DAQE -AN0 101230023 - 07

Ju ne 8 , 2007 Mike S. Astin, P.E. Holly Refining & Marketing Company 393 South 800 West Woods Cross, Utah 84087 - 1435 Dear Mr. Astin : Re: Approval Order : Holly Modernization Project

– CO PSD Major Modification , Davis County

– CDS A; NA; MAINT; NSPS; NESHAPS; HAPs; TITLE V MAJOR Project Code: N0 10123 - 0023 The attached document is the Approval Order 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 que stions you may have on this project to Mr. John D. Jenks. He may be reached at (801) 536 -4459 . Sincerely, Richard W. Sprott, Executive Secretary Utah Air Quality Board RWS : JJ : kw cc: Salt Lake Valley 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 SION 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**  **APPROV AL ORD**  **E R**  **: Holly Modernization**  **Project –**  **CO PSD Major Modification Prepared By: John D. Jenks, Engineer** 

**(801) 536 -** **4459 Email:**  **jjenks@utah.gov**



### APPROV**AL ORD E**  **R N**  **UMBER DAQE**  **- A** **N 0**  **101230023 -**  **07 Date:**  **June 8**  **, 2007** 

## Holly Refining & Marketing Company

**Source Contact Mike Astin**  **(801) 299 -**  **6660 Richard W. Sprott**  **Executive Secretary Utah Air Quality Board** **Abstract**

**Holly Refining**  **and Marketing**  **Company (Holly)**  **ha s**  **submitted a**  **Notice of**  **Intent to**  **perform a**  **number of**  **modernization upgrades**  **at their**  **refinery in**  **Woods Cross,**  **Utah. P**  **rimarily, these**  **changes will**  **result in**  **decreases in**  **emissions, with**  **the exception**  **of volatile**  **organic compounds**  **(VOC) and**  **carbon monoxide**  **(CO). The**  **CO em**  **issions will**  **increase by**  **mo re**  **than 100**  **tons per**  **year, making**  **this modification**  **a Prevention**  **of Significant**  **Deterioration (PSD)**  **major modification.**  **T he**  **refinery is**  **located in**  **Davis County,**  **which is**  **an attainment**  **area of**  **the National**  **Ambien t**  **Air Quality**  **Standards (NAAQS)**  **for all**  **pollutants, however**  **Holly’s refinery**  **is defined**  **as impacting**  **Salt Lake**  **County in**  **the PM**  **10 SIP. New Source Performance Standards (NSPS) and Maximum Achievable Control Technology**  **(MACT) regulations apply to this sour ce and specifically to this modification. Title V of the 1990 Clean**  **Air Act also applies to this source. This change will not require a modification to the PM**  **10 SIP.**  **The emissions, in tons per year, will change as follows: PM 10**  **- 84, NO** 

**x -**  **81, SO 2**  **- 82, CO**  **+168, VOC +16. These changes in emissions will result in the following, in tons per year, potential to emit totals: PM**  **10 =**  **79, NO**

**x = 613, SO** **2 = 1894.**  The project has been evaluated and found to be consistent with the requirements of the Utah Administrative Code Rule 307 (UAC R307). A public comment period was held in accordance with UAC R307 -401 - 7 and comments were received. The comments were evaluated and none were found to be adverse to the proposed AO. 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 approval order. **General Conditions:** 1. This AO applies to the following company: Site Office Corporate Office Locati on Holly Refining & Marketing Company Holly Refining & Marketing Company 393 South 800 West 393 South 800 West Woods Cross, UT 84087 - 1435 Woods Cross, UT 84087 - 1435 Phone Number (801) 299 - 6600 Fax Number (801) 299 - 6609 The equipment listed in this AO shall be operated at the following location: Plant Location: 393 South 800 West Woods Cross, Utah 84087 - 1435 Universal Transverse Mercator (UTM) Coordinate System: UTM Datum NAD27 4,526.227 kilometers Northing, 424.00 kilometers Easting, Zone 12.DAQE -AN0101230023 - 07

Page 3 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 forth in this AO shall not be exceeded without prior approval in accordance with R307 -401, UAC. 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 . 5. All records referenced in this AO, or in applicable New Source Performance Standards (NSPS), National Emission Standards for Hazardous Air Pollutants (NESHAP), and/or Maximum Achievable Control Technology (MACT) , 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. All records shall be kept for a minimum of five years. 6. Holly Refining and Marketing shall install the new gas oil hydrocracking unit, vacuum tower, associated heaters, two new SRUs with tail gas treatment and sour water stripping, upgrade the FCCU and solvent deasphalting unit, make the required changes in storage tanks, and operate its facility in accordance with the terms and conditions of this AO that is written pursuant to Holly’s notice of intent submitted to the Division of Air Quality on October 5, 2006. 7. Holly shall notify the Executive Secretary in writing when the installation of the equipment listed in Condition #6 has been completed and the equipment is operational, as an initial compliance inspection is required. T o insure proper credit when notifying the Executive Secretary, send your correspondence to the Executive Secretary, attn: Compliance Section. If construction and/or installation have not been completed within eighteen months from the date of this AO, the Executive Secretary shall be notified in writing on the status of the construction and/or installation. At that time, the Executive Secretary shall require documentation of the continuous construction and/or installation of the operation and may revoke the AO in accordance with R307 -401 - 18 . 8. This AO shall replace AO DAQE -AN0123 022 - 06, dated March 14, 2006. 9. The approved installations shall consist of the following equipment or equivalent*: A. (4 - 1) 4H1 FCC Feed Heater B. (4 -4a) 4K1A KVG Compressor West C. (4 -4b) 4K1B KVG Compressor East D. (6 - 1) 6H1 Reformer Charge and Re -he ater Furnace/Waste Heat Boiler E. (6 -2) 6H3 Reformer Reheat Furnace F. (6 - 3) 6H2 Pre - fractionator Re -boiler Heater G. (6 -4a) 6K1 SVG Compressor East H. (6 -4b) 6K2 SVG Compressor West I. (7 - 1) 7H3 H.F. Alkylation De -propanizer Re -boiler J. (7 -2) 7H1 H.F. Alkylation Regeneration Furnace K. (8 - 1) 8H1 Crude Furnace/Waste Heat BoilerDAQE -AN0 101230023 - 07

Page 4 L. (9 - 1) 9H1 Distillate Hydrotreater Reactor Charge Heater M. (9 -2) 9H2 Distillate Hydrotreater Stripper Re -boiler N. (10 -2) 10H1 Crude Desalter Feed Heater O. (11 - 1) 11H1 Straight Run Gas Plant De -pentanizer Re -boiler P. (11 -2) 11K1 Clark Compressor Q. (12 - 1) 12H1 Naphtha Hydrodesulphurization Reactor Charge Furnace R. (13 - 1) 13H1 Isomerization Reactor Feed Furnace S. (17 - 1) Sulfur Recovery Unit Tail Gas Incinerator T. (19 - 1) DHT Re actor Charge Heater U. (45 - 1) 45H1 Asphalt Mix and Storage Furnace V. (68 -2) 68H2 North In - Tank Asphalt Heater W. (68 - 3) 68H3 South In- Tank Asphalt Heater X. (51 -4) #4 Boiler Y. (51 - 5) #5 Boiler Z. (51 - 6) CO Boiler/FCC Scrubber AA. (51 - 7) FCC 34” CO Boiler By pass AB. (51 - 8) #8 Boiler AC. (66 - 1) Process Flare South AD. (66 -2) Process Flare North AE. (68 - 1) Propane Pit Flare AF. Emergency equipment 1. Diesel Powered Water Well No.3 2. Caterpillar Diesel Fire Pump No.1 3. Caterpillar Diesel Fire Pump No.2 4. Detroit Diesel Fire Pump 5. Diesel Powered Plant Air Backup Compressors (3) 6. Diesel -powered Standby Generator, Boiler House 7. Diesel -powered Standby Generator, Central Control Room AG. Three Amine Units (2 new) AH. Fluid Catalytic Cracking (FCC) Unit, which includes the O 2 skid, item #4 - 97 - 0010 AI . Distillate Hydro - desulfurization Treatment (DHT) Unit AJ. Cooling Tower AK. Gas Oil Hydrocracking Unit (new) AL. Reactor Charge Heater (new) AM. Fractionator Charge Heater (new) AN. Vacuum Tower and Vacuum Furnace Heater (new) AO. Hot Oil Heater (new) AP. Asphalt Tank Heaters ( 2 new) AQ. Sour Water Storage Tank AR. Three Sulfur Recovery Units (SRU) (2 new units with Tail Gas Treatment) AS. Two Sour Water Strippers (1 new) AT. NaSH Sour Gas Treatment Unit (new) AU. Hydrogen Plant (new) AV. Storage Tanks (new) AW. Crude Heater (new) AX. Tank 23, 15,000 -barrel distillate storage tank AY. Tank 35, 4,200,000 gallon, cone roof storage tank AZ. Tank 71, 79,944 bbl, with internal floating roof, with primary and secondary s eals BA. Tank 72, 124,388 bbl, with internal floating roof, with primary and secondary sealsDAQE -AN0 101230023 - 07

Page 5 BB. Tank 323, 15,300 bbl, floating roof, with primary seal BC. Tank 79, 10,000 bbl, cone roof tank *Equivalency shall be determined by the Executive Secretary. Operating Specification or Performance Requirements: 10. Copies of the SRU Operating Instruction/Standard shall be made available to the Executive Secretary upon request. **Indicators** 11. Holly shall utilize monitors to measure volumetric flow rates from the SRU stacks. The flow measurement shall be in accordance with the requirements of 40 CFR 52, Appendix E; 40 CFR 60 Appendix B; or 40 CFR 75, Appendix A. 12. Holly shall employ good operating practices to operate the SRUs consistent with their design ob jective of at least 95% efficiency, taking into account usual and customary variation in the refinery process. Whether Holly is complying with the above requirement shall be determined as follows: Whenever any of the daily SRU incinerator SO 2 emissions exceed 90% of the ton/day limitations outlined in condition #15 below, as measured by Continuous Emission Monitoring (CEM), Holly shall within five (5) business days perform a mass balance of the SRU Feed streams using the procedure set forth below: SRU EF FICIENCY MASS BALANCE Holly shall estimate SRU efficiency by using the method set forth below. Calculation: Recovery % = 100 - [[emissions of sulfur/sulfur inlet] X 100] Emissions of Sulfur are the same as the SO 2 emission measured by the Continuous Emi ssions Monitoring System (CEMS) divided by 1.998. The monitoring system shall comply with all applicable sections of R307 - 170 and 40 CFR 60, Appendix B (Specification #2.) Sulfur Inlet is the sulfur in the acid gas feed to the SRU, or Amine Acid Gas (AAG) and Sour Water Acid Gas (SWAG) flow multiplied by the percentage of H2 S content in each stream. Percentage H2 S shall be the values measured, on a wet-basis, in the most recent annual SRU testing pursuant to this Approval Order. The exact units to be used for the calculation must be based on the units of measurement used for these streams on the Distributed Control System (DCS) at the refinery, which are then converted into the same units for purposes of the calculation.DAQE -AN0 101230023 - 07

Page 6 Should the mass balance indicate that the SRU is achieving 95% efficiency, Holly shall have no further obligations. Should the mass balance indicate that the SRU is failing to achieve 95% efficiency, Holly shall undertake an appropriate corrective action as specified below . Within 2 business days after having performed such mass balance, Holly shall report in writing the results of the mass balance to the Executive Secretary. Within 5 business days after having performed such mass balance, Holly shall identify the reason for the SRU failing to achieve 95% efficiency. Within 15 business days after having performed such mass balance, Holly shall complete necessary adjustments or repairs so that the SRU is achieving 95% efficiency as determined by performing a mass balanc e using the same procedures set forth above. Should any necessary repairs require that the SRU be taken out of operation for a turnaround during the months of November through March of any year, Holly shall meet with the Executive Secretary to determine t he schedule on which such turnaround should occur. H olly will not be subj ect to any penalties for its failure to achieve 95% efficiency during this period, provided that it makes the necessary repairs to the SRU within 15 days of the date on which Holly shuts the unit down for repair. P ending such repairs, Holly shall make adjustments to improve SRU efficiency to the extent practicable. Should Holly determine that necessary repairs require that equipment be replaced or repaired, and that such replacement or repair cannot be performed within 15 days, Holly shall report in writing to the Executive Secretary the reason such repairs cannot be completed within the time and the schedule for completion. H olly shall meet with the Executive Secretary and jointly develop a course of action to protect air quality consistent with practical options available to Holly. S hould Holly and the Executive Secretary agree that Holly's failure to restore 95% efficiency within 15 days was caused by an unavoidable breakdown subject to an affirmative defense pursuant to R307 - 107, then Holly shall not be subject to penalties for its failure to restore 95% efficiency within 15 days. S hould they agree that the failure to restore efficiency within 15 days was unavoidable and theref ore not subject to an affirmative defense, then Holly shall be subject to penalties, unless the Executive Secretary requests Holly delay instituting repairs for air quality reasons, in which case Holly shall not be liable for penalties for that time period in which the Executive Secretary requested that Holly delay instituting necessary repairs. In any event, pending completion of repairs, Holly shall make adjustments to improve SRU efficiency to the extent practicable. Should the adjustment or repair b e effective for 30 days

– i.e., no repeat failure modes of the same type

– there shall be no violation. A separate failure within the 30 - day period shall constitute a new event. 13. SRU efficiency shall be estimated and reported to the Executive Secretary a minimum of once per year via the method specified in condition 12: Over a minimum of three and a maximum of seven operating days, or other period of time approved by the Executive Secretary of the Utah Air Quality Board, the total SRU sulfur output and incinerator SO 2 emissions (on a mass basis) shall be measured. B ased on these two parameters, sulfur input and SRU efficiency shall be calculated. An alternate method may be used if approved by the Executive Secretary; the Executive SecretaryDAQE -AN0 101230023 - 07

Page 7 recognizes that the method used by Holly (Phillips) in 1998 and 1999, or its equivalent, is an alternate approved method. Executive Secretary Authority A request to determine SRU efficiency for any time period may be ordered by the Executive Secretary. All records of SRU performance shall be maintained for a minimum of two years. 14. Emissions Credit Trade - Off The refinery may exercise an option to trade allowed annual SRU SO 2 emissions for cap sources' SO 2 emissions in the event the SRU is operating at better than 95% efficiency. This option shall not be made available until at least one year of data (12 efficiency determinations), as described below, has been collected and a trade - off request is submitted to and approved by the Executive Secretary. The (SRU) 2 4 -hour minimum operating efficiency shall have been demonstrated to be no less than 95%. When the SRU efficiency, as determined below, is greater than 95%, adjustments to the annual SO 2 emission limit for cap sources (see the AO conditions for definition of cap sources) may be made by the following procedure:

 An adjusted annual cap emission limit is the annual cap sources' emission limit adjusted upward. This adjustment is derived from SO 2 emission decreases resulting from a better than 95% efficient SRU operation.

 The adjusted annual cap emission limit shall only be used for compliance demonstration purposes. The combined annual total cap sources' and SRU SO 2 limit used for attainment and maintenance demonstration shall not be increased.

 Daily compliance limits shall not be put on an adjusted basis. 15. The emission of SO 2 into the atmosphere [excluding those from flares and during SRU down times] shall not exceed 1639 tons/year , to be emitted from the following points: The emissions shall not exceed the following: Emission Points Emissions (TPD 1 ) Total Emissions (tons/yr) (17 - 1) SRU Tail Gas Incinerator 1.60 582 (new) SRU Tail Gas Incinerator #1 0.25 90 (new) SRU Tail Gas Incinerator #2 0.25 90 (51 - 6) CO Boiler/FCC Scrubber 1.93 706 Emission Cap sources 0.47 171

1 TPD: Tons Per Day = Daily 24 -hour total. CEM shall be used to determine (a) emission rates, and (b) compl iance with the emission rates. Daily means an interval of time between two consecutive midnights.DAQE -AN0 101230023 - 07

Page 8 16. The following sources shall be included in the SO 2 emissions cap: Source (4 - 1) 4H1 FCC Feed Heater (Low-NO X) (4 -4a) 4K1A KVG Compressor West (4 -4b) 4K1B KVG Compressor East (6 - 1) 6H1 Reformer Charge & Re -heater Furnace/Waste Heat Boiler (6 -2) 6H3 Reformer Reheat Furnace (6 - 3) 6H2 Prefractionator Re -Boiler Heater (6 -4a) 6K1 SVG Compressor East (6 -4b) 6K2 SVG Compressor West (7 - 1) 7H3 H.F. Alkylation Depropanizer Re -boiler (7 -2) 7H1 H.F. Alkylation Regeneration Furnac e (8 - 1) 8H1 Crude Furnace/Waste Heat Boiler (9 - 1) 9H1 Distillate Hydrotreater Reactor Charge Heater (9 -2) 9H2 Distillate Hydrotreater Stripper Re -boiler (10 -2) 10H1 Solvent De - asphalting Re -heater Furnace (11 - 1) 11H1 Straight Run Gas Plant Depentanizer Re -boiler (12 - 1) 12H1 Naphtha Hydrodesulphurization Reactor Charge Furnace (13 - 1) 13H1 Iso merization Reactor Feed Furnace (19 - 1) DHT Reactor Charge Heater (Low-NO X) (45 - 1) 45H1 Asphalt Mix and Storage Furnace (Low-NO X) (68 -2) 68H2 North In -tank Asphalt Heater (68 - 3) 68H3 South In- Tank Asphalt Heater (51 -4) #4 Boiler (51 - 5) #5 Boiler (51 - 8) #8 Boiler (Low NO X) Reactor Charge Heater Fractionator Charge Heater Vacuum Furnace Heater Hot Oil Heater Asphalt Tank Heaters (2) Hydrogen Plant Furnace #1 Hydrogen Plant Furnace #2 17. The following sources shall not be regulated for SO 2 emissions, nor shall they be included in the emission limitation totals herein: (66 - 1) Process Flare South (66 -2) Process Flare North (68 - 1) Propane Pit Flare Emergency Equipment liste d in condition 9.AF 18. Method of Calculations: Sulfur Dioxide SO 2 emissions for the emissions cap sources shall be determined by applying the following emission factors to the relevant quantities of fuel burned. This shall be performed according to the following:DAQE -AN0 101230023 - 07

Page 9 A. SO 2 Emission factors for the various fuels shall be as follows:

 Natural gas - 0.60 lb/MMscf (Compressors Only)

 Plant gas - The emission factor to be used in conjunction with plant gas combustion shall be determined through the use of a contin uous emissions monitor which will measure the H2 S content of the fuel gas in parts per million by volume (ppmv). D aily emission factors shall be calculated using average daily H2 S content data from the continuous emissions monitor (CEM). The emission factor shall be calculated as follows: (lb SO 2/MMscf gas) = (24 hr avg. ppmv H2 S)/10 6 * (64 lb SO 2/lb mole) * (10 6 scf/MMscf) /(379 scf / lb mole)

 Fuel oil - The emission factor to be used in conjunction with fuel oil combustion (during natural gas curtailments) shall be calculated based on the weight percent of sulfur, as determined by ASTM Method 0 -4294 - 89 or approved equivalent, and the density of the fuel oil, as follows: (lb of SO 2/kgal) = (density lb/gal) * (1000 gal/kgal) * (wt. % S)/100 * (64 g SO 2/32 g S)

 The weight percent sulfur and the fuel oil density shall be recorded for each day any fuel oil is combusted. Fuel oil may be combusted only during periods of natural gas curtailment. The sulfur content of the fuel oil shall be tested if directed by the Executive Secretary. B. Fuel Consumption shall be measured as follows:

 Natural gas consumption shall be determined by the meter totalizer on the natural gas supplied to the plant.

 Plant gas consumption shall be determined through the use of flow meters  Fuel oil consumption shall be measured each day by means of leveling gauges on all tanks that supply oil to combustion sources. C. The equations used to determine emissions for the emission cap sources shall be as follows: Emissions (tons/day) = Emiss ion Factor (lb/MMscf) * Natural Gas Consumption

(MMscf/day2 )/(2,000 lb/ton) Emissions (tons/day) = Emission Factor (lb/MMscf) * Plant Gas Consumption

(MMscf/day)/(2,000 lb/ton)

2 Day is defined as a 24 - hour period between two consecutive midnights.DAQE -AN0 101230023 - 07

Page 10 Emissions (tons/day) = Emission Factor (lb/kgal) * Fuel Oil Consumpti on (kgal/24 hrs)/(2,000 lb/ton) D. Total daily SO 2 emissions for the sources included in the emissions cap shall be calculated by adding the daily results of the above SO 2 emissions equations for natural gas, plant gas, and fuel oil combustion. Results shall be tabulated for every day, and records shall be kept which include the CEM readings for H2 S (averaged for each one -hour period), all meter readings (in the appropriate units), fuel oil parameters (density and wt. % S, recorded for each day any fuel oil is burned), and the calculated emissions. 19. Emissions: Oxides of Nitrogen [NO X] Maximum NO X emissions to the atmosphere shall not exceed 1.98 tons per day . NO X emissions from all sources included in the emissions cap shall not exceed 1.98 tons per day . The emission limitation for NO X from all sources shall not exceed 613 tons/year . 20. The following sources shall be included in the NO X emissions cap: Source (4 - 1) 4H1 FCC Feed Heater (Low-NO X) (4 -4a) 4K1A KVG Compressor West (4 -4b) 4K1B KVG Compress or East (6 - 1) 6H1 Reformer Charge & Re -heater Furnace/Waste Heat Boiler (6 -2) 6H3 Reformer Reheat Furnace (6 - 3) 6H2 Prefractionator Re -Boiler Heater (6 -4a) 6K1 SVG Compressor East (6 -4b) 6K2 SVG Compressor West (7 - 1) 7H3 H.F. Alkylation Depropanizer Re -Boi ler (7 -2) 7H1 H.F. Alkylation Regeneration Furnace (8 - 1) 8H1 Crude Furnace/Waste Heat Boiler (9 - 1) 9H1 Distillate Hydrotreater Reactor Charge Heater (9 -2) 9H2 Distillate Hydrotreater Stripper Re -Boiler (10 -2) 10H1 Solvent Deasphalting Re -heater Furnace (1 1 - 1) 11H1 Straight Run Gas Plant Depentanizer Re - Boiler (12 - 1) 12H1 Naphtha Hydrodesulphurization Reactor Charge Furnace (13 - 1) 13H1 Iso merization Reactor Feed Furnace (17 - 1) Sulfur Recovery Unit Tail Gas Incinerator (19 - 1) DHT Reactor Charge Heater (Low-NO X) (45 - 1) 45H1 Asphalt Mix and Storage Furnace (Low-NO X) (68 -2) 68H2 North In - Tank Asphalt Heater (68 - 3) 68H3 South In- Tank Asphalt Heater (51 -4) #4 Boiler (51 - 5) #5 Boiler (51 - 6) CO Boiler (51 - 8) #8 Boiler (Low NO X) Reactor Charge Heater Fractionator Charge Heater Vacuum Furnace HeaterDAQE -AN0 101230023 - 07

Page 11 Hot Oil Heater Asphalt Tank Heaters (2) Hydrogen Plant Furnace #1 Hydrogen Plant Furnace #2 (new) Sulfur Recovery Unit Tail Gas Incinerator #1 (new) Sulfur Recovery Unit Tail Gas Incinerator #2 21. The following sources shall not be regulated for NO X emissions, nor shall they be included in the emission limitation totals herein: (66 - 1) Process Flare South (66 -2) Process Flare North (68 - 1) Propane Pit Flare Emergency Equipment listed in condition 9.AF 22. Method of Calculation: Oxides of Nitrogen [NO X] Cap Sources NO X emissions for the Emissions Cap Sources shall be determined by applying various emission factors to the relevant quantities of fuel combusted. A. Boilers and Furnaces: Low NO X 81 lbs/MMscf Ultra-Low NO X 41 lbs/MMscf Natural gas 140 lbs/MMscf Plant gas 140 lbs/MMscf Fuel oil 120 lbs/Kgal

 Daily natural gas consumption shall be determined by the meter totalizer on the natural gas supplied to the plant.

 Daily plant gas consumption shall be determined through the use of flow meters.

 Daily fuel oil consumption shall be monitored by me ans of leveling gauges on all tanks that supply combustion sources. Fuel oil consumption shall be allowed only during periods of natural gas curtailment.

 The equations us ed to determine emissions for the boilers and furnaces shall be as follows: Emissions (tons/day) = Emission Factor (lb/MMscf) * Natural Gas Consumption

(MMscf/day)/(2,000 lb/ton) Emissions (tons/day) = Emission Factor (lb/MMscf) * Plant Gas Consumption

(MMscf/day)/(2,000 lb/ton) Emissions (tons/day) = Emission Factor (lb/kgal) * Fuel Oil Consumption (kgal/day)/

(2,000 lb/ton)DAQE -AN0 101230023 - 07

Page 12 B Compressors:

The NO X Emission Factor for natural gas (firm supply) combustion in the compressor drivers shall be 340 0 lb/MMscf. Daily natural gas (firm supply) consumption for the compressor drivers shall be quantified by meters, which shall be installed if necessary, that will differentiate the flow of natural gas to the compressors from the flow to the of boilers and furnaces. The emissions shall then be determined using the following equation: Emissions (tons/day) = Emission Factor (lb/MMscf) * Natural Gas Consumption

(MMscf/day)/(2,000 lb/ton) Tota1 24 -hour NO X emissions for sources included in the emissions cap shall be calculated by adding the results of the above NO X equations for plant gas, fuel oil, and natural gas combustion. Results shall be tabulated for every day, and records shall be kept which include the meter readings (in the appropriate units), emission factors, and the calculated emissions. S ee Section IX .H.1.i(2) of the PM 10 SIP for details of compliance determination. 23. Emissions: PM 10 The emissions shall not exceed the following: Emission Points Emissions (TPD) Total Emissions (tons/yr) (51 - 6) CO Boiler/FCC Scrubber 0.09 32 Emission Cap 0.13 47 Total 0.22 79 24. The following sources shall be included in the PM 10 emissions cap: Source (4 - 1) 4H1 FCC Feed Heater (Low-NO X) (6 - 1) 6H1 Reformer Charge & Re -heater Furnace/Waste Heat Boiler (6 -2) 6H3 Reformer Reheat Furnace (6 - 3) 6H2 Prefractionator Re -Boiler Heater (7 - 1) 7H3 H.F. Alkylation Depropanizer Re -Boiler (7 -2) 7H1 H.F. Alkylation Regeneration Furnace (8 - 1) 8H1 Crude Furnace/Waste Heat Boiler (9 - 1) 9H1 Distillate Hydrotreater Reactor Charge Heater (9 -2) 9H2 Distillate Hydrotreater Stripper Re -Boiler (10 -2) 10H1 Solvent Deasphalting Re -heater Furnace (11 - 1) 11H1 Straight Run Gas Plant Depentanizer Re - Boiler (12 - 1) 12H1 Naphtha Hydrodesulphurization Reactor Charge Fur naceDAQE -AN0 101230023 - 07

Page 13 (13 - 1) 13H1 Isomerization Reactor Feed Furnace (17 - 1) Sulfur Recovery Unit Tail Gas Incinerator (19 - 1) DHT Reactor Charge Heater (Low-NO X) (45 - 1) 45H1 Asphalt Mix and Storage Furnace (Low-NO X) (68 -2) 68 H2 North In - Tank Asphalt Heater (68 - 3) 68H3 South In- Tank Asphalt Heater (51 -4) #4 Boiler (51 - 5) #5 Boiler (51 - 7) FCC 34” CO Boiler Bypass (breakdowns only) (51 - 8) #8 Boiler (Low NO X) Reactor Charge Heater Fractionator Charge Heater Vacuum Furnace Heater Hot Oil Heater Asphalt Tank Heaters (2) Hydrogen Plant Furnace #1 Hydrogen Plant Furnace #2 (new) Sulfur Recovery Unit Tail Gas Incinerator #1 (new) Sulfur Recovery Unit Tail Gas Incinerator #2 25. The following sources shall not be regulated for PM 10 emissions, nor shall they be included in the emission limitation totals herein: (4 -4a) 4K1A KVG Compressor West (4 -4b) 4K1B KVG Compressor East (6 -4a) 6K1 SVG Compressor East (6 -4b) 6K2 SVG Compressor West (66 - 1) Process Flare South (66 -2) Process Flare North (68 - 1) Propane Pit Flare Emergency Equipment li sted in Section 9.AF 26. Method of calculation: PM 10 Cap Sources

 PM 10 emissions for the Emissions Cap Sources shall be determined by applying the following emission factors to the relevant quantities of fuel combusted in each unit. This shall be performed according to the following:

 PM 10 Emission Factors for the combustion sources will be as follows: Natural gas: 5 lb/MMscf Plant gas: 5 lb/MMscf

 The PM 10 emission factor for fuel oil combustion shall be determined based on the H2 S content of the fuel oil as follows: PM 10 (lb/kgal) = (10 * wt.% S) + 3DAQE -AN0 101230023 - 07

Page 14

 Daily natural gas consumption for each cap source shall be determined by the meter

totalizer on the natural gas supplied to the plant.

 Daily plant gas consumption for each cap source shall be determined through the use of flow meters.

 Daily fuel oil consumption shall be monitored by means of leveling gages on all tanks that supply fuel oil to combustion sources. Fuel oil consumption shall be allowed only during periods of natural gas curtailment.

 The equations used to determine emissions for the boilers and furnaces shall be as follows: Emissions (tons/day) = Emission Factor (lb/MMscf) * Natural Gas Consumption



### (MMscf/day)/(2,000 lb/ton) Emissions (tons/day) = Emission Factor (lb/MMscf) * Plant Gas C onsumption

(MMscf/day)/(2,000 lb/ton) Emissions (tons/day) = Emission Factor (lb/kgal) * Fuel Oil Consumption (kgal/day)/

(2,000 lb/ton) Total 24 -hour PM 10 emissions for the sources included in the emissions cap shall be calculated by adding the daily results of the above PM 10 emissions equations for natural gas, plant gas, and fuel oil combustion. Results shall be tabulated for every day, and records shall be kept which include all meter readings (in the appropriate units), fuel oil parameters (wt . % S), and the calculated emissions. F or the details of compliance demonstration, refer to Section IX .H.1.i(2) of the PM 10 SIP. 27. Stack testing to determine compliance shall be performed in accordance with the requirements of Section IX.H.1.a of the P M 10 SIP. Stack testing shall be performed as specified below: Emission Point Pollutant Test Status Frequency (51 - 6) CO Boiler

/FCC Scrubber SO2 * ** SRU Incinerator SO2 CEM 3 SRU Incinerator #1 SO2 CEM SRU Incinerator #2 SO2 CEM Testing Status (To be applied above) * No initial testing is required. However, the Executive Secretary may require testing at any time in accordance with R307 - 165 - 1 , UAC. The source shall be tested if directed by the Executive Secretary.

3 In keeping with the requirements to the SIP, the CEM shall be the compliance - determining method for SO 2 .DAQE -AN0 101230023 - 07

Page 15 Test Frequency (To be applie d above)

** Test every five years. Notification The applicant shall provide a notification of the test date at least 45 days prior to the test. A pretest conference shall be held if directed by the Executive Secretary. It shall be held at least 30 days prior to the test between the owner/operator, the tester, and the Executive Secretary. The emission point shall be designed to conform to the requirements of 40 CFR 60, Appendix A, Method 1, and of the Occupational Safety and Health Administration (OSHA) or Mine Safety and Health Administration (MSHA). Easy access shall be provided to the test location. PM 10 For stacks in which no liquid drops are present, the following methods shall be used: 40 CFR 51, Appendix M, Methods 201, 201a, or 202. The back half condensables shall also be tested using the method specified by the Executive Secretary. 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 condensables shall also be tested using the method specified by the Executive Secretary. All particulate captured shall be considered PM 10 . The back half condensables shall not be used for compliance demonstration but shall be used for inventory purposes. Sample Location 40 CFR 60 Appendix A, Method 1 Volumetric Flow Rate 40 CFR 60 Appendix A, Method 2 Sulfur Dioxide (SO 2 ) CEM for the SRU Incinerators For the CO Boiler: 40 CFR 60, Appendix A, Method 6, 6A, 6B, 6C, or other testing methods approved by the Executive Secretary. Calculations 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.DAQE -AN0 101230023 - 07

Page 16 Source Operation For an existing source/emission point, the production rate during all compliance testing shall be no less than 90% of the maximum production achieved in the previous three years. 28. Visible emissions shall not exceed the following specifications:

- All scrubbers: 15 % opacity

- All baghouses: 10% opacity

- All combustion sources without controls: 10% opacity

- FCC Unit/(51 - 6): 20% opacity

- (8 - 1) 8H1 Crude Furnace/Waste Heat Boiler: 20% opacity

- Flares - 20% opacity

- All fugitive emission points - 20% opacity Opacity observations of emissions from stationary sources shall be conducted in accordance with 40 CFR 60, Appendix A, Method 9. 29. The amine plants shall reduce the H2 S content of the refinery plant gas to 0.10 grain/dscf (160 ppm) or less . The owner/operator has installed and maintains a continuous monitoring system for monitoring the H2 S content of the refinery plant gas and a continuous recorder to record the H2 S in the plant fuel gas. The mo nitoring system shall comply with all applicable sections of R3 07 - 170 - 1, and 40 CFR 60, Appendix B, Specification 7. 30. The owner/operator shall use only natural gas or plant fuel gas as a primary fuel and fuel oil as a backup fuel. If any other fuel is to be used, an AO shall be required in accordance with R307 -40 1. Small (<100 HP) fuel oil -powered equipment is exempt from the requirements of this Approval Order and related emissions are not to be used for purposes of determining compliance. 31. The total hours of operation for all the emergency diesel powered equipment listed in condition 9.AF shall not exceed 300 hours per 12 -month period, except in the case of a breakdown, without prior approval in accordance with R307 -401. C ompliance with the annual limitation shall be determined on a rolling 12 -month total. By the last day of each month a new 12 -month total shall be calculated using the previous 12 months. Records of the hours of operation shall be kept for all periods when the plant is in operation. Records of the hours of operation shall be made availabl e to the Executive Secretary or the Executive Secretary’s representative upon request, and shall include a period of two years ending with the date of the request. The total hours of operation may be determined by an engine hour totalizer installed on each engine, but a separate record of nonemergency hours shall be kept on a weekly basis. Emissions from this equipment shall not be included under the emissions cap. 32. The following tank throughput limits shall not be exceeded : Tank 71 B Three turnovers of gasoline or other liquid materials from the refinery streams (providing that its RVP is less than 9) per calendar year. Tank 72 B Three turnovers of gasoline or other liquid materials from the refinery streams (providing that its RVP is less than 9) per calendar year.DAQE -AN0 101230023 - 07

Page 17 33. Compliance with the annual limitations shall be determined on a rolling 12 -month total except where specifically exempted or otherwise provided for. B y the last day of each month, a new 12 - month total shall be calculated using the previous 12 months. Records of tank throughput shall be kept for all periods when the plant is in operation. Records of tank throughput, including calendar year totals shall be made available to the Executive Secretary’s representative upon request. Rec ords shall be kept for a period of five years. Records of tank throughput shall be maintained on blend sheets. Records of end- of -month tank volumes shall be maintained on the month - end gauge sheets. 34. The following VOC emission limitss shall not be exceeded: A. Tank 71 and 72: 4.03 tons VOC per calendar year B. Tank 79: 0.11 ton s VOC per calendar year Compliance with the limitation shall be determined based on a calendar year total based on tank throughput as outlined in Condition #32. Annual emissi ons shall be calculated for the previous calendar year by January 31 each year. The VOC emissions emitted to the atmosphere shall be determined using Tanks 4 program, or an equivalent approved by the Executive Secretary. The records should include all the input parameters needed for Tanks 4. Small (<100 HP) portable fuel oil -powered equipment is exempt from the requirements of this AO and related emissions are not to be used for purposes of determining compliance. 35. The sulfur content of any fuel oil burned shall not exceed 0.5% by weight as determined by ASTM Method D -4294 - 89 or approved equivalent. The sulfur content shall be tested if directed by the Executive Secretary. 36. In addition to the requirements of this AO, all applicable provisions of 40 CFR 60, NSPS Subparts A (General), J (Standards of Performance for Petroleum Refineries), Kb (Standards of Performance for VOL Storage Vessels), GGG (Standards of Performance for Equipment Leaks of VOC in Petroleum Refineries), QQQ (Standards of Performance for VOC Emissions from Petroleum Refinery Wastewater Systems), and 40 CFR 63 NESHAPS, Subpart CC (National Emission Standards for Hazardous Air Pollutants from Petroleum Refineries) shall apply to the affected installation . **Records & Miscellaneous** 3 7. The owner/operator shall comply with R307 - 155 - 1, UAC. This rule addresses emission inventory reporting requirements. 38. The owner/operator shall comply with R307 - 107 -2, UAC. This rule addresses excess emission reporting requirements. The owner/operator shall calculate/estimate the excess emissions as required by the rule. The total of excess emissions shall be reported to the Executive Secretary as directed for each calendar year. 39. At all times, including periods of startup, shutdown, and malfunction, owners and operators shall, to the extent practicable, maintain and operate any equipment approved under this AO includingDAQE -AN0 101230023 - 07

Page 18 associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emi ssions. D etermination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Executive Secretary which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. All maintenance performed on equipment authorized by this AO shall be recorded. The Executive Secretary shall be notified in writing if the company is sold or changes its name. 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 R307. A copy of the rules, regulations and/or attachments addressed in this AO may be obtained by con tacting the Division of Air Quality. The Utah Administrative Code R307 rules used by DAQ, the Notice of Intent (NOI) guide, and other air quality documents and forms may also be obtained on the Internet at the following web site: http://www.airquality.Utah.gov Maximum annual emissions for this source, as defined in the PM 10 SIP, Section IX .H.2.f, are currently set at the following values [all in tons per year]:

A. Particulate Matter 202.00 B. PM 10 162 .00 C. SO 2 1975.00 [includes 118 tpy for flares and 136 tpy for SRU downtime] D. NO X 693.00 These calculated emissions are for the purposes of determining the applicability of prevention of significant deterioration (PSD) and nonattainment area major source requirements of the UACR. Except for B, C, and D above, they are not to be used for purposes of determining compliance. The Division of Air Quality is authorized to charge a fee for reimbursement of the actual costs incurred in the issuance of an AO. An invoice will follow upon issuance of the final Approval Order. Sincerely, Richard W. Sprott, Executive Secretary Utah Air Quality Board