DAQE-AN0101230023-07

June 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: N010123-0023

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 questions 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

DIVISION 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: Holly Modernization 

Project – CO PSD Major Modification

Prepared By: John D. Jenks, Engineer

(801) 536-4459

Email: jjenks@utah.gov

APPROVAL ORDER NUMBER

DAQE-AN0101230023-07

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) has submitted a Notice of Intent to perform a number 

of modernization upgrades at their refinery in Woods Cross, Utah. Primarily, these changes will result 

in decreases in emissions, with the exception of volatile organic compounds (VOC) and carbon 

monoxide (CO). The CO emissions will increase by more than 100 tons per year, making this 

modification a Prevention of Significant Deterioration (PSD) major modification. The refinery is 

located in Davis County, which is an attainment area of the National Ambient Air Quality Standards 

(NAAQS) for all pollutants, however Holly’s refinery is defined as impacting Salt Lake County in the 

PM10 SIP. New Source Performance Standards (NSPS) and Maximum Achievable Control Technology 

(MACT) regulations apply to this source 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 PM10 SIP.

The emissions, in tons per year, will change as follows: PM10 -84, NOx -81, SO2 -82, CO +168, VOC +16. 

These changes in emissions will result in the following, in tons per year, potential to emit totals: PM10 = 

79, NOx = 613, SO2 = 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 Location

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. To 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-AN0123022-06, 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-heater 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 Boiler
DAQE-AN0101230023-07

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 Reactor 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 Bypass

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 O2 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 seals

BA. Tank 72, 124,388 bbl, with internal floating roof, with primary and secondary seals
DAQE-AN0101230023-07

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 

objective 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 SO2 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 EFFICIENCY 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 SO2 emission measured by the Continuous Emissions 

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 H2S content in each stream. 

Percentage H2S 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-AN0101230023-07

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 balance 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 the schedule on which such turnaround should 

occur. Holly will not be subject 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. Pending 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. Holly shall meet with the 

Executive Secretary and jointly develop a course of action to protect air quality consistent 

with practical options available to Holly. Should 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. Should they 

agree that the failure to restore efficiency within 15 days was unavoidable and therefore 

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 be 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 SO2 emissions (on a mass basis) shall be 

measured. Based 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 Secretary 
DAQE-AN0101230023-07

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 SO2 emissions for cap sources' 

SO2 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) 24-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 SO2 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 SO2 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 SO2 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 SO2 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 (TPD1) 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) compliance 

with the emission rates. Daily means an interval of time between two consecutive midnights.
DAQE-AN0101230023-07

Page 8

16. The following sources shall be included in the SO2 emissions cap:

Source

(4-1) 4H1 FCC Feed Heater (Low-NOX)

(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 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 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 Isomerization Reactor Feed Furnace

(19-1) DHT Reactor Charge Heater (Low-NOX) 

(45-1) 45H1 Asphalt Mix and Storage Furnace (Low-NOX)

(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 NOX)

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 SO2 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

18. Method of Calculations: Sulfur Dioxide

SO2 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-AN0101230023-07

Page 9

A. SO2 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 continuous emissions monitor 

which will measure the H2S content of the fuel gas in parts per million by volume 

(ppmv). Daily emission factors shall be calculated using average daily H2S 

content data from the continuous emissions monitor (CEM). The emission factor 

shall be calculated as follows:

(lb SO2/MMscf gas) = (24 hr avg. ppmv H2S)/106* (64 lb SO2/lb mole) * (106

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 SO2/kgal) = (density lb/gal) * (1000 gal/kgal) * (wt. % S)/100 * (64 g 

SO2/32 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) = Emission 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-AN0101230023-07

Page 10

Emissions (tons/day) = Emission Factor (lb/kgal) * Fuel Oil Consumption (kgal/24 

hrs)/(2,000 lb/ton)

D. Total daily SO2 emissions for the sources included in the emissions cap shall be calculated 

by adding the daily results of the above SO2 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 H2S (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 [NOX]

Maximum NOX emissions to the atmosphere shall not exceed 1.98 tons per day. NOX emissions 

from all sources included in the emissions cap shall not exceed 1.98 tons per day. The emission 

limitation for NOX from all sources shall not exceed 613 tons/year.

20. The following sources shall be included in the NOX emissions cap:

Source

(4-1) 4H1 FCC Feed Heater (Low-NOX)

(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 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 Furnace

(13-1) 13H1 Isomerization Reactor Feed Furnace

(17-1) Sulfur Recovery Unit Tail Gas Incinerator

(19-1) DHT Reactor Charge Heater (Low-NOX)

(45-1) 45H1 Asphalt Mix and Storage Furnace (Low-NOX)

(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 NOX)

Reactor Charge Heater

Fractionator Charge Heater

Vacuum Furnace Heater
DAQE-AN0101230023-07

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 NOX 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 [NOX] Cap Sources

NOX 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 NOX 81 lbs/MMscf

Ultra-Low NOX 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 means 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 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 Consumption

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

Emissions (tons/day) = Emission Factor (lb/kgal) * Fuel Oil Consumption (kgal/day)/

(2,000 lb/ton)
DAQE-AN0101230023-07

Page 12

B Compressors:

The NOX Emission Factor for natural gas (firm supply) combustion in the compressor 

drivers shall be 3400 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 NOX emissions for sources included in the emissions cap shall be calculated 

by adding the results of the above NOX 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. See Section IX.H.1.i(2) of the PM10 SIP for details of compliance 

determination.

23. Emissions: PM10

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 PM10 emissions cap:

Source

(4-1) 4H1 FCC Feed Heater (Low-NOX)

(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 Furnace
DAQE-AN0101230023-07

Page 13

(13-1) 13H1 Isomerization Reactor Feed Furnace

(17-1) Sulfur Recovery Unit Tail Gas Incinerator

(19-1) DHT Reactor Charge Heater (Low-NOX)

(45-1) 45H1 Asphalt Mix and Storage Furnace (Low-NOX)

(68-2) 68H2 North In-Tank Asphalt Heater

(68-3) 68H3 South In-Tank Asphalt Heater

(51-4) #4 Boiler

(51-5) #5 Boiler

(51-7) FCC 34” CO Boiler Bypass (breakdowns only)

(51-8) #8 Boiler (Low NOX)

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 PM10 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 listed in Section 9.AF

26. Method of calculation: PM10 Cap Sources

 PM10 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:

 PM10 Emission Factors for the combustion sources will be as follows:

Natural gas: 5 lb/MMscf

Plant gas: 5 lb/MMscf

 The PM10 emission factor for fuel oil combustion shall be determined based on the H2S 

content of the fuel oil as follows:

PM10 (lb/kgal) = (10 * wt.% S) + 3
DAQE-AN0101230023-07

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 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 Consumption

(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 PM10 emissions for the sources included in the emissions cap shall be calculated by 

adding the daily results of the above PM10 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. For the details of compliance demonstration, refer to Section IX.H.1.i(2) of the PM10

SIP.

27. Stack testing to determine compliance shall be performed in accordance with the requirements of 

Section IX.H.1.a of the PM10 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 CEM3

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 SO2.
DAQE-AN0101230023-07

Page 15

Test Frequency (To be applied 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.

PM10

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 PM10.

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 (SO2)

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-AN0101230023-07

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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 H2S 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 H2S content of the refinery plant gas and a continuous recorder to record the H2S in 

the plant fuel gas. The monitoring system shall comply with all applicable sections of R307-170-

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 R307-401. 

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. Compliance 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 available 

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-AN0101230023-07

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. By 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. 

Records 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 tons 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 emissions 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

37. 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 including 
DAQE-AN0101230023-07

Page 18

associated air pollution control equipment in a manner consistent with good air pollution control 

practice for minimizing emissions. Determination 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 contacting 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 PM10 SIP, Section IX.H.2.f, are currently set 

at the following values [all in tons per year]:

A. Particulate Matter 202.00

B. PM10 162.00

C. SO2 1975.00 [includes 118 tpy for flares and 136 tpy for SRU 

downtime]

D. NOX 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