DAQ-2025-002472

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DAQC-437-25
Site ID 10119 (B1)

MEMORANDUM

TO: FILE – CHEVRON PRODUCTS COMPANY – Salt Lake Refinery

THROUGH: Harold Burge, Major Source Compliance Manager

FROM: Joe Rockwell, Environmental Scientist

DATE: May 5, 2025

SUBJECT: PARTIAL COMPLIANCE EVALAUATION (PCE #4 of #4) – Main Refinery – Major,
Davis County, FRS # UT0000004901100003

INSPECTION DATE: April 22-24, 2025
SOURCE LOCATION: 2351 North 1100 West, North Salt Lake, Utah

MAILING ADDRESS: 685 S Chevron Way, North Salt Lake, Utah 84054

SOURCE CONTACTS: Lauren Vander Werff, Environmental Team Lead, 801-539-7386
[e-mail]
OPERATING STATUS: Operating

PROCESS DESCRIPTION:

Chevron Refinery produces propane, jet fuel, gasoline, and diesel fuel at this facility. Crude oil is received
at the plant by pipeline and stored in storage tanks. From the storage tanks, the crude oil is sent through a
desalter and then heated in the crude unit heater. The crude oil is then separated into fractions in the
distillation tower and vacuum tower. These fractions of oil are further refined through physical, thermal,
catalytic, and chemical processes.

The liquid propane gas (LPG) and gasoline are sent to the Gas Recovery Unit which further separates the
streams. The gasoline is sent to storage tanks and the LPG is further processed through the Ionic Liquid
Alkylation Unit and then onto propane storage tanks.

Jet fuel and diesel fuel are transferred from the fractionation column and sent directly to storage tanks.
Some diesel fuel is processed through the Hydrodesulfurization Unit (HDS) to remove additional sulfur
components.

Gas oil from the vacuum column is fed to the Fluid Catalytic Cracker (FCC Unit) which exposes the
product to a catalyst that further breaks down the heavy gas oil into more marketable products such as
gasoline, jet fuel, and diesel fuel.

Residual oil from the bottom of the distillation tower is fed to the Coker Unit. The Coker Unit heats the
bottom oil to very high temperatures and then fractionates the products in a distillation tower and
produces coke which is sold by rail car.
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The following is a brief description of the main process equipment operated at the Chevron Refinery:

Crude Unit:

Crude oil is heated in furnaces and sent through an atmospheric distillation column for separation. The
"bottoms" from the atmospheric column feed a vacuum distillation unit for further fractionation. Process
streams are either sent directly to product storage or sent to other units for further processing.

Fluid Catalytic Cracker (FCC) Unit:

Oil is received from the Crude Unit vacuum column and is heated in two furnaces. The oil is heated to
high temperatures and exposed to a catalyst that "cracks" the oil into smaller hydrocarbon chains. After
the cracking process, the oil is separated into fractions and sent to product storage or onto other units for
further processing. The FCC is equipped with a catalyst regenerator which burns off the coke deposited
onto the catalyst during the cracking process. Emissions from the unit are routed through cyclones and an
electrostatic precipitator and then discharged to the atmosphere through the CO boiler stack.

Reformer Unit:

Low octane hydrocarbons are sent through a series of furnaces and catalytic reactors to form higher
octane molecules for blending into gasoline. The gas stream is sent through a distillation tower for
separation after leaving the reformer.

Isomerization Unit:

Butane is exposed to a catalyst to produce isobutane which is required in the alkylation process.

Alkylation Unit:

Isobutane and propylene or butene is exposed to a catalyst (Ionic Liquid). The reaction produces several
blending components of motor gasoline.

Coker Unit:

The "heavy" oil from the Crude Unit vacuum column and FCC are heated, fractionated in a distillation
tower, and "cracked" into coke. Any product recovered by the fractionation and cracking process is sent
through other units for further processing or to product storage tanks. The remaining product is a solid
coke product which is formed in the large coke vessels. The coke is removed from the vessels with a high
pressure water drill and stored on train cars until it is shipped to the customer.

Hydrodenitrification (HDN) and Hydrodesulfurization (HDS) Units:

Liquid feed from the coker and diesel fuel are fed to these units where they are exposed to a catalyst and
hydrogen gas. This exposure creates a chemical reaction that separates the nitrogen and sulfur products
from the feed stream. The sulfur and mitrogen form hydrogen sulfide (H2S) and ammonia (NH3) rich
streams which are fed to the Amine unit and sour water stripper for processing.

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Amine Unit:

Sour gas from all process units are combined and exposed to amine which absorbs the hydrogen sulfide
from the fuel gas. The hydrogen sulfide is then stripped off of the amine with steam and sent to the Sulfur
Recovery Unit for processing. The sweet gas (contains little or no hydrogen sulfide (H2S)) is sent back to
the V-113 mixing drum and used as plant gas.

Sour Water Stripper:

Water streams containing ammonia and hydrogen sulfide are sent through a packed column tower where
high pressure steam strips the ammonia and hydrogen sulfide from the water streams. The ammonia and
hydrogen sulfide are sent to the Sulfur Recovery Unit for processing and the water stream is sent to the
Wastewater Treatment Plant.

Sulfur Recovery Units (SRU):

The ammonia and hydrogen sulfide acid gas streams from the Amine Unit and the Sour Water Stripper
are fed to a thermal reactor and heated to high temperatures. The high temperatures destroy the ammonia
and transform some of the hydrogen sulfide into sulfur dioxide (SO2). The hydrogen sulfide/sulfur
dioxide stream is sent through a series of catalytic reactors and condensers where the sulfur compounds
are converted into liquid elemental sulfur. The liquid sulfur flows into the sulfur pit and the acid gas
remaining is sent through the Sulfur Recovery Unit incinerator where it is oxidized.

Wastewater Treatment Plant:

All industrial wastewater and storm water from the refinery property is sent through a series of tanks,
oil/water separators, biological treatment disks, and filters for cleaning, before being discharged. Some
emissions from this facility are vented to a thermal oxidizer and incinerated.

Boiler Plant:

There are three boilers (#5, #6, and #7) that produce steam for the processes described above. The boilers
operate on natural gas or plant gas.

APPLICABLE REGULATIONS: Approval Order DAQE-AN101190107-24, issued December 3,
2024.

SOURCE INSPECTION EVALUATION:

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]

Status: This is a statement of fact and not an inspection item.

I.2 The limits set forth in this AO shall not be exceeded without prior approval. [R307-401]

Status: In compliance – No limitations were noted to be exceeded at time of inspection.
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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]
Status: In compliance – No modifications to the equipment or processes were noted at time of the inspection.
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]
Status: In compliance – Electronic and hard copy records were made available, for review, at time of the inspection.
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]

Status: In compliance – The refinery appeared to be well maintained and operated at time of
the inspection. The Maximo database is used to track preventative maintenance (PM)
and as needed maintenance for the entire facility.
I.6 The owner/operator shall comply with UAC R307-107. General Requirements:
Breakdowns. [R307-107]

Status: In compliance – The refinery is aware of the breakdown rule (UAC R 307-170) and breakdown reports. Breakdowns are also covered under federal regulations.
I.7 The owner/operator shall comply with UAC R307-150 Series. Emission Inventories.
[R307-150]

Status: In compliance – Emission inventories have been submitted as required. The 2024
annual emission inventory was submitted on April 9, 2025.
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

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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
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

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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

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

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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
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 Generators 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
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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

Status: In compliance – No unapproved equipment was noted at time of the inspection.
The Collection Box pump (item II.A.33(M)) is a portable pump that is brought on-site
on an as needed basis. The Collection Box pump was not operating on-site at time of
the inspection.

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]
Status: In compliance – Only approved fuels are used.
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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]
Status: Not Evaluated – CEM requirements and CEMs Quarterly Reports are evaluated by the DAQ’s CEM specialist.
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]
Status: In compliance – Fuel oil is no longer burned in the facilities boilers. The boiler fuel lines have been removed. However, the on-site generators use diesel fuel.
II.B.1.d The owner/operator shall not allow visible emissions to exceed the opacity limits set in
R307-309. [R307-309]
Status:

In compliance – No visible emissions were observed during this inspection. CEM requirements and CEMs Quarterly Reports are evaluated by the DAQ’s CEM specialist.
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.

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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]

Status: In compliance – Emission Factors (EFs) for PM10 and PM2.5 are provided in the AO
dated March 2020. EFs are determined using CEMs and stack test data. Source wide
PM10 stack tests are no longer required to be conducted. The last PM10 stack test
was conducted in 2017. DAQ has no outstanding compliance issues for stack test
notifications.
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]

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.

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[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]

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]
Status: In compliance – The AO dated March 2020, and PM10 SIP CAP emissions. According to Data Historian, which is real time data, the daily PM10 was 0.226 tons per day (tpd). The daily maximum has not been exceeded since the September 2022 inspection. The last PM10 stack test was conducted in 2017. See status of condition II.B.1.e.
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]

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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]

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]

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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]
Status: In compliance – According to the Data Historian, which is real time data, the daily PM2.5 maximum has not been exceeded since the September 2022 inspection. Data also indicated that during the 12-month period ending the date of the inspection, 40.68 tons of PM2.5 were emitted from all stationary emission points. The last PM2.5 stack test was conducted on August 16-18, 2023. The next stack test will be conducted in 2026. See status of condition II.B.1 in the #2 of #4 memo.
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]

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]

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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]
Status: In compliance – According to the Data Historian, the daily NOx maximum has not been exceeded since the September 2022 inspection. Data also indicated that during the 12-month period ending the date of the inspection, 236.9 tons of NOx were emitted from all stationary emission points. The next NOx stack test for boilers #5 and #6 is scheduled for August 22, 2025. Boiler #7 is exempt from stack testing. See status of condition II.B.1 in the #2 of #4 memo.
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.

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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]

Status: In compliance – According to the Data Historian, the daily SO2 maximum was not exceeded
since the September 2022 inspection. Data also indicated that during the 12-month period
ending the data of the inspection, 40.8 tons of SO2 were emitted from all stationary
emission points. See status of condition II.B.1 in the #2 of #4 memo.

16

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 (3) years through testing as
outlined in Condition II.B.1.e. [40 CFR 60 Subpart Db]

Status: In compliance – Only plant fuel gas and natural gas are burned. Plant fuel gas is mainly
burned so the calculated NOx emission limit is usually between 0.0 – 0.0429 lb/MMbtu. The
September 20, 2022, NOx stack test result, for boiler #5, was 0.095 lb/MMBtu. No
exceedances were found at the time of the inspection. The next stack test will be conducted
in August 2025. See status of condition II.B.1.h.

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]

Status: In compliance – Only plant fuel gas and natural gas are burned. Plant fuel gas is mainly
burned so the calculated NOx emission limit is usually between 0.0354 - 0.0423 lb/MMbtu.
The September 20, 2022, NOx stack test result, for boiler #6, was 0.038 lb/MMBtu. No
exceedances were found at the time of the inspection. The next stack test will be conducted
in August 2025. See status of condition II.B.1.h.

17

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]

Status: Not Evaluated -- CEM requirements are evaluated by DAQ’s CEM specialist. Quarterly
CEM reports are submitted.

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]

Status: Not Evaluated – CEM requirements are evaluated by DAQ’s CEM specialist. Quarterly CEM reports are submitted.
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]

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 (3)
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.
18

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]
Status: In compliance – CEM requirements are evaluated by DAQ’s CEM specialist. Quarterly
CEM reports are submitted. According to the Data Historian the maximum daily SO2 for the 12-month period ending the date of inspection, was 0.146 tons.
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]

Status: In compliance – According to the Data Historian for the 12-month period ending the date
of the inspection, 8.74 tons of SO2 emissions were emitted from the SRU and Tail Gas
Treatment Unit 1.

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]

Status: In compliance – Sulfur pit emissions are routed to the SRU’s incinerator. The emissions are
monitored as part of the SRU’s emissions.

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]

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.
19

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]
Status: In compliance – CEM requirements are evaluated by DAQ’s CEM specialist. Quarterly
CEM reports are submitted. According to the Data Historian the maximum daily SO2 for
the 12-month period ending the date of inspection, was 0.22 tons.

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]

Status: In compliance – According to the Data Historian for the 12-month period ending the date
of the inspection, 14.8 tons of SO2 emissions were emitted from the SRU and Tail Gas
Treatment Unit 2.

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]

Status: In compliance – Sulfur pit emissions are routed to the SRU’s incinerator. The emissions are
monitored as part of the SRU’s emissions.

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.

20

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]

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 (3) 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]
Status: In compliance – CEM requirements are evaluated by DAQ’s CEM specialist. Quarterly CEM reports, which include A. and B. above, are submitted. For the 12-month period ending the date of inspection, 7.41 tons of SO2 emission were emitted from the FCCU Regenerator Vent (C. above). The maximum daily SO2 for the 12-month period ending the date of inspection was 0.073 tons (D. above).
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
21

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]

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 (3) 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]
Status: In compliance – CEM requirements are evaluated by DAQ’s CEM specialist. Quarterly
CEM reports, which include C. and D. above, are submitted. For the 12-month period
ending the date of the inspection, 11.17 tons of NOx emission were emitted from the FCCU Regenerator Vent (A. above). The maximum daily NOx for the 12-month period ending the date of the inspection was 0.0196 tons (B. above).
22

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]

Status: Not evaluated – CEM requirements are evaluated by DAQ’s CEM specialist. Quarterly CEM reports are submitted.
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]
Status In compliance – The refinery last tested the FCCU, for PM2.5, on August 16-18, 2023, and
for PM10 on December 19, 2023. The result for PM2.5 was 0.7 lb/1000 lb coke burn-off and the results for PM10 was 0.58 lb/1000 lb coke burn-off. Results have been submitted to the DAQ. The next stack tests are scheduled for late 2026.
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]

Status: In compliance – The refinery is not required to follow CPMS requirements regarding the FCCU (subject to NSPS Subpart J not Subpart Ja). CEM measurements including opacity
are evaluated by DAQ’s CEM specialist. The FCCU is controlled by an electrostatic precipitator.
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]
Status: Not evaluated – The COMS is part of a CEMS program. This information is included in the Quarterly CEMs report. The CEM requirements are evaluated by DAQ’s CEM specialist. Quarterly CEM reports are submitted. See status of condition II.B.7.e.
23

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
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 60 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 60 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]
Status:

In compliance – Non-resettable hour meters have been installed on all emergency diesel generators. According to the hour of operation records no engine has operated for more than 100 hours in calendar year 2024, for maintenance. The records also indicated that the engines are exercised weekly for about 30 minutes.
Emergency diesel generator hours of operation are as follow:
Generators 2024 Emergency Hours
2025 Emergency Hours (to
date)
Generator Status
Second North Substation 16.3 2.7 1992 - Grandfathered
#1 Cooling Water Tower (CWT) 9.8 0.5 2006 - Certified
HDN Substation 1.5 0.7 2016 - Certified
Vacuum Gas Oil (VGO) 25.9 3.7 2006 - Certified Crude Substation 18.6 2.6 1998 – Grandfathered
Third North Substation 0.0 0.0 1983 –
Grandfathered Admin Building 38.3 5.3 2015 - Certified
TCLR (Loading Rack) 2.0 0.4 2014 - Certified North Tank Field 8.8 3.1 2022 - Certified
WWTP 4.2 0.3 2023 - Certified Alky Substation 26 5.9 2017 - Certified
Boiler Plant (West and East Engines) W - 307 W - 26 2018 - Certified E - 241 E - 15 2018 - Certified
Collection Box (Rental Portable Engine) 0.0 0.0 2018 - Certified FCC MCC 0.7 4.2 2018 - Certified
Fire Water Pumps (A, B and C Engines) A - 6.3 A - 1.7 2021 - Certified B - 3.9 B - 1.3 2019 - Certified
C - 2.2 C - 1.9 2020 - Certified Canal Fire Water 9.8 0.5 2020 - Certified
Reformer Substation 2.0 1.1 2020 - Certified

24

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]

Status: In compliance – According to a Rhinehart Oil invoice, dated February 18, 2025, only #2
ULSD was delivered.
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]

Status: In compliance – Engines are maintained in-house at the maintenance shop. The Maximo
database is used to track preventative and as needed maintenance. Smith Engines conducts annual and preventative maintenance (PM). See status of condition II.B.8.a.
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)]

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 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]

Status: In compliance – Stack test have been conducted and results submitted to the DAQ. Records of catalyst inlet temperatures, catalyst pressure drops, O2 sensor replacement, and portable analyzer results are maintained. See Table:
Compressor Engines Limits (ppmvd) Results (ppmvd) Test Date
K35001 236 NOx and 834 CO 128.2 NOx and 586.1 CO 8/22/2023 K35002 208 NOx and 926 CO 187.9 NOx and 227.3 CO 8/25/2023
K35003 230 NOx and 556 CO 110.0 NOx and 99.9 CO 8/23/2023
The next stack test is scheduled to be conducted in August 2025.
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.

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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]

Status: The above processes are not conducted because VOC monitoring is conducted. The El Paso
Method requirements are evaluated in Partial Compliance Evaluation 1 of 4.
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]
Status: LDAR requirements are evaluated in Partial Compliance Evaluation 1 of 4.
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;

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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]
Status: Tank requirements are evaluated in Partial Compliance Evaluation 2 of 4.
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]

Status: Flare requirements are evaluated in Partial Compliance Evaluation 3 of 4. A flare gas recovery system has been installed for flares 1 and 2, but not for flare 3.

EMISSION INVENTORY: Chevron Product Company’s 2024 annual emission
inventory was received, by the DAQ, on April 9, 2025.

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PREVIOUS ENFORCEMENT
ACTIONS: None within the previous five years.
COMPLIANCE STATUS &
RECOMMENDATIONS: Chevron Products Company should be considered to be
incompliance with AO DAQE-AN101190107-24, dated
December 3, 2024, at time of inspection.
HPV STATUS: N/A
COMPLIANCE ASSISTANCE: Discussed Vacuum Oil Gas (VGO) Furnace Stack height
increase. The stack height will be increased from 80 feet
to 120 feet sometime in the third quarter of 2025. See
Installation and Construction notice dated August 26,
2024.
RECOMMENDATION FOR
NEXT INSPECTION: Verify VGO Furnace stack height. Inspect as usual.
ATTACHMENTS: VEO Form