DAQ-2024-011873

DAQE-AN101190107-24

{{$d1 }}

Lauren Vander Werff
Chevron Products Company - Salt Lake Refinery
685 South Chevron Way
North Salt Lake, UT 84054
[e-mail]

Dear Ms. Vander Werff:

Re: Approval Order: Administrative Amendment to Approval Order DAQE-AN101190106-22 for
Corrections to Listed Equipment and an Increase in Stack Height
Project Number: N101190107

The attached Approval Order (AO) is issued pursuant to the Notice of Intent (NOI) received on April 17,
2024. Chevron Products Company - Salt Lake Refinery must comply with the requirements of this AO,
all applicable state requirements (R307), and Federal Standards.

The project engineer for this action is John Jenks, who can be contacted at [phone] or
[e-mail]. Future correspondence on this AO should include the engineer's name as well as the
DAQE number shown on the upper right-hand corner of this letter.

Sincerely,

{{$s }}

Bryce C. Bird
Director

BCB:JJ:jg

cc: Salt Lake County Health Department
EPA Region 8

195 North 1950 West • Salt Lake City, UT
Mailing Address: P.O. Box 144820 • Salt Lake City, UT 84114-4820
Telephone [phone] • Fax [phone] • T.D.D. [phone]
www.deq.utah.gov
Printed on 100% recycled paper
State of Utah

SPENCER J. COX
Governor
DEIDRE HENDERSON
Lieutenant Governor

Department of
Environmental Quality

Kimberly D. Shelley
Executive Director

DIVISION OF AIR QUALITY
Bryce C. Bird
Director

December 3, 2024

STATE OF UTAH
Department of Environmental Quality
Division of Air Quality

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APPROVAL ORDER
DAQE-AN101190107-24
Administrative Amendment to Approval Order
DAQE-AN101190106-22 for Corrections to Listed
Equipment and an Increase in Stack Height

Prepared By
John Jenks, Engineer
[phone]
[e-mail]

Issued to
Chevron Products Company - Salt Lake Refinery

Issued On
{{$d2 }}

Issued By

{{$s }}

Bryce C. Bird
Director
Division of Air Quality

December 3, 2024
TABLE OF CONTENTS

TITLE/SIGNATURE PAGE ....................................................................................................... 1
GENERAL INFORMATION ...................................................................................................... 3
CONTACT/LOCATION INFORMATION ............................................................................... 3
SOURCE INFORMATION ........................................................................................................ 3
General Description ................................................................................................................ 3
NSR Classification .................................................................................................................. 3
Source Classification .............................................................................................................. 3
Applicable Federal Standards ................................................................................................. 3
Project Description.................................................................................................................. 4
SUMMARY OF EMISSIONS .................................................................................................... 5
SECTION I: GENERAL PROVISIONS .................................................................................... 5
SECTION II: PERMITTED EQUIPMENT .............................................................................. 6
SECTION II: SPECIAL PROVISIONS ................................................................................... 10
PERMIT HISTORY ................................................................................................................... 27
ACRONYMS ............................................................................................................................... 28

DAQE-AN101190107-24
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GENERAL INFORMATION

CONTACT/LOCATION INFORMATION

Owner Name Source Name
Chevron Products Company - Salt Lake Refinery Chevron Products Company - Salt Lake Refinery

Mailing Address Physical Address
685 South Chevron Way 685 South Chevron Way
North Salt Lake, UT 84054 North Salt Lake, UT 84054

Source Contact UTM Coordinates
Name: Evan Hunter 422,270 m Easting
Phone: [phone],519,770 m Northing
Email: [e-mail] Datum NAD83
UTM Zone 12
SIC code 2911 (Petroleum Refining)

SOURCE INFORMATION
General Description
Chevron Products Company – Salt Lake Refinery is a petroleum refinery with a nominal capacity of
approximately 50,000 barrels per day of crude oil. The source consists of one fluidized catalytic cracking
unit (FCCU), a delayed coking unit, a catalytic reforming unit, hydrotreating units, and two sulfur
recovery units. The source also has assorted heaters, boilers, cooling towers, storage tanks, flares, and
similar fugitive emissions. The refinery operates with a flare gas recovery system on two of its three
hydrocarbon flares.

NSR Classification
Administrative Amendment

Source Classification
Located in Northern Wasatch Front O3 NAA, Salt Lake City UT PM2.5 NAA
Davis County
Airs Source Size: A

Applicable Federal Standards
NSPS (Part 60), A: General Provisions
NSPS (Part 60), Db: Standards of Performance for Industrial-Commercial-Institutional Steam
Generating Units
NSPS (Part 60), J: Standards of Performance for Petroleum Refineries
NSPS (Part 60), Ja: Standards of Performance for Petroleum Refineries for Which
Construction, Reconstruction, or Modification Commenced After May 14, 2007
NSPS (Part 60), K: Standards of Performance for Storage Vessels for Petroleum Liquids for
DAQE-AN101190107-24
Page 4

Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and
Prior to May 19, 1978
NSPS (Part 60), Ka: Standards of Performance for Storage Vessels for Petroleum Liquids for
Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and
Prior to July 23, 1984
NSPS (Part 60), Kb: Standards of Performance for Volatile Organic Liquid Storage Vessels
(Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or
Modification Commenced After July 23, 1984
NSPS (Part 60), GGGa: Standards of Performance for Equipment Leaks of VOC in Petroleum
Refineries for Which Construction, Reconstruction, or Modification Commenced After
November 7, 2006
NSPS (Part 60), QQQ: Standards of Performance for VOC Emissions From Petroleum
Refinery Wastewater Systems
NSPS (Part 60), IIII: Standards of Performance for Stationary Compression Ignition Internal
Combustion Engines
NSPS (Part 60), JJJJ: Standards of Performance for Stationary Spark Ignition Internal
Combustion Engines
NESHAP (Part 61), A: General Provisions
NESHAP (Part 61), M: National Emission Standard for Asbestos
NESHAP (Part 61), FF: National Emission Standard for Benzene Waste Operations
MACT (Part 63), A: General Provisions
MACT (Part 63), CC: National Emission Standards for Hazardous Air Pollutants From
Petroleum Refineries
MACT (Part 63), UUU: National Emission Standards for Hazardous Air Pollutants for
Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur
Recovery Units
MACT (Part 63), EEEE: National Emission Standards for Hazardous Air Pollutants: Organic
Liquids Distribution (Non-Gasoline)
MACT (Part 63), ZZZZ: National Emissions Standards for Hazardous Air Pollutants for
Stationary Reciprocating Internal Combustion Engines
MACT (Part 63), DDDDD: National Emission Standards for Hazardous Air Pollutants for
Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters
MACT (Part 63), GGGGG: National Emission Standards for Hazardous Air Pollutants: Site
Remediation
Title V (Part 70) Major Source

Project Description
Chevron Products Company (Chevron) requested several minor changes in their current AO as the result
of a self-audit. Multiple engine/generators have either been removed from service or have power ratings
which differ from the equipment list. These will be updated to match existing operations. There is no
expected increase in potential emissions as a result of this update.

In addition, the stack on the F-66100 VGO Furnace will be extended to allow the unit to operate at
negative pressure. This will prevent leakage and ensure the safety of refinery personnel. No changes in
firing rate or emissions are anticipated. These changes will not constitute a modification to the equipment
or processes covered under existing AO DAQE-AN101190106-22.

DAQE-AN101190107-24
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SUMMARY OF EMISSIONS

The emissions listed below are an estimate of the total potential emissions from the source. Some
rounding of emissions is possible.

Criteria Pollutant Change (TPY) Total (TPY)
CO2 Equivalent -16.27 988782.67
Carbon Monoxide -0.50 990.60
Nitrogen Oxides -2.93 763.57
Particulate Matter - PM10 -0.03 260.95
Particulate Matter - PM2.5 -0.03 109.97
Sulfur Dioxide 0 383.30
Volatile Organic Compounds -0.17 1241.89

Hazardous Air Pollutant Change (lbs/yr) Total (lbs/yr)
Acetaldehyde (CAS #75070) -4 165
Acrolein (CAS #107028) 0 239
Ethyl Benzene (CAS #100414) 0 225
Formaldehyde (CAS #50000) -6 1034
Generic HAPs (CAS #GHAPS) -9 254
Hexane (CAS #110543) 0 25309
Xylenes (Isomers And Mixture) (CAS #1330207) -2 350
Change (TPY) Total (TPY)
Total HAPs -0.01 13.79

SECTION I: GENERAL PROVISIONS

I.1 All definitions, terms, abbreviations, and references used in this AO conform to those used in
the UAC R307 and 40 CFR. Unless noted otherwise, references cited in these AO conditions
refer to those rules. [R307-101]

I.2 The limits set forth in this AO shall not be exceeded without prior approval. [R307-401]
I.3 Modifications to the equipment or processes approved by this AO that could affect the
emissions covered by this AO must be reviewed and approved. [R307-401-1]

I.4 All records referenced in this AO or in other applicable rules, which are required to be kept by the owner/operator, shall be made available to the Director or Director's representative upon request, and the records shall include the five-year period prior to the date of the request. Unless otherwise specified in this AO or in other applicable state and federal rules, records shall be kept for a minimum of five years. [R307-401-8]
I.5 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 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 Director 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. [R307-401-4]

DAQE-AN101190107-24
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I.6 The owner/operator shall comply with UAC R307-107. General Requirements: Breakdowns. [R307-107] I.7 The owner/operator shall comply with UAC R307-150 Series. Emission Inventories. [R307-150]

SECTION II: PERMITTED EQUIPMENT
II.A THE APPROVED EQUIPMENT
II.A.1 Main Refinery Chevron - Salt Lake Refinery II.A.2 F-11005 Boiler #11005 (Boiler #5) Rating: 171 MMBtu/hr Control: Low-NOx
II.A.3 F-11006 Boiler #11006 (Boiler #6) Rating: 171 MMBtu/hr Control: Low-NOx II.A.4 F-11007 Boiler #11007 (Boiler #7) Rating: 225 MMBtu/hr Control: Low-NOx and FGR
II.A.5 16001 Cooling Tower #16001 II.A.6 16002 Cooling Tower #16002
II.A.7 16003 Cooling Tower #16003 II.A.8 16004 Cooling Tower #16004 (Grandfathered)
II.A.9 F-21001 Crude Unit Furnace #F-21001 Rating: 130 MMBtu/hr Control: Low-NOx II.A.10 F-21002 Crude Unit Furnace #F-21002 Rating: 115.1 MMBtu/hr Control: Low-NOx
DAQE-AN101190107-24
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II.A.11 F-32021 FCC Furnace F-32021 Rating: 48.2 MMBtu/hr II.A.12 F-32023
FCC Furnace F-32023 Rating: 48.2 MMBtu/hr
II.A.13 F-71010 HDN Furnace F-71010 Rating: 15.6 MMBtu/hr
II.A.14 F-71030 HDN Furnace F-71030 Rating: 36.3 MMBtu/hr

II.A.15 F-35001 Reformer Furnace F-35001 Rating: 52.3 MMBtu/hr II.A.16 F-35002
Reformer Furnace F-35002
Rating: 45 MMBtu/hr
II.A.17 F-35003 Reformer Furnace F-35003 Rating: 31.7 MMBtu/hr
II.A.18 Alkylation Unit
Includes: Alkylation Furnace F-36017 Rating: 108 MMBtu/hr
Control: Low-NOx

II.A.19 F-70001 Coker Furnace F-70001 Rating: 139.2 MMBtu/hr II.A.20 F-64010
HDS Furnace F-64010
Rating: 19 MMBtu/hr Control: Low-NOx

II.A.21 F-64011 HDS Furnace F-64011 Rating: 27.3 MMBtu/hr Control: Low-NOx
II.A.22 F-66100
VGO Furnace F-66100
Rating: 40 MMBtu/hr
Control: Low-NOx

II.A.23 F-66200 VGO Furnace F-66200 Rating: 66 MMBtu/hr Control: Low-NOx
DAQE-AN101190107-24
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II.A.24 SRU/TGTU/TGI #1 SRU and Tail Gas Incinerator #1 II.A.25 SRU/TGTU/TGI #2 SRU and Tail Gas Incinerator #2

II.A.26 Catalyst Regenerator FCCU and Catalyst Regenerator
II.A.27 F61312 Flameless Thermal Oxidizer
II.A.28 Coker Flare (Flare #1) Coker Flare (Control/Safety Device)
II.A.29 FCCU Flare (Flare #2)
FCCU Flare (Control/Safety Device)
II.A.30 Alkylation Flare (Flare #3) Alkylation Flare (Control/Safety Device) II.A.31 Diesel-powered backup equipment:

A. Second North Substation Generator: One Emergency Generator Engine Rating: 750 hp Generator Rating: 500 kW

B. #1 CWT: One Emergency Cooling Water Pump Engine Rating: 665 hp

C. HDN Substation: One Emergency Generator Engine Rating: 601 hp Generator Rating: 400 kW

D. VGO: One Emergency Generator Engine Rating: 755 hp (max) Generator Rating: 500 kW

II.A.32 E. Crude Substation: One Backup Generator Engine Rating: 900 hp Generator Rating: 600 kW F. Third North Substation: One Backup Emergency Generator Engine Rating: 1490 hp Generator Rating: 1,111 kW G. Admin Building: One Backup Generator Engine Rating: 2,220 hp Generator Rating: 1,250 kW H. TCLR: One Backup Generator Engine Rating: 197 hp Generator Rating: 125 kW I. North Tank Field: One Backup Generator Engine Rating: 896 hp Generator Rating: 600 kW
DAQE-AN101190107-24
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II.A.33 J. WWTP: One Backup Generator Engine Rating: 896 hp Generator Rating 600 kW K. Alky: One Emergency Generator Engine Rating: 752 hp Generator Rating: 500 kW L. Boiler Plant: Two Compressors Engine Rating: 524 hp each M. Collection Box: One Backup Pump Engine Rating: 109 hp N. FCC MCC: One Emergency Generator Engine Rating: 895 hp Generator Rating: 600 kW O. Three Fire Water Pumps Engine Rating: 950 hp (maximum design at 2100 rpm) each II.A.34
P. One Canal Fire Water Emergency Generator
Engine Rating: 462 hp Generator Rating: 300 kW
Q. One Reformer Substation Emergency Generator
Engine Rating: 616 hp Generator Rating: 400 kW
II.A.35 Natural gas-powered backup equipment A. One Emergency Generator Engine Rating: 50 hp Generator Rating: 30 kW
II.A.36 K35001, K35002, K35003
Three Reformer Compressor Drivers Rating: 16 MMBtu/hr each
Fuel: Refinery Fuel Gas

II.A.37 Amine Unit #1 Amine Unit #1
II.A.38 Amine Unit #2 Amine Unit #2

II.A.39 K36067 Lime Loading Facility K36067
II.A.40 FCC Fines Bin

DAQE-AN101190107-24
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SECTION II: SPECIAL PROVISIONS
II.B REQUIREMENTS AND LIMITATIONS

II.B.1 Source-wide Requirements
II.B.1.a Except as otherwise stated in this AO, the owner/operator shall use only plant gas or purchased
natural gas as a primary fuel. Plant Coke may be burned in the FCC Catalyst Regenerator. Torch
oil may be burned in the FCC Catalyst Regenerator to assist in starting, restarting, hot standby, or
to maintain regenerator heat balance. If any other fuel is to be used, an AO shall be required.
[Consent Decree, R307-401]

II.B.1.b All petroleum refineries in or affecting any PM2.5 nonattainment area or any PM10 nonattainment or maintenance area shall reduce the H2S content of the refinery plant gas to 60 ppm or less as described in 40 CFR 60.102a. Compliance shall be based on a rolling average of 365 days. The owner/operator shall comply with the fuel gas monitoring requirements of 40 CFR 60.107a and the related recordkeeping and reporting requirements of 40 CFR 60.108a. As used herein, refinery "plant gas" shall have the meaning of "fuel gas" as defined in 40 CFR 60.101a and may be used interchangeably. For natural gas, compliance is assumed while the fuel comes from a public utility. [SIP Section IX.H.11.g.ii]
II.B.1.c No petroleum refineries in or affecting any PM2.5 nonattainment area or PM10 nonattainment or
maintenance area shall be allowed to burn liquid fuel oil in stationary sources except during
natural gas curtailments or as specified below:

A. The use of diesel fuel meeting the specifications of 40 CFR 80.510 in standby or
emergency equipment is exempt from the limitation above and is allowed in standby or
emergency equipment at all times

B. Plant coke may be burned in the FCC catalyst regenerator.

[R307-401-8(1)(a), SIP Section IX.H.11.g.vii, SIP Section IX.H.12.d.iv]

II.B.1.d The owner/operator shall not allow visible emissions to exceed the opacity limits set in R307-309. [R307-309]
DAQE-AN101190107-24
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II.B.1.e The owner/operator shall ensure for all stack testing performed: The owner/operator 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 Director shall be held at least 30 days prior to the test if directed by the Director. 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. 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. Where appropriate, the following test methods shall be used, although other EPA-approved test methods acceptable to the Director can be substituted and approved through the pre-test protocol: Volumetric flow rate - 40 CFR 60, Appendix A, Method 2 SO2 emissions - 40 CFR 60, Appendix A, Method 6C NOx emissions - 40 CFR 60, Appendix A, Method 7E PM10 and PM2.5 emissions - 40 CFR 51, Appendix M, Methods 201a and 202 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 Director to give the results in the specified units of the emission limitation. [R307-401] II.B.1.f Source-wide combined emissions of PM10 shall not exceed 0.715 tons per day (tpd).
[SIP Section IX.H.2.d.i]

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II.B.1.f.1 Compliance with the source-wide PM10 Cap shall be determined for each day as follows: A. Total 24-hour PM10 emissions for the emission points shall be calculated by adding the daily results of the PM10 emissions equations listed below for natural gas, plant gas, and fuel oil combustion. These emissions shall be added to the emissions from the cooling towers and the FCCU to arrive at a combined daily PM10 emission total B. For purposes of this subsection, a "day" is defined as a period of 24 hours commencing at midnight and ending at the following midnight C. Daily natural gas and plant gas consumption shall be determined through the use of flow meters D. Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that supply combustion sources E. The equation used to determine emissions for the boilers and furnaces shall be as follows: Emission Factor (lb/MMscf) * Gas Consumption (MMscf/24 hrs)/(2,000 lb/ton) F. Results shall be tabulated for each day, and records shall be kept which include the meter readings (in the appropriate units) and the calculated emissions. [SIP Section IX.H.2.d.i.C]
II.B.1.f.2 The emission factors derived from the most current performance test shall be applied to the relevant quantities of fuel combusted. Unless adjusted by performance testing, the default
emission factors to be used are as follows:
A. Natural gas:
Filterable PM10: 1.9 lb/MMscf
Condensable PM10: 5.7 lb/MMscf
B. Plant gas:
Filterable PM10: 1.9 lb/MMscf Condensable PM10: 5.7 lb/MMscf

C. Diesel fuel: shall be determined from the latest edition of AP-42 or other EPA-approved methods

D. Cooling Towers: shall be determined from the latest edition of AP-42 or other EPA-approved methods

E. FCC Stack: The PM10 emission factors shall be based on the most recent stack test and verified by parametric monitoring

F. Where mixtures of fuel are used in a unit, the above factors shall be weighted according
to the use of each fuel.

[SIP Section IX.H.2.d.i.A]

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II.B.1.f.3 The default emission factors listed above apply until such time as stack testing is conducted. Initial PM10 stack testing on the FCC stack has been performed and shall be conducted at least once every three years from the date of the last stack test. Stack testing shall be performed as outlined in Condition II.B.1.e. [SIP Section IX.H.2.d.i.B] II.B.1.g Source-wide combined emissions of PM2.5 (filterable + condensable) shall not exceed 0.305 tpd and 110 tons per rolling 12-month period. [SIP Section IX.H.12.d.i]

II.B.1.g.1 Compliance with the source-wide PM2.5 Cap shall be determined for each day as follows: A. Total 24-hour PM2.5 emissions for the emission points shall be calculated by adding the daily results of the PM2.5 emissions equations listed below for natural gas, plant gas, and fuel oil combustion. These emissions shall be added to the emissions from the FCCU to arrive at a combined daily PM2.5 emission total B. For purposes of this subsection, a "day" is defined as a period of 24 hours commencing at midnight and ending at the following midnight C. Daily natural gas and plant gas consumption shall be determined through the use of flow meters D. Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that supply combustion sources E. The equation used to determine emissions for the boilers and furnaces shall be as follows: Emissions = Emission Factor (lb/MMscf) * Gas Consumption (MMscf/24 hrs)/(2,000 lb/ton) F. Results shall be tabulated for each day, and records shall be kept which include the meter readings (in the appropriate units) and the calculated emissions. [SIP Section IX.H.12.d.i.C]
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II.B.1.g.2 The emission factors derived from the most current performance test shall be applied to the relevant quantities of fuel combusted. Unless adjusted by performance testing, the default emission factors to be used are as follows: A. Natural gas: Filterable PM2.5: 1.9 lb/MMscf Condensable PM2.5: 5.7 lb/MMscf B. Plant gas: Filterable PM2.5: 1.9 lb/MMscf Condensable PM2.5: 5.7 lb/MMscf C. Diesel fuel: shall be determined from the latest edition of AP-42 or other EPA-approved methods D. FCC Stack: The PM2.5 emission factors shall be based on the most recent stack test and verified by parametric monitoring E. Where mixtures of fuel are used in a Unit, the above factors shall be weighted according to the use of each fuel. [SIP Section IX.H.12.d.i.A]
II.B.1.g.3 The default emission factors listed above apply until such time as stack testing is conducted.
Initial PM2.5 stack testing on the FCC stack has been performed and shall be conducted at least
once every three years from the date of the last stack test.
Stack testing shall be performed as outlined in Condition II.B.1.e.
[SIP Section IX.H.12.d.i.B]

II.B.1.h Source-wide combined emissions of NOx shall not exceed 2.1 tpd and 766.5 tons per rolling 12-month period. [SIP Section IX.H.12.d.ii]
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II.B.1.h.1 Compliance with the source-wide NOx Cap shall be determined for each day as follows: A. Total 24-hour NOx emissions shall be calculated by adding the emissions for each emitting unit B. The emissions for each emitting unit shall be calculated by multiplying the hours of operation of a unit, feed rate to a unit, or quantity of each fuel combusted at each affected unit by the associated emission factor, and summing the results C. A NOx CEM shall be used to calculate daily NOx emissions from the FCCU D. A NOx CEM shall be used to calculate daily NOx emissions from Boiler #7 E. For purposes of this subsection, a "day" is defined as a period of 24 hours commencing at midnight and ending at the following midnight F. Daily natural gas and plant gas consumption shall be determined through the use of flow meters G. Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that supply combustion sources H. Results shall be tabulated for each day, and records shall be kept which include the meter readings (in the appropriate units) and the calculated emissions. [SIP Section IX.H.12.d.ii.C] II.B.1.h.2 The emission factors derived from the most current performance test shall be applied to the
relevant quantities of fuel combusted. Unless adjusted by performance testing, the default
emission factors to be used are as follows:
A. Natural gas: shall be determined from the latest edition of AP-42 or other EPA-approved
methods
B. Plant gas: shall be assumed equal to natural gas
C. Alkylation polymer: shall be determined from the latest edition of AP-42 (as fuel oil #6)
or other EPA-approved methods
D. Diesel fuel: shall be determined from the latest edition of AP-42 or other EPA-approved
methods
E. Where mixtures of fuel are used in a unit, the above factors shall be weighted according
to the use of each fuel.
[SIP Section IX.H.12.d.ii.A]

II.B.1.h.3 The default emission factors listed above apply until such time as stack testing is conducted. Initial NOx stack testing on natural gas/refinery fuel gas combustion equipment above 100 MMBtu/hr has been performed and shall be conducted at least once every three years from the date of the last stack test. At that time a new flow-weighted average emission factor in terms of lbs/MMbtu shall be derived for each combustion type listed above. Stack testing shall be performed as outlined in Condition II.B.1.e. [SIP Section IX.H.12.d.ii.B]
DAQE-AN101190107-24
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II.B.1.i Source-wide combined emissions of SO2 shall not exceed 1.05 tpd and 383.3 tons per rolling 12-month period. [SIP Section IX.H.12.d.iii] II.B.1.i.1 Compliance with the source-wide SO2 Cap shall be determined for each day as follows:
A. Total daily SO2 emissions shall be calculated by adding the daily SO2 emissions for natural gas and plant fuel gas combustion to those from the FCC and SRU stacks
B. Daily natural gas and plant gas consumption shall be determined through the use of flow meters
C. Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that supply combustion sources
D. Results shall be tabulated for each day, and records shall be kept which include CEM readings for H2S (averaged for each one-hour period), all meter readings (in the
appropriate units), fuel oil parameters (density and wt% sulfur for each day any fuel oil
is burned), and the calculated emissions
E. For purposes of this subsection, a "day" is defined as a period of 24 hours commencing
at midnight and ending at the following midnight.
[SIP Section IX.H.12.d.iii.B]

II.B.1.i.2 The emission factors derived from the most current performance test shall be applied to the relevant quantities of fuel combusted. The default emission factors to be used are as follows: A. FCCU: The emission rate shall be determined by the FCC SO2 CEM B. SRUs: The emission rate shall be determined by multiplying the sulfur dioxide concentration in the flue gas by the flow rate of the flue gas. The sulfur dioxide concentration in the flue gas shall be determined by CEM C. Natural gas: EF = 0.60 lb/MMscf D. Fuel oil: The emission factor to be used for combustion shall be calculated based on the weight percent of sulfur, as determined by ASTM Method D-4294-89 or EPA-approved equivalent acceptable to the Director, 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) E. Plant gas: the emission factor shall be calculated from the H2S measurement obtained from the H2S CEM F. Where mixtures of fuel are used in a unit, the above factors shall be weighted according to the use of each fuel. [SIP Section IX.H.12.d.iii.A]

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II.B.2 Conditions on Boiler #11005 (Boiler #5) II.B.2.a NOx emissions shall not exceed the following rate on a 30-day rolling average basis:
[NSPS Db §60.44b(b) and §60.44b(i)] En = ((0.1 x Hgo) + (0.2 x Hr)) / (Hgo + Hr)
Where: En = NOx emission limit (lb/MMbtu)
Hgo = 30-day heat input from combustion of natural gas or distillate oil Hr = 30-day heat input from combustion of any other fuel.
[40 CFR 60 Subpart Db]
II.B.2.a.1 The NOx emission rate shall be predicted based on excess O2 in the flue gas and by boiler loading as specified in a plan submitted to and approved by the Director [NSPS Db §60.48b(g)(2)]. Predicted NOx emission rate shall be evaluated at least every three years through testing as outlined in Condition II.B.1.e. [40 CFR 60 Subpart Db]
II.B.3 Conditions on Boiler #11006 (Boiler #6)
II.B.3.a NOx emissions shall not exceed the following rate on a 30-day rolling average basis: [NSPS Db §60.44b(b) and §60.44b(i)] En = ((0.1 x Hgo) + (0.2 x Hr)) / (Hgo + Hr) Where: En = NOx emission limit (lb/MMbtu) Hgo = 30-day heat input from combustion of natural gas or distillate oil Hr = 30-day heat input from combustion of any other fuel. [40 CFR 60 Subpart Db]
II.B.3.a.1 The NOx emission rate shall be predicted based on excess O2 in the flue gas and by boiler loading as specified in a plan submitted to and approved by the Director [NSPS Db §60.48b(g)(2)].
Predicted NOx emission rate shall be evaluated at least every three years through testing as
outlined in Condition II.B.1.e. [40 CFR 60 Subpart Db]
II.B.4 Conditions on the SRUs
II.B.4.a All petroleum refineries in or affecting any PM2.5 nonattainment area or any PM10 nonattainment
or maintenance area shall require:
A. Sulfur removal units/plants (SRUs) that are at least 95% effective in removing sulfur
from the streams fed to the unit; or
B. SRUs that meet the SO2 emission limitations listed in 40 CFR 60.102a(f)(1) or
60.102a(f)(2) as appropriate.

[SIP Section IX.H.1.g.iii.A]

II.B.4.b The owner/operator shall process amine acid gas and sour water stripper acid gas in the SRU(s). [SIP Section IX.H.1.g.iii.B]
II.B.4.b.1 Compliance shall be demonstrated by daily monitoring of flows to the SRU(s). Compliance shall
be determined on a rolling 30-day average. [SIP Section IX.H.1.g.iii.C]

II.B.5 Conditions on SRU and Tail Gas Treatment Unit #1
II.B.5.a Emissions of SO2 from SRU #1 shall not exceed 0.242 tons/day. [R307-401]

DAQE-AN101190107-24
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II.B.5.a.1 Daily sulfur dioxide emissions 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 CEM 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 evaluation shall be performed within 30 days of installation. The performance evaluation shall be conducted and data reduced in accordance with the methods and procedures contained in 40 CFR 60, Appendix B: Performance Specification 2. Notification must be made to the Director prior to conducting the performance evaluation. 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 evaluation shall be performed within 30 days of installation. The performance evaluation 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 Director prior to conducting the performance evaluation. 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. [R307-401]
II.B.5.b Emissions of SO2 from SRU #1 shall not exceed 88.5 tons/yr. [R307-401]

II.B.5.b.1 Compliance shall be determined on a 12-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 11 months' emission totals to give the new 12-month rolling total. [R307-401]
II.B.5.c The owner/operator shall continue to route or re-route all sulfur pit emissions so that they are
eliminated, controlled, or included and monitored as part of the SRU's emissions subject to the emissions limits of II.B.5. [Consent Decree]

II.B.6 Conditions on SRU and Tail Gas Treatment Unit #2
II.B.6.a Emissions of SO2 from SRU #2 shall not exceed 0.268 tons/day. [R307-401]
DAQE-AN101190107-24
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II.B.6.a.1 Daily sulfur dioxide emissions 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 CEM 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 evaluation shall be performed within 30 days of installation. The performance evaluation shall be conducted and data reduced in accordance with the methods and procedures contained in 40 CFR 60, Appendix B: Performance Specification 2. Notification must be made to the Director prior to conducting the performance evaluation. 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 evaluation shall be performed within 30 days of installation. The performance evaluation 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 Director prior to conducting the performance evaluation. 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. [R307-401]
II.B.6.b Emissions of SO2 from SRU #2 shall not exceed 97.7 tons/yr. [R307-401]

II.B.6.b.1 Compliance shall be determined on a 12-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 11 months' emission totals to give the new 12-month rolling total. [R307-401]
II.B.6.c The owner/operator shall continue to route or re-route all sulfur pit emissions so that they are
eliminated, controlled, or included and monitored as part of the SRU's emissions subject to the emissions limits of II.B.6. [Consent Decree]

DAQE-AN101190107-24
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II.B.7 Conditions on the FCC and Catalyst Regenerator II.B.7.a Emissions of SO2 from the FCCU Regenerator Vent shall not exceed the following rates and
concentrations: A. 25 ppmvd SO2 @ 0% O2 on a 365-day rolling average
B. 50 ppmvd SO2 @ 0% O2 on a 7-day rolling average
C. 50 tons of SO2 on a 12-month rolling average D. 0.28 tons of SO2 per day.
SO2 emissions during periods of startup, shutdown, or malfunction shall not be used in determining compliance with the emission limit of 50 ppmvd SO2 @ 0% O2 on a 7-day rolling
average basis.
The SO2 short-term limit listed in B. above shall exclude FCCU feed hydrotreater outages if
Chevron complies with an EPA-approved hydrotreater outage plan and is maintaining and operating the FCCU in a manner consistent with good air pollution control practices. It shall
apply at all other times the FCCU is in operation.
In addition, in the event that the source asserts that the basis for a specific hydrotreater outage is
a shutdown (where no catalyst changeout occurs) required by ASME pressure vessel
requirements or applicable state boiler requirements, the source shall submit a report to EPA that identifies the relevant requirements and justifies the permittee's decision to implement the
shutdown during the selected time period.
[Consent Decree, R307-401]

DAQE-AN101190107-24
Page 21

II.B.7.a.1 The SO2 emission factor for the FCC and catalyst regenerator shall be determined by continuous emission monitor. The regenerator flow rate calculation established in 40 CFR 63 Subpart UUU (MACT UUU) shall be used in conjunction for this calculation. For continuous emission monitor calculations, the monitor shall be operated, maintained, certified, and calibrated in accordance with R307-170, UAC. The provisions of 40 C.F.R. § 60.13 that are applicable to CEMS (excluding those provisions applicable only to Continuous Opacity Monitoring Systems) and Part 60 Appendices A and F, and the applicable performance specification test of 40 C.F.R. Part 60 Appendix B are applicable to the FCC/Catalyst Regenerator CEM. With respect to 40 C.F.R. Part 60, Appendix F, Chevron must conduct either a Relative Accuracy Audit ("RAA") or a Relative Accuracy Test Audit ("RATA") on each CEMS at least once every one year. The source must also conduct Cylinder Gas Audits ("CGA") each calendar quarter during which a RAA or a RATA is not performed. With respect to the O2 CEMS, in lieu of the audit points specified in 40 C.F.R. Part 60, Appendix F § 5.1.2., the source may audit the O2 CEMS at 20-30% and 50-60% of the actual O2 CEMS span value. If a new monitor is installed, an initial performance evaluation shall be performed within 30 days of installation. The performance evaluation 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 Director 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. For the stack test calculations to establish the FCC and Catalyst Regenerator SO2 emission factor, the owner/operator shall determine mass emission rates (lbs/hr, etc.) as follows: The pollutant concentration, as determined by the appropriate methods, shall be multiplied by the volumetric flow rate and any necessary conversion factors as determined by the Director. The owner/operator 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. [R307-170] II.B.7.b Emissions of NOx from the FCCU Regenerator Vent shall not exceed the following rates:

A. 100 tons of NOx per year on a rolling 12-month basis
B. 0.55 tpd
C. 57.8 ppmvd @ 0% O2 on a 365-day rolling average

D. 106.3 ppmvd @ 0% O2 on a 7-day rolling average.
The NOx long-term limit listed in C. above shall apply at all times the FCCU is in operation.
The NOx short-term limit listed in D. above shall exclude periods of startup, shutdown, and
malfunction. It shall also exclude FCCU feed hydrotreater outages if the owner/operator
complies with an EPA-approved hydrotreater outage plan. It shall apply at all other times the
FCCU is in operation.

[R307-401]

DAQE-AN101190107-24
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II.B.7.b.1 The NOx emission factor for the FCC and Catalyst Regenerator shall be determined by continuous emission monitor. The regenerator flow rate calculation established in 40 CFR 63 Subpart UUU (MACT UUU) shall be used in conjunction for this calculation. For continuous emission monitor calculations, the monitor shall be operated, maintained, calibrated, and certified in accordance with R307-170, UAC and the provisions of 40 C.F.R. § 60.13 that are applicable to CEMS (excluding those provisions applicable only to Continuous Opacity Monitoring Systems) and Part 60 Appendices A and F, and the applicable performance specification test of 40 C.F.R. Part 60 Appendix B. With respect to 40 C.F.R. Part 60, Appendix F, Chevron must conduct either a RAA or a RATA on each CEMS at least once every one year. The source must also conduct CGA each calendar quarter during which a RAA or a RATA is not performed. With respect to the O2 CEMS, in lieu of the audit points specified in 40 C.F.R. Part 60, Appendix F § 5.1.2., the source may audit the O2 CEMS at 20-30% and 50-60% of the actual O2 CEMS span value. If a new monitor is installed, an initial performance evaluation shall be performed within 30 days of installation. The performance evaluation 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 Director 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. For stack test calculations, mass emission rates (lbs/hr, etc.), the pollutant concentration, as determined by the appropriate methods, shall be multiplied by the volumetric flow rate and any necessary conversion factors as determined by the Director to establish the FCC and Catalyst Regenerator NOx emission factor. 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. [R307-170]
II.B.7.c Emissions of CO from the FCCU shall not exceed 500 ppmvd at 0% O2 on a 1-hour average
basis. CO emissions during periods of startup, shutdown, or malfunction shall not be used when determining compliance with this emission limit. [R307-401-8]

II.B.7.c.1 The source shall use CO and O2 CEMS to monitor compliance with the CO emission limit for the FCCU and Catalyst Regenerator. The source shall install, certify, maintain, and operate the CEMS in accordance with the provisions of 40 C.F.R. § 60.13 that are applicable to CEMS (excluding those provisions applicable only to Continuous Opacity Monitoring Systems) and Part 60 Appendices A and F, and the applicable performance specification test of 40 C.F.R. Part 60 Appendix B. With respect to 40 C.F.R. Part 60, Appendix F, Chevron must conduct either a RAA or a RATA on each CEMS at least once every one year. The source must also conduct CGA each calendar quarter during which a RAA or a RATA is not performed. With respect to the O2 CEMS, in lieu of the audit points specified in 40 C.F.R. Part 60, Appendix F § 5.1.2., the source may audit the O2 CEMS at 20-30% and 50-60% of the actual O2 CEMS span value. [R307-170]
II.B.7.d The owner or operator of an FCCU shall comply with an emission limit of 1.0 pounds PM per
1000 pounds coke burn-off. [SIP Section IX.H.11.g.i.B.I]

II.B.7.d.1 Compliance with this limit shall be determined by following the stack test protocol specified in 40 C.F.R. §60.106(b) to measure PM emissions on the FCCU. Each owner/operator shall conduct stack tests once every three years at each FCCU. [SIP Section IX.H.11.g.i.B.II]
DAQE-AN101190107-24
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II.B.7.e Each owner or operator of an FCCU subject to NSPS Ja shall install, operate, and maintain a continuous parameter monitor system (CPMS) to measure and record operating parameters from the FCCU and control devices as per the requirements of 40 CFR 60.105a(b)(1). Each owner or operator of an FCCU not subject to NSPS Ja shall install, operate, and maintain a continuous opacity monitoring system to measure and record opacity from the FCCU as per the requirements of 40 CFR 63.1572(b) and comply with the opacity limitation as per the requirements of Table 7 to Subpart UUU of Part 63. [SIP Section IX.H.11.g.i.B.III]
II.B.7.f Opacity from the FCCU and Catalyst Regenerator shall be monitored by a continuous opacity monitoring system. The source shall install, certify, calibrate, maintain, and operate the COMS in accordance with 40 C.F.R. §§ 60.11, 60.13, and Part 60 Appendix A, and the applicable
performance specification test of 40 C.F.R. Part 60 Appendix B. [Consent Decree]
II.B.8 Conditions on Miscellaneous Diesel-fired Equipment II.B.8.a The owner/operator shall not operate each emergency engine, backup pump, or fire engine on
site for more than 100 hours per calendar year during non-emergency situations. There is no time limit on the use of the engines during emergencies. [40 CFR 63 Subpart ZZZZ, R307-401-8]

II.B.8.a.1 To determine compliance with the above annual total, the owner/operator shall calculate a new 12-month total by the 20th day of each month using data from the previous 12 months. Records documenting the operation of each emergency engine shall be kept in a log and shall include the following: A. The date the equipment was used B. The duration of operation in hours C. The reason for the equipment usage. [40 CFR 63 Subpart ZZZZ, R307-401-8]
II.B.8.a.2 To determine the duration of operation, the owner/operator shall install a non-resettable hour meter for each emergency engine. [R307-401-8, 40 CFR 63 Subpart ZZZZ]

II.B.8.b The owner/operator shall only use diesel fuel (e.g., fuel oil #1, #2, or diesel fuel oil additives) as fuel in each emergency engine. [R307-401-8]
II.B.8.b.1 The owner/operator shall only combust diesel fuel that meets the definition of ultra-low sulfur
diesel (ULSD), which has a sulfur content of 15 ppm or less. [R307-401-8]
II.B.8.b.2 To demonstrate compliance with the ULSD fuel requirement, the owner/operator shall maintain records of diesel fuel purchase invoices or obtain certification of sulfur content from the diesel fuel supplier. The diesel fuel purchase invoices shall indicate that the diesel fuel meets the ULSD requirements. [R307-401-8]
DAQE-AN101190107-24
Page 24

II.B.8.c The following engines qualify under 40 CFR 63.6590(c) Stationary RICE subject to regulations under 40 CFR Part 60 Subpart IIII: 1. North tank field generator: one backup generator. Engine rating: 896 hp. Generator rating: 600 kW 2. TCLR generator: backup generator. Engine rating: 197 hp. Generator rating: 125 kW 3. WWTP: One Backup Generator. Engine rating: 896 hp. Generator rating: 600 kW 4. Collection box backup pump: one pump. Engine rating: 109 hp 5. One canal fire water emergency generator. Engine rating: 462 hp. Generator rating: 300 kW These engines must meet the requirements of 40 CFR 63 Subpart ZZZZ by meeting the requirements of 40 CFR 60 Subpart IIII. The requirements are listed at §60.4211(a), (c), (f), and (g). These engines are not subject to any additional requirements of 40 CFR 63 Subpart ZZZZ. [40 CFR 60 Subpart IIII, 40 CFR 63 Subpart ZZZZ]
II.B.9 Conditions on Reformer Compressor Engines
II.B.9.a Emissions of NOx and CO at the three listed reformer compressors shall not exceed the following concentration limits: K35001: 236 ppmvd NOx, 834 ppmvd CO K35002: 208 ppmvd NOx, 926 ppmvd CO K35003: 230 ppmvd NOx, 556 ppmvd CO [R307-401-8(1)(a)]
DAQE-AN101190107-24
Page 25

II.B.9.a.1 Demonstrating Compliance with Emission Limits A. Beginning no later than one year after the Emission Limits Tests and every two years thereafter, the owner/operator shall perform emission tests to demonstrate compliance with the emission limits established for the reformer compressor engines. The tests shall be conducted on each engine and shall be the average of three one-hour tests on each engine. The tests shall be conducted, and the emissions shall be calculated in accordance with 40 CFR § 60.4244. B. The owner/operator shall continuously measure and record the catalyst inlet temperature data in according to 40 CFR § 63.6625(b), reduce these data to four-hour rolling averages, and maintain the 4-hour rolling averages within the operating limitations for the catalyst inlet temperature, except for periods of startup, shutdown, and malfunction, as those terms are defined in 40 CFR § 60.2. C. The owner/operator shall measure and record the pressure drop across each catalyst bed once per month. The owner/operator shall maintain each catalyst bed so that the pressure drop across each catalyst is within the operating limitation established during the Emission Limits Tests. D. The owner/operator shall replace the O2 sensor on each reformer compressor engine in accordance with the vendor-recommended preventative maintenance schedule. Following each O2 sensor replacement, the owner/operator shall measure NOx and CO emissions once using a portable analyzer to determine the adequate set point of the AFRC to maintain operation of the reformer compressor engine near stoichiometric conditions. The owner/operator shall maintain records documenting sensor replacement and portable analyzer results. [R307-150] II.B.10 Miscellaneous SIP Conditions
II.B.10.a The owner or operator shall comply with the requirements of 40 CFR 63.654 for heat exchange systems in VOC service. The owner or operator may elect to use another EPA-approved method other than the Modified El Paso Method if approved by the Director. The following applies in lieu of 40 CFR 63.654(b): A heat exchange system is exempt from the requirements in paragraphs 63.654(c) through (g) of this section if it meets any one of the criteria in the following paragraphs (1) through (2) of this section. 1. All heat exchangers that are in VOC service within the heat exchange system that either: A. Operate with the minimum pressure on the cooling water side at least 35 kilopascals greater than the maximum pressure on the process side; or B. Employ an intervening cooling fluid, containing less than 10 percent by weight of VOCs, between the process and the cooling water. This intervening fluid must serve to isolate the cooling water from the process fluid and must not be sent through a cooling tower or discharged. For purposes of this section, discharge does not include emptying for maintenance purposes. 2. The heat exchange system cools process fluids that contain less than 10 percent by weight VOCs (i.e., the heat exchange system does not contain any heat exchangers that are in VOC service). [SIP Section IX.H.11.g.iii.A]
DAQE-AN101190107-24
Page 26

II.B.10.b For leak detection and repair, the owner/operator shall comply with the following: A. The owner/operator shall comply with the requirements of 40 CFR 60.590a to 60.593a. B. For units complying with the Sustainable Skip Period, previous process unit monitoring results may be used to determine the initial skip period interval provided that each valve has been monitored using the 500 ppm leak definition. [SIP Section IX.H.11.g.iv] II.B.10.c The owner/operator shall not allow any stationary tank of 40,000-gallon or greater capacity and
containing or last containing any organic liquid, with a true vapor pressure equal or greater than 10.5 kPa (1.52 psia) at storage temperature (see R307-324-4(1)), to be opened to the atmosphere unless the emissions are controlled by exhausting VOCs contained in the tank vapor space to a
vapor control device until the organic vapor concentration is 10 percent or less of the lower explosion limit (LEL).

These degassing provisions shall not apply while connecting or disconnecting degassing equipment.

[SIP Section IX.H.11.g.vi]
II.B.10.c.1 The Director shall be notified of the intent to degas any tank subject to the rule. Except in an emergency situation, initial notification shall be submitted at least three days prior to degassing operations. The initial notification shall include: A. Start date and time; B. Tank owner, address, tank location, and applicable tank permit numbers; C. Degassing operator's name, contact person, and telephone number; D. Tank capacity, volume of space to be degassed, and materials stored; E. Description of vapor control device. [SIP Section IX.H.11.g.vi.C]
II.B.10.d All hydrocarbon flares at petroleum refineries located in or affecting a PM2.5 nonattainment area
or any PM10 nonattainment or maintenance area shall be subject to the flaring requirements of NSPS Subpart Ja (40 CFR 60.100a-109a), if not already subject under the flare applicability
provisions of Ja. [SIP Section IX.H.11.g.v.A]

II.B.10.d.1 The owner/operator shall either: 1) install and operate a flare gas recovery system designed to limit hydrocarbon flaring produced from each affected flare during normal operations to levels below the values listed in 40 CFR 60.103a(c), or 2) limit flaring during normal operations to 500,000 scfd for each affected flare. Flare gas recovery is not required for dedicated SRU flare and header systems, or HF flare and header systems. [SIP Section IX.H.11.g.v.B]

DAQE-AN101190107-24
Page 27

PERMIT HISTORY

This Approval Order shall supersede (if a modification) or will be based on the following documents: Supersedes AO DAQE-AN101190106-22 dated August 24, 2022 Is Derived From Source Submitted NOI dated April 17, 2024 Incorporates Additional Information Received dated May 21, 2024 Incorporates Additional Information Received dated August 26, 2024

DAQE-AN101190107-24
Page 28

ACRONYMS

The following lists commonly used acronyms and associated translations as they apply to this document:

40 CFR Title 40 of the Code of Federal Regulations
AO Approval Order
BACT Best Available Control Technology
CAA Clean Air Act
CAAA Clean Air Act Amendments
CDS Classification Data System (used by Environmental Protection Agency to classify
sources by size/type)
CEM Continuous emissions monitor
CEMS Continuous emissions monitoring system
CFR Code of Federal Regulations
CMS Continuous monitoring system
CO Carbon monoxide
CO2 Carbon Dioxide
CO2e Carbon Dioxide Equivalent - Title 40 of the Code of Federal Regulations Part 98,
Subpart A, Table A-1
COM Continuous opacity monitor
DAQ/UDAQ Division of Air Quality
DAQE This is a document tracking code for internal Division of Air Quality use
EPA Environmental Protection Agency
FDCP Fugitive dust control plan
GHG Greenhouse Gas(es) - Title 40 of the Code of Federal Regulations 52.21 (b)(49)(i)
GWP Global Warming Potential - Title 40 of the Code of Federal Regulations Part 86.1818-
12(a)
HAP or HAPs Hazardous air pollutant(s)
ITA Intent to Approve
LB/YR Pounds per year MACT Maximum Achievable Control Technology MMBTU Million British Thermal Units NAA Nonattainment Area NAAQS National Ambient Air Quality Standards NESHAP National Emission Standards for Hazardous Air Pollutants NOI Notice of Intent
NOx Oxides of nitrogen
NSPS New Source Performance Standard
NSR New Source Review
PM10 Particulate matter less than 10 microns in size
PM2.5 Particulate matter less than 2.5 microns in size
PSD Prevention of Significant Deterioration
PTE Potential to Emit
R307 Rules Series 307
R307-401 Rules Series 307 - Section 401
SO2 Sulfur dioxide
Title IV Title IV of the Clean Air Act
Title V Title V of the Clean Air Act
TPY Tons per year
UAC Utah Administrative Code
VOC Volatile organic compounds

?,.',.-
State of Utah
SPENCER J. COX
Governor
DEIDRE HENDERSON
Lieutenant Governor
November 6, 2024
Lauren Vander Werff
Chevron Products Company - Salt Lake Refinery
685 S Chevron Way
North Salt Lake, UT 84054
LVanderWerff chevron.com
Dear Lauren Vander Werff,
RNIOI 190107
Re: Engineer Review:
Administrative Amendment to DAQE-AN 101190106-22 for Corrections to Listed Equipment
and an Increase in Stack Height
Project Number: N 101190107
Please review and sign this letter and attached Engineer Review (ER) within 10 business days. For this
document to be considered as the application for a Title V administrative amendment, a Title V
Responsible Official must sign the next page.
Please contact John Jenks at [phone] if you have any questions or concerns about the ER. If you
accept the contents of this ER, please email this signed cover letter to John Jenks at jjenks utah.gov.
After receipt of the signed cover letter, the DAQ will prepare an Approval Order (AO) for signature by
the DAQ Director.
If Chevron Products Company - Salt Lake Refinery does not respond to this letter within 10 business
days, the project will move forward without your approval. If you have concerns that we cannot resolve,
the DAQ Director may issue an Order prohibiting construction.
Approval Signature!
Department of
Environmental Quality
Kimberly D, Shelley
Executive Director
DIVISION OF AIR QUALITY
Bryce C. Bird
Director
195 North 1950 k esi " Sail Lake Cth I
Mailing Address P0 Box 144820 " Sail Lake cit 1 84114.4820
Telephone [phone] " Fax [phone] " T D D [phone]
"t"ww c/eq uta/; got
Pnnied on 1000o recycled paper
OPTIONAL: In order for this Engineer Review and associated Approval Order conditions to be
considered as an application to administratively amend your Title V Permit, the Responsible Official, as
defined in R307-41 5-3, must sign the statement below. THIS IS STRICTLY OPTIONAL.
If you do not want the Engineer Review to be considered as an application to administratively amend
your Operating Permit only the approval signature above is required.
Failure to have the Responsible Official sign below will not delay the Approval Order, but will require
submittal of a separate Operating Permit Application to revise the Title V permit in accordance with
R307-41 5-5a through 5e and R307-41 5-7a through 7i. A guidance document: Title V Operating Permit
Application Due Dates clarifies the required due dates for Title V operating permit applications and can
be viewed at:
https: deq.utah.gov air-quality permitting-guidance and-guidelines air-quality
"Based on information and belief formed after reasonable inquiry, I certify that the
statements and information provided for this Approval Order are true, accurate and
complete and request that this Approval Order be considered as an application to
administratively amend the Operating Permit."
Responsible Official
(Signature & Date)
Print Name of Responsible Official
Engineer Review NIOI 190107: Chevron Products Co - SL Refineiy- Salt Lake Refinery
November 6. 2024
Page I
UTAH DIVISION OF AIR QUALITY
ENGINEER REVIEW
SOURCE INFORMATION
Project Number N101190107
Owner Name Chevron Products Company - Salt Lake Refinery
Mailing Address 685 S Chevron Way
North Salt Lake, UT, 84054
Source Name Chevron Products Co - SL Refinery- Salt Lake Refinery
Source Location:
685 5 Chevron Way
North Salt Lake, UT 84054
UTM Projection 422,270 in Easting, 4,519,770 in Northing
UTM Datum NAD83
UTM Zone UTM Zone 12
SIC Code 2911 (Petroleum Refining)
Source Contact Evan Hunter
Phone Number [phone]
Email [e-mail]
Billing Contact
Phone Number
Email
Project Engineer
Phone Number
Email
Notice of Intent (NOI) Submitted
Date of Accepted Application
Lauren Vander Werff
[phone]
[e-mail]
John Jenks, Engineer
[phone]
jjenksutah.gov
April 17, 2024
August 26, 2024
Engineer Review N 101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery
November 6, 2024
Page 2
SOURCE DESCRIPTION
General Description
Chevron Refinery is a petroleum refinery with a nominal capacity of approximately 50,000
barrels per day of crude oil. The source consists of one fluidized catalytic cracking unit (FCCU),
a delayed coking unit, a catalytic reforming unit, hydrotreating units and two sulfur recovery
units. The source also has assorted heaters, boilers, cooling towers, storage tanks, flares, and
similar fugitive emissions. The refinery operates with a flare gas recovery system on two of its
three hydrocarbon flares.
NSR Classification:
Administrative Amendment
Source Classification
Located in , Northern Wasatch Front 03 NAA, Salt Lake City UT PM2.5 NAA,
Davis County
Airs Source Size: A
Applicable Federal Standards
NSPS (Part 60), A: General Provisions
NSPS (Part 60), Db: Standards of Performance for Industrial-Commercial-Institutional Steam
Generating Units
NSPS (Part 60), J: Standards of Performance for Petroleum Refineries
NSPS (Part 60), Ja: Standards of Performance for Petroleum Refineries for Which
Construction, Reconstruction, or Modification Commenced After May 14, 2007
NSPS (Part 60), K: Standards of Performance for Storage Vessels for Petroleum Liquids for
Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and,
Priorto May 19, 1978
NSPS (Part 60), Ka: Standards of Performance for Storage Vessels for Petroleum Liquids for
Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and
Prior to July 23, 1984
NSPS (Part 60), Kb: Standards of Performance for Volatile Organic Liquid Storage Vessels
(Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or
Modification Commenced After July 23, 1984
NSPS (Part 60), GGGa: Standards of Performance for Equipment Leaks of VOC in Petroleum
Refineries for Which Construction, Reconstruction, or Modification Commenced After
November 7, 2006
NSPS (Part 60), QQQ: Standards of Performance for VOC Emissions From Petroleum
Refinery Wastewater Systems
NSPS (Part 60), 1111: Standards of Performance for Stationary Compression Ignition Internal
Combustion Engines
NSPS (Part 60), JJJJ: Standards of Performance for Stationary Spark Ignition Internal
Combustion Engines
NESI-IAP (Part 61), A: General Provisions
NESHAP (Part 61), M: National Emission Standard for Asbestos
NESHAP (Part 61), FF: National Emission Standard for Benzene Waste Operations
MACT (Part 63), A: General Provisions
MACT (Part 63), CC: National Emission Standards for Hazardous Air Pollutants From
Petroleum Refineries
MACT (Part 63), UUU: National Emission Standards for Hazardous Air Pollutants for
Engineer Review NIOI 190107: Chevron Products Co - SL Refinery- Salt Lake Refinery
November 6, 2024
Page 3
Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur
Recovery Units
MACT (Part 63), EEEE: National Emission Standards for Hazardous Air Pollutants: Organic
Liquids Distribution (Non-Gasoline)
MACI (Part 63), ZZZZ: National Emissions Standards for Hazardous Air Pollutants for
Stationary Reciprocating Internal Combustion Engines
MACI (Part 63), DDDDD: National Emission Standards for Hazardous Air Pollutants for
Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters
MACI (Part 63), GGGGG: National Emission Standards for Hazardous Air Pollutants: Site
Remediation
Title V (Part 70) Major Source
Proiect Proposal
Administrative Amendment to DAQE-ANI 01190106-22 for Corrections to Listed Equipment
and an Increase in Stack Height
Proiect Description
Chevron Products Company (Chevron) requested several minor changes in their current AO as
the result of a self-audit. Multiple engine/generators have either been removed from service or
have power ratings which differ from the equipment list. These will be updated to match existing
operations. There is no expected increase in potential emissions as a result of this update.
In addition, the stack on the F-66 100 VGO Furnace will be extended to allow the unit to operate
at negative pressure. This will prevent leakage and ensure the safety of refinery personnel. No
changes in firing rate or emissions are anticipated. These changes will not constitute a
modification to the equipment or processes covered under existing AO DAQE-ANIOI 190106-22.
EMISSION IMPACT ANALYSIS
There is no change in emissions as a result of this project. The project is not subject to modeling under R307-
410-4 or R307-410-5. [Last updated October 8,2024]
Engineer Review NWI 190107: Chevron Products Co - SL Refinery- Salt Lake Refinery
November 6, 2024
Page 4
SUMMARY OF EMISSIONS
The emissions listed below are an estimate of the total potential emissions from the source. Some
rounding of emissions is possible.
I Criteria Pollutant Change (TPY) Total (TPY)
CO2 Equivalent -16.27 988782.67
Carbon Monoxide -0.50 990.60
Nitrogen Oxides -2.93 763.57
Particulate Matter - PM10 -0.03 260.95
Particulate Matter - PM25 -0.03 109.97
Sulfur Dioxide 0 383.30
Volatile Organic Compounds -0.17 1241.89
Hazardous Air Pollutant Change (lbslyr) Total (lbs/yr)
Acetaldehyde (CAS #75070) -4 165
Acrolein (CAS #107028) 0 239
Ethyl Benzene (CAS #100414) 0 225
Formaldehyde (CAS #50000) -6 1034
Generic MAPs (CAS #GHAPS) -9 254
Hexane (CAS#110543) 0 25309
Xylenes (Isomers And Mixture) (CAS #1330207) -2 350
Change (TPY) Total (TPY) ___________________________________________________________
Total HAPs -0.01 13.79
Note: Change in emissions indicates the difference between previonsAO and proposed modification.
Engineer Review N 101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery
November 6, 2024
Page 5
Review of BACT for New/Modified Emission Units
BACT review regardin2 no review of BACT required
Chevron is updating the listed power ratings of some emergency engines, delisting equipment
which has been removed from service, and increasing the stack height on the F-661 00 YOU
Furnace. None of these changes require a revisiting of BACT. The installed equipment meets the
control requirements and methodologies selected during the initial permitting process.
Equipment being removed from service is not subject to review. The change in stack height on the
YOU Furnace does not constitute a physical change or change in the method of operation of the
YOU Furnace, nor does it trigger a modification under the definitions of 40 CFR 60 Subpart A, or
40 CFR 63 Subpart A. [Last updated November 6, 2024]
SECTION I: GENERAL PROVISIONS
The intent is to issue an air quality AU authorizing the project with the following recommended
conditions and that failure to comply with any of the conditions may constitute a violation of the
AU. (New or Modified conditions are indicated as "New" in the Outline Label):
1.1 All definitions, terms, abbreviations, and references used in this AU conform to those used in
the UAC R307 and 40 CFR. Unless noted otherwise, references cited in these AU conditions
refer to those rules. [R307-101]
1.2 The limits set forth in this AU shall not be exceeded without prior approval. [R307-401]
1.3 Modifications to the equipment or processes approved by this AU that could affect the
emissions covered by this AU must be reviewed and approved. [R307-401-1]
1.4 All records referenced in this AU or in other applicable rules, which are required to be kept by
the owner/operator, shall be made available to the Director or Directors representative upon
request, and the records shall include the two-year period prior to the date of the request.
Unless otherwise specified in this AU or in other applicable state and federal rules, records
shall be kept for a minimum of five (5) years. {R307-401-8]
1.5 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 AU,
including 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 Director 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 AU shall be recorded. [R307-
40 1-4]
1.6 The owner/operator shall comply with UAC R307-1 07. General Requirements: Breakdowns.
[R307-l 07]
Engineer Review NIOI 190107: Chevron Products Co - SL Refinery- Sail Lake Refinery
November 6, 2024
Page 6
I.? The owner/operator shall comply with UAC R307-l 50 Series. Emission Inventories. [R307-
1501
SECTION II: PERMITTED EQUIPMENT
The intent is to issue an air quality AO authorizing the project with the following recommended
conditions and that failure to comply with any of the conditions may constitute a violation of the
AO. (New or Modified conditions are indicated as "New" in the Outline Label):
II.A THE APPROVED EOUIPMENT
II.A.1 Main Refinery
Chevron Salt Lake Refinety
II.A.2 F-lilieS
Boiler #1 1005 (Boiler #5)
Rating: 171 MMBtu/hr
Control: Low-NO
II.A.3 F-11006
Boiler #11006 (Boiler #6)
Rating: 171 MMBtu/hr
Control: Low-NO
II.A.4 F-11007
Boiler #11007 (Boiler #7)
Rating: 225 MMBtu/hr
Control: Low-NO and FGR
II.A.5 16001
Cooling Tower #16001
I1.A.6 16002
Cooling Tower #16002
II.A.7 16003
Cooling Tower #16003
II.A.8 16004
Cooling Tower #16004 (Grandfathered)
II.A.9 F-21001
Crude Unit Furnace #F-2 1001
Rating: 130 MMBtu/hr
Control: Low-NO
Engineer Review NIOI 190107: Chevron Products Co - SL Refineiy- Salt Lake Refineiy
November 6, 2024
Page 7
hAlO F-21002
Crude Unit Furnace #F-21002
Rating: 115.1 MMBtu/hr
Control: Low-NO
hl.A.11 F-32021
FCC Furnace F-32021
Rating: 48.2 MMBtu/hr
II.A.12 F-32023
FCC Furnace F-32023
Rating: 48.2 MMBtu/hr
II.A.13 F-71010
HDN Furnace F-71010
Rating: 15.6 MMBtu/hr
II.A.14 F-71030
HDN Furnace F-71030
Rating: 36.3 MMBtu/hr
II.A.15 F-35001
Reformer Furnace F-35001
Rating: 52.3 MMBtu/hr
II.A.16 F-35002
Reformer Furnace F-35002
Rating: 45 MMBtu/hr
II.A.17 F-35003
Reformer Furnace F-35003
Rating: 31.7 MMBtu/hr
hA. 18 Alkylation Unit
Includes: Alkylation Furnace F-3 6017
Rating: 108 MMBtu/hr
Control: Low-NO
II.A.19 F-70001
Coker Furnace F-7000 I
Rating: 139.2 MMBtu/hr
II.A.20 F-64010
HDS Furnace F-640 10
Rating: 19 MMBtu/hr
Control: Low-NO
Engineer Review N 101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery
November 6. 2024
Page 8
II.A.21 F-64011
HDS Furnace F-6401 I
Rating: 27.3 MMBtu/hr
Control: Low-NO
II.A.22 F-66100
VGO Furnace F-66100
Rating: 40 MMBtu/hr
Control: Low-NO
II.A.23 F-66200
VGO Furnace F-66200
Rating: 66 MMBtu/hr
Control: Low-NO
II.A.24 SRU/TGTU/TGI #1
SRU and Tail Gas Incinerator #1
lI.A.25 SRU/TGTU/TGI #2
SRU and Tail Gas Incinerator #2
II.A.26 Catalyst Regenerator
FCCU and Catalyst Regenerator
lI.A.27 F61312
Flameless Thermal Oxidizer
I1.A.28 Coker Flare (Flare #1)
Coker Flare (Control/Safety Device)
ILA.29 FCCU Flare (Flare #2)
FCCU Flare (Control/Safety Device)
lI.A.30 Alkylation Flare (Flare #3)
Alkylation Flare (Control/Safety Device)
I1.A.31 Diesel-powered back-up equipment:
A. Second North Substation Generator: One Emergency Generator
Engine Rating: 750 hp. Generator Rating: 500 kW.
B. #1 CWT: One Emergency Cooling Water Pump
Engine Rating: 665 hp
C. HDN Substation: One Emergency Generator
Engine Rating: 601 hp. Generator Rating: 400 kW.
D. VGO: One Emergency Generator
Engine Rating: 755 lip (max). Generator Rating: 500 kW.
Engineer Review Nb] 190107: Chevron Products Co - SL Refinery- Salt Lake Refinery
November 6, 2024
Page 9
II.A.32 E. Crude Substation: One Backup Generator
Engine Rating: 900 hp. Generator Rating: 600 kW.
F. Third North Substation: One Backup Emergency Generator
Engine Rating: 1490 lip Generator Rating: 1,111 kW.
G. Admin Building: One Backup Generator
Engine Rating: 2,220 hp. Generator Rating: 1,250 kW.
H. TCLR: One Backup Generator
Engine Rating:197 hp. Generator Rating: 125 kW.
I. North Tank Field: One Backup Generator
Engine Rating: 896 hp. Generator Rating: 600 kW.
II.A.33 J. WWTP: One Backup Generator
Engine Rating: 896 lip. Generator Rating 600 kW.
K. Alky: One Emergency Generator
Engine Rating: 752 hp. Generator Rating: 500 kW.
L. Boiler Plant: Two Compressors
Engine Rating: 524 hp each
M. Collection Box: One Backup Pump
Engine Rating: 109 hp
N. FCC MCC: One Emergency Generator
Engine Rating: 895 hp. Generator Rating: 600 kW
0. Three Fire Water Pumps
Engine Rating: 950 hp (maximum design at 2100 rpm) each.
II.A.34 P. One Canal Fire Water Emergency Generator
Engine Rating: 462 lip. Generator Rating: 300 kW.
Q. One Reformer Substation Emergency Generator
Engine Rating: 616 lip. Generator Rating: 400 kW.
II.A.35 Natural gas-powered backup equipment
A. One Emergency Generator
Engine Rating: 50 lip. Generator Rating: 30 kW.
JI.A.36 K35001, K35002, K35003
Three Reformer Compressor Drivers
Rating: 16 MMBtu/hr each
Fuel: Refinery Fuel Gas
Engineer Review N 101190107: Chevron Products Co . SL Refinery- Salt Lake Refinery
November 6. 2024
Page 10
II.A.37 Amine Unit #1
Amine Unit #1
II.A.38 Amine Unit #2
Amine Unit #2
II.A.39 K36067
Lime Loading Facility K36067
II.A.40 FCC Fines Bin
SECTION II: SPECIAL PROVISIONS
The intent is to issue an air quality AO authorizing the project with the following recommended
conditions and that failure to comply with any of the conditions may constitute a violation of the
AO. (New or Modified conditions are indicated as "New" in the Outline Label):
II.B REOUIREMENTS AND LIMITATIONS
II.B.l Source-wide Requirements
II.B. l.a Except as otherwise stated in this AD, the owner/operator shall use only plant gas or
purchased natural gas as a primary fuel. Plant Coke may be burned in the FCC Catalyst
Regenerator. Torch oil may be burned in the FCC Catalyst Regenerator to assist in starting,
restarting, hot standby, or to maintain regenerator heat balance. If any other fuel is to be used,
an AD shall be required. [Consent Decree, R307-401]
II.B.1.b All petroleum refineries in or affecting any PM2.5 nonattainment area or any PMio
nonattainment or maintenance area shall reduce the H2S content of the refinery plant gas to 60
ppm or less as described in 40 CFR 60.102a. Compliance shall be based on a rolling average
of365 days. The owner/operator shall comply with the fuel gas monitoring requirements of 40
CFR 60.107a and the related recordkeeping and reporting requirements of40 CFR 60.108a.
As used herein, refinery "plant gas" shall have the meaning of"fuel gas" as defined in 40 CFR
60.l0la, and may be used interchangeably.
For natural gas, compliance is assumed while the fuel comes from a public utility. [SIP
Section IX.H.1 1.g.ii]
II.B.1.c No petroleum refineries in or affecting any PM2.5 nonattainment area or PMio nonattainment
or maintenance area shall be allowed to burn liquid fuel oil in stationary sources except during
natural gas curtailments or as specified below:
A. The use of diesel fuel meeting the specifications of 40 CFR 80.5 10 in standby or
emergency equipment is exempt from the limitation above and is allowed in standby or
emergency equipment at all times.
B. Plant coke may be burned in the FCC Catalyst Regenerator. [R307-401-8(1)(a), SIP
Section IX.H.1 1.g.vii, SIP Section JX.H.12.d.iv]
Engineer Review N 101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery
November 6. 2024
Page 11
lI.B.1 .d The owner/operator shall not allow visible emissions to exceed the opacity limits set in R307-
309. [R307-309]
II.B. I.e The owner/operator shall ensure for all stack testing performed:
The owner/operator 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 Director shall be held at
least 30 days prior to the test if directed by the Director. The emission point shall conform to
the requirements of 40 CFR 60, Appendix A, Method I. Occupational Safety and Health
Administration (051-IA) 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.
If the desired throughput rate is not achieved at the time of testing, the achieved throughput
i-ate +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.
Where appropriate, the following test methods shall be used, although other EPA-approved
test methods acceptable to the Director can be substituted and approved through the pre-test
protocol:
Volumetric flow rate - 40 CFR 60, Appendix A, Method 2
SO2 emissions - 40 CFR 60, Appendix A, Method 6C
NO emissions - 40 CFR 60, Appendix A, Method 7E
PM10 and PM2.5 emissions -40 CFR 51, Appendix M, Methods 201 a and 202
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 Director to give the results in the specified
units of the emission limitation. [R307-401]
I1.B.I .f Source-wide combined emissions of PM10 shall not exceed 0.715 tons per day (tpd). [SIP
Section IX.H.2.d.i]
Engineer Review N 101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery
November 6. 2024
Page 12
II.B.Lf.1 Compliance with the source-wide PM10 Cap shall be determined for each day as follows:
A. Total 24-hour PM10 emissions for the emission points shall be calculated by adding the
daily results of the PM10 emissions equations listed below for natural gas, plant gas, and fuel
oil combustion. These emissions shall be added to the emissions from the cooling towers, and
the FCCU to arrive at a combined daily PM10 emission total.
B. For purposes of this subsection a "day" is defined as a period of 24-hours commencing at
midnight and ending at the following midnight.
C. Daily natural gas and plant gas consumption shall be determined through the use of flow
meters.
D. Daily fuel oil consumption shalt be monitored by means of leveling gauges on all tanks that
supply combustion sources.
E. The equation used to determine emissions for the boilers and furnaces shall be as follows:
Emission Factor (lb/MMscf) * Gas Consumption (MMscf/24 hrs)/(2,000 lb/ton)
F. Results shall be tabulated for each day, and records shall be kept which include the meter
readings (in the appropriate units) and the calculated emissions. [SIP Section IX.H.2.d.i.C]
II.B.1 .f. 2 The emission factors derived from the most current performance test shalt be applied to the
relevant quantities of fuel combusted. Unless adjusted by performance testing, the default
emission factors to be used are as follows:
A. Natural gas:
Filterable PM10: 1.9 lb/MMscf
Condensable PM10: 5.7 lb/MMscf
B. Plant gas:
Filterable PM10: 1.9 lb/MMscf
Condensable PM10: 5.7 tb/MMscf
C. Diesel fuel: shall be determined from the latest edition of AP-42 or other EPA approved
methods.
D. Cooling Towers: shall be determined from the latest edition of AP-42 or other EPA
approved methods.
E. FCC Stack: The PM10 emission factors shall be based on the most recent stack test and
verified by parametric monitoring.
F. Where mixtures of fuel are used in a Unit, the above factors shall be weighted according to
the use of each fuel. [SIP Section IX.H.2.d.i.A]
Engineer Review NWI 190107: Chevron Products Co - SL Refinery- Salt Lake Refinery
November 6, 2024
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II.B.1.f.3 The default emission factors listed above apply until such time as stack testing is conducted.
Initial PM1o stack testing on the FCC stack has been performed and shall be conducted at least
once every three (3) years from the date of the last stack test.
Stack testing shall be performed as outlined in Condition II.B.I.e. [SIP Section IX.H.2.d.i.B]
11.3. 1.g Source-wide combined emissions of PM2.s (filterable+condensable) shall not exceed 0.305
tons per day (tpd) and 110 tons per rolling 12-month period. [SIP Section IX.H.12.d.i]
lI.B.1.g.1 I Compliance with the source-wide PM2,5 Cap shall be determined for each day as follows
A. Total 24-hour PM2.5 emissions for the emission points shall be calculated by adding the
daily results of the PM2.5 emissions equations listed below for natural gas, plant gas, and fuel
oil combustion. These emissions shall be added to the emissions from the FCCU to arrive at a
combined daily PM2.5 emission total.
B. For purposes of this subsection a 'day is defined as a period of 24-hours commencing at
midnight and ending at the following midnight.
C. Daily natural gas and plant gas consumption shall be determined through the use of flow
meters.
D. Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that
supply combustion sources.
E. The equation used to determine emissions for the boilers and furnaces shall be as follows:
Emissions = Emission Factor (lb/MMscf) * Gas Consumption (MMscf/24 hrs)/(2,000 lb/ton)
F. Results shall be tabulated for each day, and records shall be kept which include the meter
readings (in the appropriate units) and the calculated emissions. [SIP Section lX.H.12.d.i.C]
Engineer ReviewNiOl 190107: Chevron Products Co - SL Refinery- Salt Lake Refinemy
November 6, 2024
Page 14
II.B.1 .g.2 The emission factors derived from the most current performance test shall be applied to the
relevant quantities of fuel combusted. Unless adjusted by performance testing, the default
emission factors to be used are as follows:
A. Natural gas:
Filterable PM2.5: 1.9 lb/MMscf
Condensable PM25: 5.7 lb/MMscf
B. Plant gas:
Filterable PM2s: I .9 lb/MMscf
Condensable PM2,s: 5.7 lb/MMscf
C. Diesel fuel: shall be determined from the latest edition of AP-42 or other EPA approved
methods.
D. FCC Stack: The PM25 emission factors shall be based on the most recent stack test and
verified by parametric monitoring.
B. Where mixtures of fuel are used in a Unit, the above factors shall be weighted according to
the use of each fuel. [SIP Section lX.H.12.d.i.A]
II.B. 1 .g.3 The default emission factors listed above apply until such time as stack testing is conducted.
Initial PM2,s stack testing on the FCC stack has been performed and shall be conducted at least
once every three (3) years from the date of the last stack test.
Stack testing shall be performed as outlined in Condition Il.B. I.e. [SIP Section IX.H. I2.d.i.B]
II.B. I .h Source-wide combined emissions ofNO shall not exceed 2.1 tons per day (tpd) and 766.5
tons per rolling 12-month period. [SIP Section lX.H.12.d.ii]
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November 6. 2024
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II.B. 1.11.1 Compliance with the source-wide NO Cap shall be determined for each day as follows:
A. Total 24-hour NO emissions shall be calculated by adding the emissions for each emitting
unit.
B. The emissions for each emitting unit shall be calculated by multiplying the hours of
operation of a unit, feed rate to a unit, or quantity of each fuel combusted at each affected unit
by the associated emission factor, and summing the results.
C. A NO. CEM shall be used to calculate daily NO emissions from the FCCU.
D. A NO CEM shall be used to calculate daily NO emissions from Boiler #7
F. For purposes of this subsection a "day" is defined as a period of 24-hours commencing at
midnight and ending at the following midnight.
F. Daily natural gas and plant gas consumption shall be determined through the use of flow
meters.
0. Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that
supply combustion sources.
H. Results shall be tabulated for each day, and records shall be kept which include the meter
readings (in the appropriate units) and the calculated emissions. [SIP Section IX.H.12.d.ii.C]
II.B. .h.2 The emission factors derived from the most current performance test shall be applied to the
relevant quantities of fuel combusted. Unless adjusted by performance testing, the default
emission factors to be used are as follows:
A. Natural gas: shall be determined from the latest edition of AP-42 or other EPA approved
methods.
B. Plant gas: shall be assumed equal to natural gas
C. Alkylation polymer: shall be determined from the latest edition ofAP-42 (as fuel oil #6) or
other EPA approved methods.
D. Diesel fuel: shall be determined from the latest edition of AP-42 or other EPA approved
methods.
E. Where mixtures of fuel are used in a Unit, the above factors shall be weighted according to
the use of each fuel. [SIP Section IX.H.I2.d.ii.A]
II.B.1 .h.3 The default emission factors listed above apply until such time as stack testing is conducted.
Initial NO stack testing on natural gas/refinery fuel gas combustion equipment above 100
MMBtu/hr has been performed and shall be conducted at least once every three (3) years from
the date of the last stack test. At that time a new flow-weighted average emission factor in
terms of: lbs/MMbtu shall be derived for each combustion type listed above.
Stack testing shall be performed as outlined in Condition II.B. 1.e. [SIP Section IX.H. I 2.d.ii.B]
Engineer Review NIOI 190107: Chevron Products Co - SL Refinery- Salt Lake Refinery
November 6, 2024
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II.B.1 .i Source-wide combined emissions of SO2 shall not exceed 1.05 tons per day (tpd) and 383.3
tons per rolling 12-month period. [SIP Section IX.H.12.d.iii]
II.B. I .i. 1 Compliance with the source-wide SO2 Cap shall be determined for each day as follows:
A. Total daily SO2 emissions shall be calculated by adding the daily SO2 emissions for natural
gas and plant fuel gas combustion, to those from the FCC and SRU stacks.
B. Daily natural gas and plant gas consumption shall be determined through the use of flow
meters.
C. Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that
supply combustion sources.
D. Results shall be tabulated for each day, and records shall be kept which include CEM
readings for H2S (averaged for each one-hour period), all meter readings (in the appropriate
units), fuel oil parameters (density and wt% sulfur for each day any fuel oil is burned), and the
calculated emissions.
E. For purposes of this subsection a "day" is defined as a period of 24-hours commencing at
midnight and ending at the following midnight. [SIP Section IX.H.12.d.iii.B]
Il.B.1 .i.2 The emission factors derived from the most current performance test shall be applied to the
relevant quantities of fuel combusted. The default emission factors to be used are as follows:
A. FCCU: The emission rate shall be determined by the FCC SO2 CEM
B. SRUs: The emission rate shall be determined by multiplying the sulfur dioxide
concentration in the flue gas by the flow rate of the flue gas. The sulfur dioxide concentration
in the flue gas shall be determined by CEM.
C. Natural gas: EF = 0.60 lb/MMscf
D. Fuel oil:
The emission factor to be used for combustion shall be calculated based on the weight percent
of sulfur, as determined by ASTM Method D-4294-89 or EPA approved equivalent acceptable
to the Director, and the density of the fuel oil, as follows:
EF (lb 502/k gal) = density (lb/gal) * (1000 gal/k gal) * wt.% S/100 * (64 lb S02/32 lb 5)
E. Plant gas: the emission factor shall be calculated from the H2S measurement obtained from
the H2S CEM.
F. Where mixtures of Iliel are used in a Unit, the above factors shall be weighted according to
the use of each fuel. [SIP Section IX.H.12.d.iii.A]
II.B.2 Conditions on Boiler #11005 (Boiler #5)
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lI.B.2.a N0 emissions shall not exceed the following rate on a 30-day rolling average basis: [NSPS
Db §60.44b(b) and §60.44b(i)]
En = ((0.1 x Hgo) + (0.2 x Hr)) I (Hgo + Hr)
Where:
En = NO emission limit (lb/MMbtu)
Hgo = 30-day heat input from combustion of natural gas or distillate oil
Hr = 30-day heat input from combustion of any other fuel. [40 CFR 60 Subpart Db]
Il.B.2.a.1 The N0 emission rate shall be predicted based on excess 02 in the flue gas and by boiler
loading as specified in a plan submitted to and approved by the Director [NSPS Db
§60.48b(g)(2)]. Predicted NON emission rate shall be evaluated at least every three (3) years
through testing as outlined in Condition II.B. I.e. [40 CFR 60 Subpart Db]
II.B.3 Conditions on Boiler #11006 (Boiler #6)
II.B.3.a N0 emissions shall not exceed the following rate on a 30-day rolling average basis: [NSPS
Db §60.44b(b) and §60.44b(i)]
En = ((0.1 x Hgo) + (0.2 x Fir)) / (Hgo + Hi)
Where:
En = NO emission limit (lb/MMbtu)
Hgo = 30-day heat input from combustion of natural gas or distillate oil
Hr = 30-day heat input from combustion of any other fuel. [40 CFR 60 Subpart Db]
II.B.3.a.1 The NO emission rate shall be predicted based on excess 02 in the flue gas and by boiler
loading as specified in a plan submitted to and approved by the Director [NSPS Db
§60.48b(g)(2)J. Predicted NO emission rate shall be evaluated at least every three (3) years
through testing as outlined in Condition JIB. I.e. [40 CFR 60 Subpart Db]
II.B.4 Conditions on the SRUs
I1.B.4.a All petroleum refineries in or affecting any PM2,5 nonattainment area or any PMio
nonattainment or maintenance area shall require:
A. Sulfur removal units/plants (SRUs) that are at least 95% effective in removing sulfur from
the streams fed to the unit; or
B. SRUs that meet the SO2 emission limitations listed in 40 CFR 60.lO2affl(l) or
60.I02a(f)(2) as appropriate. [SIP Section lX.H.1.g.iii.A]
II.B.4.b The owner/operator shall process amine acid gas and sour water stripper acid gas in the
SRU(s). [SIP Section IX.H.I.g.iii.B]
II.B.4.b.1 Compliance shall be demonstrated by daily monitoring of flows to the SRU(s). Compliance
shall be determined on a rolling 30-day average. [SIP Section IX.H. 1.g.iii.C]
1I.B.5 Conditions on SRU and Tail Gas Treatment Unit #1
JI.B.5.a Emissions of SO2 from SRU #1 shall not exceed 0.242 tons/day. [R307-401]
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IJ.B.5.a.1 Daily sulfur dioxide emissions 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 CEM 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 evaluation shall be performed within 30 days of installation.
The performance evaluation shall be conducted and data reduced in accordance with the
methods and procedures contained in 40 CFR 60, Appendix B: Performance Specification 2.
Notification must be made to the Director prior to conducting the performance evaluation.
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 B. An
annual relative accuracy test audit shall be conducted, and quarterly reports submitted, in
accordance with the procedures outlined in R307-l 70, UAC, and 40 CFR 52 Appendix E. If a
new volumetric flow measurement device is installed, an initial performance evaluation shall
be performed within 30 days of installation. The performance evaluation 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 Director prior to conducting the performance
evaluation. 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. [R307-401]
II.B.5.b Emissions of SO2 from SRU #1 shall not exceed 88.5 tons/yr. [R307-401]
II.B.5.b.l Compliance shall be determined on a 12-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 11
months' emission totals to give the new 12-month rolling total. [R307-401]
1I.B.5.c The owner/operator shall continue to route or re-route all sulfur pit emissions so that they are
eliminated, controlled, or included and monitored as part of the SRU's emissions subject to the
emissions limits of II.B.5. [Consent Decree]
I1.B.6 Conditions on SRU and Tail Gas Treatment Unit #2
II.B.6.a Emissions of SO2 from SRU #2 shall not exceed 0.268 tons/day. [R307-401]
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II.B.6.a.l Daily sulfur dioxide emissions 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 CEM 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 evaluation shall be performed within 30 days of installation.
The performance evaluation shall be conducted and data reduced in accordance with the
methods and procedures contained in 40 CFR 60, Appendix B: Performance Specification 2.
Notification must be made to the Director prior to conducting the performance evaluation.
Whenever the SO2 CEM is bypassed for short periods, SO2 GEM 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. Ifa
new volumetric flow measurement device is installed, an initial performance evaluation shall
be performed within 30 days of installation. The performance evaluation 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 Director prior to conducting the performance
evaluation. The source shall maintain records of the SO2 concentration, the mass flow rate,
and the resulting calculated emissions. Records of all GEM calibrations shall also be
maintained. [R307-401]
I1.B.6.b Emissions of SO2 from SRU #2 shall not exceed 97.7 tons/yr. [R307-401]
11.B.6.b.l Compliance shall be determined on a 12-month rolling average. Each month, the 502
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 11
months' emission totals to give the new 12-month rolling total. [R307-401]
II.B.6.c The owner/operator shall continue to route or re-route all sulfur pit emissions so that they are
eliminated, controlled, or included and monitored as part of the SRUs emissions subject to the
emissions limits of II.B.6. [Consent Decree]
II.B.7 Conditions on the FCC and Catalyst Regenerator
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H.B.7.a Emissions of SO2 from the FCCIJ Regenerator Vent shall not exceed the following rates and
concentrations:
A. 25 pprnvd 502 @ 0% 02 on a 365-day rolling average
B. 50 ppmvd SO2 @ 0% 02 on a 7-day rolling average
C. 50 tons of SO2 on a 12-month rolling average
D. 0.28 tons of SO2 per day.
SO2 emissions during periods of Startup, Shutdown, or Malfunction shall not be used in
determining compliance with the emission limit of 50 ppmvd SO2 @0% 02 on a 7-day rolling
average basis.
The SO2 short-term limit listed in B. above shall exclude FCCU feed hydrotreater outages if
Chevron complies with an EPA-approved hydrotreater outage plan and is maintaining and
operating the FCCU in a manner consistent with good air pollution control practices. It shall
apply at all other times the FCCU is in operation.
In addition, in the event that the source asserts that the basis for a specific Hydrotreater
Outage is a shutdown (where no catalyst changeout occurs) required by ASME pressure vessel
requirements or applicable state boiler requirements, the source shall submit a report to EPA
that identifies the relevant requirements and justifies the permittee's decision to implement the
shutdown during the selected time period. [Consent Decree, R307-401]
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11.B.7.a.1 The SO2 emission factor for the FCC and Catalyst Regenerator shall be determined by
continuous emission monitor. The regenerator flow rate calculation established in 40 CFR 63
Subpart UUU (MACI UUU) shall be used in conjunction for this calculation.
For continuous emission monitor calculations the monitor shall be operated, maintained,
certified, and calibrated in accordance with R307-170, UAC. The provisions of40 C.F.R. §
60.13 that are applicable to CEM S (excluding those provisions applicable only to Continuous
Opacity Monitoring Systems) and Part 60 Appendices A and F, and the applicable
performance specification test of 40 C.F.R. Part 60 Appendix B are applicable to the
FCC/Catalyst Regenerator CEM. With respect to 40 C.F.R. Part 60, Appendix F, Chevron
must conduct either a Relative Accuracy Audit ('RAA') or a Relative Accuracy Test Audit
("RATA") on each CEMS at least once every one (1) year. The source must also conduct
Cylinder Gas Audits ("CGA") each calendar quarter during which a RAA or a RATA is not
performed. With respect to the 02 CEMS, in lieu of the audit points specified in 40 C.F.R. Part
60, Appendix F § 5.1.2., the source may audit the 02 CEMS at 20-30% and 50-60% of the
actual 02 CEMS span value. If a new monitor is installed, an initial performance evaluation
shall be performed within 30 days of installation. The performance evaluation 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
Director 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.
For the stack test calculations to establish the FCC and Catalyst Regenerator SO2 emission
factor, the owner/operator shall determine mass emission rates (lbs/hr, etc.) as follows:
The pollutant concentration, as determined by the appropriate methods, shall be multiplied by
the volumetric flow rate and any necessary conversion factors as determined by the Director.
The owner/operator 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. [R307-170]
II.B.7.b Emissions of NO from the FCCU Regenerator Vent shall not exceed the following rates
A. 100 tons of N0 per year on a rolling 12-month basis
B. 0.55 tons per day
C. 57.8 ppmvd @ 0% 02 on a 365-day rolling average
D. 106.3 ppmvd @ 0% 0 on a 7-day rolling average
The N0 long-term limit listed in C. above shall apply at all times the FCCU is in operation.
The N0 short-term limit listed in D. above shall exclude periods of startup, shutdown, and
malfunction. It shall also exclude FCCU feed hydrotreater outage if the owner/operator
complies with an EPA-approved hydrotreater outage plan. It shall apply at all other times the
FCCU is in operation. [R307-40lJ
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II.B.7.b.1 The NO emission factor for the FCC and Catalyst Regenerator shall be determined by
continuous emission monitor. The regenerator flow rate calculation established in 40 CFR 63
Subpart UUU (MACT UUIJ) shall be used in conjunction for this calculation.
For continuous emission monitor calculations, the monitor shall be operated, maintained,
calibrated, and certified in accordance with R307-170, UAC and the provisions of 40 C.F.R. §
60.13 that are applicable to CEMS (excluding those provisions applicable only to Continuous
Opacity Monitoring Systems) and Part 60 Appendices A and F, and the applicable
performance specification test of 40 C.F.R. Part 60 Appendix B. With respect to 40 C.F.R.
Part 60, Appendix F, Chevron must conduct either a Relative Accuracy Audit ("RAN) or a
Relative Accuracy Test Audit ("RATA") on each CEMS at least once every one (1) year. The
source must also conduct Cylinder Gas Audits ("CGA") each calendar quarter during which a
RAA or a RATA is not performed. With respect to the 02 CEMS, in lieu of the audit points
specified in 40 C.F.R. Part 60, Appendix F § 5.1.2., the source may audit the 02 CEMS at 20-
30% and 50-60% of the actual 02 CEMS span value. If a new monitor is installed, an initial
performance evaluation shall be performed within 30 days of installation. The performance
evaluation 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 Director prior to conducting the performance test. Whenever the NO
CEM is bypassed for short periods, N0 CEM data from the previous three days will be
averaged and used as an emission factor to determine emissions.
For stack test calculations, mass emission rates (lbs/hr, etc.), the pollutant concentration, as
determined by the appropriate methods, shall be multiplied by the volumetric flow rate and
any necessary conversion factors as determined by the Director to establish the FCC and
Catalyst Regenerator N0 emission factor.
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. {R307-170]
JLB.7.c Emissions ofC0 from the FCCU shall not exceed 500 ppmvd at 0% 02 on a I-hour average
basis. CO emissions during periods of startup, shutdown or malfunction shall not be used
when determining compliance with this emission limit. [R307-401-8]
1I.B.7.c.1 The source shall use CO and 02 CEMS to monitor compliance with the CO emission limit for
the FCCU and Catalyst Regenerator. The source shall install, certi', maintain, and operate the
CEMS in accordance with the provisions of 40 C.F.R. § 60.13 that are applicable to CEMS
(excluding those provisions applicable only to Continuous Opacity Monitoring Systems) and
Part 60 Appendices A and F, and the applicable performance specification test of 40 C.F.R.
Part 60 Appendix B. With respect to 40 C.F.R. Part 60, Appendix F, Chevron must conduct
either a Relative Accuracy Audit ("RAA") or a Relative Accuracy Test Audit ("RATA") on
each CEMS at least once every one (1) year. The source must also conduct Cylinder Gas
Audits ("CGA") each calendar quarter during which a RAA or a RATA is not performed.
With respect to the 02 CEMS, in lieu of the audit points specified in 40 C.F.R. Part 60,
Appendix F § 5.1.2., the source may audit the 02 CEMS at 20-30% and 50-60% of the actual
02 CEMS span value. [R307-170]
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II.B.7.d The owner or operator ofan FCCU shall comply with an emission limit of 1.0 pounds PM per
1000 pounds coke burn-off. [SIP Section IX.H. 11.g.i.B.I]
ll.B.7.d.1 Compliance with this limit shall be determined by following the stack test protocol specified
in 40 C.F.R. §60.106(b) to measure PM emissions on the FCCU. Each owner/operator shall
conduct stack tests once every three (3) years at each FCCU. [SIP Section IX.H. 11.g.i.B.II]
11.B.7.e Each owner or operator ofan FCCU subject to NSPS Ja shall install, operate and maintain a
continuous parameter monitor system (CPMS) to measure and record operating parameters
from the FCCU and control devices as per the requirements of 40 CFR 60.105a(b)(1). Each
owner or operator of an FCCU not subject to NSPS Ja shall install, operate and maintain a
continuous opacity monitoring system to measure and record opacity from the FCCU as per
the requirements of 40 CFR
63.1572(b) and comply with the opacity limitation as per the requirements of Table 7 to
Subpart UUU of Part 63. [SIP Section IX.H.l l.g.i.B.III]
ll.B.7.f Opacity from the FCCU and Catalyst Regenerator shall be monitored by a continuous opacity
monitoring system ('COMS"). The source shall install, certi', calibrate, maintain, and
operate the COMS in accordance with 40 C.F.R. § 60.11,60.13 and Part 60 Appendix A, and
the applicable performance specification test of 40 C.F.R. Part 60 Appendix B. [Consent
Decree]
II.B.8 Conditions on Miscellaneous Diesel-fired Equipment
II.B.8.a The owner/operator shall not operate each emergency engine, back-up pump or fire engine on
NEW site for more than 100 hours per calendar year during non-emergency situations. There is no
time limit on the use of the engines during emergencies. [40 CFR 63 Subpart ZZZZ, R307-
401-8]
1I.B.8.a.1 To determine compliance with the above annual total, the owner/operator shall calculate a new
NEW 12-month total by the 20th day of each month using data from the previous 12 months.
Records documenting the operation of each emergency engine shall be kept in a log and shall
include the following:
a. The date the equipment was used
b. The duration of operation in hours
c. The reason for the equipment usage. [40 CFR 63 Subpart ZZZZ, R307-401-8]
II.B.8.a.2 To determine the duration of operation, the owner/operator shall install a non-resettable hour
meter for each emergency engine. [R307-401-8, 40 CFR 63 Subpart ZZZZ]
II.B.8.b The owner/operator shall only use diesel fuel (e.g. fuel oil #1, #2, or diesel fuel oil additives)
as fuel in each emergency engine. [R307-401-8]
II.B.8.b. I The owner/operator shall only combust diesel fuel that meets the definition of ultra-low sulfur
diesel (ULSD), which has a sulfur content of 15 ppm or less. [R307-401-8]
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II.B.8.b.2 To demonstrate compliance with the ULSD fuel requirement, the owner/operator shall
maintain records of diesel fuel purchase invoices or obtain certification of sulfur content from
the diesel fuel supplier. The diesel fuel purchase invoices shall indicate that the diesel fuel
meets the ULSD requirements. [R307-40 1-8]
II.B.8.c The following engines qualify under 40 CFR 63.6590(c) Stationary RICE subject to
NEW regulations under 40 CFR Part 60 Subpart 1111:
1. North tank field generator: one backup generator. Engine Rating: 896 hp. Generator Rating:
600 kW.
2. TCLR generator: backup generator. Engine rating 197 hp. Generator Rating 125 kW.
3. WWTP: One Backup Generator. Engine Rating 896 hp. Generator Rating 600 kW.
4. Collection box backup pump: one pump. Engine rating: 109 hp.
5. One canal fire water emergency generator. Engine Rating: 462 hp. Generator Rating: 300
kW.
These engines must meet the requirements of 40 CFR 63 Subpart ZZZZ, by meeting the
requirements of 40 CFR 60 Subpart 1111. The requirements are listed at §60.4211(a), (c), (f),
and (g). These engines are not subject to any additional requirements of 40 CFR 63 Subpart
ZZZZ. [40 CFR 60 Subpart 1111, 40 CFR 63 Subpart ZZZZ]
II.B.9 Conditions on Reformer Compressor Engines
II.B.9.a Emissions of NO and CO at the three listed reformer compressors shall not exceed the
following concentration limits:
K35001: 236 ppmvd NON, 834 ppmvd CO
K35002: 208 ppmvd NON, 926 ppmvd CO
K35003: 230 ppmvdNO, 556 ppmvd CO. [R307-401-8(1)(a)]
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Page 25
II.B.9.a.1 Demonstrating Compliance with Emission Limits
a. Beginning no later than one (1) year after the Emission Limits Tests and every two (2)
years thereafter, the owner/operator shall perform emission tests to demonstrate compliance
with the emission limits established for the reformer compressor engines. The tests shall be
conducted on each engine and shall be the average of three (3) one-hour tests on each engine.
The tests shall be conducted, and the emissions shall be calculated, in accordance with 40
CFR § 60.4244.
b. The owner/operator shall continuously measure and record the catalyst inlet temperature
data in according to 40 CFR § 63.6625(b); reduce these data to 4-hour rolling averages, and
maintain the 4-hour rolling averages within the operating limitations for the catalyst inlet
temperature, except for periods of startup, shutdown, and malfunction, as those terms are
defined in 40 CFR § 60.2.
c. The owner/operator shall measure and record the pressure drop across each catalyst bed
once per month. The owner/operator shall maintain each catalyst bed so that the pressure drop
across each catalyst is within the operating limitation established during the Emission Limits
Tests.
d. The owner/operator shall replace the 02 sensor on each reformer compressor engine in
accordance with the vendor-recommended preventative maintenance schedule. Following
each 02 sensor replacement, the owner/operator shall measure N0 and CO emissions once
using a portable analyzer to determine the adequate set point of the AFRC to maintain
operation of the reformer compressor engine near stoichiometric conditions. The
owner/operator shall maintain records documenting sensor replacement and portable analyzer
results. [R307-150]
II.B. 10 Miscellaneous SIP Conditions
II.B.10.a The owner or operator shall comply with the requirements of4O CFR 63.654 for heat
exchange systems in VOC service. The owner or operator may elect to use another EPA-
approved method other than the Modified El Paso Method if approved by the Director.
The following applies in lieu of 40 CFR 63.654(b): A heat exchange system is exempt from
the requirements in paragraphs 63.654(c) through (g) of this section if it meets any one of the
criteria in the following paragraphs (1) through (2) of this section.
1. All heat exchangers that are in VOC service within the heat exchange system that either:
a. Operate with the minimum pressure on the cooling water side at least 35 kilopascals greater
than the maximum pressure on the process side; or
b. Employ an intervening cooling fluid, containing less than 10 percent by weight of VOCs,
between the process and the cooling water. This intervening fluid must serve to isolate the
cooling water from the process fluid and must not be sent through a cooling tower or
discharged. For purposes of this section, discharge does not include emptying for maintenance
purposes.
2. The heat exchange system cools process fluids that contain less than 10 percent by weight
VOCs (i.e., the heat exchange system does not contain any heat exchangers that are in VOC
service). [SIP Section IX.H.1 I.g.iii.A]
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ll.B. I 0.b For leak detection and repair, the owner/operator shall comply with the following:
A. The owner/operator shall comply with the requirements of 40 CFR 60.590a to 60.593a
B. For units complying with the Sustainable Skip Period, previous process unit monitoring
results may be used to determine the initial skip period interval provided that each valve has
been monitored using the 500 ppm leak definition. [SIP Section IX.H. I .g.iv]
II.BJO.c The owner/operator shall not allow any stationary tank of 40,000-gallon or greater capacity
and containing or last containing any organic liquid, with a true vapor pressure equal or
greater than 10.5 kPa (1.52 psia) at storage temperature (see R307-324-4(1)) to be opened to
the atmosphere unless the emissions are controlled by exhausting VOCs contained in the tank
vapor-space to a vapor control device until the organic vapor concentration is 10 percent or
less of the lower explosion limit (LEL).
These degassing provisions shall not apply while connecting or disconnecting degassing
equipment. [SIP Section IX.H.I1.g.vi]
II.B.I0.c.1 The Director shall be notified of the intent to degas any tank subject to the rule. Except in an
emergency situation, initial notification shall be submitted at least three (3) days prior to
degassing operations. The initial notification shall include:
A. Start date and time;
B. Tank owner, address, tank location, and applicable tank permit numbers;
C. Degassing operator's name, contact person, and telephone number;
D. Tank capacity, volume of space to be degassed, and materials stored;
B. Description of vapor control device. [SIP Section IX.H.1 l.g.vi.C]
Il.B. I 0.d All hydrocarbon flares at petroleum refineries located in or affecting a PM2.5 nonattainment
area or any PM10 nonattainment or maintenance area shall be subject to the flaring
requirements ofNSPS Subpart Ja(40 CFR6O.lOoa-109a), if not already subject under the
flare applicability provisions ofJa. [SIP Section IX.H.1 I.g.v.A]
II.B.10.d.1 The owner/operator shall either:
1) install and operate a flare gas recovery system designed to limit hydrocarbon flaring
produced from each affected flare during normal operations to levels below the values listed in
40 CFR 60.lO3a(c), or
2) limit flaring during normal operations to 500,000 scfd for each affected flare.
Flare gas recovery is not required for dedicated SRU flare and header systems, or HF flare and
header systems. [SIP Section IX.H.1 1.g.v.B]
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Page 27
PERMIT HISTORY
When issued, the approval order shall supersede (if a modification) or will be based on the
following documents:
Is Derived From Source Submitted NO! dated April 17, 2024
Incorporates Additional Information Received dated May 21, 2024
Incorporates Additional Information Received dated August 26, 2024
Supersedes DAQE-ANI 01190106-22 dated August 24, 2022
REVIEWER COMMENTS
Comment repardin changes in equipment (April and May NOIs):
Chevron's first set of requested changes are outlined in Table B.1 of the April 17,2024 R307-401-12
notification. Chevron's second set of requested changes are outlined in Table B. I of the May 21,
2024 notification. These changes result in the following updates in the equipment list and conditions
of section II.B:
I1.A.3 1
Diesel-powered back-up equipment:
A. Second North Substation Generator: One Emergency Generator
Engine Rating: 750 hp. Generator Rating: 500 kW.
B. #1 CWT: One Emergency Cooling Water Pump
Engine Rating: 665 hp
C. HDN Substation: One Emergency Generator
Engine Rating: 601 hp. Generator Rating: 400 kW.
D. VGO: One Emergency Generator
Engine Rating: 755 hp (max). Generator Rating: 500 kW.
II.A.32
E. Crude Substation: One Backup Generator
Engine Rating: 900 hp. Generator Rating: 600 kW.
F. Third North Substation: One Backup Emergency Generator
Engine Rating: 1490 lip. Generator Rating: 1,111 kW.
G. Admin Building: One Backup Generator
Engine Rating: 2,220 hp. Generator Rating: 1,250 kW.
H. TCLR: One Backup Generator
Engine Rating:197 hp. Generator Rating: 125 kW.
I. North Tank Field: One Backup Generator
Engine Rating: 896 hp. Generator Rating: 600 kW
ILA.33
J. WWTP: One Backup Generator
Engineer Review N 101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery
November 6. 2024
Page 28
Engine Rating: 896 hp. Generator Rating 600 kW
K. Alky: One Emergency Generator
Engine Rating: 752 hp. Generator Rating: 500 kW.
L. Boiler Plant: Two Compressors
Engine Rating: 524 hp each
M. Collection Box: One Backup Pump
Engine Rating: 109 lip
N. FCC MCC: One Emergency Generator
Engine Rating: 895 lip. Generator Rating: 600 kW
0. Three Fire Water Pumps
Engine Rating: 950 hp (maximum design at 2100 rpm) each.
II.A.34
P. One Canal Fire Water Emergency Generator
Engine Rating: 462 hp. Generator Rating: 300 kW
Q. One Reformer Substation Emergency Generator
Engine Rating: 616 hp. Generator Rating: 400 kW
11.A.35
Natural gas-powered backup equipment
A. One Emergency Generator
Engine Rating: 50 hp. Generator Rating: 30 kW
II.B.8.a
The owner/operator shall not operate each emergency engine, back-up pump or fire engine on site
for more than 100 hours per calendar year during non-emergency situations. There is no time limit
on the use of the engines during emergencies.
[40 CFR 63 Subpart ZZZZ, R307-401-8]
II.B.8.a.1
To determine compliance with the above annual total, the owner/operator shall calculate a new 12-
month total by the 20th day of each month using data from the previous 12 months. Records
documenting the operation of each emergency engine shall be kept in a log and shall include the
following:
a. The date the equipment was used.
b. The duration of operation in hours.
c. The reason for the equipment usage.
[40 CFR 63 Subpart ZZZZ, R307-401-8]
II.B.8.c
The following engines qualif' under 40 CFR 63.6590(c) Stationary RICE subject to Regulations
under 40 CFR Part 60 Subpart 1111:
1. North tank field generator: one backup generator. Engine Rating: 896 hp. Generator Rating: 600
kW.
2. TCLR generator: backup generator. Engine rating 197 hp. Generator Rating 125 kW.
3. WWTP: One Backup Generator. Engine Rating 896 hp. Generator Rating 600 kW.
Engineer Review NIOI 190107: Chevron Products Co - SL Refinery- Salt Lake Refinery
November 6. 2024
Page 29
4. Collection box backup pump: one pump. Engine rating: 109 hp.
5. One canal fire water emergency generator. Engine Rating: 462 hp. Generator Rating: 300 kW.
These engines must meet the requirements of 40 CFR 63 Subpart ZZZZ, by meeting the
requirements of4O CFR 60 Subpart 1111. The requirements are listed at §60.4211(a), (c), (f, and (g).
These engines are not subject to any additional requirements of 40 CFR 63 Subpart ZZZZ.
[40 CFR 60 Subpart 1111,40 CFR 63 Subpart ZZZZ]
[Last updated November 6, 2024]
2. Comment regarding administrative change to stack height:
On August 26, 2024, Chevron informed UDAQ that it was increasing the stack height on the VGO
Furnace Stack. This will extend the stack length from 80 feet to 122 feet and will increase the
furnace flue gas exit elevation from 125 feet above grade to 167 feet above grade.
There are no changes to the burners, no increase in fuel gas firing capacity, and no change in the
PTE of any pollutant as a result of this project. This project also does not trigger a modification or
reconstruction of the furnace as defined in 40 CFR 60 Subpart A or 40 CFR 63 Subpart A.
Chevron anticipates that this change will allow the furnace to demonstrate negative pressure when
operating as intended. This will eliminate air leakage and ensure the safety of refinery personnel near
the furnace. As the stack height of the VGO Furnace is not specifically listed in the conditions of
Chevron's AO, no changes in the conditions of the AO are required.
[Last updated November 6, 2024]
Comment regarding administrative amendment:
The changes outlined in this combined permitting project represent administrative changes not
subject to the regular permitting pathway outlined in R307-401-5 through R307-401-8. No public
notice or comment is required for this change. Chevron has completed the changes outlined in this
project and notified UDAQ as per the requirements ofR307-401-12 - Reduction in Air Pollutants.
[Last updated November 6, 2024]
Engineer Review N 101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery
November 6. 2024
Page 30
ACRONYMS
The following lists commonly used acronyms and associated translations as they apply to this
document:
40 CFR Title 40 of the Code of Federal Regulations
AO Approval Order
BACT Best Available Control Technology
CAA Clean Air Act
CAAA Clean Air Act Amendments
CDS Classification Data System (used by EPA to classify sources by size/type)
CEM Continuous emissions monitor
CEMS Continuous emissions monitoring system
CFR Code of Federal Regulations
CMS Continuous monitoring system
CO Carbon monoxide
CO2 Carbon Dioxide
CO2e Carbon Dioxide Equivalent -40 CFR Part 98, Subpart A, Table A-I
COM Continuous opacity monitor
DAQ/UDAQ Division of Air Quality
DAQE This is a document tracking code for internal UDAQ use
EPA Environmental Protection Agency
FDCP Fugitive dust control plan
GHG Greenhouse Gas(es) -40 CFR 52.21 (b)(49)(i)
GWP Global Warming Potential -40 CFR Part 86.1818-12(a)
HAP or HAPs Hazardous air pollutant(s)
ITA Intent to Approve
LB/HR Pounds per hour
LB/YR Pounds per year
MACT Maximum Achievable Control Technology
MMBTU Million British Thermal Units
NAA Nonattainment Area
NAAQS National Ambient Air Quality Standards
NESHAP National Emission Standards for Hazardous Air Pollutants
NOI Notice of Intent
NO Oxides of nitrogen
NSPS New Source Performance Standard
NSR New Source Review
PM1o Particulate matter less than 10 microns in size
PM25 Particulate matter less than 2.5 microns in size
PSD Prevention of Significant Deterioration
PTE Potential to Emit
R307 Rules Series 307
R307-401 Rules Series 307 - Section 401
SO2 Sulfur dioxide
Title IV Title IV of the Clean Air Act
Title V Title V of the Clean Air Act
TPY Tons per year
UAC Utah Administrative Code
VOC Volatile organic compounds
Engineer Review NIOI 190107: Chevron Products Co - SL Refinery- Salt Lake Refinery
November 6, 2024
Page 31
DAQE-

RN101190107 November 6, 2024 Lauren Vander Werff
Chevron Products Company - Salt Lake Refinery 685 S Chevron Way North Salt Lake, UT 84054
[e-mail] Dear Lauren Vander Werff,
Re: Engineer Review: Administrative Amendment to DAQE-AN101190106-22 for Corrections to Listed Equipment and an Increase in Stack Height Project Number: N101190107 Please review and sign this letter and attached Engineer Review (ER) within 10 business days. For this document to be considered as the application for a Title V administrative amendment, a Title V Responsible Official must sign the next page. Please contact John Jenks at [phone] if you have any questions or concerns about the ER. If you
accept the contents of this ER, please email this signed cover letter to John Jenks at [e-mail]. After receipt of the signed cover letter, the DAQ will prepare an Approval Order (AO) for signature by the DAQ Director. If Chevron Products Company - Salt Lake Refinery does not respond to this letter within 10 business days, the project will move forward without your approval. If you have concerns that we cannot resolve,
the DAQ Director may issue an Order prohibiting construction. Approval Signature _____________________________________________________________
(Signature & Date)
195 North 1950 West • Salt Lake City, UT
Mailing Address: P.O. Box 144820 • Salt Lake City, UT 84114-4820
Telephone [phone] • Fax [phone] • T.D.D. [phone]
www.deq.utah.gov
Printed on 100% recycled paper
Department of Environmental Quality
Kimberly D. Shelley Executive Director DIVISION OF AIR QUALITY Bryce C. Bird Director
State of Utah
SPENCER J. COX Governor DEIDRE HENDERSON Lieutenant Governor

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 1
OPTIONAL: In order for this Engineer Review and associated Approval Order conditions to be considered as an application to administratively amend your Title V Permit, the Responsible Official, as
defined in R307-415-3, must sign the statement below. THIS IS STRICTLY OPTIONAL. If you do not want the Engineer Review to be considered as an application to administratively amend your Operating Permit only the approval signature above is required. Failure to have the Responsible Official sign below will not delay the Approval Order, but will require submittal of a separate Operating Permit Application to revise the Title V permit in accordance with R307-415-5a through 5e and R307-415-7a through 7i. A guidance document: Title V Operating Permit Application Due Dates clarifies the required due dates for Title V operating permit applications and can be viewed at:
https://deq.utah.gov/air-quality/permitting-guidance-and-guidelines-air-quality “Based on information and belief formed after reasonable inquiry, I certify that the statements and information provided for this Approval Order are true, accurate and complete and request that this Approval Order be considered as an application to administratively amend the Operating Permit.” Responsible Official _________________________________________________ (Signature & Date) Print Name of Responsible Official _____________________________________

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 2
UTAH DIVISION OF AIR QUALITY
ENGINEER REVIEW

SOURCE INFORMATION
Project Number N101190107 Owner Name Chevron Products Company - Salt Lake Refinery
Mailing Address 685 S Chevron Way North Salt Lake, UT, 84054
Source Name Chevron Products Co - SL Refinery- Salt Lake Refinery Source Location: 685 S Chevron Way
North Salt Lake, UT 84054 UTM Projection 422,270 m Easting, 4,519,770 m Northing UTM Datum NAD83 UTM Zone UTM Zone 12 SIC Code 2911 (Petroleum Refining) Source Contact Evan Hunter Phone Number [phone] Email [e-mail]
Billing Contact Lauren Vander Werff Phone Number [phone] Email [e-mail]
Project Engineer John Jenks, Engineer Phone Number [phone]
Email [e-mail] Notice of Intent (NOI) Submitted April 17, 2024 Date of Accepted Application August 26, 2024

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 3
SOURCE DESCRIPTION General Description
Chevron Refinery is a petroleum refinery with a nominal capacity of approximately 50,000 barrels per day of crude oil. The source consists of one fluidized catalytic cracking unit (FCCU), a delayed coking unit, a catalytic reforming unit, hydrotreating units and two sulfur recovery
units. The source also has assorted heaters, boilers, cooling towers, storage tanks, flares, and similar fugitive emissions. The refinery operates with a flare gas recovery system on two of its three hydrocarbon flares. NSR Classification: Administrative Amendment Source Classification Located in , Northern Wasatch Front O3 NAA, Salt Lake City UT PM2.5 NAA, Davis County Airs Source Size: A
Applicable Federal Standards NSPS (Part 60), A: General Provisions
NSPS (Part 60), Db: Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units NSPS (Part 60), J: Standards of Performance for Petroleum Refineries
NSPS (Part 60), Ja: Standards of Performance for Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007 NSPS (Part 60), K: Standards of Performance for Storage Vessels for Petroleum Liquids for Which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and Prior to May 19, 1978 NSPS (Part 60), Ka: Standards of Performance for Storage Vessels for Petroleum Liquids for
Which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and Prior to July 23, 1984 NSPS (Part 60), Kb: Standards of Performance for Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984 NSPS (Part 60), GGGa: Standards of Performance for Equipment Leaks of VOC in Petroleum Refineries for Which Construction, Reconstruction, or Modification Commenced After November 7, 2006
NSPS (Part 60), QQQ: Standards of Performance for VOC Emissions From Petroleum Refinery Wastewater Systems NSPS (Part 60), IIII: Standards of Performance for Stationary Compression Ignition Internal
Combustion Engines NSPS (Part 60), JJJJ: Standards of Performance for Stationary Spark Ignition Internal Combustion Engines
NESHAP (Part 61), A: General Provisions NESHAP (Part 61), M: National Emission Standard for Asbestos NESHAP (Part 61), FF: National Emission Standard for Benzene Waste Operations
MACT (Part 63), A: General Provisions MACT (Part 63), CC: National Emission Standards for Hazardous Air Pollutants From Petroleum Refineries MACT (Part 63), UUU: National Emission Standards for Hazardous Air Pollutants for

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 4
Petroleum Refineries: Catalytic Cracking Units, Catalytic Reforming Units, and Sulfur Recovery Units
MACT (Part 63), EEEE: National Emission Standards for Hazardous Air Pollutants: Organic Liquids Distribution (Non-Gasoline) MACT (Part 63), ZZZZ: National Emissions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines MACT (Part 63), DDDDD: National Emission Standards for Hazardous Air Pollutants for Major Sources: Industrial, Commercial, and Institutional Boilers and Process Heaters MACT (Part 63), GGGGG: National Emission Standards for Hazardous Air Pollutants: Site Remediation Title V (Part 70) Major Source Project Proposal
Administrative Amendment to DAQE-AN101190106-22 for Corrections to Listed Equipment and an Increase in Stack Height
Project Description Chevron Products Company (Chevron) requested several minor changes in their current AO as the result of a self-audit. Multiple engine/generators have either been removed from service or
have power ratings which differ from the equipment list. These will be updated to match existing operations. There is no expected increase in potential emissions as a result of this update. In addition, the stack on the F-66100 VGO Furnace will be extended to allow the unit to operate at negative pressure. This will prevent leakage and ensure the safety of refinery personnel. No changes in firing rate or emissions are anticipated. These changes will not constitute a modification to the equipment or processes covered under existing AO DAQE-AN101190106-22. EMISSION IMPACT ANALYSIS
There is no change in emissions as a result of this project. The project is not subject to modeling under R307-410-4 or R307-410-5. [Last updated October 8, 2024]

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 5
SUMMARY OF EMISSIONS
The emissions listed below are an estimate of the total potential emissions from the source. Some rounding of emissions is possible.
Criteria Pollutant Change (TPY) Total (TPY) CO2 Equivalent -16.27 988782.67 Carbon Monoxide -0.50 990.60
Nitrogen Oxides -2.93 763.57
Particulate Matter - PM10 -0.03 260.95
Particulate Matter - PM2.5 -0.03 109.97
Sulfur Dioxide 0 383.30
Volatile Organic Compounds -0.17 1241.89 Hazardous Air Pollutant Change (lbs/yr) Total (lbs/yr)
Acetaldehyde (CAS #75070) -4 165
Acrolein (CAS #107028) 0 239
Ethyl Benzene (CAS #100414) 0 225
Formaldehyde (CAS #50000) -6 1034
Generic HAPs (CAS #GHAPS) -9 254 Hexane (CAS #110543) 0 25309 Xylenes (Isomers And Mixture) (CAS #1330207) -2 350
Change (TPY) Total (TPY)
Total HAPs -0.01 13.79

Note: Change in emissions indicates the difference between previous AO and proposed modification.

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 6
Review of BACT for New/Modified Emission Units 1. BACT review regarding no review of BACT required
Chevron is updating the listed power ratings of some emergency engines, delisting equipment which has been removed from service, and increasing the stack height on the F-66100 VGO Furnace. None of these changes require a revisiting of BACT. The installed equipment meets the
control requirements and methodologies selected during the initial permitting process. Equipment being removed from service is not subject to review. The change in stack height on the VGO Furnace does not constitute a physical change or change in the method of operation of the VGO Furnace, nor does it trigger a modification under the definitions of 40 CFR 60 Subpart A, or
40 CFR 63 Subpart A. [Last updated November 6, 2024]

SECTION I: GENERAL PROVISIONS
The intent is to issue an air quality AO authorizing the project with the following recommended conditions and that failure to comply with any of the conditions may constitute a violation of the AO. (New or Modified conditions are indicated as “New” in the Outline Label):
I.1 All definitions, terms, abbreviations, and references used in this AO conform to those used in
the UAC R307 and 40 CFR. Unless noted otherwise, references cited in these AO conditions refer to those rules. [R307-101]
I.2 The limits set forth in this AO shall not be exceeded without prior approval. [R307-401]
I.3 Modifications to the equipment or processes approved by this AO that could affect the
emissions covered by this AO must be reviewed and approved. [R307-401-1] I.4 All records referenced in this AO or in other applicable rules, which are required to be kept by the owner/operator, shall be made available to the Director or Director's representative upon
request, and the records shall include the two-year period prior to the date of the request. Unless otherwise specified in this AO or in other applicable state and federal rules, records shall be kept for a minimum of five (5) years. [R307-401-8]

I.5 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 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 Director 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. [R307-401-4]

I.6 The owner/operator shall comply with UAC R307-107. General Requirements: Breakdowns. [R307-107]

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 7
I.7 The owner/operator shall comply with UAC R307-150 Series. Emission Inventories. [R307-150]

SECTION II: PERMITTED EQUIPMENT
The intent is to issue an air quality AO authorizing the project with the following recommended
conditions and that failure to comply with any of the conditions may constitute a violation of the AO. (New or Modified conditions are indicated as “New” in the Outline Label): II.A THE APPROVED EQUIPMENT II.A.1 Main Refinery Chevron Salt Lake Refinery
II.A.2 F-11005 Boiler #11005 (Boiler #5) Rating:171 MMBtu/hr Control: Low-NOx
II.A.3 F-11006 Boiler #11006 (Boiler #6) Rating: 171 MMBtu/hr Control: Low-NOx
II.A.4 F-11007 Boiler #11007 (Boiler #7) Rating: 225 MMBtu/hr Control: Low-NOx and FGR II.A.5 16001 Cooling Tower #16001

II.A.6 16002 Cooling Tower #16002 II.A.7 16003 Cooling Tower #16003

II.A.8 16004 Cooling Tower #16004 (Grandfathered)
II.A.9 F-21001 Crude Unit Furnace #F-21001 Rating: 130 MMBtu/hr Control: Low-NOx

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 8
II.A.10 F-21002 Crude Unit Furnace #F-21002 Rating: 115.1 MMBtu/hr
Control: Low-NOx II.A.11 F-32021 FCC Furnace F-32021 Rating: 48.2 MMBtu/hr
II.A.12 F-32023 FCC Furnace F-32023 Rating: 48.2 MMBtu/hr
II.A.13 F-71010 HDN Furnace F-71010 Rating: 15.6 MMBtu/hr

II.A.14 F-71030 HDN Furnace F-71030 Rating: 36.3 MMBtu/hr
II.A.15 F-35001 Reformer Furnace F-35001 Rating: 52.3 MMBtu/hr
II.A.16 F-35002
Reformer Furnace F-35002 Rating: 45 MMBtu/hr
II.A.17 F-35003
Reformer Furnace F-35003 Rating: 31.7 MMBtu/hr
II.A.18 Alkylation Unit Includes: Alkylation Furnace F-36017 Rating: 108 MMBtu/hr Control: Low-NOx
II.A.19 F-70001
Coker Furnace F-70001 Rating: 139.2 MMBtu/hr
II.A.20 F-64010
HDS Furnace F-64010 Rating: 19 MMBtu/hr Control: Low-NOx

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 9
II.A.21 F-64011 HDS Furnace F-64011 Rating: 27.3 MMBtu/hr
Control: Low-NOx II.A.22 F-66100 VGO Furnace F-66100 Rating: 40 MMBtu/hr Control: Low-NOx II.A.23 F-66200 VGO Furnace F-66200 Rating: 66 MMBtu/hr Control: Low-NOx
II.A.24 SRU/TGTU/TGI #1
SRU and Tail Gas Incinerator #1 II.A.25 SRU/TGTU/TGI #2 SRU and Tail Gas Incinerator #2
II.A.26 Catalyst Regenerator FCCU and Catalyst Regenerator II.A.27 F61312 Flameless Thermal Oxidizer

II.A.28 Coker Flare (Flare #1) Coker Flare (Control/Safety Device)
II.A.29 FCCU Flare (Flare #2) FCCU Flare (Control/Safety Device)

II.A.30 Alkylation Flare (Flare #3) Alkylation Flare (Control/Safety Device)
II.A.31 Diesel-powered back-up equipment: A. Second North Substation Generator: One Emergency Generator Engine Rating: 750 hp. Generator Rating: 500 kW. B. #1 CWT: One Emergency Cooling Water Pump Engine Rating: 665 hp C. HDN Substation: One Emergency Generator Engine Rating: 601 hp. Generator Rating: 400 kW.
D. VGO: One Emergency Generator Engine Rating: 755 hp (max). Generator Rating: 500 kW.

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 10
II.A.32 E. Crude Substation: One Backup Generator Engine Rating: 900 hp. Generator Rating: 600 kW. F. Third North Substation: One Backup Emergency Generator Engine Rating: 1490 hp Generator Rating: 1,111 kW. G. Admin Building: One Backup Generator Engine Rating: 2,220 hp. Generator Rating: 1,250 kW.
H. TCLR: One Backup Generator Engine Rating:197 hp. Generator Rating: 125 kW.
I. North Tank Field: One Backup Generator
Engine Rating: 896 hp. Generator Rating: 600 kW.
II.A.33 J. WWTP: One Backup Generator Engine Rating: 896 hp. Generator Rating 600 kW. K. Alky: One Emergency Generator Engine Rating: 752 hp. Generator Rating: 500 kW. L. Boiler Plant: Two Compressors Engine Rating: 524 hp each M. Collection Box: One Backup Pump Engine Rating: 109 hp
N. FCC MCC: One Emergency Generator Engine Rating: 895 hp. Generator Rating: 600 kW
O. Three Fire Water Pumps
Engine Rating: 950 hp (maximum design at 2100 rpm) each. II.A.34 P. One Canal Fire Water Emergency Generator Engine Rating: 462 hp. Generator Rating: 300 kW.
Q. One Reformer Substation Emergency Generator Engine Rating: 616 hp. Generator Rating: 400 kW.
II.A.35 Natural gas-powered backup equipment A. One Emergency Generator Engine Rating: 50 hp. Generator Rating: 30 kW.
II.A.36 K35001, K35002, K35003 Three Reformer Compressor Drivers Rating: 16 MMBtu/hr each
Fuel: Refinery Fuel Gas

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 11
II.A.37 Amine Unit #1 Amine Unit #1
II.A.38 Amine Unit #2 Amine Unit #2
II.A.39 K36067 Lime Loading Facility K36067
II.A.40 FCC Fines Bin

SECTION II: SPECIAL PROVISIONS
The intent is to issue an air quality AO authorizing the project with the following recommended conditions and that failure to comply with any of the conditions may constitute a violation of the
AO. (New or Modified conditions are indicated as “New” in the Outline Label): II.B REQUIREMENTS AND LIMITATIONS
II.B.1 Source-wide Requirements
II.B.1.a Except as otherwise stated in this AO, the owner/operator shall use only plant gas or purchased natural gas as a primary fuel. Plant Coke may be burned in the FCC Catalyst Regenerator. Torch oil may be burned in the FCC Catalyst Regenerator to assist in starting, restarting, hot standby, or to maintain regenerator heat balance. If any other fuel is to be used, an AO shall be required. [Consent Decree, R307-401] II.B.1.b All petroleum refineries in or affecting any PM2.5 nonattainment area or any PM10 nonattainment or maintenance area shall reduce the H2S content of the refinery plant gas to 60 ppm or less as described in 40 CFR 60.102a. Compliance shall be based on a rolling average of 365 days. The owner/operator shall comply with the fuel gas monitoring requirements of 40 CFR 60.107a and the related recordkeeping and reporting requirements of 40 CFR 60.108a. As used herein, refinery "plant gas" shall have the meaning of "fuel gas" as defined in 40 CFR 60.101a, and may be used interchangeably. For natural gas, compliance is assumed while the fuel comes from a public utility. [SIP Section IX.H.11.g.ii]

II.B.1.c No petroleum refineries in or affecting any PM2.5 nonattainment area or PM10 nonattainment or maintenance area shall be allowed to burn liquid fuel oil in stationary sources except during natural gas curtailments or as specified below:
A. The use of diesel fuel meeting the specifications of 40 CFR 80.510 in standby or emergency equipment is exempt from the limitation above and is allowed in standby or emergency equipment at all times. B. Plant coke may be burned in the FCC Catalyst Regenerator. [R307-401-8(1)(a), SIP Section IX.H.11.g.vii, SIP Section IX.H.12.d.iv]

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 12
II.B.1.d The owner/operator shall not allow visible emissions to exceed the opacity limits set in R307-309. [R307-309]
II.B.1.e The owner/operator shall ensure for all stack testing performed: The owner/operator 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 Director shall be held at
least 30 days prior to the test if directed by the Director. 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. 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.
Where appropriate, the following test methods shall be used, although other EPA-approved
test methods acceptable to the Director can be substituted and approved through the pre-test protocol: Volumetric flow rate - 40 CFR 60, Appendix A, Method 2 SO2 emissions - 40 CFR 60, Appendix A, Method 6C
NOx emissions - 40 CFR 60, Appendix A, Method 7E
PM10 and PM2.5 emissions - 40 CFR 51, Appendix M, Methods 201a and 202
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 Director to give the results in the specified units of the emission limitation. [R307-401]

II.B.1.f Source-wide combined emissions of PM10 shall not exceed 0.715 tons per day (tpd). [SIP Section IX.H.2.d.i]

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 13
II.B.1.f.1 Compliance with the source-wide PM10 Cap shall be determined for each day as follows:
A. Total 24-hour PM10 emissions for the emission points shall be calculated by adding the
daily results of the PM10 emissions equations listed below for natural gas, plant gas, and fuel oil combustion. These emissions shall be added to the emissions from the cooling towers, and the FCCU to arrive at a combined daily PM10 emission total.
B. For purposes of this subsection a "day" is defined as a period of 24-hours commencing at
midnight and ending at the following midnight. C. Daily natural gas and plant gas consumption shall be determined through the use of flow meters. D. Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that supply combustion sources. E. The equation used to determine emissions for the boilers and furnaces shall be as follows: Emission Factor (lb/MMscf) * Gas Consumption (MMscf/24 hrs)/(2,000 lb/ton)
F. Results shall be tabulated for each day, and records shall be kept which include the meter readings (in the appropriate units) and the calculated emissions. [SIP Section IX.H.2.d.i.C]
II.B.1.f.2 The emission factors derived from the most current performance test shall be applied to the relevant quantities of fuel combusted. Unless adjusted by performance testing, the default emission factors to be used are as follows:
A. Natural gas: Filterable PM10: 1.9 lb/MMscf Condensable PM10: 5.7 lb/MMscf B. Plant gas: Filterable PM10: 1.9 lb/MMscf Condensable PM10: 5.7 lb/MMscf
C. Diesel fuel: shall be determined from the latest edition of AP-42 or other EPA approved
methods.
D. Cooling Towers: shall be determined from the latest edition of AP-42 or other EPA approved methods. E. FCC Stack: The PM10 emission factors shall be based on the most recent stack test and verified by parametric monitoring. F. Where mixtures of fuel are used in a Unit, the above factors shall be weighted according to the use of each fuel. [SIP Section IX.H.2.d.i.A]

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II.B.1.f.3 The default emission factors listed above apply until such time as stack testing is conducted.
Initial PM10 stack testing on the FCC stack has been performed and shall be conducted at least
once every three (3) years from the date of the last stack test. Stack testing shall be performed as outlined in Condition II.B.1.e. [SIP Section IX.H.2.d.i.B] II.B.1.g Source-wide combined emissions of PM2.5 (filterable+condensable) shall not exceed 0.305 tons per day (tpd) and 110 tons per rolling 12-month period. [SIP Section IX.H.12.d.i]
II.B.1.g.1 Compliance with the source-wide PM2.5 Cap shall be determined for each day as follows:
A. Total 24-hour PM2.5 emissions for the emission points shall be calculated by adding the daily results of the PM2.5 emissions equations listed below for natural gas, plant gas, and fuel oil combustion. These emissions shall be added to the emissions from the FCCU to arrive at a combined daily PM2.5 emission total.
B. For purposes of this subsection a "day" is defined as a period of 24-hours commencing at midnight and ending at the following midnight.
C. Daily natural gas and plant gas consumption shall be determined through the use of flow
meters. D. Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that supply combustion sources. E. The equation used to determine emissions for the boilers and furnaces shall be as follows: Emissions = Emission Factor (lb/MMscf) * Gas Consumption (MMscf/24 hrs)/(2,000 lb/ton)
F. Results shall be tabulated for each day, and records shall be kept which include the meter readings (in the appropriate units) and the calculated emissions. [SIP Section IX.H.12.d.i.C]

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II.B.1.g.2 The emission factors derived from the most current performance test shall be applied to the relevant quantities of fuel combusted. Unless adjusted by performance testing, the default emission factors to be used are as follows:
A. Natural gas: Filterable PM2.5: 1.9 lb/MMscf Condensable PM2.5: 5.7 lb/MMscf B. Plant gas: Filterable PM2.5: 1.9 lb/MMscf Condensable PM2.5: 5.7 lb/MMscf
C. Diesel fuel: shall be determined from the latest edition of AP-42 or other EPA approved
methods.
D. FCC Stack: The PM2.5 emission factors shall be based on the most recent stack test and verified by parametric monitoring. E. Where mixtures of fuel are used in a Unit, the above factors shall be weighted according to the use of each fuel. [SIP Section IX.H.12.d.i.A]
II.B.1.g.3 The default emission factors listed above apply until such time as stack testing is conducted. Initial PM2.5 stack testing on the FCC stack has been performed and shall be conducted at least once every three (3) years from the date of the last stack test.
Stack testing shall be performed as outlined in Condition II.B.1.e. [SIP Section IX.H.12.d.i.B]
II.B.1.h Source-wide combined emissions of NOx shall not exceed 2.1 tons per day (tpd) and 766.5 tons per rolling 12-month period. [SIP Section IX.H.12.d.ii]

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II.B.1.h.1 Compliance with the source-wide NOx Cap shall be determined for each day as follows:
A. Total 24-hour NOx emissions shall be calculated by adding the emissions for each emitting
unit. B. The emissions for each emitting unit shall be calculated by multiplying the hours of operation of a unit, feed rate to a unit, or quantity of each fuel combusted at each affected unit by the associated emission factor, and summing the results.
C. A NOx CEM shall be used to calculate daily NOx emissions from the FCCU. D. A NOx CEM shall be used to calculate daily NOx emissions from Boiler #7 E. For purposes of this subsection a "day" is defined as a period of 24-hours commencing at midnight and ending at the following midnight. F. Daily natural gas and plant gas consumption shall be determined through the use of flow meters.
G. Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that
supply combustion sources.
H. Results shall be tabulated for each day, and records shall be kept which include the meter readings (in the appropriate units) and the calculated emissions. [SIP Section IX.H.12.d.ii.C] II.B.1.h.2 The emission factors derived from the most current performance test shall be applied to the relevant quantities of fuel combusted. Unless adjusted by performance testing, the default
emission factors to be used are as follows: A. Natural gas: shall be determined from the latest edition of AP-42 or other EPA approved methods. B. Plant gas: shall be assumed equal to natural gas C. Alkylation polymer: shall be determined from the latest edition of AP-42 (as fuel oil #6) or other EPA approved methods. D. Diesel fuel: shall be determined from the latest edition of AP-42 or other EPA approved methods. E. Where mixtures of fuel are used in a Unit, the above factors shall be weighted according to the use of each fuel. [SIP Section IX.H.12.d.ii.A]

II.B.1.h.3 The default emission factors listed above apply until such time as stack testing is conducted.
Initial NOx stack testing on natural gas/refinery fuel gas combustion equipment above 100 MMBtu/hr has been performed and shall be conducted at least once every three (3) years from the date of the last stack test. At that time a new flow-weighted average emission factor in terms of: lbs/MMbtu shall be derived for each combustion type listed above.
Stack testing shall be performed as outlined in Condition II.B.1.e. [SIP Section IX.H.12.d.ii.B]

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II.B.1.i Source-wide combined emissions of SO2 shall not exceed 1.05 tons per day (tpd) and 383.3 tons per rolling 12-month period. [SIP Section IX.H.12.d.iii]
II.B.1.i.1 Compliance with the source-wide SO2 Cap shall be determined for each day as follows: A. Total daily SO2 emissions shall be calculated by adding the daily SO2 emissions for natural gas and plant fuel gas combustion, to those from the FCC and SRU stacks.
B. Daily natural gas and plant gas consumption shall be determined through the use of flow meters.
C. Daily fuel oil consumption shall be monitored by means of leveling gauges on all tanks that supply combustion sources.
D. Results shall be tabulated for each day, and records shall be kept which include CEM readings for H2S (averaged for each one-hour period), all meter readings (in the appropriate units), fuel oil parameters (density and wt% sulfur for each day any fuel oil is burned), and the calculated emissions.
E. For purposes of this subsection a "day" is defined as a period of 24-hours commencing at midnight and ending at the following midnight. [SIP Section IX.H.12.d.iii.B] II.B.1.i.2 The emission factors derived from the most current performance test shall be applied to the relevant quantities of fuel combusted. The default emission factors to be used are as follows:
A. FCCU: The emission rate shall be determined by the FCC SO2 CEM.
B. SRUs: The emission rate shall be determined by multiplying the sulfur dioxide concentration in the flue gas by the flow rate of the flue gas. The sulfur dioxide concentration in the flue gas shall be determined by CEM. C. Natural gas: EF = 0.60 lb/MMscf
D. Fuel oil: The emission factor to be used for combustion shall be calculated based on the weight percent of sulfur, as determined by ASTM Method D-4294-89 or EPA approved equivalent acceptable to the Director, 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)
E. Plant gas: the emission factor shall be calculated from the H2S measurement obtained from
the H2S CEM.
F. Where mixtures of fuel are used in a Unit, the above factors shall be weighted according to the use of each fuel. [SIP Section IX.H.12.d.iii.A] II.B.2 Conditions on Boiler #11005 (Boiler #5)

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II.B.2.a NOx emissions shall not exceed the following rate on a 30-day rolling average basis: [NSPS Db §60.44b(b) and §60.44b(i)] En = ((0.1 x Hgo) + (0.2 x Hr)) / (Hgo + Hr) Where: En = NOx emission limit (lb/MMbtu) Hgo = 30-day heat input from combustion of natural gas or distillate oil
Hr = 30-day heat input from combustion of any other fuel. [ 40 CFR 60 Subpart Db] II.B.2.a.1 The NOx emission rate shall be predicted based on excess O2 in the flue gas and by boiler loading as specified in a plan submitted to and approved by the Director [NSPS Db §60.48b(g)(2)]. Predicted NOx emission rate shall be evaluated at least every three (3) years through testing as outlined in Condition II.B.1.e. [40 CFR 60 Subpart Db]
II.B.3 Conditions on Boiler #11006 (Boiler #6) II.B.3.a NOx emissions shall not exceed the following rate on a 30-day rolling average basis: [NSPS Db §60.44b(b) and §60.44b(i)]
En = ((0.1 x Hgo) + (0.2 x Hr)) / (Hgo + Hr) Where: En = NOx emission limit (lb/MMbtu)
Hgo = 30-day heat input from combustion of natural gas or distillate oil Hr = 30-day heat input from combustion of any other fuel. [ 40 CFR 60 Subpart Db]
II.B.3.a.1 The NOx emission rate shall be predicted based on excess O2 in the flue gas and by boiler
loading as specified in a plan submitted to and approved by the Director [NSPS Db §60.48b(g)(2)]. Predicted NOx emission rate shall be evaluated at least every three (3) years through testing as outlined in Condition II.B.1.e. [40 CFR 60 Subpart Db]

II.B.4 Conditions on the SRUs
II.B.4.a All petroleum refineries in or affecting any PM2.5 nonattainment area or any PM10 nonattainment or maintenance area shall require:
A. Sulfur removal units/plants (SRUs) that are at least 95% effective in removing sulfur from the streams fed to the unit; or B. SRUs that meet the SO2 emission limitations listed in 40 CFR 60.102a(f)(1) or 60.102a(f)(2) as appropriate. [SIP Section IX.H.1.g.iii.A]
II.B.4.b The owner/operator shall process amine acid gas and sour water stripper acid gas in the
SRU(s). [SIP Section IX.H.1.g.iii.B] II.B.4.b.1 Compliance shall be demonstrated by daily monitoring of flows to the SRU(s). Compliance shall be determined on a rolling 30-day average. [SIP Section IX.H.1.g.iii.C]

II.B.5 Conditions on SRU and Tail Gas Treatment Unit #1
II.B.5.a Emissions of SO2 from SRU #1 shall not exceed 0.242 tons/day. [R307-401]

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II.B.5.a.1 Daily sulfur dioxide emissions 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 CEM 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 evaluation shall be performed within 30 days of installation. The performance evaluation shall be conducted and data reduced in accordance with the methods and procedures contained in 40 CFR 60, Appendix B: Performance Specification 2. Notification must be made to the Director prior to conducting the performance evaluation. 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 evaluation shall be performed within 30 days of installation. The performance evaluation 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 Director prior to conducting the performance evaluation. 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. [R307-401]

II.B.5.b Emissions of SO2 from SRU #1 shall not exceed 88.5 tons/yr. [R307-401]
II.B.5.b.1 Compliance shall be determined on a 12-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 11
months' emission totals to give the new 12-month rolling total. [R307-401] II.B.5.c The owner/operator shall continue to route or re-route all sulfur pit emissions so that they are eliminated, controlled, or included and monitored as part of the SRU's emissions subject to the
emissions limits of II.B.5. [Consent Decree] II.B.6 Conditions on SRU and Tail Gas Treatment Unit #2
II.B.6.a Emissions of SO2 from SRU #2 shall not exceed 0.268 tons/day. [R307-401]

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II.B.6.a.1 Daily sulfur dioxide emissions 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 CEM 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 evaluation shall be performed within 30 days of installation. The performance evaluation shall be conducted and data reduced in accordance with the methods and procedures contained in 40 CFR 60, Appendix B: Performance Specification 2. Notification must be made to the Director prior to conducting the performance evaluation. 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 evaluation shall be performed within 30 days of installation. The performance evaluation 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 Director prior to conducting the performance evaluation. 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. [R307-401]

II.B.6.b Emissions of SO2 from SRU #2 shall not exceed 97.7 tons/yr. [R307-401]
II.B.6.b.1 Compliance shall be determined on a 12-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 11
months' emission totals to give the new 12-month rolling total. [R307-401] II.B.6.c The owner/operator shall continue to route or re-route all sulfur pit emissions so that they are eliminated, controlled, or included and monitored as part of the SRU's emissions subject to the
emissions limits of II.B.6. [Consent Decree] II.B.7 Conditions on the FCC and Catalyst Regenerator

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II.B.7.a Emissions of SO2 from the FCCU Regenerator Vent shall not exceed the following rates and concentrations: A. 25 ppmvd SO2 @ 0% O2 on a 365-day rolling average B. 50 ppmvd SO2 @ 0% O2 on a 7-day rolling average
C. 50 tons of SO2 on a 12-month rolling average
D. 0.28 tons of SO2 per day.
SO2 emissions during periods of Startup, Shutdown, or Malfunction shall not be used in determining compliance with the emission limit of 50 ppmvd SO2 @ 0% O2 on a 7-day rolling average basis. The SO2 short-term limit listed in B. above shall exclude FCCU feed hydrotreater outages if Chevron complies with an EPA-approved hydrotreater outage plan and is maintaining and operating the FCCU in a manner consistent with good air pollution control practices. It shall apply at all other times the FCCU is in operation. In addition, in the event that the source asserts that the basis for a specific Hydrotreater Outage is a shutdown (where no catalyst changeout occurs) required by ASME pressure vessel requirements or applicable state boiler requirements, the source shall submit a report to EPA
that identifies the relevant requirements and justifies the permittee's decision to implement the shutdown during the selected time period. [Consent Decree, R307-401]

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II.B.7.a.1 The SO2 emission factor for the FCC and Catalyst Regenerator shall be determined by continuous emission monitor. The regenerator flow rate calculation established in 40 CFR 63 Subpart UUU (MACT UUU) shall be used in conjunction for this calculation.
For continuous emission monitor calculations the monitor shall be operated, maintained, certified, and calibrated in accordance with R307-170, UAC. The provisions of 40 C.F.R. § 60.13 that are applicable to CEMS (excluding those provisions applicable only to Continuous Opacity Monitoring Systems) and Part 60 Appendices A and F, and the applicable performance specification test of 40 C.F.R. Part 60 Appendix B are applicable to the FCC/Catalyst Regenerator CEM. With respect to 40 C.F.R. Part 60, Appendix F, Chevron must conduct either a Relative Accuracy Audit ("RAA") or a Relative Accuracy Test Audit ("RATA") on each CEMS at least once every one (1) year. The source must also conduct Cylinder Gas Audits ("CGA") each calendar quarter during which a RAA or a RATA is not performed. With respect to the O2 CEMS, in lieu of the audit points specified in 40 C.F.R. Part
60, Appendix F § 5.1.2., the source may audit the O2 CEMS at 20-30% and 50-60% of the actual O2 CEMS span value. If a new monitor is installed, an initial performance evaluation shall be performed within 30 days of installation. The performance evaluation 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 Director 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. For the stack test calculations to establish the FCC and Catalyst Regenerator SO2 emission factor, the owner/operator shall determine mass emission rates (lbs/hr, etc.) as follows:
The pollutant concentration, as determined by the appropriate methods, shall be multiplied by the volumetric flow rate and any necessary conversion factors as determined by the Director.
The owner/operator 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. [R307-170]
II.B.7.b Emissions of NOx from the FCCU Regenerator Vent shall not exceed the following rates:
A. 100 tons of NOx per year on a rolling 12-month basis
B. 0.55 tons per day
C. 57.8 ppmvd @ 0% O2 on a 365-day rolling average D. 106.3 ppmvd @ 0% O2 on a 7-day rolling average The NOx long-term limit listed in C. above shall apply at all times the FCCU is in operation. The NOx short-term limit listed in D. above shall exclude periods of startup, shutdown, and malfunction. It shall also exclude FCCU feed hydrotreater outage if the owner/operator complies with an EPA-approved hydrotreater outage plan. It shall apply at all other times the FCCU is in operation. [R307-401]

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II.B.7.b.1 The NOx emission factor for the FCC and Catalyst Regenerator shall be determined by continuous emission monitor. The regenerator flow rate calculation established in 40 CFR 63 Subpart UUU (MACT UUU) shall be used in conjunction for this calculation.
For continuous emission monitor calculations, the monitor shall be operated, maintained, calibrated, and certified in accordance with R307-170, UAC and the provisions of 40 C.F.R. § 60.13 that are applicable to CEMS (excluding those provisions applicable only to Continuous Opacity Monitoring Systems) and Part 60 Appendices A and F, and the applicable performance specification test of 40 C.F.R. Part 60 Appendix B. With respect to 40 C.F.R. Part 60, Appendix F, Chevron must conduct either a Relative Accuracy Audit ("RAA") or a Relative Accuracy Test Audit ("RATA") on each CEMS at least once every one (1) year. The source must also conduct Cylinder Gas Audits ("CGA") each calendar quarter during which a RAA or a RATA is not performed. With respect to the O2 CEMS, in lieu of the audit points specified in 40 C.F.R. Part 60, Appendix F § 5.1.2., the source may audit the O2 CEMS at 20-
30% and 50-60% of the actual O2 CEMS span value. If a new monitor is installed, an initial performance evaluation shall be performed within 30 days of installation. The performance evaluation 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 Director 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. For stack test calculations, mass emission rates (lbs/hr, etc.), the pollutant concentration, as determined by the appropriate methods, shall be multiplied by the volumetric flow rate and any necessary conversion factors as determined by the Director to establish the FCC and
Catalyst Regenerator NOx emission factor.
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. [R307-170]
II.B.7.c Emissions of CO from the FCCU shall not exceed 500 ppmvd at 0% O2 on a 1-hour average basis. CO emissions during periods of startup, shutdown or malfunction shall not be used when determining compliance with this emission limit. [R307-401-8]
II.B.7.c.1 The source shall use CO and O2 CEMS to monitor compliance with the CO emission limit for the FCCU and Catalyst Regenerator. The source shall install, certify, maintain, and operate the CEMS in accordance with the provisions of 40 C.F.R. § 60.13 that are applicable to CEMS
(excluding those provisions applicable only to Continuous Opacity Monitoring Systems) and Part 60 Appendices A and F, and the applicable performance specification test of 40 C.F.R. Part 60 Appendix B. With respect to 40 C.F.R. Part 60, Appendix F, Chevron must conduct
either a Relative Accuracy Audit ("RAA") or a Relative Accuracy Test Audit ("RATA") on each CEMS at least once every one (1) year. The source must also conduct Cylinder Gas Audits ("CGA") each calendar quarter during which a RAA or a RATA is not performed. With respect to the O2 CEMS, in lieu of the audit points specified in 40 C.F.R. Part 60, Appendix F § 5.1.2., the source may audit the O2 CEMS at 20-30% and 50-60% of the actual O2 CEMS span value. [R307-170]

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II.B.7.d The owner or operator of an FCCU shall comply with an emission limit of 1.0 pounds PM per 1000 pounds coke burn-off. [SIP Section IX.H.11.g.i.B.I]
II.B.7.d.1 Compliance with this limit shall be determined by following the stack test protocol specified in 40 C.F.R. §60.106(b) to measure PM emissions on the FCCU. Each owner/operator shall conduct stack tests once every three (3) years at each FCCU. [SIP Section IX.H.11.g.i.B.II] II.B.7.e Each owner or operator of an FCCU subject to NSPS Ja shall install, operate and maintain a continuous parameter monitor system (CPMS) to measure and record operating parameters
from the FCCU and control devices as per the requirements of 40 CFR 60.105a(b)(1). Each owner or operator of an FCCU not subject to NSPS Ja shall install, operate and maintain a continuous opacity monitoring system to measure and record opacity from the FCCU as per the requirements of 40 CFR 63.1572(b) and comply with the opacity limitation as per the requirements of Table 7 to Subpart UUU of Part 63. [SIP Section IX.H.11.g.i.B.III]
II.B.7.f Opacity from the FCCU and Catalyst Regenerator shall be monitored by a continuous opacity monitoring system ("COMS"). The source shall install, certify, calibrate, maintain, and operate the COMS in accordance with 40 C.F.R. §§ 60.11, 60.13 and Part 60 Appendix A, and the applicable performance specification test of 40 C.F.R. Part 60 Appendix B. [Consent Decree]
II.B.8 Conditions on Miscellaneous Diesel-fired Equipment
II.B.8.a NEW The owner/operator shall not operate each emergency engine, back-up pump or fire engine on site for more than 100 hours per calendar year during non-emergency situations. There is no time limit on the use of the engines during emergencies. [40 CFR 63 Subpart ZZZZ, R307-401-8]
II.B.8.a.1
NEW
To determine compliance with the above annual total, the owner/operator shall calculate a new
12-month total by the 20th day of each month using data from the previous 12 months. Records documenting the operation of each emergency engine shall be kept in a log and shall include the following:
a. The date the equipment was used
b. The duration of operation in hours c. The reason for the equipment usage. [40 CFR 63 Subpart ZZZZ, R307-401-8]
II.B.8.a.2 To determine the duration of operation, the owner/operator shall install a non-resettable hour
meter for each emergency engine. [R307-401-8, 40 CFR 63 Subpart ZZZZ]
II.B.8.b The owner/operator shall only use diesel fuel (e.g. fuel oil #1, #2, or diesel fuel oil additives) as fuel in each emergency engine. [R307-401-8]
II.B.8.b.1 The owner/operator shall only combust diesel fuel that meets the definition of ultra-low sulfur
diesel (ULSD), which has a sulfur content of 15 ppm or less. [R307-401-8]

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II.B.8.b.2 To demonstrate compliance with the ULSD fuel requirement, the owner/operator shall maintain records of diesel fuel purchase invoices or obtain certification of sulfur content from the diesel fuel supplier. The diesel fuel purchase invoices shall indicate that the diesel fuel
meets the ULSD requirements. [R307-401-8] II.B.8.c NEW The following engines qualify under 40 CFR 63.6590(c) Stationary RICE subject to regulations under 40 CFR Part 60 Subpart IIII: 1. North tank field generator: one backup generator. Engine Rating: 896 hp. Generator Rating: 600 kW. 2. TCLR generator: backup generator. Engine rating 197 hp. Generator Rating 125 kW. 3. WWTP: One Backup Generator. Engine Rating 896 hp. Generator Rating 600 kW. 4. Collection box backup pump: one pump. Engine rating: 109 hp. 5. One canal fire water emergency generator. Engine Rating: 462 hp. Generator Rating: 300
kW.
These engines must meet the requirements of 40 CFR 63 Subpart ZZZZ, by meeting the requirements of 40 CFR 60 Subpart IIII. The requirements are listed at §60.4211(a), (c), (f), and (g). These engines are not subject to any additional requirements of 40 CFR 63 Subpart ZZZZ. [40 CFR 60 Subpart IIII, 40 CFR 63 Subpart ZZZZ]
II.B.9 Conditions on Reformer Compressor Engines
II.B.9.a Emissions of NOx and CO at the three listed reformer compressors shall not exceed the following concentration limits: K35001: 236 ppmvd NOx, 834 ppmvd CO K35002: 208 ppmvd NOx, 926 ppmvd CO K35003: 230 ppmvd NOx, 556 ppmvd CO. [R307-401-8(1)(a)]

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II.B.9.a.1 Demonstrating Compliance with Emission Limits a. Beginning no later than one (1) year after the Emission Limits Tests and every two (2) years thereafter, the owner/operator shall perform emission tests to demonstrate compliance
with the emission limits established for the reformer compressor engines. The tests shall be conducted on each engine and shall be the average of three (3) one-hour tests on each engine. The tests shall be conducted, and the emissions shall be calculated, in accordance with 40
CFR § 60.4244.
b. The owner/operator shall continuously measure and record the catalyst inlet temperature data in according to 40 CFR § 63.6625(b); reduce these data to 4-hour rolling averages, and maintain the 4-hour rolling averages within the operating limitations for the catalyst inlet temperature, except for periods of startup, shutdown, and malfunction, as those terms are defined in 40 CFR § 60.2. c. The owner/operator shall measure and record the pressure drop across each catalyst bed once per month. The owner/operator shall maintain each catalyst bed so that the pressure drop across each catalyst is within the operating limitation established during the Emission Limits Tests. d. The owner/operator shall replace the O2 sensor on each reformer compressor engine in accordance with the vendor-recommended preventative maintenance schedule. Following each O2 sensor replacement, the owner/operator shall measure NOx and CO emissions once using a portable analyzer to determine the adequate set point of the AFRC to maintain operation of the reformer compressor engine near stoichiometric conditions. The owner/operator shall maintain records documenting sensor replacement and portable analyzer
results. [R307-150] II.B.10 Miscellaneous SIP Conditions II.B.10.a The owner or operator shall comply with the requirements of 40 CFR 63.654 for heat exchange systems in VOC service. The owner or operator may elect to use another EPA-approved method other than the Modified El Paso Method if approved by the Director.
The following applies in lieu of 40 CFR 63.654(b): A heat exchange system is exempt from
the requirements in paragraphs 63.654(c) through (g) of this section if it meets any one of the criteria in the following paragraphs (1) through (2) of this section. 1. All heat exchangers that are in VOC service within the heat exchange system that either: a. Operate with the minimum pressure on the cooling water side at least 35 kilopascals greater than the maximum pressure on the process side; or b. Employ an intervening cooling fluid, containing less than 10 percent by weight of VOCs, between the process and the cooling water. This intervening fluid must serve to isolate the
cooling water from the process fluid and must not be sent through a cooling tower or discharged. For purposes of this section, discharge does not include emptying for maintenance purposes.
2. The heat exchange system cools process fluids that contain less than 10 percent by weight
VOCs (i.e., the heat exchange system does not contain any heat exchangers that are in VOC service). [SIP Section IX.H.11.g.iii.A]

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 27
II.B.10.b For leak detection and repair, the owner/operator shall comply with the following:
A. The owner/operator shall comply with the requirements of 40 CFR 60.590a to 60.593a
B. For units complying with the Sustainable Skip Period, previous process unit monitoring results may be used to determine the initial skip period interval provided that each valve has been monitored using the 500 ppm leak definition. [SIP Section IX.H.11.g.iv]
II.B.10.c The owner/operator shall not allow any stationary tank of 40,000-gallon or greater capacity and containing or last containing any organic liquid, with a true vapor pressure equal or greater than 10.5 kPa (1.52 psia) at storage temperature (see R307-324-4(1)) to be opened to the atmosphere unless the emissions are controlled by exhausting VOCs contained in the tank vapor-space to a vapor control device until the organic vapor concentration is 10 percent or less of the lower explosion limit (LEL). These degassing provisions shall not apply while connecting or disconnecting degassing equipment. [SIP Section IX.H.11.g.vi]
II.B.10.c.1 The Director shall be notified of the intent to degas any tank subject to the rule. Except in an
emergency situation, initial notification shall be submitted at least three (3) days prior to degassing operations. The initial notification shall include: A. Start date and time;
B. Tank owner, address, tank location, and applicable tank permit numbers; C. Degassing operator's name, contact person, and telephone number; D. Tank capacity, volume of space to be degassed, and materials stored; E. Description of vapor control device. [SIP Section IX.H.11.g.vi.C] II.B.10.d All hydrocarbon flares at petroleum refineries located in or affecting a PM2.5 nonattainment area or any PM10 nonattainment or maintenance area shall be subject to the flaring
requirements of NSPS Subpart Ja (40 CFR 60.100a-109a), if not already subject under the flare applicability provisions of Ja. [SIP Section IX.H.11.g.v.A]
II.B.10.d.1 The owner/operator shall either:
1) install and operate a flare gas recovery system designed to limit hydrocarbon flaring produced from each affected flare during normal operations to levels below the values listed in 40 CFR 60.103a(c), or 2) limit flaring during normal operations to 500,000 scfd for each affected flare.
Flare gas recovery is not required for dedicated SRU flare and header systems, or HF flare and header systems. [SIP Section IX.H.11.g.v.B]

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 28
PERMIT HISTORY When issued, the approval order shall supersede (if a modification) or will be based on the
following documents: Is Derived From Source Submitted NOI dated April 17, 2024
Incorporates Additional Information Received dated May 21, 2024 Incorporates Additional Information Received dated August 26, 2024 Supersedes DAQE-AN101190106-22 dated August 24, 2022
REVIEWER COMMENTS
1. Comment regarding changes in equipment (April and May NOIs): Chevron's first set of requested changes are outlined in Table B.1 of the April 17, 2024 R307-401-12 notification. Chevron's second set of requested changes are outlined in Table B.1 of the May 21, 2024 notification. These changes result in the following updates in the equipment list and conditions of section II.B: II.A.31 Diesel-powered back-up equipment: A. Second North Substation Generator: One Emergency Generator
Engine Rating: 750 hp. Generator Rating: 500 kW. B. #1 CWT: One Emergency Cooling Water Pump Engine Rating: 665 hp C. HDN Substation: One Emergency Generator Engine Rating: 601 hp. Generator Rating: 400 kW. D. VGO: One Emergency Generator Engine Rating: 755 hp (max). Generator Rating: 500 kW.
II.A.32 E. Crude Substation: One Backup Generator Engine Rating: 900 hp. Generator Rating: 600 kW. F. Third North Substation: One Backup Emergency Generator Engine Rating: 1490 hp. Generator Rating: 1,111 kW. G. Admin Building: One Backup Generator Engine Rating: 2,220 hp. Generator Rating: 1,250 kW.
H. TCLR: One Backup Generator Engine Rating:197 hp. Generator Rating: 125 kW.
I. North Tank Field: One Backup Generator Engine Rating: 896 hp. Generator Rating: 600 kW II.A.33 J. WWTP: One Backup Generator

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 29
Engine Rating: 896 hp. Generator Rating 600 kW K. Alky: One Emergency Generator Engine Rating: 752 hp. Generator Rating: 500 kW. L. Boiler Plant: Two Compressors Engine Rating: 524 hp each
M. Collection Box: One Backup Pump
Engine Rating: 109 hp
N. FCC MCC: One Emergency Generator Engine Rating: 895 hp. Generator Rating: 600 kW O. Three Fire Water Pumps Engine Rating: 950 hp (maximum design at 2100 rpm) each. II.A.34 P. One Canal Fire Water Emergency Generator
Engine Rating: 462 hp. Generator Rating: 300 kW
Q. One Reformer Substation Emergency Generator Engine Rating: 616 hp. Generator Rating: 400 kW II.A.35 Natural gas-powered backup equipment A. One Emergency Generator Engine Rating: 50 hp. Generator Rating: 30 kW
II.B.8.a The owner/operator shall not operate each emergency engine, back-up pump or fire engine on site for more than 100 hours per calendar year during non-emergency situations. There is no time limit
on the use of the engines during emergencies. [40 CFR 63 Subpart ZZZZ, R307-401-8] II.B.8.a.1 To determine compliance with the above annual total, the owner/operator shall calculate a new 12-month total by the 20th day of each month using data from the previous 12 months. Records documenting the operation of each emergency engine shall be kept in a log and shall include the following:
a. The date the equipment was used. b. The duration of operation in hours. c. The reason for the equipment usage.
[40 CFR 63 Subpart ZZZZ, R307-401-8]
II.B.8.c The following engines qualify under 40 CFR 63.6590(c) Stationary RICE subject to Regulations under 40 CFR Part 60 Subpart IIII: 1. North tank field generator: one backup generator. Engine Rating: 896 hp. Generator Rating: 600 kW. 2. TCLR generator: backup generator. Engine rating 197 hp. Generator Rating 125 kW.
3. WWTP: One Backup Generator. Engine Rating 896 hp. Generator Rating 600 kW.

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 30
4. Collection box backup pump: one pump. Engine rating: 109 hp. 5. One canal fire water emergency generator. Engine Rating: 462 hp. Generator Rating: 300 kW.
These engines must meet the requirements of 40 CFR 63 Subpart ZZZZ, by meeting the requirements of 40 CFR 60 Subpart IIII. The requirements are listed at §60.4211(a), (c), (f), and (g). These engines are not subject to any additional requirements of 40 CFR 63 Subpart ZZZZ. [40 CFR 60 Subpart IIII, 40 CFR 63 Subpart ZZZZ]
[Last updated November 6, 2024] 2. Comment regarding administrative change to stack height: On August 26, 2024, Chevron informed UDAQ that it was increasing the stack height on the VGO Furnace Stack. This will extend the stack length from 80 feet to 122 feet and will increase the furnace flue gas exit elevation from 125 feet above grade to 167 feet above grade.
There are no changes to the burners, no increase in fuel gas firing capacity, and no change in the PTE of any pollutant as a result of this project. This project also does not trigger a modification or reconstruction of the furnace as defined in 40 CFR 60 Subpart A or 40 CFR 63 Subpart A.
Chevron anticipates that this change will allow the furnace to demonstrate negative pressure when
operating as intended. This will eliminate air leakage and ensure the safety of refinery personnel near the furnace. As the stack height of the VGO Furnace is not specifically listed in the conditions of Chevron's AO, no changes in the conditions of the AO are required. [Last updated November 6, 2024] 3. Comment regarding administrative amendment:
The changes outlined in this combined permitting project represent administrative changes not subject to the regular permitting pathway outlined in R307-401-5 through R307-401-8. No public notice or comment is required for this change. Chevron has completed the changes outlined in this project and notified UDAQ as per the requirements of R307-401-12 - Reduction in Air Pollutants. [Last updated November 6, 2024]

Engineer Review N101190107: Chevron Products Co - SL Refinery- Salt Lake Refinery November 6, 2024 Page 31
ACRONYMS The following lists commonly used acronyms and associated translations as they apply to this document:
40 CFR Title 40 of the Code of Federal Regulations AO Approval Order BACT Best Available Control Technology
CAA Clean Air Act CAAA Clean Air Act Amendments CDS Classification Data System (used by EPA to classify sources by size/type) CEM Continuous emissions monitor CEMS Continuous emissions monitoring system CFR Code of Federal Regulations CMS Continuous monitoring system CO Carbon monoxide CO2 Carbon Dioxide CO2e Carbon Dioxide Equivalent - 40 CFR Part 98, Subpart A, Table A-1 COM Continuous opacity monitor
DAQ/UDAQ Division of Air Quality DAQE This is a document tracking code for internal UDAQ use EPA Environmental Protection Agency
FDCP Fugitive dust control plan GHG Greenhouse Gas(es) - 40 CFR 52.21 (b)(49)(i) GWP Global Warming Potential - 40 CFR Part 86.1818-12(a)
HAP or HAPs Hazardous air pollutant(s) ITA Intent to Approve LB/HR Pounds per hour
LB/YR Pounds per year MACT Maximum Achievable Control Technology MMBTU Million British Thermal Units
NAA Nonattainment Area NAAQS National Ambient Air Quality Standards NESHAP National Emission Standards for Hazardous Air Pollutants NOI Notice of Intent NOx Oxides of nitrogen NSPS New Source Performance Standard NSR New Source Review PM10 Particulate matter less than 10 microns in size
PM2.5 Particulate matter less than 2.5 microns in size PSD Prevention of Significant Deterioration PTE Potential to Emit
R307 Rules Series 307 R307-401 Rules Series 307 - Section 401 SO2 Sulfur dioxide
Title IV Title IV of the Clean Air Act Title V Title V of the Clean Air Act TPY Tons per year
UAC Utah Administrative Code VOC Volatile organic compounds
Review of Engineer Review RN101190107-24
Calculations for Change of Potential Emissions for Criteria Pollutants
Pre-Project Project Total Post-Project
Criteria Pollutant Total (TPY) Change (TPY) Total (TPY)
CO2 Equivalent 988798.94 -16.27 988782.67
Carbon Monoxide 991.1 -0.50 990.60
Nitrogen Oxides 766.5 -2.93 763.57
Particulate Matter - PM10 260.98 -0.03 260.95
Particulate Matter - PM2.5 110 -0.03 109.97
Sulfur Dioxide 383.3 0.00 383.30
Volatile Organic Compounds 1242.06 -0.17 1241.89
Note:
All calculations from project changes obtained from "Potential Emissions Summary" section of the R307-401-12 submittals that were submitted to
UDAQ.
Project Total Change (tpy) =
Emissions Change from "2024 WWTP Engine/Generator Reauthorization Permitting" (tpy) +
Project Change from "2024 Engine/Generator Reauthorization Permitting" (tpy)
Chevron Products Company - Salt Lake Refinery
2024 WWTP Engine/Generator Reauthorization Permitting
Potential Emissions Summary
Obtained from R307-401-12 submittal dated April 17, 2024
Potential Emissions for Permitted Engines (tpy)
Engine Description NOX SO2 CO PM PM10 PM2.5 VOC H2SO4 GHGs (as
CO2e)
Permitted Fire Water Pump #1 1.15E-01 2.28E-04 1.07E-01 6.20E-03 5.10E-03 4.95E-03 9.30E-03 0.00E+00 2.14E+01
Permitted WWTP Eng/Gen 7.40E-01 3.74E-04 3.47E-02 1.77E-03 1.77E-03 1.77E-03 2.18E-02 0.00E+00 3.58E+01
Total Emissions for Permitted Engines 8.55E-01 6.02E-04 1.42E-01 7.97E-03 6.87E-03 6.71E-03 3.11E-02 0.00E+00 5.72E+01
Potential Emissions at Reauthorized Engines (tpy)
Engine Description NOX SO2 CO PM PM10 PM2.5 VOC H2SO4 GHGs (as
CO2e)
Updated WWTP Eng/Gen 5.16E-01 5.44E-04 2.96E-02 5.38E-03 4.79E-03 4.70E-03 1.38E-02 0.00E+00 5.11E+01
Total Emissions for Reauthorized Engine 5.16E-01 5.44E-04 2.96E-02 5.38E-03 4.79E-03 4.70E-03 1.38E-02 0.00E+00 5.11E+01
Project Summary (tpy)
Engine Description NOX SO2 CO PM PM10 PM2.5 VOC H2SO4 GHGs (as
CO2e)
Total Emissions for Permitted Engines 8.55E-01 6.02E-04 1.42E-01 7.97E-03 6.87E-03 6.71E-03 3.11E-02 0.00E+00 5.72E+01
Total Emissions for Reauthorized Engine 5.16E-01 5.44E-04 2.96E-02 5.38E-03 4.79E-03 4.70E-03 1.38E-02 0.00E+00 5.11E+01
Emissions Change -3.39E-01 -5.82E-05 -1.13E-01 -2.59E-03 -2.08E-03 -2.01E-03 -1.73E-02 0.00E+00 -6.10E+00
Emissions Increase/Reduction?Reduction Reduction Reduction Reduction Reduction Reduction Reduction No Change Reduction
Project Change (tpy) = Total Emissions for Reauthorized Engine (tpy) - Total Emissions for Permitted Engines (tpy)
Chevron Products Company - Salt Lake Refinery
2024 Engine/Generator Reauthorization Permitting
Potential Emissions Summary
Obtained from R307-401-12 submittal dated May 21,2024
Potential Emissions for Permitted Engines (tpy)
Engine Description NOX SO2 CO PM PM10 PM2.5 VOC H2SO4 GHGs (as
CO2e)
Permitted Canal Firewater Engs/Pumps (3)0.92 0.00 0.11 0.01 0.01 0.01 0.07 0.00 131.55
Permitted Canal Firewater Eng/Gen 0.57 0.00 0.02 0.00 0.00 0.00 0.05 0.00 21.22
Permitted #1 CWT CW Pump Engine 0.20 0.00 0.03 0.01 0.01 0.01 0.00 0.00 36.86
Permitted Crude Sub Eng/Gen 0.98 0.00 0.23 0.02 0.02 0.02 0.03 0.00 47.98
Permitted NTF Eng/Gen 0.80 0.00 0.02 0.00 0.00 0.00 0.02 0.00 38.80
Permitted 2nd North Substation Eng/Gen 0.80 0.00 0.18 0.02 0.02 0.02 0.02 0.00 39.20
Permitted Admin Eng/Gen 0.76 0.00 0.17 0.01 0.01 0.01 0.02 0.00 98.06
Permitted TCLR Eng/Gen 0.08 0.00 0.07 0.00 0.00 0.00 0.01 0.00 9.81
Permitted FCC MCC Eng/Gen 0.46 0.00 0.29 0.01 0.01 0.01 0.11 0.00 46.75
Permitted Reformer Substation Eng/Gen 0.83 0.00 0.03 0.00 0.00 0.00 0.07 0.00 30.82
Permitted Fire Water Pump #2 0.11 0.00 0.11 0.01 0.01 0.00 0.01 0.00 21.94
Permitted HF Mitigation #1 1.00 0.00 0.23 0.03 0.02 0.02 0.03 0.00 48.56Permitted HF Mitigation #2 1.00 0.00 0.23 0.03 0.02 0.02 0.03 0.00 48.56
Total Emissions for Permitted Engines 8.52 0.01 1.71 0.16 0.14 0.13 0.46 0.00 620.10
Potential Emissions at Reauthorized Engines (tpy)
Engine Description NOX SO2 CO PM PM10 PM2.5 VOC H2SO4 GHGs (as
CO2e)
Updated Canal Firewater Engs/Pumps (3)1.16 0.00 0.14 0.03 0.02 0.02 0.06 0.00 166.33
Updated Canal Firewater Eng/Gen 0.20 0.00 0.01 0.00 0.00 0.00 0.02 0.00 26.96
Updated #1 CWT CW Pump Engine 0.21 0.00 0.03 0.01 0.01 0.01 0.00 0.00 38.81
Updated Crude Substation Eng/Gen 1.08 0.00 0.25 0.02 0.02 0.02 0.03 0.00 52.52
Updated NTF Eng/Gen 0.52 0.00 0.03 0.01 0.00 0.00 0.01 0.00 52.29
Updated 2nd North Substation Eng/Gen 0.90 0.00 0.21 0.02 0.02 0.01 0.02 0.00 43.77
Updated Admin Eng/Gen 1.00 0.00 0.22 0.02 0.02 0.02 0.03 0.00 129.56
Updated TCLR Eng/Gen 0.10 0.00 0.08 0.01 0.00 0.00 0.01 0.00 11.50
Updated FCC MCC Eng/Gen 0.52 0.00 0.32 0.01 0.01 0.01 0.12 0.00 52.23
Updated Reformer Eng/Gen 0.26 0.00 0.03 0.00 0.00 0.00 0.00 0.00 35.95
Surrendered Fire Water Pump #2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Surrendered HF Mitigation #1 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Surrendered HF Mitigation #2 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Total Emissions for Reauthorized Engines 5.94 0.01 1.32 0.13 0.11 0.10 0.30 0.00 609.93
Project Summary (tpy)
Engine Description NOX SO2 CO PM PM10 PM2.5 VOC H2SO4 GHGs (as
CO2e)
Total Emissions for Permitted Engines 8.52 0.01 1.71 0.16 0.14 0.13 0.46 0.00 620.10Total Emissions for Reauthorized Engines 5.94 0.01 1.32 0.13 0.11 0.10 0.30 0.00 609.93
Project Change (tpy)-2.59 0.00 -0.38 -0.03 -0.03 -0.03 -0.16 0.00 -10.17
Emissions Increase/Reduction?Reduction Reduction Reduction Reduction Reduction Reduction Reduction No Change Reduction
Project Change (tpy) = Total Emissions for Reauthorized Engines (tpy) - Total Emissions for Permitted Engines (tpy)
Evaluations for "Potential Emissions for Permitted Engines (tpy)" rely on emissions factors provided during initial permitting where applicable.
Review of Engineer Review RN101190107-24
Change of Potential Emissions for Hazardous Air Pollutants
Pre-Project Project Total Post-Project
Hazardous Air Pollutant Total (lbs/yr) Change (lb/yr) Total (lbs/yr)
Acetaldehyde (CAS #75070) 169 -4 165
Acrolein (CAS #107028) 239 0 239
Ethyl Benzene (CAS #100414) 225 0 225
Formaldehyde (CAS #50000) 1040 -6 1034
Generic HAPs (CAS #GHAPS) 263 -9 254
Hexane (CAS #110543) 25309 0 25309
Xylenes (Isomers And Mixture) (CAS
#1330207)352 -2 350
Total (TPY) Change (TPY) Total (TPY)
Total HAPs 13.80 -0.01 13.79
Note:
Refer to details in "Calculations for Change of Potential Emissions for Hazardous Air Pollutants" section.
Review of Engineer Review RN101190107-24
Calculations for Change of Potential Emissions for Hazardous Air Pollutants
Developed based on information submitted in R307-401-12 submittals dated April 17, 2024 and May 21,2024
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1,3-Butadiene 0.00E+00 0.00E+00 1.03E-04 6.32E-06 6.32E-06 6.32E-06 6.32E-06 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 2.70E-06
Acenaphthene 1.47E-06 1.01E-06 3.73E-06 2.30E-07 2.30E-07 2.30E-07 2.30E-07 1.09E-06 1.47E-06 1.47E-06 1.23E-06 3.64E-06 9.79E-08
Acenaphthylene 2.89E-06 1.99E-06 1.33E-05 8.18E-07 8.18E-07 8.18E-07 8.18E-07 2.15E-06 2.91E-06 2.89E-06 2.42E-06 7.17E-06 3.49E-07
Acetaldehyde 7.90E-06 5.44E-06 2.01E-03 1.24E-04 1.24E-04 1.24E-04 1.24E-04 5.87E-06 7.94E-06 7.90E-06 6.62E-06 1.96E-05 5.29E-05
Acrolein 2.47E-06 1.70E-06 2.43E-04 1.50E-05 1.50E-05 1.50E-05 1.50E-05 1.83E-06 2.48E-06 2.47E-06 2.07E-06 6.12E-06 6.38E-06
Anthracene 3.86E-07 2.66E-07 4.91E-06 3.02E-07 3.02E-07 3.02E-07 3.02E-07 2.86E-07 3.87E-07 3.86E-07 3.23E-07 9.56E-07 1.29E-07
Benzene 2.43E-04 1.68E-04 2.45E-03 1.51E-04 1.51E-04 1.51E-04 1.51E-04 1.81E-04 2.44E-04 2.43E-04 2.04E-04 6.03E-04 6.43E-05
Benzo(a)anthracene 1.95E-07 1.34E-07 4.41E-06 2.72E-07 2.72E-07 2.72E-07 2.72E-07 1.45E-07 1.96E-07 1.95E-07 1.63E-07 4.83E-07 1.16E-07
Benzo(a)pyrene 8.06E-08 5.55E-08 4.94E-07 3.04E-08 3.04E-08 3.04E-08 3.04E-08 5.98E-08 8.10E-08 8.06E-08 6.75E-08 2.00E-07 1.30E-08
Benzo(b)fluoranthene 3.48E-07 2.40E-07 2.60E-07 1.60E-08 1.60E-08 1.60E-08 1.60E-08 2.58E-07 3.50E-07 3.48E-07 2.91E-07 8.62E-07 6.83E-09
Benzo(g,h,i)perylene 1.74E-07 1.20E-07 1.28E-06 7.91E-08 7.91E-08 7.91E-08 7.91E-08 1.29E-07 1.75E-07 1.74E-07 1.46E-07 4.32E-07 3.37E-08
Benzo(k)fluoranthene 6.84E-08 4.71E-08 4.07E-07 2.51E-08 2.51E-08 2.51E-08 2.51E-08 5.07E-08 6.87E-08 6.84E-08 5.72E-08 1.69E-07 1.07E-08
Chrysene 4.80E-07 3.30E-07 9.27E-07 5.71E-08 5.71E-08 5.71E-08 5.71E-08 3.56E-07 4.82E-07 4.80E-07 4.02E-07 1.19E-06 2.43E-08
Dibenz(a,h)anthracene 1.09E-07 7.47E-08 1.53E-06 9.43E-08 9.43E-08 9.43E-08 9.43E-08 8.05E-08 1.09E-07 1.09E-07 9.08E-08 2.69E-07 4.02E-08
Fluoranthene 1.26E-06 8.70E-07 2.00E-05 1.23E-06 1.23E-06 1.23E-06 1.23E-06 9.38E-07 1.27E-06 1.26E-06 1.06E-06 3.13E-06 5.25E-07
Fluorene 4.01E-06 2.76E-06 7.67E-05 4.72E-06 4.72E-06 4.72E-06 4.72E-06 2.98E-06 4.03E-06 4.01E-06 3.36E-06 9.95E-06 2.01E-06
Formaldehyde 2.47E-05 1.70E-05 3.10E-03 1.91E-04 1.91E-04 1.91E-04 1.91E-04 1.84E-05 2.49E-05 2.47E-05 2.07E-05 6.13E-05 8.14E-05
Indeno(1,2,3-cd)pyrene 1.30E-07 8.94E-08 9.84E-07 6.06E-08 6.06E-08 6.06E-08 6.06E-08 9.64E-08 1.30E-07 1.30E-07 1.09E-07 3.22E-07 2.59E-08
Naphthalene 4.08E-05 2.81E-05 2.23E-04 1.37E-05 1.37E-05 1.37E-05 1.37E-05 3.03E-05 4.10E-05 4.08E-05 3.41E-05 1.01E-04 5.85E-06
Phenanthrene 1.28E-05 8.81E-06 7.72E-05 4.75E-06 4.75E-06 4.75E-06 4.75E-06 9.50E-06 1.29E-05 1.28E-05 1.07E-05 3.17E-05 2.03E-06
Pyrene 1.16E-06 8.01E-07 1.25E-05 7.73E-07 7.73E-07 7.73E-07 7.73E-07 8.64E-07 1.17E-06 1.16E-06 9.74E-07 2.88E-06 3.30E-07
Toluene 8.81E-05 6.07E-05 1.07E-03 6.61E-05 6.61E-05 6.61E-05 6.61E-05 6.54E-05 8.85E-05 8.81E-05 7.38E-05 2.18E-04 2.82E-05
Xylenes (isomers and mixture)6.05E-05 4.17E-05 7.48E-04 4.61E-05 4.61E-05 4.61E-05 4.61E-05 4.49E-05 6.08E-05 6.05E-05 5.07E-05 1.50E-04 1.97E-05
Total HAP 4.93E-04 3.40E-04 1.02E-02 6.26E-04 6.26E-04 6.26E-04 6.26E-04 3.66E-04 4.96E-04 4.93E-04 4.13E-04 1.22E-03 2.67E-04
Notes:
Values in blue represent potential emissions after reauthorization (post-project).
Values in red represent potential emissions before reauthorization (pre-project). Includes engines that were surrendered as a result of the permitting action.
Project Change (tpy) = Sum of Post-Project Potential Emissions (Blue Cells) - Sum of Pre-Project Potential Emissions (Red Cells)
Calculations for each engine obtained from calculations of potential emissions in R307-401-12 submittals dated April 17, 2024 and May 21, 2024. Refer to those submittals for basis of
potential HAP emissions per engine before and after reauthorization.
Pollutant Name
1,3-Butadiene
Acenaphthene
Acenaphthylene
Acetaldehyde
Acrolein
Anthracene
Benzene
Benzo(a)anthracene
Benzo(a)pyrene
Benzo(b)fluoranthene
Benzo(g,h,i)perylene
Benzo(k)fluoranthene
Chrysene
Dibenz(a,h)anthracene
Fluoranthene
Fluorene
Formaldehyde
Indeno(1,2,3-cd)pyrene
Naphthalene
Phenanthrene
Pyrene
Toluene
Xylenes (isomers and mixture)
Total HAP
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0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 5.05E-06 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 2.29E-06 0.00E+00
1.47E-06 1.01E-06 1.24E-06 1.24E-06 1.24E-06 1.83E-07 1.03E-06 1.34E-06 1.09E-06 1.10E-06 2.75E-06 8.33E-08 1.32E-06
2.89E-06 1.99E-06 2.44E-06 2.44E-06 2.44E-06 6.53E-07 2.04E-06 2.65E-06 2.16E-06 2.16E-06 5.41E-06 2.97E-07 2.60E-06
7.89E-06 5.43E-06 6.66E-06 6.66E-06 6.66E-06 9.91E-05 5.56E-06 7.23E-06 5.89E-06 5.91E-06 1.48E-05 4.50E-05 7.10E-06
2.47E-06 1.70E-06 2.08E-06 2.08E-06 2.08E-06 1.19E-05 1.74E-06 2.26E-06 1.84E-06 1.85E-06 4.62E-06 5.43E-06 2.22E-06
3.85E-07 2.65E-07 3.25E-07 3.25E-07 3.25E-07 2.42E-07 2.71E-07 3.53E-07 2.88E-07 2.88E-07 7.22E-07 1.10E-07 3.47E-07
2.43E-04 1.67E-04 2.05E-04 2.05E-04 2.05E-04 1.20E-04 1.71E-04 2.23E-04 1.81E-04 1.82E-04 4.55E-04 5.47E-05 2.19E-04
1.95E-07 1.34E-07 1.64E-07 1.64E-07 1.64E-07 2.17E-07 1.37E-07 1.79E-07 1.45E-07 1.46E-07 3.65E-07 9.86E-08 1.75E-07
8.05E-08 5.54E-08 6.79E-08 6.79E-08 6.79E-08 2.43E-08 5.67E-08 7.38E-08 6.01E-08 6.03E-08 1.51E-07 1.10E-08 7.24E-08
3.48E-07 2.39E-07 2.93E-07 2.93E-07 2.93E-07 1.28E-08 2.45E-07 3.19E-07 2.60E-07 2.60E-07 6.51E-07 5.81E-09 3.13E-07
1.74E-07 1.20E-07 1.47E-07 1.47E-07 1.47E-07 6.32E-08 1.23E-07 1.60E-07 1.30E-07 1.30E-07 3.26E-07 2.87E-08 1.57E-07
6.83E-08 4.70E-08 5.76E-08 5.76E-08 5.76E-08 2.00E-08 4.81E-08 6.26E-08 5.10E-08 5.11E-08 1.28E-07 9.09E-09 6.14E-08
4.79E-07 3.30E-07 4.04E-07 4.04E-07 4.04E-07 4.56E-08 3.37E-07 4.39E-07 3.58E-07 3.59E-07 8.97E-07 2.07E-08 4.31E-07
1.08E-07 7.46E-08 9.14E-08 9.14E-08 9.14E-08 7.53E-08 7.63E-08 9.93E-08 8.09E-08 8.11E-08 2.03E-07 3.42E-08 9.75E-08
1.26E-06 8.69E-07 1.06E-06 1.06E-06 1.06E-06 9.83E-07 8.89E-07 1.16E-06 9.42E-07 9.45E-07 2.36E-06 4.46E-07 1.14E-06
4.01E-06 2.76E-06 3.38E-06 3.38E-06 3.38E-06 3.77E-06 2.82E-06 3.67E-06 2.99E-06 3.00E-06 7.51E-06 1.71E-06 3.61E-06
2.47E-05 1.70E-05 2.08E-05 2.08E-05 2.08E-05 1.52E-04 1.74E-05 2.26E-05 1.84E-05 1.85E-05 4.63E-05 6.92E-05 2.22E-05
1.30E-07 8.93E-08 1.09E-07 1.09E-07 1.09E-07 4.84E-08 9.13E-08 1.19E-07 9.68E-08 9.71E-08 2.43E-07 2.20E-08 1.17E-07
4.07E-05 2.80E-05 3.44E-05 3.44E-05 3.44E-05 1.10E-05 2.87E-05 3.73E-05 3.04E-05 3.05E-05 7.63E-05 4.97E-06 3.66E-05
1.28E-05 8.80E-06 1.08E-05 1.08E-05 1.08E-05 3.80E-06 9.00E-06 1.17E-05 9.54E-06 9.57E-06 2.39E-05 1.72E-06 1.15E-05
1.16E-06 8.00E-07 9.80E-07 9.80E-07 9.80E-07 6.17E-07 8.18E-07 1.06E-06 8.67E-07 8.70E-07 2.18E-06 2.80E-07 1.05E-06
8.80E-05 6.06E-05 7.43E-05 7.43E-05 7.43E-05 5.28E-05 6.20E-05 8.06E-05 6.57E-05 6.59E-05 1.65E-04 2.40E-05 7.92E-05
6.05E-05 4.16E-05 5.10E-05 5.10E-05 5.10E-05 3.68E-05 4.26E-05 5.54E-05 4.51E-05 4.53E-05 1.13E-04 1.67E-05 5.44E-05
4.93E-04 3.39E-04 4.16E-04 4.16E-04 4.16E-04 5.00E-04 3.47E-04 4.52E-04 3.68E-04 3.69E-04 9.23E-04 2.27E-04 4.43E-04
Pollutant Name
1,3-Butadiene
Acenaphthene
Acenaphthylene
Acetaldehyde
Acrolein
Anthracene
Benzene
Benzo(a)anthracene
Benzo(a)pyrene
Benzo(b)fluoranthene
Benzo(g,h,i)perylene
Benzo(k)fluoranthene
Chrysene
Dibenz(a,h)anthracene
Fluoranthene
Fluorene
Formaldehyde
Indeno(1,2,3-cd)pyrene
Naphthalene
Phenanthrene
Pyrene
Toluene
Xylenes (isomers and mixture)
Total HAP
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7.34E-06 5.13E-06 0.00E+00 0.00E+00 -9.45E-05 0
2.66E-07 1.86E-07 1.36E-06 1.36E-06 -6.66E-06 0
9.49E-07 6.64E-07 2.68E-06 2.68E-06 -1.86E-05 0
1.44E-04 1.01E-04 7.32E-06 7.32E-06 -1.87E-03 -4
1.74E-05 1.21E-05 2.29E-06 2.29E-06 -2.29E-04 0
3.51E-07 2.45E-07 3.57E-07 3.57E-07 -5.37E-06 0
1.75E-04 1.22E-04 2.25E-04 2.25E-04 -2.79E-03 -6
3.15E-07 2.21E-07 1.81E-07 1.81E-07 -4.49E-06 0
3.53E-08 2.47E-08 7.47E-08 7.47E-08 -6.32E-07 0
1.86E-08 1.30E-08 3.22E-07 3.22E-07 -1.01E-06 0
9.17E-08 6.42E-08 1.62E-07 1.62E-07 -1.57E-06 0
2.91E-08 2.03E-08 6.33E-08 6.33E-08 -5.25E-07 0
6.62E-08 4.63E-08 4.44E-07 4.44E-07 -1.91E-06 0
1.09E-07 7.65E-08 1.01E-07 1.01E-07 -1.65E-06 0
1.43E-06 9.99E-07 1.17E-06 1.17E-06 -2.12E-05 0
5.48E-06 3.83E-06 3.72E-06 3.72E-06 -7.94E-05 0
2.21E-04 1.55E-04 2.29E-05 2.29E-05 -2.91E-03 -6
7.04E-08 4.92E-08 1.20E-07 1.20E-07 -1.19E-06 0
1.59E-05 1.11E-05 3.78E-05 3.78E-05 -2.95E-04 -1
5.52E-06 3.86E-06 1.19E-05 1.19E-05 -9.92E-05 0
8.97E-07 6.27E-07 1.08E-06 1.08E-06 -1.41E-05 0
7.67E-05 5.37E-05 8.16E-05 8.16E-05 -1.18E-03 -2
5.35E-05 3.74E-05 5.61E-05 5.61E-05 -8.22E-04 -2
7.27E-04 5.08E-04 4.57E-04 4.57E-04 -1.04E-02 -21
Chevron Troy Tortorich Salt Lake Refinery
Refinery Manager Chevron Products Company
685 South Chevron Way
Salt Lake City, UT 84054
Tel [phone]
Fax [phone]
April 17,2024
Mr. Bryce Bird, Director
Utah Division of Air Quality (UDAQ)
Utah Department of Environmental Quality
P.O. Box 144820
195 North 1950 West
Salt Lake City, UT 84114-4820
Attention: NSR Section
Submitted Electronically via NSR NO! Submittal Portal
RE: Chevron Products Company, Salt Lake Refinery - DAQE-AN101190106-22
Utah Rule R307-401-12 Reduction in Air Pollutants
2024 WWTP Engine/Generator Reauthorization Project
Dear Mr. Bird:
Chevron Products Company (Chevron) is proposing to replace authorization of two stationary engines
with authorization of one engine at the Salt Lake Refinery (refinery). Chevron is regulated by two (2)
active Approval Orders (AO): DAQE-ANIOI 190106-22 (dated August 24, 2022, referred to herein as
"refinery AO") and DAQE-AN 101190104-22 (dated September 26, 2022, identified for informational
purposes only). The purpose of this submittal is to meet the notification requirements in R307-401-12(2)
and request an administrative update to the refinery AO.
The project includes authorization of the following emergency backup equipment (referred to as
"reauthorized engine"):
" One backup diesel-fired engine/generator package to be referred to as the "New Wastewater
Treatment Plant (WWTP) Engine Generator. Engine Rating: 896 hp. Generator Rating: 600 kW.
The following emergency backup equipment (collectively referred to as "permitted engines") will no
longer be authorized or operated:
" One of the two engines from Condition 11.A.31 of the refinery AO: "Two Fire Water Emergency
Backup Pumps Rating: 375 hp (cont.) 400 hp (max) each." After completion of the project, only
one of the two engines will be authorized.
" From Condition ll.A.32 of the refinery AO: "WWTP: One Backup Generator *NEW*. Rating:
617 hp (400 kW)." This includes a 617 hp diesel-fired engine which drives a 400 kW generator.
Chevron identified that a recently purchased engine generator package does not align with the equipment
authorized as part of the refinery AO. The permitting package submitted on January 27, 2022 requested
authorization of a WWTP engine generator (617 hp engine to drive a 400 kW generator). Chevron
learned that a larger WWTP engine generator was ordered (896 hp engine to drive a 600 kW generator)
and placed in a temporary staging area. Chevron submitted notification to UDAQ of these issues on
February 2, 2024. This submittal will constitute reauthorization of the larger engine and is effective upon
submittal as identified in greater detail below.
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