DAQE-AN0119054-05

April 8, 2005

Kris Battleson

Chevron Texaco Products Company

2351 North 1100 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: N0119-053

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

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: 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-AN0119054-05

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 the 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 replacement 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 approval 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: 

PM10 = 175.0 

NOx = 1021.6 

SO2 = 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 provide 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 achieved 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 (hydro-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 increase 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 Chevron 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, shows 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 SUMMARY: CHEVRONTEXACO SALT LAKE REFINERY

CLEANER BURNING FUELS PROGRAM^

Pollutant SIP 

Potential Emissions

Current 

Actual 

2002/2003 

Proposed 

CFP* 

Changes

SLR** 

Banked 

Credits

NOx 1,021.6 780.6 11.8 0

SO2 2,578.2 1261.3 10.0 0

PM10 85.6 73.0 2.9 89.4

CO NA 419.5 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 maintenance status. But as the refinery affects the Salt Lake County’s (non-attainment) 

emission level of PM10, SO2, and NOx (see the Utah PM10 SIP,) Chevron has chosen low NOx (0.02 

lb/MMBtu) burners and a Tail Gas Unit to increase the SRU efficiency to about 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 refinery 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 public-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) 539-7130
DAQE-AN0119054-05

Page 4

PLANT LOCATION:

Chevron 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 forth 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 R307-305-2.

7. This AO shall replace Approval Orders DAQE-AN0119052-05, 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. Boiler #11005 (Low-NOx)

C. Crude Unit Furnace F-21001 (Low-NOx)

D. Crude Unit Furnace F-21002 (Low-NOx)

E. FCC Furnace F-32021

F. FCC Furnace F-32023

G. HDN Furnace F-71010

H. HDN Furnace F-71030
DAQE-AN0119054-05

Page 5

I. Reformer Furnace F-35001

J. Reformer Furnace F-35002

K. Reformer Furnace F-35003

L. Alkylation Furnace F-36017 (Low-NOx)

M. Coker Furnace F-70001

N. HDS Furnace F-64010 (Low-NOx)

O. HDS Furnace F-64011 (Low-NOx)

P. VGO Furnaces F-66100 and F-66200 (Low-NOx)

Q. Reformer Compressor Drivers (natural-gas fired)

R. Sulfur Recovery Unit/Tail Gas Treating Unit/Tail Gas 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 emissions 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

Crude 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 gas
DAQE-AN0119054-05

Page 6

HDS Furnace F-64010 Plant gas

HDS Furnace F-64011 Plant gas

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 emission.

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 determined by ASTM Method D4294-89 or approved equivalent, and the density of the fuel oil, as follows:

EF (lb SO2/k gal) = density (lb/gal) * (1000 gal/k gal) * wt.% S/100 * (64 lb SO2/32 lb S) 

Plant gas: the emission factor shall be calculated from the H2S measurement obtained 

from the H2S continuous emission monitor required elsewhere in this permit. The 

emission factor shall be calculated as follows:

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

scf/MMscf)/(379 scf/lb mole)

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 SO2 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 emission 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 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 

SO2 CEM is bypassed for short periods, SO2 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 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 appropriate methods below, shall be multiplied by the volumetric 

flow rate and any necessary conversion factors as determined by the Executive Secretary 
DAQE-AN0119054-05

Page 7

to establish the FCC Catalyst Regenerator SO2 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 SO2 emission rate. 40 CFR 60, Appendix A, Method 2 shall be used to determine the 

volumetric flow rate.

10. Emissions of SO2 from the sources listed under the SO2 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 SO2 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.

11. Emissions of sulfur dioxide from the SRU shall not exceed 2.128 tons/day. Compliance 

with 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 in 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 

SO2 CEM is bypassed for short periods, SO2 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 contained 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 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 52 Appendix E. Notification must be made to the Executive 

Secretary prior to conducting the performance test. The source shall maintain records of 

the SO2 concentration, the mass flow rate, and the resulting calculated emissions. 

Records of all CEM calibrations shall also be maintained. 
DAQE-AN0119054-05

Page 8

12. Emissions of SO2 from the SRU shall be no greater than 776.7 tons per twelve-month 

period. Compliance shall be determined on a twelve-month rolling average. Each 

month, the SO2 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 streams 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 SO2 or NOX 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 H2S/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 H2S 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 

representative of the H2S 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 maintained 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 test 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 the 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-4294-89 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 nitrogen 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 

nitrogen 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 NOX 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 NOx Emission factors

Boilers #1, #2, and #4 Plant gas 100 lb/MMscf

Boiler #11005 Plant gas 50 lb/MMscf

Crude Unit 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-36017 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 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 NOx 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 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: Performance Specification 2. Notification must be 

made to the Executive Secretary prior to conducting the performance test. Whenever the 

NOx CEM is bypassed for short periods, NOx 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 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 appropriate 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 NOx 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 

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 the NOX 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, 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.

20. Emissions of NOX from the sources listed under the NOX cap shall be no greater than 

1021.6 tons per twelve-month period.

Compliance shall be determined on a twelve-month rolling average. Each month, the 

NOX 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 PM10 from the sources listed below 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 Furnace 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

Except for the FCC Catalyst Regenerator, compliance with the daily PM10 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 emission 

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 PM10 emission factor shall be determined based on the sulfur content of the fuel ((S) 

according to the equation:

EF (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 stack 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 PM10 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 pollutant 
DAQE-AN0119054-05

Page 12

concentration, as determined 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 PM10 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 

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 51, Appendix M, Methods 201 or 201a shall be used to determine front-half 

PM10 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 PM10. 

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 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.

22. The following sources shall not be regulated for PM10 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 other 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 conducted 
DAQE-AN0119054-05

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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 applies 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 facilities 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 PM10

B. 1021.6 tons/yr for NOx

C. 2578.2 tons/yr for SO2, which includes 597.7 tons/yr for SRU downtime and 250 

tons/yr, estimated flaring emissions

These calculations are for the purposes of determining the applicability of 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 Board