e)(1) ofthissection and an adj,lsted average S02iniet rate (Eaio) using the bllowing formula:

%R 0 =100 (1- E:)r E~

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Where:

%RgO = Adjusted %Rg, in percent;

Eaoo = Adjusted Eao ' ng/J (lb/MMBtu); and

Eaio = Adjusted average S02iniet rate, ng/J (Ib/MMBtu).

(ii) To compute Eaio, an adjusted hourly S02iniet rate (Ehio) is used. The Ehio is computed using thefollowing formula:

Where:

EhiO = Adjusted Ehi, ng/J (lb/MMBtu);

Ehi= Hourly S02iniet rate, ng/J (lb/MMBtu);

Ew=S02concentration in fuels other than coal and oil combusted in the affected facility, as

determined by fuel sampling and analysis procedures in Method 19 of appendix A of this part,ng/J (Ib/MMBtu). The value Ewfor each fuel lot is used for each hourly average during the time

that the lot is being combusted. The owner or operator does not have to measure Ewif the

owner or operator elects to assume Ew=0; and

Xk=Fraction of the total heat input from fuel combustion derived from coal and oil, as

determined by applicable procedures in Method 19 of appendix A of this part.

(g) For oil-fired affected facilities where the owner or operator seeks to remonstrate compliance with thefuel oil sulfur limits under §60.42c based on shiprrent fuel sampling, the initial perbrmance test shallconsist of sampling and analyzing the oil in the initial tank of oil to be fired in the steam generating unit todemonstrate that the oil contains 0.5 veight percent sulfur or less. Thereafter, the owner or operator ofthe affected facility shall sample the oil in the fuel tank after each new shipment of oil is received, asdescribed under §60.46c(d)(2).

(h) For affected facilities sUbject to §60.42c(h)(1), (2), or (3) vilere the owner or operator seeks todemonstrate compliance with the S02standards based on tiel supplier certiication, the performance

test shall consist ofthe certification, the certikation from the fuel supplier, as described under §60.48c(fl, as applicable.

(i) The owner or operator ofan affected facility seeking to demonstrate compliance with theS02standards under §60.42c(c)(2) shall dermnstrate the maximum design heat input capacityof the

steam generating unit by operating the steam generating unit at this capacity for 24 hours. Thisdemonstration shall be rrade during the initial perbrmance test, and a subsequent derronstration maybe requested at any other time. If the demonstrated 24-hour average firing rate for the affected facility isless than the maximum design heat input capacitystated by the manufacturer of the affected facility, thedemonstrated 24-hour average firing rate shall be used to deterrrine the annual capacity factor for theaffected facility; otherwise, the maximum design heat input caiEcity provided by the manufacturer shallbe used.

Ul The owner or operator ofan affected facility shall use all valid S02emissions data in calculating %

Psand Ehounder paragraphs (d), (e), or (J of this section, as applicable, Wlether or not the rrinimum

emissions data requirerrents under §60.46c(~ are achieved. All valid emissions data, inclUding \6liddata collected during periods ofstartup, shutdo'Ml, and malfunction, shall be used in calculating %~or

EhOpursuant to paragraphs (d), (e), or (J of this section, as applicable

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§ 60.45c Compliance and performance test methods and procedures for particulatematter.

(a) The owner or operator ofan affected facility subject to the PM and/or opacity standards under§60.43c shall conduct an initial perbrmance test as reqJired under §60.8, and shall conduct subseapentperformance tests as requested bythe Administrator, to deterrrine compliance v,;th the standards usingthe following procedures and reerence methods, except as specified in paragraph (c) ofthis section.

(1) Method 1 of appendix A of this part shall be used to select the sarrpling site and the nurrber oftraverse sampling points.

(2) Method 3 of appendix A of this part shall be used for gas analysis when applying Method 5, 58, or 17of appendix A of this part.

(3) Method 5, 58, or 17 ofappendix A of this part shall be used to measure the concentration ofPM asfollows:

(i) Method 5 of appendix A of this part may be used only at affected facilities v,;thout wet scrubbersystems.

(ii) Method 17 of appendix A of this part may be used at affected facilities with or without wet scrubbersystems provided the stack gas terrperature does not elCeed a temperature of 160 "C (320 "F). Theprocedures of Sections 8.1 and 11.1 ofMethod 58 of appendix A of this part may be used in Method 17of appendix A of this part only if Method 17 ofappendix A of th is part is used in conjmction v,;th a wetscrubber system. Method 17 of appendix A of this part shall not be used in conjmction with a wetscrubber system if the effluent is saturated or laden Wth water droplets.

(iii) Method 58 of appendix A of this part may be used in conjunction v,;th a wet scrubber system.

(4) The sampling time for each run shall be at least 120 rrinutes and the minimum sampling volumeshall be 1.7 dry standard cubic meters (dscm) [60 dry standard cubc feet (dsc~l except that smallersampling times or volumes may be approved by the Administrator when necessitated by processvariables or other Ectors.

(5) For Method 5 or 58 ofappendix A of this part, the terrperature of the sample gas in the probe andfilter holder shall be monitored and maintained at 100 ±14 "C (320±25 "F).

(6) For determination of PM emissions, an oxygen (02) or carbon dioxide (C02) measurement shall be

obtained sirrultaneouslywith each run ofMethod 5,58, or 17 of appendix A of this part by traversing theduct at the same sampling location.

(7) For each run using Method 5, 58, or 17 ofappendix A of this part, the errission rates expressed inng/J (lb/MM8tu) heat input shall be deterrrined using:

(i) The 020r C02measurements and PM measurements obtained under this se::tion, (ii) The dry basis F

factor, and

(iii) The dry basis emission rate calculation procedure contained inMethod 19 of appendix A of this part.

(8) Method 9 of appendix A of this part (6-minute average of 24 observations) shall be used brdetermining the opacity of stack emissions.

(b) The owner or operator ofan affected facility seeking to demonstrate corrpliance v,;th the PMstandards under §60.43c(b)(2) shall derronstrate the maximum design heat input capacityof the steamgenerating unit by operating the steam generating unit at this capacity for 24 hours. This demonstrationshall be made during the initial perbrmance test, and a subsequent demonstration may be requested <iany other time. If the demonstrated 24-hour average firing rate for the affected facility is less than themaximum design heat input capacitystated by the manufacturer of the affected facility, thedemonstrated 24-hour average firing rate shall be used to deterrrine the annual capacity factor for theaffected facility; otherv,;se, the maximum design heat input caIBcity provided by the manufacturer shallbe used.

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(c) In place of PM testing with EPA Reference Method 5, 5B, or 17 of appendix A of this part, an OWleror operator may elect to install, calibrate, rraintain, and operate a CEMS for monitoring PM emissionsdischarged to the atrrosphere and record the ouput of the system. The owner or operator ofan affectedfacility who elects to continuouslymonitor PM emissions instead ofconducting perbrmance testingusing EPA Method 5, 5B, or 17 ofappendix A of this part shall install, calibrate, rraintain, and operate aCEMS and shall comply with the requirements specified in paragraphs (c)(1) through (c)(13) ofthissection.

(1) Notify the Administrator 1 month before starting use ofthe system.

(2) Notify the Administrator 1 month before stopping use ofthe system.

(3) The monitor shall be installed, eIBluated, and operated in accordance wth §60.13 of subpart A ofthis part.

(4) The initial performance evaluation shall be corrpleted no later than 180 days after the date of initialstartup of the affected facility, as specified under §60.8 of SUbpart A ofthis part or within 180 days ofnotification to the Adninistrator of use of CEMS if the owner or operator was previously determiningcompliance by Method 5, 5B, or 17 ofappendix A of this part performance tests, v.A1ichever is later.

(5) The owner or operator of an affected facility shall conduct an initial performance test for PMemissions as required under §60.8 ofsubpart A of this part. Compliance with the PM emission limit shallbe determined by using the CEMS specified in paragrap1 (d) of this section to measure PM andcalculating a 24-hour block arithmetic average emission concentration using EPA Reference Method 19of appendix A of this part, section 4.1.

(6) Compliance with the PM emission limit shall be deternined based (]1 the 24-hour daily (block)average of the hourly arithmetic average emission concertrations using CEMS outlet data.

(7) At a minimum, valid CEMS hourly averages shall be obtained as slEcified in paragraph (d)(7)(i) ofthis section for 75 percent ofthe total operating hQ.Jrs per 30-day rolling average.

(i) At least two data points per hour shall be used to calcilate each 1-hour arithmetic average.

(ii) [Reserved]

(8) The 1-hour arithmetic averages required under paragraph (d)(7) d this section shall be eJPressed inng/J or Ib/MMBtu heat input and shall be used to calcilate the boiler operating daydaily arithmeticaverage emission concentrations. lhe 1-hour arithmetic averages shall be calculated using thedatapoints required under §60.13(e)(2) ofsubpart A of this part.

(9) All valid CEMS data shall be used in calculating a-erage emission concentrations e\en if theminimum CEMS data requirements of paragraph (d)(7) ofthis section are not met.

(10) The CEMS shall be operated according to Perbrmance Specification 11 in appendixB of this part.

(11) During the correlation testing runs ofthe CEMS required by Performance Specification 11 inappendix B of this part, PM and 02(or CO2) data shall be collected concurrently(or within a 30- to 60-

minute period) by both the continuous errission monitors and the test methods speciied in paragraph(d)(7)(i) of this section.

(i) For PM, EPA Reference Method 5, 5B, or 17 ofappendix A of this part shall be used.

(ii) For 02(or CO2), EPA reference Method 3, 3A, or 3B ofappendix A of this part, as applicable shall be

used.

(12) Quarterly accuracy determinations and daily calibration drift: tests shall be performed in accordancewith procedure 2 in appendixF of this part. Relative Response Audit's must be performed annually andResponse Correlation Audits nust be performed every 3 years.

(13) Vllhen PM emissions data are not obtained becauseof CEMS breakdo'M1s, repairs, calibrationchecks, and zero and span ad~stments, emissions data shall be obtained by using other monitoring

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systems as appro-.ed by the Administrator or EPA Reerence Method 19 of appendix A of this part toprovide, as necessary, valid emissions data br a minimum of 75 percent of total operating hours on a3D-day rolling average.

(d) The owner or operator ofan affected facility seeking to demonstrate compliance under §60.43c(e)(4)shall follow the applicable procedures under §6048c(l). For residual oMired affected facilities, fuelsupplier certifications are only allowed for facilities with heat input capacities betv.een 2.9 and 8.7 MN(10 to 30 MM8tu/hr).

§ 60.46c Emission monitoring for sulfur dioxide.

(a) Except as provided in paragraphs (d) and (e) ofthis section, the owner or operator ofan affectedfacility sUbject to the S02emission limits under §60.42c shall install, calibrate, Illlintain, and operate a

CEMS for measuring S02concentrations and either ~or C02concentrations at the outlet ofthe

S02controi device (or the outlet of the steam generating mit if no S02controi device is used), and shall

record the output ofthe system. The owner or operator ofan affected facility subject to the percentreduction requirements under §60.42c shall measure S02concentrations and either ~or

C02concentrations at both the inlet and outlet oflhe S02controi device.

(b) The 1-hour average S02emission rates measured by a CEMS shall be expressed in ng/J cr

Ib/MMBtu heat input and shall be used to calculatethe average emission rates under §60.42c. Each 1hour average S02emission rate must be based on at least 30 rrinutes of operation, and shall be

calculated using the data points required untEr §60.13(h)(2). Hourly S02emission rates are not

calculated ifthe affected facility is operated less than 3J minutes in a 1-hour period and are not countedtoward determination of a steam generating unit ope-ating day.

(c) The procedures under §60.13 shall be bllowed for installation, evaluation, and operation oftheCEMS.

(1) All CEMS shall be operated in accordance vilh the applicable procedures under PerbrmanceSpecifications 1, 2, and 3 ofappendix B of this part.

(2) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordancewith Procedure 1 ofappendix F of this part.

(3) For affected facilities subject to the percent reduction reqLirements under §60.42c, the span \Blue ofthe S02CEMS at the inlet to the S0:2control device shall be 125 percent ofthe maximum estimated

hourly potential S02emission rate of the fuel combusted, and the span IBlue ofthe S02CEMS at the

outlet from the S02contrai device shall be 50 percent ofthe maximum estimated hourly potential

S02emission rate ofthe fuel combusted.

(4) For affected facilities that are not subj3cl to the percent redlction requirements of§60.42c, the spanvalue of the S02CEMS at the outlet from the S02controi device (or outlet ofthe steam generating unit if

no S02controi device is used) shall be 125 percent ofthe maximum estimated hourly potential

S02emission rate ofthe fuel combusted.

(d) As an alternati-.e to operating a CEM:> at the inlet to the S02controi device (or outlet of the steam

generating unit ifno S02controi device is used) as required under paragraph (a) 0 this section, an

owner or operator may elect to deterrrine the average S02emission rate by sampling the fuel prior to

combustion. As an alternatile to operating a CEM:> at the outlet from the S02controi device (or outlet of

the steam generating unit ifno S02controi device is used) as required under. paragraph (a) 0 this

section, an OWler or operator may elect to deterrrine the average S02emission rate by using Method 6B

of appendix A of this part Fuel sampling shall be condlcted pursuant to either paragraph (d)(1) or (d)(2)of this section. Iv'ethod 68 of appendix A of this part shall be conducted pursuant to paragraph (d)(3) ofthis section.

(1) For affected facilities combusting coal or oil, coal or oil sanples shall be collected daily in an as-firedcondition at the inlet to the steamgenerating urit and analyzed for sulfur content and heat cortent

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according the Iv'ethod 19 of appendix A of this part. Method 19 of appendix A of this part providesprocedures br converting these measurements into the brmat to be used in calculating the a\erageSOzinput rate.

(2) As an alternatil.e fuel sampling procedure br affected facilities combusting oil, oil sarrples may becollected from the fuel tank for each steam generating unit immediately after the fuel tank is filled andbefore any oil is combusted. The owner or operator ofthe affected facility shall analyze the oil sarrple todetermine the SUlfur content of the oil. If a partially empty fuel tank is refilled, a new sample and analysisof the fuel in the tank \',Quid be required upon filling. Results ofthe fuel analysis taken after each newshipment of oil is received shall be used as the dailyvalue when calculating the 3Q.day rolling averageuntil the next shipment is receil.ed. If the fuel analysis shows that the sulfur content in the iJel tank isgreater than 0.5 v.eight percent suliJr, the owner or operator shall ensure that the sultlr content ofsubsequent oil shiprrents is low enough to cause tre 3D-day rolling average sulfur content to be 0.5weight percent suliJr or less.

(3) Method 6B of appendix A of this part may be used in lieu of CEMS to measure SOzat the inlet or

outlet of the SOzcontrol system. An initial stratification test is required to \erify the adequacy of the

Method 6B of appendix A of this part sarrpling location. The stratification test shall consist ofthreepaired runs of a suitable SOzand COzmeasurement train operated at the candidate 10cati<J1 and a

second sinilar train operated according to the procedlJes in §3.2 and the applicable procedures insection 7 of Performance Specification 2 of appendix B of this part. Method 6B of appendiX A of this part,Method 6A of appendix A of this part, or a combination of Methods 6 and 3 ofappendix A of this part orMethods 6C and 3A ofappendix A of this part are sLitable measurement techniques. IfMethod 6B ofappendix A of this part is used br the second train, sarrpling time and timer operation may be adjustedfor the stratification test as long as an adequate sanple volume is collected; hov.ever, both samplingtrains are to be operated sinilarly. For the location to be acEquate for Method 6B of appendix A of thispart 24-hour tests, the mean ofthe absolute difference between the three paired runs nust be less than10 percent (0.10).

(e) The monitoring requirerrents of paragraphs (a) and (d) ofthis section shall not apply to affectedfacilities subject to §60.42c(h) (1), (2), or (3) lIhere the oy,ner or operator of the affected facility seeks todemonstrate compliance lhith the SOzstandards based on lJel supplier certifcation, as described under

§60.48c(~, as applicable.

(f) The owner or operator of an affected facility operating a CEMS pursuant to paragraph (a) ofthissection, or conducting as-fired fuel sampling pursuant to paragraph (d)(1) ofthis section, shall obtainemission data br at least 75 percent ofthe operating hours in at least 22 out of30 successil.e steamgenerating unit operating da~. If this minimum data requirement is not met with a single monitoringsystem, the owner or operator ofthe affected facility shall supplement the emission data lhith datacollected lhith other monitoring systems as approl.ed by the Administrator.

§ 60.47c Emission monitoring for particulate matter.

(a) Except as prol.1ded in paragraphs (c), (d), (e), and (J of this section, the owner or operator of anaffected facility combusting coal, oil, or \',Qod that is SUbject to the opacity standards under §60.43c shallinstall, calibrate, maintain, and operate a COIIfS for measuring the opacity of the emissions dischargedto the atmosphere and record the output ofthe system.

(b) All COMS for measuring opacity shall be operated in accordarce with the applicable proceduresunder Performance Specification 1 of appendix B of this part. The span value of the opacity COMS shallbe between 60 and 80 percent.

(c) Affected facilities that burn only distillate oil that contains nomore than 0.5 v.eight percent suliJrand/or liquid or gaseous tieIs lhith potential sulfur dioxide emission rates of26 ng/J (0.06Ib/fllMBtu)heat input or less and that do not use a postcombustion technology to reduce SOzor PM emissions are

not required to operate a CEf116 for measuring opacity if they follow the applicable procedures under§60.48c(~.

(d) Owners or operators corrplying with the PM emission limit by using a PM CEMS monitor instead ofmonitoring opacity must calibrate, maintain, and operate a CEMS, and record the output ofthe system,for PM emissions discharged to the atrrosphere as speciled in §60.45c(d). The CEMS specified inparagraph §60.45c(d) shall be operated anddata recorded during all periods ofoperation of the affectedfacility except for CEMS breakdoms and repairs. Data is recorded dlJing calibration checks, and zero

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and span adjJstments.

(e) An affected facility that does not use poskombustion technology (except a wet scrubber) brreducing PM S02' or carbon monoxide (CO) emissions, burns only gaseous fiJels or fuel oils that

contain less than or equal to 0.5 veight percent sl1fur, and is operated such that enissions ofCO to theatmosphere wom the affected facility are maintained at le-.els less than or equal to 0.15 Ib/M.IIBtu on aboiler operating dayaverage basis is not required tooperate a COMS for measuring opacity. Ownersand operators ofaffected facilities electing to corrply with this paragraph mist demonstrate complianceaccording to the procedures specifed in paragraphs (e)(1) through (4) ofthis section.

(1) You must monitor CO emissions using a CENS according to the procedJres specified in paragraphs(e)(1 )(i) through (iv) of this section.

(i) The CO CEMS must be installed, certifed, maintained, and operata:l according to the prO\,isions in§60.58b(i)(3) of subpart Eb ofthis part.

(Ii) Each 1-hour CO emissions average is calculated using the data ~ints generated by the CO CEMSexpressed in parts per nillion by volume corrected to 3 percent o<ygen (dry basis).

(iii) At a minimum, valid 1-hour CO emissions averages must be obtained br at least 90 percent of theoperating hours on a 3Q.day rolling average basis. At least tv.o data points per hour must be used tocalculate each 1-hour average.

(iv) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must beperformed in accordance wth procedure 1 in appendx F of this part.

(2) You must calculate the 1-hour average CO enissions levels for each steam generating unit operatingday by multiplying the average hourly CO output concertration measured by the CO CEMS times thecorresponding a-.erage hourly flue gas flow rate and divided by the corresponding a-.erage hourly heatinput to the affected source. The 24-hour average CO enission level is determined by calculating thearithmetic average ofthe hourly CO emission levels computed for each steam generating unit operatingday.

(3) You must evaluate the preceding 24-hour average CO enission level each steam generating unitoperating day excluding periods ofaffected source startup, shutdoWl, or malfunction. If the 24-houraverage CO enission level is greater than 0.15Ib/M.IIBtu, you must initiate investigation of the relevantequipment and control systems within 24 hours ofthe first discovery of the high enission incident and,take the appropriate correctile action as soon as practicatJe to adjust control settings or repairequipment to reduce the 24-hour average CO enission level to 0.15 Ib/MMBtu or less.

(4) You must record the CO measurements and calculations perbrmed according to paragraph (e) ofthis section and any corrective actions taken. The record of corrective action taken mist include the dateand time during v.ilich the 24-hour average CO enission level was greater than 0.15Ib/M.IIBtu, and thedate, time, and description ofthe corrective action.

(f) An affected facility that burns only gaseous fiJels or fiJel oils that contain less than or equal to 0.5weight percent sullir and operates according to a witten site-specific monitoring plan appro-.ed by theappropriate delegated pernitting authority is not required to operate a CONS for measuring opacity.This monitoring plan mist include procedures and criteria Dr establishing and monitoring speciicparameters for the affected facility indicative of compliance v.ith the opacity standard.

§ 60.48c Reporting and recordkeeping requirements.

(a) The owner or operator ofeach affected facility shall submit notification of the date ofconstruction orreconstruction and actual startup, as pro'ided by §60.7 of this part. This notification shall include:

(1) The design heat input capacityof the affected facility and identification of fuels to be corrtJusted inthe affected facility.

(2) If applicable, a copy of any federally enforceable requirement that limits the annual capacity factor forany fuel or mixture of fuels under §60.42c, or §60.43:.

(3) The annual capacity factor at which the owner or operator anticipates operating the afected facility

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based on all fUels fired and based on each irtlividual fuel fired.

(4) Notification if an emerging technology will be used fOr controlling S02emissions. The Administrator

will examine the description ofthe control de"';ce and will determine whether the technology qualifies asan emerging technology. In making this deternination, the Administrator may require the owner oroperator of the affected facility to submit additional infOrmation concerning the control delice. Theaffected facility is subject to the pro"';sions of§60.42c(a) or (b)(1), urless and until this detemination ismade by the Administrator.

(b) The owner or operator ofeach affected facility subject to the S02emission limits of §60.42c, or the

PM or opacity limits of §60.43c, shall subrrit to the Administrator the pertormance test data rom theinitial and any subsequent perbrmance tests and, ifapplicable, the perbrmance evaluation of the CEMSand/or COMS using the applicable perormance speciications in appendix B of this part.

(c) The owner or operator ofeach coa~fired, oil-fired, or wood-fired affected facility sUbject to the opacitylimits under §60.43c(c) shall subrrit excess emission reports br any excess emissions from the affectedfacility that occur during the reporting period.

(d) The owner or operator ofeach affected facility subject to the S02emission limits, fuel oil sulfur limits,

or percent reduction requirerrents under §60.42c shell submit reports to the Adninistrator.

(e) The owner or operator ofeach affected facility sUbject to the S02emission limits, fuel oil sulfur limits,

or percent reduction requirerrents under §60.42c shell keep records and subrrit reports as requiredunder paragraph (d) ofthis section, including the tJllowing information, as applicable.

(1) Calendar dates cO\ered in the reporting period.

(2) Each 3G-day average S02emission rate (ng/J or Ib/MMBtu), or 3G-day average sulfur content ('<\eight

percent), calculated during the reporting period, el1lling with the last 3G-day period; reasons br anynoncompliance with the emission standards; and a description of corrective actions taken.

(3) Each 3G-day average percent ofpotential S02emission rate calculated during the reporting period,

ending with the last 3G-day period; reasons br any noncompliance with the emission standards; and adescription of the corrective actions taken.

(4) Identification of any steam generating unit operalng days for which S020r diluent (020r CO2) data

have not been obtained by an approved method for at least 75 percent ofthe operating hours;justification for not obtaining suficient data; and a description of corrective actions taken.

(5) Identification of any times when emissions data ha\e been excluded from the calculation of averageemission rates; j.Jstification fOr excluding data; and a descrirtion of corrective actions taken ifdata havebeen excluded fOr periods other than those dLfing which coal or oil 'here not combusted in the steamgenerating unit.

(6) Identification of the F factor used in calculations, rrethod of determination, and type of fuelcombusted.

(7) Identification of whether averages ha\e been obtained based on CEM) rather than manual samplingmethods.

(8) If a GEMS is used, identification of any times when the pollutant concentration elCeeded the full spanof the GEMS.

(9) If a GEMS is used, description ofany modifications to the GEMS that could affect the ability of theGEMS to comply with PerfOrmance Specifications 2 or 3 ofappendix B 01 this part.

(10) II a GEMS is used, results ofdaily GEMS drift tests and quarterly accuracy assessments asreqUired under appendixF, Procedure 1 ofthis part.

(11) Illuel supplier certitcation is used to delTDnstrate compliance, records olluel supplier certiication

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is used to dermnstrate cOfllJliance, records offuel supplier certification as described under paragraph(f)(1). (2), (3), or (4) of this section, as applicable. In addition to records ofuel supplier certiications, thereport shall include a certifed statement signed by the owner or operator oflhe affected facility that therecords of fuel supplier certiications subrrilted represent all ofthe fuel combusted during the reportingperiod.

(f) Fuel supplier certiiication shall include the bllowing information:

(1) For distillate oil:

(i) The name of the oil supplier;

(ii) A statement from the oil supplier that the oil corrplies with the specifications under the deinition ofdistillate oil in §60.41 c; and

(iii) The sulfur content ofthe oil.

(2) For residual oil:

(i) The name of the oil supplier:

(ii) The location of the oil when the safllJle was drawn for analysis to determine the sulfur content oftheoil, specifically including Wlether the oilv.as sampled as deli-.ered to the affected facility, or whether thesample was dra'Ml from oil in storage at the oil supplier's or oil refner's facility, or other location;

(iii) The sulfur content of the oil from which the shipment came (or of the shipment itself); and

(iv) The method used to deterrrine the sulfur content oflhe oil.

(3) For coal:

(i) The name of the coal supplier;

(ii) The location of the coal when the safllJle was collected br analysis to determine the properties ofthecoal, specifically including Wlether the coalv.as sampled as delivered to the affected facility or whetherthe sample was collected Tom coal in storage at the rrine, at a coal preparation plant, at a coalsupplier's facility, or at another location. The certification shall include the nane of the coal mine (andcoal seam), coal storage lacility, or coal preparation plant (mere the sample was collected);

(iii) The results of the analysis of the coal from which the shipment came (or of the shipment itselQincluding the suliJr content, rmisture content, ash cortent, and heat content; and

(iv) The methods used to deterrrine the properties ofthe coal.

(4) For other fuels:

(i) The name of the supplier oflhe fuel;

(ii) The potential sulfur emissions rate ofthe fuel in ng/J heat irput; and

(iii) The method used to deterrrine the potential suliJr emissions rate of the fuel.

(g)(1) Except as provided under paragraphs (g)(2) and (g)(3) oflhis section, the owner or operator ofeach affected facility shall record and maintain records ofthe amount of each fuel combusted duringeach operating day.

(2) As an alternati-.e to meeting the requirements of paragraph (g)(1) ofthis section, the OWler oroperator of an affected facility that combusts only natural gas, wood, fuels using fuel certification in§60.48c(Q to demonstrate corrpliance v,;th the S02standard, fuels not subject to an emissions standard

(eXcluding opacity), or a mixture of these fuels may elect to record and maintain records ofthe amount

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of each fuel combusted during each calendar rronth.

(3) As an alternati-.e to meeting the requirements of paragraph (g)(1) of this section, the OWler oroperator of an affected facility or multiple affected facilities located on a contiguous propertyunit wherethe only fuels combusted in any steam generating wit (including steam generating units not sub¢ct tothis subpart) at that property are natural gas, mod, distillate oil meeting the most current requirementsin §60.42C to use liel certification to demonstrate compliance with the S02standard, and/or liels,

excluding coal and residual oil, not subjlct to an emissions standard (eJCluding opacity) may elect torecord and maintain records ofthe total amount of each steam generating unit liel delivered to thatproperty during each calendar rronth.

(h) The owner or operator ofeach affected facility subject to a federally enforceable requirement limitingthe annual capacity factor for any fuel or mixture of fuels under §60.42c or §60.43c shall calculate theannual capacity factor individually for each fuel combusted. The annual capacity factor is deterrrined ona 12-month rolling a-.erage basis wth a new annual capacity factor calculated at the end ofthe calendarmonth.

(i) All records required under this section shall be naintained by the owner or operator ofthe affectedfacility for a period of two years following the date ofsuch record.

U) The reporting period br the reports required under this sutpart is each six-month period. All reportsshall be subrritted to the Adrrinistrator and shall be postrrarked by the 30th day following the end of thereporting period.

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Section 508 I Accessibility

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day of February, 2009.

CERTIFICATE OF SERVICE

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

Alberto-Culver Company, 2407 Quality Way - Craighead Technology Park, Jonesboro, AR,

72401, on this ~

C4-L__Cynthia Hook, AAII, Air Division

Documents

ADEQ€¦ · Arkansas Air Pollution Control Code, Regulation 18, effective January 25, 2009 r Regulations ofthe Arkansas Plan ofImplementation for Air Pollution Control, Regulation