lasepost the attachedtwo issu(

From: BradFrost To: Batty,Stuart; Hartshorn,Wally Start: 7l19l2OO7 Due: 7l20l2$Ol Subject: Pleasepost the attachedtwo issuedpermits and the accompanyingresponsiveness summaryto the recor

Pleasepost the attachedtwo issuedpermits and the accompanyingresponsiveness summary to the recordfor the ConocoPhillipsCORE prolect. htto://www.epa.state.il.us/public-notices/qeneral- notices.html#conoco-ohillips-wood-river

Thanks Illinois EnvironmentalProtection Agency Bureauof Air Julv 2007

ResponsivenessSummary for PublicComments and Questions on the Cokerand Refinery Expansion Project at the Wood River Refineryin Roxana,Illinois andthe Wood River ProductsTerminal in Hartford,Illinois

Facility Identificationand Application Nos.: Refinery: 119090AAA, 06050052 Terminal:I 19050AAN.061 10049 Tableof Contents

Page Decision J Background CommentPeriod and Public Hearins Availabilityof Documents A AppealProvisions i Commentsand Questions with Responsesby thelllinois EPA 5 General 5 Air Pollution 8 New SourceReview 9 BACT/LAER 9 Air QualityAnalysis and Emission Offsets 15 Analysisof Altematives t6 Global Warmins 20 Air Permitting 25 Flaring 25 CrudeOil Supply 35 Delayed Coking )t Emissions 40 Other 45 Existing GroundwaterContamination 47 Compliance 48 Public Particioation 49 Other Comments 50 For Additional Information 50 DECISION

On July 19,200'1,the Illinois EnvironmentalProtection Agency (Illinois EPA) Bureauof Air issueda constructionpermit to ConocoPhillipsfor the Cokerand Refinery Expansion Project at its Wood River Refinery at 900 SouthCentral Avenue in Roxanaand the Wood River Products Terminalat 2150South Delmar in Hartford. The Bureauof Air hasalso issued this summaryto addressquestions relevant to the issuanceof the air permit and other questionsand comments raisedduring the commentperiod. Questionsrelating to the Bureauof Water permit will be addressedin a separateResponsiveness Summary when the Bureauof Water takesfinal action on therevised NPDES permit.

Copiesof thepermits can be obtainedfrom the contactlisted at the endofthis document.The permitsand additional copies ofthis documentcan also be obtainedfrom the Illinois EPA websitewww. eoa.state.il.us/public-notices/

BACKGROIJND

ConocoPhillipsoperates the Wood River Refinery locatedin Roxana,Illinois to producea varietyofpetroleum products for dishibutionin the St. LouisnChicago, and Indianapolis Metropolitan areasand throughout the Midwest. Wood River is positionedby refining capacity and by geographicallocation to processthe growing volumesofheavy crudeoil from Canada.

On May 15,2006,the Illinois EPA, Bureauof Air receivedan applicationfrom ConocoPhillips for a Coker and Refinery Expansion(CORE) Project. The CORE Project entailsinstalling facilities to increaseboth the total crudeprocessing and percentage of heavier.crudeat the Wood River Refinery in order to increasethe supply of petroleumproducts to the Upper Midwest. In order to handlethe increasedproduct throughput, ConocoPhillips is alsoproposing certain changesat the Wood River ProductsTerminal (also ownedby ConocoPhillips). The Illinois EPA is consideringConocoPhillips's CORE project and the changesto the WoodRiver Products Terminal to comprisea single largerproject for the purposeof the federalrules for Preventionof Significant Deterioration(PSD) andthe staterules for Major StationarySources Construction andModifi cation (MSSCAM).

COMMENT PERIOD AND PUBLIC HEARING

The Illinois EPA BureauofAir evaluatesapplications and issues permits for sourcesof emissionsto the atmosphere.An air permit applicationmust appropriatelyaddress compliance with applicableair pollutioncontrol laws and regulations before a permitcan be issued. Following its initial technicalreview of ConocoPhillips' application,the Illinois EPA Bureauof Air madea preliminary determinationthat the applicationsmet the standaf,dsfor issuanceof a constructionpermit andprepared draft permits for public review and comment.

ConocoPhillipsrequested that the Illinois EPA hoid a publichearing on the COREProject. This hearingalso addressed ConocoPhillips's application for revisionand reissuance of its National PollutantDischarge Elimination System (NPDES) permit to allow increasedwastewater dischargesfrom the Wood River Refinery due to the CORE project. The public commentperiod openedwith thepublication of a hearingnotice in theAlton Telegraphon March24, 20O7.The hearingnotice was published again in theAlton Telegraphon March31'' andApril 7,2O07. The publicheming was held on May 8, 2007,at theHartford Eiementary School in Hartford. The purposeof this public hearingwas to acceptoral commentsinto tle written hearingrecord and answerquestions about the proposedproject. The written commentperiod remainedopen until June15.2007.

AVAILABILITY OF DOCUMENTS

Theconstruction permits issued to ConocoPhillipsand this responsivenesssummary are availableon the Illinois PermitDatabase at wwv/.epa.gov/region5/airlpermits/ilonline.htm (pleaselook for thedocuments under All PermitRecords (sorted by name),PSD/lvlajor NSR Records).Copies ofthese documentsmay alsobe obtainedby contactingthe Illinois EPA at the telephonenumbers listed at the end of this document.

APPEAL PROVISIONS

The constructionpermits being issuedfor the proposedproject gfantsapproval to construct purswmtto the federalrules for Preventionof SigrrificantDeterioration of Air Quality (PSD),40 CFR 52.21.Accordingly, individuals who filed commentson the draft permit or participatedin the public hearingmay petition the U.S. EnvironmentalProtection Agency (USEPA)to review the PSD provisionsof the issuedpermit. In addition, as commentswere submittedon the draft permit for the proposedproject that requesteda changein the draft permit, the issuedpermit does not becomeeffective until afterthe period for filing ofan appealhas passed. The procedures governingappeals are containedin the CodeofFederal Regulations(CFR), 'Appeal ofRCRA, UIC andPSD permits," 40 CFR 124.19.If anappeal request will be submittedto USEPAby a meansother than regularmail, refer to the EnvironmentalAppeals Board website at www.epa.gov/eab/eabfaq.htrn#3for instructions. If an appealrequest will be filed by regulm mail, it shouldbe senton a timely basisto the following address:

U.S. EnvironmentalProtection Agency Clerk of the Board,Environmental Appeals Board (MC I l03B) Ariel RiosBuilding 1200Pennsylvania Avenue, N.W. Washington,D.C. 20460-0001 Telephone:202/233 -0122

A THE ILLINOISEP

General

1. Peoplehave catalytic converters on their cars. ConocoPhillipsshould put catalytic converte$on its operations.

The various emissionutrits at the refinery are and will be equippedwith appropriate equipmentto control emissionsof different pollutants. This control equiprnentdoes not include catalyticconverters like thoseused on automobileengines, Catalytic convertersare specificallydesigned to control certain pollutantsas presentin the exhaustfrom gasoline-fueledengines. The typesof control equipmentthat are used on different emissionunits at the refinery dependon the particular emission characteristicsof the units. For example,the emissionsof nitrogen oxides(NO*) from the Fluidized Catalytic Cracking (FCC) Units will be controlledby selective catalyticreduction (SCR)systems, which useammonia and a catalystbed to control emissions.NO, emissionsfrom heatersand boilerswill be controlledwith ultra low NO, burners that minimizethe formation of NO*.

What is the cunent conventionalcrude distillation capacityof the refine4fl

The current conventionalcrude distillation capacityis 306,000barrels per day.

3. What is the curent output of dieselfuel from the refinery?

ConocoPhillipsindicates that the output of dieselfuel is approximately70,000 barrels per day' all of which is low sulfur diesel.

A What will be the cetanelevel of the ultralow sulfir dieselfue1 after the proposedproject is complete?Is the cetanelevel dependenton renewablediesel production?

At the public hearing,ConocoPhillips indicated tlat the cetanelevel of low sulfur dieselocurrently at 48, is not expectedto change. The specificationfor low-sulfur dieselis a minimum cetanelevel of 42. The cetanelevel of low sulfur fuel produced by the refinery is not dependenton renewablediesel production.

5. Are future projectsexpected to reducearomatic content and increasecetane to meetthe new USEPA regulations?

The lllinois EPA is not able to predict the outcomeof future projectsat tle refinery.

Is gasolineoutput with the proposedproject dependenton the ethanoladdition to meet the minimum octanerequirements?

According to ConocoPhillips,the refinery hasthe ability to make gasoline blendstocksthat do not require ethanoladdition. Howeyer,one of the advantagesof the project is the ability to make more o'reformulatedblendstock." This is the gasolineblendstock that is preparedfor usewith 10 percentethanol.

7. What is the maximum vaporpressure specification for gasolinein summermonths?

As explainedby ConocoPhillipsat the public hearing,there is no longer a vapor pressurespecification. Reformulated gasoline has what is termed a "VOC limit," which is an equationthat incorporatesvariables such as the actual distillation points of the blend, the sulfur content etc.

6. What is the cap on vapor pressureof gasoline?

As explainedby ConocoPhillipsat the public hearing,since reformulated gasoline is now requiredothere is no longer a cap on the vapor pressureof gasoline.The actual vapor pressurefor the reformulatedgasoline blendstock produced by the refinery is now about 5.5 Reid vapor pressure(RVP). In the past,when the vapor pressure was capped,the RVP was 8.0. The reasonthat reformulatedblendstock has to be lower than 5.5 RVP is becauseblending ethanolwith gasolineelevates the vapor pressure,which must be compensatedfor by a lower RVP in the gasoline blendstock.

9. Will the proposedproject enableConocoPhillips to removepentanes during the summer to allow ethanolblending? Also, ifpentanes aretaken out, where arethey stored?

The new coker gasplant will irnprovethe separationof pentanesfrom the gasoline blendstock.These pentanes are storedand blendedinto conventionalgasoline for usein attainmentareas.

10. How much natural gasdoes the refinery usetoday comparedwith how much it will use after the proposedproject? Will hydrogenbe producedfrom natural gas?

The main sourceoffuel for usein the refinery is refinery fuel gasproduced as a byproduct of refining operations.According to ConocoPhillips,the refinery would typically useabo 'I 40 million standardcubic feet of natural gasper day after the proposedproject which is what it currently uses. The proposedhydrogen plant will userefinery gasas a feedstock.The needfor hydrogenis minimizedby the using of coking as an initial cracking process.As related to minimizationof flaring, useof natural gasto supplementthe fuel supply to the refinery is desirableas it provides the necessaryflexibility to be able to consistentlyrecover waste gas for useas fuel

11. Ratherthan flaring wastegases, ConocoPhillips should capture the energyvalue ofwaste gasesby capturingthem and using them as fuel.

Theserecovery systems are alreadyin placeat the refinery, For example,the majority of fuel gasesused in the refinery, which are usedas fuel in the heatersand boilers,comes from recoveredprocess gss.

6 12. I am concernedabout benzene releases from the refinery.

A variety of federal regulatory programscurrently in placeare actitrgto reduce releasesof benzenefrom the refinery. In addition, USEPAis adoptingregulations to reducethe benzeneemissions from automobilesand other gasolinepowered vehicles,which would require a signilicant reductionin the benzenecontent of gasoline.

13. I am concemedabout the amountand quality of wastewaterdischarged from the refinery.

Commentsand questionsabout wrstewaterdischarges will be addressedby the Illinois EPA's Bureau of Water when it takeslinal action otr ConocoPhillips' applicationfor a revisedNPDES permit for the Wood River Refinery. t4. We arerunning out of gas. We've reachedmaximum production,and we've got to find the gasor the peholeumand we haveto useit at the sametime. We haveto conserve.It doesn'tmake senseto use it up as fast aswe can becausewe have children and grandchildrento think about. The other thing that's a reality is the problem ofglobal warming issuethat we all haveto deal with. I hopethat ConocoPhillipswill look into using renewablesources of energyat this refrnery. Are there any plansto try to use solar panelsor wind or electricity generatedfrom the river as part of the proposedproject?

As discussedby ConocoPhillipsat the public hearing ConocoPhillipshas a technologygroup that is looking into alternativesources of power,but at this point in time they do not fit into this particular project.

15. What additional safetymeasures can be takenby ConocoPhillipsto assurethe safetyof the workers andthe surroundingcommunity should a major incident occur? What waming alert systemis in place for the surroundingcommunities in the eventof a chemicalleak, explosionor toxic release?A full emergencycommunity alert system shouldbe in place that includesa telephonewarning systemand communitywarning signalsthat distinguishwhether residents should evacuate or seekcover inside,with the environmentalstandards.

ConocoPhillipsindicates that worker safetyis alwaysa concern,both to protect individual workers from accidentsand to prevent incidents. Work to improve worker safetylincluding safet5rawareness, safetSr compliance and operationaland processchanges to improve safety,occur on an ongoingbasis. Theseactions also reducerisks for nearby residents.The refinery doeshave a communityalert network, by which it can quickly contactarea residentsby phonein the caseof an emergency.

16. The draft permit doesnot addressnew equipmentand processchanges for productionof renewablediesel fuel from animal fats and vegetableoi1s, as recently announcedby ConocoPhillips. If this activity is going to occur at the Wood River refinery, why is there nothing in the permit applicationand the draft permit relating to theseplans? The production of renewablediesel fuel is not addressedby the applicationfor this permit or the permit itself becauserenewable diesel fuel is not part of the CORE project that is being addressed.ConocoPhillips has not announcedspecific plans for the Wood River refinery in this regard. If ConocoPhillipsdecides to produce renewablediesel fuel at the Wood River refineryna separateconstruction permit would be required for the new equipmentand processchanges that would be involvedwith the project. The changesin emissionthat would accompanythe project would be addressedduring the processingof that application. Air Islulios t7. How many odor complaintswere receiveddue to the Wood River refinery during the last tlree years,and what was the natureof thern? What evaluationsand equipment improvementshave been carried out in order to eliminateodor complaints?Have evaluationsbeen performed to eliminateodor complaintsin the new project?

Five odor complaintshave been received by the Illinois EPA in the pastthree years due to "refinery-type' odors. Three were petroleumodors in the Hartford area. One was a sulfur odor in the SouthRoxana area. One was a pungenttype odor in the Wood River area.

The refinery was granteda constructionpermit in May 2006to replacea ground level flare with an elevatedflare. The useofan elevatedflare as opposedto a ground level unit will reduceany potentialfor odor associatedwith the operationof this flare.

Additional odorsare not anticipatedto result from this project. One of the principal concernsfor odorsis emissionsof hydrogensullide (HrS). The control equipmentin placetoday and the proposedcontrols in this project will result in minimal emissionsof H2S. If odorsdo occur,the Illinois EPA will investigateand take appropriateaction for eachodor complaint that it receives.If equipmentis not being operatedproperly, the solutionis obvious. If equipmentis operatedproperly but nuisanceodors occur,further investigationwould be neededto determinewhat shouldbe doneto alter the operationto mitigate or eliminatesuch odors.

18. Whenthe wind blows from that direction where I live, abouta half mile away,I smell the cokerwhen it rains. Thecrude oil odoris sobad. Is it goingto beworse?

Although there havebeen a handful of complaintsdue to refinery type odors,none havebeen related to the operationof the existingcoking unit Operationof a second cokingunit is not expectedto generateadditional odors at the refrnery.

19. I live aboutthree miles downwind of the refinery and I havehad asthmaall my life. I cannotimagine what it would be like to havemore particlesin the air. While the project itself will haveemissions of particulate matter, they will be more than offsetby the reductionsin emissionsof particulate maffer from existingunits, so there will be a net decreasein particulate matter emissions.(Refer to the Attachmentsto the permit that addressemissions of particulatematter.

BACT/LAER

20. Canthe Illinois EPA providea listingof the emissionunits that ConocoPhillips purchasedfrom Premcor?

Appendix C of the ConsentDecree contains a list of assetsConocoPhillips purchasedfrom Premcor. This ConsentDecree can be found on the internet at

21. Whatdoes 'lowest achievableemission rate" mean?

The lowestachievable emission rate is the most stringent emissionlimit derived from either (1) the most stringent emissionlimitation contained in the implementationplan of any statefor such classor categoryof source;or (2) the moststringent emissionlimitation achievedin practiceby suchclass or categoryof source.

22. ConocoPhillipsshould invest up front in better control technologyat the refinery.

ConocoPhillipsis required to upgradeemission control technologyon various units at the relinery pursuant to the Consent Decree,which requires upgrades of control equipments on boilers and heaters,the sulfur recoveryplants, and catalytic crackingunits. All units at the refinery mrst comply lvith applicablefederal NESHAP standards. For new and modified units affectedby the proposedproject, in addition to complyingwith federal NSPSstandards, ConocoPhillips must implementBest Available Control Technology(BACT) for emissionsof carbon monoxide(CO) and the Lowest AchieveEmission Rate for emissiotrsof volatile organicmaterial (VOM). zJ. If this projectis approved,ConocoPhillips should be requiredto usethe best available emissioncontrol tecbnology,regardless of the cost. It shouldalso not be able to do any emissionstrading. ConocoPhillipscan afford to do everythingpossible to reducethe emissionsfrom the refinery after this project and it shouldbe requiredto do that.

This project is subjectto New SourceReview for emissionsof VOM and CO. Accordingly,ConocoPhillips must implementthe LowestAchievable Emission Rate (LAER) for VOM emissionsand the BestAvailable Control Technology@ACT) for CO emissions.LAER doesnot considercost of coltrols unlessthe costof maintaining a particular level ofcontrol would be so great that a project could not

9 be built or operatedat any locationor reasonableset of circumstances.Cost factors can be consideredin a BACT determination,to the extentallowed by USEPArules and guidance.Cost was not a significantfactor in the determinationsof BACT and LAER madefor the proposedproject.

24. The CO emissionlimit proposedin the applicationas BACT for fladng,0.37 lbVmillion Btu, wouldnot be enforceable.There is no practicalmethod to enforcethis limit, which by its natureis an emissionfactor and not a measurement.ConocoPhillips also has not proposedany methodto verify compliancewith this limit. It would be very convenient for ConocoPhillipsto havea BACT limit thatby definitionis met independentof how much CO a flare emits,with the calculatedemissions always being equalto the limit.

As notedby this comment,the CO emissionlimit proposedby ConocoPhillipsas BACT for flaring is a USEPAemission factor and was not intendedto be enforceablein the samemanner as a more traditional emissionlimit. Instead"the proposedCO emissionlimit was intendedto serveas a representationof the CO emissionsof a properly operatedflare. However,as implied by this commen! proper operationof a flare shouldbe direcUyaddressed by specifyingthe particular work practicesthat must be implementedfor the flare, It would be poor regulatory practice to rely on a emissionlimit to implicifly require proper operationof a flare as speciticpractices for proper operationcan readily be set In addition,setting BACT solelyin terms of an emissionlimit would not act to require practicesto prevent and minimize flaring.

25. TheCO enissionlimit proposedin the applicationby ConocoPhillipsas BACT for flaring,0.37 lbs/million Btu (proposedon page7-9 of the application)was correctly rejectedby the Illinois EPA. SettingBACT asthis emissionlimit would not serveto reduceCO emissionsby reducingthe amountof flaringthat occurs. While it doesnot appearthat the Illinois EPA hasapplied this limit asBACT, it is whatConocoPhillips proposed.In casethe Illinois EPA is still consideringthis limit or has somehowincluded it in its calculationsunderlying other limits in the draft permit, the Illinois EPA should rejectsuch a notion. Theproposed limit is actuallya USEPAemission factor for CO ernissionsexpressed in termsofthe fuel value ofthe wastegas that is flared. This factor hasnothing to do with BACT. Sucha limit would allow unlimitedhours of routine flaring at this rate, andby definition is not the bestavailable technology but is insteadan averageor typical CO emissionfactor for flaring.

The issuedpermit doesnot setBACT for CO in terms of this emissionrate proposed by ConocoPhillips.BACT for CO is setin terms of work practicesto minimize CO emissions,consistent with the generalapproach taken in the draft permit. These work practiceshave been further developedas a result of further reviewby the Illinois EPA in responseto other public comments,

26. Project VOM flaring emissionsdo not meetLAER requirements.The Project Summary for the proposedproject preparedby the Illinois EPA incorrectly implies that the main sourceof VOM from flaringis thepilot flame,so that this shouldbe the mainfocus of

l0 the LAER evaluationand no other sourceofflare emissionsneed be evaluatedfor LAER.T However,the largestcontributor to VOM emissionsftom flming is the waste gasesthat are flared, since a percentageofthe VOM is not destroyedand is ernitted. Flaresare typically considered to havea VOM destructionefficiency of98% with good combustionconditions, with 2Toof VOM routedto the flme being emitted. This is a significant percentagegiven the natureand magnitude of flaring that can occuf at a refinery. Thereforethe statementabove that "since flares themselvesare VOM confrol devices,no additionalcontrol ofthe VOM that is generatedthrough the combustionof pilot fuel gasis necessary"is doubly inaccurate.LAER requiresmeasures to pfevent flaring eventsentirely, rather than allowing flaring, which still emits VOM to the atmosphere.

The statementin the Project Summary addressedby this commentwas not intended to havethe further meaningclaimed by this comment. Indeed,the statementis fully consistentwith the further discussionin the comment,as it addresseswaste gases, rrther than the pilot flame, as the principal contributor to CO and VOM emissions from flaring and the appropriatefocus of a BACT and LAER evaluationfor flaring.

27. The draft permit would set "blendedlimits" on emissionsfrom new flares and other units so that separateBACT and LAER limits for flaring would not be set. In paf,ticular, Condition4.7.6 of the draftpermit, which shouldaddress only flaring,would set emissionlimits for the DelayedCoker Unit Flare (DCUF) that may also addressother operationsrelated to the new coker. The limits that are set for the new HydrogenPlant (HP2)would addressthe HydrogenPlant Heater (lIP2 H-1), the associatedCooling Water Tower (CWT 24) and, fugitive emissions,as well asthe flaxe(IIP2F). The scope of theselimits obscuresexactly how muchemissions of CO andVOM wouldbe allowed for flaring with BACT and LAER. The applicationmust provide a clear and complete project descriptionand the permit must set limits for the individual emissionunits to ensurethat eachunit meetsBACT and LAER.

The permit doesnot set "blended" limits for the permitted annual emissionsof the flare for the new DelayedCoker Unit and this flare's permitted emissionsof CO and VOM are setby Condition 4.7.6,

While blendedlimits are set for the permitted annual emissionsof the flare for the new HydrogenPIan! the flare is permitted to emit up to the limits in Condition 4.7.6. Ilowever, separate,lower limits are alsoset in Condition 4.1.6for the process heaterfor the plant, Heater HP2 H-1. Condition 4,6.6sets a limit on the VOM emissionsof CoolingWater Tower 24, allowing only minimal VOM emissions.The emissionsofthe llare by itself are expectedto be no more than the differencein theselimits. For example,the expectedannual emissionsof CO would be no more

| 'The RBLC databasestates for past pernits that sinceflares are themselvesVOM control devices,no additional control of the VOM from the combustionofpilot fuel gasis necessary.Therefore, no additionalVOM control technologiesare necessaryfor the two new flares." Project Summary,page 19.

ll than 36.2tons.2 While annualCO emissionscould be greaterOut in no casemore than 147.9tons as limited by Condition 4.7.6),this could only occur with circumstancesthat actedto lower CO emissionsof the processheater, This approachhas beentaken for the new HydrogenPlant giventhe nature and designof the unit which generatesa low VOM contenqbyproduct wastegas stream that is normally usedas fuel in the unit itself.

28. The BACT/LAIR evaluationfor flaring did not evaluatethe most stringenttechnologies available,which prevententire flaring eventsand achievethe maximum degreeof CO and VOM emissionreductions. In this regard,the applicationincorrectly indicatesthat thereare no "technicallyfeasible CO controloptions" for the flares.(See Sections 7.3 of the application.) Other refinerieshave equipmentand practicesthat minimize flaring emissionsby minimizing flaring. Suchapproaches were not evaluatedfor the project. Preventingflaring eventscompletely or minimizing the quantitiesof gasesflmed is the bestmethod to preventboth VOM and CO emissionsand all other flaring emissions (includingcarbon dioxide (CO)). Suchmethods were not evaluatedin the application for theproposed project.

The BACTiLAER evaluationsfor the proposedproject for flaring was madebased on the featuresin the designof the new DelayedCoker Unit that will act to minimize flaring and in the contextof existingrequirements that addressflaring at the Wood River refinery. In particular, the ConsentDecree also includes requirements relatedto hydrocarbonflaring events,as is relevantto emissionsofCO and VOM from flaring. The causeof significanthydrocarbon flaring incidentsmust be investigated,including performanceof root causeanalyses, steps must be taken to correct the conditionsthat causesuch incidents. and the number and extentof such incidentsmust be minimized, Detailedreporting is alsorequired for theseincidents. Provisionshave beenincluded in the issuedpermit that makesimilar requlrement applicablefor the new flaresthat would be installedwith the proposedproject

29. Additional evaluationof BACT and LAER is neededfor venting ofpressurerelief devicesto gasrecovery systems (while addingsufficient compressorcapacity so that this doesnot causeadditional flaring).

Pressurerelief devicesare addressedby the provisionsfor flaring, as they are mechanismsthrough which wastegases are ventedfrom processunits at refineries for recovery or flaring.

30. The annualVOM emissionrate from flaring achievedby Shell, Martinez, shouldbe used asthe basisto set a LAER limit for the proposedproject. This resultsin a LAER limit for the Wood River refinery of 5.9 tonVyear,given that the Wood River refinery is about four times larger than the Martinez refinery.' Shell statesin its Flare Minimization Plan that it hasbeen able to achievelow flaring emissionsincluding emergenciesin a safe

' 147.9tons (overall limit on CO emissions)- 11 1.7 tors (limit on heaterCO emissions)= 36.2 tons (remainder availablefor flare). 3 (385,000banels per day(bpd) projected for ConocoPhillips)/(9S,500bpd ShellMartinez) x 1.5py = 5.9 *,

t2 ma rer. Nothing in the BAAQMD flare rule with its requirementfor a Flare Minimization Plan (FMP) causesany compromisein saferefinery operations,which allow flaring in a true emergency.However, the FMP doesrequire rigorous monitoring, reporting planning, and evaluationofflare events,and equipmentimprovements so that methodsand equipmentare in placeto preventemergencies and minimize flaring. These methodsmake the refinery saferby minimizing emergencyshutdowns and reducing repeatedfl aring emissions.

The information cited in this commentdoes not support settinga LAER requirementfor the Wood River relinery that is expressedin terms of annual emissions.As noted by the comment,the relevant BAAQMD regulationsdo not prohibit flaring, as flaring is an appropriateaction to addressdisposal of process gasin emergencies.Likewise, Flare Minimization Plan preparedby ShellMartinez indicatesthat noneof the proceduresthat are part ofthat plan would restrict access to the flares when flaring is viewedas necessary for personnelor equipmentsafety, which further necessitatesflaring by operatorswithout hesitationwhen warranted for safety. Settinga limit in terms of annual emissionsof flaring, in the manner proposedby this comment,would potentially act to prohibit flaring when it was appropriate. It would setan absolute,enforceable limit on the extentof flaring that could occur at the refinery independentof the actual circumstancesat the refinery in a particular year.

J1- Additional evaluationof LAER is requiredfor fugitive emissionsfor the refinery as a whole to provide baselineand future conditionswith increasedcapacity, which will likely lead to increasesin fugitive ernissions.Information on frequencyof inspectionofvalves, flanges,pumps, and compressorsfor leaksand information on any past violations at the refinery involving theseoperations should be provided. Lists shouldbe provided includingthe numbers of all typesofvalves, flanges, pumps, and compressor seals.

LAER for VOM emissionsdue to componentleaks is appropriately addressedby relianceupon and referenceto the provisionsof the NESHAP for Petroleum Refineriesthat addresscomponents leaks. The NESHAP providesa comprehensive approachto this sourceof emissionsfor very effectivecontrol of emissions.It requiresimplementation of a Leak DetectionAnd Repair (LDAR) program to identify and repair leaking componentsin a timely manner. As certain typesof serviceand applicationsare more likely to havecomponents that experience frequent leaksand require repairs and follow-up monitoring if conventionaltypes of fittings are used,the NESHAP leadsto useof "advancedfittingsr" as discussedin this commen! in thoseapplications. This is becauseof the stringent definition of the NESHAP for a leaking component,At the sametime, advancedlittings are not required in circumstancesin which they might actually leadto increasedemissions, as advancedfitting are not as reliableunder certain typesand conditionsof service.

The ConsentDecree addresses VOM emissionfrom existingcomponents at the refinery, as it requires enhancementsto the LDAR Program for existing components.These enhancements should act to significantlyreduce the VOM

13 emissionsfrom leakingcomponents at the existingprocess units at the refinery.

TablesC-3a and C-3b of the applicationprovide a listing of the varioustypes of componentsto be installed,type of servicefor eachcomponents, quantity ofeach componenttype, and the area (processunit) in which the componentswould be installed.

)2. Additional evaluationof LAER is requiredfor VOM emissionsfrom wastewater treatmenttanks andponds, including evaluationofupstream controlsto prevent contaminationof wastewaterthat leadsto emissionsof hydrocarbonsand wastewater containinghydrocarbons and other pollutants and enclosureof any openwastewater systems,and data on concentrationof hydrocarbons(lighter productsand heavy diesel- range)and other contaminantsin the wastewater.

LAER is appropriatelyset for wastewatertreatment plant operations, Pollution preventiontechniques are well establishedto prevent avoidablecontamination of wastewater,As suchcontamination does occur and is inevitablegive the nature of petroleumrefining. The initial focusfor control of emissionsof VOM and other volatile pollutantsfrom wastewateris containingsnch materials with the wastewater.This enablesemissions of thesematerials to be controlledin the initial treatment units, which are designedto separatevolatile material from the wastewater,rather than beinglost directly to the atmospherefrom the drain system as wastewateris being transportedto enclosedtreatment units. The VOM emissions from the initial treatment units are then readily controlledas the emissionsare combustible.The VOM emissionsgenerated as a byproduct of subsequent treatment units are alsoreadily controlled as units are enclosedand the bulk ofthe gasstream is methaneproduced from anaeraobicwastewater treatment.

Data on the presenceof hydrocarbonsin the wastewaterwould not be useful,as it would not directly correlatewith the potentialVOM emissionsfrom treatment plant operations. In particular, the presenceof product materialsshould be expectedto reduceVOM emissionsas VOM emissionswould dissolvein suchcompounds and then be readily removedin the oil water separators.

JJ. LAER for VOM ernissionsfor the new storagetanks shouldrequire that tanks be equippedwith unslottedguidepoles, rather than slottedguidepoles. Unslotted guidepoles shouldalso be installedon existing storagetanks. This is becauseslotted guidepoles havea sigrrificantcontribution to the VOM emissionsof a floating roof tank.

Slottedguideposts that are closedat the top and equippedwith sleevesand wipers, aswould be usedfor the new tanks, do not contribute significantlyto the VOM emissionsfrom a floating roof tank. The useof unslottedguideposts and appropriately equippedslotted guideposts, cannot be distinguishedfor purposesof control of VOM emissions,based on USEPA emissionsestimation methodology for tanks, In part, this is becauseslotted guideposts eliminate the needfor separate fittings on a tank for samplingatrd level measurements,which alsocontribute to

14 VOM emissions.As a resulf the net effectof useof slottedguideposts is not significant.

34. Additional evaluationof LAER is requiredfor existing storagetanks at the refinery, which will haveincreased tlroughput due to the project, which shouldbe upgradedto BACT. The applicationshould have listed all storagetanks for an evaluationofbaseline conditionsincluding tank type, product,throughput, information on tank fittings and controls,past violations, tank degassing procedwes, tank cleaning procedures, etc.

The existingtanks for which LAER requirementshave not beenset are not subject to LAER becausethey are not beingphysically modified and will not experiencea changein the methodof operation, The applicationdoes addresses increases in VOM emissionsat existingtanks that will potentiallyoccur due to increasesin the throughput of thesetanks as a result of tle project.

AIRQUALITY AI{ALYSIS AND EMISSION OFFSETS

35. Has therebeen an evaluationby the Illinois EPA of cumulativeimpacts of this project in conjunctionwith the other nemby sourcessuch as US Steelin GraniteCity?

This project will potentially result in an increasein emissionsof CO that would qualify as significantunder the federal rules for Preventionof Significant . Deterioration(PSD). The air quality impact analysisperformed for CO emissions for the proposedproject showsthat air quality for CO will not be signilicantly impactedby the project. Modeling of other PSDpollutants was not performed or required for the proposedproject as emissionsofthese other PSD pollutantswill either decreaseor not increasesignificantly with the project as comparedto the applicablePSD significantemission rate. Accordingly, air quality for thesePSD pollutantswill improve or not changesignificantly,

The role of the Wood River refinery in regionalair quality for ozoneand PM25,for which the Greater St, Louis area is alsocurrently nonattainment,will be addressed by the lllinois EPA and the Missouri Departmentof Natural Resources.This will occur during the air quality analysisthat will be part of the developmentof the plans to bring the area into attainmentwith the National Ambient Air Quality Standardsfor ozoneand PM2s.

36. Throughemission offsets, clean air in St. Louisis beingtraded for dirty air in Roxana.

The offsetsfor emissionsof VOM required for the proposedproj€ct do not trade cleanair in one locationfor dirty air itr another,as both St Louis and Roxanaare locatedin the Greater St. Louis area. This is becausethe ozonein the ambient air is not emittedfrom sourcesbut is formed in the atmospherefrom photochemical reactionsofprecursor compounds,i.e., VOM and N0,, in the presenceof sunlight. High ambientlevels of ozonethat exceedthe National Ambient Air Quality Standardmay occur many miles downwind from a collectionof sourcesat which

15 precursor compoundsare emitted. Long rangetransport of precursorsis also important for ozoneair quality as transport affectsthe levelsof precursorsin the air enteringurbln areas. Given thesecircumstances, the Greater St. Louis areais a singlenonattainment area, with an overall problemwith nonattainmentofthe ozone air quality standard. Given the nature of the problem,it is not possibleto distinguishor differentiatethe effectson ozoneair quality from emissionsof VOM in Roxanafrom thosein St Louis.

Incidentally,the plannedoffsets also satisfy applicable regulatory requirements. Illinois' rules governingmajor modificationsin nonattainmentareas, which reflect the provisionsof the CleanAir Ac! require emissionsoffsets for VOM to be obtainedfrom within the samenonattiinment area as a proposedproject, The emissionoffsets planned for this project clearly meetthis requirement.

What is the nameof the sourceproviding the VOM emissionoffsets for this project?

The offsetswill comefrom JW Aluminum Company,which is locatedjust southwest of downtown St Louis.

38. What is the statusof the PremcorConsent Decree and how is it manaeedwith the ConsentDecree for ConocoPhillips?

The ConsentDecree previously signed by Premcor(99-87-GPM) has effectivelybeen incorporatedinto the new ConsentDecree with ConocoPhillips(II-05-0258) as is shownby the provisionsin the new decreeaddressing the Distilling West FCC Unit.

39. Creditsfor somethingthat was requiredunder a consentdecree should not be available for usein a netting or offset hansaction.

The relevantprovision ofthe ConsentDecree that addressesthe ability to utilize creditsfor the proposedproject is Paragraph262(d). This paragraphprovides that if ConocoPhillipshas a singleproject that involvesinstallation of ConsentDecree controlsas well as other constructionthat would occur at the sametime and be permitted as a singleproject ConocoPhillipscan utilize the emissionsdecreases from the installation of controlsrequired by the ConsentDecree for that project.

40. How is eachunit purchasedfrom Premcortaken into accountin the netting analysis?

The permit for the project includesinformation showinghow eachunit is or is not usedin the netting exercisefor the proposedproject. (Refer to the permit, Table III in Attachments2 through 8.)

AI\ALYSIS OF ALTERNATIVES

41. Pollutionprevention methods and project altematives to coking,which would avoidthe variousimpacts from coking, shouidhave been publicly evaluated.

lo There are not apollution preventionmethods" available to ConocoPhillipsthat would avoid the needfor coking. While tle healy streamof material that will be cokedcould be sold as asphalt,the marketsfor asphaltare both limited and seasonal.If this streamwere sold as asphaltothis streamof material alsowould not be availrble to be refined into gasolineand dieselfuel, which are the products ofthe refinery for which consumptionis increasing.

Coking is a modern crude oil processingtechnology that is routinely usedat refineriesfor the purposesand in the circumstancesin which ConocoPhillipswould useit. The reasonswhy this technologyis usedin particular situation relateto well- recognizedfactors that affectdecisions by any refinery with respectto process equipment Theseinclude availability and costof crude oil for the relinery givenits location,the amountsof different productsthat consumedby local markets,the value of different products,the type of processingthat is neededto produce different products given the nature of tle crude oil supply,the reliability, yield, energyconsumption and other demandsof different processes,the capacityand capability of existingequipment at a relineryothe ability to meetor supplementthe demandfor certain productsby other means,competition from other companiesto meetthe demand,etc. Given the commonuse of coking processesto crack heavy petroleumstreams distilled from crude oil or bitumen, it is not necessaryfor ConocoPhillipsto revealthe specificevaluations and businessdecision-making that led up to the proposedproject.

Why shouldn't the refinery use a hydrocrackerin conjunctionwith the delayedcoker?

The primary conversionprocesses commonly evaluated are non-catalytic(e.g., delayedcoking) and catalytic(e.g., hydrocracking). A refinery must generally determinewhich processis more advantageousbased on criteria suchas the compositionof crude oil supply that is availablefor the refinery, operatingand maintenanceneeds, frequency of start-ups,and markets for different products. Becausethe Wood River refinery is an existingrefinery, ConocoPhillipsmust also considerwhich processwill better handlethe various products and intermediates from either the catalytic or non-catalyticprocess considering the existingprocessing equipmentat the refinery. Of particular relevanceis the fact that this refinery currently operatesa delayedcoker, which meansthat the proposedsecond delayed coker could be installedto be directly integratedwith the existingdownstream processunits. Considerableimprovements over the yearshave also been made to the safetyof delayedcokers through the Nutomttic unheadingof cokedrums. The Illinois EPA has determinedthat there is no reasonto believethat the proposed coker is any lesssophisticated or "modern" given the current configuration ofthe refinery and the typesof crude slateswhich would be processedat the refinery, Also relevantfor this choiceis the energybalance and products of the refinery. The hydrocrackingprocess is dependentupon the useof hydrogen,where as coking crackshydrocarbons without needfor hydrogen. Coking doesproduce a solid by- product for ryhich there must be a suitablemarket.

77 +J. If therewere a cleanerfeedstock available {iom Canada,it might lower emissionsand requireless water and wastewater and cleaning ofpipelines and less processing at the Wood River refinery. It seemslike a cleanerfeedstock might reducethe environmental impact of the entireprocess from the start of the pipeline to the activities at the Wood River refinery.

The transportationprocess for this new supplyof crude oil versustransport of partially refined productswill not result in any additional energyimpacts or cleaning. When the material is receivedat the refinery, all of the non-petroleum materialswill be processedin the refinery just as existingcrude is processed.For example,water will be extractedin the process,and it will be handledthrough the wastewatertreatment plant consistentwith typical refinery practices.

44. At the oil sandsdeposit in Alberta, Canada,state-of-the-axt refining technologyis being usedto processsome of bitumeri,with a high-percentageconversion to light crudecalled syntheticcrude oil, which is put into light products. In contrast,delayed coking is an older technology,which hasbeen the subjectofOSHA andUSEPA safetywarnings. Why is ConocoPhillipsinstalling a delayedcoker unit when it could use modem technology,like in Canada?Also, why couldn't the crudeoil undergohydrocracking in Canadabefore it is shipped?My understandingis that it could andthe Wood fuver refinerywould havemore usable product and less coke and it wouldhave less wastewater becausetoo cut all that coke out anduse voluminous amounts ofwater, which would help with the coneof depressionand help with the discharges.

The refining of bitumen that takesplace in Canadais performed becausethe bitumen recoveredfrom oil sandsis very viscousand cannotbe directly shippedby conventionalpipelines. It must generallyeither be blendedor diluted with lighter petroleumproducts or processedor "upgraded,o'with the resultingmaterial is generallyreferred to as"synthetic crude oil." This upgradingis performed using standard refining processes,including delayedcoking followedby hydroctacking,as will alsobe performedwith modernequipment at the Wood River refinery. The extentof processingthat occursin Canadais dictatedby the needto producea syntheticcrude oil that is sulficiently liquid that is can be shippedby pipeline.It is more economicalfor existingrefineries, which are closerto marketsand have facilitiesto make a rangeof final products,to then completethe processingofthe syntheticcrude oil, rather than duplicatethose facilities in Canada. Other factors alsoact to influencethe extentof initial processingofthe bitumen that is performed in Canada,e.g., the availability ofnatural gasto make the hydrogenneeded for hydrocrackingand the abse[ceof local markets for petroleumcoke.

Can a cleanergrade of crudeoil be transportedfrom Canadato the Wood River Refinery by using upgradedtechnology in Canada?

Production ofa cleanergrade ofcrude oil in Canadawould necessarilyentail "full refining" of the crude oil in Canada. While it would be possibleto constructa new

18 refinery in Canadaat the sourceofthe crude oil, it is more costeffective and eflicient to pipe crude oil to existingrefineries that alreadyhave the facilitiesto processmaterial to supply the demandsand environmentalspecifications for local markets.

46. Otherrefineries that processheavy crudehave or haveplans to build a facility to gasify the crudeto makehydrogen and electricity for the refinery. From the perspectiveof national energysecurity, wouldn't it be betterthan the use of the natural gas,as prcposed, andwouldn't that create more localjobs and wouldn't that be a highervalue use ofcoke?

The Illinois EPA is not aware of any refineriesthat havefacilities to gasify petroleumcoke to directly producehydrogen or that plan to constructsuch facilities. Certain refineriesdo havefacilities to gasifypetroleum coke to produce fuel gas,which can then be usedas fuel in processunits or in a cogenerationfacility or usedas a feedstockto producehydrogen, A hydrogenplant is being developedto usepitch as a feedstock.Ilowever, steammethane reformitrg, as usedat the Wood River refinery, usingfuel gasor natural gasas a feedstock,is commonlyused to producehydrogen at refineries.

Most of the fuel combustedat the Wood River refinery is not natural gasas suggestedby this comment, Rather, the primary fuel at the relinery is fuel gasthat is a byproduct from certain refining processes,The gasificationof petroleumcoke would greatly increasethe magnitude,duration and costof expandingthe Wood River refinery. It is alsounclear what operationslbenefit would be derivedfrom sucheffort asthe relinery will producesufficient relinery fuel gasand hydrogenfor its operationswithout a gasificationunit. Operation of a cokegasification unit would alsoadd anotherelement of complexityto the operationand managementof the refinery. As gasificationof petroleumcoke is believedgenerally desirable, it is certainly possiblefor anothercompany to pursue devetopmentofa new source specificallyfor that purpose,relying on ConocoPhillipsand other refineriesto provide its feedstock. i1 Someof thenegative impacts ofthe useofpetroleum coke as fuel in a boiler areits high sulfur content,which potentially contributesto higher emissionsof sulfur dioxide (SOz) and sulfuric acid mist ftom the boiler, the combustioncharacteristics ofthe coke, which potentially increasesNO* emissions,and the heavy metalsin the ash.*

Useof petroleumcoke as a fuel in a boiler generallyposes emissions issues that are similar to thosethat are posedby useof high-sulfur coal in the boiler. That is, the boiler must be equipped with appropriate control systemsfor emissionsof PM, N0, and SO21as neededto comply with applicableemissions standards that apply to the boiler. While the trace levelsof certain metalsin petroleumcoke, such as vanadium and nickel, are higher than in coal,emissions ofthese metalsare controlledalong o Challenges and Economics of lJsing Petroleum Cokefor Power Generation,World Energy Comrrission" http://www.worldenergy.org/wec-geis/pubtications/default/techjapers/l7th_congress/l 2_26.asp

19 with the PM and they etrdup in the ash. On the other hand, sincethe mercury contentof petroleumcoke is much lower than that ofcoal, useofpetroleum coke doesnot posethe sameconcerns for mercury impact as the useof coal.

48. The analysisof altemativesto theproposed project should have considered the broader impactson the United Statesof using crudeoil from Canada.At a minimum, these impactsinclude the overallimpacts additional energy use, additional hydrogen use, additionalflaring, increasesin refinery accidents,additional use ofcoke as fuel in power plants,impacts ofnew pipelinesand pipeline accidents, and potential on impactson regionalair quality due to changesin vehicle fuels. Theseimpacts and long-term implicationsare severe when considering added emissions criteria pollutants, toxic pollutantsand greenhouse gases, as well asdestruction of land andwater resources,and impactson people,plants, and wildlife.

It is beyondthe scopeof the analysisof alternativesfor the proposedproject to considerthe impactson the United Statesfrom using Canadiancrude oil, as recommendedby this project The United Statesobtains crude oil from various oil fields,both domesticand foreign,with a variety of impactsassociated with the production and transportationofthat crude oil. While purchaseof foreign crude oil reducesthe environmentsimpacts on the United Statesfrom oil production,it has economicirnpacts on the United Statesand the world economy.Use of domestic crude oil reducesthose economic impacts but has environmentalirnpacts. In some cases,those impacts can be severe.For example,the Exxon Valdezoil spill involved transportationof crude oil by tanker from Alaska.

GLOBALWARMING

49. Condition2.5 in the draftpermit states that the ntnois EPA hasbroadly considered altemativesto the proposedproject, as required by 35 IAC 203.306.However, the Illinois EPA was prematurein finding that it hasconsidered altematives to the project. The high energyuse of the project and resultantemissions of greenhousegases should havebeen considered pursuant to 35 IAC 203.306,as a majorenvironmental and social costofthe project. Altemativesto theproject that would avoidsevere project energy use andemissions ofgreenhouse gases should be evaluated,as required by 35 IAC 203.306. At a minimum, this cost of theseimpacts should be identified and evaluated,so that altemativescan be seriouslyevaluated.

Alternativesto the proposedproject were reasonablyanalyzed. While there are theoreticallyalternatives to this project that would avoid the proposedprojec! these alternativescan be readily dismissed.For example,the existingmotor vehiclefleet could be replacedwith electricalvehicles, with electricity suppliedby wind-based power plants. Not only is this not somethingthat ConocoPhillipswould undertake, but it is not somethingthat could be undertakenas an alternativeto the proposed project asit respondsto needsfor conventionalfuels in the immediatefuture.

On a more realistic level,the continuingand increaseddemand for fuels in the

20 marketsserved by the Wood River relinery could potentiallybe met by refineries other than the Wood River refinery. However,importation of fuel to the Midwest from other locationswould not eliminatethe emissionsfrom somesimilar project, as suchproject would still occur elsewhereto meetthe public demandfor fuels and changesin the global suppliesof crude oil. As emissionsof criteria pollutants affect air quality on a regionalscale and greenhousegases are of concernon a global scale, relocationof the project would be of uncertain benefitsenvironmentally. Moreover, importation of fuels would certainly havesignilicant impacts on residentsof the 'greater St Louis area as it would affectthe costand availability of fuelsin the area. It could alsohave negative environmental effects as it would affectthe availability of reformulatedgasoline for the area,which the Wood River refinery producesas the local refinery servingt:he area. In summary,the proposedproject is a reasonable proposalby ConocoPhillipsfor the Wood River refinery to continuein its historic role in supplying fuels to the Greater St. Louis area and the Midwest While the refinery has impactson the environment thoseimpacts are signilicantly outweighed by the benefitscurrently being provided for societyof the fuels that the refinery produces.

50. h 2006, GovernorBlagojevich arurounceda climate changeinitiative by the Stateof Illinois to addressemissions ofgreenhouse gases, which will build on Illinois'role asa national leaderin protectingpublic health and the environment. This initiative marksthe begiruringof seriousefforts by Illinois to addressglobal climate changeand builds on stepsthat Illinois is alreadytaking to lower emissionsof greenhousegases, such as providing incentivesfor energyefficiency and encouragingthe use of wind power and biofuels.

Governor Blagojevichhas instructed the Illinois Climate ChangeAdvisory Group, which he has convenedfor this initiative, to evahate a full range of policiesand strategiesto reduceIllinois' emissionsof greenhousegases. Accordingly, the Advisory Group is focusednot only on the facilitiesthat supply fuel and energy,but alsoon the facilities and peopleof Illinois who usethat fuel and energy. This is critical as significantreductions in emissionsof greenhousegases requires comprehensiveactions to reduceenerry consumption,including significant improvementsin the energyefficiency of transportation,heating, cooling and lighting, machineryand appliances,etc. While facilitiesthat producefuels and energy,e.g., petroleum refineries, can 4!!q make improvementsto reducethe energyconsumed in their operations,these reductions are not suflicient to roll back emissionsof greenhousegases. As related to emissionsof greenhousegases from "crude oil,o'a reduction in the usageof gasolineand other petroleumproducts usage is needed.sThus the focusof efforts in Illinois to reduceemissions of greenhouse gasesfrom useof petroleum-basedfuels must be to actually reducethe usageofsuch fuels. This will alsoprovide other benefitssuch as stabilizingfuel prices, maintaining and improving air quality, and reducingtraffic congestion.The

5 Wlfle renewablefuels, i.e., ethanoland biodiesel, can be substitutedfor sofirefuel, the extentof such substitution that is feasibleis rolatively minor in terms ofthe overall emissionsof greenhousegases attributable to use of petroleum-basedfuels.

2l activitiesofthe refineriesthat supply fuels are a secondaryconsideration in these efforts, both due to the lessermagnitude of their emissionsand their role in meeting lllinois's current needsand demandsfor fuels.

51. The U.S. Global ChangeResearch Program published a report on impactsof climate changein the Midwest,' which finds that, higher summertemperatur€s and resultant increasedair pollutionin theMidwest will resultfrom climatechange. This is because hotter summerscould act to increasethe formation of ground-levelozone, which is formed throughreactions ofprecursor compoundsenergized by sunlight on hot days. As major urbanareas in the Midwest afe currently nonattainmentfor ozone,climate change is making it more diffrcult to attain and maintain compliancewith the ozoneair quality standards.The report also found that heat-relateddeaths in the region due to climate changewill increase,and the report as a whole found many other severeimpacts due to climate change.The public is relying on the Illinois EPA to seriouslyevaluate altemativesto the proposedproject that will not only protectpublic health from traditional air pollutants,but also from greenhousegases, whose effect is to exacerbate air pollution and threatsto public health.

As observedby this comment,global warming potentiallyhas myriad negative impactson human health and welfare and the environmengboth directly and indirectly. Ilowever, it is alsoobvious that the challengeof global warming will require a comprehensiveregulatory approachin the United States,which is ultimately irnposedby Congresson a national level. Until specificregulations are put into placeby the appropriatestate or national authorities,ad-hoc actions to compelindividual action on globalwarming through conventionalenvironmental permitting programsare capricious. Even if suchactions were taken, they would probably provide only illusory benefits,as they would be limited in their scopeto new projects. They would not reachor affect existingsources, which contributethe majority of emissionsof concern. Such actionsmight alsohave a stifling effecton the continuing developmentand deploymentof new technologyto improve energy efficiencyand reduceemissions of greenhousegases, as such actionswould stifle innovation or discouragecapitsl investment.

52. The applicatio_nfor tlle proposedproject doesnot containinformation for emissionsof CO2,methane' and other greenhousegases from the new and modified heatersthat are part of theproject, which couldbe readilycalculated by ConocoPhillips,The analysisof altemativesto the project shouldhave reviewed the environmentaland social impactsof emissionsof greenhousegases, which requires a quantificationof theseemissions, in order to demonstratethat the benefitsofthe project will outweighits environmentaland social impacts,as requiredto comply with Illinois regulations. A fulI review of project

' Climate ChangeInrpacts on the United States,The PotentialConsequences ofClinate Variability and Change, Overview: Midwest, by the National AssessmentSynthesis Teanr, US Global ChangeResearch Prograng 2000, http://rvww.usgcrp.gov/usgcrp/Library/nationalassessmenV?Mw.pdf,(The U.S. Global ChangeResearch Program (USGCRP)is a governmentreseaxch program codified by Congressin the Global ChangeResearch Act of 1990.) Full webpage:http://www-usgcrp.gov/usgcrp/Library/nationalassessmenVovervi€wmidwest.htrn ' Many emissionspoints in the refiaery ernit methane,which is a pot€ntgreenhouse gas, 20 times strongertltan CO2,and a major componentofthe fuel gasused at refineries- Illinois' definition ofVOM excludesmethane.

22 altemativesshould have also includedprevention andL/or mitigation of emissionsof greenhousegases. Estimates ofCO2 emissionswere provided by ConocoPhillipsfor anotherrecent proposal to expandits refinery in RodeoCalifomia.s tt showedthat the increasein emissionsof greenhousegases would be lmger than many of the decreasesin emissionsfrom California'sEarly Action measure,effectively wiping out decreasesmade in othersectors. Estimating emissions of greenhousegases from the proposedproject just makesgood sensesince the project will set refmery practiceand the environmental impactsofthe refineryfor decades.

The important greenhousegas emitted from processingofcrude oil and useof petroleumrefineries is COz, This is becauseCO2 is the product of comb[stion when carbon, which makesup the bulk of crude oil, is burned. This is dilTerent from methaneand other greenhousegases, which are pollutants in the more traditional sense,as they are contaminantsand processesmay be manipulatedor controlledto reducethe formation of thesematerials. For example,the trace levelsof emissions of methanethat accompanycombustion of any fossilfuel can be minimizedby good combustionpractices. In contrast,COt is the unavoidableproduct of combustionof carbon,as is desirableas it representscomplete combustion of that carbon to COzo ratherthan CO.

As alreadydiscussed, use of petroleum-basedfuels directly leadsto emissionsof greenhousegases. The magnitudeof this contribution is large, with activitiesrelated to useof petroleumproducts currently contributing about 45 percentofthe CO2 emissionsof the United States.As observedby this comment,emissions of CO2can be readily calculatedfrom information on the type and amount offuel that is being burned. Emissionsof COz associatedwith useof crude oil can be roughly estimated using a factor of 1000pounds of CO2per ton of crude oil consumed.Accordingly, asthis project involvesa nominal increasein the annual capacityof the Wood River relinery of about 27 million barrels,the project potentially involveshandling crude oil that could annuallycontribute as much as about 12.5million metric tons of COr emissionsto the atmosphere.eAs the majority of theseemissions would occur when gasoline,diesel and other petroleumproducts produced by the refinery are used,thr split betweenconsumption/emissions at the relinery and consumptionlemissionsof ttre usersof fuels is of uncertain significance.Reductions in theseemissions will require improvementsin energyefficiency by the usersas fuels sothat lessfuel is consumedon a regional,national and international leveL

3 ConocoPhillipsis pursuingpermit for a major expansionat its refmery in Rodeo California. For that project, ConocoPhillipsprovided an estimateofthe CO2emissions increases, about 1.25million metric tons per year. This is a large increase,as it is more than I o/oofthe comprehensivesinventory for emissionsofgreenhouse gases prepared by the BAAQMD for the entire Bay Area, which addressesemissions ftom industrial sources,cars, tucks, ships, building heating,etc. The proposedproject at the Wood River refmeryrepresents a much larger refinery and expansion(up to 385,000bpd, comparedto the Rodeo76,000 bpd refinery) and involves heavycrude oil, which requiresmore processingthan lighter crude oil. CO2emissions will be rnrch higher for the proposedproject than for the ConocoPhillipsRodeo refinery, which are alreadyextremely large. ' While 12.5million metric tons may seelike a large number,global emissionsof CO2are measuredin terms of billions of metric tons oer vear.

z) 53. ConocoPhillipshas publicly arurounced plans to reduceemissions of greenhousegases. In 2006,ConocoPhillips became the first majorUS oil companyto join theUS Climate Action Pmtnership.James Mulva, ConocoPhillips' chairman and chief executive has beenreported as saying that "Voluntary programs are not goingto meetthe challenge of climatechange," .. . "The longerwe wait - two or five yearsor morefrom now - it wont be mitigation,it will be adaptation."roUnfortunately, the proposed project is movingin the oppositedirection, with moreenergy-intensive processing ofvery heavyCanadian crudeoil.

In actualfact ConocoPhillipswent on record supporting mandatory,national regulatiotrsaddressing greenhouse gas emissions. This is consistentwith its participation in the US Climate Action Partnership,which is a diversegroup of businessesand environmentalleaders that havecome together to call for rnandatory action on climatechange, endorsing a comprehensiveapproach involving phased targetsfor reduction of emissionsof COz accompaniedby a rangeof policy approaches.ConocoPhillips should be praisedfor its endorsementof regulatory actionto addressglobal climatechange, especially when certain other companies would prefer to ignore global warming. However,ConocoPhillips corporate positionon climatechange is not inconsistentwith the current project,which would meeta needfor fuel in the immediatefuture using an existingrefinery.

ConocoPhillipsis pursuing the current project becauseits primary businessis supplyingpetroleum based fuels, products for which there is both an ampleneed and evengreater demand. As observedby this commen! the United Statesis far behind Europe and many other developednations in actionsthat would reducethe demandfor the petroleum-basedfuels that ConocoPhillipsproduces. Other countriesalso provide strongersupport for the developmentof alternativeenergy technologies,as will be critical to rollback emissionsofgreenhouse gas emissions. f). Emissionsof greenhousegases should be monitoredand measured. How much methane andCO2 would be releasedby uncontrolledpresswe-relief devices? How muchCOz will be releasedby the hydrogenplant?

Treating emissionsof COz and other greenhousegases as regulatedair pollutant, as is effectivelybeing requestedby this comrnent,would be inconsistentwith current Illinois law. In particular, CO2is a compoundthat is presentin the earth's

1o "ConocoPhillips:The anti-Exxon: The Texas-basedoil conpany breakswith he otherU.S. majorsto support mandatorynational regulation ofgreenhouse as emissions,"Fortane,Marc Grnther, April I l, 2007, http://money.crm.con/2007/M/10/news/companies/pluggedin_gunther_conocophillips.fortune/index.htm

an rtmosphere,occurring both naturally and as a product of fossilfuel combustion. COr in the atmospherehas not beencommonly regarded as an air "pollutant." lndeed,the ecospheredepends upon the presenceofCO2 emissionsto support green plants, Historically, CO2in the ambient atmospherehas not beenconsidered harmful to humansor the environment.

At the sametime, the Illinois EPA is working to developrequirements for tracking and routine reporting of emissionsof CO2,and perhapsother greenhousegases in Illinois in the near future. This activity would be comprehensive,as it would addressall significantstationary sources of theseemissions, Improved tracking of emissionsof suchemissions is important in conjunctionwith lllinois' current initiative to reduceemissions of greenhousegases.

56. What energyefficiency evaluationswere carriedout for this project, if any?

ConocoPhillipsindicated that is has an "enerry action checklist"that setsenergy standardsthat everyne\tr construction project must meet. For example,new processunits must be designedso that the lsmpsrature of the final product is such that all usableheat energyhas beenrecovered. This checklistis ConocoPhillips' way of evaluatingproposed projects for energyefliciency.

57. How muchadditional methane will be emittedby flaringdue to theproposed project?

Emissionsof methanefrom the refinery from flaring shouldbe decreasingdlre to the various measuresthat are being implementedto mininize flaring.

Air Permittins

FLARING

)6. Theproposed project w"ill entail construction of two new flaresand increased use of existingflares. These flares me subjectto BACT for CO emissionsand LAER for VOM emissions.However, the draft pemrit would not require BACT or LAER for flaring.

The existingflares are not subjectto BACT or LAER becausethey are not being physicallymodified and will not experiencea changein the methodof operation. This is becausethey will be in the sameservice, with the sameprocess stream and function, as at present. Indeed,due to the requirementsof the ConsentDecree it is appropriate to anticipate that emissionsofthe existing processflares at the refinery will be declining. The issuedpermit includesadditional requirementsas part of BACT and LAER for the new flares in responseto public comments.

59. The applicationdoes not include emissionsinformation relatedto flaring ftom the project or from contemporaneousprojects over the last five years,which shouldhave been provided.Not only is therea largepotential to emit at the newflares, but ernissionsat existing flares will increasedue to the project becauseof increasedproduction at the

25 refinery. The applicationis not completewithout this information andmust be supplemented.

The applicationdoes include emissionsinformation for new, modified and debottleneckedflares and for any increasesin flaring and flaring emissions associatedwith contemporaneousprojects.

60. USEPA prohibits routine flaring and requirespreventative measures to minimize SOz emissionsfrom flaring. A USEPA EnforcementAlert" wams that frequent,routine flaring,which may causeexcessive, uncontrolled SOz emissions, is not considered"Good Pollution Control Practice,"and may violate federalregulations adopted pursuant to the CleanAir Act. Unforfunately,none of theserequirements are met by the proposed project.The applicationfailed to providethe necessary analysis on availablemethods, suchas having sufficient compressor capacity to rigorouslyprevent and minimize entire flaring eventsand thus achievemaximum controls and lowest emissionsfiom flaring. Suchmetlods minimize emissionsof all pollutantsfrom flaring, and areused at other refrneries.

As alreadyexplained, the VVoodRiver refinery is subjectto req[irements to minimize flaring as it contributesto SO2emissions. Incidentally, while expressing concemsabout excessiveflaring, the USEPA confirmedthat the proper useof flaring is a goodengineering practiceo as flaring destroyshazardous and objectionablegases by burning thosegases. Flaring alsoprevents injuries to employees,fires and explosions,and damageto equipment.

61. The applicationincorrectly statesthat there is no way to reduceCO emissionsfrom flaring and at the sametime control VOM emissions,assuming that either VOM waste gasmust be flaredor elsedirectly emitted.l2 However, recovery of wastegas back to a refinery's fuel gas systemacts to preventboth VOM and CO emissionsllom flaring.

This statementwas madein the contextof the Wood River refinery, where measures to reducehydrocarbon and thus VOM emissionsfrom flaring by minimizing and eliminatingsuch events are in place, Given that suchmeasures are in place,the flaring eventsthat actuallydo occur must generallybe consideredunavoidable, as indicatedin the application. (Certainls any further discussionabout whether a particular flaring eventwas avoidablewill occur after the eventhas occurred,)

62, CO emissionsfrom flaring arerelated to combustionefficiency, which varies. If the combustionefficiency of a flarewere 1007o,there would be no CO emissionsfrom the flare. Flare combustionefficiency varies accordingto the quality of the gasesbumed, the

" USEPA EnforcementAlert, Vol.3,Number9, October 2000 http://www.epa.gov/conpliance/resowces/newsletters/civiUenfalert/flaring.pdf

12 "No processchanges that would reducethe CO emissionsexist. Sincathe flafes s€rveas VOM control devicesin an 8-hour ozonenon-attainment area, their operationis necessary-Therefore, no CO control technologiesexist for the new flares." Application,page 7-9

26 capacityof the flare,how well the flaremixes the fuelsand air, flare exit velocity,wind conditions,etc. Combustionefliciency can vary from low, downto only 600loor lessof VOM combustedto very high, over 99Voefficiency. Regulatorsin Texasand Califomia use destructionefficiencies down to 93o%when calculating flare emissionswhen waste gassent to a flare has a low Btu contentinstead ofthe 9870more commonlyused in emissioncalculations. Many studiesshow that efficiency can be very low, downto even 307o.The ratios of emittedCO, COz,VOM, etc.,also vary. ChoosingUSEPA's CO emissionfactor, which relatesto averageor typical conditions,for BACT for a flare would be unsound.

It is commonpractice to conservativelycalculate VOM emissionsfrom flaring using a minimum level of destructionefliciency so as to overstateVOM emissions.This levelof combustionelficiency is 98 percent,which USEPAindicates is the minimum levelof destructionefliciency that will generallybe achievedwhen a flare is operatedto cornplywith 40 CtrR 60.18,as is required for flares at the Wood River refinery. Similar approachesare taken for emissionsof other pollutantsfrom flaring that are affectedby destructionor combustionefliciency of the flare. While the destructionefliciency for flaring that doesnot comply with 40 CFR 60.18may be lower than 987o,as discussedby this commen! this is not relevantto the flares at the Wood River refinery. In addition,this commentdoes not identify a methodby which the effectof normal variation in destructionefficiency of a flare and its effect on VOM emissionscould be readily determinedin practice or showthat sucha methodis needed,

63. The flare associatedwith the new hydrogenplant would not be "assisted"with either introduction ofair or steam. Steamor air-assistedflares are consideredbasic to provide good mixing in a flare and maintain combustionefficiency. Non-assistedflares should not be consideredto meetBACT requironents.

The wastegas from the hydrogenplant that would be flared, which shouldonly occur during upsetsor emergenciesgiven the nature of hydrogenplantso is expected to be low-Btu gas,which is primarily CO and COz and has a low VOM contetrt, As the heat contentofthe wastegas is between200 and 300 Btu per SCF, useofsteam or air assistis not required for effectivecombustion, as reflectedin USEPA's regulationsfor proper designand operationof flares.

64. There aremany proven approachesfor reducingthe numberof flaring episodesand the quantity ofwaste gas flmed and thus reducingall flaring emissions. They include: l) Having sufficient compressorcapacity, including redundantcompressor capacity to recyclewaste gases to the refinery fuel gassystem (especially important when the refinery is being expandedso that more wastegases may be produced);2) Managing depressurizationduring unit shutdownsso that the gasrecovery systemis not overwhelmed;3) Constructingstronger pmcess vessels to increaseworking presswes to enablecontainment ofprocess gasesduring shutdownrather than flaring; 4) Implementationof detailedprocedures to diagnoseand eliminate unnecessaryflaring, and 5) Fixing equipmentthat repeatedlymalfunctions and causesunnecessary "emergency"

27 flaring. A plan for minimizing flaring androot causeanalysis for flaring activity that doesoccur arekeys to preventingunnecessary flaring. Theseapproaches are used at existing refineriesand havebeen shown to lower the numberand magnitudeof flaring events.An analysisof suchapproaches was not provided for the proposedproject andthe draft permit would only superficially addressthese approaches to reducingflaring and flaring emissions.

As generallyobserved by this commentothere are many ways to reduceemissions from flaring. For the new processflare systemsat the relinery, the various approachesto minimizationof flaring and flaring emissionsdiscussed in this commentare required as appropriatefor the particular processunits that are servedby the flare system. This has beenclarified in the corditions of the issued permit for flaring. The oneexception is constructingstronger process vessels. This has not beenidentified as a reasonableor recommendedapproach to reducing flaring emissions.It would poseoperational concerns as it would implicitly entail operationof processvessels at higher pressures.In addition, careful managementof depressurizationofvessels during unit shutdownsappears to be very effectivein minimizing and eliminatingshutdowtrs as a cotrtributor to flaring.

65. The SCAQMD and the BAAQMD haveboth identified adequatecompressor capacity for recoveryofwaste gas as being effective in minimizingflaring eventsand their associated emissions.This approachwas not evaluatedfor the proposedproj ect for BACT and LAER.

The new flare systemfor the new DelayedCoker Unit will include redundantwaste gascompressors, as currently usedat the Shell,Martinez refinery. A conditionhas beenincluded in the issuedpermit requiring this as an elementof BACT and LAER for this new flare system.The flare for the new hydrogenplant doesnot handlea wastegas that is suitablefor recoveryfor usein the relinery fuel gassystem.

66. Without rigorousmonitoring, adequatecompressor capacity, process control, and appropriatepermit conditions,significant flaring can be expectedat the Wood River refinery with the proposedproject.

The extentof future flaring at the Wood River refinery is minimizedby operational and economicincentives to maintain stableprocess operation with consistent product yields and to recoverwaste gas that is producedfor useas fuel. ConocoPhillipsalso has a statedobjective of minimizing its CO2emissions. Accordingly,it is unclearto what extent,if any, the permit must mandateparticular action by ConocoPhillipsto preventsignificant flaring at the refinery in the future. Nevertheless,the issuedpermit mandatesthat ConocoPhillipstake particular actionsto minimize flaring, consistentwith the actionsthat havebeen taken at and required of other refineries.

67. Without adequatecompressor capacity, significant flaring can be expectedat the Wood River refinery with the proposedproject. The applicationdoes not provide information

28 for the nine existing flares in different areasof the refinery for baselinecompressor capacityor the amount,if any, that this capacitywould be increasedwith the proposed project. As foundby theBAAQMD andSCAQMD, compressor capacity is key in preventingflaring. It allows the refinery to consistentlyrecover waste gases for use as fuel,rather than flaring these gases with associatedemissions. Adding compressor capacity,as discussed in its FlareMinimization Plan, enabled Shell, Martinez to reduce flaring, including emergencyflaring, to very low levels comparedto other refineriesin the Bay Area. The Tesoro,Avon refinery (previously Tosco),also in the Bay Area, which had the worst flaring recordprior to the BAAQMD rulemaking,reduced its emissionsgreatly by addingcompressor capacity.

Adequatecompressor capacity is only one approachto minimizing flaring. Whether other approachedare adequatefor the existingllares at the Wood River refinery or additional wastegas compression capacity will haveto be installedat the relinery is not a matter that can be determinedat this time as measuresto reduceemissions from existingflares are ongoing. Whether additional compressorcapacity should be installedfor existingflare systemsat the refinery is a matter that is appropriately dealt with in the contextof the ConsentDecree.

68. At the refineriesin the Bay Area, flaring, including ernergencyflaring, was also further reducedafter adoptionof rules for flaring by the BAQMD, showingthe feasibility of conholling flaring throughprevention mechanisms. The principles and equipmentused by refineriesin theBay Areamust be appliedwith specificityto the proposedproject.

For the flare for the DelayedCoking Unit, for which BACT and LAER are required, the issuedpermit requiresthat ConocoPhillipsimplement the measures similar to that specifiedby the BAAQMD to reduceflaring. Theseare preparation of and operationpursuant to a Flare Minimization Plan and performanceof "root causeanalyses" for significantllaring incidents. In this regard,the BAAQMD's flaring rules put into placecertain administrativerequirements whose purpose is to lead to reduction in flaring and flaring emissions.The rules do not identify or prescribespecilic measures that refineriesmust useto reduceflaring. Thus, while the DelayedCoking Unit will have a gasrecovery system with redundant compressorcapacity as alreadydiscussed, this is not a measurethat is mandatedby the BAAQMD rules.

The BAAQMD's rules for flaring at petroleum refineriesdo not addressflaring at wastewatertreatment plants, At wastewatertreatm€trt plants, flares serveas control devicesfor the emissionsfrom certain units and do not handlewaste gas streamsas are potential presentwith the operationand upsetofprocess units at a refinery,

69. A detailedevaluationr3 ofthe refineriesin the Bay Are4 which revieweddata reported by the refineriesand their Flare Minimization Plans,found that the dirtiest refinery processescaused more flaring, with moreemissions, than other refinery processes. This rr "Flaring PreventionMeasures," Comnunities for a Better Environment(CBE), Greg Karras, April 2007 is directly applicableto the Wood River refinery, which is expandingits dirtiest refining processes.

This evaluationfound that certain refining processeshad the El@!!!4! to generate more emissionsfrom flaring. Accordingly,it recommendedthat theseparticular processesbe subjectto especiallythorough reviewwith appropriate actions implementedto minimizeflaring associatedwith theseprocesses.

70. The applicationfailed to evaluateLAER achievedin priictice by refineriesthat rigorously implementapproaches to minimize flaring. Shell has documentedits approachesfor minimizing flaring and achievingvery low flaring emissionsat its refinery in Martinez, Califomia,in the FlareMinimization Plan for this refineryrarequired by BAAQMD rules. BACT and LAER for flaring at the Wood River refinery shouldbe at leastas stringentas the equipmentand practices in place at the Shell Martinez refinery. Even beforeadoption of the BAAQMD rules, the Shell Martinez refinery did not havelarge flaring events conpared to the large and routine flaring events,with substantialemissions, at other refineriesin the Bay Area. The Shell Martinez refinery hascontinued to exhibit very low flaring emissionscompared to other Bay Area refineries. The Flare Minimization Plan for the Shell Martinez refinery shouldbe evaluatedand the approachesapplied to Wood River refinery in detail to satisfyBACT and LAER requirements.

In responseto this commen! the Flare Minimization Plan preparedby Sbell Martinez has beenclosely reviewed. The issuedpermit requiresa Flaring Minimization Plan for the new coker flare being constructedas part of this project (coker flare) that addressthe various approachesthat havebeen taken by Shell Martinez to reducingflaring, as presentedin the Flare Minimization Plan for that relinery.

71. Shell, Martinez hastwo wastegas recovery compressors for dedicateduse in its Delayed Coking Area,,with eachcompressor having enoughcapacity to handlegases from this areawhen one of thecompressors is out of service.ConocoPhillips should do the same.

As previouslydiscussed, the flare systemfor the new DelayedCoker Unit will include redundantwaste gas compressors, like the systemat the Shell Martinez relinery, In this regard, ShellMartinez, with its DelayedCoker Unit that was installedin the mid-1990's,also provides anecdotal evidence that operationof a modern DelayedCoker Unit doesnot significantlycontribute to flaring emissions, given ShellMartinez's excellentrecord on minimizing flaring emissionsas cited by ra Shell's Flare Minimization Plan for the Martinez refrnery indicatesthat 'lAs the refinery alreadyhas very significant capital infrastructurefor flare gasrecovery in place,procedural modifications can be usedto achieve much highet returnson a $/ton emissionsreduction basis. New refmery procedruesdescribed in this Flare MinimLation Plan addressactions to fiuther minimize flaring during processupsets and additionalplanning requirementsfor maintenanceand tumaroundactivities. Careful planning ofaay activity with the potential for flaring is the most successfirlminimization approachthat hasbeen enployed at SMR. Proceduresfor reporting and investigatingall flaring provide meansto leam fiorn unanticipatedevents. The result ofthis work will be firrther reductionsin flaring." Excerpt ftom the Shell Martinez Refinery, Flare Minimization Plan, RedactedVersioq RevisedMarch 25 2007, submittedto the Bay Area AiI Quality ManagementDistrict this commenter.

72. The Shell Martinez RefrneryFlare Minimization Plan emphasizedthe importanceof thoroughroot causeanalysis of flaring incidentsto avoid similar eventsin the future and reduceemissions from flming emissions.This measureis neededfor the proposed project dueboth to the large increasein refinery capacityand the refinery's history of flaring.

The issuedpermit requiresthat root-causeanalyses be performed for the new flare for the DelayedCoking Unit for any signilicantflaring incident for hydrocarbons.

Operationalmonitoring for wastegas that is flared is important to provide accuratedata for emissionsfrom flaring and to provide a factual basisfor evaluationofthe numberand natureof flaring eventsand their associatedemissions and to perform root causeanalyses for flaring. Monitoring devicesarc availableto frack the flow of gasesto a flare. Monitoring for the concentrationof VOM and sulfur compoundsin wastegases, in combinationwith recordsfor pilot andpurge gas flow, is neededto provide good information on the wastegas bumed by a flare and the accompanyingemissions.

The issuedpermit requirescontinuous monitoring to identify when wastegases are flared. This requirementis accompaniedby requirementsfor monitoring or instrumentationto reasonablydetermine the amount of gasthat is flared, requirementsfor sarnplingand analysisof wastegas or maintenanceof recordsfor the compositionofthe gas,and requirementsfor rnonitoring or recordsrelated to fuel usagefor the pilot and venting ofpurge gasto the flare.

74. The draft permit would only superficially addressmonitoring for flaring. Despitereadily availablemonitoring devicesand a ConsentDeffee that addressesexcessive flaring at the wood River refinery in the past,it is surprisingthat the draft permit doesnot contain requirementsfor monitoring of flow or compositionof wastegas going to the flare. BACT and LAER for flaring necessitateoperational monitoring in order to minimize emissions.As monitoring of flaring hasbeen successfully implemented pursuant to applicableregulations at many California refineries,this work provides a ready-made solution for deficienciesin the applicationfor the proposedproject, with proven methods that can be included directly into the permit.

In particular,rigorous operationalmonitoring shouldbe requiredfor flaring as specified by the rules of the SCAQMD and BAAQMD. The Flare Monitoring Rule, Regulation 12-I 1," which wasadopted by theBAAQMD in 2003,shows that issues related to operationalmonitoring for flaring havebeen worked out, including verification ofgas flow and analysisfor hydrocarbonsand sulfrr contentof wastegas. This rule was adoptedfollowing input with manufacturersof monitors, refineriesand the public. Each requirementof this rule shouldbe incorporatedinto the permit for the proposedproject. Thesemeasutes are neededfor the proposedproject due both to the large increasein refinery capacityand the refinery's history of flaring. The TexasCommission on ls BAAQMD R€gulation 12 Rule 11, htp://*vw.baaqmd.govldst/regulationVrgl2l1.pdf

JI EnvironmentalQuality also found that accurateemissions data must first be collectedin order to then be ableto identify and developoptions for controlling refinery flaring, which emphasizesthe importanceof operationalmonitoring aspart of flare emission control.'oThe ShellMartinez Refinery Flare Minimization Plan also emphasized the importanceof monitoring.

The issuedpermit includesan appropriatelevel of specificityfor operational monitoring for flaring, As the fundamentalobjective for flaring is to minimize and eliminatellaring, it is not appropriatefor the permit to includethe detailed requirementsfor operationalmonitoring presentin the BAAQMD's Flare Monitoring Rule. Given the very low levelof flaring that shouldoccur in the future at the Wood Rjver refinery, a simpler approachto operationalmonitoring at the refinery shouldbe established,as compared to the circumstancesofthe refineriesin California that led to the BAAQMD and SCAQMD adoptingtheir Flare Monitoring rules severalyears ago. Accordingly,the issuedpermit setsthe purposesthat must be fullilled for the operationalmonitoring for flaring, i.e.,collection ofdata to identify when wastegases are flared and in what quantity. The permit doesnot prescribewhat monitoring techniquesmust be usedand how monitoring must be conducted.

75. In 2006,the BAAQMD adoptedadditional requirernents for reporting of flaring at refineriesin its rules for FlaresAt PetroleumRef,rneries, Regulation 72-12. The provisiols of this rule shouldalso be includedin the conditionsofthe permitfor the project.''

The issuedpermit includesappropriate provisions for reporting related to flaring. Given the nature of the Itlinois EPA's proceduresfor review of reports from sources,detailed reporting relatedto flaring associatedwith this projept \rill be more efficiently and effectivelyhandled if it occursin conjunctionwith routile quarterly reporting, rather than asstand-alone reports for significantflaring events. Provisionsfor prompt reporting upon occurrenceof certain flaring events are appropriately set in the Clean Air Act Permit Program (CA-APP)permit for the refinery.

76. The monitoring conditionsin the draft permit for flaring, which only reiteratefederal

'" TCEQ Master Conhol ShategyList, Point Soutces,page 5, September7,2005 http://lvww.nctcog.orgltrans/airlsip/future/lists/TCEQointo/o20Source%20l-ist.pdf

17 ReportableFlaring Event: Aly flaring where mor€ than 500,000standard cubic feet per calendarday ofvent gas is flared or wheresulfur dioxide (SOr) emissionsare gr€aterthan 500 poundsper day. For flares that are operatedas a backup,staged or cascadesysten! the volune is determinedon a cumulativebasis; the total volume equalsthe total ofvent gasflared at eachflare in the system.For flaring lasting more than one calendarday, eachday offlaring constitutesa sepamteflaring eventunless the ormer or operatordemonstntes to the satisfactionofthe A?CO that the causeof flaring is the samefor two or more consecutivedays. A reportableflaring event endswhen it can be demonstratedby monitoring required in Section12-12-501 that the integrity ofthe water sealhas been maintained sufficiently to preventvent gasto the flare tip. For flares without water sealsor water sealmonitors as requiredby Section1 2- I 2-50I , a reportableflaring eventends when the rate of flow of vent gas falls below 0.5 feet per second. h@://rwrv.baaqmd.gov/dst/regulations Iryl 2 12.pdf

.L requirementsfor monitoring of flares and which were in place in the pastwhen ConocoPhillipshad excessive flaring, are vaguely stated.

The monitoring requirementsof the applicablefederal rules for flaring are appropriately incorporatedtry the permit by referenceto thoserules. These requirementsaddress proper operationof a flare for effectivedestruction of organic constituentsin wastegas and effectivecombustion as relatedto generationof CO,

77. The Wood River refinery has a major potential for emissionsfrom flaring.l8 Baseline flming emissionsand compressorcapacity at the refinery must be provided to the public, andpotential increasesfrom flaring must be evaluatedin light of this information about other refineries. However,the applicationdid not provide information on existing or wastegas compressor capacity or information on root causesofpast flaring at the refinery, or the volume, duration,and emissionsof individual flaring events. Without monitoring of the volume and compositionof wastegas sent to the flare, and without designingsuffrcient gas recovery capacity, increased and poorly quantified flaring will occur at existing flares at the refinery with this project.

Under the ConsentDecree, ConocoPhillips must prepare and submit its Compliance Plan for Flaring Devices,which will addressthe existingflares at the Wood River refinerynby December31,2007 [Paragraphs l4l and 142ofthe Decree]. ConocoPhillipsmust alsouse flow metersor reliable flow estimationparameters to determinethe emissionsfrom flaring [Paragraph 165].

78. The permit shouldrequire ConocoPhillipsto developand implernenta flare minimization plan to capturewaste gas for useas fuel, ratherthan flaring it, so that flaring emissions arereduced.

Wastegas is routinely capturedfor useas fuel rather than being flared. For existing processunits, requirementsfor minimization of flaring are establishedby the ConsentDecre€, The Decreerequires ConocoPhillips to developa plan that includessteps to correct the conditionsthrt causeor contribut€ to excessiveAcid GasFlaring and Hydrocarbon Flaring,

As part of this project, ConocoPhillipswill be installing redundantwaste gas recoverT/compressors for the new DelayedCoker Uni! eachof which is designedfor 100percent of routine gasesfrom the unit. The issuedconstruction permit also requiresConocoPhillips to developand implement a [laring Minimization Plan for the new Coker Unit and the new Hydrogen Plant. tE Although it is unlikely that the Wood River refinery performedas well as the averageBay Area refinery before the Bay Area reductionsoccurred (since USEPA found that excessiveflaring was occurring),ifthe Wood River refinery had performedas well per barrel of cmde oil processed,baseline emissions ofTotal Organic Carbon(TOC) for the refinery would be about 1898tons per year. Furthermore,the proposedproject representsa 126oloincrease rn refmery capacity(306,000 to 385,000bpd). Flaring emissionswill likely increasemore than 26% becausethe refmery is increasingproduction in the most intensivepart ofthe refinery, with higher-sulflu inputs. With a 26% increaseon top ofbase TOC emissions1898 tons per year, TOC emissionsftom flaring at the Wood River refinery would increaseby almost 500 tons per year, evenusing conservativeassurptions that could underestimateflaring.

JJ 79. What monitoring deviceswith what detectionlimits arecurrently installedto measure flow and compositionofwaste gasesfor eachexisting flare at the refinery? What specificmonitoring devices will be installedfor the newflares?

The existingflares must be operatedto comply with the requirementsof the New SourcePerformance Standards (NSPS) and/or National EmissionStandards for HazardousAir Pollutants(NESHAP) for flares. The NSPSand NESHAP require monitoring for a pilot flame be presentin a flare at all times that wastemay be sent to the flare, which ensuresthat any wastegases that are sentto the flare will be ignited and combusted.They do not require other monitoring. Under the Consent Decree,ConocoPhillips must be able to reasotrablydetermine flow and H2Scontent of wastegas.

The issuedpermit requiresthat monitoritrg and recordkeepingbe implementedfor new flares to be ableto determineflow and compositionof wastegas. Useof specific monitoring devicesis not required and can be addressedin the processingofa revisedTitle 5 permit (CleanAir Act Permit Program Permit) to addressthe proposedproject.

80. How many flaring eventsdue to upsetsoccurred at the Wood River refinery during the last three years.

There were ten eventsin 2005.ten eventsin 2006.and four eventsin 2007. The majority of eventsoccurring in 2005were attributable to problemswith the startup of the gascompressor on the distilling westcoker. The majority of eventsfor 2006 were attributable to power outages.Power outagesalso contributed to events. Power outagesaffect both the processunit and the wastegas sy$tem, as they rely upon availability of electricalpower. ConocoPhillipsindicates that it is working with Ameren to improve the reliability of the power supply for the refinery.

81. How many flaring eventsresulted in visual smokingand what evaluationswere performedto determinethe associatedemissions ofparticulate matter andpolycyclic aromatichydrocarbons?

There were sevenevents in 2005,seven events in 2006,and oneevent in 2007, Specificevaluations were not conductedto quantify €missionsof particulatematter or polycyclichydrocarbons. Such evaluation was not considerednecessary given the duration of eventsNnd the compositionof the refinery's wastegas streams, which do not contain signilicantlevels of aromatic hydrocarbons.

82. How much SOz,VOM, PM, NO*, CO, and CO2is emittedfrom the existing flares affectedby the project? Is that listed somewhereand shouldit be part of the permit?

Table C-l of the applicationcontains the baselineannual emissions of CO, NO*, and VOM for the existingflares affectedby the project, The annual emissions,based on

J+ 24 consecutivemonths of actual emissiondata are: 7.8 tons of CO,3.6 tons of NO*, and 3.4 tons of VOM. The emissionsof PM and SOzwere not quantified asthey would be minimal given the nature of the gasstreams being flared. Historically emissionsof CO2 from the refinery havenot beenquantified. The increasesin emissionsat theseflares are addressedin Attachment I of the permit

83. What is the destructionefliciency assumedfor calculatingflaring emissionsand what is thebasis ofthis figure?

For purposesof calculationemissions, properly operatedflares are assumedto achieve98 percentdestruction elliciency for VOM and CO containedin the waste gas. This conservativelevel of performanceis basedon information on USEPA'S Compilation of Air Pollutant Emission Factors, LP-42. Actual destruction efliciency could be significantlyhigher,

84. How much compressorcapacity for recoveringwaste gases is being installedfor eachof the new flares for the project? What calculationswere performedto ensurethe compressorcapacity will be sufficient to eliminateall routine flaring?

Redundantcompressors are being installedon the new coker flare. Each compressoris designedto route 100percent ofthe projectedflow of wastegas from the cokeunit to the fuel gasrecovery system.re The adequacyofthe recoverysystem in practicewill be addressedby the required Flaring Minimization Plan. Other flareswhich would handlegases from the existingflare gasrecovery system are not affectedby this project.

CRUDE OIL SUPPLY

85. The proposedproject would involve modificationsand expansionfor the purposeof processingless-expensive, heavier crude oil, with resultantincreased local and global pollution and hazards,that will be locked in for decades.The proposedproject represents a majornew directionin U.S. refmeryoperations with modificationsto processheavy Canadiancrude oil recoveredfrom oil sands.This project is a test caseof this trend for useof heaviercrude oil with higherenergy use. Processingof oil sandshas impacts in Canada,including degradationofpristine boreal forest and impactson plants and wildlife Canada.This project requirescareful evaluationdue to its natureand its long-term . implications.

It is beyondthe scopeofthe Illinois EPA's review ofthe applicationsfor the proposedproject to formally considerthe various impactsin Canadafrom the recoveryand processingof crude oil from oil sands. This is a matter that is appropriately consideredand addressedby the federal and provincial governments of Canadaas they regulatethis activity. However,as this commentobserves, the recoveryof crude oil in Canadais accompaniedby environmentalimpacts, as is the le ConocoPhillips indicates that the gas flow rates ofprocess units were modeled at maximum design rates ol units plus an engineedng safety factor using corputer simulation software for petoleum refining processes.

35 recoveryof oil from other locations. Theseimpacts are loweredas the consumption of crude oil is reduced.

86. What evaluationsof heavy-metals,such as lead and mercury,in the heavy crudeoil have beenperformed? Will mercuryand lead be emittedfrom the refiningprocess? What measurernentsare planned for the future for heavy metalsin coketo be manufacturedand whatwill be donebecause of theincrease in theseheavy metals? What practices will be usedto ensurethat theseincreases ofheavy metalsdo not escapeinto the environment?

Heary metals,which are presentin parts per million and billion levelsin crude oil, havenot beenidentified al a speciaiconceinfor crude oil.20Loss of metalsto the environmentis controlledby the generalnature of refining operationsand the emissioncontrol prscticesand add-oncontrol equipmentimplemented for certain units. As an operationalmatter, there are alsoproduction consequencesas metals can poisoncatalysts used in refining operations. USEPAand the American PetroleumInstitute are currenfly engagedin studieson the heavymetal contentsin various crude oils, to further improve the understandthe relationshipbetween metalsin the crude oil supply,the operationof refining units, and the metalscontent of products and environmentaldischarges.

87. Theheavy crude oil that will be usedat the WoodRiver refinery will be very cheap. ConocoPhillipsstands to makea lot of moneyfrom this projectand it canafford these enhancedenvironmental controls without sacrificingjobs. Often with increased environmentalcontrols, there might actually be opportunity for morejobs becauseof the workersthat are neededto operateand maintain of thesecontrols.

Heavy crude oil is not cheap. It is only lessexpensive when comparedto lighter crude oil. The lower costof heaviercrude oil is accompaniedby additional expenses . for investmentin the facilitiesneeded to be ableto processthe heaviermaterial. It is alsoaccompanied by shifts in the amount of different productsthat can be made and the revenuestream for a refinery. The quality of different products may alsobe affectedso that additional effort may be neededto adapt and enhancecertain processunits to maintain product quality. As Canadahas ratified the Kyoto protocol,the costof heavycrude from Canadamay increasedue to the costsof mitigating emissionsof greenhousesassociated with the extractionand initial processingof crude oil from oil sands.Accordingly, this project is the result of a complexbusiness decision by ConocoPhillips.One of the elementsthat must go into this businessdecision is a recognitionthat the Wood River refinery will haveto operatein compliancewith environmentalrequirements, with a workforce that is ableto properly operaternd maintain environmentalcontrol systems.This is an essentialaspect of the proposedproject irrespectiveof the costof compliance.

88. Processingofheavier crude oil (with longerhydrocarbon molecules and higher sulfur content)means more refining to producegasoline and diesel,and to removesulfur. This

4 According to information provide by ConocoPhillips, the lead and mercury content in the expected crude slate is apploxirrately 3 ppm and 7 ppb respectively.

36 will increasethe potential for upsetconditions and associated emissions due to thehigher temperaturesand pressuresneeded to processheavier crude oil.

The refinery currently processesheary crude oil, so that the proposedproject would not representN significant change to the overall operationof the refinery. While the project involvesinstallation of a secondDelayed Coker Unit to havemore capacity to crack the heavieststream from crude oil, the new crackingunits would be designedfor this purposeand include appropriate featuresto maintain safe operation. Accordingly, an increasein upsetsshould not be expectedwith the proposedproJect.

89. ConocoPhillipshas appliedfor authorizationto operateduring breakdownswhen pollution control equipmentdoes not work. This underminesthe effective control of emissions,which will be especiallyimportant when processing heavier crude oil, which is likely to increaseprocess upsets at therefinery.

ConocoPhillipsrequest for authorizationfor excessemissions during malfunction and breakdownaddressed possible exceedances of a genericstate emission standard for SOzemissions. Under staterules, ConocoPhillips must obtain "prior authorization" for exceedancesof the statestandard as it must showthat continued operationwith excessemissions may be necessaryto protect personnelor equipment This alsoenables a permit to be preparedwith conditionsthat appropriately addressthe possibilitythat suchcontinued operatior with excess emissionsmay occur. However,whether ConocoPhillipsactions to avoid malfunctionsand reduceemissions in the eventofa malfunction are still subjectto scrutiny by the Illinois EPA and USEPA as to whether the particular eventwas avoidableand goodair pollution control practiceswere followed. In contrast,the federal NSPSstate that the otherwiseapplicable standard simply doesnot apply during malfunctions. The appropriatenessof actionstaken by a sourcerelative to malfunction rre only subjectto after-the-factreview asto whether it was avoidable and goodair pollution control practiceswere followed.

DELAYED COKTNG

90. Coking is a high temperatweand pressureprocess for the heaviestfraction of crudeoil handledby a refinery. Emissionsof particulatematter, other criteria pollutants,toxic heavy metals,and greenhousegases can be extreme,especially considering fugitive emissionsand accidental releases. These should all havebeen evaluated. This is especiallynecessary given the proposed use of crudeoil from Canadianoil sands,which is particulmly heavy,so this project resultsin a large amountof coking and energyuse. Data on the carboncontent of the crudeoil supply to the refinery and the rangeof sulfur, heavy metals,selenium, and other contaminantscontained in the crude oil and impactsof thesepollutants should have been provided by ConocoPhillips.

Emissionsof PSDAISRpollutants from coking are addressedin the application, including emissionsfrom both routine operation and emergencyflaring. Emissions

37 of healT metalshave not beenidentified as a particular concernfor cokingunits as fine material is not entrainedin a gasstream during the coking process.While USEPA has adoptedNESHAP standardsfor emissionsof metal hazardousair pollutants from catalyticcracking and catalyticreforming units, it hasnot adopted similar NESHAP standardsfor coking. Moreover,these NESHAP for these catalyticprocess units set a number of alternativestandards that apply either to total particulate emissionsor nickel.emissiotrs,a single heavy metal. Emissionsof greenhousegases associated with coking are better addressedin terms ofthe overall energyconsumption and emissionsof a refinery2ror in terms of the total emissions of greenhousegases associated with the crude oil that a relinery processes.

91. An evaluationis neededfor the impactsofincreased coking at the refinery on wastewater.This is especiallytrue givan the planneduse of crudeoil from Canadianoil sands.

The impactson the wastewatertreatment plant havebeen addressed by the air permit as further shownin Section4.10 of the permit, The wastewlter treatment plant will require modificationsto accommodatean increasein wastewaterflow and solidsand organicloading due to increasedrefining operationsand to treat the wastewaterfrom the scrubberson the FCC Units. Thesemodifications will have emissionconsequences and are appropriatelylimited by this sectionofthe permit

92. An evaluationis neededfor the impactsofincreased coking at the refinery on soil contamination.This is especiallytrue giventhe planneduse of crudeoil from Canadian oil sands.

This project shouldnot contributeto soil contaminationat the refinery. Soil contaminationat refineriesis generallythe result of historic relinery designand operatingpractices. As suchspills occurred,lighter materialstypically are of particular concernfor contamination. As spills of material now occur at the refinery with the potentialfor soil contamination,such spills must be investigated and either remediatedor appropriately containedpending remediation in the future,

93. Becauseof employeeaccidents associated with DelayedCoker Units, a ChernicalSafety Alert (Hazardsof DelayedCoker. Unit (DCL| Operations,August 2003) wasjointly issuedby USEPA,the OccupationalSafety and Health Administration (OSHA), the U.S. Departmentof Labor, and the ChemicalEmergency Preparedness and PreventionOffice. This alert found that DelayedCoker Units areincreasing in use due to their ability to processlower quality crudeoil, ashigher quality crudebecomes less available to refiners. The alert fowrd that theseunits havehazards that must be addressedby the operatorsof the units, listing the variouspiocess steps and the specifichazards that areposed.

'' The quantity and quality ofthe intermediatesftearis producedby an initial conversionprocess, like coking, has implicationsfor the amountof energyconsumed by downsteam processunits at a refinery. The product slateof a refinery is also relevantfot a meaningfirlassessment ofthe energyeffrciency ofa refinery.

38 While this ChemicalSafety Alert identified potentialsafefy hazards for workers from delayedcoking units, it alsodescribed actions that could be taken to minimize thoserisks. ConocoPhillipsindicates that the new DelayedCoker Unit is being designedwith features,such as mechanicalinterlocks and an automatedremote drum unheader,to addressthe dangersthat may be posedby older coker unit and help prevent accidents.Similar upgradesare plannedfor the existingcoker unit during a future maintenanceturnaround at the refinery. In the meantime,a manual safetyprocedure involving multiple signaturesas cross-checks is being used to preventincidents. That procedurewas enhancedthis spring and ConocoPhillips indicatesthat it has beenvery effective. The Illinois EPA will be examiningthe effectivenessand the adequacyof the measurescurrently beingimplemented by ConocoPhillipsand the measuresthat are planned. This will occur asprrt of the Illinois EPA's investigationinto recentreleases that haveoccurred from the existing coker unit at the refinery,

94. Thenew cokingunit, whichwill processthe heavy crude, is goingto producepetroleum coke. GivenUSEPA's and Illinois' newrules on mercuryemissions from coalfired power plants,what will ConocoPhillipsdo with the petroleumcoke if power plants can not useit? Do all the coal-firedpower plants around use it or just a few or some?

There is no reasonto believethat coal-firedpower plants will no longer use petroleumcoke from the refinery. Additionally, the market that the refinery choosesto sell products to has no impact on its ability to complywith the applicable regulations.

Incidentally,the new coker will not directly processheavy crude oil. The function of the new coker unit is to further processmore ofthe bottom fraction ofcrude oil, which is currently produced at the relinery and sold as asphalt. The coker unit will convertthis bottom fraction into petroleumcoke, a solid fuel material, and a liquid streamthat can be further processedinto higher value petroleumproducts.

95. I am concemedabout coking becauseofpast releasesfrom the coker units at the refinery, which releasedmaterial that causeddamage to homesand property. As part ofthis project,is ConocoPhillipstaking into considerationthat accordingto an August 2003 documentprepared by the USEPA and OSHA, delayedcoker units havebeen found to causeffequent and severeaccidents. Considering the pastviolations at the refinery, will employeesbe safe and nearbyresidents be safegiven the hazardsassociated with these units? What stepswill be takento ensurethe safetyof employees?

The past releasesappear to havebeen caused by operator error. As part of this projectosafety interlocks will be installedon the new coking unit to prevent similar releasesfrom the new unit. ConocoPhillipsindicates that the new coker unit will haveall ofthe latestsafety features for a coking uni! including automated equipmelt, interlock valves, enhancedinstrumentation and other safety systemB.

96. What measureshave been evaluated to eliminate fugitive dust from coking during the

39 manufacture,storage and transportationofpetroleum coke dueto the project? Have there beenrecent violations at the refinery involving theseoperations.

With appropriate housekeepingpractices, the handlingof petroleumcoke is not a significantsource of fugitive dust The cokeis ctrt out of the cokedrums with water jets, which ryetsthe surfaceof the cokepreventing dusting. Thereafter,fugitive dust can be readily controlledby appropriatehandling practiceswith applicationof additionalwater or other dust suppressantas neededto control fugitive dust. Given thesecircumstances, the handlingof cokeby ConocoPhillipshas not posedany concernsfor compliance.

EMISSIONS

97. A full evaluationis neededfor emissionsPlt4z5 from the project, including secondary formationof PM2.5caused by SOzand NO* emissiorsfrom theproject.

The generaleffect of the changesoccurring at the refinery, including the proposed project, is to reduceits contribution to the levelsof PMz.sin the ambient air and to improve air quality. This is becausethe net effectof thesechanges is to reduce emissionsof direct PM. Emissionsof precursorsto PM2J are alsoreduced as emissionsof emissionsof SO2are substantiallyreduced. (Emissionsof NO* would not increasesignificantly, even with the permitted increasein production.)

As the Greater St. Louis areais currenfly designatednonatfainment for PM2.5,the Illinois EPA and the Missouri Departmentof Natural Resourcesmust developand implementattainment plans to bring the area into attainmentof the National Ambient Air Quality Standards(NAAQS) for PM25. This will provide a comprehensiveevaluation of local and regionalemissions of direct PM2.5and precursorsto PM2.5oincluding emissionsfrom the Wood River refinery, asnecessary to assurethat the complianceof the NAAQS for PM2.5is achievedand maintained throughout the area.

98. Thisprovision of the ConsentDecree purporting to allow useof emissionreductions as partofprojects at therefinery is contraryto the CleanAir Act andthus invalid.22 Section 173(c)(2)of the CleanAir Act expres,slyprohibits the use of emissionsreductions requiredby the Act asoffsets. ConocoPhillips cannot be allowedto useemission reductionsrequired by the ConsentDecree as offsets for this projectbecause these reductionsare required by the CleanAir Act.

Section173(c)(2) of the CleanAir Act, which dealswitl emissionoffsets for major projectsin nonattainmentareas, is not relevantto the permitting ofthe proposed project for emissionsof SO2, Not only will the proposedproject occur in an

22 Pxagraph 262(d) ofthe Consent Decree provides that "...utilize emissions reductions from the installation of controls required by this Consenl Decree in determining whether a project that includes both the installation of contols under this Consent Deqee and other constmction that occurs at the same time and is permitted as a single Foject triggers rnajor New Source Review requircments.;"

40 attainmentarea for SOu,and not in a nonattainmentarea, but the decreasesin SO2 emissionare being usedfor purposesof'nettingtt to demonstratethat the proposed project is not a major project. The emissionsdecreases are not being usedas emissionoffsets, which would entail a transfer of emissionreduction credits from onesource to another,as is occurring for the proposedproject for emissionsof voM.

99. If the emissiondecreases from the installation of scrubberson the FCC Units were not creditedagainst the proposed project, the project would havea significantincrease in SOu emissionsand be a majormodification for emissionsof SOzunder the PSDru1es. The additionof the scrubbersto theFCC Units resultsin decreasesin SOzemissions of 5,909.6tpy from FCC 1 and5,221.9 tpy from FCC 2 (total 11,132tpy). If thesedecreases werenot creditedtowards the project, the projectwould have a net SO2decrease of only 36 tpy.'3 When increasedSOz from flaring, missing from the application,are included, hundredsof tonsper yearmore emissions are added with theproposed project. While theseemissions can be preventedwith BACT for new and existing flares that will handle the additionalwaste gases due to theproposed project, the project would increaseSO2 emissionsby more than 40 tpy as currently proposed. This triggersPSD for emissionsof SO2,requiring BACT for emissionsof SO2from new andmodified emission units.

As this commentconfirms, at mostonly a fraction of the decreasein SO2emission from the installation of scrubberson the FCC Units is neededto ensurethat the proposedproject is not a major project for emissionsof SOz. Accordingly, assumingfor purposesof argumentthat evenmost ofthe decreasein SOzemissions from installation of scrubberson the FCC Units could not be relied upon for the permitting ofthe proposedproject, the remaining decreaseswould still be sullicient for the project not to be a considereda major modilication for emissionsof SO2.

In addition, the refinery is subjectto requirements,as touched upon by this comment,that act to prevent increasesin SO2emissions due to increasedflaring at existingflares in conjunctionwith this project. In particular, the Cons€ntDecree includesrequirements to investigatethe causeof flaring incidentsthat contribute to SO2emissions, including performanceof root causeanalysis, to take stepsto correct the conditionsthat causesuch incidents, and to minimizethe number and extentof suchincidents. Theserequirements are accompaniedby provisionsfor detailed reporting for signilicant flaring incidentswith estimatesof SO2emissions, the root causeanalysis lnd the correctiveaction plan. Stipulatedpenalties apply if an incident resultedfrom carelessoperation, failure to operatein accordancewith good engineeringpractice, or failure to follow written procedures.A condition has been includedin the issuedpermit that makesclear that thesepractices, other than stipulatedpenalties, are alsoapplicable for the new flare that would be installed with the new DelayedCoking Unit.

100. In order to clearly evaluatethe proposedproject and altematives,the project shouldbe assessedwithout the SO: emissiondecreases from the scrubberson the FCC Units

'" I I,168tpy - 11,132tpy=36tpy

41 (11,132tons), which arenot allowableunder the CleanAir Act, andseparately from offsetsfrom otherprojects (3,165 tons). In this light, theproposed project by itself will resultin an annualSO2 emissions increase of 3,129tons.

This commentreflects an incorrect evaluationofthe proposedproject for emissions of SO2, The project is only being permitted for 1548tons per year of "new' SO2 emissions.The project alsowill only be accompaniedby an emissionsdecrease of 11554tons per year from other contemporaneousprojects, However,these decreasesby themselveswould still be sullicient for the project to net out of PSD review for emissionsof SO2. The installationof the scrubberson the existingFCC Units will provide a further decreasein emissionsofSOz ofat least111132 tons per year. In summary,there will be a substantialdecrease in refinery's SOzemissions from current levelsafter the proposedproject is complete.These circumstances do not necessitatean alternativeformulation ofthe extentofthose decreasesto assess the effectofthe project or corsider alternativesto the proposedproject.

101. To the extentthe decreasesin SOzemissions listed for other"Contemporaneous" projects were or will be carriedout pursuantto the ConsentDecree or are otherwiserequired by the CleanAir Act, they arenot allowable for offsets.The Illinois EPA must provide a detailedevaluation of this issueand historical review ofreasons for these contemporaneousprojects in orderto addressthe potential improper use of offsetsby ConocoPhillipsfor thisproject.'*

The emissionsdecreases for ContemporaneousProjects are itemizedin Table C-12 of the application. Thesedecreases occurred with and were relied upon for other projects at the refinery. Their circumstatrcesof thesepast decreasesare identicalto the future emissionsdecreases that will occur at the FCC Units with installationof scrubbers. Incidentallg the amount of thesedecreases is only aboul 11580tons.

1O2. The current SOzemissions of the Wood River refinery are very high comparedto those ofrefineriesin Texasand California. The touted 11,168 ton reductionin annualSO2 emissionsthat will accompanythe proposedproject is long overdueand is improperly being usedto cover up the increasesin SOzemissions that actually result from the proposedproject, when SO2 emissions should have been reduced separately, on its own merits. For example,the baselineannual SOz emissions of the Wood River refmery, with a currentcapacity of about306,000 bpd, areabout 11,468 tons, which is almost8 times higherthan the emissionsof BP's SouthCoast refinery when adjusted for capacity.2s

Emissionof SO2should not be comparedas simply as suggestedby this comment

2a AppendixC ofthe applicationshows the total use of3,165 tpy of SOxoffsets, i.e., 1,580tpy of offsetsfrom conternporaneousprojects ofat slartupof"FCCU-3 and DU-2 LC Startup"and 1,585tpy ofadditional offsetswhen theproject is conpleted. " In 2005,the average SO2 emissions reported for the28 refrneriesin Texaswere 1,985 tons, for a total52,868 tons. In 2005, the averageSO2 emissions for the five refineriesin the SanFrancisco Bay Are were 2532 tons, for a total of 12,662tons. In the SouthCoast area (Los Angelesarea), t}re averageSO2 emissions of sevenrefineries were 683 tons, for a total ofonly 4779 tons. The largestcapacity Califomia refinery, the BP SouthCoast refinery with a capacityof260,000 barrels per day(bpd), ernitted only 1221rons ofSO: in 2005.

A1 This is becauseof the various factorsthat affect SOr emissionsof a refinery. These factorsinclude locationand accessto different sourcesofcrude oil, the nature of crude oil that a relinery is capableofprocessing, the nature ofthe refining processes at the refinery, ageof the units at a refinery, and a number of other factors.

103. Thetotal SO2baseline ernissions ofthe WoodRiver refinery are not providedin the application(Table C-l, proposedProject Emission Increases Summary, Appendix C 5)26 Theremay be additional significant SO: emissionsfrom facilities at the refinery that are not includedin this listing, which shouldbe provided to the public aspart of the applicationand for considerationof altemativesto the project.

The applicationwas appropriatelyprepared to addressthe existingemission units at the relinery that are affectedby the proposedproject. Information on the total baselineemissions of SOr of the Wood River Relinery is availablefrom the dnnual EmissionReports submitted by ConocoPhillipsfor 2004and 2005,which indicate annualSOz emissions of about 12,500tons. It is not necessaryto include data in the applicationfor baselineemissions for existingunits that are not affectedby this project. In fact the majority of the emissionsof the refinery are addressedin the application,since the project includeschanges at existingprocess units at the start of the refining process.

104. Evenafter the ernissionsdecreases with theproj ect are achieved, with controlofSO2 emissionsof the FCC Units, the total annualSO2 ernissions for the variousoperations at the WoodRiver refinery listed in the applicationme 1891tons (Appendix C TableC-l). This Table doesnot provide total SOzfor all refinery units, only emissionsfrom the units in the project, so the total for the refinery may be evenhigher. When comparedto the averageSO2 emissions for refineriesin other regions,the Wood River refinery will still havemore SOz emissions than the typical refinery in Texas,(1786 tpy)'' or Califomia (1,607tpy). It will alsohave higher emissionsthan the largestCalifomia refinery (BP with 1,22I tpy). Accordingily, the Wood River refinery cannotbe consideredto provide the best control for emissionsofSO2, or evanthe averagerate of control, after the proposedproject.

It is wholly inappropriate to comparethe future @i!!99 SO2emissions of the Wood River refinery, as setby the permit, to the gg!@! emissionsof other refineries. The permitted emissionsofthe refinery, as setby the permit, incorporatesafety factorsto accountfor normal variation in the operationofprocesses and control measuresas related to emissions.After the proposedproject is completed,it is expectedthat the actual SO2emissions from the Wood River refinery will consistenUybe significantlylower than the permitted emissions,with actual SOz

26 The total ofemissions listed for the units at the refinery after the project in Appendix C, Table C-l is not provided, only the changein emissions. However,the column entitled "PotentiaVProjectedActual EmissionRate (tons/yr)" providesemissiors expectedafter the COREProject for individual rmits, which totals on the Table to I tons/yr. ''-1_89 The refinery in Texasthat emitted 11,786 tons of SO2in 2005 is not typical and is an outlier corpared to the other Texasrefineries.

43 emissionsthat coincidentallyare equalto or lessthatr the "average' relineries discussedin this comment.

The actual SOt emissionsof other refineriesare alsonot indicativeof the amountof SO2emissions that thoserefineries are allowedto emit by applicableemissions standardsand permits. Accordingly,their actual SOzemissions do not provide a meaningfulreference for whetherthe SOzemissions of the Wood River refinery would be well controlledin the future. In this regard,the ConsentDecree, which addressesexisting emission units, and the federal New SourcePerformance Standards,which will addressnew and modilied units at the retinery, can be consideredto require very goodcontrol ofthe SOzemissions of tle relinery in the future.

105. Thedecreases in the SOzernissions ofthe FCCUnits arerequired by a ConsentDecree with the USEPA. the Stateof Illinois and other statesthat addressthe Wood River refineryand other refineries operated by ConocoPhillips.28Therefore ConocoPhillips cannottake credit for thesedecreases for permitting the proposedproject. In particular, the ConsentDecree requires ConocoPhillips to install certainemission controls at the WoodRiver refinery,including scrubbers on the FCCUnits, which provide most of the SOzemissions decreases. The ConsentDecree also states that ConocoPhillipsmay not take credit for reductionsrequired by the ConsentDecree.

The provisionsofthe ConsentDecree with respectto tusett of emissionreductions are more involvedthat indicatedin this comment. The ability of ConocoPhillipsto useemissions decreases that result from actionsunder this decreeis a matter that is addressedby the actualterms of the ConsentDecreg which allow useofthe emissiondecreases for permitting of the proposedproject. (Paragraph262(d) of the ConsentDecree). The provisionsof the ConsentDecree that addressuse of emission decreaseswere negotiatedby ConocoPhillips,the USEPAand other partiesto the Decree,as the Decreeconstitutes a negotiatedsettlement of allegedviolations on the part of ConocoPhillips.

106. The SOulimits for theFCC Units proposedin the draftpermit do not representBACT and shouldbe lower. The draft permit would require the FCC Units to meet limits of 25 ppmvdSO2, 365-day rolling average,and 50 ppmvd,7-day mlling average,both at 07o 02, pursuantto Paragraphs57 and 60 of the ConsentDecree. A study by the USEPA, the University of Texas,and the TexasCommission on EnvironmentalQuality reviewing the emissionrates achieved in practicefound that the Valero refinery in CorpusChristi, Texasmet a 20 ppm limit in 2003.This limit shouldbe requiredfor this project.

This commentdoes not support settinglower SOr limits for the FCC Units. The proposedproject doesnot trigger a requirementfor BACT for emissionsof SOz, In addition, thesecomments suggest that a stringent levelof control for SO2emissions

'?8 United States ofAmerica and tbe States oflllinois, I-ouisiana and New Jersey, Comnonwealth ofPennsylvania and the Northwest Clean Air Agency v. ConocoPhillips Conpany; Civil Action No. H-05-0258, entered by the Dishict Court for the Southem District of Texas on January 27, 2005 (Consent Decree) is alreadyrequired by the Cors€nt Decree. The study cited by this commentshows actual SOr emissionsat 20 ppm in a particular year, which is consistentwith an emissionlimit setat 25 ppm, to provide a safetyfactor for normal variation in operationof an FCC Unit and its SO2emission control systems.

I07. It is not clearwhether there is a netreduction in emissionsfrom this project,as ConocoPhillipsclaims. With all of thenetting and all of the debottleneckingand all of theproblems that meinvolved, there is goingto be an increasein emissions.I don't want the netting to be "smoke andmirro6." I want thereto be an actualdecreases in ernissions.

The project will result in a net increasein enissionsof someregulated pollutants (e.g.,VOM, CO, and PM). For pollutants for which there is net decreasein emissions(e.g.,NO. and SO2),In order for emissionsdecreases to be considered creditablefor purposesof a netting exercise,they must be actual decreasesin emissions.

108. Whatwill be theincrease in emissionof H2Sfrom theproposed project, in pourds,from both the Wood River andthe Distilline West facilities?

There will be at most a minlmal increaseof IIzS as a result of this project. Most of the HrS and other sulfur compoundswill be recoveredby the new sulfur recovery units as elementalsulfur. The IIzS in the tail gasfrom the Sulfur RecoveryUnits is convertedto SOzin the oxidizers. The HzSin the fuel gassystem will be converted to SO2through combustionin the heatersor other combustiondevices.

109. An evaluationis neededfor ernissionsand impacts ofthe projecton thepublic from odors,including odorsdue to flaring, fugitive H2Semissions from higher sulfur products at the refinery, and other sourcesof emissions.

This project will not be significantfor emissionsof H2S. This is becausestreams with potentially significantlevels of emissionsof H2Swill be combusted,either as fuel gasor by flaring, convertingthe HzS to SOz. Overall, the emissionsof H2Sfrom the refinery shouldbe decreasingbecause of improvementsbeing made pursuant to the ConsentDecree,

OTHER

110. TheD.C. Circuit Courtrecently vacated the Boiler MACT Rule,which meansthere is no industry standardand permits require individual MACT analysesfor any boilers that weresubject to this rule.'"

While the D.C. Circuit Court recentlyissued an order finding that the "Boiler MACT Rule" should be vacated,tle Circuit Court has not y€t issueda final mandateto vacatethis rule. In the interim. the Boiler MACT Rule remainsin

2ehttp://pacer.cadc.uscourts.gov/docs/commodopinions/200?061M-1385a.pdf.

45 effect. When and if a final mandateis issued,the Illinois EPA would proceedas instructedby USEPAfor this unusualdevelopment with respectto this rule. This could necessitateConocoPhillips having to obtain a revisedconstruction permit for the boilers and steamgenerating units that would haveotherwise been subject to the Boiler MACT Rule. A case-by-caseMACT determinationmight alsohave to be madethrough an appropriaterevision of the CAAPP permit for the refinery, so as to addressexisting boilers at the refinery, independentofthe proposedproject.

I I 1. How many pressure-reliefdevicesat the refinery vent to the afmosphereand what monitoringdevices are used to determinewhether these devices have vented? How many pressure-reliefdevices &om thenets project will ventto the atmosphere?What monitoring deviceswill be usedto determinewhether they havevented?

While many of the pressurerelief devicesvent to the existingvent gasrecovery system,which routesdischarges to the fuel gassystem, tlere are certainpressure relief valvesthat vent directly to the atmosphereto protect equipmentand workers from catastrophicfailure. There are no new hydrocarbonpressure relief valvesas part of the proposedproject. Pressurerelief valvesare recognizedas potential sourcesof emissionsdue to leaksand are addressedby the Leak Detectionand Repair (LDAR) program that ConocoPhillipsmust implementunder stateand federal rules. For pressurerelief valves,this program requiresmeasurements with a potrable orgrnic vapor analyzerwhenever a valve opens. Thesemeasurements are usedto confirm that the valve has properly resealedafter the eventwas over or that the new rupture disk was properly installedover the pressurerelief valve.

Il2. Will the valvesfor theproposed project be leaklessbellow valves? How manynew compressorsand pumpswill havedouble seals and how many will not?

ConocoPhillipsis not planning to usebellow valves. Bellowsvalves and certain other "leakless"equipment can havesignificant emissions when failures occur.In particular, bellow valvesare not reliable in "aggressivettservice. This type of equipmentis alsonot availablefor all situationsin relinery operations.

All new pumpsin light liquid servicein the new units will be equippedwith double seals.It is anticipatedthat the definition for a leak setas LAER could be met wlth control technologiessuch as dual or mechanicalseals.

113. Hasthe Illinois EPA anallzedhow the proposedchanges to federalNew Source PerformanceStandards (NSPS) for petroleumrefineries, which will be applicableto this project, affect the permit?

Many of the amendmentsand new rules30were driven by the control technologies required by USEPA'sNew SourceReview Consent Decrees for various refineries. Although theserules are not expectedto be adopteduntil 2008,the proposedproject

'o On April 30, 2007, the USEPA proposedamendments to the currentNSPS for Petoleum Refineries(40 CFR 60 SubpartJ) and a new NSPSfor units including FCC units, coking units, and sulfur plants. (40 CFR 60, SubpartJa).

/+o will be designedcomply with thesenew and revisedNSPS standards, which are consistentwith tle stringent emissionlimits setin the ConocoPhillipsCorsent Decree.

114. The EndangeredSpecies report submitted by ConocoPhillipsis inadequatebecause they usedwhat appearsto be an inappropriatemodel for the depositionmodeling and the follow-up evaluation- using one for hazardouswaste incineration facilities ratherthan for the refining of crudeoil from Canadiantar sands. In addition, the dataused in the modelappears to for the existingsupplies of crudeoil.

The analysisfor impactsof the proposedproject on threatenedand endangered specieswas properly prepared. Depositionmodeling was conductedwith an appropriate model. While the specificmodel was originally developedto address depositionassociated with hazardouswaste incineration, it is alsosuitable for addressingdeposition of emissionsfrom other types of sources.This is because there is nothing unique about how depositionoccurs from a hazardouswaste incinerator as comparedto how depositionoccurs from other typesof sources.The data usedin the analysisthat reflected'current" compositionof certain emissions was appropriategiven the very conservativenature ofthe pafricular data. In addition, the analysisshowed very low potential impactsso that the precisionofthis data was not a critical elementfor the conclusionofthe analysis.

nxistins Groundwat

115. Will thecone ofdepression under our townsget largerwith the additionalgroundwater that will be pumpedand usedfor the proposedproject?

The proposedproJect will not expandthe coneof depressionas the pumping rate will not increasewith this project. The coneof depressionis the intentional result of actionstaken to prevent the migration of existingsoil contaminationunder certain areasof the refinery. By pumping groundwaterfrom under the refinery and maintaining a coneof depression,groundwater flows toward the refinery, rather than away from the refinery, which preventsthe spreadof contamination. Collected groundwateris then tr€atedto removecontamination.

116. Is therea reasonthat that contaminationis not beingremediated in anotherway insteadof just pulling the water down far enoughso it is not coming into contactwith contaminated soil? GivenConocoPhillips stated goal ofprotecting the localcommunity and the environment,it should find anotherapproach to the contaminationinstead of wastingthis much groundwater,which could be otherwisebe usedfor productivepurposes.

Equilon EnterprisesLLC d/bia ShellProducts US is required by a RCRA permit issuedby the Illinois EPA, Bureau of Land to maintain a gradient control under the refinery, This is doneby maintaining a coneof depressionthat prevents contaminationfrom migrating off-site. ConocoPhillipsis maintainingthe coneof depressionfor Equilon, as it is required to do under a contractwith Equilon. When

47 the RCRA permit was issred,this approachwas determinedto be an acceptable approachfor containingcontamination. This approachis both feasibleand cost- effectiveas it doesnot disrupt the operationof the refinery. The groundwaterthat is pumpedis productively,as it is one ofthe sourcesof water for the refinery ll7. How is the groundwatercontamination in the Hartford are4 where a layer of oil floats on the top of groundwater,being addressed?

The groundwatercontamination in the Hartford area is being remediatedby the Hartford Working Group under an Administrative Order on Consentfrom USEPA (No. R7003-5-04-001).The Hartford Working Group is a consortiumof the companiesthat havebeen found to be responsiblefor this contaminationand are subjectto this Order. ConocoPhillipsis not one of thesecompanies. esmplianec

118. It is the responsibilityofthe Illinois EPA to reviewand grant the constructionpermit not only for what complieswith the CleanAir Act and Illinois' regulationsbut alsohow it impactsthe people who live here. The Illinois EPA hasdiscretion. The Illinois EPA can be permissiveand relar requirementsor it can requirethe besttechnologies and actual pollution reductions. The Illinois EPA can require strict controlsand monitoring and can enforcecompliance and prosecute violations.

The Illinois EPA's action on the applicationfor the proposedproject is constrained by applicablelaws and regulations.The Illinois EPA doesnot havethe authority to relax requirementsas suggestedby this comment. Likewise,the Illinois EPA does not havethe authority to arbitrarily set requirementsfor control of emissionsthat are more stringent than allowedunder applicableregulations and permitting programs. The Illinois EPA hasused the discretionaryauthority that it doespossess to setstringent requirementsfor the proposedproject accomFaniedby rigorous requirementsfor monitoring. The Illinois EPA alsoenforces compliance and, with the assistanceof the Ofllce of the Attorney General,prosecutes violations.

I 19. The Wood River Refinery has a history of noncompliancewith environmentalregulations asdoes ConocoPhillips. ConocoPhillips was suedby theUSEPA and the Stateof Illinois for violatingthe CleanAir Act. It is the subjectof a ConsentDecree that requires it to do certainthings by certaindates so that their facilities comply with the law. It has askedfor more time to comply with certainrequirements.

The requestfor extensiondoes not apply to the Wood River refinery. ConocoPhillipshas requestedfor someof its other refineriesthat were affectedby a hurricane,which prevent€dthem from meetingthe schedulein the ConsentDecree.

120. Theproposed project requires evaluation ofthe commitrnentofConocoPhillips to clean up emissionsofthe refinery due to pastviolations independentof this expansion.

48 ConocoPhillipshas beenfulfilling its obligationsunder the ConsentDecree to resolvealleged emission violations at the Wood River relinery. l2l. ConocoPhillipswas out of compliancewit the CleanAir Act for the lasttwelve quarters.

The ECHO databasedoes indicate that the refinery has allegedlybeen out of compliancewith the CleanAir Act. However,the lllinois EPA is not awareof current violationsof applicableair pollution control laws or regulations. It is believedthat the noncompliancethat underliesthe data in the ECHO databaseis historic a6nssmpliance,which has beenlegally resolved with the ConsentDecree,

122. It hasbeen my experiencewith other public hearingson constructionpermit applications that I ask questionsat the hearing,and if the Illinois EPA staff doesnot know the arswers,then I don't get the answersuntil after it is all over. I haveno opportunityto commenton the answers.The Illinois EPA shouldfind someway of putting the answers on the record so that I can then submit and extendthe commentperiod so I can comment on the answers.I do not expectall the answersto be availableat a public hearing,but it would be very helpful if I would be able to havethe answersand then be able to comment on them.

The proceduresfor public commentperiods and public hearingsdo not accommodatethe continuing exchangeor dialog on draft constructionpermits requestedby this comment The Illinois EPd staff respondsto questionsat public hearingson constructionpermits as it is ableto do so. However,the primary purposea public commentperiod, including a public hearingis to obtain input from the public on the lllinois EPA's preliminary decisionsthat a proposedproject is entitled to a construction permit.

123. More detaileddata must be provided by ConocoPhillips,rather than requiring the public to effectively pmvide the analysisby pulling togetherthis information. An evaluationis neededfor many ofthe issuesraised at the public hearingthat were not answeredat the hearing.The public broughtup key environmentaland health issuesand questionsabout basic data and impactsof the project. The transcript showsthat many of theseissues were not evaluated.There should be a follow-upon all questionsevaluated.

This ResponsivenessSummary provides the Illinois EPA's follow-up to the various issuesand questionsraised at the hearing and in written public comments.As explainedin responseto various comments,comments did not identify issuesthat required submittal of more data or performanceof additional analysesby ConocoPhillips.

L24. There aremany additionalclear hazardsfrom this project,but the applicationfailed to provide basic information for public analysis,and the time for public review was short consideringthe fact that the public had to assemblemuch basic data. The Illinois EPA

49 shouldre-evaluate the project taking into accountthese additional issues and re-open the commentperiod

The public commentperiod, which lastedover 80 days,provided a reasonable amountof time for the public to review the applicationfor the proposedproject and submit informed comments.The public commentsdo not raise any issueswhose nature is suchthat they warrant preparation of a new draft permit by the lllinois EPA and re.openingof a public commentperiod. While various concernsare raised about the proposedproject the commentsdo not showthat the project, ascurrently proposedby ConocoPhillips,would posesignificant hazards to the public or should not be permitted.

her Comments

125. Fuelefficiency standards for vehiclesneed to be inueased.We alsoneed to movepast fossil fuels anddevelop electric cars and wind and solar energy. As SenatorObama has stated,for the sakeofow security,our economy,ourjobs andour planet,the ageofoil must end in our time.

126. Thereare a lot of healthproblems in this area. Many of our children haveasthma. We do not needany moreparticulate matter or ozonein the air.

127. ConocoPhillipsshould operate its heatingand cracking units more efliciently.

128. It is importantto work to devisecredible, practical, cost-effective approaches to address the emissionsof greenhousegases at the national and at the intemational1evel, given the global natureof climate change. ConocoPhillipsshould strive to do this for this project.

nor ldAitionat Intor

Questionsabout the public comment period and pemit decisionshould be directedto

Bradley Frost, CommunityRelations Coordinator Illinois EnvironmentalProtection Agency Officeof CommunityRelations 1021North GrandAvenue. East P. O. Box 19506 Springfield,Iliinois 62794-9506

217-782-7027 Desk Line 217-782-9t43TDD 217-524- 5023 Facsimile

[email protected]

50 21'7/ 7 82 -21,L3

CONSTRUCTION PERMfT , NESI{AP SOURCE - NSPS SOI]RCE _ PSD APPROVAI

PERMITTEE

ConocoPhiltips company At tn : Tom Wlmn 1000 South Pine, 5540 CB Ponca City, Oklahoma 7 4602

Application No. : 06110049 I.D. No. : 119050A4N Applicaut' s Designation: Date Received: November 27, 2006 Subject: Terminal Expansj-on Date Issued: iluly 19, 2007 Location: 2150 South Delmar Avenue, Hartford

This Permit is hereby granted to the above - de 6 ignatsed permittee to CONSTRUCT emission source(s) and/or ai-r pollution control equipment corrsisting of a terminal expansion, that is, modifications to the existing petroleum product terminal to accomodate the neighboring wood River Refinery,s CORE project, as described in the above - ref erenced application. This Permit is subject to standard conditions attached hereLo and the following special condition(s):

In cbnjunction with this permit, approval is given with respect to tshe federal regulationE for Prev€nt.ion of SignificanE Deterioration of Aix Quality (PSD) for the above referenced project, as described in the application, in that the Iflinois Environmental Protection Agency (Il1inois EPA) finds that the application fulfills all applicable requirements of 40 CFR 52.21. This approval is issued pursuant to the federal Clean Air AcE, as amended, 42 U.S.C. 7401 et. seq., the Federaf regulations promulgated thereunder at 40 CFR 52.21- fcr Prevention of Significant Deterioration of Air Quality (PSD), and a Delegation of Authority agreement between the UniEed States Environmental Protect.ion Agency and bhe lllinois EPA for Ehe administration of the PSD Program. This approval becomes effective in accordance with the provieions of 40 CFR 124.15 and may be appealed in accordance 'rith the provisions of 40 CFR L2q.t9. This approvaL is also based upon and subj ect. to the findi.ngs and conditions which follow:

If you have any questions on this perrnit, please contact Ja6on Schnepp at 2L7 /7A2-2LL3.

Edwin C. Bakowski, P.E. Date Issued: Acting Manager, Permit Section Divigi-on of Air PolluLion control

ECB:.JMS:psj

cc: Region 3 Lotus Notes cEs lLLrNorsENvrRoNueNrnr PnorrcrroN AcEwCy

1021 NoRrH CRANDAVENUI EAST, P.C). Box 19276, SpRrNcFLErD,ILLtN()ts 62794-9276 - \ 217) 7A2 3397 JAMrsR. THoMpsoNCENTER, 100 WEsrRANDOLPH, SurrE 1 1 -300, CrflcACO, ll, 60601 - (312) 814-6026

RoD R- BLACqEVTCH,CovERNoR DoucLAs P. Scorr, DTRECTOR

RocKFoRn- 4S02 North Main Street, Rockiord, lL6ll0l-{813)9A7776A . DrsPLANrr-95llW.HaffisonSL.,De!}.larnes,lL60016 1847)294-4000 EniN 595 SouthState, Elgin, lL60l2l (847)608 1131 . PEoRIA-5415N. UniverlitySt., Peoria, lL6l614 (309)691 5461 lll,R|AL,ofLAND-PtoRA-7620N. tlniversity St., Peoria, lL6l614 (109)6915462 . CH^MP^cN-2125south Fi|st Stre€r, Champaign, lL61820 (217)2785800 SpRncaEtD 4500 5. SlxthStreci Rd., Springfield, IL 627C6 {217)7A6-6892 . C{rLLNsvrLLE 2009 Mall Street,Collinsville, lL 62234- (618l34{'-5120 MARToN2309 W. Main St.,Suitc I I6, Marion,lL 62959 (618)991 7200

PR NrFD o! RF.Y.TED P^PER TABLE OF CONTENTS

Page

1.0 IJTST OF ABBREVIATIONS AND ACRONTMS COMMOIILYOSED 3

2.0 FIIIDINGS 4

3.0 OVERAIJIJ SOIIRCE CONDITIONS

Project Descript.ion Source-Wide Applicable Provisions and Regulations Source-Wide Non-Appl icabi lity of Regulations of Concern Source-W.ide Production and Emission Limitations Source-Wide Recordkeeping Requirements Source-Wide Reporting Requirements 10 AuthorlzaEi.on uo Operate 11

4.0 I'I[IT SPECIFIC COIIDITIONS trOR SPECIFIC E!figSIOtT I'NITS L2

4.! Loading Rack storage Tanks 18 z.a Components 26 Roadways 30

5 . O ATTACIIIIEII'TS

1 Project Emission Summary 1- l_ 2 NOx NetEing Analys.is CO Emission Summary SO, Netting Analysi s VOM Emission Summary 6 PM Netting Analysis 7 PMlo I'Tett ing Analys is PM2.s Necting Analysis 8-1 Summary of BACT/I,AER Determinations 10 Standard Permit Conditions 10-1 IJIST OF ABBRBVIATIONS A.ND ACRO}TSMS COIIMOI|IJY USED

BACT Be6t Available Control Technoloqv bbl Barrel CAAPP Clean Air Act Permit Proqram CEMS Continuous Emission Monitoring system CFR code of Federal Requlations Carbon Monoxide CORE Coker and Refinerv ExDansion Proiect Fahrenheit FCCU Fluidized Catal.ytic Cracking Unit HAP Hazardous Air Poflutant hr Hour IAC T1l inois AdministraEive Code I.D. No. IdentificaEion Nunber of source, assigned by Iflinois EPA f llino.is EPA Illinois Environmental Protection Aqencv Kg Kifogram I,AER Lowest Achievabfe Emission Rate llD Pound Mg Megagram MACT Maximum Achievabte ControL Technoloqy Mo MonEh m3 Cubic meters ms/r, Milfigrams per lJiter mnBtu Million British Thermal Units MMGaI Milli-on qallons MSSCAM Major stationary sources Construction and Modificatlon (35 IAC Part 203), aLso known as Nonattainmenl New Source Review (NA NSR) NESHAP Nat.iona1 Emission Standards for Hazardous Air PollutanLs NO* Nitrogen Oxides NSPS Ner^, Source Performance Standards PM Particulate Matter PMro Particul.ate matter with an aerodynamic diameter less than or equal to a nominal 10 microns as measured by applicable test or monitorinq methods pM^ _ Particulate matter with an aerodynamic dianeter Less than or equal to a nominal 2.5 microns as measured by applicable lest or moniEorinq methods ppm Parts per million psD Prevention of Sionificant DeterloraEion (40 CFR 52.21) psia Pound Der square inch absolute Sou Sulfur Dioxide USEPA United States Environmental Proiectsion Aqency vcu VaDor Combustion Unit voc Volatile orqanic comDounds ( eynonymous with voM) voM Vo1atile Orqanic Material Yr Year 2.O FINDTNGS

2.L a. ConocoPhillips has requested a permit for modifications to the ex.isting petroleum product terminal that are required to accommodate the Wood River Refinery's proposed CORE (Coker and Refinery Expansion) project. A separate construction permit application (Application Number 06050052) has been submitEed for the changes at Lhe refinery. A further description of the various chaages being made is provlded in each of the unit- gpecj.fic condit.ions of this permit (Section 4.0).

h The lltinois EPA is considering ConocoPhil tips ' s CORE project and the changes to the Wood River Products Terminal to comprise a single larger project for the purpose of PSD and NA NSR.

2.2 The petroleum product terminal is located in an area designated nonattainment for ozone and PM?.s. For purposes of regulating PM2.5, PMro will serve as a surrogate pollutant for PMr.s, consistent with current USEPA guidance.

This project and the net emissions increase for the project exceeds 40 tons per year of vol-ati1e organic material (vOM). The project is therefore subject to 35 IAC 203: Major stationary Sources construction and Modification (MSSCAM). (See Attachment 5b. )

This projecE has potential emissions increases which are more than 100 tons/year of carbon monoxide (co). The project is therefore subject to PSD revj-ew as a major modification for CO emissions. (See Attachment 3.)

After reviewing all materials submitted by conocoPhillipg, the Itlinois EPA has determined that the projects will comply with al1 applicable Board emissions standards and meet the l,or{,est Achievabl"e Emj-ssion Rate (LAER) as required by MSSCAMand Best Available coatrol Tectrnology (BACT) as required by the PSD rules.

h As some units aesocialed witsh this project which conLribute to a significant increase in emissioos do not undergo a physical change or change in the method of operation, these units are not subject to BACT or LAER. These units are further identified in Condition 3.3.1 (storage tanks with increase in utilization) .

aa In additlon to the emission units associated 'rith thie project not undergoing a physical change or change in the method of operation, there is no relaxation of any exi6Eing federally enforceable emission limitE as a result of this Droiect for said units.

The Illinoj-s EPA has broadly considered alternatives to this project, as required by 35 IAC 203.305. AlternaLive sites would not possess the necessary piping infrastructure, and alternatiwe sizes of equipment would not necessarily meet the consumer demands for gasoline suppty- Accordingty, the benefits of the proposed project significantly outwelgh its environmental and social cosLs,

Pursuant to 35 IAC 203.305, the Permittee has demonstrated that all major stationary sources \^rhich it owns or operates in lllinois are in compli.ance or on a schedule for compliance with all applicable state and federal air pollution controf requirements, as further identified in condition 3.2.5 of this permit-

2 .'1 A copy of the application and the Illinois EPA's review of the application and a draft of Lhis permiL was forwarded to a focation in the vicinity of the plant, and the public was given notice and opporLunity to examine this material, to submit comments, and to request and participate in a public hear.ing on lhis matLer. 3.0 OVER,A].I, SOI'RCE COIIDITIONS

3.1 Project Description

The modifications to the existing petroleum product terminal are required to accommodate the Wood River Refj.nery's proposed CORE (Coker arrd Refinery Expansion) project. The following are the key elements of the proposed modi fication:

One new gasoline tank,' Two nen ethanol tanks t Ttto new distillate tanks, Expans j.on of the existing truck loading rack;

The key elements discussed above and ocher changes made as part of this project are fufther addressed in unit-specific conditions (see section 4.1 through 4.4).

3.2 Source-Wide Appficable Provisions and RegulaLions

3.2.1 specific emission unitE at this source are subject to particular regulaEions as set forth in section 4 (Unit-Specific conditions for Specific Emj,ssion Units) of this permit.

In adatition, emission units aE this source are subject to the following reguLaEions of general applicability:

No person sha1l cause or allo\^r the emission of fugitive particutate matter from any process, including any material handling or storage activity, that is visible by an observer looking generatly overhead at a poin! beyond the property line of the source unless Ehe wind speed is greater than 40.2 kilometers per hour (25 miles per hour) , pursuant to 35 IAC 212.3O1 and 212.3I4.

b. Pursuant to 35 IAC 2L2-723 (a), no person shal1 cause or aLlow Ehe emission of smoke or other particulate matter, with an opacity greater than 30 percen!, j.nto Lhe atmosphere from any emissj.on unit other than those emission units subject to the requirements of 35 rAc 2a2.f22, except as allowed by 35 IAC 212.123 (b) and

3.2.3 Emiss.ions Offsets

a, The Permittee, either alone or coordinated rrrith ConocoPhillips' wood River Refinery, shall maintain 440.1 tons of voM enission offsets ge[erated by other sources in the st. l,ouis, Mi s sour.i /MeLro -East. fllinois nonattainment area such that Ehe total is 1-15 times the vOM emissions increase allowed for this project (i.e., 3?8 tons of offsets for the permibbed increase from the refinery, 328.7 Lo s/year, and 62.1 tons of offsets for lhe permitted increase from the terminal, .54.0 tons/year). b. .1 . This VoM emission reduction credit is provided by permanent. emission reductions that occurred at the folloL,ing 6ource, as identified be1ow. These emission reductions have been relied upon by the Illinois EpA to issue this permit and cannot be used as emission reduction credits for other purposes. The reductione aL bhe source identified below have been made enforceable by the withdrawal of the air pollution control permits for the units generating Ehe permanent em.isslon reductions.

COMPANY NAME, I. D. No. Permanent Shutdown of Facility 440 .1 tons/year VOM

ii. ft the Permittee proposes to rely upon emission offsets from another source, the PermiEtsee shall apply for and obtain a revision to this pernit priox to relying on such emission offsets, which appfication shall be accompanied by detailed documentation for the nature and amount of those alternative emission of fsets.

The acquisition of emission offsets sball be completed either 90 days afLer isguance of this Construction Permit or prior to commencement of construction of this project, whj.chever occurs fater, unless the Permittee requests an extension and it is approved by the lllj.nois EPA.

condition 3.2.3 represents the actions identified in conjunction with this project to enBure that the project is accompanied by emission offsets and does not interfere with reasonable further progress for VOM.

3.2.4 State Rules for Gasoline Distribul-ion

Gasofine loadout operations at this terminal are subject to 35 IAC 2L9 Subpart Y, which provides that:

No person shall cause or allow the transfer of gasoline into any delivery ves6e1 from any bulk gasoline terminal unless [35 IAC 219.582 (a) ] :

i The bulk gasoline terminal is equipped with a vapor controf system thal limits emission of voM to 80 mg/1 (0.0006? 1bs/9a1) of gasoline loaded;

ii. The vapor control system is operating and al1 vapors displaced in the loading of gasoline to the delivery vessel are vented onlv to the vapor control svstem;

ii-i. There is no liquid drainage from the loading device when it is not in uset !v. All loadilrg and vapor return lines are equipped with fittings which are vapor tighE; and

The delivery vessel displays the appropriate sticker pursuant to the requirementE ot 35 IAC 219.584(b) or (d) ; or, j-f the Eerminal j.s driwer-loaded, the terminal owner or operator shall be deemed to be in compliance with 35 IAC 2L9.582 when terminal access authorization is limited to those owners and/or operators of delivery vessels ltho have provided a current certification as required bv 35 IAC 21e. s84 (c) (3). la The operator of a bulk gasoline terminal shall [3s rAc 21e.582 (b) I :

f. Operate the terminal vapor collection system and gasoline loaaling equipment in a mannex that prevents:

cauge pressure from exceeding 18 inches of water and vacuum from exceeding 5 inches of vrater as measured as close as possible to the vapor hose connection; and

A reading equal to or greater than 100 percent of the lower expl-osive limit. (LEL meaBured art propane) when tested in accordance with the procedure described in EPA 450/2-?8-051 Appendix B, incorporated by reference in 35 IAc 2L9 .1,L2t aljd

Awoi.dable leaks of liquid during loading or unloading operations.

ii. Provide a pressure tap or equivalent on the terminal vapor collectiorr system in order to allow the determination of compliance with 35 rAc 2),9.5a2 (d) (1) (A) ; and

ii-i. !,lithin 15 business days after discovery of the leak by lhe owner, operator, or the Agency repair and retest a vapor collectj-on system which exceeds the limits of 3s IAc 219.s82 (c) (1) (A) or (B).

The Pexmittee shall comply \"rith the applicable gasotine deliwery vessel requirements and gasoline volatility slandards in 35 IAC 2I9.5A4 and 219.585, respectively- compliance Schedules

A11 alleged non-compliance (with applicable state and federal air poll-ution control requirements) posed by the major stationary sources in lllinois that are owned, operaEed, or under the same common control as the PermitLee are addressed in the Consent Decree that was filed on Januarv 2'1. 2005.

source-wide Non-Appl icabi I ity of Regulations of Concern

3.3.1 PSD/NAANSR

The Permitt.ee has addressed lhe appLicabi-lity and compliance of 40 CFR 52.21, PSD and 35 IAC Part 203, Major Stationary Sources Construction and Modification (MSSCAM). The limits established by th.is permit are intended to ensure Ehat the project addressed in this construction permit does not constitute a major modificatsj.on of tshe source pursuant to these rules for NO", PM, PMro, PMz.s, and SO2 emi-ssions (See also Atstachments 1 through 8).

.1. Thi6 permit is issued based upon an increase in voM emissionB from storage of addj.tional gasoline and distilLat.e as a conaequence of the coRE project of at mosE 5.7 tons/year (Refer to Condition a.2.6(a) (ii)).

3.3.2 NESI{AP

This permit is issued based on the terminal being operated by the distribution division of conocoPhillips Corporation, so that it j-s subject Eo the NESIAP fox casoline Distribution Facilities, 40 CFR 53 Subpart R (Refer to casoline Distribution Industry (Stage I) - Background Information for Promulgated SEandards, USEPA, Novehber L994, EPA-453/R-94-002b, PB 95- L70346, paqe 3-18).

Note: If the terminal were managed by the same perEonnel as the refinery, the terminal woufd be subject to the NESHAP for Refineries, 40 CFR 53 Subpart CC.

3.4 Source-Wide Production and Emission Limitations

None .

Plant -Wide Recordkeeping Requirements

3-5.1 Retention and Avail-ability of Records

a- AI1 records and logB required by this permit sha1l be retained for at least five years from the date of entry (unless a longer retention period is specj.fied by the particular recordkeeping provision herein) , sha1l be kept at a focation at Ehe source that is readily accessible to the IlLinois EPA or USEPA, and shall be made available for inspection and copying by the Illinois EPA or USEPA upon xequest.

b- The Permitt.ee shall retrieve and print, on paper during normal source office hours, anv records retained in an electronic format (e.9., computer) in response to an Illinois EPA or USEpA request for records during the course of a source inspection.

Records Associated With Non-Attainment Area Pollutants From Existing Units with Increase in Utilization

Storage Tanks

For the storage tanks for which ttre increase in utilization approach for determining the change in emissions is being used:

i. The increase in throughput at the terminal's maximun capacity from the COREproject (ga11ons/month).

lL Emissions of voM attributable to the increase in throughpuE (ton6/montsh and tons/year) .

3.6 Plant-Wide Reporting Requirements

3.5.1 Reporling and NotificaEions Associated with Performance Teats

The Illinois EPA shall be notified prior to these tests to enable the fllinois EPA to obserqe these tests. Notification of the expected date of testing shal1 be submitted a minimum of 30 days prior to Ehe expected date- Notificatiorr of the actual date and expected time of tesEing shal1 be submitted a minimum of 5 working days prior to the actual date of the test. The lllinois EPA may at its discreEion accept notifications with shorter advance notice provided that the lllinois EPA will no! accept auch notifications if it interferes with the Illinois EPA's ability to observe testing.

At least 60 days prior to the actual date of testing, a wri-tten test plan shall be submitted to the Illinois EPA for review. This plan sha11 describe the specj.fic procedures for testing, including as a minimum:

The person(s) who will be performing sampling and analvsis and their experience wiEh si-milar tests.

ii. The specific conditions under which testing will be performed, including a discussion of why theBe conditions wilL be representative of maximum emissions and the means by which the operating parametera for the emission unit and any control equipment will be determj.ned.

iii. The specific determinations of emissions and operation. wh.ich are intended to be made, including sampling and monitoring Locations -

10 iv. The test method(s) that will be used, with tbe specific analysis method, if the method can be used with different analvsis methods -

A-ny minor changes in standard methodology proposed to accommodate the specific circumstances of testing, with i us ti ficar ion -

Copies of the Final Reports (s) for these teBts shall be submitted to the Illinois EPA vrithin 30 days after the teat results are compiled and finalized. The Final Report. shall include as a mini.mum:

i. A summary of results.

ii. cenera.l- informaEior

iii. Description of test method(s), including degcription of sample points sampling train, analysis equipment, and test schedu.le.

iv. Detailed descripEion of test conditions, lncluding:

Process information.

B. concrol equipment informaLion.

v. Data and calculations, including copies of all raw data sheets, opacity observaeion records alrd records of laboratory analyses, sample calculations, and data on equipment calibration.

3 .'7 Authorizati-on to Opexate

rhe new/modified emisston units addressed by this construction permj.t may be operated under this permit until renewal of the CAAPP permit provided. the source submits a timely and complete CAAPP renewal application.

11 4.0 I'N-IT SPECIFIC COI{DITIONS FOR SPECIFIC EMISSION I'II-ITS

Loading Rack

411 nAarri 61- i ^n

The existing loading rack wiLl be ptrysically modified by adding loading bays/arms. The rack will continue to load petroleum products and warious gasoline feed stocks into trucks. A nehr loading rack control device (e.9.. vapor cornlcustion unit (VCU) ) will be insLalled Eo control voM emissions from the Loadinq rack -

4.t.2 l,.iBt of Emission Units and Air Potlution control Equipment

Em-isEaon Emission Control Unit Descriptj-on Eguipment Modified Loadinq Rack vcu*

or a similar control device capable of achieving an equj-valent 1eve1 of control ,

4.1,3 Appl-icable Provisions and Regulatiorrs

a. The "affecEed unit- for the purpose of these unit-specific conditions, is lhe loading rack described in conditions 4.1,1 and 4-1.2.

4.1.3-1 Applicable Federal Standards (40 CFR 63, Subpart R)

The affected unit is subject to 40 CFR 63, Subpart R: National Emi-ssion Standards for casoline Distribution Facilities (Bulk Gasoline Termj-na1s and Pipeline Breakout stations) , which provides that.

a. Each, owner or operator of loading racks at a bulk gasoline terminal subject to the prowisions of SubparE R shal1 comply with the requiremeDts in 40 CFR 60.502 except for 40 CFR 60.500(b) , (c) , and (j). For purposes of 40 cFR 63-422, the Eerm "affected facility" u6ed in 40 cFR 60.502 means Ehe loading racks Ehat load gasoline cargo tanka at the bulk gasoline terminals subject to the provisions of this subpart [40 CFR 63.a22(a\1.

l^ Emissions to the atmosphere from the vapor collection and processing Eystems due to the Loading of gasoline cargo tanks sha11 not exceed 10 milligrams of total organic compounds per liter of gasoline loaded [40 CFR 53.422(b)1.

Each owner or operator of a bulk gasoline terminal subject to the provisions of this subpart shall comply with 40 cFR 60 - s02 (e) as follows [40 CFR 63.a22 (cl I z

72 1. For the purposes of 40 CFR 60.502, the term "tank truck" as used in 40 CFR 50.502(e) means "cargo tank - ,,

ii- 40 cFR 60.502(e) (5) is changed to read: The terminal owner or operator shatt take steps assuring that the nonvapor-tight gasoline cargo tank wlll not be reloaded at the facility untj-l vapor tightness documentation for that gasoLine cargo tank is obtained which docunents that:

The tank truck or railcar gasoline cargo tank meets the test requirements in 40 CFR 53,425(e), or the raj.lcar gasoline cargo tank meets appLicable test requirements in 40 cFR 53 .42s (i) ;

B. For each gasoline cargo tank failing the test in 40 CFR 63.425(f) or (g) at the facility, the cargo tank either:

1. Before repair work is performed on the cargo tank. meets the test requirements in 40 cFR 63 .425 (g', or (h) ; or

After repair work is performed on the cargo tank before or during the tests in 40 CFR 63.425(g) or (h), subsequently passes the anrrual certification test described in 40 CFR 63.425(el .

4.1,.3-Z Applicable Federal Standards (40 cFR 60, Subpart Xx)

The affected unit is subject Eo 40 CFR 50, Subpart XX: standards of performance for Bulk casoline Terrninals.

Note: Pursuant to 40 CFR 63.a20(g) , each owner or operalor of a bulk gasoline terminal or pipeline breakout station subject to the provlsions of 40 CFR 63, SubparE R that js also subject to applicable provisions of 40 CFR part 60, Subpart XX sha1l comply only with the prowisions in each subparL that cantain the mosL etringent control requirements for that facility,

4.1-3-3 Applicable state Regulations (35 IAC ParE 219, Subpart B)

The affected unit is subject to 35 IAc 279.f22 (a), which provides that no person sha11 cause or allow lhe discharge of more than 3.6 kg/hour (8 lbs/hour) of otgarfic material jnto the atmosphere during the loading of any organic material from the aggregate loading pipes of any loading area having throughputs of greater than 151 cubic meters per day (40,000 gallons/day) into any railroad tank car, tank truck gr trailer unless such loading area ig equj-pped with submerged loading pipes or a device that is equallv effective in controllinq emi6sions and is approwed by the Agency according to the provisions of 35 IAc 201, and further processed cons.istent with 35 IAc 2l-9.108.

4.L.4 Non-Applicabi l ity of Regulations of concern

Non applicability of regulation of concern are not set fox the affected units .

Control Requirements and Work Practices

a. BACT Technology

The loading rack control device {e.9., vctt) sha11 be maintained and operated rrith good cornleustion pfactice to reduce eni-ssions of CO.

al IJAL I t;mlssaon llamat

Emissious of CO from the control system for the affected unit shalt not exceed 0.0835 1b/1,000 gallons of petroleum product loaded, during loading of material.

a- J,AER Technolog-y

The affected unit shall be controlled by Ehe loading rack control device (e-9., vCU). consistent wiEh the NESIIAP (40 CFR 53, Subpart R), which system shal1 be maintained and operated with good cornbustion practice to reduce emissions of voM.

The uncaptured emissions from the affected unit shaLl be minimized by compliance with the requirements of the NESHAP (40 cFR 63, Subpart R) addressing vapor tightness of cargo taflks and operation of vapor collectj.on systems.

lL I,AER Emission limit

EmiBsions of VOM fxom Ehe loading rack control device (e.9., vcu) ,expressed as Total organic compounds (Toc) shal1 not exceed '7.0 mg/L of gasoline loaded.

Condj.tion 4.L.5(a) repreeents the application of the Beet Available Control Technol.ogy. Condition 4.1.5(b) represents the application of the lJowest Achievable Emission Rate.

4.1.6 Production and Emissi-on Limitatione

a- Operation of the affected unit shall not exceed the following limits.

14 Throuqhput Material (callons/Month) (catlons/Year) Gasoline 51, 100, 000 306,600,000 Distillate 51,100, 000 .105,600,000

L Emissions from the affected unit atEributable to material cornlousted in the VCU shafl not exceed the followincr limits:

Emission Limit Increase' Pollutant (Tons/Month) (Tons/Year) (Tons ) co 4.3 25.6 23.8 NO" 1-.',7 10 .2 9.5 VOM (Captured) 72.A VOM ( Fuqitive) 20 .L

The increase in emissions is based upon a comparison of the actual emissions (average of 2oo4 and 2005) with the emission limits-

Compfiance ri'ith the annual limit sha.ll be determined from a rurrning total of 12 months of data.

4 .4 .'1 Testing and Inspection Requirements

The Permiltee shall comply with the appticable test methods and procedures in 40 cFR 53.425. In parcicufar, the owner or operator subject !o the emission Etandard in 40 CFR 53.422(b) Bha1l comply with the requirements in 40 cFR 53.42s(a) (1) and (2) [40 cFR 63.42s(a) ].

i. Conduct a performance test on the vapor processing and collection systems according to either 40 cFR 63.42s(a) (r) (i) or (ii).

A. Use the test methods and procedures in 40 CFR 50.503, except a reading of 500 ppm shall be used to determine the level of leaks Eo be repaired under 40 cFR 50.503(b); or

use alternative test methods and procedures in accordance with the albernative teBt method requirements in 40 CFR 63-'1 (f).

ii. The performance test requirements of 40 CFR 60.503(c) -- ^.res sv rrvL aPl,ry Lv "lra defined in 40 cFR 53.421 and meeting the flare requirements in 40 CFR 53-11 (b). The owner or operator shalf demonstrate that the flare and associated vapor collection system is in compliance with the requj.rements in 40 CFR 63.11(b) and 40 CFR 60.503(a), (b), and (d) , respectively- 4.1.8 Monitoring Requirements

a, The ori'ner or operator shall i.nstall, calibrate, certify, operate, and maintair, according !o the manufacturer's specj-fications, a continuous monitori[g sysEem (cMs) as specified in 40 cFR 63.427 (a) (1) , (a) (2) , (a) (3) , or (a) (4) , except as allowed in (a) (5) [40 cFR 63.42? (a) ] .

a, Where a carbon adsorption syslem is used, a conLinuous emissj.on monitoring system (CEMS) capable of measuring organic cornpound concentration shal-1 be insEalled in the exhausE air stream [40 CFR 63 . a2? (a) (1) I .

ii. where a refrigeration condenser system is used, a continuous parametser moniEoring Bystem (CPMS) capable of measuring temperalure shal1 be j-nstalled irnmediately downstream from the outlet to the condenser section. Alternatively, a CEMS capable of measuring organj-c compound concentration may be installed in the exhaust air stream [40 CFR 63.421 la) (2Jl .

iii. Where a thermal oxidation system other than a flare is used, a cpMS capable of meaauring temperature must be installed in the firebox or in the ductwork lmmediaLely downstream from the firebox in a position before any substantial heat exchange occurs [40 cFR 53.427 (a) (3) I .

iv. Where a flare meeting the requiremerrts in 40 CFR 53.11 (b) is used, a heat-sensing device, Euch as an ultraviolet beam sensor or a thermocouple, must be installed in proximity to the pilot 119hE to indicate the presence of a flame [40 CFR 53.427(a) (4)].

Monitoring an alternative operating parameter or a parameEer of a vapor processing system other than those listed il 63.427 (a) witl be allowed upon demonstrating to the USEPA's satisfaction that the alternative parameter demonstrates continuous compliance with the emission standard in 40 CFR 63.422(b, [40 CFR 63.427(a) (s)].

4.L.9 Recordkeeping Requirements

The Permittee 6ha11 comply with the applicable recordkeeping requirements of 40 cFR 63.428-

b. The Permit.tee €hal1 maintain recordE of the followinq rcemg:

1. Identification of each type of material loaded. aa. Amount of each material loaaled (gal.1ons/month and gallons/year) .

iii. Emissions from the affected unit (tons/month and tons/year) with supporting calculations and documentation.

4.1.10 Reporting Requirements

a. The Permittee shalt promptly notify the Illinois EPA of deviations of an affected unit with the permit requirement.s of Lhis section (Section 4,1) . Reporbs sha11 incfude information specified in Conditions 4.1.10(a) {i) and (ii).

.1 . Emissions from Ehe affected unit in excess of the limits specif.ied in condition 4.1.6 vrithin 30 days of such occurrence.

ii- operation of tshe affected unit in excess of the limit specified in Condition 4.1.6 within 30 days of such

b. The Permittee shall comply with the applicable reporting requirements specified in 40 CFR 63 -428.

77 4.2 Storage Tanks

4.2 .7 Descriptj.on

New tanks will be installed as part of this project as follows:

Two new ethanol tanke (Tanks 209 and 210). These tanks will have an internal floating roof. Two new dist.illate tanks (Tanks 2001 and 2002). These tanks will be a fixed roof design. A ne\^,gasoline tank (Tank 2003). This tank lrill have an internal floating roof .

Several ex.isting tanks will experience an increaae in utilization as a result of this project- These emissj-on increases are listed in SecEion 3.3-1 of this permit-

List of Emisgion units and Air Pollution control Equipment

Emission Emission control unl E Description Equipments Tank 209 New ethanol storage tank,' Internal 20,000 barrel capacity. Fl-oating Roof Tank 210 New eEhanol storage Eank,. Internal 20,000 barrel capacity Floating Roof Tank 2001 New distillate gtorage None tank; 200,000 barrel capacity; fixed roof. Tank 2002 New distillale storage None tank; 200,000 barrel capacity; fixed roof. Tank 2003 New gasollne storage tank; Internal 200,000 barrel capacity - Floating Roof

4.2.3 Arplicable Provisions and Regulations

a. An "affected tank" for Ehe purpose of Ehese unit-specific conditions. is a storage tank described in conditions 4.2.L arld 4.2.2.

4.2.3-I Applicabte Federal Standards (40 CFR 50, Subpart Kb)

The affected ethanol and gasoline tanks are subject to 40 cFR 60, subpart Kb: standards of Performance for Volatile organic Liquid storage Vessels (IncLuding Pecroleum Li.quid sLorage Vessels) for Which Construction, Reconstruction, or Mod.ification commenced after .fu1y 23, 19A4, which prowides bhat the affected ethanol and gasoline tanks sha1l be equipped with a fixed roof in cornloination with an internal floating roof meeting the following specifications :

The internal floaEing roof shaLl rest or float on the liquid surface (but no! necessarilv in compLete contact

18 with it) inside a storage vessel that has a fixed roof. The inLernal floating roof shall be floaling on the liquid surface at all times, except during initial fill and during those intervals when Ehe storage vessel is completely emptied or subsequenlly emptied and refilLed. When the roof is resting on the 1eg supports, the process of filling, emptying, or refilling shall be continuous and sha1l be accompliBhed as rapidly as possible [40 cFR 60 .112b (a) (1) (i) 1 . h The internal floating roof sha1l be equipped with the following closure device between the wall of the storage vessef and the edge of the ilrternal floating roof:

l. A foam-or liquid-filled seaf mounted in contact with the liquid ( liqu.id-mounted seal). A liquid-mounted seal means a foam-or liguid-filled seal mounted in conEac! with the tiquid between lhe wal1 of the storage vessel and the fl-oating roof continuously around the circumference of the tank [40 CFR 60.112b (a) (1) (ii) (A) 1 .

Each opening in a Doncontact internal floating roof except for automatic bleeder vents (vacuum breaker vents) and the rim space ventB .is to provide a projection befow the liquid surface [40 CFR 60.112b(a) (1) (iii)].

Each opening in tbe internal floating roof except for leg sleeves, automatic bleeder vents, rim space vents, column wells, ladder we116, sample we11s, and stub drains is to be equipped with a cower or 1id which is to be maintained in a closed position at alt times (i.e., no visible gap) except when the device is in actual use. The cover or lid 6ha11 be equipped with a gasket. Covers on each access hatch and automatic gauge float well shall be bolted except when they are in use [40 cFR 50.112b(a) (1) (iv) ].

Automatic bfeeder wenEs shall be equipped with a gasket and are to be closed at all times when the roof is fLoating except when the roof i.e being fl-oated off or is being landed on the roof leg supports [40 cFR 60 . 112b (a) (1) (v) I . f. Rim space vents 6ha1l be equipped \arith a gasket and are to be set to open only when the internal floating roof is not floating or at the manufactureris recommended setting [40 cFR 60.112b (a) (1) (vi) 1 .

Each penetration of the internal floating roof for the purpose of sampling shall be a sample we1l. The sample wel"l" shall have a slit fabric cover that covers at leasE 90 percent of the openinq 140 CFR 60.112b(a) (r) (vii)1.

19 h. Each peneLration of the internal floating roof that allows for passage of a colunn supporting the fixed roof shalL have a flexible fabric sleeve seal or a gasketed sliding cover [40 CFR 60.112b(a) (r) (wiii)].

Each penetration of the internal floating roof that allo'..'s for passage of a ladder sha11 have a gasketed sliding cover [40 cFR 60.112b(a) (r) (ix)].

Applicable Federal Standards (40 CFR 53, Subpart R)

The affected gasoLi-ne tank is subject to 40 CFR 53, Subpart R: NationaL Emission Standards for casoline Distribution Facilities (Eulk casoline Terminals and Pipeline Bxeakout SEat.ions), which provides that the affected gasoline atorage tank shalL be instatled according to the requirements in 40 CFR 60.112b(a) (1) , except for the requirements in 40 cFR 50.112b(a) (1) (iv) through (ix) [40 CFR 63.423(a) l.

4.2.3-3 Applicable State Re$rlations (Storage containers of vol,)

The affected ethanol Eanks are subjecE to 35 IAC 2!9.120t Control Requirements for Storage Containera of VOL, which provides that the affected ethanol tanks shall be equipped 'tith an iDternal float.ing roof that meets the fotlowing specifications:

The j-nternal floating roof shall rest or float on the Iiquid surface (but not necessarily in complete contact with it) inside a storage vegsel thaE ha6 a fixed roof. The internal floating roof shalt be floating on the liguid surface at all times, except during initial fill and during those intervals when the storage vessel is completely emptied and subsequently refilled. When the roof is reeting on the leg supports, the process of filting, emptying, or refilling shall be continuous and shalL be accomplished as rapidly as possible.

}\ Each internal floating roof shall be eguipped with the following cloBure device between the wall- of the storage vessel and the edge of the inEernal floating roof:

t". A foam- or liguid-fitled seal mounted in contact with the tiquid (liquid-mounted seal). A liquid-mounted seaf means a foam- or liquid-filled seal mounted in conEact wj-th the liquid between the wafl of the storage vessel and the floating roof coatinuously around the circumference of the tank.

Each opening in a noncontact internal floatj-ng roof except fox aut.omatic bleeder vents (vacuum breaker vents) and the rim space venta is to provide a projection belo!,l,' Ehe Liquid surface.

20 d. Each opening in the internal ffoating roof except for 1eg sleeves, automatic bleeder vents, rim space ventg, colurnn \^relIs, ladder wells, sample wells, and stub drains is to be equipped with a cover or lid whlch is to be maintained in a closed positj-on at all Eimes (i.e., no visible gap) except wheB the device is in actual use, The cover or fid sha1l be equipped with a gasket. Covers on each access hatch and automatic gauge float welL shafl be bolted exceDt when thev are in use.

Automatic bleeder vents shall be equipped \^rith a gasket and are to be closed at all times when the roof rs floating except when the roof is being floated off or is being landed on the roof leg supports,

f. Rim space vents sha1l be equipped with a gasket and are !o be set to open only when Ehe internal floating roof is not floating or at the manufacturer's recommended setting.

9. Each penetration of Ehe inlernal floating roof for the purpose of sampling shall be a sample we1L. The sample well shafl have a slit fabric cover that covers at least 90 percent of the opening.

h. Each penetration of the internal floating roof that allows for passage of a ladder sha1l have a gasketed sliding

4.2.3-4 Applicable State Regulations (Storage ContainerB of VPL)

The affected gasoline lank is subject to 35 IAC 2L9.7-ZLl storage Containers of VPL, which provides that:

a. The affected gasoline tank shal1 be designed and equipped with a floating roof which rests on the surface of the vPL and is equipped with a closure seal or seals between the roof edge and the tank wa1l , such floating roof shaLl not be permit.ted if the vPr, has a vapor pressure of 85.19 kPa (12.5 p6ia) or greater at 294.3oK (?0oF). No person shalf cause or al-Iow the emi-ssion of air contaminants into the atmosphere from any gauging or Bampling devices attached to such lanks, except during sampfi[g or maintenance operations [35 IAc 2L9-]-2r (b) (1] I .

4.2.3-5 Applicable State Regulations (l,oading Operatiore)

The affected tanks are subject to 35 IAC 2I9-L222 Loading Operations, which provides that:

The affected tanks shal1 be equipped with a permanent submerged loading pipe, submerged fi11, or an equivalent device approved by Lhe Illinois EPA according to the provisions of 35 r11- Adm. Code 201 [35 IAC 21-9-L22(h\J

2L b. Pursuant to 35 IAc 2L9.r22 (c) , if no odor nuisance exists the limitations of 35 IAC 2L9.a22 (b) shall only apply to the loading of volatile organic liquids with a vapor pressure of L7 -24 kPa (2-5 psia) or greater at 294-3oK {?00F) .

4.2.4 Non-Appl icabi l ity of Requlations of Concern

The affected distillate tanks are not subject to 40 CFR 60 subpart Kb, because the affected distillate tanks are storage vessels with a capacity greater than or equal to 151 m3 storing a liquid with a maximum true vapor presEure less rhan 3 - 5 kpa [40 cFR 50.110b (b) ] .

b. This permit is issued based on the affected distillate and gasoline tanks not being subject to 35 IAc 219.a2o pursuant to 219.119(e) becauee lhe affected tanks are only u6ed t,o store petroleum liquids.

1. This permit is issued based on the affected distillate tanks not being subject. to 35 lAC 21,9.f2I: Storage Containers of VPL, because the affected distillate tanks will not store a volatiLe petroleum liquid, i.e., the vapor pressure will be below 1.5 DSia.

ii. This permit is issued based on the affecEed ethanol tanks not being subject to 35 IAc 2I9.I21: Storage Containers of vPL, because the affected ethanol tanks will not store a volatile petroleum liquid as defined in 35 IAC 2LL.46L1 .

at. f. This permit is issued based on the affected distill-ate tanks not being subject to 35 IAc 21,9.L23: Petroleum Liquid storage Tanks, because the affected distillate tanks will nob store a volatile petroleum liguid, i.e., lhe vapor pressure will be below 1.5 psia.

ii This nermit is issued based on the affected ethanol and gasoline tanks not being subject to 35 IAC 2f9.'J-23: Petroleum Liquid Storage Tanks, because the affected tanks 209, 210, and 2003 are subject to 40 cFR 60 SubparE Kb [35 rAC 219.123 (a) (5) ] ,

controL Requirements and Work Practices

LAER Technology

t. Affected ethanol and gasoline Eanks shall be controlled by an internal floating roof with a primary liquid-mounted seal consistent with the conLrol requirements of the 40 CFR 50 Subpart Kb and 40 CFR 53 Subpart R and a secondary rim-mounted seal .

22 ii. The true vapor pressure of the material stored in the affected distitlate tanks shall not exceed 0.1 psia at the maximum storaqe temDerature.

condition 4.2.5(a) represents the application of the Lowest Achievable Emission rate.

4.2,6 Production and Ernission Limitations

a- a. Emissions and operation of the affected tanks shall not exeeed the following limits:

Throughput VOM Emissions 'lanl< (MMGal/Mo) (MMGal/Yr) (Tons/Yr) 209 & 210 30.7 0.1

ii. Breathing loss en.issions of the following affecLed ganks sha11 not exceed the followj.ng limits:

VOM Emissions 'I anK (Tons/Year) 2001 & 2002 2003 13.1

Note: The working losses from affected tanks 2001, 2002, and 2003 are addressed by Condition 3.3.1, which includes both new and existing gasoline and distillate slorage Eanks.

lr compliance \^'ith the annual limits shall be determined from a runninq totaf of 12 months of data.

Testing and Inspection Requirements

For the affected gasoline tank, the Permittee shall cornply with the applicable test methodE and procedures in 40 cFR 63 .425 .

b. The Permittee shall fulfil1 all applicable testing and procedures requirements of 40 CFR 60,113b(a) for the affected ethanol and gasoline tanks [40 CFR 50.f13b(a)]

a. If the owner or operator determines that it is unsafe to inspect the vessel to determine compliance wiEh 40 cFR 50.113b(a) because the roof appears to be structuralfy unsound and poses an imminent danger to inspecting personnel, the owner or operator shall comply with the requirements in either 40 CFR 53.120(b) (7) (i) or 40 cFR 53.120(b) (7) (ii) [40 cFR 63.640 (n) (8) (ii) I .

ii. If a failure is detected during the inspections required by 40 CFR 60.113b(a) (2), and the vessef

23 cannot be repaired within 45 days and the vessel cannot be emptied withi-n 45 days, the onner or operator may utilize up to two extensions of up to 30 additional calendar days each. The o\"rner or operator is not required to provjde a request for the extension tso tshe Administrator [40 CFR 53.640 (n) (8) (iii) I .

b. The Permittee shall fulfill all applicable monitoring of operacions requirements of 40 CFR 60.116b for the affected ethanol and gasoline tanks [40 CFR 60.116b].

4.2.4 Monitoring Requirements

Monitoring requirements are not set for ghe affected tanks.

4.2.9 Recordkeeping Requirement s

a. The Permittee shal1 maintain records of the folJ.owing tEems:

1. The type, characEerisEic and quanEiEy of each material stored in each affected tank, including the maxamum Erue vaDor pressure,

ii. Throughput (million gallons/month and milLion gallons/year).

iii. voM emiesions from each affected tank (tona/month and tons/year).

b. The Permittee shall fulfill all applicable recordkeeping requirements of 40 CFR 60.115b for the affected gasoline artd ethanol lank6 [40 cFR 50.11sb] .

The Permittee sha1l fu]fill al1 applicable recordkeeping requirements of 40 CFR 53.428 for the affected gasoline tank, which records shalf be kept for at least 5 years.

4,2.L0 Reporting Requirements

a. The Permittee sha11 promptly notify the Illirois EPA of deviations of an affected tank with the permit requirements of this sect.ion (Section 4.2). Reports shaLl include informat.ion specified in conditions a.2.10(a) (i) and (ii).

L. Emissions from Lhe affected tanks in excess of the limits specified in Condition 4.2.6 within 30 days of guch occurrence.

ii. Operation of the affected tanks in exceBe of the fimit specified in Conditiorr 4.2-6 within 30 days of 6uch occurrence.

24 The PermiLtee shall fu1fill a1I applicable reporting requirements specif-ied in 40 CFR 60.1L5b for the affected gasoline and ethanol- tanks [40 cFR 50.115b].

The Permittee shall futfill all appJ-icable reporting requirements of 40 cFR 63.428 for the affecEed gasoline tank . Components

nac ^? i nl- i ^n

New piping will be required to connect the new storage tanks and moditied loading rack. Leaks may occur from components such as valves? connectors, and seals.

4.3.2 l,ist of Emission Units and Air Pollution Control Equipment

Emis sion Emisslon Controf unit Descrr.pEion Equipment ComponenEs Components (Connectors, None Valves, Pump seals )

Applicable Provisions and Regulations

a. ArI "affected component" for the purpose of these unit- specific conditionE, is a new component installed as part of the Eerminal expansion as deecribed in conditions 4.3.1 and 4.3.2, and any subsequent replacemenE of such nera' component ,

Applicable Federal Standards (40 CFR 53, Sulpart R)

Certain affected components are subject Lo 40 CFR 63, SubparE R: National Emission Standards for Gasofine Distributi.on Facilities (Bulk Gasofine Terminals and Pipeline Breakout stations) , whi.ch provides that:

a. The Permittee shal-l perform a monthly feak inspection of all equipment. in gasoline service. For this inspection, detection methods incorporating sight, sound, and smell are acceptable. Each piece of equj.pmenE sha11 be inspected during the loading of a gasoline cargo taak [40 cFR 63.424 (a) I .

b. A 1og book sha1l be used and sha11 be signed by ttre owner or operator at the completion of each inspection. A section of the log shall contain a list, summary description, or diagram(s) showing the location of a1l equipment in gasoline service at the facility [40 CFR 63 .424 (b) I .

Each detection of a liquid or vapor leak shal1 be recorded in the 1og book. When a leak is detected, an initial attempt at repair shalt be made as soon as practicable, but no later than 5 calendar days afLer the leak i6 detected. Repair or replacemen! of teaking equipment shall be completed within 15 caleadar days after detection of each 1eak, excepL as provided in 40 CFR 63.424(d) [40 CFR 63.424 (c) I . d. Delay of repair of leaking equipnent will be allowed upon a demonstration to the USEPA that repair wiEhin 15 days is not feasible. The owner or operator shall provide the reason(s) a delay is needed and the date by which each repair is expected to be completed [40 cFR 63.424(d) I.

Initial compliance sha1l be achieved upon startup [40 CFR 63.424 (e) I .

f. As an afternaLive to compliance with the provisions in 40 CFR 63.424(a) through (d), o'rrners or operators may impfement an instr.ument leak monitoring program that has been demonsErated to the USEpA as at least equivalenE 140 cFR 63 .424 (f) I .

s. owners and operators shall not a11ow gasoline to be handled in a manner bhat would result in vapor re.Leases to lhe atmosphere for extended periods of time. Measures to be Eaken include, but are not limited to, the foflowing [40 cFR 63.424 (g) ] .

1. Minimize gasoline spills;

ii. clean up spills as expeditiously as practicablet

iii. cover all open gasoline conEainers wittt a gasketed seal when not in use;

iv. Minimize gasoline serlt to open wastse collection syslems that collecb and transport gasofine to reclamation and recycling dewices, auch a6 oil/water .separators.

4.3.3-2 Applicable State Regufations (35 IAC 219, Subpart C)

Pursuant to 35 IAC 219.142, no person shall cause or allow the discharge of more than 32.8 ml (2 cu in) of votatile organic Iiquid with vapor pressure of 11 .24 kPa (2.5 psia) or greater at 294.3oK (70oF) into the atmosphere from any pump or compressor in any 15 minute period at standard conditions.

4.3.4 Non-Applicabi lity of Regulations of concern

None .

Control Requiremetts and Work practices

a. IJAER Technology

a. Affected components shall comply with the general standards in 40 cFR 53.162 (40 CFR 63, Subpart H) for components in gas/vapor service, light liquid service and heavy liquid service, and the tollowing specific standards:

2'7 Affected pumps (Iight liqu.id service) sha1l comply with the sEandards for pumps in l-ight Iiquid eervice in 40 cFR 63.163-

B. Affected open-ended vafves or lines shall comply with the standards for open-ended valves or lines in 40 CFR 63.L67.

c. AffecEed valves (gas/vapor service and light Iiquid service) shall comply with the standards for vaLves in gas/vapor service and in light liquid service in 40 cFR 63.168-

D. Affected pumps, valves, and connectors in heawy liquid service, shall comply with Lhe standards for pumps, valvea, and connectors in heavy liquid service in 40 cFR 63.169-

ii- For affected components, the Permittee shall monitor the component to detect leaks by the method specified in 40 CFR 63.180(b), except Ehat a more stringent definition of a leak shall appLy, i.e., an instrument reading of 500 parts per million or greater from valwes in gas and light liquid service and an instrument reading of 2,000 ppm or greater fxom purry)s in light liquid service shal1 be considered a 1eak.

Condition 4.3.5(a) represents the application of the Loh'est Achievable Emission rate.

4.3.6 Production and Emission lJimitations

a. Emissions of VOM from the affected components and existing components at the terminal shall not exceed 2.5 tons per year (combined). This limit represents an increase of 0.2 tons VoM. Compliance with this limit shall be determined using publistteal USEPA methodology for determining VOM emissions from leaking components.

4.3.'7 Testing Requirements

The Permittee shall use the Test Methods and Procedures of 40 cFR 60.485.

Monitoring Requ.iremelrts

None .

Recordkeeping Requirements

a. The Permittee shafl maintain recordg consistent with the recordkeeping requirements of 40 CFR 60.4A6. b. The permittee shall maintain records of the followinq items for affected comDortents:

.1. Nunber of components by unit or l-ocation and t)T)e.

al-. Calculated voM emissions, including supporting calculations, attributable to these components (tons/year).

4.3.10 Reporting RequiremenEs

The Permittee shall pronptly noLify the Iflinois EpA of deviatsions of an affected component with the permit requiremenEs of Chis section (Section 4.3). Reports shall describe the probable cause of such deviations, and arry corrective actions or preventable measures taken. As the operation of affected components is addressed by reporting requirements under appLicable rules, thie requirement may be satisfied with the reporting required by such regulations.

h The Permittee shall submit reports consistenL with the Reporting requirements of 40 CFR 60.447. 4.4 Roadways

4.4.L nAc-ri h1- i ^n

The affected units for the purpose of these unit-specific conditions are roadways affected by the coRE project, which may be sources of fugitive particulate matter due to vehicle traffic or wind blown dust. These emissions are control.led by paving and implementation of work practices to prevents the generation and emissions of particulate matter.

4.4.2 List of Emission Units and Air Pollution control Equipment

Emission Control Emission Unil Descrrptaon Fftr i 6hahi Roadways Paved roads Pavement of Roadrravs

4,4.3 Applicable Provisioqs and Regulations

a. An "affected unit/ for the purpose of these unit-specifi conditions, are the units described in Conditions 4.4.1 and 4.4 .2 .

b. 1. The affecced uniEs are subjecE Eo 35 lAC 2L2.3OL, whi.ch provides that no person shall cause or a11ow the emission of fugitive particulate maEter from any process, including any material handl.ing or storage activity. that is wisible by an observer looking generally toward the zenith at a point beyond the property line of the source.

-t-a Not rr'ithstanding the above, pursuant to 35 IAC 2f2.3L4, the above limib sha1l nots apply when the wind speed is greater than 25 mi1e,/hour (40.2 km,/hour), as determined in accordance with the provj-sions of 35 lAC 2I2.3a4.

4.4.4 Non-Applicabi l ity of Regulations of concern

won-appl icabi l ity of regulations of concern are not set for the affected units.

4.4.5 Contxol Requirements and Work Practices

a. Good air pollution control practices shall be implemented to minirnize and significantly reduce nuisance dust from affected units associated with the coRE projecE. After conBtruction of hhe CORE project is complete, these practiceB shall provide for pavement on all regularly traveled roads.

30 Production and Emission Limitations

a. The emissions of fugitive dust from roadways shal1 noL exceed 10-7 tons/year of PM and 2-1 tons/year of PMro.

b- Compliance w.ith annuaf limits shal] be determined on a monthly basis from the sum of Ehe data for the current month plus the preceding 11 months (running 12 month total) .

4.4.7 Testing Requiremente

a. Silt Loading Measurements

l-. The Permittee shall conduct measurements of the silt loading on varj-ous affected roadway segmenEs, as followe:

A. sampling and analysis of the silt loading sha1l be conducted using the "Procedures for sampling Surface/Bulk DusE Loading," Appendix c.1 in Compilation of Air Pollutant Emission Factors, USEPA, AP-42- A series ot samples shal1 be taken to determine the average silt loading and addreBs the change in sj-lt loadings as related to the amount and nature of vehicle traffic.

ii. Measurements shall be performed by the following dates:

A. Measurements shall first be completed Do later than 30 days after the date that initial startup of the CoRE project is completed-

Measurements shall be repeated within 30 days irr the evenL of changes involving affected units that would acL to increase silt loading (so that dala that is representative of Ehe current circumstances of the affected units has not been collected), including changeE in the amount or tl4)e of traffic on affected units, and changes in the standard operating practices for affected units, such as application of salt or traction material" during cold weather.

Upon written request by the ll1inois EPA, the Permittee sha11 conduct measurements, as specified in the request, which shal1 be completed within 75 days of the fllinois EPA's request.

iii. The Permittee shall submit test plans, test notifications and test reporus for these measurements ag specified bv overall Source condition 3.6.1,

31 provided, however, that once a Eest plan has been accepted by the ]llinois EPA, a new tesl plan need not be submitted if the accepted plan will be followed or a new lest pla! is requested by the Iflinois EPA.

4.4.8 Monitoring Requirements

Monitoring requirements are not set for the affected unlts.

Recordkeeping Requirements

The Permittee shaLl maintain records of the followinq items for the affected units:

The Permittee shall mainEain records for each period of time when it reliea upon the exemption provided by 35 IAc 212-3L4 to not comply with 35 rAC 2L2.3O1, with supporting documentation for Ehe determination of wind Bpeed.

b. The Permittee shall keep records for the silt measurements conducted for affected units pursuant to condition 4.4.7(al , including records for the sampling and analysis activities and results.

The Permittee shalt maintain records for the PM emissions of the affected units to verify compliance with the limits in condition 4-4.6, based on bhe above recorda for the affected units, and appropriate USEPA emission eEtimation methodology and emission factors, with supporting calculations.

d. The Fermittee shall mainEain the following records rel-ated to emissions of fugi.tive particulate matter from affected units, As records of certain information are to be kept in a fi1e, the Permi.tEee shall review and update such information on a periodic baBia so that the file contains accurate information addresEinq the current circumstances of the source.

A file that contains information on the length and state of road segments at the plant and the characteri- stic s of the various calegories of vehicles present at the source as necessary !o determine emissions.

r.1 A file thaE conEains information for Ehe enission factors (1bs/vehicle mile traveled), based on methodology for estimating emissions published by USEPA, with supporting explanation and calculations.

iii. Records of Ehe estimated vehicle miles traveLed on each roadway segment (mi1es/month, by category of vehicle), with supporting documentalion and calculations. These records may be developed from the records for the amount of different materials handled at the source and informatior in a file that describes ho'r different materials are handled.

iv- Recorda for emissions, in tons/month, based on the emission factors and other informati.on contained in other required records, with supporting calculations.

4.4.10 Reporting Requirements

a- The Permittee shall promptly notify the lllinois EPA of deviations h'iEh permit requixements by affected units as follows. Report.s shatl deBcribe the probable cause of such deviations, any corrective actions taken, and preventive measures taken and be accompanied by the relewant records for Ehe incidentr

Notification within 30 days for any incident in which 35 IAC 212.301 mav have been violated.

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PSD Applicabj.lity - NO" Netting Analysis

Contemporaneous Time Period: iluly 2OO2 through October 2009

Table I - Projec! hiasiona Increaaea and Decrea8ea

Emission Change Proj ec t /Act ivity (Aor:s/'Iearl CORE Proj ect

Table II - Source-Wide Creditable Contercporateoua hiasio! IncreaEea

Pe rmi- t Emissions Increase Proj ect,/AcLivi!y Numbe r (Tons/Year) Norlh ProDertv Flare 06030049 6/ 2OO7 Low Sulfur casoline (SzU) 05050052 2/ 20O7 Ultra tow Sulfur Diesel 04050025 4 / 2006 157.8 HarLford fnteqration 03080006 4/ 20O4 Ti-er 2 01120044 1,a/2003 FCCU 1 Alterations (Boiter 1?) 03030059 9 / 2003 Total: 804.8

Table III - Source-Wlde Creditable Cortgerporaneous EmisBion Decreaaea

EmissionE Decrease Proj ect/Act ivity Date (TonB/Year) North Property cround Ffare Decornmissioned 7/ 2OO7 1.5 J(t ta Snucclown L2/ 2002 CR-3 2"" Reheat Heater (fuet switch) L1/ 2002 CR-3 1"" Reheat Heater (fuel Ewitch) ar/2002 7L3.7 CR-3 Charge Heater (fue1 switch) 1J./ 2O02 No. 2 Crude Unit. H-25 ao/ 2002 29.1 Isom UniE, H-33 (Hartford Integration) L0/ 2002 Isom Unit, H-32 (Hartford Integration) 1,O/ 2O02 10.8 LSR Hydrotreating, H-31 (Hartford Inteqration) 70/2002 Itydrogen Plant, H-30 (Hartford Inteqration) 70/ 2002 10.0 Alkylation Heater, H-19 (Hartford Inteqration) LO/ 2O02 20.4 Reroute/ El-imination of Flare Streams at Hartford 10/ 2002 71 .4 FCCU Shutdown at Hartford Lo/ 2OO2 320.0 Total :

Table IV - $eb his8iona Change

(Tons/Year) IncreaseB and Decreases Associated With proposed Modification Creditable Contemporaneous Emi s sion Increases 804-8 Creditabl e Contemporaneous Emission Decreases 24 .7 Attachment 2b

Non-attainment NSR Applicabilj.ty - NO, Netting Anatysis (8-hour Ozone)

Contemporaneous Time Period: May 2001 through October 2009

Table I - PlojecE BrisEions Irrcreaaea and Decreaaeg

Emission Change Pf,oj ect.,/Activity (Tons/Year) CORE Proj ect

Table If - gource-wide Creditsa.ble ConEeq)oraneouB EEisaion Itlcreaaea

Permit Emissions Increase Proj ect/Act ivity Nurnlcer Date (Tons/Year) North Property Flare 06030049 6/ 2007 L.2 Low Sulfur casoline (SZU) 0s050062 2/2O07 20 .6 Ultra IJow Sulfur Diesel 040s0025 4/2005 HarLford Integration 03080006 4 / 2004 Tier 2 01120 04 4 Lr/ 2003 99.2 FCCU 1 Afterations (Boiler 17) 03030069 9/ 2003 1.8 RAU Steam Reboiler 01050090 LO/ 20OA 24 .8 Total:

Table III - Source-wLde Creditable Colt€uDoraDeour hl,aalo! DecreaseE

Emissions Decrease Proj ectlActivity Date (Tons/Year) North Property cround Flare Decommissioned 7/ 2OO7 RFP Shutdown 72/2002 CR-3 2"' Reheat lleat.er (fuet switch) 11/2002 CR-3 16c ReheaE Heater (fuet switch) La/2002 CR-3 Charge Heater (fuel switch) Lr/2002 115.8 No. 2 Crude Unit, H-25 LO/ 2OO2 I6om Unit, H-33 (Hartford Integration) LO/2002 fsom Unit, H-32 (gartford Integration) L0/ 2002 10.8 LSR Hydrogreating, H-31 (HarEford Integration) ro/ 2002 1,.7 Hydrogen Plant, H-30 (Hartford InEeqration) ro/2o02 10.0 Alkylation HeaEer, H-19 (Eartford Integration) ao/2o02 20 ,4 Reroute/El iminat j-on of Flare Streams at Hartford ro/2002 FCCU Shutdo!,m aE Hartford L0/2O02 320.0 CR-1 2nd Inter-reactor Heater, H-3 (Fue1 Switch) 2 / 2002 32.L CR-1 1st lDter-reactor Heater, H-2 (Fuel Switch) 2 /2002 19.1 CR-l Feed Preheat, H-1 (Fuel Switch) 2 / 2002 RAU Deethanizer Heater Shutdovrn lo/2o01, Total: a22-9 TabLe Iv - Net hisEionE Clralfge

(Tons/Year) Increases and Decreases Associated With ProDosed Modification Creditable CoDternporaneous Emission fncreases 897.1 Creditable Contemporaneous Emission Decreases 422.9 -11.4 Attachment 3

PSD Applicability - cO Netting Anafysis

Contemporaneous Time Period: .fuly 2002 through ostober 2009

Iable I - Project EliEaiona Increaaea alld Decr€a8e8

Emission change Proj ect,/AcEivity (Tons/Year) CORE Proi ect 7 ,047 .4

Table II - Source-WLde CrediEable CoDt€str oraleoua hiaaioD Increaa€E

Permf t Emissions Increase Proj ect/Activity Number Date (Tons,/Year) North Property Flare 06030049 6 / 2007 Low Sulfur Gasoline (SZU) 05050062 2 / 2OO7 40.6 Ultra Low SuIfur Diesel 04050025 4/2006 Tier 2 07L20044 LL/20O3 70.7 FCCU 1 Alterations (Boiler 17) 03030069 9 / 2003 1.r 'tota t :

Table III - Source-wida CreditsabLe ContemporaneouB Eniseiofl DecreaEeg

Emi.ssrons Decrease Proj ect/Act ivity Date (Tons/Year) HTR-vF1-North 72/2009 L4 .7 gTR-VF1-South L2/ 2009 HTR-BEU-I{M1 Shutdown 12/ 200e HTR-BEU-III42 Shutdovn 1-2/ 2OOa 18.8 Boiler 15 Shutdown L2/ 2008 '? North ProperEy cround Flaxe Decommissioned / 2oo7 7.9 HTR - KHT 4 / 2006 l(F P ljnLltctowrl 72/ 2002 No. 2 Crude Unit, H-25 ro/ 2oo2 Isom Unit, H-33 (Hartford Inteqration) r0 / 2002 0.6 'J-O Isom Unit, H-32 (Hartford Inteqration) / 2002 2.7 IJSR Hydrotreatinq, H-31 (Hartford Intesration) 1,0/ 2002 0.4 Hydrogen pfant, H-30 (Hartford Integration) 10 / 2002 Alkylation Heater, H-19 (Hartford Inteqration) lo / 2oo2 FCCU Shutdown ac Hartford 70/ 2002 TotaL: 2AA.4

Table IV - tilets hiBaiona Chatrge

(Tons/Year) IncreaEes and Decreases Associated With ProDosed Modification 1-, O47 .4 Creditable ConternporaneouB Emission Increases 2Lt .4 Creditable Contemporaneous Emission Decreases 2AA.4 910 .4

3-1 AEtachment 4

PSD Applicabitity - SO, Net.ting Analysis

Conternporaneous Time Period: July 2002 through October 2009

Table f - Projec! hisaions IncreaEeE and Decr€asea

Emissi.on Change Proj ect/Activity ( r'ons/ Year l CORE Proj ect -9,583.1

?abI€ ff - Source-wlde Cradllable CoaEeDporaDeous biggion Increaa€E

PErm.l t Emissions Increase Proj ect /Act ivi ty Numlcer (Tons/Year) North Property Flare 06030049 6/200'l 0-1 Low Sulfur Gasoline (SZU) 05050052 2 / 2001 Ultra Lov, Sulfur Diesel 04050026 4/2006 101-4 Hartford Integration 03080006 4 / 2004 17.3 Tier 2 01120044 IL/2O03 FCCU 1 Alterations (Boiler 17) 03030059 9/2003 0.1 'I OCa1 : 179.4

Table III - Sourc€-wide Credltab]'e CoDE€dDoraneouE hLssion DecreeBe€

Emissions Decrease Proj ect/Activity (Tons/Year) HTR-VF1-North 72/ 2OO9 0.1 HTR-VF1-South a2/ 2009 0.1 HrR-BEU-HM1 Shutdokrn L2/ 2OO8 1.0 HTR-BEU-HM2 Shutdo\^,r 12/ 2OOA o .'l Boiler 16 Shutdoern L2/ 2008 North Propertsy cround Flare Decommiseioned 7/2007 }IIR - KHT 4/ 2O06 7.2 CR-3 2no Reheats Hear.er (fue1 switch) aI/ 2002 339.0 CR-3 1" Reheat Hearer (fuel swiEch) 11/ 2002 CR-3 Charqe Heater (fuel swiLch) 1r/2O02 No. 2 Crude Unit. H-25 1O/ 2O02 0.8 Isom Unit, H-33 (Hartford fnteqration) 1o/ 2002 0.1 Isom Unit. H-32 (Hartford Integration) r0/ 2oo2 0.3 Hydrogen P1ant, H-30 (Hartford Integration) ro / 2002 0.3 A]kylat.i.on Heater, H-19 (Hartford Inteqration) 70/2O02 FCCU Shutdown at Hartford LO/ 2002 Total:

Table IV - Net hisaioEs change

(?ons/Year) lncreaees and Decreases Associated with proposed Modification Creditable Contemporaneous Emission lncreases 479.4 Creditable Contemporaneous Emiesion Decreases -11,137.3

4-7 Attachment 5

Non-atEainment NSR Applicability - VOM Netting Analysls (8-hour Ozone)

Contemporaneous Time Period: May 2001 through October 2009

Table I - Project hiasl-orE llrcrearea and D6creaEes

Emission Change Proj ecti/Act.ivity ( r'ons/ Yea4 CORE Proj ect

Tabl6 II - gource-Wide CrodiLable Conterrtrroraneour EmiEEion Incr€ag€s

Permit Emissions Increaae Proj ect/Act.ivity Nufilcer Date (Tons/Year) '1 Tank A-39-l- 05100052 / 200'7 Tank A-49-1 05100052 1 / 2008 Tank CH-243 05100051 6 / 200'7 North Property Flare 05030049 6/ 2oO'? Loh, Sul fur Gasoline (SZU) 05050062 3/ 2001 UlEra Low Sulfur Diesel 04050026 4 /2iO6 30.7 Tanks 32-1 and 33-1 05090047 3 / 2006 Tank 403 (Terminal) 05050044 9/ 2OO5 9.6 Tarrk A-19-1 03020012 5/ 200s 'ta Hartford Inteqration 03080005 4/ 2OO4 Tank A- 157 03020012 a/ 2004 8.4 Tank D-9-1 02050051 r / 2oo4 o.4 Tier 2 0Lr20044 1,1,/ 20 03 FCCU 1 Alterations (Boiler 17) 03030059 9/ zo03 0.1 Sludge Processing Unit o LJ-20042 3/ 2O02 RAU Steam Reboiler 01060090 ao/ 200L 0.9 'lol]a L:

Tab1e III - Source-wide Credltable CortEeqporaneous Emissiolr Decr€aaes

EmisBions Decrea6e Proj ect/Act ivity Date (TonE/Year) Tank D- 50 Demo 2006-09 Tank F- 12 Demo 2005-09 1-4.6 Tank F-35 Demo 2006-09 VF-1 Fuqitives 72 / 2009 HTR-VF1-North 12 / 2OO9 1.0 HTR-VF1- South 12 / 2009 1.1 HTR-BEU-HM1 Shutdown 1-2/ 200A 7.7 HTR-BEU-HM2 Shutdo'rn 72/ 2008 Boiler 15 Shutdown 12/ 2OOA 5.3 Tank A- 49 9/2008 Tank A-39 9 / 2007 0.3 North Property Ground Flare Decommissioned 7/ 2OO7 HTR _ KHT 4 / 2006 Gasoline T'ank Replacement 3/ 2006

5-1 Emissions Decrease Proj ect /Activity Date (Tons/Year) Tank A-4 Demo 7/ 20O5 0.2 Tank F- 10 Demo r/ 2oo6 Tank A-19 Demo 5/ 20Os Tank A-9 Demo L/2004 0.4 'I anK A- /Z !arewaEer 12l2OO3 'J-2 RFP Shutdorrn / 2OO2 0.1 Tank 10-21 70/ 2O02 casoline Storage Tanks (35-1, 35-2) ro / 2002 6.3 No- 2 Crude Unit, H-25 ro/ 2002 lsom Unit, H-32 (Hartford Integration) LO/ 2O02 Hydrogen Plant, g-30 (Hartford fneeqration) Lo/ 2002 o.2 Alkylation Heater, H-19 (Hartford lrtegration) L0/ 2O02 0.4 Rerout e /El imination of Flare Streams at Hartford 10/ 2O02 FCCU Shutdown at Hartford 1-O/ 2002 4A.4 RAU Deethanizer Heat.er Shutdown r0/ zooL Total : 115.5

Table IV - Net, hieaions Chatge

(Tons/Year) Increases and Decreases Aasociated With proposed Modification 3A2.7 Creditable ContemF,oraneous Emission Increases Creditable ContemDoraneous Emission Decreases 409.8 At.tachment 5

PSD Applicability - PM Netting Analys.ls

Contemporaneous Time Period: July 2002 Lhrough October 2009

Table I - EroJecE hisaions Increasea ard Docrea8es

Emission Change Proj ect/Activi ty (Tons/Year ) CORE Proj ect

Table II - Source-Wide Creditable cortearDorareouE EmiEgion Increasea

Permit Emissions Increase Proj ect/Activity Nunber Date (Tons/Year) Low Sulfur casoline (SZU) 05050062 2/ 2OO7 10.9 Ultra Low Sulfur Diesel 04050025 4 /2006 'l Ler z 01120044 rLl2o03 FCCU 1 Alterations (Boiler 1?) 03030069 9/2003 0.1 Total:

TabI€ III - source-WLde Creditable Conts€$Doraneoua hiaaiou DecreaEea

Emissions Decrease Proj ect/Act ivi ty (Tons/Year) HTR-VF1-North L2/ 2009 HTR-VF1-South 72/ 2009 I{TR-BEU-HM1 Shutdown 12/ 200a 2.4 FIR-BEU-HM2 Shutdown L2/ 2OOA 11 Boiler 15 Shutdown !2 / 2008 }ITR- KHT 4/2006 2.9 RFP Shutdown !2/ 2002 CR-3 2"" Reheat Heater (fuel sh,ifch) LL/2002 11. I CR-3 1" Reheat Heater (fuel switch) 77/2002 )1 1 CR-3 Charge Iteater (fuel srritch 1L/2002 No. 2 Crude Unit, H-25 L0/ 2OO2 Isom Unit, H-33 (Hartford Inteqration) 70/ 2002 0.1 fsom UniE, H-32 (Hartford Integration) 1,0/ 2002 o.2 IJSR Hydrotreatinq, H-31 (Hartford Inteqratj.on) to / 2002 Hydrogen Plant., H-30 (Hartford InEegration) 10 / 2002 o.2 Alkylation Heater, I{-19 (HarLford tnteqration) 10120 02 0.4 FCCU Shutdown at. Hart.ford ro / 2002 Total : 396.0

Table Iv - Net &liBaions change

(Tons,/Year) Increases and Decreases Associated With Proposed Modification L9'7.9 CreditabLe ConternDoraneous Emission Increases Creditable Contemporaneous Emission Decreases 396.0 -139-5 Attachment 7

PSD ApplicabiliEy - PM10Netting Aralysis

Contsmper-3nsqus Time Period: .tuly 2002 through October 2009

Table I - Projec! EDiEeionE Increa3eE ala DecreaseE

Emission Change Pro j ect.,/Act ivity (Tons/Year) CORE Proj ect 95 .4

Table II - Source-Wide Creditable Conle!trIroraaeoug hiEgion Increaaes

Permit Emissions Increase Proj ect /Activity Nudber Date (Tons/Year) l,ow Sulfur Gasoline (SZU) 05050062 2/ 2OO1 10.9 UlEra Lolt SuIfur Diesel 04050026 4 / 2006 'I aer z 01720044 L1-/2OO3 FCCU 1 Al-terat.ions (Boiler 17) 03030069 9/2003 0.1 Total,:

Table III - Source-Wide Creditable Conte,nlroraneous hiBgion DecreaEes

Emissions Decrease Proj ect,/Activity Date (Tons/year) HTR-VF1-North L2/2OO9 HTR-VF1-South L2/ 2009 HTR-BEU-HML Shutdown t2/2OO8 HTR-BEU-HM2 Shutdown a2/ 2008 11 BoiIeT L6 Shutdown a2/ 2008 7.4 I{TR - ICIT 4/2006 2.9 RFP Shutdown 72 / 2002 0.2 ').'t CR-3 2"" Reheat l{eater (fuel svritch) / 2002 8.0 CR-3 1" Reheat Heater (fuel- swiEch) 1r/2O02 CR-3 Charge Heater (fuel switch) 7L/2002 No. 2 Crude Unit. H-25 lo /2002 Isom Unlt, H-33 (Hartford Integration) LOt2002 0.1 Isom Unit, H-32 (Hartford Inteqration) LO/2002 0.2 Hydrogen Plant, H-30 (Hartford Integration) LO/ 2002 Alkylation Heater, H-19 (Harlford Inteqration) LO/ 2OO2 0.4 FCCU Shutdown at' Hartford ao/ 2002 381.2

Table IV - NeE &daEiora Change

(TOnS/ Year) fncreases and Decreases Associated With proDosed Modification 95 .4 Creditable Contemporaneous Emission lncreases Creditable Co4temporaneous Emission Decreases 38L.2 -22'1.2 Attachment I

Non-AEtainment Area NSR Applicability - PMr.s" Netting Analysis

Contemporaneous Time Period: May 2001 through October 2009

Table I - Proj€ct hl,EElona IncreaEeE and Decreaaea

Emisslon change Proj ect/Activity UUI(E PrO] ECE

Tsble II - Sourqe-wide creditabl€ Colrteoporarreous hi8sioD IDcr€aa€E

Permit Emissions Increaee Proj ect/Activity Nunlcer Date (tons/Year) Low Sulfur eaeoline (SZU) 05050052 3 l2OO1 10.9 Ullra Lo\r Sulfur Diesel 04050026 4 / 2006 Tier 2 01120044 L1,/20O3 5.4 FCCU 1 Alterations (Boiler 17) 03030059 9/2003 0.1 Total :

Table III - Source-wida CredLtable Cont@poraneoug Emlsaion DecreaaeE

Emissions Decreage Proj ect/AcEivity Date (Tons/Year) HTR-VF1-North 1,2/ 2009 HTR-VF1-South L2/ 2OO9 HTR-BEU-HMI Shutdown 12/ 2008 HTR-BEU-I{I{2 ShuEdov,n 12 / 2OO8 Boiler 15 Shutdown 12/ 2008 7.4 HTR - IC{T 4/2006 RFP Shutdown 1,2/ 2002 o.2 CR-3 2"" Reheat Heater (fuel swiEch) r!/2002 8.0 cR-3 1" Reheat Heater (fuel switch) 1,L/2OO2 CR-3 Charge Heater (fue1 svritch) a\/ 2002 No. 2 Crude Unit. H-25 L0/2002 0.6 Isom Unit, H-33 (Hartford Int.egration) ro/ 2oo2 0.1 fsom Unit, H-32 (Hartford Inteqration) \o/2002 o -2 Hydroger PlanE, H-30 (Hartford IntegraEion) to/2oo2 o.2 Alkylat.ion Heater, H-19 (Hartford rnteqration) ro / 2002 o.4 FCCU Shutdown aE Hartford LO/ 2OO2 CR-1 2nd Inter-reactor Healer, H-3 (Fuel Siritch) 2 / 2002 3.0 CR-l 1st Inter-reactor Heater, H-2 (Fuel Switch) 2/2002 CR-1 Feed Preheat, H-1 (FueL Switch) 2/ 2OO2 5.5 RAU Deethanizer Heater Shutdown 10/ 2001 Totaf: Tabl-e Iv - Ilet HrlsEions Change

(Tons /Yearl Increases and Decreases Associated With Proposed Modiflcation 95.4 Creditable Contemporaneous Emission Increases 58.6 Creditable ConlemporaneouB Emission Decreases 398.6 -244 .6

Emissions of PM2.5in this table are expressed as emissions of PMlo, which is being used as a surrogate pollutant (see condition 2.2) -

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(, d o & rd .u H or q) }J d (o rt o ! OJ (u o 3q (rd o |f 2V ATTACSMaNT 10: STAI|DARD PERMIT COI{DITIONS

STANDARD CONDITIONS FOR CONSTRUCTION/DEVELOPMENI PERMITS ISSUED BY THE ILLINOIS ENVIRONMENTAI, PROTECTION AGENCY

The lll-inois Environmental Protection Act (Illinois Revised Slalutes, Chapter 111,-L/2, SecLion 1039) authorizes the Enwironmental Proteclion Aqencv to impose condiEions on permi"ts, which it igsues.

The following conditions are applicable uDless superseded by special condition(s). l- Unless this permit has been extended or it has been voided by a newly issued permit, this permit witl expire one year from Ehe date of issuance, unless a continuous program of construction or development on this project has sEarted by such t.ime.

The consEructi-on or development covered by thi6 permit shall be done in compliance with applicable provisions of the lllinois EnvironmenEal Protection Act and Regulations adopEed by the lllinois Pollution Control Board.

There shall be no deviations from the approved plans and gpecifj.cations unless a written request for modification, along with plans and specifications as required, shall have been submitted to the Illinois EPA and a supplementaf written permit i6sued.

The Permittee shal1 a1low any duly authorized agents of the lllinois EPA upon the presentation of credentials, at reasonable times:

To enter the Permittee's property where actual or potential effluenE, emiasj-on or noiBe sources are located or where any activity is to be conducted pursuant to Ehis permit,

h To have access to and to copy any records required to be kept under the terms and conditions of this permi!,

To inspect, including during any hours of operation of equipmenE constructed or operated under this permit, such equipment and any equipment required to be kept, used, operated, calibrated and maintained under Ehis permit,

d. To obt.ain and remove samples of any diachargte or emissions of polfuEanEs, and

?o enter and utilize any photographic, recording, testing, monitoring or other equipment for the purpose of preserving, testing, monitoring, or recording any activity, diBcharge, or emission authorized by this permit.

10-1 5. The issuance of this permit:

Shall not be considered as in any manner affecting the ti.tle of the premises upon whlch the permiEted facilities are to be located,

b. Does not release the Permittee from any liability for damage Eo person or property caueed by or resulting from the construction, maj-nlenance, or operation of the proposed facilities-

Does not release the Permittee from compliance with other applicable statuEe6 and regulations of the United States, of lhe State of rlfinois, or with appl.icabLe local 1aws, ordinances and regulations.

d. Does not take into consideration or atEest Eo the structural stability ot any uaits or parts of the prcoject, and

In no manner implies or suggests that the lllinois EPA (or its officers, agents or employees) asEumes any liability, directly or indi"rectly, for any los6 due to damage, installation, maintenance, or operation of the proposed equipment or facility.

6a. Ual-ess a joint cons truction/operation permit has been igsued, a permit for operation shall be obtained from the Tllinois EPA before the equipment covered by this permit is placed into operation.

For purposes of shakedown and testing, unlese otherwise Bpecified by a speciaf permit conditj-on, lhe equipmenE covered under this permit may be operaEed for a period not to exceed thirty (30) days.

7. The lllinois EPA may file a complaint with Ehe Board for nodification, suspension or revocatlon of a permit.

Upon discovery that the permit application contained mi srepresentations, misinformation or false statement or that all relewant facts were not disclosed, or

b. Upon finding that any sEandard or special condiEions have been violaied, or

Upon any violationB of the Enwironmental Protection Act or. any regulation effectiwe thereunder as a result of Ehe conslructsion or development authorized by this pemit.

ao-2 217 / 7 A2 -21-73

CONSTRUCTION PERMIT _ NESHAP SOURCE _ NSPS SOURCE _ PSD APPROVAI,

PERMlTTEE

ConocoPhillip3 waod River Refinery Attn: David W. Dunn 900 South Centraf Avenue Roxana, Illinois 620A4

Application No.: 06050052 I.D. No.: 119090AAA Appli-cant's Designation: WRR-87 Date Received: May 15, 2006 Subject: coker and Refinery Expansion (CORE) Project DaLe lssued: July 19, 2007 Location: 900 Soufh Central Avenue, Roxana

This Permit is hereby granted to the above- designaled Permittee to CONSTRUCT emission source(s) and/or air pollution control equipmenE consisting of the CORE project, that is, various changes to the refinery to increase both the total crude processing and the percentage of heavier crude at the refinery, as described in the above - ref erenced application. This Perrnit is subject to standard condiEions attached hereto and the following special condition(s):

In conjunction with this permit, approval is given rr'ith respect to the federal regulations for Prevention of Significant Deterioration of Air Quality (pSD) for the above referenced project, as described in Ehe application, in thaE the ]llinois Environmental Proteceion Agency (Illj.nois EPA) find6 that the application fulfills all applicable requirements of 40 CFR 52.21. This approval is j.ssued pursuant to the federal clean Air Act, as amended, 42 U.S.C- 7401 et. seq.. the Federal regulations promulgaeed thereunder at 40 cFR 52.2! for Prevention of Significant Deterioration of Air Quality (PsD), and a Delegation of Authority agreemert belween the United States Environmental Protection Agency and the lllinois EPA for the administration of the PSD Program. This approval becomes effective ln accordance with the prowisions of 40 CFR 124,15 and may be appealed in accordance with the prowisions of 40 CFR L24.L9. This approval is also based upon and subject to the findings and condilions which fol"low:

If you have any questions on this permit, please corrtact ,fason Schrepp at 21-7/782-2713.

Edwin C. Bakowski, P. E. Date I s sued: Acting Manager, Permit Section Division of Air Pollution ControL

ECB: JMS : psj cc: Region 3 TJotus Notes lrrrNorsENvraoNurNrnl PRorrcroN AcrNcv

1021 NoRrHCRAND AVENUE EAsr, P-O. Box 19276, SpRrNCr,|LLD,lLLrNors 62794-9276 | 217) 782-3397 JAMESR. THoMpsoN CEN TER, 100Wrsr RANr)or.pH,SurfF l1-300, CHrcACo,1160601 (3'12)814-6026 RoD R. BLACOtEvrcH,Covrr

RocKFoRD-4302North Main Street, Rockford, Jl 61103 (815)987-7760. DEsPLATNES 9511W.Harrison5t.,f)esPlaines, ll 60016 (647)2944000 ELcrN- 595 SouthState, Elgjn, lL 6012:l 1847)608 31ll . Pr.)Rr^. 5415 N. LJniversiiySt., Peoria, lL 6l6l4 (309)693-5463 BLRt\r-oF L^\D - PEoRTA7620 N. UnivcrsitySt., P€$ria, lL61614 (309)693-5462 . CHAMPATGN2l25 SouthFirst Srreet, ahampaign, lL61820-i2171278-5800 SpRrN.iFlrLl).1500 5. SjxthStreet Rd., Springfield , lL 62706 1117)786,6892 . CoLLTNSVLLE2009lvlallSLreei, CDllinsville, I162234 (618)1465120 M^RroN 2309W.MairSt.,Suite116,Mnrion, 1162959 (6lB)9917200

PR|NrLu uN RLCTLLLL' PAPIR TABI,E OF CONTENTS

Page

1.0 I.IST OF ABBREVIAfIONS AND ACROIIYT{S COUMO$IJY USAD

2.O FINDINGS

3.0 OVERAI,I, SOI'RCE CONDITIONS 7

Project Descript.ion 7 Source-Wide Appli.cable Provisiona and Regulations 7 3.3 Source-Wide Non-Applicability of Regulations of Concern 10 Source-Wi-de ProductioD and Emission Limitations 10 Source-wide Recordkeeping Requirements 3.6 Source-wide Reportj-ng Requirements 14 3.7 Authorization to Operate

4.0 I'NIT SPECIFIC COISDITIONS IIOR SPECIFIC EMISSION I'NITS

4.1 Process HeaEers 4.2 Distilling west (DW) Cracked Gas plant 23 4.3 Components 2'7 4.4 Storage Tanks 4.5 Catalytic Cracking Unita 40 4.6 Cooling Water Towers 4 .'7 Flares 55 4.8 Sulfur Recovery Units 7L 4.9 Miscelfaneous pM Emission Units 4.10 Wastewater Treatment. Plant '18 4.11 Roadways and Other Open Areas 81

5 . O ATTACIIME!{TS

1 Project Emission Surnmary ) NOx Netting Analysis 3 CO Emission summary SO, Netting Analysis 4-l- 5 VOM Emission Summary 6 PM Netting Analysis 7 PMlo NeEting Analysis '7-l PM2-s Netting Analysis 9 Summary of BACT/!,AER Determinations 10 Standard Permit CondiEions 1.0 I,IST OF ABBREVIATIOITS AIID ACROIIYMS COMI.'ONEYI'SED

AP'4 2 Compilation of Air Poflutant Emission Factors, Volume 1, stationary Point and Other sources (and Supplementss A through F), usEPA, office of Air ouality Planning and standards. Research Trianqle Park, Nc 277r'L BACT Best Available ConErol Technolocry bbl Barrel CAAPP clean Air Act Permit Proqram CEMS continuous Emission Monitorinq System CFR Code of Federal Requlations co Carbon Monoxide CORE coker and Refinery Expansion Project dscm Drv standard cubic meters ds cf Dry standard cubic feet F Fahrerlheit FCCU Fluidized Catalytic Cracking Unlt Grains H,S Hydrosen sulf i-de HAP Ilazardous Air PolluEant HHV Higher Heating Value hr Hour Illinois Administrative Code LD. No. Identification Number of Source, assigned by Illinois EPA lLCS rllinois Compiled Statutes lllinois EPA fllinois Environmental Protection Agency Kg Ki logram Kilopa6cal I,AER Lowest Achievable Emission Rate Lb Pound mg Mi ll iqram Mg Megagram MACT Maximum Achievable Control'fechnoloqy M,f/ scm MeqaiouleB per standard cubic MeEer Mo Month ml Cubic meters mmBtu Million British Thermal units MMGaI Million qaflons MSSCAM Major stationary sources construction and Modification (35 IAC Part 203), also known as Nonatstainment New source Review (NA NSR) NESI{AP National Emission standards for Hazardous Air Pollutants No" Nitrogen oxides NSPS Ne\^, Source Performance standards o, Oxygen PM Particulate Matter PMro Particul"ate matter with an aerodynamic diameter less than or equal to a nominal 10 microns as measured by applicable test ox monitorinq methods Particufate matter vrith an aerodynamic diameaer less than or equal to a nominal 2.5 microns as measured by applicable test or monitoring meEhods ppm Parts per mil lion PSD Prevention of Siqnificant Deterioration (40 cFR 52.21) Pound per scruare inch absolute scf Standard Cubic Feet Selective CatalyEic Reduction Soz Sulfur Dioxide SSMP Startup, Shutdown, Malfuncgion Plan USEPA United States Environmentaf Protection Aqency voc Volatile Organic Compounds ( strnonymous r/rith VOM) voM Volatile Organic Material wGs Wet Gas Scrubber IT Year 2.0 FINDINGS

a. conocoPhillj-ps has requested a permit for various changes to the refinery to increase both the total crude processlng and the percentage of heavier crude at the refinery. The name selected by conocoPhillips for thi6 project is the coker and Refinery Expansion (coRE) projecE. A further description of the various changes being made is provided in each of the uniE- specific conditi.ons of this permit (Section 4.0).

b. In order to handle the increased product throughput, conocoPhillips is also proposing certain chaDges at the Wood River Products Terminal (also owned by ConocoPhillips) . A construcE.ion perm.iu application (ApplicaEion Number 06110049) has been submitted for these changes. The Illinois EPA is considering conocoPhi 11ips ' s CORE projecL and the changes to the wood River Products Terminal to comprise a single larger project for the purpose of PSD/NA NSR.

2.2 The wood River Refj-nery is located in an area designated nonattainment for ozone and PM2.5. For purposes of regulating PM?-5, PMlo wifl serve as a surrogate pollutant for PM2.5, consistent with current USEPA guidance -

a. This project and the net em.issions increase for Ehe source exceeds 40 tons per year of volatiLe organic material (voM), The project is therefore subject to 35 IAc 203: Major StaLionary sources Construction and Modification (MSSCAM). (See AtEachment. 5.)

b. This project has potential emissions increases which are more than 100 Eons/year of carbon monoxide (Co) . The project is therefore subject to PsD review as a major modification for co emissions. (see Attachment 3. )

a. After reviewing all maEerials submitted by ConocoPhillips, the Illinois EPA has determined that the projegt will comply with all applicable Board emissions standards and meet the Lowest Achievable Emission Rate (LAER) as required by MSSCAMand Bests Available control Technology (BACT) as required by the PSD rules.

b. i. As eome units associated with th.is project vrhich contribute to a signj.ficant increase in emissions do not undergo a physical change or change in the mebhod of operaLion, these units are not subject Co BACT or LAER. These units are further identified in condition 3-3 (storage tanks with increase j-n utilization) and condition 3.4 (debottlenecked heaters and cooling water tohTers) of this Permit.

ii. In addit.ion Eo the emission units associated with this project not undergoing a physical change or change in the method of operation, there is no relaxaEion of any existing federalty enforceable emission limits as a result of lhis Droiect for sa.id unif,s-

The Illinois EPA has broadly considered alternatives to this project, as required by 35 IAC 203.305. Much of the equipment requiring LAER is existing equipment on site which has been idle. Alternative sites would not possess the necessary piping infrastructure, and allernaEive sizes of equipment would not necessarily meet ghe consumer demands for gasoli-ne supply. Accordingly, the benefits of the proposed project significantty outweigh its environmental and social costs.

Pursuant to 35 lAC 203.305, the Permittee has demonstrated that alf major stationary sources !r,'hich it ownn or operates in lflinois are in compliance or on a schedule for compLiance wilh all applicable state and federal air pollution control- requirements, as further idengified in Condition 3.2-5 of this permit.

2.7 A copy of the application and the Illinois EPA's review of the applicatsi,on and a draft of this permit was forwarded to a location in the vicinity of the plant., and the pu.blic vras given notice and opportunity to examirre this maEerial, to submit comments, and to request and participate in a public hearing on this matter. 3.0 OVERAI,I, SOI'RCE CONDITIONS

3.1 Proiec! Description

The coRE project enta.ils various changes tso the refinery to increase both the total crude processing and tshe percentage of heavier crude at lhe refinery. The following axe the key elements of the coRE projecE:

New delayed coking unit and associated coker units to converts vacuum resj-due to clean products and conversion feeds which will enable the processing of higher vofumes of heavy crudei Metallurgical upgrades and other equipment revisions of Distilling Unit 1 (DU-1) and the addition of a new vacuum Flasher (VF5) to handfe the high acid, high sulfur heavy crudes; Restart the idled Disbilling unit 2 Lube Crude (DU-2 LC) column to provide additional crude unit processing capacity; Metallurgi-cal upgrades and other equipment revisions of Fluid Catalytic cracking Unit 1 (FCCU 1) and Fluid Catalytic Cracking Unit 2 (Fccu 2) to handle hhe higher acid charge and change in the unit yield6. and installat.ion of new wet gas scrubbers (WGs) and selectiwe catalytic reduction (scR) systems on the flue gas fram these unils; Restart the Distilling West (formerly premcor) catalytic cracking unit (Fccu 3) and associated equipment (acquired as part of the Hartford Integration project) to allow for the processing of the additional gas oil (note thaE FCCU 3 will be permitted as a new uniE) ,. New hydrogen pIant,. Restart of Lube Vacuum Fractionation Column as a Hydrocracker Po6t - Fractionator (HCF) ; Restart of catalytic Feed Hydrotreater as an Ultra Low Sulfur Diesel Hydrotreater (Ul,D-2) ; Additional Bulfur processing capacity; Additsional amine treating and sour water stripping; Modifications Lo the wastewater treatment plani.

The key efements discussed above and other changes made to the refinery as part of this project are further addressed in uniE-specific conditions (see Section 4.1 through 4.11). In addition, as explained in Finding 2.a(b\, this permit also accounts for the emissions increases related to the CORE Project occurring at the Wood River Wood River Products Terminal (IDr 119o50AAN), as addressed by construction Permit 05110049.

3.2 Source-Wide ADDlicable Provisions and Requlations

specific emission units at thj-s source are subject to particular regulations as set forth in section 4 (uniE-Specific conditions for specific Emi6sion units) of this permit. 3.2.2 In addition, emission uniEs at this source are subject !o Ehe following regulations of general applicability:

a. No person shall cause or allow the emission of fugitive particulate matter frorn any proces6, including any material handling or storage activity, that is visible by an observer looking generally overhead at a point beyond the property fine of the source unless the wind speed is greater than 40,2 kilometers per hour (25 miles per hour), pursuant Eo 35 IAC 2L2.3O1 and 212.314.

b. Pursuant to 35 IAC 212.a23 (a) , no person shall cause or alLow the emission of smoke or other particulaEe matter, wiEh an opacity greater than 30 percent. into the atmosphere from any emission unit othex than those emission units subject to the requirements of 35 IAC 212.1,22, except as allowed by 35 IAC 2L2.a23 (b) and

No owner or operator of a petroleum refinery shall cause or allow a refinery process unj-E turnaround excepE j.n cornpliance with an operating procedure as approved by the Agency [3s rAc 219.444(at).

3.2.3 Emissions OffseEs

The Permittee, either alone or coordinated vrith ConocoPhillips' Wood Riwer Products Terminal, shal1 maintain 440.1 tons of voM emission offsets generated by other sources in the St. Louis. Mis Biouri/Metro-East, Illinois nonattainment area such that the total is 1.15 times the voM emissions increase allowed for this project (i.e., 378 tons of offsets for the permitted increase from the refinery, 128-7 torrs/year, and 62.1 tons of offsets for the permitted increase from the terminal, 54.0 tons/year) .

h This vOM emission reduction credit is provided by permanent emission reductions that occurred at the follovring source, as identified below. These emission reducEions have been relied upon by the Illinois EPA to issue this permit and cannot be used ag emission reduction credits for other purposes- The reductions at the source identified below have been made enforceable by the rrithdrawal of the air pollution control permits for the units generating the Dermanent emission reductions.

lTWAluminum, St- Louis, M.issouri Reduction in VOM Emissions 440.1 tons/vear VOM

ii- If the Perrnittee proposes to rely upon emissj.oa offsets from another source, the Permittee shall apply for and obtain a revision to this permit prior to relying on such emission offsets, which application shall be accompanied by detailed documentation for the nature and amount of those alternative emission of fsets.

The acquisition of emission offsets shall be completed ej-ther 90 days after issuance of this Construclion Permit or prior to commencement of construction of the CoRE Project, whichever occurs later, unless the Permittee requests an extension and i! is approved by the Illi-noj.s EPA.

condition 3.2.3 represents the actions identified in conjunction with t.his project to ensure that the project is accompanied by emission offseta and does not interfere with reasonable further progress for vOM.

Incorporation of Consent Decree Limits

The Permittee is subject to cextai[ requirements in the Consent Decree United states of America and the staEes of lllinois, Louisiana and New irersey, commonwealth of Pennsylvania and the Northwest clean Aj-r Agency v. ConocoPhillips company; civil Action No. I{-05-0258, entered by the District court for the Southern District of Texas on ,January 27, 2OO5 (Consent Decree) .

Pursuant to Paragraph 123 of the Consent Decree, the Permittee shall either eliminate, control, and/or include and monitor as part of a Covered SRP'S emissions under 40 cFR 60.104(a) (2), all sulfur pit emissions. "ConErof" for purposes of th.is Paragraph includes routing sulfur pit emissions into a contactor box of a Beavon Stretford TGU b. Pursuant Eo Paragraph 113 of the Corrsent Decree, Section G.: "so2 Emission Reductions from and NsPs Applicability to Heaters and Boilers", as of .fanuary !, 2006, all heaters and boilers (except Distilling west) are affected facilities, as that term is used in the NSPS, 40 CFR Part 60, and are subject to and sha1l comply with the requirements of the NSPS Subparts A and .T for fuel gas cornbustion devices.

Compliance Schedules

A11 alleged non-compliance (with applicable state and federaL aj-r poLlution control requirements) posed by the major stationary sources in Illinois that are ouned, operated, or under the same common control as the Permittee are addressed in the Consent Decree. Source-Wide Non-Appf icabif ity of Regulations of Concern

3.3.1 PSD/NAANSR

The Permittee has addressed the applicability and compliance of 40 CFR 52-21, PSD and 35 IAC Part 203, Major Stationary Sources construction and Modification (MsscAM), The limits established by thj.s permit are intended bo ersure that the project addresBed in uhis construcEion permit does not constitute a major modification of the refinery pursuant to these rules for NOx, PM, PMlo, PM2.5, and SO, emissione (See also Attachments 1 through 8),

a. This permit is ieeued based upon an increase in voM emissions from storage of additional materials, including crude oi1 and product as a consequence of the COREproject of at most 97.9 tons/year (Refer to condition a. a .6 (a) (ii) ).

3.3.2 NaEional Emission Slandards For Hazardous Air Poll-utants

a. The existing affected heaters are considered existing large gaseous fuel unit; therefore, the existing affected heaters are subject to only the initial notification requirements in 40 CFR 63.9(b) (i.e., they are noE subject to the emission fimits, work practice standards, performance testj-ng, monitoring, SSMP, site-specific monitsorj-ng p1ans, recordkeeping and reporting requirements of subpart DDDDD or any other requirementa in 40 cFR Parl 63, Subpart A) .

Source-wi.de Pxoduction and Emission Limitations

3 .4.1 Debottlenecked Heaters

a. The maximum design firing rate of the following existing heaters, which will be ..debottlenecked,, (i.e., experience an increased firing rate as a result of the CORE project) shaLl not exceed the followinq:

Fir j-ng Rate* (mmBtu/hr) DU-z Lube Crude Heater, F-200 I'IJD2 H-1 Process Heater 32 ttut HeaEer cq 1 HDU-2 Charge Heat.er 81 CR-2 North Heater 137.5 CR-2 South Heater CR-3 Charge Heater, H-4 420 CR-3 1" Reheat Heater, H-5 (combined CR-3 2"" Reheat Heater. H-5 limit )

12-month rolling average, HIfV

10 b. Emissions from Ehe followinq heaters shal1 not exceed lhe following limits:

NO" PM' n voM Heater (Ton/Yr) (Ton/Yr) (Ton/Yr) DU-2 F-200 181.6 4.9 ULD2 H_1 6.8 1-0 0.8 HCF Heater 2.1 HDU-2 Chg Htr 34 .I 1.9 CR-2 N- Htr CR-2 S. Htr 165.3 4.5 3.2 cR-3 H-4 439.1 73.7 cR-3 H-5 (cornbined (cornbined (combined linir) limit ) limit)

compliance with annual limits shall be determined on a monthly basis from the Bum of the data for the current month plus the preceding 11 months (running 12 month total) .

3.4.2 Debottlenecked Cooling Water Towers

a. i, The total capacity of existing cooling water towers cWT-3 and cWT-15, which will be debottfenecked {i.e., experience an increase j-n water circulation rate as a result of the CORE project) expressed .in term6 of design circulation rate, shall not exceed 35,000 gallons per minute (12-month rolling averate) .

ii. The totaf dissolved solids content of water ciriulating in the affected units shall not exceed 3,000 ppm on a monthly average basis and 2,000 ppm, on an annual average basis.

b. Emissions from the deboEtlenecked cooling itater bowers shall not exceed the following limits. Compliance with lhe annual limits shall be deEermined from a running total of 12 months of data:

PM,nEmissions VOM Emissions unac (Tons/Mo) (Tons/Yr) (Ton6/Mo) {Tons /Yr) ct4T- 3 0.89 7.L 0.01 0.1 cwT-15 0.26 0.01 0-1

Debottfenecked Flares

a. Emissions from the following existing flares, whi-ch will be debottlenecked (i.e., experience an increase in gas fLow to the flare) shal1 not exceed the following limltss. compliance with the annuaL limits shal1 be determined from a rrrnnino t^fal ^f 12 months of daUa.

1I Emissions ('fons//Year) Emission Unit NO* voM WWTPvOC Flare #1 5.0 !{WTP VOC Flare #2

Note: debottlenecked units are the unils that have not been modified but experience an increase in their effective capacity due to the removal of capacity Iimitations on an associated unit.

Plant-Wide Recordkeeping Requirements

3.5.1 Retention and Availabilitv of Records

A1l records and logs required by this permiE shall be reEained for at least five years from the date of entry (unfess a longer retention period iB specified by tbe parti-cular recordkeeping prowision herein), shall be kept at a location at the source that is readily accessible to the Illinois EPA or usEPA, and shall be made available for inspection and copying by the lllinois EPA or USEPA upon requesc.

b. The Permit.tee shall retrieve and print, on paper during normal" source office hours, any records retained in an electronic format (e.g-, computer) in response to an Illinois EPA or USEpA request for records during the course of a source insDection.

3.5.2 Records Associated With PSD PolluEants From Existing Units

a. Before beginning actual construction of the project, the Permittee sha1l document and maintain a record of the follorring informati-on [40 cFR 52.2L(rl (e) (i)l ,

i. A description of the project;

ii. Identification of the emi.ssi"ons unit(s) whose emj-ssions of a regulated PSD pollutant could be af fect.ed by the projecti and

iii. A description of the applicability test used to determine that the project is not a major modificaiion for any regulated PSD pollutan!, including the baseline actuaf emissions, the projected actual emissions, the amount of emi6sions excluded under 40 cFR s2.21(b) (41) (ii) (c) and an explanation for why such amount was excluded, and any nettiag calculations, if applicable.

b. The Permittee shall keep records for the emisaions of any regulated PSD pollutant bhat could increage as a result of the project and that is emitted by any emissions unit identified in 40 cFR 52.2'J-(r, (6) (i) (b) (see a16o condition 3.5.2(a) (ii)) and calculate and maintain a record of the annual emissions, in tons per year on a caLendar year basis, for a period of 5 years followlng resumption of regular operations after tshe change, or for a period of 10 years following resumption of regular operations afEer the change if the project increases the design capacity of or potential to emit that regulated PSD pollut.ant aE such emissi-ons unit [40 cFR s2.21-lr) (6) (iii)].

Records Associated With Non-Attainment Area Pollutantg From ExisEinq units with Increase in Utilization

Storage Tanks

For lhe storage tanks for which the increase .in utilization approach for determining the change in emissions is being used:

i. The increage in throughput at the refinery's maximurn capacity from the CORE project (gallons/monbtl).

ii. Emiseions of VOM attribuf,able to the increase in throughput (tons/month and toas/year).

3.5.4 Records Associated With Non-Attainment Area PolluEants From Debottfenecked Units

Boilers/Heaters

i. A fife sho\aring documentation of the maximum rated firing rate of each heater (mmBtu/hr, HHV).

ii. A file showing bhe potential NOv vOM. and PMlo emissions from each heater with supporting calculations and documentation (tons/vear) .

b. Coollng Water Towers

.a. cooling water capacity of each cooling water Eower, expressed in terms of design circulation rate (gallons/ninute ) -

ii. Emissions of voM and PMro from each cooling water Eower (tons/nonth and tons/year).

Flares

l-. A file showing the potential No" and voM emissions from each flare with supporting calculations and documentation (tons/year) . 3.6 Plant-wide Reporting Requirements

3.6.L Records Asgociated With PSD PolluLants From Ex.isting Units

a. The Permittee shall submit a report to the lllinois EpA and UsEpA if the annual emissions, in tons per year, from the project identified i! 40 CFR 52.27(Tl (5) (i) (See also Condition 3 .5 ,2 (a) ) , exceed the baseline actual emissions (as documented and maintained pursuant to 40 cFR 52'2r(r) (e) (i) (c) , by a significant amounE (as defined in 40 CFR 52.21(b) (23) for that regulated PsD pollutant, and if such emissions differ from the preconstruction projection as documented and maintained pursuant to 40 CFR 52.21(r) (6) (i) (c) . such report shall be submiEted Eo the Illinois EPA and USEPA within 60 days after the end of such year. The report sha11 contain the following [40 cFR 52.21(r) (5) (v)l:

i. The name, address and telephone number of the major sEationary source i

ii. The annual emi ss ions as calculaled pursuant to 40 cFR s2.21,(Tl (5) (iii) ; and

iii. Any other information that the Permittee wisheB to include i-n the reporE (e-g-, an explanation as to why the emissions di ffer f rom Ehe preconstruclion hr^.i 6^F i -- \

3.6.2 Reporting and Notj-fications Associated with Performance Tests

a. The Illinois EPA sha11 be notified prior to these testa to enable Ehe lllinois EPA to observe these tests. Notification of the expected date of tesEing shall be submitted a minimum of 30 days prior to the expected date. Notification of the actual date and expected. time of testirg shall be submilted a minimum of 5 working days prior to the actuaf date of the test. The lllinois EPA may at its discretj-on accept notifications with shorter advance notj,ce provided that the lllinois EPA will not accept such notifications if it interferes with the fllinois EPA's ability to observe testing.

L At leasE 60 days prior to the actual date of testing, a written test plan shall be submiEted to the rllinoiE EPA for review. This plan shal1 describe ttle specific procedures for testing, including as a minimum:

1. the person(s) who wilL be performing sampling and analvsis and their experience with similar tests.

ii. The specific condiLions under whj-ch testing will be performed, including a discussion of why these conditions will be representative of maximum

14 emissions during normal operation and the means by which the operating parameters for the emission unit and any controf equipment vri1l be detemined.

iii. The specific determinations of emissions and operaLion, which are intended to be made, including sampling and moniboring locations.

iv. The test method(s) that will be used, with the specific analysis method, if Lhe method can be used with different analvsis methods.

Any minor changes in standard methodology proposed to accommodate the speciflc circumstances of lesting, with j ustification.

Copies of the Final Reports(s) for these tests shall be submitted to the Illinois EPA within 30 days after the test results are compiled and finalized. The Final Report ehall include as a minimum:

l. A sumrnarv of results

ii. ceneral informat ior

iii. Description of lest method(s), including description of sanple points, sampling train, analysis equipment, and test schedule.

iv. Detailed description of test conditions, including:

A. Process informagion, e.g-, Fccu feed rate and sulfur content, air blower rate, cat.alyst rervale r:fF end -oke burn-off rate,

control equipment information, e.9., equipment condition and operating parameters during testing, including pressure drop across lhe wet gas scrubber and the liquid gas ra!e6 of the scrubber (the ratio of the scrubbant flow in 9a11ons to the flue gas flow in standard cubic feet, hourly average).

v. Data and calculations, including copies of all raw data sheets, opacity observation records and records of laboratory analyses, sample calcuLatiolB, and data on equipment calibration.

3.7 Au!hor! 3e! ren__! e_ ep_grgl9

The new/modified emission units addressed by this construction permit. may be operated under this permit untif renewal of the CIAAPPpermi! provided the source submits a timely and complete CAAPP renewal applicatj-on. 4.0 I'NIT SPECIPIC CONDITIONS POR SPECIFIC EMISSION UNITS

4.1 Process Heaters

4-1.1 Description

Proces6 heaters will provide heat to various refinery operations - The heaters will burn gaseous fuel, i.e., refinery fuel gas, natural gas, or process off-gas sLreams. The new heaters will be equippeat with ullra 1ow NO" burners.

several exj.sting boilerg and heaters wilI be debottlenecked, i.e., the uni.us have not been physically nodified but experience an increase in their effective capacity due Eo the removal of capacity limilations on an associaled unit, as a resuLt of this project. These emission increases are accounted for in Section 3 of this permit. One treater, fhe Al-ky tlM-2 process heater nill be altered by deratinq the maximum firing rate of this furnace to 99 mrnBtu/hr. Ultra-1ow NO* burners will also be insEalled on this modified heater.

List of Emission Units and Air Poltution Control Esuipment

Emission Emission Control Unit Descriptron Equipment VF5 H35 OH4 New vacuum Flasher Process Ultra Low NO* Healer (400 mr8tu/hr) * Burners DCUz H351H1 New Delayed Coker Unit No. 2 Ultxa Low NOx Process Heater (330 Burners mmBtu/hr) * DCU2 n351H2 New Delayed Coker Unit No. 2 Ultra Low NO. Process Heater (330 Burners mmBtu/trr) * DCNH H-1 New Coker Naphtha Ultra Low NO* Hydrotrealer No. 2 Procese Burnera Heater (20 mmBtu/hr) + vr,Dz H-2 Nev, Ultra Low Sulfur Diesel U1tra Low NOx No. 2 Process Heater (55 Burners mrnBtu/hr) * Alky HM-2 Modif ied Alkylacion uniE Ultra I,ow NO" Process Heater (99 Burners mmetu/hr) *; this heater is being derated; ultra low Nox burnerg will be installed BEU H3 New Benzene Extraction Unit Ultra T,ow NO* Process Eeater (250 Burners mmBtu/hr) * HP2 II.1 New Hydrogen Plant No. 2 Ultra Low NO* Process Heater (1.275 Burners mmttu/hr) *

Firing rates 1i6ted are lz-monEh rolling awerage, Ln lerms of lttfv 4.1.3 Applicable Provisions and Regulations

a- An "affected heater" for the purpose of these unit- specific conditions, is a heater described in Conditions 4.1.1 and 4.1.2-

lr The affected heaters are subject to the NSPS for PetroLeum Refineries, 40 CFR 60 Subparts A and J. The Permittee shal1 comply with all applicable requlrements of 40 cFR Part 60 Subpartg A and J-

i. The Permittee shall not burn in Lhe affected heaters any fuel gas that contains hydrogen sulfide (Ers) in excess of 230 mg,/dscm (0.10 gr/decf) [40 CFR 50.104 (a) (1) I .

Note: Pursuaat to 40 CFR 60.105(a) (3) (ii) , the monitoring level for SO, in the exhaust from a heater that is equivalent. to the 230 mg/d6cn H2S fuel limit is 20 ppm SO2 (dry basis, zero percent excess air).

The affected heaters are subject to National Emission Standards for llazardous Air pollutants For Industrial-, commerciaf, and Institutional Boilers and Process l{eat.ers, 40 CFR 63, Subpart DDDDD. The Permittee shalf comply with aI1 applicable requirements of 40 CFR part 63 Subpart DDDDD.

.1 , Pursuant to 40 CFR 63.7500(a) (1) and 63.7505(a), Co emissions from the new affected heaters shall not exceed 400 ppm by volume on a dry basis corrected to 3 percent oxygen (3-run average), except during periods of startup, shutdonrr, and malfunction.

Note: The altered affected heat.er (Alky HM-2) is considered an existing large gaseous fuel unit under the ru1e, and is subj ect to only the initial noEification requirements in 40 CFR 53.9(b) (i.e., the heater is not subject to the emission limits, work practice standards, performance testing, monitoring, SSMP. site-specific monitoring planB, recordkeeping and reporting requirements of this rule or any other. xequirements in 40 CFR 53, Subpart A).

d. The affected heaters are subject to 35 IAc 215.121, tthi-ch provides that no person shall cause or allow the emission of carbon monoxide (CO) into the at.mosphere from the affected heaLers to exceed 200 ppm, corrected to 50 percent excess air [35 IAC 21,6.\2al -

4.r-4 Non-Appl icabil ity of Regulations of Concer!

None .

77 Control Requirements and Work Practices a. i. BACT/LAER Technology

The affected heaters shall be maintained and operaced with good combustion praclices to reduce emissions of CO arrd VOM.

ii. BACT Emission Limit

EmisEions of CO from the affected heaters shall not exceed 0 .02 lblmr8tu, I{HV.

iii. LAER Emission Limit

Emiesions of voM from the affected heaters shall not exceed 0.003 lb/mmBtu, HHV. condition 4.1.5(a) (i) and (ii) represents the application of the Besl Available Control Technology. Condition 4.1.5(a) (i) and (iii) represents the application of the Lowest Achievable Emigsion Rate . lr The affecled heaters shall be equipped, operated, and maintained with ultra low No* burners. These burnerB shal1 be operated and maintained in conformance with good air pollutio! control practices -

caseous fuels, i.e-, refLnery fuel gas, natural gas, process off-gas streams, or a cord)ination of such fuels shal1 be the only fuels fired in Ehe affecEed heaters.

i. Pursuant to 40 cFR 63.?505(b) , the Permittee shall always operate and maintain the new affected heaters, including air pollutsion control and monitoring equipment, according to the provisionE in 40 CFR 53 .6 (e) (1) (i) .

ii. Pursuant tso 40 CFR 63.15O5(e) , the Permittee shall develop and implement a written ssMP according to the provisions in 40 CFR 63.5(e) (3), for the new affecEed heaters -

Production and Emission l,imitations a. Tbe maximum design firing rate of the affected heatexs shall not exceed the followinq:

Firing Rate* Heater (mmBtu/hour) VF5 H3 5OH4 4 00 DCU2 H3 s lH1 330 DCU2 H351II2 330 DCNH H-1 20

18 Firing Rate* Heater {mmBtu/hour) ULD2 H.2 Alky HItt- 2 99 BEU H3 250

12-month rolling average, IIHV h Annual emissions from the affected heaters shall not exceed the following limiEs:

NO, co voM SO: PM/PMlo Equipment (Tons,/Yr ) (Tons/Yr) (Tons /Yr) (Tons/Yr) (Tons/Yr) vF5 I{350H4 70.1 35.0 59 - 0 13.1 DCU2 H3 51II1 4 -3 32 .3 10.8 DCU2 H3 5 tHz 57 .4 za .9 4.3 10.8 DCNH H-1 0.3 2.0 0.1 ut D2 H-2 0.? 5.4 1.8 Alky HM-2 11 .3 8.7 1.3 BEU H3 43.8 3.3 8.2 HP2 H-1 240.L TLl .7 16.I

Compliance with annual limits shall be deterrnined on a monthly basis from the sum of the data for lhe current month plus the preceding 11 months (running 12 month total) .

Testing Requirements a, Nitrogen Oxides Testing

i-. Within 60 days after achieving the maximum producEion rate at which the affected heaters will be operated, bu! not fater than 180 days afler initial startup, the NOx emissions of affected heaters vF5 H350H4, DCU2 I{351H1, DCU2 H351II2, Alky HM-2, BEU H3, and HP2 H-1 shall be neasured during conditions which are representalive of maximum emissions during normal operaE.aorl.

al The following methods and procedures shall be used for testing of emissions, unless another method is approved by the Illinois EPA: Refer to 40 CFR 50, ADpendix A for USEPA test methods.

Location of Sample Points USEPA Method 1 Gas Flow and velocity USEPA Method 2 Flue Gas welghr USEPA Method 3 Moisture USEPA Method 4 Nitrogen oxides USEPA Method 7e or USEPA Method 19

19 Lr Carbon Monoxide Testinq For New Affected Heaters

i- Pursuant to 40 cFR 63.7510(9), tne Permittee shall demonstrate initial compliance with the co emission limit no later than 180 days after startup of each new affecEed heaEer.

The Permittee shall use the applicable performance tests and procedures in 40 cFR 63 .752O and 63.7530.

B. Pursuant to 40 cFR 53.7510(c) , tshe initial comnliance demonstration is :

1. For new affected heaEers in any of the limited use subcategories or with a heat input capacity less Ehan 100 mnBtu per hour. the initial compliance demonstration shal1 be conducLing a performance test for carbon monoxide according to Table 5 to 40 cFR 53, Subpart DDDDD.

For new affected healers in any of the large subcategories and with a heat input capaciEy of 100 mmBEu per hour or greater, the initial compliance demonstration shall be conducting a performance evaluation of your continuous emission monitoring system for carbon monoxide according tso 40 cFR 63.7525(a).

ii- Pursuant to 40 CFR 63.'7515 (e), the Permittee shall conduct atl applicable performarrce tests according 40 CFR 63.7520 on an annual basis. Annual performance tests musl be completed between 10 and months after the previous performance test.

Hydrogen Sulfide Testing

rn accordance with 40 CFR 50.8, within 50 days after achiewing the maximum production rate ac which the affected heaters will be operated, but not later than 180 days after initial startup of the affected heater and at such oLher t.imes as may be reguired by the lllinois EPA, lhe Permiltee stralL conducE performance test(6) in accordance with 40 CFR 60.105(e) and furnish the Illirois EPA a wribben report of the resulta of such performance test (s) .

Noter The hydrogen sulfide te6ting requirement is not required if the H,s content of the fuel gas to the affected heater is monitored bv an exislinq CEM.

20 4-1.8 Monitorinq Reduirements

a, PursuanE to 40 CFR 63.1525 (a), the Permittee shal1 instal1, calibrate, maj-ntain and operate a continuous emissions monitoring system (CEMS) according to the procedures in 40 cFR 63.7525 (a) (1) through (6) for emi.ssions of co from new affected heaters with a heat input capacity of 100 mmBtu per hour or greater-

ra, The Permittee shal1 demonstrate continuous compliance by foltowing the continuous compliance requirements of 40 CFR 53.7535 and 63.7540.

h Pursuant to 40 CFR 53.7505(d), the Permittee sha11 develop a site-specific monitoring plan according to the requirements in 40 CFR 63.?505(d) (1) through (4) for the ne\d affected heat.ers ,

The Permittee shall compty with the applicable monitoring requirements specified in 40 cFR 60.105 by one of the following methods:

1. rnsEalling, calibrating, maintaining and operating an instrumeDt for cortinuously monitoring and recording the concentration (dry basis) of HrS in fuel gases before being burned in the affected heaters, or

ii. Installing, calibrating, maintaining and opexating an instrument for continuousty monitoring and recording the concentration of so, emissions into the atmosphere.

iii. Notwithstanding the above, pursuant Lo 40 CFR 60.13(i) , after receipt and consideration of written application, the USEPA may approve alternatives to the above monitorinq Drocedures.

d. The PermiEtee *":..rt].i., records of the concentraEion (dry basis) of "n"ff.H2S in fuel gases before being burned in the affected heaters (or soz emissions to the atmosphere, if monitoring is performed according to condition 4.1.8(c) (ii)) to demonstrate compliance with condition 4.1.3 (b) (i).

Note: Pursuant to 40 CFR 60.105(a) (3) (ii), the SO, monltoring level equivalent to the H2S standard under 40 CFR 50.104(a) (1) sha1l be 20 ppm (dry basis, zero percent excess aar)

4.1.9 Recordkeeping Requirement s

a. The Permittee shall maintain records of the followinq items for the affected heaters:

2L Firing rate of the affected heaters (mmBtu/hr, HHV on a 12 month ro11in9 average) -

aa I{eat content of the fuel gas (Btu/scf)

j"ii. NO*, CO, VOM, SO2, PIrl and PMlo emissions from the affected heaters (tons/month and tons/year).

b. The Permittee sha11 comply with the applicable recordkeeping requirements in 40 CFR 63.'7555 for the nert affected heaters.

4.1.10 Reporting Requirements

a. The PermiEtee sha1l promptly notify the lllinois EPA of deviations of an affected heater with the permit requirementa of this section (section 4.1). Reports shall include information specified in conditions 4.1.10(a) (i) and {ii).

Emissions from the affected heaters in excess of the limits specified in condiLion 4.1.6 within 30 day6 of such occurrence.

.1.1 Operatj.on of the affected heaters in excess of the limits specified in Condition 4.1.6 \a?ithin 30 day6 of such occurrence,

Pursuant to 40 CFR 53.7515(g) , the Permittee shall report the results of performance tests within 50 days after the compfetion of the performance teBts for the new affected heaters. This report should al"6o verify thaE ghe operati-ng limits for affected heaters have not changed or provide documentation of revised operating parameters established accordj-ng to 40 CFR 63.7530 and Table 7 to 40 CFR Part 63 Subpart DDDDD, as applicabl-e. The reports for all subsequent performance tests should include all applicable information required in 40 CFR 53.7550.

The Permittee shal1 cornply with the applicable notification and recordkeeping requirements in 40 CFR 63.7545 and 53.?550, respeceively for the new affected heaEers.

d. The existing affected heater Atky Hl4-2 shal1 comply with the initial notification reguiremenls in 40 cFR 63.9(b).

The Permittee shatl comply with the applicable reporting requirements specified in 40 cFR 50.107(e) ard (f) and 40 cFR 60 . 10s (e) (3) . Distilling WesC (DW) Cracked cas plant

4.2.1 DescriDtion

Overhead from the DW CCU (FCCU 3) Main Fractionator will be routed to the exi€ting DW cracked gas pfanE- Certain compounds from this plant must be sent to a treatment system which uses caustic. Off-gas from the DW caustic regeneraeion system will be routed to a new DW caustic reqeneraLor thermal oxidizer.

Emissions from this cracked gas plant come from fugitive components and the new DW caustic regenerator thermal oxidizer. The fugitive componeDts are addressed in secEion 4-3 of this permit. The remainder of this secLion addresses the thermal oxidizer -

4.2.2 Lisu of Emission Units and Air Pollucion Control Equipment

EmiBsion Emission Control Uni t Description Equipment DW Cracked DW Cracked cas Plant, including l.Tew Thermal Gas Plan! vent to cauatic regenerator oxidizer system from which off-gases are vented Eo the rrew thermal oxidizer

4.2.3 Applicable provisions and Regulations

a- An 'affected unit" for the purpose of these unit-specific conditions, is the new thermal. oxidizer described in Conditions 4.2.! a'fd 4.2.2.

b. The affected unit is subject to the NSPS for Petroleum Refineries, 40 CFR 50 Subparts A and ,t. The Permittee shall compty \dith all applicable requirements of 40 CFR Part 60 Subparts A and J. The affected unit is considered a fuel gas combustion device under Ehis rule.

The Permj-ttee sha11 not burn in the affected unit any fuel gas that contains hydrogen sulfide (H,s) in excess of 230 mg/dscm (0.10 grldscf) [40 CFR 60.10a (a) (1) I .

Note: Pursuant. to 40 CFR 60.105(a) (3) (ii) , Ehe monitoring level for so, in the exhaust from the affected unit that is equivalent to the 230 mg/dscm HrS fuel limit is 20 ppm SO, (dry basi6, zero percent excess air') -

4.2.4 Non-Appl icabil ity of Regulations of concern

Non appLicabilitsy of regulations of concern are not set for the affected units .

23 4.2.5 Control Requirements and Work Practices

a. i. BACT/LAER Technology

The affected unit shatl be maintained and operated with good cornlcuation practice to reduce emissious of CO and VOM.

.ii. BACT Emission Limit

Emissions of co from the affected unit shall not exceed 0-082 lb/mmBtu, HgV.

1r.r . L,llER Emassion Limi.t

Emissions of voM from the affected unit shall not exceeo (J. {JU5 lDl mrruJEu,fttlv.

condition 4.2.5(a) (i) and (ii) representg Ehe applicatj.on of the Best Avaifable Control Technology. Condi.tion +.2.5(a) (i) and (iii) represents the application of the Lowest Achievable Emission Rate.

caseous fuels, i-e., refinery fuel gas, natural gas, process off-gas streams, or a combination of euch fuels shall be the onlv fuets fired in the affected unit.

Production and Emission Limitations

a. The maximum design firing rate of the affected unit sha11 Irot exceed 12.53 mrnBtu/hr (1z-month rolLing average, HI{v)

b. Emissions from the affected uaiE Ehafl not exceed the followinq limits:

Emissions PollutanE (TonB/Month) (Tons/Year) NO* 0.5 co o.4 Soz o.2 FM/PM1o/PM,. s 0.1 0.4 voM 0.1 0.3

Compliance with annual limits shall be determined on a monthly basis from the sum of the data for the currenE month plus the preceding 11 months (running 12 month total ) .

Testing Requirements

a. Hydrogen sulf j-de Testing

rn accordance with 40 cFR 60.8, within 60 days after achieving the maximum production rate a! which the

24 affected unit will be operated, but not later than 180 days after initial starlup of the affected unit and at such other times as may be required by t.he lllinois EPA, che Permituee shall conduct performance test(s) in accordance with 40 cFR 60.106(e) and furnish the lllinois EPA a written report of the results of such performance test{s),

Note: The hydrogen sulfide tesLing requirement is not necessary if the HrS content of the fuel gas to the affected unit is monitored bv an existinq cEM.

Monitoring Requirements a. The Permibtee shall conply with the applicable monitoring requj.rements specified in 40 cFR 50.105 by one of Ehe following methods :

L. lnstatling, calibratlng, maintaining and operaling an instrument for continuausly monitoring and recording the concentration (dry basis) of llas in fuel gases before beinq burned in the affected unit, or

ii. Installing, calibrating, maintaining and operating an instrument for continuously monitoring and recording the concentration of SO" emissions into the :fm^chha?A

iii. Notwithstanding the above. purguant to 40 cFR 60.13(i), after receipE and consideration of l/iritten applicati.on, the USEPA may approve alt.ernatives to lhe above monitorinq Drocedures.

The Permittee shall maintain records of the concentration (dry basis) of H,s in fuel gases before being burned in the affected unit (or so2 emissions to the atmosphere, if monitoring is performed according to condition 4.2.8(a) (ii)) to demonstrate compJ.iance with condition 4.2.3 (b) (i) .

Note: Pursuant to 40 CFR 50.105(a) (3) (ii), the sO: monitoring level equivalent to the H2s standard under 40 CFR 60.104(a) (1) shatl be 20 ppm (dry basis, zero percent excess air).

Recordkeep j.ng Regui remenE s a- The Permittee shatl maintain records of the foflowinq items for the affected unit:

i. Firing rate of the affected unit (mrnBtu/hr, HI{V on a 12 month rolling average).

ii. Heat content of the fuel gas (Btu/scf).

25 iii. No,, co, voM, sor, PM and PMlo emissions from the affected unit (tons/month and tons/year) .

4.2 - 10 Reporting Requirements

a. Ttle Permittee shall promptly notify tbe lllinois EPA of deviations of an affected urlit with the permit requirements of this section (Section 4.2). Reports shall include information specified in conditions a.2-10(a) (i) and {.ii}.

i. Emissions from the affected unit in excesg of the limits specified in Condition 4.2.5 within 30 days of such occurrence.

ii- Operation of the affected unit in excess of the limit specified in Condition 4.2.6 within 30 days of such occurrence .

The Permittee shatl comply with the applicable reporting requirements specified in 40 CFR 60.107(e) and (f) and 40 cFR 50.10s (e) (3) . 4.3 Components

4.3.1 nFcFr i nf i ^n

As part of the piping and pumpiug equipmenL associat.ed with coRE project, leaks may occur from components such as valves, connectors, and seals.

4.3.2 List of Emission Units and Air Pollution control Equj-pment

Emission Eroission control unr|] Description Equipment Components componenEs (Connectors, valves, None Pump seals, sampling Connections, Drains, Compressor Seals, PRVS)

Applicable Provisions and Regulations

a. Ar "affected component" for the purpose of these urit- specific conditions, is a new component instalfed as parE ^f t-hF anPFl nr.'ieat as described in Conditions 4.3-1 and 4.3.2, and any subsequent replacement of such new componenc .

b. This permit. ig isgued based upon certain affected components being subject to National Emission Standards for Hazardous Air Pollutants From Petroleum Refineries, 40 CFR 53, Subparts A and CC. The I1]inois EPA administers the NESHAP for subjecE sources in lllinois pursuant to a delegation agreement with the USEPA. The Permittee shall comply with all applicable requirements of 40 cFR 53, Subparts A and CC.

Note: The refinery has indicaEed that it generally complies with the equipment leak requirementg specified in 40 CFR 53, subpart cc by complying wilh the SEandards of Performance for Equipment Leaks of voc in the Synthetic organic chemicals Manufacturing Industry 40 CFR 50, Subpart \,ry.

This permit is issued based upon certain affected components being subject to standards of Performance for Equipment Leaks of voc in Petroleum Refineries, 40 cFR 60, Subparts A and GGG. The llfinois EPA administers the NSPS for subject sources in Illinois pursuant to a delegation agreement with the usEpA. The Permitlee shall comply wiEh al1 applicable requirements of 40 cFR 50, subparts A and

trlote: The refinery has indicated that it generally compl.ies with the equipment leak requirements specified.in 40 CFR 60, subpart GGG by complying with the Standards of Performance for Equipment Leaks of VOC in the Sl.nthetsj.c Organic Chemicals Manufacturing Industry 40 CFR 60, Subpar! W.

d. Thi-s permit is issued based on the affected components associated with the project being subject Eo 35 IAC Part 219 Subpart R: Petroleum Refining and Related InduBtries; Asphalt Materials.

Note: When the requiremenls for equipmenE leaks under 40 CFR Part 63 Subpart CC, or 40 CFR 50 Subpart GGG are more stringenL than the LDAR requirements in 35 IAC 219.445- 452, compliance with 40 CFR Part 53 Subpart CC or 40 CFR 50 subpart GGG for the applicable component shall be deemed compliance wiEh 35 IAc 219.445-452.

4.3.4 Non-Appl icabi l ity of Regulabions of concexn

Pursuant to 40 CFR 63.640(p), components that would be also subject to the provisions of 40 CFR Parts 60 and 61 are required only t'o comply with tshe provisions of 40 CFR Part 53 Subpart CC, rather than Parts 60 and 51.

4.3.5 Control Requirements and Work Practices

a. LAER TechnoLocrv

i. Affected components shall conply with the applicable general standards in 40 CFR 63.a62 (4O CFR 53, Subpart lI) for components in gas/vapor service, Light liquid service, and heal1z liquid service, aDd the following specific standards:

Affected pumps (1ight liguid service) sha1l comply with tshe standards fox pumps ia lights Iiouid service in 40 CFR 63.153.

B. Affected compressors (gas service) shall comply with the standards for compressors in 40 CFR

Affected pressure relief devices (gas,/vapor service) shall comply with the standards for pressure relief devices in gas/vapor service in 40 cFR 63.165.

Affected sampling connection systems shall comply with the standards for sampling connecej.on systems in 40 CFR 63.165.

Affected open-ended valves or lineB Bhall comply with the standards for open-ended walves or lines in 40 CFR 63.1,61. Affected valves (gas/vapor service and light lj.quid service) shalL comply with the sLandards for valves in gas/vapor service and in light liquid service in 40 cFR 53.158.

AffecLed pumps, valves, and connectors in heawy liquid service, shall comply with the standardg for pumps, valves, and connectors in heavy liquid service in 40 CFR 53.169.

ii, For affected components, the permittee shall monicor lhe component to detect leaks by the method specified in 40 CFR 53.180(b), .except that a more stringent definition of a leak shall apply, i.e., an instrumenE readi"ng of 500 parts per million or greater from valves in gas and light liquid service and an instrument reading of 2,000 ppm or greater from pumpg in liqht licruid service shall be considered a feak-

Condition 4.3-5(a) represents the application of the Lowest. Achievable Emission rate.

4.3.6 Production and Emission l,imitations

a. Emissions of VOM from the affected cornponent s shall not exceed 45.8 tons per year. compliance with Ehis limit shall be determined using published USEPA methodology for determining voM emissions from leaking components.

4.3.7 Testing Requirements

The PermitLee shall comply wiLh the applicable TesE Methods and Procedures of 40 CFR 50.485.

b. The Permi.ttee shalf repair and retest the leaking components as Eoon as possible wiehin 22 days after the Leak is found, but no lat€r Ehan June 1 for the purposes of 35 rAc 2I9-447 (a) (1), unless the leaking components cannot be repaired until the unit is shut down for tuxnaround -

4.3.8 Monitorinq Reouirements

The PermitEee sha1l develop a monitoring program plan consistent with the provisions of 35 IAC 21"9.445-

b. The Permittee shall conducts a monitoring program consistent wj-th the provisions of 35 IAC 2L9-447.

The Permittee shall identify each affected component consistent with the monitoring program plan submitted pursuant to 35 IAC 219.446,

29 4.3.9 Recordkeeping Requirement.s

i. The Permittee sha11 comply with the recordkeeplng requiremenes of 40 CFR 50.485.

ii. The Permittee shatl maintain the recordB required by 40 CFR 60.485 for a minimum of 5 years, pursuant to 40 cFR 63.648 (h) .

b. The Permittee shall record all leaking components r^rhich have a concenLration exceeding 10,000 ppm consistent with the provisions of 35 IAC 2!9.448.

c. The Permittee shafl maintain records of the folLowinq items for affected components:

i, Number of components by unit or location and El@e.

ii. calculated voM emiBgions, including supporting calculations, attribulable to these conponents (tons/year).

4.3 . 10 Reportlng Requlrements

a. The Permittee shall promptly notify the Illinois EPA of deviations of an affected component with the permit requj.rements of this section (sect.j.on 4.3). Reports shall describe the probable cauae of such deviationB, and any corrective actions or preventable measures taken. As Ehe operation of affected components is addresBed by reporting requirements under applicable ru1es, thj-s requirement may be sat.isfied wibh Lhe reporting required by such regulaEi-ons.

h The Permittee shall comply wiEh the applicable Reporting requi-rements of 40 CFR 60.4A7.

The Permittee shal1 report to the lllinoj-s EPA consistent wi-th the provisions of 35 IAC 219.449.

30 4.4 Storage Tanks

4.4.! Description

New tanks and moditications to an existing tank will be required as a result of the increased throughput and heavier crude slate, as follows:

An existing storage taak (TK-A126), which has not been in operation for several years, will be recoastructed and restarted to handle the additionaL ultra low sulfur diesel production from the U1,D-2 unit. The tank wj-l1 be a fixed roof bank design and store ultra lov, Bulfur diesel, which has a lo\d vapor pressure. Two new crude oil tank6 (Tanks A-98 and A-99) will be installed to handle additional crude throughput to the refinery resulting from the start-up of the DU-2 LC. Each tank wj-Il have an internal floabing roof. Tank 80-6 will be modified by installing a dome on the exlsting external floating roof, The purpose of the dome is to control potential- odors from the tank. 'Ihis dome effectively converts Ehe external floatj"ng roof into an internaL ffoating roof. This Eank is required for storage of sour water and sour waEer coacentrate prior to processing at the new sour water stripper at t.he Sulfur P1ant. A new methanol tank will be i.nstalled at the WasEewater Treatment Plant, to store supplemental feed Eo Ehe bioorganLsms in the activated sludge ponds. This tank will be a fixed roof desiqn.

several exisling tanks will experience an increase in utilization as a resufts of this project. These emiseion increaseg are accounted for in section 3.3.1 of this permit.

4.4.2 List of Emission units and Air Pollution control Eguipment

Emiesion Emission control Uni t Description Emr i hmFn l- TK.A12 6 New ultra low sulfur None -l iaeA'

4 -4.3 Applicable Provisions and Regulat ions

a. An "affected tank" for the purpose of these unit-specific conditions, is a storage tank described in Conditiong 4,4.L a\\d 4.4.2 -

b. The affected tanks TK-A126, TK-A098, TK-A099, and 80- 5 are eubject to National Emission Standardg for Ilazardous Air Pollutants From Petroleum Refineries, 40 CFR 63, Subparts A and CC. The Illinois EPA administers the NESHAP for subject sources in Illinois pursuant to a delegation agreement with the USEPA. The Permittee shall comply with all applicable requiremencs of 40 CFR 63, Subparts A and

Note: affected tank TK-A125 is cons.idered a Group 2 storage vessel under Ehis rule and has no conlrol requirements. Affected tanks TK-A098, TK-A099, and 80-6 are conaidered Group 1 storage vesaels under this rule and therefore recuire GrouD 1 controls.

ii. The metharol tank is subjecE to Natiarral Emission Standard8 for Hazardous Air Pollutants For Organic Liquj.ds Distribubion, 40 CFR 63, Subparts A and EEEE. The Illlnois EPA administers the NESHAP for subject. sources in fllinois pursuant to a delegaEion agreement with the USEPA. The Permittee shall comply with all applicable requirements of 40 CFR 63, Subparts A and EEEE.

Note: The vapor pressure of meEhanol is such that no controls are required by this rule.

The affect.ed tanks TK-A098, TK-A099, and 80-6 are subject to 40 CFR 60, Subpart Kb: Standards of Performance for volatile organic l,iquid Storage vessels (Including Petroleum Liquid storage vessels) for Which construction. Reconstruction, or Modificabion Commenced after .]uly 23, 1984. The affected tanks are subject to 35 IAC Part 2L9, Subpart B: Organic Ernissions From Storage and Loading Operations.

4-4.4 Non-Appl icabi lity of Regulations of Concern

a- i. This permit is issued based on the affected tank A- 126 noE being subject to the NsPs for Volatile organic Liquid Storage vessels (Including PeEroleum Liquid Storage vessels) for Which Construction, Reconstruct.ion, or Modificatj-on commenced After 'JuIy 23, 1984, 40 CFR 60 Subpart Kb, because the affected tank A-125 is a storage vessel with a capacity greater than or equaf to 151 m3 storing a Iiquid wi.th a maximum true vapor pressure less than 3.s kPa [40 CFR 50.110b(b)].

ii. This permit. is issued based on the affected methanol- tank not being subject to the NsPs for volaEile organic Liquid storage vesaels (Including Petroleum Li-quj.d storage ve6sel6) for which construction, Reconstruction, or Modification commenced After .tuly 23, L984, 40 CFR 60 Subpart Kb, because the affected mechanol tank is a storage vessels with a capacity of less bhan 75 m3 (19,812-9 gallons) [40 cFR 50 . 110b (a) I .

b. i. This permit is issued based on the affected tanks A- L26, A-98, A-99, and 80-5 not being subject to 35 IAC 2L9 -I2O pursuant to 219.119(e) because the affected tanks are only used to store pegroleum lj-quids.

ii. This permit is issued based on the affected methanol tank not being subject to 35 IAC 21,9.L20 because the affected methanol tank has a capacitv of less than 40,000 gal1ons.

i. This permit is issued based on the affected tank 4-126 not being subject to 35 IAC 2a9.727: Storage containers of VPL, becau€e the affected tank A-125 will not store a volatile petroleum liquid, i.e., the vapor pressure will be below 1.5 psia.

.ii. This permit is issued based on the affected methanol tank not being subject to 35 IAc 2L9.12a1 Storage containers of vPL, because the affected methanol tank does not store a volatj.le petroleum liquid as defined in 35 lAC 271.46L0 .

d. i. This permit is issued based on the affected tank A- 126 not being subjecE to 35 lAC 2'L9.1-23: PetroLeum Liquid storage Tanks, because the affected tank A-126 will not store a volatile petroleum liquid, i.e., the vaDor pressure will be below 1.5 Dsia. ii. Thj.s permit is issued based on the affected methanoL tank not being subject to 35 IAc 279.123:. Petroleum Iriguid storage Tanks, because the affected methanol tank has a capacity of less than 40,000 gallons [35 rAc 219.123 (a) (Z) I .

iii. This permit is issued based on the affected Eanks A-98, A-99, and 80-5 not being subject Eo 35 IAC 21-9.1,23: PeLroleum Lj-quid Storage Tanks, because the affected tanks A-98, A-99, and 80-5 are subject to 40 CFR 60 subpart Kb [35 IAc 2L9.a23 (a) (s)1.

4.4 -5 Control Requirements and Work pracEices

a. LAER Technology

i. Affected tanks A-98, A-99, 80-6 shalL be controlled by an internal floating roof (i.e., domed external floating roof for tank 80-5) ,,rith a primary 1i-guid- mounted seal consislent. wieh the control requirements of the 40 cFR 50 subpart Kb and 40 cFR 53 subpart cc and with a secondarv rim-mounted seal .

ii. The true vapor preE sure of the materj-al stored in the affected tank A-126 shall not exceed 0.09 psia at the maximum monthly average storage Eemperature.

iii. The true vapor pressure of the material stored in the affected methanol tank shal1 not exceed 3:5 psia at the maximum monthly average storage temperature.

Condition 4.4.5(a) represents the application of the Lowest Achievable Emission rate -

b. NSPS Control Requirements: The affected tankB A-98, A-99, and 80-6 shall be equipped with a fixed roof in conbination with an inLernal floatj.ng roof meeting the following specif ications :

.1 . The internal floating roof shafl rest or float on the liquid surface (but not necessarily in complete contact with it) inside a storage vessel that has a fixed roof. The internal floatj-ng roof shall be fJ.oating on the liqui.d surface at all times, excepE during inj-tial fill and during those intervals when the storage wessel is completely emptied or subsequently emptied and refil1ed. When the roof is resting on the leg supports, the process of fil1ing, ernptyiDg, or refilling shall be continuous and shall be accomplished as rapidly as possible [40 CFR 60.112b (a) (1) (i) I .

11. The internal floating roof shall be equipped with the following closure device betrrreen the wafl of the

34 storage vessel and the edge of the internal floaLing roof:

A foam-or liquid-filled seal mounted in contact with the liquid (liquid-mounted seal). A liquid-mounled seal means a foam-or liquid- filled seal mounted in contact with the liquid between the wal1 of the storage vessel and the floating roof continuously around Ehe circumference of the tank [40 cFR 60.112b (a) (1) (ii) (A) 1 . iii. Each opening in a nonconEact internal floating roof except for auEomatic bleeder vents (vacuum breaker vents) and the rim space vents is to provj.de a projection below the f.iquid surface [40 cFR 60.112b (a) (1) (iii) I . iv. Each opening in the internal floating roof except for leg sleeves, automatic bLeeder vents, rim space verts, column r,vefIs, ladder wel1s, sample wells, and stub drains is to be equipped with a cover or lid which is to be maintained in a closed position at all Eimes (i.e., no visible gap) except when the device is in actual use. The cover or lid shalt be equipped with a gasket. covers on each access hatch and automatic gauge float well ehall be bolted except when they are in use 140 cFR 60.112b(a) (r) (iv) l.

Automatic bleeder vents shall be equipped with a. gaskeL and are to be cLosed at all times r{hen the roof is floauing except when the r.oof is being floated off or is being landed on lhe roof feg supporrs [40 cFR 50.112b (a) (r) (v) ] . vi. Rim space vents shall be equipped with a gasket and are Eo be set to open only when the internal floating roof is not. floating or at the manufacturer's recommendedsetting [40 CFR 60.112b(a) (1) (vi]1. vii. Each penetration of the internal floating roof for the purpose of sampling shalL be a sample well. The sample well shalt hawe a sLit fabric cover thab covers at least 90 percent of the opening [40 CFR 50. 112b(a) (r) (vii) l viii. Each penetraEion of the internal floating roof that allows for passage of a colum supporEing the fixed roof shall have a flexible fabric sleeve seal or a gasketed sliding cover [40 cFR 50.112b (a) (1) (viii) ] . ix. Each penetration of the internal floating roof that allows for pasgage of a ladder shal1 have a gasketed sliding cover 140 cFR 60.112b(a) (1) (ix)1. State Cont.rol Resuirements

a. Affectsed tanks A-98, A-99, and 80-6 shall be designed and equipped with a floating roof which rests on the surface of the VPL and is equipped rrith a closure seal or Eeals betrr'een the roof edge and the tank wa11. such floating roof shaIl not. be permiEted if the vPL has a vapor presaure of 86.19 kPa (12.5 psia) or greater at 294.3oK (70oF) . No person sha11 cause or allow the emission of air contaminants into the atmosphere from any gauging or sampling devices attached to such tankB, except during Bampling or mainteDance operations [35 IAC 2r9 -72)- (b) (1) ] .

ii. The affected tanks shall be equipped with a permanent submerged loading pipe, submerged fi1l, or an equivalents device approwed by the lllinois EPA according to the provisions of 35 Il1 . Adm. Code 201 [35 IAC 2L9.1-22(b)].

4.4-6 production and Emission Limitations

a. i. Emisgions and operation of the following affected tanks shal1 not exceed the following limit.s:

FL,^ti^Ln,,F vOM Emissions Tank (Ml'lcal/Mo) (MMGat/Yr) (Ton/Mo) (Ton/Yr) A-125 115.0 589.9 MethanoL 0.02 0.13 0.02

al. Breathing loss emisgions of the f ollor,Jing affected tanke shall not exceed the folfowing Limits:

VOM EmissionB LanK (Ton/Mo) (Ton/Yr) A-98 0.08 A-99 0.08 0.5

Note: The workj.ng losses from affected tanks A-98 and A-99 are addressed by Condition 3.3.1, \,thich includes both new and existing crude oil gEorage tanka .

iii. Emissions of the fotlowing affected tank shall noE exceed the followinq limite:

VOM Emlssions Tank (Ton/Mo) (Ton/Yr) 80-5 0.07 | 0.4

L Compliance with the annual limits sha11 be determined from a running total of 12 months of data.

35 4.4-7 Testing and Inspection Reguirements

a. The Permittee shall fulfitl all applicable testiag and procedures requirements of 40 CFR 60.113b(a) for the affected tanks A-98, A-99, and 80-6 [40 CFR 60.113b(a)l

a. If the owner or operator determines that it is unsafe to inspect the vessel to determine compl.iance wiEh 40 CFR 50.113b(a) because the roof appears to be structurally unBound and poses an imminent danger t'o inspecting personneJ", the owner or operator shall cornply with the requirements in either 40 cFR 53.120 (b) (7) (i) or 40 CFR 63.120 (b) (7) (ii) [40 CFR 53.640(n) {8) (ii) I .

ii. If a failure iB detecEed during the inspectione required by 40 CFR 60.113b(a) (2), and the vessel cannot be repaired lr'ithin 45 days and the vessel cannot be emptied within 45 days, the ewner or operator may uEilize up to two extensions of up to 30 additional calendar days each. The owner or operator is not required to provide a request for the extension to the Admini.strator [40 cFR 53.640 (n) (8) (iii) I .

h The Permittee shal1 fulfitl all applicable rnonitorlng of operations requirements of 40 CFR 50.116b for the affected tanks A-98, A-99, and 80-6 [40 CFR 60.116b] .

4.4.4 Monitoring Requirements

Monitoring requirements are not set for the affected tanks.

4.4.9 Recordkeeping Requirement.s

a. The Permittee 6ha11 maintain records of the followinq itemE:

i. The cl4)e, characteristic and quantity of each material stored i.n each affected tank, including the maximum true vapor pressure.

ii. Throughput (mitlion gallons/month and million ga11ons,/year).

iii. voM emissions from each affected tank (tons/month and tons/year) .

b. The Permittee shall fulfilt all applicable recordkeeping requirements of 40 CFR 60.115b for the affected tanks A-98, A-99, and 80-6 [40 CFR 50.115b] - The Permittee sha11 fulfill atl applicable recordkeeping requirements of 40 CFR 63.654 for the affected tanks TK- A125, TK-A098, TK-Ao99, and 80-6.

For the methanol tank. the Permittee shall keep documentation, including a record of the annual" average true vapor preasure of the total Table I (of 40 CFR 63 Subpart EEEE) organic IIAP in the stored organic liquid, that verifies the storage tank is not required to be controlled under this subpart. The documentation must be kept up-to-date and must be in a forrn suitable and readily available for expeditious inspection and review according Eo 40 CFR 53.10(b) (1), including records stored in electronic form in a separate location [40 cFR 63.2343 (b) (3) 1 .

4.4.10 Report j.ng Requiremepts

a. The Permittee shafl promptly notify the Illinois EPA of deviationg of an affected tank with the permit requirements of Ehis section (Section 4.4). Reports shall include information specified in Conditions 4.a.10(a) (i) and (ii).

a. Emissions from the affected tanks in excess of the Iimits specified in condition 4.4.6 within 30 days of such occurrence -

ii. operation of the affected tanks in excesE of the limit specified in condition 4.4.6 \^rithin 30 days of such occurrence.

b. The Permittee shalt fulfill all applicable reportsing requirements specified in 40 CFR 60.115b for the affecEed tanks A-98, A-99, altd 80-6 [40 CFR 50-115b].

a. Owners and operators of storage vessels complying h'ith subpart Kb of Part 60 may submit the inspection reports required by 40 CFR 60-115b(b) (4) as part of the periodic reports required by 40 CFR Part 53, subpart CC, rather than wit.hin the 30-day period specified in 40 CFR 60.115b(b) (4) [40 CFR 53.640(n) (8) (v)1.

ii. The reports of rim seal inspectj.ons specified in 40 cFR 60.115b(b) (z) are not required if none of the measured gaps or calculated gap areaB exceed the limitatj.ons specified in 40 cFR 60.113b(b) (4). Documentation of the inspections shall be recorded as specified in 40 cFR 60-115b(b) (3) [40 cFR 63.640(n) (8) (vi) I .

ff an extension is utifized in accordance with 40 cFR 63.540(n) (8) (iii), the owner or operatox shall, in the

38 next periodic report, identify the vessel, provide the information lisred in 40 cFR 50.113b(b) (a) (iii), and descr.ibe the nature and date of the repair made or provj.de the date the storage vessef was emptied [40 CFR 53 . 540 (n) (8) (iv) I . d. The Permittee shall fulfil] al1 applicable reporting requirementss of 40 CFR 53-654 for the affected tanks TK- A125, TK-A098, TK-A099, and 80-6.

The Permittee shall comply witsh the applicable reporting requiremenEs in 40 CFR 63-2343.

39 Fluidized Catalytic Cracking Units (FCCU)

nac-ri h1- i ^n

The FCCU converEs gas-oil, an intermediate weight stream produced in the ca:ude unit at the ref inery, into a lighter stream that can be used in production of diesel fuel, gasoline, and other products. The gas-oi1 is mixed in the FCCU reactor with a finely powdered caEalyst, which promotes a cracking reaction to reduce the size of the molecules. During the cracking react.ion, carbon is deposiEed on the caEalysu. The catalyst is separated from the cracked products by internal cyclones in the reactor and sent to the regenerator section of ghe FccU, where carbon deposited during the reaction is removed by combustion- The carbon free regeneratsed catalyst ig returned to the reactor so that the FCCU operates as a continuous proceset. The emissions from the FCCU come from the regenerator section.

FCCU 3 is considered a co.rpldte cornbustion unit (high temperature, ful1 burn). High temperature regeneration, or ful1 conbustioa regeneration uses excess oxygen and high operation temperatures to reduce the carbon deposits (i.e., coke) on the FCCU catalyst and to complete combustion of CO. No CO heater is used on FCCU 3 because CO concentrations in the high temperature regenerator effluen! are relat.ively low. To maintain low concentrations of CO, FCCU 3 will be equipped with a system to inject a cornbuEtj.on promoter (catalyst) which would act to raise the operating tempexature in the regeneraLor.

FCCU 1 and FccU 2 are considered parEiaL combustion units. A partiaf combustion unit will have fower regeneration bed temperatures and less oxygen available for combustion. FCCU 1 and FCCU 2 are equipped rrith separate fuel-fired Co heaters to heat the regenerator ven! gas abowe its i-gnifion temperature. Excess oxygen is supplied to complete conversi-on of carbon monoxide to carbon dioxide.

Modifications to FCCU 1 include metatlurgical upgrades to the feed preheat exchange equipment and the feed piping, interral modification to the fractionator !ray6, .installation of new light-cycle oi1 cooling, modifications to the high-presaure separator, and Co heater enhancements. Modifications Eo FCCU 2 include metallurgical upgrades to the feed preheat exchange equipment and the feed piping. internal modification to the fractionator trays, installation of new light-cycle oil cooling, modifications to the high-pressure separator, and CO heater enhancements. Both FCCU 1 and FCCU 2 will be equipped with a wet gas scrubber (VlcS) and selective catalytic reduction (SCR) - The WGS will control SO2 and will supplemen! the exiBting cyclones used to control Farticulate rnatter. SCR L\'ill be installed on t.he existing co heaters associated with these units to control emissions of NO*.

40 FccU 3 was previously operated by Premcor and has been idle since 2002. As part of the COREproject, FCCU 3 vri1l be restarted and permiEted as a new unit, as required by a Consent Decree. This project incfudes the installation of a wGS to control particulate matter and sulfur dioxide emissions in the regeneraEor. The WGS will control SO2 and will supplement the existing cyclones used to control particulate matter. SCR will be installed on the exhaust from Ehe reqenerabor to control emissions of NOx.

4.5.2 List of Emissi.on Units and Air Pollution Control Esuipment

Emission Emis s ion conErol unat Description Equipment FCCU 1 Modif ied FLuj.dized catalytic scR, vtcs, co cracking uuit (partial combustion unit) Flare FCCU 2 Modified Fluidized CatalyLic scR, t{Gs, co cracking UniE (partial comlcustion unit ) Cyclones, Flare FCCU 3 ResEart of Fluidized catalytic scR, vrcs, cracking unit (ful1 combustion cyclones, uniE ) FIare

Applicable Provisions and Regulations

a. The "affected uniE" for lhe purpose of these unit-specific conditions, is a fluidized catalytic cracking unit deBcribed in conditions 4.5.1 and 4-5.2.

b. NSPS Provisions

The affecled uniEs are subject to the NsPs for Petrofeum Refineries, 40 CFR Part 50, Subpart ,J. ?he Permittee shall comply with all appticable requirements of 40 cFR ParC 60, Subpart ,J.

1, The affected unit6 are subject to 40 cFR 50.102: standard for particulate matter, which provides that no owner or operator shall discharge or cause the discharge into lhe atmosphere from any fluid catalytic cracking unit catalyst regenerator:

A. Particulate matter in excess of :.-O k9/l'49 Q.A 'lLlr-^nl ^F ^^Va hrrrh-^ff ih l-ha ^.fAlval- regenerator [40 CFR 50. 102 (a) (1) ] .

Gases exhibiting greaEer than 30 percent opacity, except for one six-minute average opacity reading in any one hour period [40 CFR 60.102 (a) (2) I .

41- ii. The affected units are subject to 40 cFR 50.103: Standard for carbon monoxide, which Frovides that no owner or dperator subject to the provisions of this subpart shall discharge or cause Lhe d.ischarge into the aEmosphere from any fluid catalytic cracking unj-t catalyst regenerator any gases that conEain carbon monoxide (CO) in excesg of 500 ppm by volume (dry basis) [40 CFR 50.103 (a) ] .

iii. The affected units are subject to 40 CFR 50.104 1 standards for sulfur oxides, \n'hich provides that vrith an add-on controf device, reduce sulfur dioxide emissions to the aEmosphere by 90 percent or maintain sulfur dioxide emissions to the atmosphere less than or equal to 50 ppm by volume (vpprn), whichever is less stringent [40 CFR 50.104 (b) (1) ] ; or

Note: This permit does no! address other alternaEive so2 emiasion standards in Subpart .t, which rel-y on processing of very low-sulfur content material by FCCU, rather than use of an add-on control device.

NESHAP Provisions

The affected units are subject to NESI{AP for Petroleum Refineri.es: Catalytic Cracking Unlts, catalytic Reforming Units, and sulfur Recovery Units, 40 CFR Part 63, subpart UUU. The Permittee sha1l comply with al1 applicable requirements of 40 CFR Part 53, Subpaf,t UIru.

a. Metal HAP Emissions

The Permittee shall comply q'ith the appl.icable requirements for metal HAP emissions from catalyEic cracking units in 40 CFR 63.1564. In paxtj"cular, the Permittee shall comply \"rith the emission Iimitations for NSPS units, pursuant to 40 CFR 63.1564(a) (1) .

ii. Organic HAP Emissions

The Permitt.ee shall comply with the applicable requirements for organic I{Ap emj.6sions from catalytic cracking units in 40 CFR 63.1565. In particular, the Permittee shall comply with the emission limitations for NSPS units, purauant to 40 CFR 53.1565(a) (1). d. Consent Decree Provisions

The affected units are subject to certain requirements in the consent Decree United SLates of America and the states of lL1inois, Louisiana and New ,fersey, common'realth of Pennsylwania and lhe Northr.reet Clean Air Agency v. ConocoPhillips Company; Civil AcEion No. H-05-0258,

42 ent.ered by the District Court for the Southern District of Texas on ,fanuary 27, 2OO5 (Consent Decree) -

StaEe Provisions a. PM Standards

A. The affected units are subject to 35 IAc 2L2.3Aa, ,rhich provides thaE the PM emisslons from the catalyst regenerators of an FCCU shafl not exceed in any one hour period the rate determined using the equations contained in 35 rAc 212.381.

The affected units are subject to 35 rAc 2a2.123 (a), which provides that the emission of smoke or olher particulate matter shall not have an opacixy greater Ehan 30 percent, except as alfowed by 35 IAC 21"2.I23 (b) and 2L2.L24.

ii. so2 standards

A. Except as further provided by 35 rAc 2a4, no person sha11 cause or allo\a' the emission of sulfur dioxide into the almosphere from any affected unit to exceed 2000 ppm 135 rAc 214.3011.

B. Pursuant to 35 IAc 21,4.382 (c) (3), no person shall cause or al1ow the total emission of sulfur dioxide into the atmosphere from the following source groupings !o exceed the following amounts:

All catalytic cracking units - 3,430 lbs/hour (1,s60 kglhour) [3s IAc 2L4.3az (c) (s) (r)1.

Pursuant to 35 IAC 214-382 (d), compliance with the above limit shall be demonstrated on an three -hour block average basis.

Note: condition 4.5.3(e) (ii) (B) applies to FCCU 1 and FCCU 2 only.

iii. co standards

The affected units FccU 1 and FCCU 2, are subjecL to 35 IAC 2a6.36a (b), which provides that the emission of a carbon monoxide wa6!e stream into the atmosphere from any existing petroleum process, as defined in 35 IAC 20f .!02, using catalyst regenerators of fluidized catalytic converters eguipped with in-situ coldoustion of carbon monoxide, shal1

43 not emit CO waste gas streams into the atmosphere in concentrati.on of more than 750 ppm by volume corrected to 50 percent excess a1r.

B. The affected unit Fccu 3, i6 subject Eo 35 rAc 21,6-367 (c), which providee that Ehe emission of a carbon monoxide waBte stream into Ehe atmosphere from any new petroleum process, as defined in 35 IAc 2oL.Loz, using catalyst regenerators of fluidized caEalytic converters eguipped rr'ith in-situ combugtion of carbon monoxide, shall not emit CO waEte gas streams into the aLmosphere in concentration of more than 350 ppm by vol-ume correctsed to 50 percent excess a1r.

av. voM Standards

No person shall cause or allow the discharge of organic materials in excess of 100 ppm equivalent methane (molecular weight 15.0) into the atmosphere from any catalyst regenerator of a petsroleum cracking system [35 lAC 219.a41(a) (1) ] .

Non-Applicabi lity of Regulations of Concern

lJ tArJ ZtZ.JZ_L anq ZtZ.SZZ Snal.l. nOE apply to catalyst regenerators of fluidized catalytic converters [35 IAC 212.3811 .

b. The FcCUs are exempt from 40 CFR 63 Subpart CC (Refinery NESHAP) pursuant to 40 CFR 53.640(d) (4).

4.5.5 Control Requirements and Work Practices

.a. Technology

A. The affected units Fccu 1 and Fccu 2 sha11 be controlled by venting emissions to a CO heater or other cornlcustion device.

B. The affected unit FCCIT 3 shall utilize high temperature regeneration, i.e., fu11 cornlcustion, supplemented with co promoter as needed to comply witsh the applicable hourly limit.

aa. BACT EmisBion Limit

A- Emissions of CO from affected unitE FccU 1 and FCCU 2 shal1 not exceed:

44 1. 100 ppmdv corrected to 0 percent oxygen on a 365 day rolling average,' and

2, 500 ppmdv corrected to 0 percent oxygen on an hourly awerage basis.

EmissionE of Co from Fcctt 3 shall not exceed:

L 150 ppmdv corrected !o 0 percent oxygen on a 365 day rolling average; and

2. 500 ppmdv corrected to 0 percent or

condition 4.5.5(a) represents the application of the Best AvaiLable Control Technolocrv.

a. !A!jl< I ecnnorocrv

The affected units shatl be maintained and operated with good air pollution control practice to reduce emissions of VOM.

ii, I,AER Emission Li-mit

Emissions of vOM from FCCU 1 ard FCCU 2 shafl not exceed 0.05 1b/1000 lb of coke burned,

Emissions of VOM from FccU 3 sha1l not exceed 11 lbl1OOO bbl of feeat. conditian 4.5.5(b) represents the application of the Lowest Achievable Emis s-ion Rate.

i. Pursuant to Paragraph 60 and 81 of the Consent Decree, the Permittee shafl instalt and operate a wet gas scrubber on the affecEed unit Fccu 3.

ii. This permit authorizes the Permittee to install and operate a wet gas scrubber on affected uni"ts Fccu 1 and FCCU 2.

iii. This permic authorizes the Permittee to inBtalL and operate SCR on affected units.

The Permittee shall comply with the applicable general requirements for affected units idenbified in 40 cFR

The Permittee shall prepare an operation, maintenance, and monitoring plan according to the requirements in 40 cFR 53.1574(f) and operate at all times accoxding to the procedures in the plan [40 cFR 63.1564 (a) (3) and 40 CFR 63 . 155s (a) (3) I - 4.5.5 Production and Emission Limitations

1- The daily average coke burn rate of FccU 1 shall not exceed 540 tons (12-month rolting average).

ii. The daily average coke burn rate of FCCU 2 shall noE exceed 540 ions (12-month rolling average) -

iii- The daily average coke burn rate of FCCU 3 shall no! exceed 300 tons {12-month rolli.ng average).

lr 1- so2 concentrations from the affected units shall not exceed 25 ppmvd on a 365-day rolling average basis and 50 ppmvd on a 7-day rolling average basis, eash at O+ 02, pursuant to Paragraphs 57 and 50 of the consent Decree.

Emissions of PM shall not exceed 0.5 pound PM per 1000 pounds of coke burned on a 3-hour average basis, pursuant to Paragraphs 77 and 81 of the Consent Decree.

Nox concentrations from the affected units Fcgu 1 and FCCU 2 shal1 not exceed 20 ppmvd on a 365-day rolling average basis and 40 ppmvd on a 7-day rolling average basis, each at 08 02, pursuant to Paragraphs 27 and 38 of the consent Decree.

ii. Annual emissions from the affected units shalL noE exceed the following limits. Compliance with the annual limits shaLl be determined from a running total of 12 months of data:

Emissions (Tons/Year) UNAE co No, so, PM/PM1o VOM FCCU 1 293 .9 168.1 98.5 FCCU 2 rb6. _L 98.6 FCCU 3 189.8 4L .6 72.4 54.8 50.2

4.5.7 Test j-ng Requirements

a. i. within 60 days after achieving Ehe maximum production rate at which the affected units wj.]1 be operated, but not later than 180 days after initial startup of the affected units and at such other times as may be required by Ehe USEPA under SecEion 114 of the Act, Ehe o\,rner or operator shall conduct performance test(8) and furniah the Illinois EPA and USEPA a written report of the results of such performance test (s) [40 CFR 60.e(a)]. ii. Upon request by the Illlnoj-s EPA, the wet gas scrubbers controlling the affected units shall be retested in accordance with applicable test(s) methods as set in ConditioD 4.5.7.

h a. The method and procedures specifled by the NSPS, 40 CFR 50.106 and 50.108, shafl be used for testing of pM, co and SO2 emissions and opacity, un1es6 USEPA approves an alternative t.est method pursuant to 40 cFR 60.8.

ii. The following meLhods and procedures shall be used for testing of Nox and voM emissions, unless another method is approved by the ll1j-nois EPA: Refer to 40 CFR 50, Appendix A, for USEPA test methods.

Location of sample Points USEPA Method 1 Gas Flow and vetocity USEPA Method 2 Flue Gas weight USEPA Melhod 3 Moisture USEPA Method 4 Nitrogen oxides USEPA Method 7 VolatiIe organic Material USEPA Method 25A

The Reference Method 1lsted above refers to the base method or any of .its "sub-methods", e.9,, Method 2 includes Methods 2, 2A, 28, 2c, and 2D; Method 3 includes Melhods 3 and 34; and Method 7 includes Methods 7, 7A, 78, 7C, 7D, and ?E.

Pursuant to Paragraph 83 of the Consent Decree, the test methods specified in 40 cFR 50.105(b) (2) shall be used to measure the PM emissions from the affected unit FCCU 3- This test shall be performed no later than 6 months after initial startup of the affected uniE FCCU 3 and annually thereafter,

4.5.8 Monitoring Requirements

a. Consent Decree Monitorinq RequirementE

Pursuant to Paragraph 54, 60, ?3, and 86 of the Consent Decree, the Pemittee shall use so2, NOx, CO, and O, CEMS to monitor the performance of the affected units.

Monitorirrg Requirements

1- The Permittee shall cornply with the applicable monitoring of emissions and operations requirementa identified in 40 CFR 60.105 for the affecEed unita. In particular, opacity, Co, and So2 continuous monitoring Bystema shall be installed, calibrated, maintained and operated for the affected units, pursuant to 40 CFR 60.105.

47 ii. Notwithstanding the above, pursuant to 40 cFR 60-13 (i) , after receipL and consideration of written application, the USEPA may approve alternatives to the above monitoring procedures.

NESHAP Monitorinq Requirements

i. Pursuant to 40 CFR 63.1564(a) (2) each affected unlt shalf be equipped with a continuous opacity monitoring system.

B. The Permittee shalI insEal.l-. operate, and maintain these contj.nuous Ioonitoriog syEteln to measure and record the opacity of emissions from each catalyst regenerator vent [40 cFR 63.a564 (b) (1) I .

As an alternative to the requirement to install an opacity monitor, an alternative monitoring pl-an may be requested from the USEPA to demonstrate compliance with the opacity limits by establishing operating limits for an affected unit as set forth in 40 CFR 53 . 1s54 (a) (2) .

l-1. A. Pursuant to 40 CFR53.1565(a) (2) each affected unit shall be equipped with a co continuous emission monitori.ng system.

The Permittee shall insta1l, opef,ate, and maintain these cont.inuous emission moniEor j.ng system to measure and record the concentration by volume (dry basis) of Co emissions from each catalyst regenerator vent [40 CFR 53.1565 (b) (1) I .

Recordkeeping Requirement s a. The Permittee sha11 cornply wiEh Ehe applicable recordkeeping requireKents identified in 40 crR 50.107 for the affected units. lr The Permittee shall comply with the applicable recordkeeping requirements identified in 40 cFR 63.L576 for the affected units.

The Permittee shafl maintain records of the fol lovring items for affected units:

a. Dail-v coke burn raEe for each affected unit ( lons )

ii. Monthly and annual emissions of co, No*, so,, PM/PM1o and vOM (tons/month and tons/year) witb supporting documentation,

48 4.5.10 Egporting Requirements

Reporting of Deviations

The Permit.tee shall promptly noEify the Illinois EPA of deviations of an affected unit with ttre permit requirements of this section (Section 4-5) - Reports shall include information specified in conditions 4.5.10(a) (i) and (ii):

I. Emissions from the affecled units in exceEs of the limits specified in Condj.tion 4.5.5 within 30 days of such occurrence.

ii. operaLion of the affected units in excesB of the limits specified in Condition 4.5.6 within 30 days of guch occurrence.

The Permittee sha1l comply with the applicable reporting requirements identified in 40 CFR 60.107 for the affected unt-Es.

The Permittee shal1 comply with the applicable notif ication requirements identified in 40 CFR 63.t574 tor the affected units.

d. The Permittee shall cornply w.ith the applicable reporting requirements identified in 40 CFR 53.1575 for the affected units.

4.5.11 Operational Flexibility/AnticipaLed Operating Scenarios

Operationaf flexibility is not set for the affected unj-ts.

4.5.12 Cornpliance Procedures

Initial compliance with the NESHAP's metal HAP emisgion limits sha1l be demonstrated according to Table 5 of 40 cFR 53 Subpart IJIru, pursuant to 40 cFR 63.1564 (b) (5) .

ii. continuous compliance with the NESIaP's metal I{AP emission limits shal1 be demonstrated according to the methods specified in Tables 6 and 7 of 40 CFR 63 Subpart Ulru 140 CFR 63.1564(c) (1)1.

I. rnitial compliance with the NEsraP's organic HAP emission linits shall be demonstrated aqcording to Table 12 of 40 CFR 53 Subpart tnJU, pursuant Eo 40 CFR 53 . 155s (b) (4) .

ii. continuous compl,iance r^rith the NESHAP's organi-c HAP emission limits sha1l be demonstrated according to the methods specified in Tables 13 and 14 of 40 cFR 63 Subpart tlUU [40 CFR 63.1565 (c) (r) ] . Coolinq Water Towers

Descriptj-on

The coofing lowers are part of the non-contact cooling water systems that circulate waLer to refinery process units to remove heat from proceGa streamB via heat exchangers - The cooling towers "cool" the heated water by meana of evaporatian aflowing the cooling water to be recirculated several times before it is sent to wastewater treatment.

The cooling towers are sources of particulate matter because of minerals conLained in the water, which are em.itEed .if a water droplet completely evaporates in the cooling tower.

Several existing cool ing towers will be debottlenecked as a resuLt of this proj ect. The associaEed emigsion iDcreases are accounted for in Section 3 of this permit.

4.6.2 LisE of Emission Units and Air Pollution Contxol Esuipment

Emissi.on Emissi-on control Unit Description EquiDment cw23 New North Property Cooling Water Drift Tower Elimi-nators cwz4 New HP-2 Cooling Water Tower Drift Eliminators SRU CWT New cooling water tower for the Drift Sulfur Recoverv Units. Eliminators

Applicable Provisions and Regulations

a. An "affected unit" for the purpose of these unit-specific condieions is a cooling water tower described in Conditions 4.6.1 and 4.6.2.

Pursuant. to 40 cFR 63.402, the Permittee shall not use chromium-based water treatment chemicalg in any affected unit .

The Permittee shall comply with the monitoring, recordkeeping, and reporting requirements of 35 IAC 2L9.9s6 (d) as included in Condilions 4.6.8, 4.6.9, and 4.6.10, for each affected unit.

d. Any affectsed units that supply cooling water to a process subject to the Hazardous Organic NESHAP, 40 CFR 63 Subpart F (e.9., BEU) must comply wittr the heat exchanger system requj-rement.s of 40 cFR 53.104.

50 4.6.4 Non-Appl i cabi I ity of Regulations of Concern

a. The LDAR program of Condition 4.3 does not apply to the affected units as the towers and piping contain mostly water and are not in VOM service- AppropriaLe monitoring is addressed in Condition 4.5.8.

4-6-S Control Requirements and work Practices

a. LAER Technology

The design drift loss from Ehe drift eliminators on lhe affecLed unj-ts shall noL exceed 0.005 percent (12-month rolling average) .

Condibion 4.6.5(a) represents the application of the Lowest Achievable Emission Rate as required bv 35 IAc Part 203.

4.5.6 Production and Emission LimitationE

a. i, The total capacity of the affected units, expressed in terms of design circulation rate, shal1 not exceed the following limits, hourly average:

RaEe unlc (callons /Minute ) cw23 50, 000 cw24 15, 000 SRU CWT s,000

ii. The total dissolved solids content of water circulating in the affected units Ehal1 not exceed 3,000 ppm on a monthly average basis, and 2,000 ppm on an annual average.

t- Emissions from the affected units shall noE exceed the following limits. compliance with the annual limits sha11 be deEermined from a runninq total of 12 months of data:

PM/PMro Emissions voM Emisslons Unit (Tons/Mo) (Tons,/Yr ) (Tons,/Mo) (Tons/Yr) CI.l23 1-3.2 0.03 0.2 cw24 0.49 0.01 0.1 SRU CWT 0.15 0.01 0.1

sampling and Analysis

a. The Permittee shatl sample and analyze the lri'ater being circulated in ttre affected units on at least a monlhly basis for the total dissolved solids conlent. Measurernents of the total dissolved solids content in the wastewater discharge associated with the affected unit, as required by a Nationa.l Pollution Discharge Elimination

51 system permit, may be used to satisfy this requirement if the effluent has not been diluted or otherwise treated in a manner that would significantly reduce its total dissolved solids content.

Upon written requests by the lllinois EPA, the Permittee shall promptly have the water circulating io the affected unit sampled and analyzed for the presence of hexavalent chromium in accordance with the Drocedures of 40 CFR 53.404 (a) and (b) .

4.6.8 Inspection Requirements

'Ihe Permittee shall comply 'rith the following control mea€tures for the affected units [35 IAC 219.9e6 (d) I :

a. The owner or operator of a non-contact process watef cooling tower sha11 perform the following actions to control emissions of VOM from such a tower:

L. Inspec! and monitor such tower to identify leaks of VOM inEo the water, a6 further specified in 35 IAC 21s. e85 (d) (3) ;

ii. when a leak is identified, initiaEe and carry out steps to identify the specific leaking component or components as soon as practicable, as further specified in 35 IAC 219.986(d) (4);

iii. When a leaking component is identified which:

can be removed from service without disrupting production, remove the component from service;

B. cannoE be removed from service without disrupting productioir, undertake repair of the component at the next reasonable opportunity !o do so including any perj.od when the component is out of service for scheduled maintenarrce, as further specified in 35 IAc 21,9.986(dl (4) i

iv. Maintain records of inspection and monitoring activities, i.dentificatior of leaks and leaking components, eLininati-on and repair of 1eaks, and operation of equipment as related to these activities, as furEher specified in 35 fAC 219. e85 (d) (s) .

b. A VOM leak shal1 be considered to exist in a non-contact process water cooling lrat.er sysEem if Ehe VOM emissions or vOM content exceed background levels as determined by monitoring conducted in accordance with 35 IAC 21.e. sa6 (d) (3) (A). The owner or operator of a non-contact process water cooling tower shall carry out an inspection and monitoring program to identify VOM leaks in the cooling water sysEem.

l-, The owner or operator of a non-conlact process water cooling Lower sha1l submit to the lLlinois EPA a proposed monitoring program, accompanied by technical justification for the program, including justificatj.on for Ehe sampling location(s), parameter(s) selected for measurement, monitoring and inspection frequency, and the criteria used relaEive to the monitored parameters to determine whether a leak exists as specified in 35 rAC 219.986(d) (2).

Note: The above submittal is not required for Ehe affected units if the Permittee elects to implement the monitoring program currentfy applied at the refinery' s existsing cooling towers.

ii. This inspection and monitsoring program for non- contacts process water cooling towers sha1l include, but shall not be limited to:

Monitoring of each such lower with a water flow ratse of 25,000 gallons per minute or more at a petroleum refinery at least weekly and monitoring of other towers at least monthly;

Inspeclion of each auch tower at least lreekly if moaitoring is not performed at least weekly.

iii. This inspecEion and monitoring program shal1 be carried out in accordance with written procedures which the Agency shall specify as a condition in a federally enforceabfe operating permit. These procedures shall include bhe VoM background levels for the cooling tower as establ.ished by the owner or operator through monitoringt describe uhe locations at rrhich samples will be taken; identify the parameter(B) to be rneasured, the frequency of measuremelts, and the procedures for monLtoring each such tower, that is, taking of samples and other subsequent handling and anafyzing of samples; provide the criteria used to determine that a leak exists as specified in 35 IAc 2L9.9a6 (d) (2); and describe the records which will be maintained.

iv. A non-contact process water cooling tower is exempt from j-hF rF.nrirFments of 35 IAC 219.986(d) (3) (B) and (d) (3) (C) , if all equipment, where leaks of vOM into cooling water may occur, is operaied at a minimum pressure in the cooling vrater of at least 35 kPa greater than the maxj-mum pressure in the process f1uid.

53 d. The repair of a leak in a non-contact process water cooling tower shall be considered Eo be completed in an acceptable manner as follows:

1. Efforts to identify and locate the leaking components are initiat.ed as soon as practicable, but in no event faLex than three days after detection of the leak in the cooling water toweri

ii. Leaking components shall be repaired or removed from service as soon as possible but no later tharr 30 days after the leak in bhe cooling water tower is detected, unless the leaking componente cannot be repaired until the next scheduled shutdown for maantenance,

4.6.9 Recordkeeping Requirement s

a. The Permittee Bhatl keep records as set forth below for the affected units [35 rAc 2L9.9a6 (d] (5)l:

i. Records of inspection aad monitoring activity;

ii. Records of each leak identified in such tower, lrith date, time and nature of observation or measured level of parameter;

iii. Records of activity to identify leaking components, with date initiated, summary of componentB inspected r,t'ith dates, and method of inspectsion and observations; arrd

iv. Records of activiLy to remove a leaking component from service or repair a teaking component, with date ini.tiated and completed, description of actions taken and the basis for determining Ehe leak in such tower has been eliminated. If the leaking conponent is not identified, repaired or eliminated within 30 days of initial identification of a leak in such tower, thia report shall include specific reasons why the leak could not be eliminated sooner including all oEher intervening periods when the process unit was out of 6ervice, actions taken to minimize voM losses prior to efimination of the Leak and any actions taken co prevent the recurrence of a leak of this tl4)e.

b. The Permittee shall keep records of the total capac.ity of the affected units (gallons /minuEe, hourly average).

The Permittee shall keep records of emias.ions of VOM, PM, and PM1o, wiEh supporting calculations (!on6/monbh and tons/year) . 4 .6 .70 Reporting Requirements

The Permittee shall promptly notify the lllinois EPA of deviations of an affected unit wiEh the permit requirements of this secLion (Section 4.6). Reports shall include informatiol Epecified in Condition 4-6.10(b) .

The owner or operator of a non-coDtact process water cooling tower shall submit an annual report to the Illinois EpA which provides [35 IAC 219.986 (d) (6)]:

The nurnlcer of leaks identified in each coolinq tovrer;

1a A general description of activity Eo repair eliminate teaks which were identified;

iii. Identification of each leak which rras not repaired in 30 days from the date of identitication of a leak j"n such a tower, with description of the leaks, explanation why the leak was noL repaired in 30 daysi

iv. Identification of any perj-ods vrhen required inspection and monitoring activlties were not carried out .

b. Emissions from the affecled units in excess of the limit.s gpecified in condition 4.5.6 within 30 days of such occurrence -

ii. operabion of the affected units in excess of the limits specified in Condition 4.5.6 within 30 days of such occurraence.

55 4.7 Flares

4.7 .1 nae^ri -t- i ^n

at.r."1-*n"=e of releases of frammabte process gas that can not be recovered, as can occur from various units, by combustion. These releases can occur from safety relief valves, test instruments and monitors, waste process gas and blowdown, and gases collected via venEs and drains during depres suri zation of vessels or equipment in preparation for turnaround and maintenance. Many releases are of sufficienE quantity thac most. of it may be compressed and recovered and then used in heaters and boilers after being processed wiEh amine absorbers to remove H2S. The excess that cannot be recovered is sent to a flare. The reLeases are generally hydrocarbons but may be hydrogen or any combination of hydrogen, hydrocarbon, sulfur compounds and inert gases. The flares burn Ehe gase6 to form carbon dioxide, sulfur dioxide, and water. Only recovered gases are treated through the amine absorbers. If the compressor capacity is exceeded then lheae gaaes go directly to a flare and those gases are likely to contarn H2S.

Releases to flare sysEems are managed to prevent product loss. some processes require a minor amount of venting during normal operation to safely dispose of non-condensable gases, such aB nitrogen, tha! are present as dictaEed by Ehe nature of ttre process.

The new coker flare is eguipped with a sysbem for using steam (i.e., steam-assisEed) Eo assure more complete combustion.

Aa these flares cornbust process gases, they must be operated in compliance with applicable federal emissions standards for f larinq .

4.7.2 Lj.Bt of Emission Units and Air Pollution Control Equipment

Emission Uni-t Description DCUF New Coker Flare, Steam-Assiated HP2F New HP-2 F1are, Nonassisted

4.7 .3 Applicable Provisions and Regulations

a. An "affected unit.' for the purpose of these unit -specific conditions is a flare described in Conditions 4.7.1 and 4.7 .2.

b. The affected un.its are subject to New Source Performance standards (NSPS) for petroleum Refineries, 40 cFR Part 60, Subpart .f. The affected units are considered a fuel gas conbustion device purauant to this NSPS- i. PursuanE to 40 CFR 50.104(a) (1), the Permittee shaLl not burn in the affected unit, any fuel gas Ehat contains hydrogen sulfide (Hrs) in excess of 230 mg/dscm (0.10 gr/dscf). The cornbustion in a flare of procesa upset gase$ or fuel gas that is released to the flare as a result of relief vafve leakage or other emergency malfunctions is exempt from this ,amr i ?ahah r-

The affected units are subject to ceneral Control Device Requirements Epecified aE 40 CFR 50.18, which provides: a. Flareg shall be designed for and operaEed wj-th no wisible emissions ae deEermined by the methods specified in 40 cFR 60-18(f) , except for per.iods not to exceed a total of 5 minutes during any 2 conaecutive hours [40 CFR 50.18 (c) (1) ] . ii. Flares sha1l be operated with a flame present at all Eimes, aB determined by the methods specified in 40 cFR 50.18(f) [40 cFR 60.ls(c) (2)]. iii. The Permittee has the choice of adhering to either Ehe hea! content specifications in 40 CFR 50.18(c) (3) (ii) and the maximumtip welocity specifications in 40 CFR 50.18(c) (4), or adhering to the requirements in 40 cFR 50.18(c) (3) (i) [40 CFR 60.18 (c) (3) I . av. steam-assisted aod nonassisted flares shall be designed for and operated with an exit velocity, as determined by the methods specified in 40 CFR 60.18(f) (4), less Enan La. J m/sec (60 ft/sec) , except as prowided in 40 CFR 60.18(c) (a) (ii) and (iii) [40 cFR 60.18 (c) (4) (i) I .

B. steam-assisEed and nonassisted flares designed for and operated with an exit velocity, as determined by the meEhods specified in 40 CFR 50.18 (f) (4) , equal to or greater than 18.3 m/sec (50 ft/sec) but less than 122 n/sec (400 ft,/sec) are allowed if the neL heating walue of the gas being cornbusted is greater than 3?.3 M.T/scm (1,000 Btu/scf) 140 CFR 50. 18 (c) (4) (ii) 1.

steam-assisted and nonassisted flares designed for and operated with an exit velocity, as determined by the methods specified in 40 CFR 60.18(f) (4), less than the velocity, VGx, as determined by the rnethod specified in 40 CFR 60.18(f) (5), and less than L22 mlsec (4oo ftlsec) are allowed [40 CFR 50-18(c) (4) (iii)].

5',7 Air-assisted flares shafl be designed and operated with an exit velocity less than Lhe velocj-ty, vcx, as determined by the method specified i.n 40 CFR 60.18 (f) (6) [40 cFR 60. 18 (c) (s) ] .

vi. Flares used to comply with this 40 cFR 50.18 shaLl be steam-assisted, air-assisLed, or nonas6isted [40 cFR 60.18 (c) (5) I .

vii. ovrners or operators of flares used to comply lrith the provisions of 40 CFR 50.18 shall monitor these conErol devices to ensure that they are operated and maintained in conformance with Eheir designs. Applicable subparts will provide provisions stating how owners or operators of flares shall moniEor these control devices [40 CFR 60-18(d]1.

viii. Flares used to comply with prowisions of 40 cFR 50.18 sha1l be operated at a1l timee when emissions may be vented to them [40 cFR 50.18 (e) ] .

Note: The affected units conErol VoM em.issiona from varioue emission units which are subject to cerlain regula!ions, vrhich reference Ehe general controf device requiremerts in the NSPS at 40 CFR 60-18- In addition, both new and existing flares at the refinery become affected facilities under the NsPs pursuant to Paragraph 11 of the Consent Decree-

d. The affected unitB are subject to 35 IAC 214.301, which provides that no person shall cause or allow the emission of sulfur dioxide into the atmosphere from any affected flare to exceed 2,000 ppm.

4.7.4 I'Torr-Applicabi lity of Regulations of Concern

Non-appl icabi lity of regulations of concern are not set for the affectsed units.

Ll q Control Requirements and Work Practices

a. BACT/LAER Technolog'y

.1 . The affected units shall be operated with equipment design specifications and work practices consisEent with the I'TSPSrequirements for flares in 40 CFR 60.18.

ii. Gaseous fuels meeting the requirements of 40 CFR 60.104(a) (1) and proceas upseL gases (as defined in 40 CFR 60.101 (e)) shall be Ehe only gases conibusted in the affected units. 1lt The Delayed coking unit shall be designed, operated and maintained with a waste gas recovery system with redundant compressor capacity, i.e., a system with two or more waste gas recovery compressors whose capacity is sufficient to handle the normal range of waste gas generated from operation of the Delayed coking Unit (lncluding startup and shutdown), even when one compressor is not in service, as may occur rrrith rout-ine preventative maintenance of compresgors iv. Except during malfunction, as defined by 40 CFR 63.2, depressuri zat ion of process vessels in the Delayed coking unit shall be conducEed .rith waste gases recovered for use in the fuel gas system until the pressure in the vessel is no more than 5,0 lb per square inch gauge, before any lrraste gases are sent !o be combusted in an affected unit.

Note: T\-rrnarounds of the delayed Coker Unit are subject. to the requirements of 35 rAc 2L9.444.

Flaring associated with the Delayed coker Unit arld I{ydrogen Plant shal1 be minimized by operating and maintaining the affected units, iucluding the asaociated waste gas recovery system for the Del.ayed coker unit, in accordance with a Flaring Minimization Plan (Plan) in accordance with Conditio[ 4.7.6-2 which Plan may be consolidated with other plans required for the Delayed coker Unit and affected units, such as the turnaround pLan required by 35 IAC 2r9 .444 (b\ . vf The Permittee sha11 conduct an event-specific investigation into each hydrocarbon flaring incident for the Delayed coker Unit or Hydrogen Plant, whj.ch investigation sha1l include a root-cause analysis for the incident unlesg the Permittee relieB upon a previous analysis for an incident, wiEh a report for the incident and investigaEion submitted to the Illinois EPA in accordance with condition 4.7.10(d). For lhis purpose, a hydrocarbon flaring incident is the flaring of waste gas Ehat involves flaring of 100,OOO scf or more of waste gas or results in VOM emissi.ons of 50 or more pounds in a Deriod of 24 hours or less. condition 4.7.5(a) represents the application of the Best Available controL Technolog-y and the applicaEion of the Lowest Achievable Emission RaLe.

The Permittee shall not vent any gas stream conlaining reduced sulfur compound concentrationg to an affected unit that woul"d cause the SO2 into the atmosphere from any affected unit to exceed 2,000 ppm, except as aflowed by

59 Conditj-on 4.7.5(b) (i) . This requirement ensures that the affected units meet the emission standard of 35 IAc 214.301.

a. SubjecL Eo the following terms and conditions, the Permittee is authorized pursuant to 35 IAC 201.149 to vent gases containing reduced aul-fur compound colcentrations to the DCUF (coker Flare) thaE would cause the sulfur dioxi.de emissions irrto the atmosphere from this flare to exceed the limitations stated .in 35 IAC 214.301 during malfunctions of equipment wenting Eo DCUF:

This auLhorization only allows such continued operation as neces€rary to prevent hazard to persons or severe damage to equipment or to provide essential services and does not extend to continued operation solely for the economic benefit of the Permittee -

B. Upon occurrence of excesa emissions due to malfunct.ion or breakdown, the Permittee shaIl as soon as practicable reduce equipment foad, repair equipment, remove equipment from service or undertake other action so that excess emissions cease -

The Permittee shal1 fulfill applicable recordkeepj.ng and reporting requirements of Conditions 4.7.9(ft and 4.7.10(c) , pursuant to 35 rAC 201. 149.

Following notification to the Tllinois EPA of a malfunction or breakdown r,rith excess emissions, the Permittee shal1 comply wiEh all reasonable directives of the Illinois EPA with respect to such incident, pursuant to 35 rAc 20L.263.

This authorization does not relieve the Permittee from the continuing obligation to minimize excese em.iB6ion6 during malfunction or breakdown. A6 provided by 35 IAC 20L.265, an authorizatj.on in a permit for continued operation with exces6 emissi-ons during malfunclion and breakdown does not shield the Permittee from enforcement for any 6uch violation and only constitutes a prima facie defense to such an enforcement action provided that the Permittee has fully complied with al1 terms and conditions connected wi-th such authorlzation.

60 4.7 .6-I Emission l,imitations

Emissions from the affected units shall not exceed t.he following timits. compliance with the annual limits shall be determlned from a mnning total. of 12 monLhe of daLa:

Emissions (Tons/Year) Emission Unit NO* Sor VOM PM/ PMl N 644.5 | 4.1 HP2 * I4'7.9 246.8 t2'7.2 | 24.A

Note: HP2 includes IlP2 H-1, cwa 24, HP2F, and HP2 Fugitives.

4.'7.6-2 Flaring Minimization plan

a. The Flaring Minimization Plan (Plan) prepared by the PermitLee for the Delayed coker unit and l{ydrogen Plant sha1l incfude the followinq:

1. A general description of the Delayed Coker unit, incJ.uding lhe associated waste gas recovery system and affected units, accompanied by process flow diagram (s ) .

ii, A descripEion of the Permittee's wriEten operating procedures for Ehe rrormal operation of the Delayed coker unit, including recovery of waste gas for use as fuel during startup and shutdown.

iii. A detailed description of the established respons ibi l ities of different personnel aE the refinery for the operation and maintenance of the Delayed Coker UniE.

iv. A detailed description of Ehe Permittee's procedures for flaring due to occurrence of process upsets or equipment failures, iacluding provisions in these procedures that act to minimize flaring.

v. A detaited descripEion of the PermitEee's procedures to minimize flaring in conjuncEion with major maint.enance and turnarounds of the Delayed Coker Unit, including the planning conducted as part of such work to minimize flaring.

vi. A detailed description of the Permittee's procedures for the fuel gas systems to facilitate acceptance of waste gas and to maintain or restore recovery of waste gae during flaring ewents.

vii. A detailed description of the Permittee's procedures for preventative maintenance of the Delayed coker Unit, including provisions in these procedures that should act to miaimize flaring.

viii. A detailed description of the Permittee's procedures for periodic evalualion of flaring activity generaLly and specific evaluation of flaring incidents, including both identification of the causes of flaring, assessment of measures to eliminate or reduce Buch flaring, and implementation of feasibLe measures tso xeduce flarinq.

b. t-. The Permittee sha11 submit a copy of the Plan to the Illinois EPA for review and comments at leasE 50 days prior to initiat startup of che delayed coker unit-

ii- The Permittee sha1l review tfre Plan on at least an annual baBis and revise the plan so that it is kept ^rl rra-l-

iii. The Permittee shall make changes to the Plan upon request by the Illinois EPA for an emission unit if required by the fllinois EPA or usEPA, as prowided for by 40 cFR 53.6(e) (3) (vii), or as otherwise required by 40 CFR 63.6(e) (wiii) [40 CFR 63.6 (e) (3) (vii) and (viii) I .

iv. Theae Plans are records required by thi6 permit, which the Permittee must retain in accordance with the general requirements for retention and awailability of recordB. In addition, when the Permittee reviges the p1an, lhe Permittee must also retain and make avaiLable the previous (i.e., superseded) version of the Plan for a per.iod of a! least 5 years after such revision.

4 -7 .7 IEEET9_ ugqr r r9s9g!9

a. i. Upon request by the lllinois EPA, the Permittee strall conduct testing of an affecEed unit under such operating conditions as may be specified by the Illinois EFA and/or USEPA. This test sha1l meet the following requirements :

A. The test shall be conducted by an approved independent testing service.

The test shall be conducted during conditionB which are representat.ive of maximum emissions during normal operation.

L1. The following methods shall be used for testing:

USEPA Reference Method 22 shafl be used ta determine the compliance of flares with the visible emi.ssj.on provisions of Condition 4.'7-i (c) (i) (40 cFR 50.18) . The observalion period is 2 hours and shall be used according to Method 22 [40 cFR 60-18(f) (1)] .

The net heating value of the gae being cornbusted in a flare shall be calculated using the equation in 40 cFR 50.18(f) (3).

The actual exit veloci.Ly of a flare shall be determined by dividing the volumet.ric flowraLe (in units of standard temperature and pressure), as determined by USEPA Reference Methodg 2, 2A, 2C, or 2D as appropriate; by the unobEtructed (free) cross sectional area of the flare tip [40 cFR 60 .1S (f) {4) ] .

D. The maximum permitted velocity, V**, for flares complying wirh 40 cFR 60.18(c) (a) (iii) shall be determined by the equation in 40 cFR 50.18 (f) (5) .

The maximum permitted velocity, v**, for air- assisted flares shall be deterrnined by the equation in 40 cFR 60.18(f) (6) . tr l-. Upon request by the Iltinois EpA, the Permittee shall conducE sampling of process streams in the Delayed coker Unit Eo obtsain xepresentative samples of the waste gases that would be sents to the flare for the Unit if wasce gases were to be flared.

ii, The Permittee shall have these samples analyzed for hydrocarbon and sul-fur content using appropriate ASTM Test methods or standard analysis methods.

The Permittee shall maintain records of the reporgs for these tests, whj.ch shal-l include the foLlowing, for at least five years from the date that a more recent test is performed :

i. The date, Dlace and time of samplinq or measuremenls,

i.i. The date (s) analyses were performed.

iii. The company or entsity that performed the analyses.

iv. The analvtical techniques or methods used.

v. The resulcs of such anafyses-

vi. The operating conditions of the unit at the time of samDlinq or measurement. 4.7 . A-L Monitoring Requirements

a. i. As provided by Lhe NSPS, compliance with the ErS standard in 40 cFR 60.r04(a) (1) shall be measured as follows: Method 11, 15, 15A, or 15 shal1 be used Eo determine the H2S concentration in the fuel gas- The gases entering the sampling train should be at about atmospheric pressure. If the pressure in the refinery fuel gas lines is relatiwely high, a flow control valve may be used to reduce the pressure. If the line pressure is high enough to operate tshe Bampling train without a vacuum pump, the pump may be eliminated from the sampling train. The sampfe shall be drawn from a point near the centroid of the fuel gas line [40 CFR 50.106 (e) (1) ] .

ii. The Permittee shall comply with the monitoring requiremenis specified in 40 CFR 50.105 for the affected units by installing, caLj.brating, maintaining and operating eittrer of the following continuous monitorinq svstems :

A. AlI instrumen! for continuousl-y monitoring and recording the conceatration by voJ.ume (dry basie, zero percent excess air) of so2 emissions i-nto the atmosphere from the affected uniEs- The monitor shall include an oxygen monilor for correcti[g the data for excess air; or

B. An instrument for continuously monitoring and recording Ehe concenlration (dry basis) of H2S in fuel gases subject to 40 CFR 60.104(a) (1) before beinq burned in the affected units,

Note: The condcusiion of procesg upset gases or fuel gas that is released to the flare as a result of relief valve leakage or other emergency maffunctions is exempt from lhe H?S limitation in 40 CFR 60.104(a) (1) - ContiBuous monit.oring is not required for exempt gas streams.

j-ii, Notwithstanding the above, the Permittee may also comply with alternative monitorirrg procedures pursuant to 40 CFR 60.13(i), if after receipt and consideration of written appfication, the USEPA approves such procedures for the affecEed units.

b. The Permittee shall continuously monitor each affected unit for the presence of a flare pilot ffame using a thermocouple or any other equivalent device to detect the presence of a ffame. [40 cFR 50.18(f) (2)] The Permj.tt.ee shalt continuously monitor each affecLed unit associated with the Defayed Coking unit for the occurrence of flow of waste gases, other than normal flow of purge gas and leakage from "closed" pressure rel,ief valves, to the affected unit,

d. The Permittee shalL continuously monitor either: 1) The flow and hydrocarbon and sulfur contenE of waste gas to each affected unit associated with the Delayed coking uniE; or 2) The operating parameters of the Delayed coking unit and affected uniEs as needed for the flow and composition of waste gas to the affected units to be det.ermlned.

The Permittee shafl keep records of the data collected by these monitorirg systems and the operation and maintenance of these moniLoring systems. including:

.4, Records of the date and duration of any time when a required monitoring instrument or device for an affected unit was not in operation, with explanation.

ii. Records to address compliance with condition 4.7.3(b) (i) of either: 1) The concentration by volume (dry basis, zero percent excess air) of So2 emissions into the atmosphere (so, monj.toringl i or 2) The concentration (dry basis) of H2S in fuel gases before being burned in the affected unit (Hrs moniEorinq).

iii. Recorde of the date and duration of any time when there was no pilot flame present at an affected unit, hrith explanation.

4.7, 8-2 Obser\ration Requirements

a. unless a continuous video inage of the flare tip of an affected unit j.s provided to the operaEor(s) in the control room for an affected unit, the Permittee sha1l conduct observation for visible emissions from an affected unit when waste gases are flared for more than 30 minutes, as follows:

t. observations 6ha1l not be required between sunaet and sunrise, during other periods when valid observations of visible emissions using USEPA Method 22 irre not possible, during periods when all personnel capable of conducting such observations are engaged in other essential tasks related to the event, and during periods when such observations would pose a significant safety hazard to an obaerver due to lhe unusual circumstances of the event.

ii. observations shal1 be conducted using Method 22 iii. observaLions shal-l begin within 45 minutes after the start of the flare event and continue on at l-easl an hourly basis thereafter.

lv. The duration of each period of observation sha11 be at least 5 minutes, after which time observation may be ended even if visible emissions are observed.

The Permittee shal1 keep a 1og or other records for thi6 acLivity that includes information as specified by Method 22 for each period of observations and information explaining h/hy observaEions, if any, were not performed for the flaring event.

4.7.9 Recordkeeping Requirements

The PermiEtee shal-I maintain records of the followinq items:

A file containing an engineering analysis for the wasEe gas recovery system for the Delayed coker unit addressi.ng compliance with conditiol 4.'7.5 (a) (iii), including a description of the recovery system. the capacity of each compressor, and informacj-on on the generation of waste gas during the different modes of operatj-on of Ehe Defayed coker Unit.

b. A file that contains documentation for the methodology that the Permittee will fo]Iow for calculating emissions from each affected unit, including:

A description of the procedure for calculating emissions attributable tso combusEion of fuel for Ehe pilot flame fue1, purge gas and waste gas.

ii. A description of the procedures for determining flows of different streamE to the flare as related to operational monitoring, if continuous monitoring is nol conducted for a 6tream.

.iii- A deBcription of the procedures for determining the composiEion of different streams to the flare as related to operational monitoring, if continuous monit.oring is not conducted for a stream, wj.th the composit.ion that wj-11 be used for different streams, with supporting documentation.

Records of the foltowing items for each exceedance of a standard, requiremert of limit in condition 4-7.3, 4.'7-5, or 4-i.6, which shalf include:

Identification of the applicable requirement (s) that may have been exceeded.

66 ii. Duration of lhe possible exceedance.

iii- An estimate of the amourt of emissions in excess of the appficable requirement (s).

iv. A description of the cause ot the possibfe exceedance.

v. Whe! compliance was reestablished.

Records for operation and emissions of each affecEed uniE, including:

i. operation and emiBsions associated with the piloE flame and purge gas Etreams.

ii. fnformation for each period rdhelt waste gas was flared, including, date, Eime, duration, reason for flaring, total volume of gas ftared*, whether any waste gas e'as recovered for fuel with estimated amount, hydrocarbon and sulfur content of the waste gas*, total emissions of vOM and SO?, detailed expfanation of reason for flaring, any measures taken to prevent similar events and other relevant information rel-ated to the flarins event.

Accompanied by support ing calculations-

Records of VOM, NO*, SOr, and CO emissions from each affected unit (tons/month and tone/year). f- Records, pursuant lo 35 IAC 20'1,.263, of continued operation of equipment vellEi'lg to the DCUF subject to condition 4.7.5(b) (i) during malfunclions and breakdown. which as a minimum, shal1 include;

i. Date and duration of malfunction or breakdown.

li. A detailed explanation of the malfunction or breakdown.

iii, An explanation why the affected equipment venting to the DCUF continued to operate in accordance with CondiEion 4.7.5 (b) (i) .

iv, The measures uaed to reduce the quantity of emissions and ehe duration of the event.

v. The steps taken to prevent simifar malfunctions or breakdowns or reduce their frequency and severity.

vi. The amount of release above tl.Flical emissions during maf function/breakdown. 4 -7.1,0 Reporting Requirements

The Permittee sha1l comply vrith the applicable reporting requirements specified in 40 cFR 60.107(e) and (f) and 40 cFR 60.105 (e) (3).

tr The Permittee shall promptly notsify the Illinois EPA of deviations of an affected unit with the permit rdquirements of this section (Section 4.7,, as follows. Reports shall include information specified in Condition 4.7.10 (b) (i) .

-t. Exceedance of the limits in Conditions 4.1 .3, 4.'1 .5, or 4.'7.6t shall be reported withih 30 days and sha11 include:

Identificatio! of the limil that may have been exceeded ,

B. Duration of the possibl-e exceedance.

An estimate of the amount of emissions .1n excess of lhe aDDlicable standard.

A description of the cause of the possible exceedance,

E. when compliance was reestablished.

Reporting of Malfunctiols and Breakdow[s

The Permittee shall provide lhe following notification and reports to the Illinois EPA, Air Cornpliance Unit and Regional Field Office, pursuant to 35 IAC 201.263, concerning continued operatj"on of equipmen! venting Eo the DCUF subject to condition 4.7.5(b) (i) during malfunction or breakdown:

1. The Permitt.ee shall notify the r11inoi6 EpA's regional office by telephone as sooD as possible during normal working hours, but no later than three days, upon the occurrence of noncompliance due to malfunction or breakdown.

Upon achievement of compliance, the Permittee shafl give a written follow-up notice wi.thin 15 days to the ltl.inois EPA, Air Conpliance Unit and Regional Field office, providing a detailed explanation of the event, an explanation why coniinued operation of equipment venting to the DcuF was [ecessary, the length of time during which operation continued under such condilions, the meaBures taken by the Permittee to minimize and correct deficiencies with

68 chronology, and when Ehe repairs rrrere completed or when the particular equipment venting to the DCUF was taken ouE of Eervice.

c. If compliance is noL achieved wiEhin 5 working days of the occurrence, the Permittee shall submit interim status reports to the l]linois EPA, Air Compliance Unit and Regional Field Office, within 5 days of the occurrence and ewery 14 days thereafter, unEil conpliance is achieved. These interj-m reports shall provide a brief explanation of the nature of the malfuncti.on or breakdown, corrective actions accomplished to daLe, actions anticipated to occur with schedule, and the expected date on which repairs will be complete or the particular equipment venting to the DcItF will be Eaken ou! of service. ii. The Permittee shall submit semi-annual malfunction and breakdown reports to Ehe fLlinois EPA consistent with the source'6 CAAPP permit. These reports may be submitted along with other semi-annual reports required by the source's CAAPP permit and shall include the follow.ing information for malfunctions and breakdowns of equipment venting to the DcttF during the reportiog period:

A listing of malfunctions and breakdowns, in chronoloqical order, that includes:

The date, t ime, and duration of each incident -

The identity of the affected operation (s ) involved in the incident..

Dates of lhe nobices and reports of Conditions a.7.10 (c) (i) .

Any supplemerrtal information the PermiEtee wishes to provide to the notices and reportE of CondiEions a.7.10 (c) (i) .

The aggregate duration of all incidents during the reporting period.

If there have been no such incidents durj.ng the reporting period, this shall be stated in the report .

With its Alnuaf Emission Report, the PerrniEtee shall submit a report to the rllinois EpA for flarirg by each

69 affected unit during the previous year, which report shal1:

a. List each event during the year when waste gas was flared. with a description of the event, including cause, amount of emissions and duration.

ii. summarize flaring activity and emissions during the previous year, includirg an assessment of the cause(s) tor such flaring as related to the number of events and share of emi.ssionB.

iii- Include copies of the summaxies for flaring activlty for the preceding three years, as reported in earlier reports.

iv. Provide an analysis of the amount of waste gas chau was recovered aB related to the amount of waste gas that was flared.

Summarize actions or measures implemented during the previous year Eaken to reduce flaring, and the reason for and observed effec! of these actions.

vi. Summarize actions or meaEureE planned for implementation during the current year to reduce flaring, and the reaaon for and expected effect of these actions. d. with the periodic monitoring reports required by the CAAPP pexmit for the 6ource, for any reporting period in which significant flaring incident(s) occurred, the Permittee shall submj-t report(s) to the Illinoj.a EPA for the root cause analysis performed for the incident (s) pursuant to Condition 4 .7 .5 (a) (vi). 4-B Sulfur Recovery Unit.s (SRU)

4.8.1 nF c -ri hf i ^-

As part of the CORE project, bwo additional sulfur recovery trains (SRU-E and SRU-F) wi.1] be constructed. Each SRU will have a separate Claus Unit, a Tail cas Treating Unit (TGU) and Thermal oxidizer -

Also constructed vrill be additional suLfur storage and loading facilities- The vapors recovered from the slorage and loading facilities will be routed to the Claus Trains or TGU to ensure that captured residual HrS/SO, is controlled.

4.4.2 List of Emission Units and Air Pollution Control. EquiDment

Emis sion Emission control Unit Description Equipment SRU-E suLfur Recoverv unit "E" TGU (TGU-E), Thermal Oxidizer SRU.F Sulfur Recowery Unit 'F' TdII /T':TT-F1 Thermal oxidizer

4.8.3 AppLicable Provisions and ReguLatj-ons

a. An "affected unit" for the purpose of these unit-specific condiEions, is a eulfur recovery unit described in CondiLions 4-8-1 and 4.8.2.

b. NSPS Provisions

The affected units are subject to the NSPS for Petroleum Refi-neries, 40 cFR Part 50, Subpart .f.

Each affected unit is subjects to 40 CFR 60-104(a) (2) (i), which provides that no owner or operator shall discharge or cau€re the discharge of any gases into the atmosphere from any C1aus sulfur recovery planE (oxidation control syst.em foLlowed by incineration) containing in excess of 250 ppm by volurne (dry basis) of sulfur dioxide (sor) at zero percent excess aar.

l"t The Permittee shal1 compty with atl appticable requirement.g of 40 CFR Part 50, Su.bpart ,J for the affected units.

NESHAP Provisions

The affected units are subject to the NESI{AP for petroleum Refineries: catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units, 40 CFR Part 53, Subpart IJuU.

7l a- The Permittee shall comply with the applicable requirements for HAP emissions from sulfur recovery units in 40 CFR 63.1568. In partlcufar, the Fermj.ttee sha]l comply with the emission limitaEions for NsPs units, pursuant to 40 cFR 63.1568(a) (1) -

ii. The Permittee shall comply wiLh a1I applicabl.e requiremenEs of 40 CFR Part 63, Subpart UttU for the affected unit.s .

State Provis.ions

a, The affected units are subject to 35 IAc 2I4.382(bl , which provides that no person sha11 cause or aI1ow the emiBsion of more than 1,000 ppm of sulfur dioxide into the atmosphere from any new process emission source in the St. Louis (Illinois) major metropolitan area des.igned to remove sulfur compounds from the flue gases of petroleum and petrochemical processes. compliance with this standard shall be demonstrated on a three-hour block aweraqe basis.

4.4.4 Non-AppLicabi l ity of Regulationg of Concern

None ,

4.8.5 Control Requirement.g and work Practices

a, i. BACT/LAER Technology

The tshermal oxidizer on each affecEed unit thall be maintained and operaEed with good combuscion practice to reduce emissi.ons of CO and VOM.

Lt. BACT Emission Limit

Emissions of co from the affecEed units shall not exceed 0.082 lb,/mmBtu. Itrfi/.

ar. !AE;l< _E;maES.aOn lJlmlE

Emissions of voM from each affected unit shall not exceed 0.005 lb,hmBEu, rury.

Note: Condilion 4.8.5(a) (i) and (ii) represenE the application of the Best AvailabLe Control Technology. Condition 4.8.5(a) (i) and (iii) represent the application of the Lor,vest Achievable Emission Rate.

b. The Permittee shall aperate the affected unitB and associated ai.r polfution control equipment in a manner consistent with good ai.r potlution control practices for minimizing emisBions set forth in 40 CFR 60.11(d) . The Permittee shall prepare an operaLion, maintenance, and monitoring pl.an according to the requj-rements in 40 CFR 63-1-574 (f) and operate at all limes according to the procedures in rhe plan [40 CFR 63 - 1568 (a) (: ) ] .

d. The permittee shall comply with the applicable general requirements for affected units identified in 40 cFR 63.1570.

Production and Emission Limitati-ons

a. Annual emissions from the affected unlts shalf not exceed the fof lowinq l imiEg :

NO" co voM SO: PM/PM1O Equipment (Tons/Yr) (TonslYr) (Tons/Yr) (Tons,/Yr; (Tons/Yr) SRU-E 18.4 278.7 2.O 'l- SRU-F 18.4 -4 2.O

b. compliance with annual limite shall be determined on a monthly basis from the sum of the data for the current month pJ.us the preceding 11 months (running 12 month total).

4.4.1 Testing Requirementa

a. within 50 days after achieving the maxj,mum production rate aE which each affected units r^rill be operated, but not later than 180 days after initial startup of Ehe affected units and at such other times as may be required by the USEPA under Section 114 of the Act, the Permittee shaL] conduct performance tesE (s) and furnish the Illinois EPA and USEPA a written report of the results of such performance test (s) [40 CFR 60.8 (a) ] .

b. I. The rnethod and procedures specified by ttre NSPS, 40 CFR 60.105 and 50.108, 6ha11 be used for testing of so2 emissions and opacity, unleBs USEPA approves an alternalive test method pursuant to 40 CFR 50.8.

ii. Appropriate USEPA Reference Methods in 40 CFR Appendix A shall be used for testing of No* and co emfss]-ons.

4.8,8 Monitoring Requirements

a. The Permittee shal1 comply with the monitoring requirements specified in 40 cFR 50.105 for the affected units by installing, catibratinq, maintainj-ng and operating the following continuous monitoring system:

a. An instrument for continuously monitoring and recording the concentration (dry basis, zero percent excess air) of so2 emissions into the atmosphere - The monitor shall include an oxygen monitor for correcting the data for excess air [40 cFR 60.10s (a) (5) I.

A. The span vafues for Ehis monitor are 500 ppm so, and 25 percenr o, [40 cFR 50.105 (a) (s) (i) ] .

B. The performarlce evaluations for this SOz monltor under 40 cFR 60.13(c) Bhall use Performance Specificafion 2 - Methods 6 or 6C and 3 of, 3A shalf be used for conducting Ehe relative accuracy evaluations [40 cFR 60 . 105 (a) (s) {ii) 1 .

ii. Notwithslanding the above, the Permittee may also comply rrrith alEernative monitoring procedures pursuant to 40 CFR 60.13(i), if after receipt and consideraEion of rrritten application, the USEPA approves such procedures for the affected units.

b. NESHAP Monitorinq Requi-rements

.1 . The Permittee sha11 install, operate, and maintain continuous monitoring system to measure and record the hourly average concentration of so, (dry basis) at zero percenL excess air for each exhaust stack. This sysEem must j.nclude an oxygen monitor for correctilg the data for excess air [40 CFR 63 .1s68 (b) (1) I .

Recordkeeping Requirements

a. The Permittee sha1l maintain records of sulfur production (Iong tonE/day, long tons/monih, and long tons/year).

b. The Permittee shall maintain records of emiesiong of No", CO, VOM, SO2, and PM/PMro (tons,/month and tons/year).

4.8.10 Reporting Requirements

a. Reporting of Deviations

The Permittee sha11 prornptly notify the Illinois EPA of deviations of an affected unit with the permit requirements of this section (seccion {,8). Reports shall include information specified in Condition 4.8.10(a) (i).

L. Vlithin 30 days of exceedance of the limits in Condition 4 .8.5.

b. The Permittee shall comply with the appticabte reporting requirements specified in 40 CFR 60.10?(e) and (f).

74 For the purpose of reports under 40 CFR 50.7(c) , periods of excess emissions that shall be determined and reporLed are defined as follows [40 CFR 50.105(e)] |

i. AII 12-hour periods during which the average concentration of SO, as measured by the SO, continuous moniEoring system under 40 CFR 60.105(a) (5) exceeds 250 ppm (dry basis, zero percent excqss air) [40 CFR 60.los(e) (a) (i)],. or

ii. All 12-hour periods during which the average concentration of reduced sulfur (as sor) as measured by the reduced sulfur continuous monitoring system under 40 cFR 50.105(a) (6) exceeds 300 ppm [40 cFR 50.105 (e) (a) (ii)l ; or

iii. AI1 12-hour periodg during which the average concentration of so, as measured by the SO, continuous monitoring system under 40 CFR60.105 (a) (7) exceeds 250 ppm (dry basis, zero perceDt excess air) [40 cFR 60.105(e) (4)(iii)]. d. The Permittee shall submit the notificaEion of compfiance status containing the results of the initj.al compliance demonstration according Eo lhe requirements in 40 cFR 63.Ls74 [40 CFR 63.1558 (b) (7) ] .

75 4.9 Miscellaneous PM Ernission Units

4.9.7 nAd^ri ht- i ^n

Addj.tional catalyst loading operations wil,l be needed due to the restart of FCCU 3. These emissions are fugitive in nature consisting entirely of particulates. catalyst hopper vents will be routed to Ehe WGS at FCCL 3.

The storage and handling of coke produced at the new delayed coking unit will generate fugitive particulate emissions. These coke handling operationa include several new conveyor and crane transfer points, a neh' crusher, front-end loader (FEL) lraffj-c, and load.ing of coke haul trucks.

4.9.2 List of Emission Units and Air Pollution Control Equipment

Emission control Emis6ion unit DescripEion Equipment FCCU 3 Catalyst Loading at FCCU 3 None Catalyst Loading coke Handl ing Coke Handling None

4.9.3 Applicable Provisions and Regulations

a. The "affected units' for the purpose of these uniE- specific conditions, are the units descrlbed in conditions 4.9.1 and 4.9.2.

The affecced un.ite are subject to 35 IAC 212.301 and 3s rAc 212.123 (See afso Condition 3.2.21a) and (b))

4.9.4 Non-Appl icabi lity of Regulations of concern

Non- appl icabi lity of regulations of concern are not set for the affected units.

4.9.5 Contsrol Requirements and Work Practices

Control requirement.s and work practices are not set for the affected units.

Production and Emission Limitations

The maxj.mum catalysts loading rate aE FCCU 3 shall not exceed 10 tons/day (12-month rolLing average).

.11 Emissions from the affected catalyst loading operatior at FCCU 3 shal1 not exceed the foflowing limits. compliance witsb the annual limits shall be determined from a runnincr total of 12 months of data:

76 Emi6sions Pollutant (Tons/Month) (Tons/Year) PM o.2 1-1 PMro 0.3

L .t- The maximum coke processed shall not exceed 5,400 dry tons/day (12-month rolling average) .

ii. Emissions from the affected coke handling operations shalL not exceed the following limits. compliance with the annual limits shall be deterrnined from a rrrnnincr r-^tal .rf 12 months of data:

Emi s sions Pollutant (Tons/Month) (Tons/Year ) PM '7.O PMr o

4 -9 -7 Testing Requirements

Testing requirements are not set for the affecEed units.

4.9.8 Monitorlng Requirements

Monitoring requirements are not set for the affected units.

4.9.9 Recordkeeping Requi rements

The Permittee shaLl maintain records of the followinq items:

a. Catafyst loading rate at FCCU 3 (tons/day) .

b. Coke processed (dry tons/day) ,

c. PM and pMro emj-ssj.ons (tons/month and tons/year) from the affecbed catalyst loading operation and the affecEed coke handling operaEi.on with supporting calculations arrd documentatioa.

4.9.10 Reporting Reguiremencs

a. ReporEing of Deviations

The Permittee shall promptly notify the Illinois EPA of devj-ations of an affected unit with the permit requirements of this section (Section 4.9) . Reports shall include informatsion specified in Condition 4.9.10(a) (i) .

i. within 30 days of exceedance of the limite ln Condi.tion 4.9.6-

77 4.10 tJagtewater Treatment Plant

4 - 10. 1 Description

The !,rastewater treatment plant (WWTP) will be modified to accommodaEe an increase in wastewater flow and solids and orgauic loading due to increased refining operations and to treat the wasEewater from Lhe new WGS orl FCC Units, The modifications include new Bcrubber solids clarifiers, reconfiguring Pond 1 to activated sludge service, modificationa to Pond 2 with a denitrification zone added to the back of the pond, and a new fj.nal clarifier. In addition, new proces€r surnps will be installed to supporE Ehe new and expanded process

Emissions from the existing primary treatment system, which are controlled by flares, are addressed in SecEion 3.4.3 (Debottlenecked Flares) of this permit.

4.Lo.2 Lis! of Emission Units and Aj-r pollurion_llgqqIql-EgglpqEqq

Emiss ion Em.iss ion Control Uni E Descxiption Equipment IIWTP New scrubber solid8 clarifiers, None reconfiguring Pond 1to activated sludge service, modificaEions Eo Pond 2 with a denitrification zone added to the back of the pond, and a new final clarifier. Ne!'r Final Clarifier (Secondary) None

4.10.3 Applicable Provisions and Re$.llations

a- The "affected uniEs" for the purpose of these unit - specific conditions, are the units described in conditi.ons 4.10.1 and 4.L0.2.

b. Certain existing equipment associaEed wj.th the affected unibs are subject to the following rules, as further described in the source's CAAPP permit:

NESITAPfor Betzene Waste Operati"ons, 40 CFR 61 Subpaxt FF NESHAP for Refineries, 40 CFR 53 Subpart cc NSPS for Tanks, 40 CFR 50 Subpart Kb I'TSPSfor Refinery WaBtewater Systems, 40 CFR 50 Subpart QQQ

4.10.4 Non-Applicabi l ity of Regulations of Concern

Non- applicabil ity of regulations of concern are noE set for the affected units .

7A 4.10.5 Control Requirements and Work Practiceg

a. LAIR Technology

1. The WWTP6ha11 be operated in accordance with good air pollution controf practice lo minimize emissions of voM.

Condition 4.10.5(a) represents the application of the IJowest Achievable Emission Rate. Specific provisions setting LAER for the scrubber soLids clarifiers, denitrification zone, and final clarifier are not being established due Eo the small amount of VOM beinq emitted from these nnFr': I i .ins

4.10.6 Production and Emission timitations

a. voM emission from the wwfP, in total, shall not exceed 8.5 tons/month and 84 .7 Eons/year.

l^ voM emissions from the new scrubber solids clarifiers 6ha11 not exceed 1.0 tons/year.

compliance with the annual limits shal1 be determined from a running total of 12 months of data using Water 9 or other simitar USEPA methodology for determination of VOM emission from vrastewater treatment plants.

4 .a0 .'7 Testing Requirements

a. The Permittee shall comply with the applicable test methods, procedures, and compliance provisions at 40 CFR

4. L0.8 Monitoring Requirements

a. The Permiltee shalJ. comply with the applicable mooitoring of operations at 40 CFR 51.354.

4.10.9 Recordkeeping Requi

a. The Permittee shal1 comply with the applicable recordkeeping requirements at 40 CFR 61.356.

b. The Permittee shafl maintain records of the followinq items:

i. Throughput (millions gallons/day) .

ii. voM emissions (tons/month and tons/year) from the affected units with supporEing calculations and documenLation.

79 4, 10. 1-0 Reporting Requirements

a. 'rhe Permitt.ee shall comply with the reporting requirements at 40 cFR 61 -357.

11 Reporting of Deviations

The Permittee shall pronltr)tly notify the lllinois EPA of deviaEions of an affected unit with the permit requirementss of this section (4.10). Reports shall include information specj-fied in Condition 4.10.10(a) (i)

i- Within 30 days of exceedance of the limits in Condition 4.10.5.

80 4.11 Roadways and Other Open Areas

4.11.1 Description

The affected units for the purpose of these unit-specific conditions are roadways, parking areas, and other open areas which are affected by the new CORE process units, and which may be sources of fugitive parli,culate matter due to vehicle traffic or wind blown dust. These em.issions are conErolled by paving and implementation of work pracEices to prevent the generation and emi.seions of particulate matter.

4 .77 .2 List of Emission Units and Air Pollution Control Equipment

Emi ss ion Ernission ControL Unit Description Egu.lpmenL Roadways and Paved and unpaved roads ; Fugiiive Dust OEher Open parking lots; other open Control Program Areas areas.

4.].L.3 Applicable Provisions and Requlations

a, An "affected unit" for the purpose of theBe uniE-Epecific conditions, are the units described in Conditions 4.11.1 and 4.11 .2.

t. The affected units are subject to 35 IAC 2I2.301,, which provides that no person shall cause or allow the emiss.ion of fugitive particuLate matter from any process, including any material handling or storage actiwity, tha! i6 visible by an observer looking generally toward the zenith at a point beyond the property line of the source.

ii Not withstanding the above, pursuant to 35 IAC 2L2.3L4, the above limit sha1l not apply and spraying to control fugitive dust pursuant to 35 IAc 2L2.3O4 through 272.370 and 212.312 sha1l not be required when the wind speed is greater than 25 mile/hour (40.2 km/hour), as detsermined in accordance with the provisions of 35 IAC 2f2.3L4.

The affected units are subject to 35 IAC 212-305, which provides that all normal traffic pattern access areas surroundi-ng storage piles specified in 35 IAC 212,304 arrd all normal traffic pattern road6 and parking facilities shall be paved or. lreated with water, oils or chem.ical dust suppressants. A1f paved area6 shalf be cleaned on a regular basis, A11 areas treated with wat.er, oils or chemi-cal dust suppressants shall have the treatment applied on a regular basis, as needed, in accordance with the operating program required by 35 IAC 2a2.309, 2L2.3LO ar\d,2L2.31,2 (see also Condition 3.3.1). 4 -Lr .4 Non-Applicabi l ity of Regulations of Concern

Non-appl icabi lity of regulations of concern are not set for the affected units.

4 .l-i. - 5 Control Requirements and Work Practices

a. cood air pollutioll corrtrol practices shall be implemented to minimize and significantly reduce nuisance dust from affected units associated with the coRE projecL. After conEtruction of the CORE project is complete, theEe practices shall provide for pavement on all regularly travefed roads and treatmenL (flushing, vacuuming, duats suppressant application, etc.) of roadways and areas that are routinely subject to vehicle traffic for wery effective control of dust (nominal 90 percent control) .

For this purpose, roads that serve any new permanent office building, new employee parking areas or are uEed on a daily basis by operating and maintenance personnel for the refinery in the course of thej-r typicaL duties, roads that experience heavy use during regularly occurring maintenance of the refinery during the course of a year, shall alf be considered to be subject to regular travel and are required to be paved. Regularly traveled roads shalf be considered to be subject lo routine vehicle traffic except as they are used primarily for periodic maintenance and are currently inactive or as traffic has been temporarily blocked off. Other roads sha1l be considered to be routinely traveled if activities are occurring such that ttrey are experiencing significant vehicle traffic.

The handling of material collecced from any affected unit associated with lhe refinery by sweeping or vacuuming trucks shall be enclosed or shal1 utilize epraying, pelletizing, screw conveying or oiher equivalent methods to control PM emissions.

4.1-l-.6 Production and EmiBsion Limitations

a. The emissions of fugitiwe dust from roadways and parking lots sha11 not exceed 59.3 tons/year of PM and 11.6 tons,/year of PMro.

b..' Compliance wj.th annual limits shall be determined on a monthly basis from the sum of the data for the currenC month plus the preceding 11 months (running 12 monEh total ) . 4.11,.7 Testing Requirements

a. Opacity Measuxement Requirements

1. The Permittee sha1l conduct performance observations, which include a series of observations of the opacity of fugitive emiasions from the affected units as follows to determine the range of opacity from affected units and the change in opaci.ty as related to the amount and naLure of vehicle traffic aod implementation of the operating program. For performance observations, the Permittee sha1l submit test plans, test notificaEions and test reports, as specified by overall Source condition 3.5.2.

A. Performance observations Bhall first be completed no later than 30 days after initial startup of the coRE project, in conjunction vrith the measurements of silt loading on the affected units required by Condition 4.11. ? (b) .

B. Performance observations shall be repeated within 30 days in the event of changes involving affected unlts that would act to increase opacitsy (so that observations that are represeatative of the currenL circumstances of the affected units have no! been conducted), including changes in the amount or tl4)e of traffic on affected units, changes in the standard operating practices for affected ^--licaEion aD dPl]- of saft or traction material during cold weather, and changes in the operating program for affecLed unitss-

f a. compliance observations sha1l be conducted for affected units on at least a quarterly basis to verify opacicy levets and confirm the effectiveness of the operating program in controlling emigsions.

,1ta. Upon written request by the Illinois EPA, the Permittee shall conduct performance or compliance observations, as specified in the reques!, Unless another date is agreed to by the Illinois EPA, performance observations sha1l be completed within 30 days and compliance observations shall- be completed within 5 days of the Illinois EpA's request.

Silt Loading Measurements

i. The Permittee sha1l conduct measurements of the silt loading on warious affected roadway segments and parking areas, as follows r

83 sampfing and analysj-s of the silt loading sha11 be conducted using the "Procedures for sampling surface/Bu1k Dust Loading," Appendix c.1 in compilation of Air Pollutant Emission Factors, USEPA, AP-42. A series of samples shall be taken to determine the average silt. loading and address the change in sitt loadings as related to the amount and natsure of vehicle traffic alld implementation of the operating program.

ii. Measurements 6ha11 be performed by Ehe following dates:

Measurements shall first be completed no fater lhan 30 days after the date that initial- startup of the CORE project is compfeted.

MeaauremenLs shalt be repeated within 30 days in the event of changes involving affected units that would act to increase silt loadiag (so that data that is representative of the current circumstances of the affected unitB has not been collected), including changes in the amount or t)?e of traffic on affected units, changes in the standard operating practices for affected units, such as application of salt or traction material during cold weather, and changes in the operating program for affected units.

c. Upon written requesc by the Illinois EPA, the Permittee shaLl conduct measurements, as specifi-ed in the request, which shall be completed within 75 days of the Illinois EPA'e requesE.

iii. The PermitLee shall submit test plans, test notifications and test reports for these measurements as specified by Overall Source Condition 3.5.2, provided, however, that once a test plan has been accepled by the l11.inoi6 EPA, a new tesC plan need not be submiEred if the accepced pLan wj.l.1 be followed or a new test plan iE requested by the Illinois EPA.

4.11.8 Monitoring Requirements

Monitoring requirements are not set for the affected unies.

.11.9 Recordkeeping Requirements

The Permittee shall maintain records of the folfowing items for the affected units: The Permittee shal1 maintain records for each period of tirne when it relies upon the exemption provided by 35 IAc 212 -314 to not comply with 35 IAC 212.301 or implement measures otherwise required by 35 lAC 212.3o4 through 2I2-3lOt or 2L2.31-2, with supporting documentation for the det.ermination of wind speed, b. The Permittee shal1 maintain records documenting implementation of the operating program required by Condition 4.11.3 (c) , including:

.1 . Records for each treaEment of an affected unit or unt Es :

The identity of tbe affected unit{s), the date and time, and the identification of Ehe truck(s) or treatment equipment used;

For application of dust suppressant by truck: target application rage or truck speed during application, total quartity of water or chemical u6ed and, for application of a chemical or ctremical solution, the identity of the chemical and concenlraEion, if applicabfe;

For skreeping or cleaning: rdentity of equipment used and identification of any deficiencies in the condiEion of equipment i and

For other tl4)e of treatment: A description of the action that was taken.

ii. Records for each incident when control measures were not implemented and each incj.dent when additional control measures were impfemented due to particular activities, including description, date, a statement of explanation, and expected duration of such cfrcumstances -

1. The Permittee shal1 keep records for the silt measurements conducted for affected units pursuant to condition 4.11.7(b), including records for the sampling and analysis activities and results.

ii. The Permittee sha11 maintain recordE for all opacity measurements made in accordance with USEPA Method 9 for the affected units Eha! Lhe Permittee conducts or that are conducted on its behest by individuals who are gualified to make such observations. For each oaa"*ion on which such measurements are made, these records sha1l include the formal report for the measurements if conducted pursuant to Condition 4.al.7(a), or otherwise the identity of the observer, a description of the measurements that vtrere made, the

85 operaEing condition of the affected unit, the obgerved opacity, and copies of the raw data sheets for the measurements. d. The Permittee sha1l maintain records for the PM emissions of the affected units to verify cornpliance with the limits in Condilion 4.L1.6, based on the above records for the affected units including data for implementation of the operating program, and appropriate USEPA emiBsion estj-mation methodology and emission factors, wich support ing calculations .

The Permittee sha1l maintain the follo.^'ing records related to emissions of fugitive parEiculate matter from affected units. As records of certain information are to be kept in a fi1e, the Permittee shall review and update such information on a periodic basj-s so that Lhe file contains accurate information addressinq the currenE circumstsances of the source.

A file that contains information on lhe length and state of road segments at the plant, the area aud state of other open areas at the source traveled by vehicles, and the characteristics of the various categories of vehicles present at the source ag necessary to determine emissions -

.1f A file that containa information for the emission control efficiency or controlled emission factorB (lb,/vehicle mile traveled) achieved by the standard management practices implemented by the Permj"ttee pursuant to its operating program for the various categories of vehicles on the road segments and open areas at the source, based on methodofogy for estimaling emissions published by USEPA, with supportiag explanation and calculations.

iii, For emisBion that are not controlled or for which emissiong are determined by apptying a conlrol efficiency to an uncontrolled emisB.ion factor, information for the standard emission factors (lblvehicle mile travel-ed) uEed for uncontroLled emissions for the various categories of vehicles on the road segmentss and open areas at the source, based on methodology for estimating emissions publi.shed by UsEpA, witsh supporting explanation and calculations.

iv. Records of the estimated vehicle miles travefed on each roadway segment of, other open area (mi1es,/month, by category of vehicle), with supporting documentation and calculations. These records may be developed from the recordEi for the amount of different materials handled at Ehe source and informat.ion in a file that describes how different materiaLs are handled.

Records for each period when standard management practices were not implemented, including a description of the event, an estimate of control measures that were present during the event and an estimate of the additional emissions that occurred .l,rri hd l-ha 6rr6h+

VL Records for enj-ssions, in lon/month, based on the emission factors and other information contained in other required records, with supporting calculations

4. 11.10 Reportlng Requirements

a. The Permittee shall- promptly notify Che lflinois EPA of deviations with permit requirements by affected units as follows- Reports sha1l describe the probable cause of such deviations, any corrective actions taken, and preventive measures taken and be accompanied by the relevant records for the incident:

Notification wirhin 30 days for any incident in which 35 IAC 212.301 mav have been violated.

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PSD Applicability - No* Netting Analysis

Contemporaneous Time Period: July 2002 through october 2009

Tabl€ I - Project higsions Increarea and Decrea8€E

Emission Change Proj ectlActivity (tons/Year) CORE Proj ect -47 .5

Table fI - sourcE-wide Creditable CoDteuporaDeaua Eniaaion Increaaea

Permrt Emisslons Increase Proj ectlActivity Number Date (Tons/Year) North Propertv Flare 06030049 6 / 2OO'7 a.2 Low Sulfur casoline (SZU) 05050062 2 / 2001 20 .6 Ultra Low Sulfur Diesel 04050025 4 / 20O6 l{artford Inteqration 03080005 4 / 2OO4 524.2 Tier 2 01120044 L1-/ 2O03 FCCU 1 Alterations (Boiler 17) 03030059 9/ 2OO3 Total: 804.8

TabLe III - gource-wide Creditable Contenporaneoue EmiEELon Decreasea

Emissions Decrease Proj ectlActivity Date (Tons/Year) Nort.h P-roperty cround Flare Decommissioned 7/ 2OO'7 }(tP Snl]EOOWn 12/ 2002 CR-3 2"" Reheat Heater (fue1 switch) L1-/ 2O02 46.7 CR-3 1" Reheat Heater {fue1 switch) rr/ 2oo2 113.1 cR-3 Charge Heater (fuel switch) n / 2002 No- 2 Crude Unit, H-25 \o / 2002 29 .7 Isom Unit, H-33 (Hartford Inteqration) LO/ 2O02 Isom U[it, H-32 (Hartford Integration) ro / 2002 10.8 'J-o T.SR Hydrotsreating, H-31 (Hartford Integration) / 2O02 7.1 Hydrogen PlanE, H-30 (Hart.ford Inteqration) 10/ 2002 10.0 Alkylation Heater, H-19 (Hartford Integration) lo /2002 20.8 RerouEe/Elimination of Flare Sgreams at Harlford 1O/2O02 r7.4 FCCU Shutdown at Hart.f ord r0 / 2o02 320.0 ToEal : 732.5

Table IV - Net hriEaionB Cbange

(Tons/Year) Increases and Decreases Associated With Proposed Modification -47 .5 Credi table Contemporaneous Emi-ss ion Increases 804.8 Credi table Corrtemporaneous Emi ss ion Decreases 732.6 AEtachment 2b

Non-attainment NSR Applicability - NO* Netting Analysis (8-hour Ozone)

Contemporaneous Time Period: May 2001 throuqh October 2009

Table I - Projech tuiaaiona Incr€aaea and DecreaE€a

Emission change Proj ect/Act ivity (Ton6/Year) CORE Proj ect

Tabl€ II - Source-ltide Cr€ditable CotteBporaneous hisaiolt Incr€aaea

Perm].i Emissions Increase Proj ect/Activity Number Date (Tons/Year) North Propertv Flare 06030049 6/2007 L.2 Lor,, sulfur casoline (SZu) 05050062 2/2007 20.6 Ultra IJow Sulfur Dieset 04050026 4 / 2006 Hartford Integration 03080005 4/2004 Tier 2 01120044 7]./2003 FCCI 1 Alterations (Boiler 1?) 03030059 9 / 2OO3 1.8 RAU Steam Reboiler 01050090 70 / 2007 24 .4 Total :

Table III - Sourc€-Vlide Creditable Conbqporaneou8 hliasiolr D€creases

Emissions Decrease Proj ect./Activity /r|1^h< /varrl North Property Ground Flare Decammissioned 7/ 2001 RFP Shutdown 12/ 2002 CR-3 2"" Reheat Heater (fuel Bwitch) ar/ 2002 46.7 CR-3 1"! Reheats Heater (fue1 switch) 1L/ 2002 llt 1 CR-3 Chafge Heater (fue1 switch) rr | 2002 115.8 No. 2 Crude UniE, H-25 ro/ 2002 Isom UniL, H-33 (HarEford Inteqration) 10/ 2OO2 Isom Unit, H-32 (Hartford Inteqration) LO/ 2002 10.8 l,sR HydrotreaEing, H-31 (Hartford Inteqration) 70 / 2002 Hydrogen Plant, H-30 (Hartford lntegration) 10/ 2002 10.0 Alkylation Heater, H-19 (Hartford Inteqration) ro/ 2002 20 .9 Reroute/El imination of Flare Streams at Hartford r.o/2o02 L1 .4 FCCU Shutdown at ltartford 10/ 2002 320.0 CR-1 2nd Inter-reactor Heater, H-3 (Fuel Switch) 2 / 2002 1t I CR-1 1st Inter-reactor Heater, H-2 (Fue1 Switch) 2/ 2002 19.1 CR-1 Feed Preheat, H-l (Fuef Switch) 2/2002 RAU Deethanizer Heater Shutdown 1,O/ 2001, Total : 822.9 Iv - Net EmiasionE Clrauge

(T'ons/Year) Increases and Decreases Associated With ProDosed Modification Creditable CoDtemporaneous Emission Increases 897.1 CrediEable Contemporaneous Emission Decreases -11.4 Attachment 3

PsD Applicability - co Netting Analysis

Contemporaneous Time Period: July 2002 through October 2009

Table I - Project EmigEions llcreaaas and Decreaa€a

Emission Change Proj ect,/Activity (Tons/Year) CORE Proj ect 1, O4'1.4

Table If - Source-Wide Credita.ble ContesrDoraneous EniaEio! Increaaet

Permit Emissi-ons Increase Proj ect/Aclivity Number Date (Tons/Year) NorEh Property Flare 05030049 6/ 20O7 Low Sul"f ur Gasoline (SZU) 050s0062 2/ 2007 40.6 Ultra Low Sulfur Diesel 04050026 4 / 2006 '10 Tier 2 01120 044 1ll2003 .'1 FCCU 1 Alterations (Boiler 17) 03030059 9/ 2003 1.1 Total :

Table III - Sourc€-Wide Cr€ditabte eonleuporaneous Emiasion Decreaseg

Emi-ssi.ons Decrease Proj ects/Activity Date (Tons/Year) HTR-VF1-North 72/ 2O09 HTR-VF1- Soutsh 1-2/ 2O09 I{TR-BEU-HM1 Shutdovm 72/ 2Ooa HTR-BEU-HM2 Shutdown L2/ zOOa Boil,er 15 Shutdowrr 1"2| 20Oe a1 '7 North Property Ground Flare Decornmissioned 1/2007 HTR-KHT 4/ 2OO6 RFP Shutdown L2/ 2OO2 No. 2 Crude Uni.t, H-25 IO/2O02 7.4 Isom Unit, H-33 (Hartford Inteqration) 1O/ 2002 Isom Unit, H-32 (Hartford Integration) to / 2o02 LSR Hydrotreating, H-31 (Hartford Inteqration) ro/2oo2 0.4 Hydrogen PlanE, H-30 (Hartford Integration) r0/ 2002 Alkylation Heater, E-19 (Hartford Inteqration) 1O/2O02 FCCU Shuldown at Hartford 70/2002 Total : 244.4

Iable IV - NeE EmisaionE Change

(Tons/Year) IncreaBes and Decreases Associated with ProDosed Modification 1 na't /L Creditable Contemporaneous Emission Increases ztr.4 creditable contemporaneous EmiBsion Decreases 2AA,4 9'70 .4

3-1 AtEachment 4

PSD Applicability - SO, NeEting Analysrs

Contemporaneous Time Period: July 2002 through October 2009

Table I - Project EmiagionB Ircreagea aEd DecreaEea

Emission change Proj ect /Aceivity (rons/Year) CORE Proj ect

Table II - Source-Wide Crealltab!-e Corrt@paraneous hLssLoll Incr€aEes

Permlt Emissions Increase Proj ect/Activity Nunber Date (Tons/Year) North Propertv Flare 05030049 6/ 2007 0.1- Low Sulfur casoline (SzU) 05050062 2 / 20O1 Ultra ],ow Sulfur Diesel 04050026 4 / 2006 101.4 Hartford Int.egrat ion 03080005 4/ 2OO4 L7 .3 'r'1er 2 o1L20044 17/2003 28.O FCCU 1 Alterations (Boiler 1?) 03030069 9/ 2OO3 0.1 TotaI: L79.4

Table III - Source-wide Creditable ColteqraraDeous hiEsion DecreaE€E

Emiseions Decrease Proj ect /Activity (Tons/Year) HTR'VF1-North 1-2/ 2OO9 0.1 HTR-VF1-Sauth 72/2009 0.1 HTR-BEU-HM1 Shutdown 12/200A 1.0 I{TR-BEU-HM2 Shut.down 72/ 2OOA 0.7 Boiler 16 Shutdown 12/ 2008 North Property cround FLare Decommissioned 7/ 2007 2.9 IITR- IC{T 4 / 2OO6 7.2 CR-3 2"" Reheat Heater (fueI switch) \7 / 2002 339.0 CR-3 1" Reheat Ileater (fuel switch) rL/ 2002 646.5 CR-3 Charge Heater (fueI switch) 1"r/2O02 663.0 No. 2 Crude Unit. H-25 \0 / 2o02 0.8 't-o Isom Unit, H-33 (Hartford Inteqration) / 2oo2 Isom UniL, H-32 (Hartford Int.eqration) L0/ 2OO2 Hydrogen Plant. H-30 (Hartford Intesration) ro / 2002 0.3 Alkylation Heater, H-19 (Hareford InteqraEion) LO/2OO2 FCCU Shutdo\,rn at Hartford LO/ 2OO2 Total:

Iabl€ IV - Net tuiiagion8 Change

(Tons/Year) Increases and Decreases Associated With proposed Modification Creditabfe Contemporaneous Emission Increases L79.4 Creditable Contemporaneous EmiBsion Decreases 1,733.6 -11,137.3 Attachment 5

Non-atEainment NSR Applicabillty - VOM Netting Analysis (8-hour Ozone)

Contemporaneous Time Period: May 2001 lhrough October 2009

Iab].e I - Projacts EmisaionE Increaaes aDd Desr€ases

Emission change Proj ect /Activity (Tons/Year) CORE Proj ect 382 .7

Table II - Sourc€-gtide Credleable ContsenlroraneouB tuj.ssion IncreaEeE

Permit Emiaaions f ncreas'e Proj ect /Activity Number (Tons/Year) Tank A-39-1 06100062 7/ 2OO7 Tank A-49- 1 05100052 7 / 2008 Tank CH- 243 06100051 6 / 2OO1 o,2 Norlh Property Flare 06030049 6/ 2007 2.4 Low Sulfur Gasoline (SZU) 05050062 3/ 2OO7 Ultra Low sulfur Dieset 04050026 4 / 2006 Tanks 32-1 and 33-1 05090047 3/ 2005 Tank 403 (Terninal) 05050044 9/ 2005 Tank A-19-1 03020012 5 / 200s Hartford Inteqration 03080005 4 / 2004 Tank A- 157 03020012 a/2004 Tank D-9-1 02050051 r/2004 0.4 'r'1er 2 01120044 r1,/ 2003 FCCU 1 AlteratsioaB (Boiler 17) 03030069 9/ 2003 0.1 Sludge Processing Unit 0L720042 3 / 2002 RAU Steam Reboiler 01060090 ro/ 2oor Total i

TabI6 III - Source-Wide Cr€ditable Cont€@DoraDeouE hlssLon DecrGa8eg

Emiseiong Decrease Proj ect./Activiry (Tons/Year) Tank D-50 Demo 2006-o9 Tank F-12 Demo 2005-09 Tank F-35 Demo 2006-o9 0.3 VF-1 Fugitives 12/ 20O9 HTR-VF1-North L2/ 20O9 1.0 HTR-VF1-South L2/ 20O9 1.1 I{TR-BEU-HM1 Shutdown 12/ 2008 IITR-BEU-HM2 Shuedown L2/ 20O8 L.2 Boifer 15 Shutdowrr t2 / 2O0A Tank A-49 9/2OOe 0.5 Tank A-3 9 9/ 2OO7 North Property cround Flare Decommissioned 7/ 2O07 HTR'IC{T 4/ 2OO6 2.r casoline Tank ReDlacement 3/ 2006 0.1 Emissions Decrease Proi ect/Activity Date (Tons/Year) Tank A-4 Demo 1/2006 o.2 Tank F-10 Demo a/ 2oo6 Tank A- 19 Demo s/ 200s 4.7 Tank A-9 Demo 1/ 2oo4 0.4 Tank A-72 Firewater 72 / 2003 3.2 RFP Shutdown 12/ 2OO2 0.1 Tank 10-21 1,0/2002 Gasoline Storage Tanks (35-1, 35-2) 70/ 2002 6.1 No. 2 Crude Unit., H-25 ro /2002 Isom Unit, H-32 (Hartford Inteqration) 1,O/2002 o.2 Hydrogen Plant, H-30 (Hartford Integration) 1O/2O02 Alkylation Heater, H-19 (Hart.ford lntegration) ro / 2002 0.4 Reroute/El iminat ion of Flare Streams aE Hartford LO/ 2002 FCCU Shutdown at Hartford r0/2o02 4A.4 RAU Deethanizer Heater Shutdown 10/2001 0.9 Total:

Table IV - Ne! hiasions change

(Tons/Year) Increases and Decreases Associated With proDosed ModificaLion 342.7 creditable Contemporaneous Bmission Increases Creditable Contemporaneous Emi ss ion Decreases 115.5 409.8 Attachment 5

PsD Applicability - PM NetEing Analysis

Contemporaneous Time Period, July 2002 through October 2009

Table I - Projecg hieEionE IncreaaeE and Decreases

Emission Change Proj ecElActivity (Tons/Year) CORE Proj ect L91 .9

Table II - Source-wide ClediEable Congeuporaueoua hisaion lrrcreaaea

Permit Emissions Increase Proj ecElActiviEy Number ('rons/Year) Low Sulfur casoline (szu) 05050062 2/2OO7 10 .9 Ultra Low Sulfur Diesel 04050025 4 /2006 TieE 2 01120044 rr/2o03 5.4 FCCU 1 Alterations (Boiler 1?) 03030059 9/2O03 0.1 Total:

Table III - Source-Wide Cr€dil,able CoDt@poraDeoua hLsal-o! DecreaEes

Emissions Decrease Proj ecE/Activity Date IITR-VF1-North !2 / 2009 11 HTR-VF1-SouCh 1,2/2009 1.5 HTR-BEU-IIM1 Shutdown 1,21200s HTR-BEU-HM2 Shuldov,rn 12/ 2OO8 L.7 Boiler 15 Shutdown 12/2OOA HTR_ IGIT 4 / 2006 RFP Shutdown 12 /2OO2 CR-3 2'" Reheat Heater (fuel switch) 7r/2O02 11.1 CR-3 l8L Reheats Heater (fuel switch lL/2O02 11 1 CR-3 Charge Heater (fueL switch) rL/2O02 No. 2 crude Unit, H-2S !0/2002 Isom Unit, H-33 (Hartford Inteqration) L0/2O02 0.1 Isom Unit, H-32 (Hartford Inteqration) ro /2o02 LSR HydrotreaEing, H-31 (Hartford Integration) L0/ 2OO2 Hydrogen Plant, H-30 (Hartford Intesration) ro /2o02 Alkylation Heater, H-19 (Hartford Integration 1,0/ 2OO2 0.4 FCCU Shutdoem at Hartford ro/2o02 Total: 396.0

TabLe Iv - Neb hdasions Chalg€

(Tons/Year) Increaaes and Decreases Associated viiLh PropoEed Modificalion 791 .9 Creditable Contemporaneous Emission Increases Creditable Contemporaneous Em.ission Decreases 396.0 Attachment 7

PSD Applicability - PMro Netting Analysis

contemporaneous Time Period: July 2002 through October 2009

Tabl.e I - Ptoject hissionE Ircreasea alrd DecreaEeE

Emission change Proj ect /Act ivity ('rons/ Year) CORE Proj ect 95 .4

Table II - Source-$tide CredLLable CoDteqroraneous hiaElo! IncreaEes

Permi! Emissions Increase Proj ect/Activity Numbex Date ( lOnS/ Year/ Low sulfur Casoline (SzU) 05050062 2/2oo7 10.9 UlEra Lor,r Sulfur Di.esel 04050026 4 / 2006 Tier 2 01120 044 1,t/ 2003 FCCU 1 Alt.erat.ions (Boiler 1z) 03030059 9/ 2OO3 0.1 Total:

Table III - Sourco-Wide Cr€digablg Contenporaneoua hi3sion DecreaseE

Emiasions Decrease Proj ect/Act ivity Date t lons/ Ieafl HTR-VF1-North L2/ 2009 HTR-VF1-South 12/ 2009 1.5 HTR-BEU-I{M1 Shutdown 12/ 200a '1 HTR-BEU-m42 ShuEdown 72/ 200A 1 '1 Boifer 15 Shutdown 12/ 2008 .4 HTR -IC{T 4/ 2o06 RFP ShuEdown L2/2002 CR-l 2"' Retreat lleater (fuel switch) aL/2002 8.0 cR-3 16t Reheat Heater (fuel sh'itch) rr/2o02 15.4 CR-3 Charge Heater (fuel switch) r1/ 2002 No- 2 Crude Unit, H-25 LO/2002 0.6 Isom Unit, H-33 (Hartford lnteqration) LO/ 2OO2 0.1 Isom Unit, H-32 (Harbford Inteqration) ro/ 2002 o -2 Hydrogen Plaflt, H-30 (Hartford Inteqration) 10/ 2002 o.2 Alkylation Heater, H-19 (Hartford Ingeqration) 10/ 2002 0-4 FCCU Shutdown at Hartford 70/ 2002 Total: 3Ar.2

Table IV - Net hiEaionE change

(Tons/Year) Increases and Decreases Associated With Proposed Modificabion 95 .4 Creditable Contemporaneous Emission Increaseg Creditable Contemporaneous Emission Decreases 381".2 -227 .2 AEEachment I

Non-Attainment Area NSR Applicabitity - PMr.r' Netting Analysis

Contemporaneous Time Period: May 2001 through October 2009

Table I - Project hiaaiona fncreaEeE aad Decreeses

Emission Change Proj ect/Activity (Tons/Year) CORE Proj est 95.4

Table II - Source-WLde Creditable CoDEenporaneoua hiEsion Increaeeg

Permit Emissions fncrease Proj ect /AcLivity Number Date (Tons/Year) Low Sulfur casoline (SZU) 05050062 3 / 2OO7 10.9 Ultra Low Sulfur Diesel 04050025 4 / 2006 Iier 2 01120044 Lr/2OO3 5.4 FCCU 1 Alterations (Boiler 17) 03030059 9/ 2003 0.1 Total : 58.5

Ta.ble III - Source-$Iide Creditable ConEeflporarteouE hisElon D€creaaea

Emissions Decrease Proj ectlActivity DaEe (Tons/Year) HTR-VF1-NoITh 12/ 2009 1.3 HTR-VF1-South L2/ 2O09 IITR-BEU-HM1 Shutdoh'n t2 / 200a IITR-BEU-IiM2 Shutdown 12l2008 1.? Boiler 15 Shutdovrn L2/ 200A 7.4 HTR- KHT 4/ 2006 2.9 RFP Shutdown 12/ 2002 cR-3 2nd Reheat Heater (fuel switch) rr / 2002 8.0 CR*3 1"'Reheat lleater (fuel switch) La/2OO2 15 .4 CR-3 Charge Heater (fuel swit.ch) 77/ 2002 No. 2 Crude Unit, H-25 LO/ 2OO2 Isom Unit, H-33 (Hartford Inteqration) LO/ 2002 Isom Unit, H-32 (Hartford Integration) 70/ 2002 Hydrogen Plant, H-30 (Hartford lntegration) L0/2002 Alkylation Heater, H-19 (Hartford Integration) L0/2002 0.4 FCCU ShuEdown at Hartford L0/2O02 323.3 CR-1 2nd Inter-reactor Heater, H-3 (Fuel switch) 2 / 2002 CR-1 1st Inter-reactor Heater. H-2 (Fuel Switch) 2/ 2OO2 6.4 CR-1 Feed preheat, H-1 (Fuel S\"ritch) 2 / 2002 RAU Deethanizer Heater Shutdown 10/2001 Total:

8-1 Table Iv - Net hdBslols ChaDqe

(Tons/Year ) Increases and Decreases Associated With proposed Modification 95.4 Creditabfe ConEemporaneous Emission Increases creditable contemporaneous Emission Decreases -244 .6

Emissions of PM2.5in this table are expressed as emisaions of PMro, which is being uaed aB a surrogate pollutant (see Condition 2.2). t :q r-roE T lr(I)01 .r i- nJ>o. 0) llr -r -Qrdo UL ! d o pq r,t o r!€ ; }1N $ .no o (.) .ul o (o r+r .E, q, t.l uo (., ctEd (d '.r u .A I! Qr rx(E lr| L) Or Ci ..1 L)'!d o b o o tdoc) @ UE, o F] lr (t) o h .JO>U El]9 qr ou) 3E EO o 0J> -.t o o ooo q-.1 .-d o o (] oc) 3 go U (.) +r do lr (, r-1 ,{ .rr I o (.) .u o O\-o o r+.rlt1 o (.) . 1 .-l (t .rl o OT .tJ -.1 (6 ru nJ lJ -.r t br o g> l{ .r q (d- !t ou i'1 (D orno q o -rl o C) O{tr rd tt '|r & ..1 o .tJ .\ d do (l) (l) UltJ El lt A, 7 tq g_.t5 ct {! ]J ]J o0) o ol o o o..rr c) .u rH o o lr 0) rr .d6-r El fl c.l Fl o (d.d o{ ql (,Fr o\o tr trd'lJ = o-r (d c (, {)0r! r.tI () r'r o o GG .nu.. O{N N ol QO (,) (.) o!(s (o d (J ..r o ..r -,r o 'Elql oco l.r ti EE frD d dl ulp' {')0 rd ..1 -.t 6 r{ JJ E .]J (J odu o (ullll do o .-r c t d0) ocu o --r -.1 o o F-t 3-i o Odrrr oEt ol t h h>, P ul"l E d Y(s t ql t E {l |il d)C i t'lc -u co lico ! co tr BI la .- --.i o --i o {l oA O.i .cll 'l o;dp uidp OF .a .doo p rJ ! rl Fl o; o tr; o r!G c{ d;rJ (I;.lJ flr r-l N )rlx ol (JE ol c-d c-d O otr O ocl od) ..1 O ,lJ -.1 O lJ s8tr J o po!u o -.r m (D odp lu ct dp (, ^d o U@ 0) o 50fr lro fr a2 0) o o (.) .qgl|)lr 0-l U tr ..t -.1 goo coo OU OE ! p o]J o ouo rJ il r+r td u U oo| U rrl rd o Tt'l' (,t,6 o td E> l{ .'h0r> dC)> d -, tl (l)l ob cro.pE pE h Elc .qUO OUor Ol 'n E D!0rol troor. rl tdo o Uoh o.I ttr 0 Er tr p. ol ..1 U !o ttl ..J!ob u f.) f4l]Ood JJ .ul (0 6Ood q-.t PI ET o oolr|H !ulr)g .u o l.ql l{ c) 6qJOC) (, .'l oFr ! i lr >d > p.>6 > !o! -a .lJ (d orj tr d Ed tr d (){')(6 (u.1 PE'! .'oEd OrN N 6 oo r-l (6 Or > r'r H Or > o ..1 -.i o H o r)1^-r a^-r F]r d Dtq tr D,q k O --l '-l d o o ,{ (J o at) J u ttr o UlJ 4 40 (JOo>O U-.ltr>O o --r -.1 OU o z 2 E{Ur-r dt Er !d rr d.d z OEE z

ail 1 c. ..: 6:l

]J o lr a ,p tr c)d d ..t OJ .u ord A 16 ld o t.| rs FI U B (l)lJ o -r.r cn dln o 5it o lu t'l GO JJ tr IDN t'l >.-! co ID 7E rd q) o rd -r1 g o (l)]J lr h6 0l tr do -1 (D o (6 -.t o .u (tr o3 6 oc) q) BX o .1J otl oo (611 E o a\ UU Uts (oD. ttl ATTACHMENT 10: STANDARD PERMIT CONDITIONS

STANDARD CONDITIONS FOR CONSTRUCTION,/DEVE],OPMENTPERMITS ISSUED BY THE IIJIIINOIS ENVIRONMENTA! PROTECTION AGENCY

The Illinois EnvironmenLal Protection Act (I1linois Revised Statutes, Chapter 11-L-I/2, section 1039) authorizes the EnvironmenEal Protection Agency to impose conditions on permits, which it issues.

The folLowing condi.Eions are applicabte unless superseded by speciaL condition(s).

1. unless this permit has been extended or it hae been voided by a newly issued permit, this permiE will- expire one year from the date of issuance, unless a continuous program of construction or developmenE on this project has sEarted by such time.

The construction or devel-opment covered by this permit shall be done in compLiance with applicable prowisions of the lllinois Environmental Protection Acts and Regulations adopted by the 111inoi.s Poflution Control Board.

3. There shal1 be no deviations from the approved plans and specifications unless a written request for modification, along wiEh plans and specifications as required, shall have been submitted to the Illinois EPA and a supplemental written perrnit issued.

The Permittee shall alLow any duly authorj-zed agent of the lllinois EPA upon the presentation of credentials, at reasonable times:

To enter the Pernittee'B property where actual or potential effluent, emission or noise gources are located or where any activity is to be conducted pursuant to this permit,

l^ To have access to and to copy any records required to be kept under the terms and cond.itions of this permiL,

c. To in6pect, including during any hours of operation of equipment constructed or operated under thia permit, such equipment and any equipment required to be kep!, used, operated, callbrated and maintained under this permiE,

d. To obtain and remove samples of any discharge or emissions of pollutants, and

e. To enLer and utilize any photographic, recording, testing, monitoring or other equipmenE for the purpose of preserving, t€sting, monitoring, or recording any activity, discharge, or emission authorized bv this Dermit. 5. The issuance of this permit:

a. sha1l not be considered as in any manner affectirg the title of l-he nrFmi sPs rln^n which Ehe permitEed facilities are to be located,

b, Does not release the Pemittee from any liability for damage Eo person or property caused by or resulting from the consEruction, maintenance, or operation of the proposed facilicies.

c. Does not release the Permittee from compliance with other . applicable statutes and regulations of the united States, of the state of lllinoj-E, or with appficable local laws, ordi.nances and regulatj-ons -

d. Does rrot take i,nto consideration or atbest to the structural stability of any units or parts of the project, and

e. In no nanner implies or suggests Ehat Ehe lllinois EPA (or itB officers, agenEs or employees) aElsumes any liability, direcEly or indirectly, for any loss due to damage, instaflation, maintenance, or operation of the proposed equipment or facility.

5a. Unless a joinL construction/operation permit has been iBsued, a permit for operation shall be obtained from the Illinoi.s EPA before the equipment covered by this permi! is placed into operation.

b. For purfloses of shakedovrn and testing, unless otherwiee specified by a special permit condition, the equipment covered under this permit may be operated for a period not to exceed thirty (30) days.

7. The Illinois EPA may file a complaint with the Board for modification, suspension or revocaEion of a permit.

a. Upon discovery that the permit application contained mi srepresentations , misinformation or falee statement or that all relewant facts u'ere noE disclosed, or

b. Upon finding that any standard or special conditions have been violated, or

c. Upon any violationB of the Environmental Protection Act or any regulation effectiwe tshereunder as a resuLt of the conslxuction or development authorized by this permit-