DAQE - AN0119054 - 05

April 8, 2005 Kris Battleson Chevron Texaco Products Company 2351 North 110 0 West Salt Lake City, Utah 84116 Dear Ms. Battleson : Re: Approval Order: Combine Approval Orders DAQE -AN0119052 - 05 and DAQE - AN0119053 - 05 Davis County - CDS A, NSPS, MAIN, Title V Major Project Code: N0 119 - 053 The attached document is the Approval Order (AO) for the above -referenced project. Future correspondence on this Approval Order should include the engineer's name as well as the DAQE number as shown on the upper right -hand corner of this letter. Please direct any technical questions you may have on this project to Mr. Mike Beheshti. He may be reached at (801) 536 - 4069 . Sincerely, Richard W. Sprott, Executive Secretary Utah Air Quality Board RWS:RR:MB:dn cc: Davis County Health Department Mike Owens, EPA Region VIII

150 North 1950 West • PO Box 144820 • Salt Lake City, UT 84114 - 4820 • phone (801) 536 - 4000 • fax (801) 536 - 4099 T.D.D. (801) 536 - 4414 • www.deq.utah.gov 

## State of Utah Department of Environmental Quality Dianne R. Nielson, Ph.D. Executive Director DI VI SI ON OF AIR QUALITY Richard W. Sprott Director JON M. HUNTSMAN, JR. Governor GARY HERBERT Lieutenant Governor

## STATE OF UTAH **Department of Environmental Quality Division of Air Quality**  **APPROVAL ORDER: COMBINE APPROVAL ORDERS DAQE**  **- AN0119052**  **- 05 AND DAQE**  **- AN0119053**  **- 05** 

**Prepared By: Mike Beheshti, Engineer**

**(801) 536 -**  **4069 Email: mbeheshti@utah.gov**  

### APPROVAL ORDER NUMBER **DAQE -**  **AN0 119054**  **- 05**  **Date: April 8, 2005** 

## Chevron Products Co - SL Refinery

**Source Contact Kris Battleson**  **(801) 539 -**  **7222**

**Richard W. Sprott Executive Secretary**  **Utah Air Quality Board Abstract** 

**On March 8, 2005, Chevron Products Company requested th e Division Of Air Quality to consolidate**  **Chevron’s approval orders DAQE AN0119052 -**  **05, which was issued on February 28, 2005, to provide for low** **- sulfur fuel production, and Approval Order DAQE**  **- AN0119053**  **- 05, which was issued on**  **March 3 to provide for the rep lacement of Cooling Tower # 3. Construction schedule had prompted**  **Chevron to request New Source Review (NSR) to use Approval Order DAQE -**  **AN0119048 -**  **03, dated June 16, 2003, as the basis of modification for the two approval orders named here.**  **Since both a**

**pproval orders received a 30 -**  **day public review and no comment was received, the consolidation of the two approval orders into one will require no additional public review. Emissions**  **will remain unchanged as follows:**

**PM 10**  **= 175.0 NO**  **x = 1021.6**  **SO 2**  **= 2578.2 As the banked emissions exist in a registry at the Division of Air Quality, they are not duplicated in the**  **Approval Order. For continuity of thought, this Approval Order retains the abstract to the Approval Order, which was**  **issued to pr ovide for the production of low**  **- sulfur fuel.**  **Abstract to Approval Order DAQE -**  **AN0119052 -**  **05 Federal regulations require refineries progressively to lower the sulfur content of the fuels they**  **produce to the levels specified in 40 CFR 80, all to be achiev ed by January 1, 2010. The first critical**  **date will be June 1, 2006, by which time the sulfur content of on -**  **road diesel must be not greater than 15 ppm. To achieve this objective by the critical dates, Chevron plans to:**  **1. Expand the existing HDS Unit (h**  **ydro -**  **desulfurization unit) to process 13 thousand barrels per day (MBPD) of crude diesel.**  **2. Install a VGO (vacuum gas oil) hydro** **- treating unit to provide 18 MBPD feed to the FCC**  **(fluidized catalytic cracker.) 3.**  **Install a TGU (tail gas treating unit) to incr ease sulfur recovery to about 99.8%**  **4. Install a 50,000** **- barrel tank to store 15**  **- ppm diesel fuel.**  **A hydrogen plant, to be installed, owned, and operated by a third party, will provide hydrogen to the HDS and the VGO. In this connection, the CO** **- boiler at Ch**  **evron will be de -**  **commissioned before the hydrogen plant has begun operation. The banking and potential transferring of PM**  **emissions from the decommissioning will be addressed in a future Notice of Intent (NOI). The emissions picture, given in the Table, s**  **hows that the proposed plant modifications will not change the refinery’s emission caps. The Table further shows that the emission increases are far below the**  **significant emission levels and that the modifications are minor.**DAQE -AN0119054 - 05

Page 3

**EMISSIONS SUMMA RY: C**  **H EVRONTEX** **ACO SALT L AK**  **E REFINERY CLEA**  **NER BURNING FUELS PROGRA M^**  **Pollutant SIP** 

**Potential Emissions Current**  **Ac tual**  **2002/2003 Proposed** 

**CFP*** **Changes SLR** **

**Banked Credits**  NO x 1,021.6 780.6 11.8 0 SO 2 2,578.2 1261.3 10.0 0 PM 10 85.6 73.0 2.9 89.4 CO NA 4 19.5 31.2 2507.3 VOC NA 309.5 8.1 485.9 ^ Emissions in tons per year * CFP: Clean burning fuels program **SLR: Salt Lake Refinery . **The refinery operates in Davis County, which is an attainment area for all pollutants except ozone for which it has a mai** 

**ntenance status. But as the refinery affects the Salt Lake County’s (non -**  **attainment) emission level of PM**  **10 , SO**  **2 , and NO** 

**x (see the Utah PM**  **10 SIP,) Chevron has chosen low NO**  **x (0.02**  **lb/MMBtu) burners and a Tail Gas Unit to increase the SRU efficiency to abo ut 99.8% as Best**  **Available Control Technology (BACT). These and adherence to the applicable NSPS and NESHAPS satisfy the New Source Review’s (NSR) BACT requirements**  . **Approval Order DAQE -**  **AN0119048 -**  **03is modified to include the proposed changes to the refin**  **ery and its operation. Chevron is a Title** **- V source.**  

### As the proposed modifications will not change the SIP **- specified**  **emissions, the Board’s approval will not be required.** This project entails the consolidation of approval orders DAQE - AN0119052 - 05 and DAQE -AN0119053 - 05, which were issued to Chevron, respectively, on February 28, 2005 and on March 3, 2005. Both approval orders were issued in compliance with the requirements of the Utah Administrative Code Rule 307 (UAC R307) and each received a 30 - day p ublic - comment period. The consolidation of the two approval orders, therefore, required no further public comment period. This air quality Approval Order (AO) authorizes the project with the following conditions, and failure to comply with any of the conditions may constitute a violation of this order. **General Conditions:** 1. This AO applies to the following company: Chevron Products Company 2351 North 1100 West Salt Lake City, Utah 84116 Phone: (801) 539 - 7200 FAX: (801) 539 - 7130DAQE -AN0119054 - 05

Page 4 PLANT LOCATION:

Ch evron Refinery 2351 North 1100 West Salt Lake City, Utah 84116 Universal Transverse Mercator (UTM) Coordinate System: 4,519,770 meters Northing, 422,270 meters Easting, Zone 12, UTM Datum 27 2. All definitions, terms, abbreviations, and references used in this AO conform to those used in the Utah Administrative Code (UAC) Rule 307 (R307), and Title 40 of the Code of Federal Regulations (40 CFR). Unless noted otherwise, references cited in these AO conditions refer to those rules. 3. The limits set for th in this AO shall not be exceeded without prior approval in accordance with R307 - 401. 4. Modifications to the equipment or processes approved by this AO that could affect the emissions covered by this AO must be approved in accordance with R307 - 401 - 1. 5. All records referenced in this AO or in applicable NSPS and NESHAP standards, which are required to be kept by the owner/operator, shall be made available to the Executive Secretary or Executive Secretary’s representative upon request, and the records shall include the two - year period prior to the date of the request. Records shall be kept for the following minimum periods: a. Emission inventories - Five years from the due date of each emission statement or until the next inventory is due, whichever is longer. b. All other records - Two years. 6. Regardless of any inconsistency between conditions of this AO and Section IX, Part H, and paragraph 2.b.G (Section IX.H.2.b.G) (Chevron U.S.A.) of the SIP, this AO shall take precedence as provided by R307 - 3 05 - 2. 7. This AO shall replace Approval Orders DAQE - AN0 119052 - 05, dated February 28, 2005, and Approval Order DAQE

–AN0119053 - 05, dated March 3,2005. 8. The approved installations shall consist of the following equipment: A. Boilers #11001, #11002, and #11004 B. Bo iler #11005 (Low -NO x) C. Crude Unit Furnace F - 21001 (Low -NO x) D. Crude Unit Furnace F - 21002 (Low -NO x) E. FCC Furnace F - 32021 F. FCC Furnace F - 32023 G. HDN Furnace F - 71010 H. HDN Furnace F - 71030DAQE -AN0119054 - 05

Page 5 I. Reformer Furnace F - 35001

J. Reformer Furnace F - 35002 K. Reformer Furnace F - 35003 L. Alkyl ation Furnace F - 36017 (Low -NO x) M. Coker Furnace F - 70001 N. HDS Furnace F - 64010 (Low -NO x) O. HDS Furnace F - 64011 (Low -NO x) P. VGO Furnaces F - 66100 and F - 66200 (Low -NO x) Q. Reformer Compressor Drivers (natural - gas fired) R. Sulfur Recovery Unit/Tail Gas Treating Unit/Tail Ga s Incinerator S. FCC CO Boiler and Catalyst Regenerator (1 stack- CO Boiler to be decommissioned upon Hydrogen Plant’s startup, after the shakedown period, but before the hydrogen plant has become operational) T. FCC Flare U. Alkylation Flare V. Coker Flare W. Amine Unit X. Tank #20015 (20,000 bbl external floating roof tank with primary and secondary seals storing sour water) Y. Tank #30107 (30,000 bbl external floating roof tank with primary and secondary seals storing wastewater) Z. Tank #40112 (40,000 bbl fixed roof storing diesel) AA. Tank #50113 (50,000 bbl fixed roof storing primarily diesel) BB. HF Mitigation system CC. Cooling Tower #1 DD. Cooling Tower #2 (Grandfathered) EE. New Cooling Tower (to be installed in 2005) FF. Cooling Tower #4 (Grandfathered) Limitations 9. Combined emission s of sulfur dioxide from the sources listed below shall not exceed 2.977 tons/day. Sources included in emission cap Fuel Type Boilers #11001, #11002, and #11004 Plant gas Boiler #11005 Plant gas Crude Unit Furnace F - 21001 Plant gas Crud e Unit Furnace F - 21002 Plant gas FCC Furnace F - 32021 Plant gas FCC Furnace F - 32023 Plant gas FCC Catalyst Regenerator Coke HDN Furnace F - 71010 Plant gas HDN Furnace F - 71030 Plant gas Reformer Furnace F - 35001 Plant gas Reformer Furnace F - 35002 Plant gas Reformer Furnace F - 35003 Plant gas Alkylation Furnace F - 36017 Plant gas HF Alkylation Polymer Polymer oil Coker Furnace F - 70001 Plant gasDAQE -AN0119054 - 05

Page 6 HDS Furnace F - 64010 Plant gas

HDS Furnace F - 64011 Plant g as VGO Furnaces F - 66100 and F - 66200 Plant gas Reformer Compressor Drivers Natural gas Compliance with the daily limitation shall be determined by summing the emissions calculated as follows: Except for FCC Catalyst Regenerator, daily sulfur dioxide emissions from affected units shall be determined by multiplying the quantity of each fuel used daily (24 hr usage) at each affected unit by the appropriate emission factor below. The values shall be summed to show the total daily sulfur dioxide emissio n. Emission factors (EF) for the various fuels shall be as follows: Natural gas : EF = 0.60 lb/MMscf Fuel oil & HF Alkylation polymer : The emission factor to be used for combustion shall be calculated based on the weight percent of sulfur, as determine d by ASTM Method D 4294 - 89 or approved equivalent, and the density of the fuel oil, as follows: EF (lb SO 2/k gal) = density (lb/gal) * (1000 gal/k gal) * wt.% S/100 * (64 lb SO 2/32 lb S) Plant gas : the emission factor shall be calculated from the H 2 S me asurement obtained from the H 2 S continuous emission monitor required elsewhere in this permit. The emission factor shall be calculated as follows: EF (lb SO 2/MMscf gas) = (24 hr avg. ppmdv H 2 S) /10 6 * (64 lb SO 2/lb mole) * (10 6 scf/MMscf)/(379 scf/lb mo le) The source shall maintain a record of fuel meter identifiers and locations, conversion factors, and other information required to demonstrate the required calculations. Records shall be kept showing the daily fuel usage, fuel meter readings, required fuel properties, hours of equipment operation, and calculated daily emissions. The SO 2 emission factor for the FCC Catalyst Regenerator shall be determined by either a continuous emission monitor or by a stack test every three years. For continuous emiss ion monitor calculations the monitor shall be maintained and calibrated in accordance with R307 - 170, UAC. 40 CFR 60 Methods 2, 3A and 6C shall be used to determine relative accuracy. If a new monitor is installed, an initial performance test shall be pe rformed within 30 days of installation. The performance test shall be conducted and data reduced in accordance with the test methods and procedures contained in 40 CFR 60, Appendix B: Performance Specification 2. Notification must be made to the Executiv e Secretary prior to conducting the performance test. Whenever the SO 2 CEM is bypassed for short periods, SO 2 CEM data from the previous three days will be averaged and used as an emission factor to determine emissions. The volumetric flow rate will be d etermined using a method approved by the executive secretary. For stack test calculations, mass emission rates (lbs/hr, etc.), the pollutant concentration, as determined by the appropriate methods below, shall be multiplied by the volumetric flow rate and any necessary conversion factors as determined by the Executive SecretaryDAQE -AN0119054 - 05

Page 7 to establish the FCC Catalyst Regenerator SO 2 emission factor. The applicant shall

provide a pre - test protocol at least 45 days prior to the test. A pretest conference between the owner/operator, the tester, and the Executive Secretary shall be held at least 30 days prior to the test if directed by the Executive Secretary. The emission point shall conform to the requirements of 40 CFR 60, Appendix A, Method 1. Occupational Safety and Health Administration (OSHA) approved access shall be provided to the test location. The throughput rate during stack testing shall be no less than 90% of the rated throughput or 90% of the highest monthly throughput achieved in the previous three years whichever is the least. 40 CFR 60, Appendix A, Method 6, 6A, 6B, or 6C shall be used to determine the SO 2 emission rate. 40 CFR 60, Appendix A, Method 2 shall be used to determine the volumetric flow rate. 10. Emissions of SO 2 from the sources list ed under the SO 2 cap shall be no greater than 953.9 tons per twelve - month period. Compliance shall be determined on a twelve - month rolling average. Each month, the SO 2 emissions calculated to show compliance with the daily limitations for the previous mo nth shall be summed to give a monthly emission total. This shall be added to the previous eleven month emission totals to give the new twelve - month rolling total. 11. Emissions of sulfur dioxide from the SRU shall not exceed 2.128 tons/day. Compliance wi th the limitation shall be determined as follows: Daily sulfur dioxide emissions from the SRU/TGU/TGI shall be determined by multiplying the sulfur dioxide concentration in the flue gas by the mass flow of the flue gas. The sulfur dioxide concentration i n the flue gas shall be determined by a continuous emission monitor that meets or exceeds the requirements contained in 40 CFR 60, Appendix B: Performance Specification 2. The monitor shall be maintained and calibrated in accordance with R307 - 170, UAC. 40 CFR 60 Methods 2, 3A and 6C shall be used to determine relative accuracy. If a new monitor is installed, an initial performance test shall be performed within 30 days of installation. The performance test shall be conducted and data reduced in accordance with the test methods and procedures contained in 40 CFR 60, Appendix B: Performance Specification 2. Notification must be made to the Executive Secretary prior to conducting the performance test. Whenever the SO 2 CEM is bypassed for short periods, S O 2 CEM data from the previous three days will be averaged and used as an emission factor to determine emissions. The mass flow rate of the flue gas shall be determined by a volumetric flow measurement device that meets or exceeds the requirements containe d in 40 CFR 52 Appendix E. An annual relative accuracy test audit shall be conducted, and quarterly reports submitted, in accordance with the procedures outlined in R307 - 170, UAC, and 40 CFR 52 Appendix E. If a new volumetric flow measurement device is i nstalled, an initial performance test shall be performed within 30 days of installation. The performance test shall be conducted and data reduced in accordance with the test methods and procedures contained in 40 CFR 52 Appendix E. Notification must be made to the Executive Secretary prior to conducting the performance test. The source shall maintain records of the SO 2 concentration, the mass flow rate, and the resulting calculated emissions. Records of all CEM calibrations shall also be maintained.DAQE -AN0119054 - 05

Page 8 1 2. Emissions of SO 2 from the SRU shall be no greater than 776.7 tons per twelve - mo nth

period. Compliance shall be determined on a twelve - month rolling average. Each month, the SO 2 emissions calculated to show compliance with the daily limitations for the previous month shall be summed to give a monthly emission total. This shall be added to the previous eleven month emission totals to give the new twelve - month rolling total. 13. The SRU shall remove no less than 95% of the sulfur contained in the feed s treams to the unit. The feed streams shall include the overhead stream from the amine unit regenerator and the overhead stream from the sour water stripper. 14. The following sources shall not be regulated for SO 2 or NO X emissions nor shall they be included in the emission limitation totals herein: FCC flare Alkylation flare Coker flare 15. The hydrogen sulfide content of plant gas burned at the Crude unit furnaces F - 1 and F - 2, the SRU Incinerator, the HDS furnaces F - 6410 and F - 6411, Boiler #11005, and the VGO furnaces F - 66100 and F - 66200 shall not exceed 0.10 grains H 2 S/dscf as required by 40 CFR 60, Subpart J. Compliance with this limitation shall be determined as follows: A. For natural gas, compliance is assumed while the fuel comes from a public utility. B. For plant gas, the H 2 S content of the plant gas shall be measured with a continuous monitor that meets or exceeds the requirements contained in 40 CFR 60, Appendix B: Specification 7. The monitor shall be installed in a location representativ e of the H 2 S content in the plant gas system. The location shall be approved in writing by the Executive Secretary prior to installation. The current approved location of the monitor is downstream of the V - 113 fuel - gas mix drum. The monitor shall be mai ntained and calibrated in accordance with R307 - 170, UAC. 40 CFR 60 Method 11 shall be used to determine relative accuracy. If a new monitor is installed, an initial performance test shall be performed within 30 days of installation. The performance tes t shall be conducted and data reduced in accordance with the test methods and procedures contained in 40 CFR 60, Appendix B: Performance Specification 7. Notification must be made to the Executive Secretary prior to conducting the performance test. If th e monitor reading is not available, the refinery plant gas shall be sampled as close to the monitor location as safely possible at least once each day. The sample shall be analyzed for sulfur content by use of a chemical detector tube capable of reading the required concentration (e.g., Draeger Hydrogen Sulfide No. 1/D or equivalent). Breakdowns shall be handled as specified in R307 - 170 UAC **.** 16. The sulfur content of any fuel oil or diesel burned in Boiler #11005 shall not exceed 0.5 percent by weight for fuel oil consumed.DAQE -AN0119054 - 05

Page 9 The sulfur content of plant fuel oil burned elsewhere within the plant shall not exceed

1.5% by weight. Compliance with the limitation shall be based on the most recent determination of sulfur content of the fuel oil. ASTM Method D - 4 294 - 89 or an approved equivalent shall determine the sulfur content. Certification of other fuels shall be by Chevron’s own testing or test reports from the fuel marketer. Fuel oil may only be burned during periods of natural gas curtailment. 17. The n itrogen content of fuel oil burned in Boiler # 11005 shall not exceed 0.3 weight percent. Compliance with this limitation shall be based on records of the nitrogen content of the fuel oil combusted in the Boiler and calculation of the average fuel nitroge n content on a per calendar quarter basis. The nitrogen content shall be determined using ASTM Method D3431 - 80 or fuel suppliers. 18. The SRU shall only be taken out of service for scheduled maintenance during the months of April through October. Notice shall be submitted to the Executive Secretary by the end of the first calendar quarter of each year planned, and 30 days before any SRU turnaround. 19. Combined emissions of NO X from the sources listed below shall be no greater than 3.248 tons per day. Except for the FCC Catalyst Regenerator, compliance with the daily limit shall be determined daily by multiplying the quantity of each fuel burned at each affected unit by the associated emission factor for that fuel at that unit, and summing the results. The sources, fuels, and associated emission factors for this limitation are as follows: Sources included in emission cap Fuel Type NO x Emission factors Boilers #1, #2, and #4 Plant gas 100 lb/MMscf Boiler #11005 Plant gas 50 lb/MMscf Crude Uni t Furnace F - 21001 Plant gas 50 lb/MMscf Crude Unit Furnace F - 21002 Plant gas 50 lb/MMscf FCC Furnace F - 32021 Plant gas 100 lb/MMscf FCC Furnace F - 32023 Plant gas 100 lb/MMscf. FCC Catalyst Regenerator Coke Stack test or CEMs HDN Furnace F - 71010 Plant gas 100 lb/MMscf HDN Furnace F - 71030 Plant gas 100 lb/MMscf Reformer Furnace F - 35001 Plant gas 100 lb/MMscf Reformer Furnace F - 35002 Plant gas 100 lb/MMscf Reformer Furnace F - 35003 Plant gas 100 lb/MMscf Alkylation Furnace F - 360 17 Plant gas 50 lb/MMscf HF alkylation polymer Polymer oil 120 lb/kgal Coker Furnace F - 70001 Plant gas 100 lb/MMscf HDS Furnace F - 64010 Plant gas 50 lb/MMscf HDS Furnace F - 64011 Plant gas 50 lb/MMscf VGO Furnaces F - 66100 and F - 66200 Plant gas 32 lb/MMscf Reformer Compressor Drivers Natural gas 3400 lb/MMscf SRU Tail Gas Incinerator Plant gas 100 lb/MMscf All units in the above list shall be stack - tested if directed by the Executive Secretary. The permitted source may also perform a stack test to provide information for updating the emission factors listed above. All stack tests shall conform to the following:DAQE -AN0119054 - 05

Page 10 The applicant shall provide a pre - test protocol at least 45 days prior to the test. A pretest

conference between the own er/operator, the tester, and the Executive Secretary shall be held at least 30 days prior to the test if directed by the Executive Secretary. The NO x emission factor for the FCC Catalyst Regenerator shall be determined by either a continuous emission mo nitor or by a stack test every three years. For continuous emission monitor calculations, the monitor shall be maintained and calibrated in accordance with R307 - 170, UAC. 40 CFR 60 Methods 2, 3A and 7E shall be used to determine relative accuracy. If a new monitor is installed, an initial performance test shall be performed within 30 days of installation. The performance test shall be conducted and data reduced in accordance with the test methods and procedures contained in 40 CFR 60, Appendix B: Per formance Specification 2. Notification must be made to the Executive Secretary prior to conducting the performance test. Whenever the NO x CEM is bypassed for short periods, NO x CEM data from the previous three days will be averaged and used as an emissio n factor to determine emissions. The volumetric flow rate will be determined using a method approved by the executive secretary. For stack test calculations, mass emission rates (lbs/hr, etc.), the pollutant concentration, as determined by the appropri ate methods below, shall be multiplied by the volumetric flow rate and any necessary conversion factors as determined by the Executive Secretary to establish the FCC Catalyst Regenerator NO x emission factor. The emission point shall conform to the require ments of 40 CFR 60, Appendix A, Method 1. Occupational Safety and Health Administration (OSHA) approved access shall be provided to the test location. The throughput rate during compliance testing shall be no less than 90% of the rated throughput or 90% o f the highest monthly throughput achieved in the previous three years whichever is the least. If the desired throughput rate is not achieved at the time of testing, the achieved throughput rate +10% will become the maximum allowable throughput rate. Additional testing shall be required, following the same procedure, to establish a higher throughput rate if the existing maximum allowable throughput rate is to be exceeded. 40 CFR 60, Appendix A, Method 7, 7A, 7B, 7C, 7D, or 7E shall be used to determine th e NO X emission rate. 40 CFR 60, Appendix A, Method 2 shall be used to determine the volumetric flow rate. To determine mass emission rates (lbs/hr, etc.), the pollutant concentration, as determined by the appropriate methods above, shall be multiplied by the volumetric flow rate and any necessary conversion factors determined by the Executive Secretary to give the results in the specified units of the emission limitation. The source shall maintain a record of fuel meter identifiers and locations, convers ion factors, and other information required to demonstrate the required calculations. Records shall be kept showing the daily fuel usage, fuel meter readings, required fuel properties, hours of equipment operation, and calculated daily emissions. 20. Emissions of NO X from the sources listed under the NO X cap shall be no greater than 1021.6 tons per twelve - mo nth period. Compliance shall be determined on a twelve - month rolling average. Each month, the NO X emissions calculated to show compliance with the daily limitations for the previous month shall be summed to give a monthly emission total. This shall be added to the previous eleven month emission totals to give the new twelve - month rolling total.DAQE -AN0119054 - 05

Page 11 21. Combined emissions of PM 10 from the sources listed bel ow shall be no greater than 0.234

tons per day. Sources included in emission cap Boilers #1, #2, and #4 Boiler #11005 Crude Unit Furnace F - 21001 Crude Unit Furnace F - 21002 FCC Furnace F - 32021 FCC Furnace F - 32023 FCC Catalyst Regenerator HDN Furn ace F - 71010 HDN Furnace F - 71030 Reformer Furnace F - 35001 Reformer Furnace F - 35002 Reformer Furnace F - 35003 Alkylation Furnace F - 36017 Coker Furnace F - 70001 HDS Furnace F - 64010 HDS Furnace F - 64011 VGO Furnaces F - 66100 and F - 66200 SRU Tail Gas Incinerator E xcept for the FCC Catalyst Regenerator, compliance with the daily PM 10 limit shall be determined daily by multiplying the quantity of each fuel burned at the affected units by the associated emission factor for that fuel, and summing the results. The emis sion factors for this limitation are as follows: Natural gas: 1.9 lb/MMscf Plant gas: 1.9 lb/MMscf Fuel Oil/ HF alkylation polymer: The PM 10 emission factor shall be determined based on the sulfur content of the fuel ((S) according to the equation: E F (lb/1000 gal) = (Wt. % S * 10) + 3.22 Units in the above list shall be stack- tested if directed by the Executive Secretary. The permitted source may also perform a stack test to provide information for updating the emission factors listed above. All s tack tests shall conform to the following: The applicant shall provide a pre - test protocol at least 45 days prior to the test. A pretest conference between the owner/operator, the tester, and the Executive Secretary shall be held at least 30 days prior to the test if directed by the Executive Secretary. The PM 10 emission factor for the FCC Catalyst Regenerator shall be determined by a stack test at least once every three years. Mass emission rates (lbs/hr, etc.), the pollutantDAQE -AN0119054 - 05

Page 12 concentration, as determine d by the appropriate methods, shall be multiplied by the

volumetric flow rate and any necessary conversion factors as determined by the Executive Secretary to establish the FCC Catalyst Regenerator PM 10 emission factor. The emission point shall conform to the requirements of 40 CFR 60, Appendix A, Method 1. Occupational Safety and Health Administration (OSHA) approved access shall be provided to the test location. The throughput rate during compliance testing shall be no less than 90% of the rated throughput or 90% of the highest monthly throughput achieved in the previous three years whichever is the least. If the desired throughput rate is not achieved at the time of testing, the achieved throughput rate +10% will become the maximum allowable throughpu

t rate. Additional testing shall be required, following the same procedure, to establish a higher throughput rate if the existing maximum allowable throughput rate is to be exceeded. 40 CFR 51, Appendix M, Methods 201 or 201a shall be used to determine f ront - half PM 10 emissions in stacks in which no liquid drops are present. 40 CFR 51, Appendix M, Method 202 shall be used to determine back -half condensibles in such stacks. For stacks in which liquid drops are present, methods to eliminate the liquid drops should be explored. If no reasonable method to eliminate the drops exists, then the following methods shall be used: 40 CFR 60, Appendix A, Method 5, 5a, 5d, or 5e as appropriate. The back half condensibles shall also be tested using Method 202. All particulate captured in the back half shall be considered PM 10 . The back half condensibles shall not be used for compliance demonstration but shall be used for inventory purposes. 40 CFR 60, Appendix A, Method 2 shall be used to determine the volumetri c flow rate. To determine mass emission rates (lbs/hr, etc.), the pollutant concentration, as determined by the appropriate methods above, shall be multiplied by the volumetric flow rate and any necessary conversion factors determined by the Executive Secretary to give the results in the specified units of the emission limitation. 22. The following sources shall not be regulated for PM 10 emissions nor shall they be included in the emission limitation totals herein: A. FCU flare B. Alkylation flare C. Coker flare D. Reformer compressor drivers 23. The owner/operator shall use only plant gas as a primary fuel. HF Alkylation Polymer may be burned in the Alky furnace, F - 3617. Plant coke may be burned in the Fluid Catalytic Cracker Regenerator. If any oth er fuel is to be used, an AO shall be required in accordance with R307 - 403, UAC. 24. Visible emissions from this source shall not exceed those set in the SIP Section IX. Part H.2.a.B. Opacity observations of emissions from stationary sources shall be conductedDAQE -AN0119054 - 05

Page 13 according to 40 CFR 60, Appendix A, Method 9 or by a Continuous Opacity Monitoring

system. The Fluid Catalytic Cracker (FCC) shall not exceed 20% opacity, except for up to three six - minute periods in excess of 20% opacity per hour, which may include no more than one six - minute period in excess of 30% opacity per hour, each exceedance being allowed when associated with short - term, minor process and feed variations. 25. The applicable portions of 40 CFR 60 Subpart A and 40 CFR 60 Subpart J applie s to Crude Unit furnaces F - 1 and F - 2, the SRU Incinerator, HDS furnaces F - 6410 and F - 6411 the Boiler #11005, the VGO Furnaces F - 66100 and F - 66200, and the SRU/TGU/TGI. 40 CFR Subpart GGG applies to the Amine unit, Sulfur Recovery unit, HDS unit, Boiler # 11005, and the VGO unit. 40 CFR 60 Subpart Db applies to Boiler #11005. The seals on Tank #20015, and #30107 shall be maintained in accordance with R307 - 327 - 2, UAC, Installation and Maintenance for Petroleum Liquid Storage. 26. All installations and f acilities authorized by this AO shall be adequately and properly maintained. 27. The owner/operator shall comply with R307 - 155 - 1, UAC. This rule addresses emission inventory reporting requirements. The monthly flaring emissions and emissions from SRU maintenance shall be estimated and reported as part of the annual inventory. 28. The owner/operator shall comply with R307 - 107, UAC. This rule addresses unavoidable breakdown reporting requirements. 29. Any future modifications to the equipment approved by this order must be approved in accordance with R307 - 401 - 1, UAC. This AO in no way releases the owner or operator from any liability for compliance with all other applicable federal, state, and local regulations including the UAC. Allowable annual emissions for this source are currently calculated at the following values: A. 175.0 tons/yr for PM 10 B. 1021.6 tons/yr for NO x C. 2578.2 tons/yr for SO 2 , which includes 597.7 tons/yr for SRU downtime and 250 tons/yr, estimated flaring emissions 

### Thes e calculations are for the purposes of determining the applicability o f prevention of significant deterioration and non - attainment - area major source requirements of the UAC R307. Approved By: Richard W. Sprott, Executive Secretary Utah Air Quality Bo ard